FORM 6-K
SECURITIES AND EXCHANGE COMMISSION
Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 of
of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2004 | Commission File Number: 1-15226 |
ENCANA CORPORATION
1800, 855 2nd Street SW
Calgary, Alberta, Canada T2P 2S5
(Address of principal executive office)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
Form 20-F [ ] Form 40-F [ü]
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): [ ]
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): [ ]
Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934:
Yes [ ] No [ü]
If Yes is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-[ ]
Exhibits 1 and 2 to this report, furnished on Form 6-K, shall be incorporated by reference into each of the Registration Statements under the Securities Act of 1933 of the registrant:
Form S-8 No. 333-13956; Form S-8 No. 333-85598; Form F-9 No. 333-113732; and Form F-9 No. 333-118737.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: October 27, 2004
ENCANA CORPORATION | ||||
(Registrant) | ||||
By: | /s/ Linda H. Mackid | |||
Name: Linda H. Mackid | ||||
Title: Assistant Corporate Secretary |
Form 6-K Exhibit Index
Exhibit No. |
||
The following documents have been filed with Canadian securities commissions and with each of the Toronto Stock Exchange (via SEDAR) and the New York Stock Exchange (via EDGAR): | ||
1.
|
Unaudited Interim Consolidated Financial Statements for the period ended September 30, 2004. | |
2.
|
Managements Discussion and Analysis dated October 26, 2004 relating to the period ended September 30, 2004. | |
In addition, we attach, among other documents, the comfort letter of our auditors, PricewaterhouseCoopers LLP, in relation to the aforesaid documents and the Consolidated Financial Ratios, which were filed with the unaudited Interim Consolidated Financial Statements for the period ended September 30, 2004. These documents have been filed with the various Canadian securities commissions. | ||
3.
|
Covering letter dated October 27, 2004 regarding Financial Ratios and the Auditor Comfort Letter. | |
4.
|
Comfort Letter, dated October 27 2004, of PricewaterhouseCoopers LLP. | |
5.
|
Supplemental Financial Information
(Unaudited) Exhibit to September 30, 2004 Consolidated Financial Statements Consolidated Financial Ratios Medium Term Notes & Debt Securities. |
|
6.
|
Certificate, dated October 26, 2004, of Gwyn Morgan, President & Chief Executive Officer, regarding the Certification of Interim Filings during Transition Period pursuant to Form 52-109FT2. | |
7.
|
Certificate, dated October 26, 2004, of John D. Watson, Executive Vice-President & Chief Financial Officer, regarding the Certification of Interim Filings during Transition Period pursuant to Form 52-109FT2. |
Interim Consolidated Financial Statements
(unaudited)
For the period ended September 30, 2004
EnCana Corporation
U.S. DOLLARS
Interim Report | PREPARED IN US$ |
EnCana Corporation
CONSOLIDATED STATEMENT OF EARNINGS (unaudited)
September 30 |
||||||||||||||||||||
Three Months Ended |
Nine Months Ended |
|||||||||||||||||||
(US$ millions, except per share amounts) |
2004 |
2003 |
2004 |
2003 |
||||||||||||||||
REVENUES, NET OF ROYALTIES |
(Note 5) | |||||||||||||||||||
Upstream |
$ | 2,070 | $ | 1,509 | $ | 5,853 | $ | 4,651 | ||||||||||||
Midstream & Marketing |
889 | 781 | 3,206 | 2,713 | ||||||||||||||||
Corporate |
(501 | ) | 1 | (1,033 | ) | 2 | ||||||||||||||
2,458 | 2,291 | 8,026 | 7,366 | |||||||||||||||||
EXPENSES |
(Note 5) | |||||||||||||||||||
Production and mineral taxes |
97 | 33 | 258 | 131 | ||||||||||||||||
Transportation and selling |
144 | 125 | 468 | 375 | ||||||||||||||||
Operating |
382 | 322 | 1,081 | 960 | ||||||||||||||||
Purchased product |
800 | 692 | 2,909 | 2,406 | ||||||||||||||||
Depreciation, depletion and amortization |
694 | 525 | 2,051 | 1,497 | ||||||||||||||||
Administrative |
43 | 41 | 136 | 121 | ||||||||||||||||
Interest, net |
103 | 71 | 278 | 202 | ||||||||||||||||
Accretion of asset retirement obligation |
(Note 10) | 8 | 5 | 20 | 15 | |||||||||||||||
Foreign exchange (gain) |
(Note 7) | (288 | ) | (20 | ) | (209 | ) | (436 | ) | |||||||||||
Stock-based compensation |
5 | 6 | 14 | 12 | ||||||||||||||||
Gain on dispositions |
(Note 4) | | | (35 | ) | | ||||||||||||||
1,988 | 1,800 | 6,971 | 5,283 | |||||||||||||||||
NET EARNINGS BEFORE INCOME TAX |
470 | 491 | 1,055 | 2,083 | ||||||||||||||||
Income tax expense |
(Note 8) | 77 | 205 | 122 | 342 | |||||||||||||||
NET EARNINGS FROM CONTINUING OPERATIONS |
393 | 286 | 933 | 1,741 | ||||||||||||||||
NET EARNINGS FROM DISCONTINUED OPERATIONS |
(Note 6) | | 4 | | 193 | |||||||||||||||
NET EARNINGS |
$ | 393 | $ | 290 | $ | 933 | $ | 1,934 | ||||||||||||
NET EARNINGS FROM CONTINUING OPERATIONS PER COMMON SHARE |
(Note 13) | |||||||||||||||||||
Basic |
$ | 0.85 | $ | 0.60 | $ | 2.02 | $ | 3.64 | ||||||||||||
Diluted |
$ | 0.84 | $ | 0.60 | $ | 2.00 | $ | 3.60 | ||||||||||||
NET EARNINGS PER COMMON SHARE |
(Note 13) | |||||||||||||||||||
Basic |
$ | 0.85 | $ | 0.61 | $ | 2.02 | $ | 4.05 | ||||||||||||
Diluted |
$ | 0.84 | $ | 0.61 | $ | 2.00 | $ | 4.00 | ||||||||||||
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
Nine Months Ended | ||||||||||||
September 30, |
||||||||||||
(US$ millions) |
2004 |
2003 |
||||||||||
RETAINED EARNINGS, BEGINNING OF YEAR |
||||||||||||
As previously reported |
$ | 5,276 | $ | 3,457 | ||||||||
Retroactive adjustment for changes in accounting policies |
| 66 | ||||||||||
As restated |
5,276 | 3,523 | ||||||||||
Net Earnings |
933 | 1,934 | ||||||||||
Dividends on Common Shares |
(137 | ) | (103 | ) | ||||||||
Charges for Normal Course Issuer Bid |
(Note 11) | (126 | ) | (360 | ) | |||||||
RETAINED EARNINGS, END OF PERIOD |
$ | 5,946 | $ | 4,994 | ||||||||
See accompanying Notes to Consolidated Financial Statements.
1
Interim Report | PREPARED IN US$ |
EnCana Corporation
CONSOLIDATED BALANCE SHEET (unaudited)
As at | As at | |||||||||||
September 30, | December 31, | |||||||||||
(US$ millions) |
2004 |
2003 |
||||||||||
ASSETS |
||||||||||||
Current Assets |
||||||||||||
Cash and cash equivalents |
$ | 107 | $ | 148 | ||||||||
Accounts receivable and accrued revenues |
2,066 | 1,367 | ||||||||||
Risk management |
(Note 14) | 84 | | |||||||||
Inventories |
700 | 573 | ||||||||||
2,957 | 2,088 | |||||||||||
Property, Plant and Equipment, net |
(Note 5) | 23,623 | 19,545 | |||||||||
Investments and Other Assets |
637 | 566 | ||||||||||
Risk Management |
(Note 14) | 46 | | |||||||||
Goodwill |
2,410 | 1,911 | ||||||||||
(Note 5) | $ | 29,673 | $ | 24,110 | ||||||||
LIABILITIES AND SHAREHOLDERS EQUITY |
||||||||||||
Current Liabilities |
||||||||||||
Accounts payable and accrued liabilities |
$ | 2,059 | $ | 1,579 | ||||||||
Risk management |
(Note 14) | 800 | | |||||||||
Income tax payable |
526 | 65 | ||||||||||
Current portion of long-term debt |
(Note 9) | 550 | 287 | |||||||||
3,935 | 1,931 | |||||||||||
Long-Term Debt |
(Note 9) | 8,036 | 6,088 | |||||||||
Other Liabilities |
85 | 21 | ||||||||||
Risk Management |
(Note 14) | 332 | | |||||||||
Asset Retirement Obligation |
(Note 10) | 490 | 430 | |||||||||
Future Income Taxes |
4,712 | 4,362 | ||||||||||
17,590 | 12,832 | |||||||||||
Shareholders Equity
|
||||||||||||
Share capital |
(Note 11) | 5,412 | 5,305 | |||||||||
Share options, net |
21 | 55 | ||||||||||
Paid in surplus |
53 | 18 | ||||||||||
Retained earnings |
5,946 | 5,276 | ||||||||||
Foreign currency translation adjustment |
651 | 624 | ||||||||||
12,083 | 11,278 | |||||||||||
$ | 29,673 | $ | 24,110 | |||||||||
See accompanying Notes to Consolidated Financial Statements.
2
Interim Report | PREPARED IN US$ |
EnCana Corporation
CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)
September 30 |
||||||||||||||||||||
Three Months Ended |
Nine Months Ended |
|||||||||||||||||||
(US$ millions) |
2004 |
2003 |
2004 |
2003 |
||||||||||||||||
OPERATING ACTIVITIES |
||||||||||||||||||||
Net earnings from continuing operations |
$ | 393 | $ | 286 | $ | 933 | $ | 1,741 | ||||||||||||
Depreciation, depletion and amortization |
694 | 525 | 2,051 | 1,497 | ||||||||||||||||
Future income taxes |
(Note 8) | (47 | ) | 154 | (437 | ) | 325 | |||||||||||||
Unrealized loss on risk management |
(Note 14) | 497 | | 1,028 | | |||||||||||||||
Unrealized foreign exchange (gain) |
(Note 7) | (193 | ) | (15 | ) | (122 | ) | (404 | ) | |||||||||||
Accretion of asset retirement obligation |
(Note 10) | 8 | 5 | 20 | 15 | |||||||||||||||
Gain on dispositions |
(Note 4) | | | (35 | ) | | ||||||||||||||
Other |
11 | 18 | 51 | 29 | ||||||||||||||||
Cash flow from continuing operations |
1,363 | 973 | 3,489 | 3,203 | ||||||||||||||||
Cash flow from discontinued operations |
| 4 | | 2 | ||||||||||||||||
Cash flow |
1,363 | 977 | 3,489 | 3,205 | ||||||||||||||||
Net change in other assets and liabilities |
(25 | ) | (111 | ) | (71 | ) | (82 | ) | ||||||||||||
Net change in non-cash working capital from continuing operations |
(276 | ) | 159 | (103 | ) | 200 | ||||||||||||||
Net change in non-cash working capital from discontinued operations |
| (3 | ) | | 54 | |||||||||||||||
1,062 | 1,022 | 3,315 | 3,377 | |||||||||||||||||
INVESTING ACTIVITIES |
||||||||||||||||||||
Business combination with Tom Brown, Inc. |
(Note 3) | | | (2,335 | ) | | ||||||||||||||
Capital expenditures |
(Note 5) | (1,147 | ) | (1,345 | ) | (3,892 | ) | (3,438 | ) | |||||||||||
Proceeds on disposal of assets |
941 | | 1,072 | 19 | ||||||||||||||||
Dispositions (acquisitions) |
(Note 4) | (1 | ) | (91 | ) | 287 | (207 | ) | ||||||||||||
Equity investments |
(Note 4) | 8 | (25 | ) | 52 | (158 | ) | |||||||||||||
Net change in investments and other |
(46 | ) | (41 | ) | (68 | ) | (68 | ) | ||||||||||||
Net change in non-cash working capital from continuing operations |
(24 | ) | 46 | (70 | ) | (112 | ) | |||||||||||||
Discontinued operations |
| 307 | | 1,585 | ||||||||||||||||
(269 | ) | (1,149 | ) | (4,954 | ) | (2,379 | ) | |||||||||||||
FINANCING ACTIVITIES |
||||||||||||||||||||
Net (repayment) issuance of revolving long-term debt |
(662 | ) | 722 | (215 | ) | 262 | ||||||||||||||
Issuance of long-term debt |
1,000 | | 3,761 | | ||||||||||||||||
Repayment of long-term debt |
(1,205 | ) | (71 | ) | (1,754 | ) | (142 | ) | ||||||||||||
Issuance of common shares |
(Note 11) | 30 | 12 | 184 | 95 | |||||||||||||||
Purchase of common shares |
(Note 11) | | (560 | ) | (230 | ) | (682 | ) | ||||||||||||
Dividends on common shares |
(45 | ) | (35 | ) | (137 | ) | (103 | ) | ||||||||||||
Other |
(6 | ) | 8 | (11 | ) | (5 | ) | |||||||||||||
Discontinued operations |
| | | (282 | ) | |||||||||||||||
(888 | ) | 76 | 1,598 | (857 | ) | |||||||||||||||
DEDUCT: FOREIGN EXCHANGE LOSS ON CASH AND
CASH EQUIVALENTS HELD IN FOREIGN CURRENCY |
| 1 | | 9 | ||||||||||||||||
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS |
(95 | ) | (52 | ) | (41 | ) | 132 | |||||||||||||
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD |
202 | 300 | 148 | 116 | ||||||||||||||||
CASH AND CASH EQUIVALENTS, END OF PERIOD |
$ | 107 | $ | 248 | $ | 107 | $ | 248 | ||||||||||||
See accompanying Notes to Consolidated Financial Statements.
3
Interim Report | PREPARED IN US$ |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
1. BASIS OF PRESENTATION
The interim Consolidated Financial Statements include the accounts of EnCana Corporation and its subsidiaries (the Company), and are presented in accordance with Canadian generally accepted accounting principles. The Company is in the business of exploration for, and production and marketing of, natural gas, natural gas liquids and crude oil, as well as natural gas storage operations, natural gas liquids processing and power generation operations.
The interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2003, except as noted below. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements. The interim Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2003.
2. CHANGE IN ACCOUNTING POLICIES AND PRACTICES
Hedging Relationships
On January 1, 2004, the Company adopted the amendments made to Accounting Guideline 13 (AcG - 13) Hedging Relationships, and 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 has elected not to designate any of its price risk management activities in place at September 30, 2004 as accounting hedges under AcG - 13 and, accordingly, will account for all these non-hedging derivatives using the mark-to-market accounting method. The impact on the Companys 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 which will be recognized into net earnings as the contracts expire. At September 30, 2004, it is estimated that over the following 12 months, $42 million ($30 million, net of tax) will be reclassified into net earnings from net deferred losses.
The following table presents the deferred amounts expected to be recognized in net earnings as unrealized gains/(losses) over the years 2004 to 2008:
Unrealized | ||||
Gain/(Loss) |
||||
2004 |
||||
Quarter 4 |
$ | (64 | ) | |
Total remaining to be recognized in 2004 |
$ | (64 | ) | |
2005 |
||||
Quarter 1 |
$ | | ||
Quarter 2 |
13 | |||
Quarter 3 |
9 | |||
Quarter 4 |
9 | |||
Total to be recognized in 2005 |
$ | 31 | ||
2006 |
24 | |||
2007 |
15 | |||
2008 |
1 | |||
Total to be recognized in 2006 to 2008 |
$ | 40 | ||
Total to be recognized |
$ | 7 | ||
At September 30, 2004, the remaining net deferred loss totalled $7 million of which $72 million was recorded in Accounts receivable and accrued revenues, $3 million in Investments and other assets, $30 million in Accounts payable and accrued liabilities and $52 million in Other liabilities.
4
Interim Report | PREPARED IN US$ |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
3. BUSINESS COMBINATION WITH TOM BROWN, INC.
In May 2004, the Company completed the tender offer for the common shares of Tom Brown, Inc., a Denver based independent energy company for total cash consideration of $2.3 billion.
The business combination has been accounted for using the purchase method with results of operations of Tom Brown, Inc. included in the Consolidated Financial Statements from the date of acquisition.
The calculation of the purchase price and the preliminary allocation to assets and liabilities is shown below. The purchase price and goodwill allocation is preliminary because certain items such as determination of the final tax bases and fair values of the assets and liabilities as of the acquisition date have not been completed.
Calculation of Purchase Price |
||||
Cash paid for common shares of Tom Brown, Inc. |
$ | 2,341 | ||
Transaction costs |
13 | |||
Total purchase price |
$ | 2,354 | ||
Plus: Fair value of liabilities assumed
|
||||
Current liabilities |
276 | |||
Long-term debt |
406 | |||
Other non-current liabilities |
39 | |||
Future income taxes |
710 | |||
Total Purchase Price and Liabilities Assumed |
$ | 3,785 | ||
Fair Value of Assets Acquired |
||||
Current assets (including cash acquired of $19 million) |
$ | 440 | ||
Property, plant, and equipment |
2,879 | |||
Other non-current assets |
9 | |||
Goodwill |
457 | |||
Total Fair Value of Assets Acquired |
$ | 3,785 | ||
Included in current assets as Assets held for sale is $278 million related to the value of certain oil and gas properties located in west Texas and southwestern New Mexico and the assets of Sauer Drilling Company, a subsidiary of Tom Brown, Inc., which the Company has entered into purchase and sale agreements. These sales were completed on July 30, 2004.
5
Interim Report | PREPARED IN US$ |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
4. DISPOSITIONS (ACQUISITIONS)
In March 2004, the Company sold its investment in a well servicing company for approximately $44 million, recording a gain on sale of $34 million.
On February 18, 2004, the Company sold its 53.3 percent interest in Petrovera Resources (Petrovera) for approximately $287 million, including working capital adjustments. In order to facilitate the transaction, EnCana purchased the 46.7 percent interest of its partner for approximately $253 million, including working capital adjustments, and then sold the 100 percent interest in Petrovera for a total of approximately $540 million, including working capital adjustments. There was no gain or loss recorded on this sale.
On January 31, 2003, the Company acquired the Ecuadorian interests of Vintage Petroleum Inc. (Vintage) for net cash consideration of $116 million. On July 18, 2003, the Company acquired the common shares of Savannah Energy Inc. (Savannah) for net cash consideration of $91 million. Savannahs operations are in Texas, USA. These purchases were accounted for using the purchase method with the results reflected in the consolidated results of EnCana from the dates of acquisition.
Other dispositions of discontinued operations are disclosed in Note 6.
5. SEGMENTED INFORMATION
The Company has defined its continuing operations into the following segments:
| Upstream includes the Companys exploration for, and development and production of, natural gas, natural gas liquids and crude oil and other related activities. The majority of the Companys Upstream operations are located in Canada, the United States, the United Kingdom and Ecuador. International new venture exploration is mainly focused on opportunities in Africa, South America and the Middle East. | |||
| Midstream & Marketing includes natural gas storage operations, natural gas liquids processing and power generation operations, as well as marketing activities. These marketing activities include the sale and delivery of produced product and the purchasing of third party product primarily for the optimization of midstream assets, as well as the optimization of transportation arrangements not fully utilized for the Companys own production. | |||
| Corporate includes unrealized gains or losses recorded on derivative instruments. Once amounts are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates. |
Midstream & Marketing purchases all of the Companys North American Upstream production. Transactions between business segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis.
Operations that have been discontinued are disclosed in Note 6.
6
Interim Report | PREPARED IN US$ |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
5. SEGMENTED INFORMATION (continued)
Results of Operations (For the three months ended September 30)
Upstream |
Midstream & Marketing |
|||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Revenues, Net of Royalties |
$ | 2,070 | $ | 1,509 | $ | 889 | $ | 781 | ||||||||
Expenses |
||||||||||||||||
Production and mineral taxes |
97 | 33 | | | ||||||||||||
Transportation and selling |
140 | 114 | 4 | 11 | ||||||||||||
Operating |
304 | 258 | 77 | 64 | ||||||||||||
Purchased product |
| | 800 | 692 | ||||||||||||
Depreciation, depletion and amortization |
672 | 502 | 8 | 9 | ||||||||||||
Segment Income |
$ | 857 | $ | 602 | $ | | $ | 5 | ||||||||
Corporate |
Consolidated |
|||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Revenues, Net of Royalties * |
$ | (501 | ) | $ | 1 | $ | 2,458 | $ | 2,291 | |||||||
Expenses |
||||||||||||||||
Production and mineral taxes |
| | 97 | 33 | ||||||||||||
Transportation and selling |
| | 144 | 125 | ||||||||||||
Operating |
1 | | 382 | 322 | ||||||||||||
Purchased product |
| | 800 | 692 | ||||||||||||
Depreciation, depletion and amortization |
14 | 14 | 694 | 525 | ||||||||||||
Segment Income |
$ | (516 | ) | $ | (13 | ) | 341 | 594 | ||||||||
Administrative |
43 | 41 | ||||||||||||||
Interest, net |
103 | 71 | ||||||||||||||
Accretion of asset retirement obligation |
8 | 5 | ||||||||||||||
Foreign exchange (gain) |
(288 | ) | (20 | ) | ||||||||||||
Stock-based compensation |
5 | 6 | ||||||||||||||
Gain on dispositions |
| | ||||||||||||||
(129 | ) | 103 | ||||||||||||||
Net Earnings Before Income Tax |
470 | 491 | ||||||||||||||
Income tax expense |
77 | 205 | ||||||||||||||
Net Earnings from Continuing Operations |
$ | 393 | $ | 286 | ||||||||||||
* Corporate revenue primarily reflects unrealized gains or losses recorded on derivative instruments. See also Note 14.
7
Interim Report | PREPARED IN US$ |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
5. SEGMENTED INFORMATION (continued)
Results of Operations (For the three months ended September 30)
Upstream |
Canada |
United States |
Ecuador |
|||||||||||||||||||||
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
|||||||||||||||||||
Revenues, Net of Royalties |
$ | 1,283 | $ | 1,072 | $ | 512 | $ | 281 | $ | 159 | $ | 81 | ||||||||||||
Expenses |
||||||||||||||||||||||||
Production and mineral taxes |
23 | 4 | 56 | 28 | 18 | 1 | ||||||||||||||||||
Transportation and selling |
91 | 80 | 23 | 22 | 16 | 9 | ||||||||||||||||||
Operating |
170 | 170 | 32 | 18 | 30 | 16 | ||||||||||||||||||
Depreciation, depletion and amortization |
445 | 377 | 131 | 78 | 63 | 33 | ||||||||||||||||||
Segment Income |
$ | 554 | $ | 441 | $ | 270 | $ | 135 | $ | 32 | $ | 22 | ||||||||||||
U.K. North Sea |
Other |
Total Upstream |
||||||||||||||||||||||
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
|||||||||||||||||||
Revenues, Net of Royalties |
$ | 50 | $ | 17 | $ | 66 | $ | 58 | $ | 2,070 | $ | 1,509 | ||||||||||||
Expenses |
||||||||||||||||||||||||
Production and mineral taxes |
| | | | 97 | 33 | ||||||||||||||||||
Transportation and selling |
10 | 3 | | | 140 | 114 | ||||||||||||||||||
Operating |
12 | 3 | 60 | 51 | 304 | 258 | ||||||||||||||||||
Depreciation, depletion and amortization |
26 | 12 | 7 | 2 | 672 | 502 | ||||||||||||||||||
Segment Income |
$ | 2 | $ | (1 | ) | $ | (1 | ) | $ | 5 | $ | 857 | $ | 602 | ||||||||||
Total Midstream | ||||||||||||||||||||||||
Midstream & Marketing |
Midstream |
Marketing |
& Marketing |
|||||||||||||||||||||
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
|||||||||||||||||||
Revenues |
$ | 158 | $ | 180 | $ | 731 | $ | 601 | $ | 889 | $ | 781 | ||||||||||||
Expenses |
||||||||||||||||||||||||
Transportation and selling |
| | 4 | 11 | 4 | 11 | ||||||||||||||||||
Operating |
65 | 57 | 12 | 7 | 77 | 64 | ||||||||||||||||||
Purchased product |
88 | 112 | 712 | 580 | 800 | 692 | ||||||||||||||||||
Depreciation, depletion and amortization |
8 | 7 | | 2 | 8 | 9 | ||||||||||||||||||
Segment Income |
$ | (3 | ) | $ | 4 | $ | 3 | $ | 1 | $ | | $ | 5 | |||||||||||
8
Interim Report
|
PREPARED IN US$ |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
5. SEGMENTED INFORMATION (continued)
Upstream Geographic and Product Information (For the three months ended September 30)
Produced Gas |
Produced Gas |
|||||||||||||||||||||||||||||||
Canada |
United States |
U.K. North Sea |
Total |
|||||||||||||||||||||||||||||
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
|||||||||||||||||||||||||
Revenues, Net of Royalties |
$ | 970 | $ | 806 | $ | 462 | $ | 259 | $ | 10 | $ | 2 | $ | 1,442 | $ | 1,067 | ||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||
Production and mineral taxes |
18 | 15 | 51 | 25 | | | 69 | 40 | ||||||||||||||||||||||||
Transportation and selling |
72 | 71 | 23 | 22 | 7 | 1 | 102 | 94 | ||||||||||||||||||||||||
Operating |
99 | 89 | 32 | 18 | | | 131 | 107 | ||||||||||||||||||||||||
Operating Cash Flow |
$ | 781 | $ | 631 | $ | 356 | $ | 194 | $ | 3 | $ | 1 | $ | 1,140 | $ | 826 | ||||||||||||||||
Oil & NGLs |
Oil & NGLs |
|||||||||||||||||||||||
Canada |
United States |
Ecuador |
||||||||||||||||||||||
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
|||||||||||||||||||
Revenues, Net of Royalties |
$ | 313 | $ | 266 | $ | 50 | $ | 22 | $ | 159 | $ | 81 | ||||||||||||
Expenses |
||||||||||||||||||||||||
Production and mineral taxes |
5 | (11 | ) | 5 | 3 | 18 | 1 | |||||||||||||||||
Transportation and selling |
19 | 9 | | | 16 | 9 | ||||||||||||||||||
Operating |
71 | 81 | | | 30 | 16 | ||||||||||||||||||
Operating Cash Flow |
$ | 218 | $ | 187 | $ | 45 | $ | 19 | $ | 95 | $ | 55 | ||||||||||||
Oil & NGLs |
||||||||||||||||
U.K. North Sea |
Total |
|||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Revenues, Net of Royalties |
$ | 40 | $ | 15 | $ | 562 | $ | 384 | ||||||||
Expenses |
||||||||||||||||
Production and mineral taxes |
| | 28 | (7 | ) | |||||||||||
Transportation and selling |
3 | 2 | 38 | 20 | ||||||||||||
Operating |
12 | 3 | 113 | 100 | ||||||||||||
Operating Cash Flow |
$ | 25 | $ | 10 | $ | 383 | $ | 271 | ||||||||
Other & Total Upstream |
Other |
Total Upstream |
||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Revenues, Net of Royalties |
$ | 66 | $ | 58 | $ | 2,070 | $ | 1,509 | ||||||||
Expenses |
||||||||||||||||
Production and mineral taxes |
| | 97 | 33 | ||||||||||||
Transportation and selling |
| | 140 | 114 | ||||||||||||
Operating |
60 | 51 | 304 | 258 | ||||||||||||
Operating Cash Flow |
$ | 6 | $ | 7 | $ | 1,529 | $ | 1,104 | ||||||||
9
Interim Report
|
PREPARED IN US$ |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
5. SEGMENTED INFORMATION (continued)
Results of Operations (For the nine months ended September 30)
Upstream |
Midstream & Marketing |
|||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Revenues, Net of Royalties |
$ | 5,853 | $ | 4,651 | $ | 3,206 | $ | 2,713 | ||||||||
Expenses |
||||||||||||||||
Production and mineral taxes |
258 | 131 | | | ||||||||||||
Transportation and selling |
448 | 331 | 20 | 44 | ||||||||||||
Operating |
861 | 719 | 224 | 241 | ||||||||||||
Purchased product |
| | 2,909 | 2,406 | ||||||||||||
Depreciation, depletion and amortization |
1,947 | 1,444 | 60 | 21 | ||||||||||||
Segment Income |
$ | 2,339 | $ | 2,026 | $ | (7 | ) | $ | 1 | |||||||
Corporate |
Consolidated |
|||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Revenues, Net of Royalties * |
$ | (1,033 | ) | $ | 2 | $ | 8,026 | $ | 7,366 | |||||||
Expenses |
||||||||||||||||
Production and mineral taxes |
| | 258 | 131 | ||||||||||||
Transportation and selling |
| | 468 | 375 | ||||||||||||
Operating |
(4 | ) | | 1,081 | 960 | |||||||||||
Purchased product |
| | 2,909 | 2,406 | ||||||||||||
Depreciation, depletion and amortization |
44 | 32 | 2,051 | 1,497 | ||||||||||||
Segment Income |
$ | (1,073 | ) | $ | (30 | ) | 1,259 | 1,997 | ||||||||
Administrative |
136 | 121 | ||||||||||||||
Interest, net |
278 | 202 | ||||||||||||||
Accretion of asset retirement obligation |
20 | 15 | ||||||||||||||
Foreign exchange (gain) |
(209 | ) | (436 | ) | ||||||||||||
Stock-based compensation |
14 | 12 | ||||||||||||||
Gain on dispositions |
(35 | ) | | |||||||||||||
204 | (86 | ) | ||||||||||||||
Net Earnings Before Income Tax |
1,055 | 2,083 | ||||||||||||||
Income tax expense |
122 | 342 | ||||||||||||||
Net Earnings from Continuing Operations |
$ | 933 | $ | 1,741 | ||||||||||||
* Corporate revenue primarily reflects unrealized gains or losses recorded on derivative instruments. See also Note 14.
10
Interim Report
|
PREPARED IN US$ |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
5. SEGMENTED INFORMATION (continued)
Results of Operations (For the nine months ended September 30)
Upstream |
Canada |
United States |
Ecuador |
|||||||||||||||||||||
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
|||||||||||||||||||
Revenues, Net of Royalties |
$ | 3,770 | $ | 3,343 | $ | 1,313 | $ | 845 | $ | 432 | $ | 243 | ||||||||||||
Expenses |
||||||||||||||||||||||||
Production and mineral taxes |
61 | 33 | 155 | 81 | 42 | 17 | ||||||||||||||||||
Transportation and selling |
277 | 241 | 93 | 56 | 49 | 24 | ||||||||||||||||||
Operating |
505 | 482 | 80 | 43 | 89 | 50 | ||||||||||||||||||
Depreciation, depletion and amortization |
1,296 | 1,089 | 330 | 211 | 197 | 87 | ||||||||||||||||||
Segment Income |
$ | 1,631 | $ | 1,498 | $ | 655 | $ | 454 | $ | 55 | $ | 65 | ||||||||||||
Transportation and selling for the United States includes a one-time payment of $21 million made in Q2 2004 to terminate a long-term physical delivery contract.
U.K. North Sea |
Other |
Total Upstream |
||||||||||||||||||||||
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
|||||||||||||||||||
Revenues, Net of Royalties |
$ | 168 | $ | 73 | $ | 170 | $ | 147 | $ | 5,853 | $ | 4,651 | ||||||||||||
Expenses |
||||||||||||||||||||||||
Production and mineral taxes |
| | | | 258 | 131 | ||||||||||||||||||
Transportation and selling |
29 | 10 | | | 448 | 331 | ||||||||||||||||||
Operating |
32 | 10 | 155 | 134 | 861 | 719 | ||||||||||||||||||
Depreciation, depletion and amortization |
93 | 53 | 31 | 4 | 1,947 | 1,444 | ||||||||||||||||||
Segment Income |
$ | 14 | $ | | $ | (16 | ) | $ | 9 | $ | 2,339 | $ | 2,026 | |||||||||||
Total Midstream | ||||||||||||||||||||||||
Midstream & Marketing |
Midstream |
Marketing |
& Marketing |
|||||||||||||||||||||
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
|||||||||||||||||||
Revenues |
$ | 881 | $ | 649 | $ | 2,325 | $ | 2,064 | $ | 3,206 | $ | 2,713 | ||||||||||||
Expenses |
||||||||||||||||||||||||
Transportation and selling |
| | 20 | 44 | 20 | 44 | ||||||||||||||||||
Operating |
192 | 188 | 32 | 53 | 224 | 241 | ||||||||||||||||||
Purchased product |
655 | 423 | 2,254 | 1,983 | 2,909 | 2,406 | ||||||||||||||||||
Depreciation, depletion and amortization |
58 | 18 | 2 | 3 | 60 | 21 | ||||||||||||||||||
Segment Income |
$ | (24 | ) | $ | 20 | $ | 17 | $ | (19 | ) | $ | (7 | ) | $ | 1 | |||||||||
Midstream Depreciation, depletion and amortization includes a $35 million impairment charge made in Q2 2004 on the Companys interest in Oleoducto Trasandino in Argentina and Chile.
11
Interim Report
|
PREPARED IN US$ | |
For the period ended September 30, 2004 |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
5. SEGMENTED INFORMATION (continued)
Upstream Geographic and Product Information (For the nine months ended September 30)
Produced Gas |
||||||||||||||||||||||||||||||||
Canada |
United States |
U.K. North Sea |
Total |
|||||||||||||||||||||||||||||
Produced Gas |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
||||||||||||||||||||||||
Revenues, Net of Royalties |
$ | 2,887 | $ | 2,534 | $ | 1,198 | $ | 776 | $ | 36 | $ | 8 | $ | 4,121 | $ | 3,318 | ||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||
Production and mineral taxes |
46 | 33 | 142 | 77 | | | 188 | 110 | ||||||||||||||||||||||||
Transportation and selling |
222 | 193 | 93 | 56 | 19 | 6 | 334 | 255 | ||||||||||||||||||||||||
Operating |
297 | 258 | 80 | 43 | | | 377 | 301 | ||||||||||||||||||||||||
Operating Cash Flow |
$ | 2,322 | $ | 2,050 | $ | 883 | $ | 600 | $ | 17 | $ | 2 | $ | 3,222 | $ | 2,652 | ||||||||||||||||
Transportation and selling for the United States includes a one-time payment of $21 million made in Q2 2004 to terminate a long-term physical delivery contract.
Oil & NGLs |
||||||||||||||||||||||||
Canada |
United States |
Ecuador |
||||||||||||||||||||||
Oil & NGLs |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
||||||||||||||||||
Revenues, Net of Royalties |
$ | 883 | $ | 809 | $ | 115 | $ | 69 | $ | 432 | $ | 243 | ||||||||||||
Expenses |
||||||||||||||||||||||||
Production and mineral taxes |
15 | | 13 | 4 | 42 | 17 | ||||||||||||||||||
Transportation and selling |
55 | 48 | | | 49 | 24 | ||||||||||||||||||
Operating |
208 | 224 | | | 89 | 50 | ||||||||||||||||||
Operating Cash Flow |
$ | 605 | $ | 537 | $ | 102 | $ | 65 | $ | 252 | $ | 152 | ||||||||||||
Oil & NGLs |
||||||||||||||||
U.K. North Sea |
Total |
|||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Revenues, Net of Royalties |
$ | 132 | $ | 65 | $ | 1,562 | $ | 1,186 | ||||||||
Expenses |
||||||||||||||||
Production and mineral taxes |
| | 70 | 21 | ||||||||||||
Transportation and selling |
10 | 4 | 114 | 76 | ||||||||||||
Operating |
32 | 10 | 329 | 284 | ||||||||||||
Operating Cash Flow |
$ | 90 | $ | 51 | $ | 1,049 | $ | 805 | ||||||||
Other |
Total Upstream |
|||||||||||||||
Other & Total Upstream |
2004 |
2003 |
2004 |
2003 |
||||||||||||
Revenues, Net of Royalties |
$ | 170 | $ | 147 | $ | 5,853 | $ | 4,651 | ||||||||
Expenses |
||||||||||||||||
Production and mineral taxes |
| | 258 | 131 | ||||||||||||
Transportation and selling |
| | 448 | 331 | ||||||||||||
Operating |
155 | 134 | 861 | 719 | ||||||||||||
Operating Cash Flow |
$ | 15 | $ | 13 | $ | 4,286 | $ | 3,470 | ||||||||
12
Interim Report
|
PREPARED IN US$ | |
For the period ended September 30, 2004 |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
5. SEGMENTED INFORMATION (continued)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, |
September 30, |
|||||||||||||||
Capital Expenditures |
2004 |
2003 |
2004 |
2003 |
||||||||||||
Upstream |
||||||||||||||||
Canada |
$ | 634 | $ | 901 | $ | 2,337 | $ | 2,287 | ||||||||
United States |
328 | 280 | 854 | 626 | ||||||||||||
Ecuador |
53 | 65 | 163 | 172 | ||||||||||||
United Kingdom |
92 | 19 | 421 | 45 | ||||||||||||
Other Countries |
15 | 15 | 49 | 63 | ||||||||||||
1,122 | 1,280 | 3,824 | 3,193 | |||||||||||||
Midstream & Marketing |
15 | 58 | 40 | 207 | ||||||||||||
Corporate |
10 | 7 | 28 | 38 | ||||||||||||
Total |
$ | 1,147 | $ | 1,345 | $ | 3,892 | $ | 3,438 | ||||||||
Property, Plant and Equipment |
Total Assets |
|||||||||||||||
As at |
As at |
|||||||||||||||
September 30, | December 31, | September 30, | December 31, | |||||||||||||
Property, Plant and Equipment and Total Assets |
2004 |
2003 |
2004 |
2003 |
||||||||||||
Upstream |
$ | 22,590 | $ | 18,532 | $ | 27,030 | $ | 21,742 | ||||||||
Midstream & Marketing |
808 | 784 | 1,977 | 1,879 | ||||||||||||
Corporate |
225 | 229 | 666 | 489 | ||||||||||||
Total |
$ | 23,623 | $ | 19,545 | $ | 29,673 | $ | 24,110 | ||||||||
13
Interim Report
|
PREPARED IN US$ | |
For the period ended September 30, 2004 |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
6. DISCONTINUED OPERATIONS
On February 28, 2003, the Company completed the sale of its 10 percent working interest in the Syncrude Joint Venture (Syncrude) to Canadian Oil Sands Limited for net cash consideration of C$1,026 million ($690 million). On July 10, 2003, the Company completed the sale of the remaining 3.75 percent interest in Syncrude and a gross overriding royalty for net cash consideration of C$427 million ($309 million). There was no gain or loss on this sale.
On January 2, 2003 and January 9, 2003, the Company completed the sales of its interests in the Cold Lake Pipeline System and Express Pipeline System for total consideration of approximately C$1.6 billion ($1 billion), including assumption of related long-term debt by the purchaser, and recorded an after-tax gain on sale of C$263 million ($169 million).
As all discontinued operations have either been disposed of or wind up has been completed by December 31, 2003, there are no remaining assets or liabilities on the Consolidated Balance Sheet. The following tables present the effect of the discontinued operations on the Consolidated Statement of Earnings for 2003:
Consolidated Statement of Earnings
For the three months ended | ||||||||||||
September 30, 2003 |
||||||||||||
Midstream - | ||||||||||||
Syncrude |
Pipelines |
Total |
||||||||||
Revenues, Net of Royalties |
$ | 8 | $ | | $ | 8 | ||||||
Expenses |
||||||||||||
Transportation and selling |
| | | |||||||||
Operating |
4 | | 4 | |||||||||
Depreciation, depletion and amortization |
1 | | 1 | |||||||||
Gain on discontinuance |
| | | |||||||||
5 | | 5 | ||||||||||
Net Earnings Before Income Tax |
3 | | 3 | |||||||||
Income tax expense |
(1 | ) | | (1 | ) | |||||||
Net Earnings from Discontinued Operations |
$ | 4 | $ | | $ | 4 | ||||||
Consolidated Statement of Earnings
For the nine months ended | ||||||||||||
September 30, 2003 |
||||||||||||
Midstream - | ||||||||||||
Syncrude |
Pipelines |
Total |
||||||||||
Revenues, Net of Royalties |
$ | 87 | $ | | $ | 87 | ||||||
Expenses |
||||||||||||
Transportation and selling |
2 | | 2 | |||||||||
Operating |
46 | | 46 | |||||||||
Depreciation, depletion and amortization |
7 | | 7 | |||||||||
Gain on discontinuance |
| (220 | ) | (220 | ) | |||||||
55 | (220 | ) | (165 | ) | ||||||||
Net Earnings Before Income Tax |
32 | 220 | 252 | |||||||||
Income tax expense |
8 | 51 | 59 | |||||||||
Net Earnings from Discontinued Operations |
$ | 24 | $ | 169 | $ | 193 | ||||||
14
Interim Report
|
PREPARED IN US$ | |
For the period ended September 30, 2004 |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
7. FOREIGN EXCHANGE (GAIN)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, |
September 30, |
|||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Unrealized Foreign Exchange (Gain) on Translation of U.S. Dollar Debt Issued in Canada |
$ | (193 | ) | $ | (15 | ) | $ | (122 | ) | $ | (404 | ) | ||||
Realized Foreign Exchange (Gain) |
(95 | ) | (5 | ) | (87 | ) | (32 | ) | ||||||||
$ | (288 | ) | $ | (20 | ) | $ | (209 | ) | $ | (436 | ) | |||||
8. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, |
September 30, |
|||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Current |
||||||||||||||||
Canada |
$ | 76 | $ | 31 | $ | 441 | $ | (18 | ) | |||||||
United States |
3 | 10 | 18 | 10 | ||||||||||||
Ecuador |
44 | 8 | 98 | 21 | ||||||||||||
United Kingdom |
| 1 | | 3 | ||||||||||||
Other |
1 | 1 | 2 | 1 | ||||||||||||
Total Current Tax |
124 | 51 | 559 | 17 | ||||||||||||
Future |
(47 | ) | 154 | (328 | ) | 687 | ||||||||||
Future Tax Rate Reductions * |
| | (109 | ) | (362 | ) | ||||||||||
Total Future Tax |
(47 | ) | 154 | (437 | ) | 325 | ||||||||||
$ | 77 | $ | 205 | $ | 122 | $ | 342 | |||||||||
* On March 31, 2004, the Alberta government substantively enacted the income tax rate reduction previously announced in February 2004.
The following table reconciles income taxes calculated at the Canadian statutory rate with the actual income taxes:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, |
September 30, |
|||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Net Earnings Before Income Tax |
$ | 470 | $ | 491 | $ | 1,055 | $ | 2,083 | ||||||||
Canadian Statutory Rate |
39.1 | % | 41.0 | % | 39.1 | % | 41.0 | % | ||||||||
Expected Income Taxes |
184 | 201 | 413 | 853 | ||||||||||||
Effect on Taxes Resulting from: |
||||||||||||||||
Non-deductible Canadian crown payments |
51 | 44 | 154 | 176 | ||||||||||||
Canadian resource allowance |
(57 | ) | (56 | ) | (173 | ) | (206 | ) | ||||||||
Canadian resource allowance on unrealized risk management losses |
13 | | 40 | | ||||||||||||
Statutory and other rate differences |
(19 | ) | 1 | (49 | ) | (23 | ) | |||||||||
Effect of tax rate changes |
| | (109 | ) | (362 | ) | ||||||||||
Non-taxable capital gains |
(55 | ) | (1 | ) | (41 | ) | (71 | ) | ||||||||
Previously unrecognized capital losses |
(5 | ) | (71 | ) | 10 | (71 | ) | |||||||||
Tax basis retained on dispositions |
(59 | ) | | (162 | ) | | ||||||||||
Large corporations tax |
6 | 8 | 13 | 25 | ||||||||||||
Other |
18 | 79 | 26 | 21 | ||||||||||||
$ | 77 | $ | 205 | $ | 122 | $ | 342 | |||||||||
Effective Tax Rate |
16.4 | % | 41.8 | % | 11.6 | % | 16.4 | % | ||||||||
15
Interim Report
|
PREPARED IN US$ | |
For the period ended September 30, 2004 |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
9. LONG-TERM DEBT
As at | As at | |||||||
September 30, | December 31, | |||||||
2004 |
2003 |
|||||||
Canadian Dollar Denominated Debt |
||||||||
Revolving credit and term loan borrowings |
$ | 1,509 | $ | 1,425 | ||||
Unsecured notes and debentures |
1,325 | 1,335 | ||||||
Preferred securities |
| 252 | ||||||
2,834 | 3,012 | |||||||
U.S. Dollar Denominated Debt |
||||||||
Revolving credit and term loan borrowings |
965 | 417 | ||||||
Unsecured notes and debentures |
4,716 | 2,713 | ||||||
Preferred securities |
| 150 | ||||||
5,681 | 3,280 | |||||||
Increase in Value of Debt Acquired * |
71 | 83 | ||||||
Current Portion of Long-Term Debt |
(550 | ) | (287 | ) | ||||
$ | 8,036 | $ | 6,088 | |||||
* Certain of the notes and debentures of the Company were acquired in business combinations and were accounted for at their fair value at the dates 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.
To fund the acquisition of Tom Brown, Inc., the Company arranged a $3 billion non-revolving term loan facility with a group of the Companys lenders. The facility size has been reduced to an outstanding amount of $846 million as at September 30, 2004. The remaining facility amount is to be reduced to $450 million by August 20, 2005 and to zero on May 20, 2006.
During the quarter, the Company completed an issue of notes under its shelf prospectus. The US$250 million notes are due in 2009 and bear interest at 4.60%. The US$750 million notes are due in 2034 and bear interest at 6.50%. The proceeds from the note issue were used to repay bank and commercial paper indebtedness. In addition, the Company also redeemed, at par value, the C$200 million 8.50% Preferred Securities and the US$150 million 9.50% Preferred Securities.
10. 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 | As at | |||||||
September 30, | December 31, | |||||||
2004 |
2003 |
|||||||
Asset Retirement Obligation, Beginning of Year |
$ | 430 | $ | 309 | ||||
Liabilities Incurred |
64 | 64 | ||||||
Liabilities Settled |
(9 | ) | (23 | ) | ||||
Liabilities Disposed |
(35 | ) | | |||||
Accretion Expense |
20 | 19 | ||||||
Other |
20 | 61 | ||||||
Asset Retirement Obligation, End of Period |
$ | 490 | $ | 430 | ||||
16
Interim Report | PREPARED IN US$ |
For the period ended September 30, 2004
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
11. SHARE CAPITAL
September 30, 2004 |
December 31, 2003 |
|||||||||||||||
(millions) |
Number |
Amount |
Number |
Amount |
||||||||||||
Common Shares Outstanding, Beginning of Year |
460.6 | $ | 5,305 | 478.9 | $ | 5,511 | ||||||||||
Shares Issued under Option Plans |
6.9 | 184 | 5.5 | 114 | ||||||||||||
Shares Repurchased |
(5.5 | ) | (77 | ) | (23.8 | ) | (320 | ) | ||||||||
Common Shares Outstanding, End of Period |
462.0 | $ | 5,412 | 460.6 | $ | 5,305 | ||||||||||
To September 30, 2004, the Company purchased, for cancellation, 5,490,000 Common Shares for total consideration of approximately C$304 million ($230 million). Of the amount paid, C$101 million ($77 million) was charged to Share capital, C$36 million ($27 million) was charged to Paid in surplus and C$167 million ($126 million) was charged to Retained earnings.
The Company has stock-based compensation plans that allow employees and directors to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. Options granted under the plans are generally fully exercisable after three years and expire five years after the grant date. Options granted under previous successor and/or related company replacement plans expire ten years from the date the options were granted.
The following tables summarize the information about options to purchase Common Shares at September 30, 2004:
Weighted Average | ||||||||
Stock Options | Exercise Price | |||||||
(millions) |
(C$) |
|||||||
Outstanding, Beginning of Year |
28.8 | 43.13 | ||||||
Exercised |
(6.9 | ) | 35.46 | |||||
Forfeited |
(0.6 | ) | 47.30 | |||||
Outstanding, End of Period |
21.3 | 45.42 | ||||||
Exercisable, End of Period |
13.4 | 43.90 | ||||||
Outstanding Options |
Exercisable Options |
|||||||||||||||||||
Number of Options | Weighted Average Remaining | Weighted Average Exercise | Number of Options Outstanding | Weighted Average | ||||||||||||||||
Range of Exercise Price (C$) |
Outstanding (millions) |
Contractual Life (years) |
Price (C$) |
(millions) |
Exercise Price (C$) |
|||||||||||||||
13.50 to 19.99 |
0.4 | 0.6 | 18.62 | 0.4 | 18.62 | |||||||||||||||
20.00 to 24.99 |
0.8 | 1.1 | 22.53 | 0.8 | 22.53 | |||||||||||||||
25.00 to 29.99 |
0.7 | 1.2 | 26.23 | 0.7 | 26.23 | |||||||||||||||
30.00 to 43.99 |
0.7 | 1.7 | 39.87 | 0.6 | 39.41 | |||||||||||||||
44.00 to 53.00 |
18.7 | 3.1 | 47.96 | 10.9 | 47.87 | |||||||||||||||
21.3 | 2.4 | 45.42 | 13.4 | 43.90 | ||||||||||||||||
The Company 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. Stock options granted in 2004 have an associated Tandem Share Appreciation Right attached. 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 for the three months ended September 30, 2004 would have been $384 million; $0.83 per common share basic; $0.82 per common share - diluted (2003 $281 million; $0.59 per common share basic; $0.59 per common share diluted). Pro forma Net Earnings and Net Earnings per Common Share for the nine months ended September 30, 2004 would have been $906 million; $1.97 per common share basic; $1.94 per common share diluted (2003 - $1,908 million; $3.99 per common share basic; $3.94 per common share - diluted).
17
Interim Report | PREPARED IN US$ |
For the period ended September 30, 2004
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
11. SHARE CAPITAL (continued)
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:
September 30, | ||||
2003 |
||||
Weighted Average Fair Value of Options Granted (C$) |
$ | 12.21 | ||
Risk Free Interest Rate |
3.89 | % | ||
Expected Lives (years) |
3.00 | |||
Expected Volatility |
0.33 | |||
Annual Dividend per Share (C$) |
$ | 0.40 |
12. COMPENSATION PLANS
The tables below outline certain information related to the Companys compensation plans at September 30, 2004. Additional information is contained in Note 16 of the Companys annual audited Consolidated Financial Statements for the year ended December 31, 2003.
A) Pensions
The following table summarizes the net benefit plan expense:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, |
September 30, |
|||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||
Current Service Cost |
$ | 1 | $ | 2 | $ | 4 | $ | 5 | ||||||||
Interest Cost |
3 | 3 | 9 | 9 | ||||||||||||
Expected Return on Plan Assets |
(2 | ) | (2 | ) | (8 | ) | (7 | ) | ||||||||
Amortization of Net Actuarial Loss |
1 | 1 | 3 | 3 | ||||||||||||
Amortization of Transitional Obligation |
| (1 | ) | (1 | ) | (2 | ) | |||||||||
Amortization of Past Service Cost |
| | 1 | 1 | ||||||||||||
Expense for Defined Contribution Plan |
3 | 3 | 10 | 9 | ||||||||||||
Net Benefit Plan Expense |
$ | 6 | $ | 6 | $ | 18 | $ | 18 | ||||||||
At September 30, 2004, $17 million has been contributed to the pension plans and the Company expects to make no additional contributions during the remainder of 2004.
B) Share Appreciation Rights (SARs)
The following table summarizes the information about SARs at September 30, 2004:
Weighted Average | ||||||||
Outstanding SARs |
Exercise Price ($) |
|||||||
Canadian
Dollar Denominated (C$)
|
||||||||
Outstanding, Beginning of Year |
1,175,070 | 35.87 | ||||||
Exercised |
(497,785 | ) | 35.15 | |||||
Forfeited |
(11,040 | ) | 29.25 | |||||
Outstanding, End of Period |
666,245 | 36.52 | ||||||
Exercisable, End of Period |
666,245 | 36.52 | ||||||
U.S. Dollar
Denominated (US$)
|
||||||||
Outstanding, Beginning of Year |
753,417 | 28.98 | ||||||
Exercised |
(279,258 | ) | 29.27 | |||||
Forfeited |
(1,472 | ) | 24.08 | |||||
Outstanding, End of Period |
472,687 | 28.82 | ||||||
Exercisable, End of Period |
472,687 | 28.82 | ||||||
18
Interim Report | PREPARED IN US$ |
For the period ended September 30, 2004
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
12. COMPENSATION PLANS (continued)
B) Share Appreciation Rights (SARs) (continued)
The following table summarizes the information about Tandem SARs at September 30, 2004:
Outstanding Tandem | Weighted Average | |||||||
SARs |
Exercise Price (C$) |
|||||||
Canadian Dollar Denominated (C$) |
||||||||
Outstanding, Beginning of Year |
| | ||||||
Granted |
976,650 | 54.58 | ||||||
Forfeited |
(77,500 | ) | 54.24 | |||||
Outstanding, End of Period |
899,150 | 54.61 | ||||||
Exercisable, End of Period |
| | ||||||
C) Deferred Share Units (DSUs)
The following table summarizes the information about DSUs at September 30, 2004:
Weighted Average | ||||||||
Outstanding DSUs |
Exercise Price (C$) |
|||||||
Canadian Dollar Denominated (C$) |
||||||||
Outstanding, Beginning of Year |
319,250 | 48.68 | ||||||
Granted, Directors |
58,145 | 53.69 | ||||||
Granted, Senior Executives |
1,686 | 57.54 | ||||||
Outstanding, End of Period |
379,081 | 49.49 | ||||||
Exercisable, End of Period |
297,874 | 51.82 | ||||||
D) Performance Share Units (PSUs)
The following table summarizes the information about PSUs at September 30, 2004:
Weighted Average | ||||||||
Outstanding PSUs |
Exercise Price ($) |
|||||||
Canadian Dollar Denominated (C$) |
||||||||
Outstanding, Beginning of Year |
126,283 | 46.52 | ||||||
Granted |
1,687,571 | 53.97 | ||||||
Forfeited |
(70,540 | ) | 53.17 | |||||
Outstanding, End of Period |
1,743,314 | 53.46 | ||||||
Exercisable, End of Period |
| | ||||||
U.S. Dollar Denominated (US$) |
||||||||
Outstanding, Beginning of Year |
| | ||||||
Granted |
249,830 | 41.12 | ||||||
Forfeited |
(19,547 | ) | 41.12 | |||||
Outstanding, End of Period |
230,283 | 41.12 | ||||||
Exercisable, End of Period |
| | ||||||
19
Interim Report | PREPARED IN US$ |
For the period ended September 30, 2004
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
13. PER SHARE AMOUNTS
The following table summarizes the Common Shares used in calculating Net Earnings per Common Share:
Three Months Ended |
Nine Months Ended |
|||||||||||||||||||||||
March 31, |
June 30, |
September 30, |
September 30, |
|||||||||||||||||||||
(millions) |
2004 |
2004 |
2004 |
2003 |
2004 |
2003 |
||||||||||||||||||
Weighted Average Common Shares Outstanding Basic |
460.9 | 460.3 | 461.7 | 473.4 | 461.0 | 478.0 | ||||||||||||||||||
Effect of Dilutive Securities |
6.2 | 5.2 | 4.5 | 4.5 | 6.1 | 5.7 | ||||||||||||||||||
Weighted Average Common Shares Outstanding Diluted |
467.1 | 465.5 | 466.2 | 477.9 | 467.1 | 483.7 | ||||||||||||||||||
14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
As a means of managing commodity price volatility, the Company has entered into various financial instrument agreements and physical contracts. The following information presents all positions for financial instruments only.
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 on 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 on 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 from January 1, 2004 to September 30, 2004:
Net Deferred | ||||||||||||||||||||
Amounts Recognized | Total Unrealized | |||||||||||||||||||
Acquired |
on Transition |
Fair Market Value |
Gain/(Loss) |
|||||||||||||||||
Fair Value of Contracts, January 1, 2004 |
(Note 2) | $ | | $ | 235 | $ | (235 | ) | $ | | ||||||||||
Fair Value of Contracts Acquired with Tom Brown, Inc., Net of Amortization |
5 | | (5 | ) | | |||||||||||||||
Change in Fair Value of Contracts Still Outstanding at September 30, 2004 |
| | (328 | ) | (328 | ) | ||||||||||||||
Fair Value of Contracts Realized During the Period |
| (242 | ) | 242 | | |||||||||||||||
Fair Value of Contracts Entered into During the Period |
| | (700 | ) | (700 | ) | ||||||||||||||
Fair Value of Contracts Outstanding |
$ | 5 | $ | (7 | ) | $ | (1,026 | ) | $ | (1,028 | ) | |||||||||
Premiums Paid on Collars and Options |
24 | |||||||||||||||||||
Fair Value of Contracts Outstanding and Premiums Paid, End of Period |
$ | (1,002 | ) | |||||||||||||||||
The total realized loss recognized in net earnings for the quarter and year-to-date ended September 30, 2004 was $256 million ($173 million, net of tax) and $664 million ($449 million, net of tax), respectively.
20
Interim Report | PREPARED IN US$ |
For the period ended September 30, 2004
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)
At September 30, 2004, the net deferred amounts recognized on transition and the risk management amounts are recorded on the Consolidated Balance Sheet as follows:
As at | ||||
September 30, 2004 |
||||
Deferred Amounts Recognized on Transition |
||||
Accounts receivable and accrued revenues |
$ | 72 | ||
Investments and other assets |
3 | |||
Accounts payable and accrued liabilities |
30 | |||
Other liabilities |
52 | |||
Total Net Deferred Loss |
$ | (7 | ) | |
Risk Management |
||||
Current asset |
$ | 84 | ||
Long-term asset |
46 | |||
Current liability |
800 | |||
Long-term liability |
332 | |||
Total Net Risk Management Liability |
$ | (1,002 | ) | |
A summary of all unrealized estimated fair value financial positions is as follows:
As at | ||||
September 30, 2004 |
||||
Commodity Price Risk |
||||
Natural gas |
$ | (500 | ) | |
Crude oil |
(537 | ) | ||
Power |
6 | |||
Foreign Currency Risk |
| |||
Interest Rate Risk |
29 | |||
$ | (1,002 | ) | ||
Information with respect to power, foreign currency risk and interest rate risk contracts in place at December 31, 2003 is disclosed in Note 17 to the Companys annual audited Consolidated Financial Statements. No significant new contracts have been entered into as at September 30, 2004.
21
Interim Report | PREPARED IN US$ |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)
Natural Gas
At September 30, 2004, the Companys gas risk management activities for financial contracts had an unrealized loss of $(495) million and a fair market value position of $(500) million. The contracts were as follows:
Notional Volumes | ||||||||||||||||||||
(MMcf/d) |
Term |
Average Price |
Fair Market Value |
|||||||||||||||||
Sales Contracts |
||||||||||||||||||||
Fixed Price Contracts |
||||||||||||||||||||
Fixed AECO price |
454 | 2004 | 6.19 | C$/Mcf | $ | (34 | ) | |||||||||||||
NYMEX Fixed price |
702 | 2004 | 5.15 | US$/Mcf | (96 | ) | ||||||||||||||
Colorado Interstate Gas (CIG) |
52 | 2004 | 5.55 | US$/Mcf | (1 | ) | ||||||||||||||
Other (1) |
162 | 2004 | 5.57 | US$/Mcf | (10 | ) | ||||||||||||||
NYMEX Fixed Price |
180 | 2005 | 5.66 | US$/Mcf | (79 | ) | ||||||||||||||
Colorado Interstate Gas (CIG) |
113 | 2005 | 4.87 | US$/Mcf | (51 | ) | ||||||||||||||
Other (1) |
110 | 2005 | 5.21 | US$/Mcf | (50 | ) | ||||||||||||||
NYMEX Fixed Price |
525 | 2006 | 5.66 | US$/Mcf | (99 | ) | ||||||||||||||
Colorado Interstate Gas (CIG) |
100 | 2006 | 4.44 | US$/Mcf | (35 | ) | ||||||||||||||
Other (1) |
171 | 2006 | 4.85 | US$/Mcf | (60 | ) | ||||||||||||||
Collars and Other Options |
||||||||||||||||||||
AECO Collars |
73 | 2004 | 5.36 - 7.54 | C$/Mcf | (3 | ) | ||||||||||||||
NYMEX Collars |
24 | 2004 | 4.45 - 5.95 | US$/Mcf | (1 | ) | ||||||||||||||
Purchased NYMEX Put Options |
33 | 2004 | 5.00 | US$/Mcf | | |||||||||||||||
Other (2) |
57 | 2004 | 4.31- 6.53 | US$/Mcf | (1 | ) | ||||||||||||||
Purchased NYMEX Put Options |
474 | 2005 | 5.00 | US$/Mcf | (17 | ) | ||||||||||||||
Other (2) |
5 | 2005 | 4.56 - 7.23 | US$/Mcf | (2 | ) | ||||||||||||||
NYMEX 3-Way Call Spread |
180 | 2005 | 5.00/6.69/7.69 | US$/Mcf | (28 | ) | ||||||||||||||
Basis Contracts |
||||||||||||||||||||
Fixed NYMEX to AECO Basis |
325 | 2004 | (0.54 | ) | US$/Mcf | 9 | ||||||||||||||
Fixed NYMEX to Rockies Basis |
303 | 2004 | (0.50 | ) | US$/Mcf | 12 | ||||||||||||||
Other (3) |
240 | 2004 | (0.39 | ) | US$/Mcf | 3 | ||||||||||||||
Fixed NYMEX to AECO Basis |
877 | 2005 | (0.66 | ) | US$/Mcf | 38 | ||||||||||||||
Fixed NYMEX to Rockies Basis |
268 | 2005 | (0.49 | ) | US$/Mcf | 21 | ||||||||||||||
Other (3) |
442 | 2005 | (0.47 | ) | US$/Mcf | 2 | ||||||||||||||
Fixed NYMEX to AECO Basis |
464 | 2006-2008 | (0.65 | ) | US$/Mcf | 22 | ||||||||||||||
Fixed NYMEX to Rockies Basis |
249 | 2006-2008 | (0.57 | ) | US$/Mcf | 6 | ||||||||||||||
Fixed NYMEX to CIG Basis |
150 | 2006-2008 | (0.76 | ) | US$/Mcf | (10 | ) | |||||||||||||
Fixed Rockies to CIG Basis |
31 | 2006-2008 | (0.10 | ) | US$/Mcf | | ||||||||||||||
Other (3) |
132 | 2006 | (0.45 | ) | US$/Mcf | (1 | ) | |||||||||||||
Purchase Contracts |
||||||||||||||||||||
Fixed Price Contracts |
||||||||||||||||||||
Waha Purchase |
30 | 2004 | 6.18 | US$/Mcf | (1 | ) | ||||||||||||||
Waha Purchase |
27 | 2005 | 5.90 | US$/Mcf | 5 | |||||||||||||||
Waha Purchase |
23 | 2006 | 5.32 | US$/Mcf | 4 | |||||||||||||||
Premiums Paid on 3-Way Call Spread |
3 | |||||||||||||||||||
Total Natural Gas Financial Positions |
(454 | ) | ||||||||||||||||||
Gas Storage Financial Positions |
(49 | ) | ||||||||||||||||||
Gas Marketing Financial Positions (4) |
3 | |||||||||||||||||||
Total Fair Value Positions |
(500 | ) | ||||||||||||||||||
Contracts Acquired |
5 | |||||||||||||||||||
Total Unrealized Loss on Financial Contracts |
$ | (495 | ) | |||||||||||||||||
(1) | Other Fixed Price Contracts relate to various price points at Chicago, San Juan, Waha, Houston Ship Channel (HSC), Mid-Continent, Rockies and Texas Oklahoma. |
(2) | Other Collars and Other Options relate to collars at Permian, San Juan, Waha, Colorado Interstate Gas (CIG), HSC, Mid-Continent, Rockies and Texas Oklahoma. |
(3) | Other Basis Contracts relate to Chicago, San Juan, CIG, HSC, Mid-Continent, Waha and Ventura. |
(4) | The gas marketing activities are part of the daily ongoing operations of the Companys proprietary production management. |
22
Interim Report | PREPARED IN US$ |
EnCana Corporation
Notes to Consolidated Financial Statements (unaudited)
(All amounts in US$ millions unless otherwise specified)
14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)
Crude Oil
At September 30, 2004, the Companys oil risk management activities for all financial contracts had an unrealized loss of $(558) million and a fair market value position of $(537) million. The contracts were as follows:
Notional Volumes | Average Price | |||||||||||||||
(bbl/d) |
Term |
(US$/bbl) |
Fair Market Value |
|||||||||||||
Fixed WTI NYMEX Price |
62,500 | 2004 | 23.13 | $ | (148 | ) | ||||||||||
Collars on WTI NYMEX |
62,500 | 2004 | 20.00-25.69 | (133 | ) | |||||||||||
Unwind WTI NYMEX Fixed Price |
(9,000 | ) | 2004 | 39.22 | 8 | |||||||||||
Purchased WTI NYMEX Call Options |
(111,000 | ) | 2004 | 46.64 | 29 | |||||||||||
Fixed WTI NYMEX Price |
45,000 | 2005 | 28.41 | (260 | ) | |||||||||||
Costless 3-Way Put Spread |
10,000 | 2005 | 20.00/25.00/28.78 | (56 | ) | |||||||||||
Unwind WTI NYMEX Fixed Price |
(4,500 | ) | 2005 | 35.90 | 14 | |||||||||||
Purchased WTI NYMEX Call Options |
(38,000 | ) | 2005 | 49.76 | 18 | |||||||||||
Fixed WTI NYMEX Price |
15,000 | 2006 | 34.56 | (27 | ) | |||||||||||
Purchased WTI NYMEX Put Options |
17,000 | 2006 | 26.59 | (3 | ) | |||||||||||
(558 | ) | |||||||||||||||
Crude Oil Marketing Financial
Positions (1) |
| |||||||||||||||
Total Unrealized Loss on Financial Contracts |
(558 | ) | ||||||||||||||
Premiums Paid on Call Options |
21 | |||||||||||||||
Total Fair Value Positions |
$ | (537 | ) | |||||||||||||
(1) | The crude oil marketing activities are part of the daily ongoing operations of the Companys proprietary production management. |
15. COMMITMENTS AND CONTINGENCIES
Ecuador
In Ecuador, a subsidiary of the Company has a 40 percent economic interest in relation to Block 15 pursuant to a contract with a subsidiary of Occidental Petroleum Corporation. During the third quarter, 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 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.
16. RECLASSIFICATION
Certain information provided for prior periods has been reclassified to conform to the presentation adopted in 2004.
23
EnCana Corporation
Managements Discussion and Analysis
October 26, 2004
This Managements Discussion and Analysis (MD&A) for EnCana Corporation (EnCana or the Company) should be read in conjunction with the unaudited interim Consolidated Financial Statements (Interim Consolidated Financial Statements) for the three and nine months ended September 30, 2004, as well as the audited Consolidated Financial Statements and MD&A for the year ended December 31, 2003. Readers are referred to the legal advisory detailing Note Regarding Forward-Looking Statements contained in the back of this MD&A. Certain definitions used in this MD&A are defined in the sections found at the back of this MD&A entitled Note Regarding Oil and Gas Information and Note Regarding Currency, Protocols and Non-GAAP Measures. The Interim Consolidated Financial Statements and comparative information have been prepared in accordance with Canadian GAAP in the currency of the United States (except where indicated as being in another currency). The production and sales volumes in this MD&A and the supplementary information in the Interim Consolidated Financial Statements, have been presented on an after royalties basis consistent with U.S. protocol reporting. This MD&A is dated October 26, 2004.
OVERVIEW
Summary of Key Events and Key Financial Results in the Third Quarter
Third quarter 2004 compared to third quarter 2003:
| Upstream sales volumes increased by 22 percent to 780,741 BOE per day. |
| North American natural gas prices (excluding financial hedges), averaged $5.18 per Mcf in 2004 compared to $4.66 per Mcf in 2003, an increase of 11 per cent. |
| Liquids prices (excluding financial hedges), averaged $32.83 per barrel in 2004 compared to $21.22 in 2003, an increase of 55 percent. |
| Operating expenses and corporate administration costs decreased on a BOE basis by $0.15 and $0.10 respectively. |
| As part of the continuing alignment of the North American assets with EnCanas unconventional resource play strategy the Company completed $940 million in mature conventional property dispositions. |
| Reduction in long-term debt (including current portion) during the third quarter in 2004 of $729 million. |
| Realized financial commodity and currency hedge losses of approximately $265 million ($180 million after-tax) in 2004 compared to a $58 million ($40 million after-tax) loss for 2003. |
| Mark-to-market accounting for derivative instruments resulted in a $497 million ($321 million after-tax) charge to earnings for unrealized losses in 2004 with no corresponding amount in 2003 since mark-to-market accounting was adopted as of January 1, 2004. |
| A $193 million ($155 million after-tax) unrealized gain on Canadian issued U.S. dollar debt in 2004 compared to an unrealized gain of $15 million ($12 million after-tax) in 2003. |
| A $95 million ($79 million after-tax) realized foreign exchange gain in 2004 compared to a realized gain of $5 million ($3 million after-tax) in 2003. |
| Current income tax provision increased to $124 million in 2004 compared to a tax provision of $51 million in 2003, for a total increase in cash taxes of $73 million. |
- 1 -
CONSOLIDATED FINANCIAL RESULTS
Three Months Ended | Nine Months Ended | Year | ||||||||||||||||||||||||||
September 30 |
September 30 |
Ended |
||||||||||||||||||||||||||
Consolidated Financial Summary | 2004 vs | 2004 vs | ||||||||||||||||||||||||||
($ millions, except per share amounts) |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2003 |
|||||||||||||||||||||
Revenues, Net of Royalties |
$ | 2,458 | 7 | % | $ | 2,291 | $ | 8,026 | 9 | % | $ | 7,366 | $ | 10,216 | ||||||||||||||
Net Earnings from Continuing Operations |
393 | 37 | % | 286 | 933 | -46 | % | 1,741 | 2,167 | |||||||||||||||||||
- per share - basic |
0.85 | 42 | % | 0.60 | 2.02 | -45 | % | 3.64 | 4.57 | |||||||||||||||||||
- per share - diluted |
0.84 | 40 | % | 0.60 | 2.00 | -44 | % | 3.60 | 4.52 | |||||||||||||||||||
Net Earnings |
393 | 36 | % | 290 | 933 | -52 | % | 1,934 | 2,360 | |||||||||||||||||||
- per share - basic |
0.85 | 39 | % | 0.61 | 2.02 | -50 | % | 4.05 | 4.98 | |||||||||||||||||||
- per share - diluted |
0.84 | 38 | % | 0.61 | 2.00 | -50 | % | 4.00 | 4.92 | |||||||||||||||||||
Operating Earnings (1) |
559 | 104 | % | 274 | 1,403 | 32 | % | 1,059 | 1,375 | |||||||||||||||||||
- per share - diluted |
1.20 | 111 | % | 0.57 | 3.00 | 37 | % | 2.19 | 2.87 | |||||||||||||||||||
Cash Flow from Continuing Operations (2) |
1,363 | 40 | % | 973 | 3,489 | 9 | % | 3,203 | 4,420 | |||||||||||||||||||
- per share - basic |
2.95 | 43 | % | 2.06 | 7.57 | 13 | % | 6.70 | 9.32 | |||||||||||||||||||
- per share - diluted |
2.92 | 43 | % | 2.04 | 7.47 | 13 | % | 6.62 | 9.21 | |||||||||||||||||||
Cash Flow (2) |
1,363 | 40 | % | 977 | 3,489 | 9 | % | 3,205 | 4,459 | |||||||||||||||||||
- per share - basic |
2.95 | 43 | % | 2.06 | 7.57 | 13 | % | 6.71 | 9.41 | |||||||||||||||||||
- per share - diluted |
2.92 | 43 | % | 2.04 | 7.47 | 13 | % | 6.63 | 9.30 |
(1) | Operating Earnings is a non- GAAP measure and is described and discussed under Operating Earnings in this MD&A. | |
(2) | Cash Flow from Continuing Operations and Cash Flow are non- GAAP measures and are discussed under Cash Flow in this MD&A. |
Quarterly Summary
2004 |
2003 |
2002 |
||||||||||||||||||||||||||||||
($ millions, except per share amounts) |
Q3 |
Q2 |
Q1 |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
||||||||||||||||||||||||
Revenues, Net of Royalties |
$ | 2,458 | $ | 2,718 | $ | 2,850 | $ | 2,850 | $ | 2,291 | $ | 2,332 | $ | 2,743 | $ | 2,116 | ||||||||||||||||
Net Earnings from Continuing Operations |
393 | 250 | 290 | 426 | 286 | 805 | 650 | 248 | ||||||||||||||||||||||||
- per share - basic |
0.85 | 0.54 | 0.63 | 0.92 | 0.60 | 1.67 | 1.35 | 0.52 | ||||||||||||||||||||||||
- per share - diluted |
0.84 | 0.54 | 0.62 | 0.91 | 0.60 | 1.66 | 1.34 | 0.51 | ||||||||||||||||||||||||
Net Earnings |
393 | 250 | 290 | 426 | 290 | 807 | 837 | 282 | ||||||||||||||||||||||||
- per share - basic |
0.85 | 0.54 | 0.63 | 0.92 | 0.61 | 1.68 | 1.74 | 0.59 | ||||||||||||||||||||||||
- per share - diluted |
0.84 | 0.54 | 0.62 | 0.91 | 0.61 | 1.67 | 1.73 | 0.58 | ||||||||||||||||||||||||
Operating Earnings (1) |
559 | 379 | 465 | 316 | 274 | 275 | 510 | 239 | ||||||||||||||||||||||||
- per share - diluted |
1.20 | 0.81 | 1.00 | 0.68 | 0.57 | 0.56 | 1.05 | 0.49 | ||||||||||||||||||||||||
Cash Flow from Continuing Operations (2) |
1,363 | 1,131 | 995 | 1,217 | 973 | 1,039 | 1,191 | 874 | ||||||||||||||||||||||||
- per share - basic |
2.95 | 2.46 | 2.16 | 2.63 | 2.06 | 2.16 | 2.48 | 1.83 | ||||||||||||||||||||||||
- per share - diluted |
2.92 | 2.43 | 2.13 | 2.61 | 2.04 | 2.14 | 2.46 | 1.81 | ||||||||||||||||||||||||
Cash Flow (2) |
1,363 | 1,131 | 995 | 1,254 | 977 | 1,007 | 1,221 | 935 | ||||||||||||||||||||||||
- per share - basic |
2.95 | 2.46 | 2.16 | 2.71 | 2.06 | 2.10 | 2.54 | 1.96 | ||||||||||||||||||||||||
- per share - diluted |
2.92 | 2.43 | 2.13 | 2.69 | 2.04 | 2.08 | 2.52 | 1.94 |
(1) | Operating Earnings is a non- GAAP measure and is described and discussed under Operating Earnings in this MD&A. | |
(2) | Cash Flow from Continuing Operations and Cash Flow are non- GAAP measures and are discussed under Cash Flow in this MD&A. |
- 2 -
Cash Flow
EnCanas cash flow from continuing operations increased $390 million, or $0.88 per share diluted, in the third quarter of 2004 compared to the same period in 2003 and increased $286 million, or $0.85 per share diluted, during the first nine months of 2004 compared to the first nine months in 2003. Significant items are as follows:
Third quarter 2004 compared to third quarter 2003:
| Natural gas sales volumes increased 24 percent to 3,128 MMcf per day. |
| Crude oil and NGLs sales volumes increased 19 percent to 259,408 barrels per day. |
| North American natural gas prices (excluding financial hedges), were $5.18 per Mcf in 2004 compared to $4.66 per Mcf in 2003, an increase of 11 percent. |
| Liquids prices (excluding financial hedges), are $32.83 per barrel in 2004 compared to $21.22 in 2003, an increase of 55 percent. |
| Operating expenses are $3.38 per BOE in 2004 compared to $3.53 per BOE in 2003, a decrease of $0.15 per BOE. |
| Corporate administration costs are $0.60 per BOE in 2004 compared to $0.70 per BOE in 2003, a reduction of $0.10 per BOE. |
| Realized financial commodity and currency hedge losses are approximately $265 million ($180 million after-tax) in 2004 (comprised of $0.15 per Mcf on natural gas and $9.28 per barrel on liquids) compared to $58 million ($40 million after-tax) for 2003 (comprised of $0.06 per Mcf on natural gas and $2.18 per barrel on liquids). |
| A $95 million ($79 million after-tax) realized foreign exchange gain in 2004 compared to a realized gain of $5 million ($3 million after-tax) in 2003 primarily as a result of the rise in the U.S./Canadian dollar exchange rate and its impact on Canadian issued U.S. denominated debt. |
| Current tax provision increased by $73 million to $124 million in 2004 from $51 million in 2003 partially offsetting increased cash flow from higher volumes and prices. |
Nine months ended September 2004 compared to nine months ended September 2003:
| Crude oil and NGLs sales volumes increased 27 percent to 264,672 barrels per day. |
| Natural gas sales volumes increased 17 percent to 2,960 MMcf per day. |
| North American natural gas prices (excluding financial hedges), are $5.26 per Mcf in 2004 compared to $5.01 per Mcf in 2003, an increase of 5 percent. |
| Liquids prices (excluding financial hedges), are $28.67 per barrel in 2004 compared to $23.57 in 2003, an increase of 22 percent. |
| Realized financial commodity and currency hedge losses are approximately $648 million ($439 million after-tax) in 2004 (comprised of $0.16 per Mcf on natural gas and $7.11 per barrel on liquids) compared to $283 million ($194 million after-tax) for 2003 (comprised of $0.19 per Mcf on natural gas and $2.71 per barrel on liquids). |
| An $87 million ($71 million after-tax) realized foreign exchange gain in 2004 compared to a realized gain of $32 million ($18 million after-tax) in 2003 primarily as a result of the rise in the U.S./Canadian dollar exchange rate and its impact on Canadian issued U.S. denominated debt. |
| Current tax provision increased by $542 million to $559 million in 2004 from $17 million in 2003 partially offsetting increased cash flow from higher volumes and prices. |
Cash flow is a non-GAAP measure but is 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 Interim Consolidated Financial Statements.
Net Earnings
EnCanas net earnings from continuing operations increased $107 million, or $0.24 per share diluted in the third quarter of 2004 compared to the same period in 2003 and decreased $808 million, or $1.60 per share diluted during the first nine months of 2004 compared to the first nine months in 2003. In addition to the items affecting cash flow as detailed previously, significant items are:
- 3 -
Third quarter 2004 compared to third quarter 2003:
| Mark-to-market accounting for derivative instruments resulted in a $497 million ($321 million after-tax, $0.69 per share diluted) charge to earnings for unrealized losses in 2004 with no corresponding amount in 2003. |
| A $193 million ($155 million after-tax, $0.33 per share diluted) unrealized gain on Canadian issued U.S. dollar debt in 2004 compared to an unrealized gain of $15 million ($12 million after-tax, $0.03 per share diluted) in 2003 as a result of a larger increase in the period end U.S./Canadian dollar exchange rate between June 30, 2004 and September 30, 2004 compared to the same period in 2003. |
Nine months ended September 2004 compared to nine months ended September 2003:
| Unrealized mark-to-market losses of $1,028 million ($677 million after-tax, $1.44 per share diluted) 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 or $0.23 per share diluted, compared to a gain of $362 million, or $0.75 per share diluted, in 2003. |
| A $122 million ($98 million after-tax, $0.21 per share diluted) unrealized gain on Canadian issued U.S. dollar debt in 2004 compared to an unrealized gain of $404 million ($320 million after-tax, $0.66 per share diluted) in 2003 as a result of a small increase in the period end U.S./Canadian dollar exchange rate between December 31, 2003 and September 30, 2004 compared to significant appreciation in the period end U.S./Canadian dollar exchange rate between December 31, 2002 and September 30, 2003. |
Net earnings in the third quarter of 2003 include $4 million, or $0.01 per share diluted, from discontinued operations and on a year-to-date basis net earnings in 2003 include $193 million, or $0.40 per share diluted, from discontinued operations.
Impacts on results due to the change in the U.S./Canadian dollar exchange rate need to be considered when analyzing specific components contained in the Interim Consolidated Financial Statements. For every 100 dollars denominated in Canadian currency spent on capital projects, operating expenses and administrative expenses, the Company incurred additional costs, as reported in U.S. dollars, of approximately $4.00 ($5.20 year-to-date) based on the increase in the average U.S./Canadian dollar exchange rate from the third quarter of 2003 of $0.725 ($0.701 year-to-date) to the third quarter of 2004 of $0.765 ($0.753 year-to-date). Revenues were relatively unaffected by the increased exchange rate since commodity prices received are largely based in U.S. dollars or in Canadian dollar prices which are closely tied to the value of the U.S. dollar.
Operating Earnings
Operating earnings is a non-GAAP measure that shows net earnings from continuing operations excluding the after-tax effects of unrealized mark-to-market accounting for derivative instruments, the gain/loss on translation of U.S. dollar denominated debt issued in Canada and the effect of the reduction in income tax rates. The following table has been prepared in order to provide shareholders and potential investors with information clearly presenting the effect on the Companys results of mark-to-market accounting for derivative financial instruments, the translation of the outstanding U.S. dollar debt issued in Canada and the effect of the reduction in the Canadian and Alberta tax rates. Management believes these items reduce the comparability of the Companys underlying financial performance between periods. The majority of the unrealized gains/losses on U.S. dollar debt issued in Canada relate to debt with maturity dates in excess of five years.
- 4 -
Quarterly Summary of Operating Earnings
2004 |
2003 |
2002 |
||||||||||||||||||||||||||||||
($ millions) |
Q3 |
Q2 |
Q1 |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
||||||||||||||||||||||||
Net Earnings from Continuing Operations, as reported |
$ | 393 | $ | 250 | $ | 290 | $ | 426 | $ | 286 | $ | 805 | $ | 650 | $ | 248 | ||||||||||||||||
Add: Unrealized mark-to-market accounting loss (after-tax) (2) |
321 | 104 | 252 | | | | | | ||||||||||||||||||||||||
Add: Unrealized foreign exchange (gain) loss on translation of
Canadian issued U.S. dollar debt (after-tax) |
(155 | ) | 25 | 32 | (113 | ) | (12 | ) | (168 | ) | (140 | ) | (6 | ) | ||||||||||||||||||
Add: Future tax (recovery) expense due to tax rate reductions |
| | (109 | ) | 3 | | (362 | ) | | (3 | ) | |||||||||||||||||||||
Operating Earnings (1)(3) |
$ | 559 | $ | 379 | $ | 465 | $ | 316 | $ | 274 | $ | 275 | $ | 510 | $ | 239 | ||||||||||||||||
($ per Common Share - Diluted) |
||||||||||||||||||||||||||||||||
Net Earnings from Continuing Operations, as reported |
$ | 0.84 | $ | 0.54 | $ | 0.62 | $ | 0.91 | $ | 0.60 | $ | 1.66 | $ | 1.34 | $ | 0.51 | ||||||||||||||||
Add: Unrealized mark-to-market accounting loss (after-tax) (2) |
0.69 | 0.22 | 0.54 | | | | | | ||||||||||||||||||||||||
Add: Unrealized foreign exchange (gain) loss on translation of
Canadian issued U.S. dollar debt (after-tax) |
(0.33 | ) | 0.05 | 0.07 | (0.24 | ) | (0.03 | ) | (0.35 | ) | (0.29 | ) | (0.01 | ) | ||||||||||||||||||
Add: Future tax (recovery) expense due to tax rate reductions |
| | (0.23 | ) | 0.01 | | (0.75 | ) | | (0.01 | ) | |||||||||||||||||||||
Operating Earnings (1)(3) |
$ | 1.20 | $ | 0.81 | $ | 1.00 | $ | 0.68 | $ | 0.57 | $ | 0.56 | $ | 1.05 | $ | 0.49 | ||||||||||||||||
(1) | Operating Earnings 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)/loss 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 January 1, 2004. See Note 2 of the Interim Consolidated Financial Statements. | |
(3) | Unrealized (gains)/losses have no impact on cash flow. |
Year-to-Date Summary of Operating Earnings
Three Months Ended September 30 |
Nine Months Ended September 30 |
|||||||||||||||||||||||
2004 vs | 2004 vs | |||||||||||||||||||||||
($ millions) |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
||||||||||||||||||
Net Earnings from Continuing Operations, as reported |
$ | 393 | 37 | % | $ | 286 | $ | 933 | -46 | % | $ | 1,741 | ||||||||||||
Add: Unrealized mark-to-market accounting loss (after-tax) (2) |
321 | | | 677 | | | ||||||||||||||||||
Add: Unrealized foreign exchange (gain) loss on translation of
Canadian issued U.S. dollar debt (after-tax) |
(155 | ) | 1192 | % | (12 | ) | (98 | ) | -69 | % | (320 | ) | ||||||||||||
Add: Future tax (recovery) expense due to tax rate reductions |
| | | (109 | ) | -70 | % | (362 | ) | |||||||||||||||
Operating Earnings (1)(3) |
$ | 559 | 104 | % | $ | 274 | $ | 1,403 | 32 | % | $ | 1,059 | ||||||||||||
($ per Common Share - Diluted) |
||||||||||||||||||||||||
Net Earnings from Continuing Operations, as reported |
$ | 0.84 | 40 | % | $ | 0.60 | $ | 2.00 | -44 | % | $ | 3.60 | ||||||||||||
Add: Unrealized mark-to-market accounting loss (after-tax) (2) |
0.69 | | | 1.44 | | | ||||||||||||||||||
Add: Unrealized foreign exchange (gain) loss on translation of
Canadian issued U.S. dollar debt (after-tax) |
(0.33 | ) | 1000 | % | (0.03 | ) | (0.21 | ) | -68 | % | (0.66 | ) | ||||||||||||
Add: Future tax (recovery) expense due to tax rate reductions |
| | | (0.23 | ) | -69 | % | (0.75 | ) | |||||||||||||||
Operating Earnings (1)(3) |
$ | 1.20 | 111 | % | $ | 0.57 | $ | 3.00 | 37 | % | $ | 2.19 | ||||||||||||
(1) | Operating Earnings 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)/loss on translation of U.S. dollar denominated debt issued in Cana da and the effect of the reduction in income tax rates. | |
(2) | The Company adopted mark-to-market accounting on derivative financial instruments prospectively January 1, 2004. See Note 2 of the Interim Consolidated Financial Statements. | |
(3) | Unrealized (gains)/losses have no impact on cash flow. | |
- 5 - |
Cash Flow from Continuing Operations and Current Income Tax
Changes to cash flow from continuing operations, when comparing 2004 to prior periods are significantly impacted by changes in the provision for current income tax. The following table has been prepared to disclose the quarterly cash flow from continuing operations and the current income tax provision.
($ millions) |
2004 |
2003 |
2002 |
|||||||||||||||||||||||||||||
Q3 |
Q2 |
Q1 |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
|||||||||||||||||||||||||
Cash Flow from Continuing Operations |
$ | 1,363 | $ | 1,131 | $ | 995 | $ | 1,217 | $ | 973 | $ | 1,039 | $ | 1,191 | $ | 874 | ||||||||||||||||
Current Income Tax(1) |
$ | 124 | $ | 203 | $ | 232 | $ | (73 | ) | $ | 51 | $ | (54 | ) | $ | 20 | $ | (107 | ) | |||||||||||||
(1) | Amount deducted (added) in determining Cash Flow from Continuing Operations. |
Current income tax is discussed in the Corporate area under Results of Operations in this MD&A.
RESULTS OF OPERATIONS
Upstream Operations
Financial Results ($ millions)
Three Months Ended September 30 |
2004 |
2003 |
||||||||||||||||||||||||||||||
Produced | Crude Oil | Produced | Crude Oil | |||||||||||||||||||||||||||||
Gas |
and NGLs |
Other |
Total |
Gas |
and NGLs |
Other |
Total |
|||||||||||||||||||||||||
Revenues, Net of Royalties |
$ | 1,442 | $ | 562 | $ | 66 | $ | 2,070 | $ | 1,067 | $ | 384 | $ | 58 | $ | 1,509 | ||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||
Production and mineral taxes |
69 | 28 | | 97 | 40 | (7 | ) | | 33 | |||||||||||||||||||||||
Transportation and selling |
102 | 38 | | 140 | 94 | 20 | | 114 | ||||||||||||||||||||||||
Operating |
131 | 113 | 60 | 304 | 107 | 100 | 51 | 258 | ||||||||||||||||||||||||
Operating Cash Flow |
$ | 1,140 | $ | 383 | $ | 6 | $ | 1,529 | $ | 826 | $ | 271 | $ | 7 | $ | 1,104 | ||||||||||||||||
Depreciation, depletion and amortization |
672 | 502 | ||||||||||||||||||||||||||||||
Upstream Income |
$ | 857 | $ | 602 | ||||||||||||||||||||||||||||
Nine Months Ended September 30 |
2004 |
2003 |
||||||||||||||||||||||||||||||
Produced | Crude Oil | Produced | Crude Oil | |||||||||||||||||||||||||||||
Gas |
and NGLs |
Other |
Total |
Gas |
and NGLs |
Other |
Total |
|||||||||||||||||||||||||
Revenues, Net of Royalties |
$ | 4,121 | $ | 1,562 | $ | 170 | $ | 5,853 | $ | 3,318 | $ | 1,186 | $ | 147 | $ | 4,651 | ||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||
Production and mineral taxes |
188 | 70 | | 258 | 110 | 21 | | 131 | ||||||||||||||||||||||||
Transportation and selling |
334 | 114 | | 448 | 255 | 76 | | 331 | ||||||||||||||||||||||||
Operating |
377 | 329 | 155 | 861 | 301 | 284 | 134 | 719 | ||||||||||||||||||||||||
Operating Cash Flow |
$ | 3,222 | $ | 1,049 | $ | 15 | $ | 4,286 | $ | 2,652 | $ | 805 | $ | 13 | $ | 3,470 | ||||||||||||||||
Depreciation, depletion and amortization |
1,947 | 1,444 | ||||||||||||||||||||||||||||||
Upstream Income |
$ | 2,339 | $ | 2,026 | ||||||||||||||||||||||||||||
Consolidated Upstream Results
Overall results reflect a 22 percent increase in sales volumes of 141,418 BOE per day during the third quarter 2004 and a 21 percent increase in sales volumes of 129,069 BOE per day for the nine months ended September 30, 2004 compared with the same periods in 2003.
Revenues, net of royalties reflects the increase in natural gas and crude oil benchmark prices (see the Business Environment section of this MD&A) for both the third quarter and year-to-date results offset by the realized hedging losses. The effect of realized commodity and currency hedging losses was $265 million, or $3.69 per BOE, in the third
- 6 -
quarter 2004 compared to $58 million, or $0.99 per BOE, in the three month period ended September 30, 2003. For the nine months ended September 30, 2004, realized commodity and currency hedge losses were $648 million, or $3.12 per BOE, compared to $283 million or $1.65 per BOE, for the same period in 2003.
Operating expenses in the third quarter of 2004 averaged $3.38 per BOE compared to $3.53 per BOE in 2003. For the nine months ended September 30, 2004, operating expenses were relatively unchanged at $3.39 per BOE compared to $3.41 per BOE for the same period in 2003.
Depreciation, depletion and amortization (DD&A) expense increased by $170 million in the third quarter of 2004 and $503 million year-to-date September 30, 2004, compared to the same periods in 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 BOE basis, excluding Other activities, DD&A rates were $9.27 per BOE for the third quarter of 2004 compared to $8.49 per BOE in the same period of 2003. DD&A rates were $9.23 per BOE for the first nine months of 2004 compared to $8.38 per BOE in the same period of 2003. Increased DD&A rates in the third quarter and on a year-to-date basis in 2004 were primarily the result of the increase in the average U.S./Canadian dollar exchange rate and the acquisition of Tom Brown Inc. (TBI). DD&A rates for the nine months ended September 30, 2004 exclude the impairment of an Upstream international exploration prospect in Ghana which was recorded and disclosed in the second quarter of 2004.
Revenue Variances for 2004 Compared to 2003 ($ millions) (1)
Three Months Ended September 30 |
Nine Months Ended September 30 |
|||||||||||||||||||||||||||||||
2003 | 2004 | 2003 | 2004 | |||||||||||||||||||||||||||||
Revenues, | Revenue Variances | Revenues, | Revenues, | Revenue Variances | Revenues, | |||||||||||||||||||||||||||
Net of | in: | Net of | Net of | in: | Net of | |||||||||||||||||||||||||||
Royalties |
Price (2) |
Volume |
Royalties |
Royalties |
Price(2) |
Volume |
Royalties |
|||||||||||||||||||||||||
Produced Gas |
||||||||||||||||||||||||||||||||
Canada |
$ | 806 | $ | 62 | $ | 102 | $ | 970 | $ | 2,534 | $ | 132 | $ | 221 | $ | 2,887 | ||||||||||||||||
United States |
259 | 32 | 171 | 462 | 776 | 45 | 377 | 1,198 | ||||||||||||||||||||||||
U.K. North Sea |
2 | | 8 | 10 | 8 | 4 | 24 | 36 | ||||||||||||||||||||||||
Total Produced Gas |
$ | 1,067 | $ | 94 | $ | 281 | $ | 1,442 | $ | 3,318 | $ | 181 | $ | 622 | $ | 4,121 | ||||||||||||||||
Crude Oil and NGLs |
||||||||||||||||||||||||||||||||
Canada |
$ | 266 | $ | 64 | $ | (17 | ) | $ | 313 | $ | 809 | $ | 55 | $ | 19 | $ | 883 | |||||||||||||||
United States |
22 | 10 | 18 | 50 | 69 | 19 | 27 | 115 | ||||||||||||||||||||||||
Ecuador |
81 | 4 | 74 | 159 | 243 | (44 | ) | 233 | 432 | |||||||||||||||||||||||
U.K. North Sea |
15 | 1 | 24 | 40 | 65 | (3 | ) | 70 | 132 | |||||||||||||||||||||||
Total Crude Oil and NGLs |
$ | 384 | $ | 79 | $ | 99 | $ | 562 | $ | 1,186 | $ | 27 | $ | 349 | $ | 1,562 | ||||||||||||||||
(1) | Includes continuing operations only. | |
(2) | Includes realized commodity hedging impacts. |
The increase in sales volumes accounts for approximately 69 percent of the change in revenues, net of royalties in the third quarter of 2004 and approximately 82 percent for the first nine months of 2004. In the table above, impacts from price changes are reduced as a result of the period over period changes in realized commodity and currency hedge losses mentioned previously.
- 7 -
Quarterly Sales Volumes | ||||||||||||||||||||||||||||||||
(After Royalties) |
2004 |
2003 |
2002 |
|||||||||||||||||||||||||||||
Q3(4) |
Q2 |
Q1 |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
|||||||||||||||||||||||||
Produced Gas (MMcf per day) |
||||||||||||||||||||||||||||||||
Canada |
||||||||||||||||||||||||||||||||
Production |
2,138 | 2,177 | 2,000 | 2,008 | 1,914 | 1,899 | 1,922 | 1,943 | ||||||||||||||||||||||||
Inventory withdrawal |
| | | | | | 120 | 117 | ||||||||||||||||||||||||
Canada Sales (5) |
2,138 | 2,177 | 2,000 | 2,008 | 1,914 | 1,899 | 2,042 | 2,060 | ||||||||||||||||||||||||
United States (5) |
958 | 824 | 684 | 654 | 604 | 558 | 534 | 516 | ||||||||||||||||||||||||
United Kingdom |
32 | 36 | 28 | 20 | 7 | 12 | 13 | 8 | ||||||||||||||||||||||||
3,128 | 3,037 | 2,712 | 2,682 | 2,525 | 2,469 | 2,589 | 2,584 | |||||||||||||||||||||||||
Oil and NGLs (bbls per day) (1) |
||||||||||||||||||||||||||||||||
Canada Sales (5) |
154,726 | 157,935 | 156,640 | 164,859 | 163,179 | 149,292 | 148,147 | 148,196 | ||||||||||||||||||||||||
United States (5) |
14,947 | 12,752 | 9,237 | 9,612 | 9,691 | 10,376 | 8,148 | 10,162 | ||||||||||||||||||||||||
Ecuador |
||||||||||||||||||||||||||||||||
Production |
76,567 | 78,376 | 76,320 | 72,731 | 54,582 | 36,754 | 39,893 | 34,856 | ||||||||||||||||||||||||
Transferred to OCP Pipeline (2) |
| | | | (4,919 | ) | (2,039 | ) | (5,941 | ) | | |||||||||||||||||||||
Over / (under) lifting |
(1,721 | ) | (73 | ) | 4,662 | 4,621 | (9,856 | ) | 2,506 | (2,679 | ) | 1,044 | ||||||||||||||||||||
Ecuador Sales |
74,846 | 78,303 | 80,982 | 77,352 | 39,807 | 37,221 | 31,273 | 35,900 | ||||||||||||||||||||||||
United Kingdom |
14,889 | 20,728 | 18,088 | 15,067 | 5,813 | 9,019 | 10,610 | 7,786 | ||||||||||||||||||||||||
259,408 | 269,718 | 264,947 | 266,890 | 218,490 | 205,908 | 198,178 | 202,044 | |||||||||||||||||||||||||
Total (BOE per day) (3) |
780,741 | 775,885 | 716,947 | 713,890 | 639,323 | 617,408 | 629,678 | 632,711 | ||||||||||||||||||||||||
(1) | NGLs include Condensate. | |
(2) | Crude oil product ion in Ecuador transferred to the OCP Pipeline for use by OCP in asset commissioning. | |
(3) | Natural gas converted to BOE at 6 Mcf = 1 BOE. | |
(4) | Quarterly volumes reflect decreases as a result of the 2004 property dispositions of 81 MMcf/d in natural gas and 22 Mbbls/d of liquids or a total of approximately 36 MBOE/d. | |
(5) | Includes Tom Brown, Inc. sales volumes in 2004: |
Natural Gas (MMcf/d) |
Oil and NGLs (bbls/d) |
|||||||||||||||
Q3 |
Q2 |
Q3 |
Q2 |
|||||||||||||
Canada |
18 | 9 | 923 | 511 | ||||||||||||
United States |
257 | 123 | 4,949 | 2,689 | ||||||||||||
Total Volumes |
275 | 132 | 5,872 | 3,200 | ||||||||||||
- 8 -
Year-to-Date Sales Volumes Ended September 30
(After Royalties) |
Three Months Ended September 30 |
Nine Months Ended September 30 |
||||||||||||||||||||||
2004 vs | 2004 vs | |||||||||||||||||||||||
2004(4) |
2003 |
2003 |
2004(5) |
2003 |
2003 |
|||||||||||||||||||
Produced Gas (MMcf per day) |
||||||||||||||||||||||||
Canada |
||||||||||||||||||||||||
Production |
2,138 | 12 | % | 1,914 | 2,105 | 10 | % | 1,913 | ||||||||||||||||
Inventory withdrawal |
| | | | | 38 | ||||||||||||||||||
Canada Sales (6) |
2,138 | 12 | % | 1,914 | 2,105 | 8 | % | 1,951 | ||||||||||||||||
United States (6) |
958 | 59 | % | 604 | 823 | 45 | % | 566 | ||||||||||||||||
United Kingdom |
32 | 357 | % | 7 | 32 | 191 | % | 11 | ||||||||||||||||
3,128 | 24 | % | 2,525 | 2,960 | 17 | % | 2,528 | |||||||||||||||||
Oil and NGLs (bbls per day) (1) |
||||||||||||||||||||||||
Canada Sales (6) |
154,726 | -5 | % | 163,179 | 156,428 | 2 | % | 153,595 | ||||||||||||||||
United States (6) |
14,947 | 54 | % | 9,691 | 12,322 | 31 | % | 9,413 | ||||||||||||||||
Ecuador |
||||||||||||||||||||||||
Production |
76,567 | 40 | % | 54,582 | 77,086 | 76 | % | 43,797 | ||||||||||||||||
Transferred to OCP Pipeline (2) |
| | (4,919 | ) | | | (4,296 | ) | ||||||||||||||||
Over / (under) lifting |
(1,721 | ) | | (9,856 | ) | 946 | | (3,369 | ) | |||||||||||||||
Ecuador Sales |
74,846 | 88 | % | 39,807 | 78,032 | 116 | % | 36,132 | ||||||||||||||||
United Kingdom |
14,889 | 156 | % | 5,813 | 17,890 | 111 | % | 8,463 | ||||||||||||||||
259,408 | 19 | % | 218,490 | 264,672 | 27 | % | 207,603 | |||||||||||||||||
Total (BOE per day) (3) |
780,741 | 22 | % | 639,323 | 758,005 | 21 | % | 628,936 | ||||||||||||||||
(1) | NGLs include Condensate. | |
(2) | Crude oil production in Ecuador transferred to the OCP Pipeline for use by OCP in asset commissioning. | |
(3) | Natural gas converted to BOE at 6 Mcf = 1 BOE. | |
(4) | Quarterly volumes reflect decreases as a result of the 2004 property dispositions of 81 MMcf/d in natural gas and 22 Mbbls/d of liquids or a total of approximately 36 MBOE/d. | |
(5) | Year-to-date volumes reflect decreases as a result of the 2004 property dispositions of 41 MMcf/d in natural gas and 16 Mbbls/d of liquids or a total of approximately 23 MBOE/d. | |
(6) | 2004 Includes sales volumes from the acquisition of TBI. For the three months ended September 30 sales volumes from North America included 275 MMcf/d of natural gas and 5,872 bbls/d of liquids. For the nine months ended September 30 sales volumes from North America included 136 MMcf/ d of natural gas and 3,035 bbls/d of liquids. |
On a year-to-date basis, 2004 volumes are higher by 21 percent, or 129,069 BOE per day, compared to 2003. Increases in Canadian natural gas sales volumes in the third quarter and on a year-to-date basis in 2004 were primarily the result of successful resource play drilling programs at Greater Sierra and Cutbank Ridge in northeast British Columbia as well as southern plains shallow gas in Alberta. Third quarter 2004 natural gas sales volumes in the United States increased as a result of the TBI acquisition in the second quarter of 2004 and successful drilling program at Mamm Creek. Higher natural gas sales volumes in the United States for the first nine months of 2004 were primarily the result of successful resource play drilling programs at Mamm Creek, Jonah and North Texas and the TBI acquisition.
Increases in liquids sales volumes in the third quarter and for the first nine months of 2004 are primarily the result of the commencement of sales on the OCP Pipeline in Ecuador in September 2003 and the increased interests in the Scott and Telford fields in the United Kingdom. Increases in North American liquids sales in the third quarter of 2004 resulting from development at Foster Creek and Pelican Lake were more than offset by the reduction in volumes resulting from the Petrovera disposition in the first quarter of 2004 and additional non-core dispositions that closed in the third quarter of 2004. For the first nine months of 2004, North American liquids sales volumes were higher when compared to the same
- 9 -
period in 2003 as a result of continued Foster Creek development, successful drilling programs at Suffield and positive response from the waterflood program at Pelican Lake offset partially by the Petrovera disposition and additional non-core dispositions in the third quarter of 2004.
Per Unit Results Produced Gas ($ per thousand cubic feet)
Three Months Ended September 30 |
Canada |
United States |
United Kingdom |
|||||||||||||||||||||||||||||||||
2004 vs | 2004 vs | 2004 vs | ||||||||||||||||||||||||||||||||||
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
||||||||||||||||||||||||||||
Price (1) |
$ | 5.10 | 11 | % | $ | 4.61 | $ | 5.36 | 11 | % | $ | 4.82 | $ | 3.84 | 47 | % | $ | 2.62 | ||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
0.09 | 13 | % | 0.08 | 0.57 | 24 | % | 0.46 | | | | |||||||||||||||||||||||||
Transportation and selling |
0.37 | -8 | % | 0.40 | 0.26 | -33 | % | 0.39 | 2.34 | -11 | % | 2.63 | ||||||||||||||||||||||||
Operating |
0.50 | | 0.50 | 0.36 | 9 | % | 0.33 | | | | ||||||||||||||||||||||||||
Netback |
$ | 4.14 | $ | 3.63 | $ | 4.17 | $ | 3.64 | $ | 1.50 | $ | (0.01 | ) | |||||||||||||||||||||||
Gas Sales Volumes (MMcf per day) |
2,138 | 12 | % | 1,914 | 958 | 59 | % | 604 | 32 | 357 | % | 7 | ||||||||||||||||||||||||
(1) | Excludes realized commodity and currency hedge activities. |
Nine Months Ended September 30 |
Canada |
United States |
United Kingdom |
|||||||||||||||||||||||||||||||||
2004 vs | 2004 vs | 2004 vs | ||||||||||||||||||||||||||||||||||
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
||||||||||||||||||||||||||||
Price (1) |
$ | 5.17 | 3 | % | $ | 5.03 | $ | 5.49 | 11 | % | $ | 4.95 | $ | 4.07 | 47 | % | $ | 2.76 | ||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
0.08 | 33 | % | 0.06 | 0.63 | 29 | % | 0.49 | | | | |||||||||||||||||||||||||
Transportation and selling (2) |
0.38 | 6 | % | 0.36 | 0.32 | -11 | % | 0.36 | 2.28 | 6 | % | 2.16 | ||||||||||||||||||||||||
Operating |
0.52 | 6 | % | 0.49 | 0.36 | 29 | % | 0.28 | | | | |||||||||||||||||||||||||
Netback |
$ | 4.19 | $ | 4.12 | $ | 4.18 | $ | 3.82 | $ | 1.79 | $ | 0.60 | ||||||||||||||||||||||||
Gas Sales Volumes (MMcf per day) |
2,105 | 8 | % | 1,951 | 823 | 45 | % | 566 | 32 | 191 | % | 11 | ||||||||||||||||||||||||
(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. |
Average natural gas prices, excluding the impact of financial hedges, in the third quarter of 2004 reflect the increase in the benchmark NYMEX and AECO gas prices, offset partially by the increased applicable differentials compared to the same period of 2003. Higher benchmark NYMEX prices of 16 percent in the quarter (3 percent year-to-date) compared to the same period in 2003 was partially offset by increased natural gas price differentials. Realized commodity and currency hedging losses on natural gas were approximately $44 million, or $0.15 per Mcf in the third quarter of 2004 compared to a loss of approximately $14 million, or $0.06 per Mcf in the third quarter 2003. On a year-to-date basis to September 30, realized commodity and currency hedging losses on natural gas were approximately $133 million, or $0.16 per Mcf in 2004 compared to a loss of approximately $129 million, or $0.19 per Mcf in 2003.
Per unit production and mineral taxes in the U.S. in the quarter and for the nine months ended September 30, 2004 compared to the same periods in 2003 increased due to a combination of higher prices and a higher effective tax rate in Colorado caused by the significant growth in Colorado production.
On a year-to-date basis the per unit transportation and selling costs for Canadian natural gas have increased as a result of higher average distances to sales markets from production facilities and the increased U.S./Canadian exchange rate. Natural gas per unit transportation and selling costs for the U.S. have decreased in the quarter and for the nine months ended September 30, 2004 compared to the same periods in 2003 as a result of the TBI acquisition where a majority of the production is sold at the wellhead and does not incur additional transportation charges. The U.K. increase in transportation and selling expense year-to-date 2004 compared to the same period in 2003 reflects a change in the cost sharing
- 10 -
arrangements for the Scottish Area Gas Evacuation (SAGE) pipeline as a result of the 2004 acquisition of additional interests in the Scott and Telford fields.
Canadian natural gas per unit operating expenses were unchanged in the third quarter of 2004 compared to the same period in 2003 but $0.03 higher on a year-to-date basis primarily due to the higher U.S./Canadian exchange rates. Increases in the U.S. per unit natural gas operating expenses for the third quarter and for the nine months ended September 30, 2004 compared to the same periods in 2003 were a result of higher operating costs from the TBI and North Texas property acquisitions and non-recurring charges related to the prior year.
Per Unit Results Crude Oil and NGLs
Three Months Ended September 30
Crude Oil ($ per barrel)
North America |
Ecuador |
United Kingdom |
||||||||||||||||||||||||||||||||||
2004 vs | 2004 vs | 2004 vs | ||||||||||||||||||||||||||||||||||
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
||||||||||||||||||||||||||||
Price (1) |
$ | 31.49 | 55 | % | $ | 20.26 | $ | 33.47 | 51 | % | $ | 22.13 | $ | 40.88 | 46 | % | $ | 27.92 | ||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
0.34 | 143 | % | (0.80 | ) | 2.62 | 482 | % | 0.45 | | | | ||||||||||||||||||||||||
Transportation and selling |
1.42 | 125 | % | 0.63 | 2.36 | | 2.36 | 2.44 | 23 | % | 1.98 | |||||||||||||||||||||||||
Operating |
5.42 | -9 | % | 5.93 | 4.35 | | 4.33 | 9.98 | 52 | % | 6.55 | |||||||||||||||||||||||||
Netback |
$ | 24.31 | $ | 14.50 | $ | 24.14 | $ | 14.99 | $ | 28.46 | $ | 19.39 | ||||||||||||||||||||||||
Crude Oil Sales Volumes (bbls per day) |
142,506 | -5 | % | 149,582 | 74,846 | 88 | % | 39,807 | 12,819 | 138 | % | 5,384 | ||||||||||||||||||||||||
(1) | Excludes realized commodity and currency hedge activities. |
NGLs (1) ($ per barrel)
Canada |
United States |
United Kingdom |
||||||||||||||||||||||||||||||||||
2004 vs | 2004 vs | 2004 vs | ||||||||||||||||||||||||||||||||||
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
||||||||||||||||||||||||||||
Price |
$ | 33.46 | 42 | % | $ | 23.52 | $ | 36.09 | 42 | % | $ | 25.50 | $ | 25.82 | 38 | % | $ | 18.69 | ||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
| | | 4.05 | 53 | % | 2.64 | | | | ||||||||||||||||||||||||||
Transportation and selling |
0.45 | -22 | % | 0.58 | | | | 0.44 | -78 | % | 2.01 | |||||||||||||||||||||||||
Netback |
$ | 33.01 | $ | 22.94 | $ | 32.04 | $ | 22.86 | $ | 25.38 | $ | 16.68 | ||||||||||||||||||||||||
NGLs Sales Volumes (bbls per day) |
12,804 | -7 | % | 13,758 | 14,363 | 51 | % | 9,530 | 2,070 | 383 | % | 429 | ||||||||||||||||||||||||
(1) | NGLs results includes Condensate. |
- 11 -
Nine Months Ended September 30
Crude Oil ($ per barrel)
North America |
Ecuador |
United Kingdom |
||||||||||||||||||||||||||||||||||
2004 vs | 2004 vs | 2004 vs | ||||||||||||||||||||||||||||||||||
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
||||||||||||||||||||||||||||
Price (1) |
$ | 27.70 | 22 | % | $ | 22.73 | $ | 28.25 | 14 | % | $ | 24.68 | $ | 35.16 | 22 | % | $ | 28.74 | ||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
0.35 | | | 1.93 | 9 | % | 1.77 | | | | ||||||||||||||||||||||||||
Transportation and selling |
1.36 | 8 | % | 1.26 | 2.30 | -3 | % | 2.37 | 2.04 | -4 | % | 2.13 | ||||||||||||||||||||||||
Operating |
5.29 | -11 | % | 5.92 | 4.17 | -16 | % | 4.99 | 7.08 | 61 | % | 4.41 | ||||||||||||||||||||||||
Netback |
$ | 20.70 | $ | 15.55 | $ | 19.85 | $ | 15.55 | $ | 26.04 | $ | 22.20 | ||||||||||||||||||||||||
Crude Oil Sales Volumes (bbls per day) |
143,172 | 3 | % | 139,187 | 78,032 | 116 | % | 36,132 | 15,855 | 105 | % | 7,737 | ||||||||||||||||||||||||
(1) | Excludes realized commodity and currency hedge activities. |
NGLs (1) ($ per barrel)
Canada |
United States |
United Kingdom |
||||||||||||||||||||||||||||||||||
2004 vs | 2004 vs | 2004 vs | ||||||||||||||||||||||||||||||||||
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
||||||||||||||||||||||||||||
Price |
$ | 29.65 | 24 | % | $ | 23.99 | $ | 34.15 | 26 | % | $ | 27.07 | $ | 23.79 | 15 | % | $ | 20.69 | ||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
| | | 3.77 | 108 | % | 1.81 | | | | ||||||||||||||||||||||||||
Transportation and selling |
0.39 | 105 | % | 0.19 | | | | 1.19 | -20 | % | 1.49 | |||||||||||||||||||||||||
Netback |
$ | 29.26 | $ | 23.80 | $ | 30.38 | $ | 25.26 | $ | 22.60 | $ | 19.20 | ||||||||||||||||||||||||
NGLs Sales Volumes (bbls per day) |
13,452 | -8 | % | 14,591 | 12,126 | 31 | % | 9,230 | 2,035 | 180 | % | 726 | ||||||||||||||||||||||||
(1) | NGLs results includes Condensate. |
Increases in the average crude oil price, excluding the impact of financial hedges, in the third quarter and first nine months of 2004 reflect the increase in the benchmark West Texas Intermediate (WTI) and Dated Brent oil prices, offset partially by the increased applicable differentials compared to the same periods in 2003. Higher benchmark WTI crude oil prices of 45 percent in the quarter (27 percent year-to-date) for 2004 compared to the same periods in 2003 were partially offset by increased crude oil price differentials (up 49 percent in the third quarter and up 44 percent on a year-to-date basis) and a higher proportionate share of heavier blend oils in the product mix. Realized commodity and currency hedging losses on crude oil were approximately $221 million, or $9.28 per barrel of liquids in the third quarter of 2004 compared to a loss of approximately $44 million, or $2.18 per barrel of liquids in the third quarter 2003. On a year-to-date basis to September 30, realized commodity and currency hedging losses on crude oil were approximately $515 million, or $7.11 per barrel of liquids in 2004 compared to a loss of approximately $154 million, or $2.71 per barrel of liquids in 2003.
North American per unit production and mineral taxes increased in the third quarter and year-to-date primarily due to the impact of mineral tax amendments related to prior years that were recorded in the third quarter of 2003, which reduced mineral taxes by approximately $16 million or $0.42 per barrel on a year-to-date basis for 2003. This increase is offset slightly by the increased production weighting from properties that are not subject to production and mineral taxes combined with the disposition of several properties that were subject to production and mineral taxes. Per unit production and mineral taxes in Ecuador increased $2.17 per barrel in the third quarter of 2004 and $0.16 per barrel on a year-to-date basis over the same period of 2003 due to higher realized prices on the Tarapoa block volumes. The Company is required to pay the Ecuadorian government a percentage of revenue from this block based on realized prices over a base price.
Per unit crude oil transportation and selling costs in North America for the third quarter were higher by $0.79 per barrel over the same period of 2003. This is mainly due to a change in the method of allocating transportation between the Upstream and Midstream & Marketing segments which was revised during the third quarter of 2003 and a sales pipeline
- 12 -
break at Pelican Lake resulting in additional trucking charges and repair costs during the third quarter of 2004. On a year-to-date basis, the per unit crude oil transportation and selling expenses in North America have increased $0.10 per barrel mainly due to the higher U.S./Canadian exchange rates. Per unit transportation and selling costs in Ecuador for the nine months ended September 30, 2004 decreased as a result of lower net realized costs of operations of the OCP Pipeline.
North American crude oil per unit operating costs have decreased $0.51 per barrel in the third quarter and $0.63 per barrel on a year-to-date basis compared to the same periods in 2003. This is due to the sale of Petrovera which had relatively higher operating costs, as well as lower per unit fixed costs due to increased volumes offset partially by the increased U.S./Canadian exchange rates. In Ecuador, a significant portion of operating expenses are fixed, resulting in lower per unit operating expenses as sales volumes increased for the nine months ended September 30, 2004 compared to the same period in 2003. The third quarter crude oil per unit operating expenses in Ecuador has increased slightly due to higher workover costs during the quarter. The increase in the U.K.s third quarter and year-to-date 2004 crude oil operating expenses is primarily related to platform turnaround, higher maintenance and fuel expenses and the U.S./U.K. exchange rates.
Midstream & Marketing Operations
Financial Results ($ millions)
Three Months Ended September 30
Midstream |
Marketing |
Total |
||||||||||||||||||||||||||||||||||
2004 vs | 2004 vs | 2004 vs | ||||||||||||||||||||||||||||||||||
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
||||||||||||||||||||||||||||
Revenues |
$ | 158 | -12 | % | $ | 180 | $ | 731 | 22 | % | $ | 601 | $ | 889 | 14 | % | $ | 781 | ||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Transportation and selling |
| | | 4 | -64 | % | 11 | 4 | -64 | % | 11 | |||||||||||||||||||||||||
Operating |
65 | 14 | % | 57 | 12 | 71 | % | 7 | 77 | 20 | % | 64 | ||||||||||||||||||||||||
Purchased product |
88 | -21 | % | 112 | 712 | 23 | % | 580 | 800 | 16 | % | 692 | ||||||||||||||||||||||||
Depreciation, depletion
and amortization |
8 | 14 | % | 7 | | | 2 | 8 | -11 | % | 9 | |||||||||||||||||||||||||
$ | (3 | ) | $ | 4 | $ | 3 | $ | 1 | $ | | $ | 5 | ||||||||||||||||||||||||
Nine Months Ended September 30
Midstream |
Marketing |
Total |
||||||||||||||||||||||||||||||||||
2004 vs | 2004 vs | 2004 vs | ||||||||||||||||||||||||||||||||||
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
||||||||||||||||||||||||||||
Revenues |
$ | 881 | 36 | % | $ | 649 | $ | 2,325 | 13 | % | $ | 2,064 | $ | 3,206 | 18 | % | $ | 2,713 | ||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Transportation and selling |
| | | 20 | -55 | % | 44 | 20 | -55 | % | 44 | |||||||||||||||||||||||||
Operating |
192 | 2 | % | 188 | 32 | -40 | % | 53 | 224 | -7 | % | 241 | ||||||||||||||||||||||||
Purchased product |
655 | 55 | % | 423 | 2,254 | 14 | % | 1,983 | 2,909 | 21 | % | 2,406 | ||||||||||||||||||||||||
Depreciation, depletion
and amortization |
58 | 222 | % | 18 | 2 | -33 | % | 3 | 60 | 186 | % | 21 | ||||||||||||||||||||||||
$ | (24 | ) | $ | 20 | $ | 17 | $ | (19 | ) | $ | (7 | ) | $ | 1 | ||||||||||||||||||||||
Revenues and purchased product expense in Midstream & Marketing operations increased in the third quarter and on a nine-month basis compared to the same periods in 2003 due primarily to increases in commodity prices. Decreases in transportation and selling costs in the third quarter and year-to-date to September 30, 2004 compared to the same periods in 2003 is primarily due to the reallocation of all natural gas downstream transportation costs to the Upstream segment.
- 13 -
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 which represents the primary reason for the decrease when comparing year-to-date results between 2003 and 2004.
The increase in year-to-date 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 $35 million.
Corporate
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||
Corporate Items ($ millions) |
September 30 |
September 30 |
||||||||||||||||||||||
2004 vs | 2004 vs | |||||||||||||||||||||||
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
|||||||||||||||||||
Revenues, Net of Royalties |
$ | (501 | ) | | $ | 1 | $ | (1,033 | ) | | $ | 2 | ||||||||||||
Expenses |
||||||||||||||||||||||||
Operating |
1 | | | (4 | ) | | | |||||||||||||||||
Depreciation,
depletion and
amortization |
14 | | 14 | 44 | 38 | % | 32 | |||||||||||||||||
Administration |
43 | 5 | % | 41 | 136 | 12 | % | 121 | ||||||||||||||||
Interest, net |
103 | 45 | % | 71 | 278 | 38 | % | 202 | ||||||||||||||||
Accretion of asset
retirement
obligation |
8 | 60 | % | 5 | 20 | 33 | % | 15 | ||||||||||||||||
Foreign exchange
gains |
(288 | ) | 1340 | % | (20 | ) | (209 | ) | -52 | % | (436 | ) | ||||||||||||
Stock-based
compensation |
5 | -17 | % | 6 | 14 | 17 | % | 12 | ||||||||||||||||
Gain on dispositions |
| | | (35 | ) | | | |||||||||||||||||
Income tax expense |
77 | -62 | % | 205 | 122 | -64 | % | 342 | ||||||||||||||||
Corporate revenues, net of royalties in the third quarter of 2004 include approximately $500 million in unrealized mark-to-market losses related to commodity contracts. On a year-to-date basis, revenues, net of royalties include mark-to-market losses on commodity contracts of approximately $1,035 million. Other mark-to-market gains ($7 million year-to-date) on derivative financial instruments related to interest and electricity consumption are recorded in the interest, net and operating expense account respectively.
Depreciation, depletion and amortization include provisions for corporate assets such as computer equipment, office furniture and leasehold improvements. The increase in expense on a year-to-date 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.
The administrative expenses for the third quarter of 2004 compared to the same period in 2003 are relatively unchanged. The year-to-date results reflect the effect of the change in the U.S./Canadian dollar exchange rate and increased long-term compensation expenses. Administrative costs were lower by $0.10 per BOE, at $0.60 per BOE, for the third quarter of 2004 ($0.65 per BOE year-to-date) compared with $0.70 per BOE for the third quarter in 2003 ($0.70 per BOE year-to-date). Lower per unit administrative expenses are primarily as a result of the increase in sales volumes.
The higher interest expense resulted primarily from the higher average outstanding debt level as a result of the TBI acquisition in the second quarter and on a year-to-date basis for 2004 versus the same periods in 2003 and the impact of the change in the U.S./Canadian dollar exchange rate.
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The majority of the foreign exchange gain of $288 million in the third quarter resulted from the change in the U.S./Canadian dollar period end exchange rate between June 30, 2004 and September 30, 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.
The effective tax rate for the third quarter of 2004 was 16 percent compared to 42 percent for the same period in 2003 and 12 percent compared to 16 percent for 2003 on a year-to-date basis as disclosed in Note 8 to the Interim Consolidated Financial Statements. EnCanas effective tax rate in any particular reporting period is a function of the relationship between the amount of net earnings before income taxes for the period and the magnitude of the items representing permanent differences that are excluded from the calculation of earnings for the period that will be subject to tax. There are a variety of items of this type, including:
| The non-taxable half of Canadian capital gains (losses); |
| Adjustments for the impact of legislative changes which have a prospective impact on future income tax obligations; |
| The effects of asset dispositions where the tax values of the assets sold differ from the accounting value; and |
| Items such as resource allowance, non-deductible crown payments and some marked to market adjustments where the treatment is different for income tax and accounting purposes. |
Given the nature and scale of EnCanas activities, it is difficult to forecast the magnitude and timing of these types of items.
EnCana sold oil and gas interests in a manner which resulted in the retention of certain associated tax basis resulting in a reduction to the tax provision for the third quarter in 2004 of $59 million and $162 million for year-to-date 2004.
Current income tax expense for the third quarter of 2004 was $124 million compared to $51 million for the same period in 2003. Current taxes were expected to increase significantly in 2004 when compared to the prior year as the effects of the merger with Alberta Energy Company Ltd. (AEC) were reflected in the Companys tax position for 2003.
The operations of the Company are complex and related tax interpretations, regulations and legislation in the various jurisdictions that the Company and its subsidiaries operate in are continually changing. As a result, there are usually some tax matters under review. The Company believes that the provision for taxes is adequate.
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CAPITAL EXPENDITURES
Capital Investment
Three Months Ended September 30 |
Nine Months Ended September 30 |
|||||||||||||||||||||||
2004 vs | 2004 vs | |||||||||||||||||||||||
($ millions) |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
||||||||||||||||||
Upstream |
||||||||||||||||||||||||
Canada |
$ | 598 | -33 | % | $ | 897 | $ | 2,282 | 9 | % | $ | 2,096 | ||||||||||||
United States |
325 | 16 | % | 279 | 851 | 38 | % | 615 | ||||||||||||||||
Ecuador |
53 | -18 | % | 65 | 163 | -5 | % | 172 | ||||||||||||||||
United Kingdom |
82 | 332 | % | 19 | 290 | 544 | % | 45 | ||||||||||||||||
Other Countries |
15 | | 15 | 49 | -22 | % | 63 | |||||||||||||||||
Total Upstream |
$ | 1,073 | -16 | % | $ | 1,275 | $ | 3,635 | 22 | % | $ | 2,991 | ||||||||||||
Midstream & Marketing |
15 | -74 | % | 58 | 40 | -74 | % | 154 | ||||||||||||||||
Corporate |
10 | 43 | % | 7 | 28 | -26 | % | 38 | ||||||||||||||||
Core Capital Expenditures |
$ | 1,098 | -18 | % | $ | 1,340 | $ | 3,703 | 16 | % | $ | 3,183 | ||||||||||||
Acquisition of Tom Brown, Inc.(1) |
| | | 2,335 | | | ||||||||||||||||||
Acquisitions(2) |
49 | -49 | % | 96 | 189 | -59 | % | 462 | ||||||||||||||||
Dispositions(3) |
(940 | ) | | | (1,359 | ) | | (19 | ) | |||||||||||||||
Net Capital Expenditures(4) |
$ | 207 | -86 | % | $ | 1,436 | $ | 4,868 | 34 | % | $ | 3,626 | ||||||||||||
(1) | Excludes approximately $406 million of TBI acquired debt. | |||
(2) | Represents Corporate acquisitions and property acquisitions. |
(3) | The Petrovera acquisition of $253 million and subsequent disposition for $540 million has been included on a net basis in dispositions in the first quarter of 2004. |
(4) | Excludes discontinued operations. |
The Companys core capital expenditures for the third quarter of 2004 were offset significantly by non-core asset dispositions that were discussed in the second quarter MD&A. The increase in Upstream core capital expenditures for the nine month period in 2004 compared to the same period in 2003 was primarily as a result of continued development of EnCanas North American resource play properties. Net capital expenditures increased approximately $1.2 billion for the nine months ended September 30, 2004 compared to the same period in 2003 as a result of the TBI acquisition, higher levels of operating activity in Upstream, and the impact of the higher U.S./Canadian dollar exchange rate partially offset by $1.4 billion in non-core asset dispositions. The Companys capital investment was funded by cash flow in excess of amounts paid for purchases under the Normal Course Issuer Bid, proceeds received on dispositions of non-core assets as well as debt.
Upstream Capital Expenditures
The decreases in Upstream capital expenditures in the third quarter compared to the same quarter in 2003 is largely attributable to the September 2003 land acquisitions at Cutbank Ridge. The increase in Upstream capital expenditures on a year-to-date basis in 2004 compared to the same period in 2003 reflect increased drilling and development activities and the impact of the increased average U.S./Canadian dollar exchange rate on Canadian dollar denominated expenditures. On a year-to-date basis the change in the average U.S./Canadian dollar exchange rate resulted in an increase on Canadian dollar denominated capital expenditures of approximately $168 million. Capital spending was primarily focused on North American resource play properties with spending in Canada directed mostly at natural gas and oil exploration and
- 16 -
development of properties on the Suffield and Palliser Blocks in southeast Alberta, as well as Greater Sierra and Cutbank Ridge in northeast British Columbia and Pelican Lake in northeast Alberta. The majority of capital expenditures in the U.S. were directed towards drilling in Mamm Creek, Jonah and Texas. Capital expenditures in the U.K. primarily reflect activity related to the development of the Buzzard field. The Company drilled 3,998 net wells year-to-date September 30, 2004 compared to 4,113 net wells in the same period of 2003.
Midstream & Marketing Capital Expenditures
Capital expenditures in Midstream & Marketing relate primarily to improvements to midstream facilities and various development initiatives. Expenditure levels were significantly higher in 2003 due to the expansion of the gas storage business and the buyout of equipment operating leases.
Corporate Capital Expenditures
Corporate capital expenditures relate primarily to spending on business information systems, leasehold improvements and furniture and office equipment.
Acquisitions and Divestitures
During the third quarter of 2004, the Company disposed of various non-core properties in North America for proceeds of approximately $940 million as disclosed previously in the second quarter MD&A. Total dispositions for the nine months ended September 30, 2004 are approximately $1.4 billion.
Other major acquisitions and divestitures completed and disclosed in the first two quarters of 2004 include the TBI acquisition for approximately $2.7 billion including $0.4 billion in acquired debt; the acquisition of additional interests in the Scott and Telford fields in the U.K. for approximately $112 million; and the disposition of the Companys interest in the Petrovera Partnership for approximately $287 million.
LIQUIDITY AND CAPITAL RESOURCES
EnCanas cash flow from continuing operations was $1,363 million for the three months ended September 30, 2004, up $390 million compared to the same period last year and on a year-to-date basis was $3,489 million for the period ended September 30, 2004, up $286 million compared to the same nine-month period in 2003. The increase in cash flows in the quarter and on a year-to-date basis were primarily due to increased revenues from the growth in sales volumes, higher commodity prices offset by higher realized commodity hedging losses, an increase in the current tax provision and an increase in the U.S./Canadian dollar exchange rate.
During the third quarter of 2004, long-term debt plus the current portion of long-term debt decreased $729 million compared to the previous quarter ended June 30, 2004 as a result of the dispositions and increase in cash flows. EnCanas net debt adjusted for working capital was $9,014 million as at September 30, 2004 compared with $5,931 million at December 31, 2003. Working capital was a deficit of $978 million at September 30, 2004 and included unrealized losses on mark-to-market accounting on derivatives of $674 million and a current tax payable of $526 million. This compares to a working capital surplus of $157 million as at December 31, 2003. Cash flow together with proceeds from dispositions was used for the purchase of shares under the Companys Normal Course Issuer Bid and capital expenditures. As a result of these activities, long-term debt plus the current portion of long-term debt increased $2,211 million as at September 30, 2004 compared to the 2003 year-end.
Net debt to capitalization was 43 percent as of September 30, 2004, up from 34 percent at December 31, 2003, primarily as a result of the acquisition of TBI and the impact of mark-to-market accounting on derivatives. Management calculates this ratio for internal purposes to steward the Companys overall debt position as a measure of a companys financial strength.
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EnCanas long term credit ratings were confirmed by all its credit rating agencies by the end of the third quarter. Standard & Poors has affirmed an A- with a Negative Outlook, Dominion Bond Rating Services has affirmed an A(low) with a Negative Trend and Moodys lowered EnCanas rating to Baa2 Stable. The agencies are expected to continue to monitor the Companys operating and financial performance through the year end.
On July 29, EnCana made 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.
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.
On August 9, 2004, EnCana redeemed all of its 8.50% 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% Preferred Securities due 2048, which had an aggregate principal amount of $150 million, at par.
As at September 30, 2004, the Company had available unused committed bank credit facilities in the amount of $1,865 million.
In October 2003, EnCana received approval from the Toronto Stock Exchange 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 23.2 million of its Common Shares over a 12-month period ending October 21, 2004. In the third quarter of 2004, EnCana did not purchase any of its shares under the Bid. On a year-to-date basis, EnCana purchased for cancellation approximately 5.5 million of its shares at an average price of C$55.37 per share. From the inception of this Bid in October 2003 through its expiry in October 2004, the Company had purchased for cancellation approximately 9.1 million Common Shares at an average price of C$51.56 per share.
On October 26, 2004 the Company received Toronto Stock Exchange approval for a new Normal Course Issuer Bid commencing October 29, 2004 for a twelve month period. Under this bid, EnCana will be able to purchase for cancellation up to 23.1 million of its Common Shares, representing five percent of the approximately 462 million Common Shares outstanding as of October 15, 2004.
BUSINESS ENVIRONMENT
Natural Gas
Three Months Ended | Nine Months Ended | Year | ||||||||||||||||||||||||||
September 30 |
September 30 |
Ended |
||||||||||||||||||||||||||
Natural Gas Price Benchmarks | 2004 vs | 2004 vs | ||||||||||||||||||||||||||
(Average for the period) |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2003 |
|||||||||||||||||||||
AECO Price (C$/Mcf) |
$ | 6.66 | 6 | % | $ | 6.29 | $ | 6.69 | -5 | % | $ | 7.07 | $ | 6.70 | ||||||||||||||
NYMEX Price ($/MMBtu) |
5.76 | 16 | % | 4.97 | 5.81 | 3 | % | 5.66 | 5.39 | |||||||||||||||||||
Rockies (Opal) Price ($/MMBtu) |
5.06 | 16 | % | 4.37 | 5.02 | 22 | % | 4.10 | 4.12 | |||||||||||||||||||
AECO/NYMEX Basis Differential ($/MMBtu) |
0.70 | 84 | % | 0.38 | 0.78 | 5 | % | 0.74 | 0.65 | |||||||||||||||||||
Rockies/NYMEX Basis ($/MMBtu) |
0.70 | 17 | % | 0.60 | 0.80 | -49 | % | 1.56 | 1.27 |
Concerns that North American natural gas supply will not be able to meet increasing demands and the influence of high crude oil prices have continued to result in historically high average NYMEX gas prices. Lower average AECO gas prices on a year-to-date basis in 2004 can be attributed to wider differentials from NYMEX in the third quarter combined with the appreciation of the U.S./Canadian dollar exchange rate. The increased AECO/NYMEX basis differential in the third quarter of 2004 compared to the third quarter of 2003 can be attributed to increased transportation differentials for the marginal sales volumes transported from Alberta to Eastern Canada.
- 18 -
Percentage of Natural Gas Volumes Benchmark Price Exposure
(Annual approximate percentage)
Crude Oil
Three Months Ended | Nine Months Ended | Year | ||||||||||||||||||||||||||
September 30 |
September 30 |
Ended |
||||||||||||||||||||||||||
Crude Oil Price Benchmarks | 2004 vs | 2004 vs | ||||||||||||||||||||||||||
(Average for the period U.S.$/bbl) |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2003 |
|||||||||||||||||||||
WTI |
43.89 | 45 | % | 30.21 | 39.21 | 27 | % | 30.94 | 30.99 | |||||||||||||||||||
Dated Brent |
41.54 | 46 | % | 28.41 | 36.28 | 27 | % | 28.65 | 28.84 | |||||||||||||||||||
WTI/Bow River Differential |
12.09 | 49 | % | 8.12 | 10.72 | 44 | % | 7.42 | 8.01 | |||||||||||||||||||
WTI/OCP NAPO Differential (Ecuador)(1) |
14.31 | 85 | % | 7.75 | 12.71 | 64 | % | 7.75 | 8.06 | |||||||||||||||||||
WTI/Oriente Differential (Ecuador) |
11.63 | 118 | % | 5.34 | 9.07 | 63 | % | 5.57 | 5.59 |
(1) | The WTI/OCP NAPO Differential was posted as of September 2003. |
Continued increased demand in Asia and North America along with supply uncertainties in the Middle East as well as west Africa and recent damage to production platforms in the Gulf of Mexico has caused the WTI crude oil price to be significantly higher in the third quarter and on a year-to-date basis in 2004 when compared to the corresponding periods in 2003. | ||||
The Canadian WTI/Bow River heavy oil differential widened in the third quarter of 2004 compared to the third quarter of 2003 primarily due to the higher price for WTI, as well as wider U.S. Gulf Coast light to heavy product differentials. As a percentage of WTI, Bow Rivers average sales price for the third quarter of 2004 was 72 percent of WTI as compared to 73 percent in the third quarter of 2003. On a year-to-date basis, Canadian WTI/Bow River heavy oil differential was higher primarily as a result of the increase in WTI. | ||||
The Company currently transports nearly all of its Ecuadorian production through the OCP Pipeline as NAPO blend. NAPO blend is a heavier crude than the SOTE Oriente blend, previously the predominant crude oil from Ecuador, resulting in a wider differential to WTI. The third quarter and year-to-date 2004 increases in the 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. |
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U.S./Canadian Dollar Exchange Rates
Three Months Ended | Nine Months Ended | Year | ||||||||||||||||||||||||||
September 30 |
September 30 |
Ended |
||||||||||||||||||||||||||
Foreign Exchange Benchmarks | 2004 vs | 2004 vs | ||||||||||||||||||||||||||
(Average for the period) |
2004 |
2003 |
2003 |
2004 |
2003 |
2003 |
2003 |
|||||||||||||||||||||
U.S./Canadian Dollar Period-End Exchange Rate |
0.791 | 7 | % | 0.741 | 0.791 | 7 | % | 0.741 | 0.774 | |||||||||||||||||||
U.S./Canadian Dollar Average Exchange Rate |
0.765 | 6 | % | 0.725 | 0.753 | 7 | % | 0.701 | 0.716 |
The third quarter 2004 over third quarter 2003 average U.S./Canadian dollar exchange rate increase was primarily the result of the economic slowdown in the U.S., continuing differences between Canadian and U.S. interest rates and the U.S. current account deficit.
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. As at September 30, 2004, there were 462 million Common Shares outstanding compared to 465 million Common Shares outstanding at September 30, 2003 and 461 million Common Shares outstanding as at December 31, 2003. There were no Preferred Shares outstanding as at September 30, 2004 or September 30, 2003.
Employees and directors have been granted options to purchase Common Shares under various plans. During the third quarter of 2004, approximately 1.0 million Common Shares were issued (year-to-date approximately 6.9 million Common Shares) under the terms of these plans. These plans and outstanding balances are disclosed in Note 11 to the Interim Consolidated Financial Statements.
As discussed previously in the Liquidity and Capital Resources section of this MD&A, the Company did not repurchase any of its Common Shares during the third quarter. The Company has repurchased for cancellation 5.5 million Common Shares at an average price of C$55.37 in the first nine months of 2004 under a Normal Course Issuer Bid that was approved by the Toronto Stock Exchange in October 2003.
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. In addition, the Company has made commitments related to the risk mitigation program and has incurred additional commitments as a result of the TBI acquisition. See Note 14 of the Interim Consolidated Financial Statements for the financial transactions and the Risk Management section of this MD&A for a discussion of the physical contracts.
Included in the long-term debt commitments, the Company had $2,446 million outstanding as at September 30, 2004 related to Bankers Acceptances, Commercial Paper and LIBOR loans that are supported by revolving credit facilities and term loan borrowings. Approximately $846 million of this amount is related to the bridge credit facility which was put in place to finance a portion of the TBI acquisition and is required to be reduced to $450 million principal outstanding by August 2005 and repaid in its entirety by May 2006. With respect to the balance of the outstanding revolving credit facilities and term loan borrowings of approximately $1,600 million, the Company intends and expects that it will have the ability to extend the term on an ongoing basis. Further details regarding the Companys long-term debt are described in Note 9 to the Interim Consolidated Financial Statements.
As at September 30, 2004, EnCana had entered into long-term, fixed price, physical contracts with a current delivery of approximately 48 MMcf per day with varying terms and volumes through 2017. The total volume to be delivered within the terms of these contracts is 172 billion cubic feet at a weighted average price of $3.55 per Mcf. At September 30, 2004, these transactions had an unrealized loss of $177 million.
- 20 -
A subsidiary of the Company in Ecuador has a 40 percent economic interest in relation to Block 15 pursuant to a contract with a third party. The state oil company of Ecuador has formally notified the third party of a contractual dispute which is disclosed in Note 15 of the Interim Consolidated Financial Statements.
In addition to the above, the Company is proceeding with its arbitration related to value added tax and is in discussions related to certain income tax matters related to interest deductibility in Ecuador.
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 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. 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 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 as a defendant. The Gallo complaint claims damages in excess of $30 million, before potential trebling under California laws. As is customary, none of the other actions 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 accounting standard for Hedging Relationships. Derivative instruments outstanding at January 1, 2004, that did not qualify as a hedge 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 September 30, 2004, approximately $242 million of these net losses were recognized. The timing of recognition of the remaining net gains of $7 million ($5 million after-tax) is described in Note 2 of the Interim Consolidated Financial Statements.
- 21 -
Changes in the fair value from June 30, 2004 to September 30, 2004 for these contracts, as well as all other outstanding hedge contracts, were marked-to-market and a $497 million loss ($321 million after-tax) was recognized in net earnings for the three months ended September 30, 2004. All unrealized losses on derivative instruments as at September 30, 2004 are disclosed in Note 14 of the Interim Consolidated Financial Statements.
RISK MANAGEMENT
EnCanas results are impacted by external market risks associated with fluctuations in commodity prices, foreign exchange rates and interest rates in addition to credit, operational and safety and environmental risks.
Commodity Prices
The Company partially mitigates its exposure to market 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 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 the Company has entered into various financial instrument agreements for both natural gas and crude oil as disclosed in Note 14 of the Interim Consolidated Financial Statements. As at September 30, 2004, EnCana has fixed price physical contracts of approximately 48 MMcf per day and various physical Rockies natural gas basis contracts with varying terms and volumes through 2007. At September 30, 2004, these transactions had an unrealized loss of approximately $17 million.
Other Risks
Other risks are partially mitigated through comprehensive insurance programs or managed by executing policies and standards that comply or exceed government regulations and industry standards. The Company also partially mitigates risks such as land access through communication and negotiation with individuals and communities in which it operates. Environmental risks such as the Kyoto Accord and similar initiatives in the U.S.A. remain unchanged as discussed in the 2003 year-end MD&A.
OUTLOOK
EnCana plans to focus primarily on exploitation of its North American resource plays to grow natural gas and crude oil production. The Company also has substantial assets in the Gulf of Mexico, Canadian East Coast, the U.K. central North Sea and Ecuador. The Company also plans to continue its focused, high-upside North American and international exploration programs.
The Company expects its 2004 core capital investment program to be between $4,700 million and $5,000 million and funded from cash flow and proceeds from divestitures of non-core assets.
Sales volume guidance for 2004 was increased in the second quarter and represents an approximate 15 percent growth over 2003 full year sales volumes (based on the midpoint of guidance). Included in the increased guidance is a 12 percent organic growth rate from the Companys inventory of resource plays and international assets. The guidance range for sales volumes was increased in June 2004 to reflect the strong operating performance from the Companys resource play assets in North America year-to-date.
Operating and Administrative Expenses
Total operating costs for 2004 are expected to range between $3.30 and $3.50 per BOE with administrative expense between $0.60 and $0.70 per BOE.
- 22 -
Current Income Taxes
At the date hereof, based on First Call consensus commodity pricing, for the balance of the year and production and capital expenditure estimates based on the mid-point of public guidance, EnCana expects the 2004 provision for current income taxes will be within the guidance range of $675 million to $820 million.
- 23 -
NOTE REGARDING FORWARD-LOOKING STATEMENTS
In the interest of providing EnCana shareholders and potential investors with information regarding the Company and its subsidiaries, certain statements throughout this MD&A constitute forward-looking statements within the meaning 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 crude oil, natural gas and NGLs for 2004 and beyond; the Companys plans to focus on exploitation of its resource plays and international exploitation projects to grow production of oil and natural gas; amounts which may be issued under the Companys multi-jurisdictional shelf prospectus program; the Companys projected capital investment levels for 2004 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; the Companys projected ability to extend its debt program on an ongoing basis; projected operating and administrative costs for 2004; the impact of the Kyoto Accord and similar initiatives in the U.S.A. on operating costs; projected tax rates and projected current taxes payable for 2004 and 2005 and the adequacy of the Companys provision for taxes; and rating agency monitoring and reviews which may occur in the future.
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; 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 brought 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.
NOTE REGARDING 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
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information provided by EnCana may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). 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.
Natural Gas Conversions
Natural gas volumes that have been converted to barrels of oil equivalent (BOE(s)) have been converted on the basis of six thousand cubic feet (Mcf) to one barrel (Bbl). BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent equivalency at the well head. Natural gas volumes are also often presented in million cubic feet (MMcf). Natural gas volumes are sold based on heat content in British Thermal Units (Btus) but physically measured in standard cubic feet (scf). The heat content of natural gas varies by formation and therefore by production region. For example, the heat content of EnCanas natural gas production in Alberta is approximately 1,020 Btu/scf and the U.S. Rockies is approximately 1,110 Btu/scf. The average heat content of EnCanas natural gas production in total is approximately 1,040 Btu/scf or 1.04 million British Thermal Units (MMBtu)/Mcf.
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.
NOTE REGARDING CURRENCY, PROTOCOLS NON-GAAP MEASURES AND REFERENCES TO ENCANA
All information included in this MD&A and the Interim 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 $0.73 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 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.
October 26, 2004
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EnCana Corporation | ||||
EnCana on 8th | tel:(403)645-2000 | |||
1800 855 2nd Street SW | ||||
PO Box 2850 | ||||
Calgary AB Canada T2P 2S5 | www.encana.com |
October 27, 2004
British Columbia Securities Commission
Alberta Securities Commission
Saskatchewan Securities Commission
The Manitoba Securities Commission
Ontario Securities Commission
Autorité des marchés financiers
New Brunswick Office of the Administrator of Securities
Prince Edward Island Securities Office
Nova Scotia Securities Commission
Newfoundland Department of Government Services and Lands, Securities Division
Registrar of Securities, Northwest Territories
Registrar of Securities, Yukon Territory
Registrar of Securities, Nunavut Territory
The Toronto Stock Exchange
Dear Sirs:
Re: EnCana Corporation (EnCana) Interim Report for the period ended September 30, 2004
This filing is being done in accordance with the continuous filing obligations of National Instrument 44-102 of the Canadian Securities Administrators arising from the following documents which were filed with the securities regulatory authorities across Canada:
a) | EnCanas Medium Term Note program in respect of which a Short Form Shelf Prospectus dated August 20, 2003 relating to the offering of Medium Term Notes in an aggregate principal amount of up to $1.0 billion (SEDAR project no. 00562373); | |||
b) | EnCanas debt securities program in respect of which a Short Form Shelf Prospectus dated September 16, 2004 relating to the offering of debt securities in an aggregate principal amount of up to US$2.0 billion debt securities (SEDAR project no. 00686926); and | |||
c) | EnCana Holdings Finance Corp.s U.S. debt securities program in respect of which a Short Form Shelf Prospectus dated March 26, 2004, relating to the offering of debt securities (guaranteed by EnCana) in an aggregate principal amount of up to US$2.0 billion debt securities (SEDAR project no. 00622960). |
Consolidated Financial Ratios, provided in connection with EnCanas continuous offering of medium term notes and debt securities, and a comfort letter from PricewaterhouseCoopers LLP, in respect of the unaudited Consolidated Financial Statements for the period ended September 30, 2004, have been filed under the SEDAR project number for the said interim financial statements.
Yours truly,
ENCANA CORPORATION
[signed] Kerry D. Dyte
KERRY D. DYTE
Corporate Secretary
PricewaterhouseCoopers LLP | ||
Chartered Accountants | ||
111 5th Avenue SW, Suite 3100 | ||
Calgary, Alberta | ||
Canada T2P 5L3 | ||
October 27, 2004
|
Telephone +1 (403) 509 7500 | |
Facsimile +1 (403) 781 1825 | ||
Direct Tel. (403) 509-7500 | ||
Direct Fax (403) 781-1825 |
British Columbia Securities Commission
Alberta Securities Commission
Saskatchewan Securities Commission
Manitoba Securities Commission
Ontario Securities Commission
Autorité des marchés financiers
New Brunswick Securities Administration Branch
Nova Scotia Securities Commission
Prince Edward Island Securities Office
Securities Commission of Newfoundland and Labrador
Registrar of Securities, Northwest Territories Registrar of Securities
Registrar of Securities, Yukon
Registrar of Securities, Nunavut
Re: EnCana Corporation (EnCana) Interim Financial Statements
We refer to the base shelf short form prospectus of EnCana dated August 20, 2003, relating to the sale and issue of up to $1,000,000,000 of Medium Term Notes and the base shelf short form prospectus of EnCana Holdings Finance Corp., an indirect wholly owned subsidiary of EnCana, dated March 26, 2004, relating to the sale and issue of up to U.S. $2,000,000,000 in debt securities guaranteed by EnCana and the base shelf short form prospectus of EnCana dated September 16, 2004 relating to the sale and issue of up to U.S. $2,000,000,000 in debt securities and (collectively, the Prospectuses).
The Prospectuses now also incorporate by reference the following unaudited interim consolidated financial statements of EnCana:
Consolidated balance sheet as at September 30, 2004; and Consolidated statements of earnings and cash flows for the three and nine month periods ended September 30, 2004 and 2003 and the consolidated statement of retained earnings for the nine month periods ended September 30, 2004 and 2003. |
PricewaterhouseCoopers refers to the Canadian firm of pricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entry.
We have not audited any financial statements of the Company as at any date or for any period subsequent to December 31, 2003. Although we have performed an audit for the year ended December 31, 2003, the purpose and therefore the scope of the audit was to enable us to express our opinion on the financial statements as at December 31, 2003 and for the year then ended, but not on the financial statements for any interim period within that year.
Therefore, we are unable to and do not express opinions on the unaudited interim consolidated financial statements, or on the financial position, results of operations or cash flows of the Company as at any date or for any period subsequent to December 31, 2003.
We have, however, performed a review of the unaudited interim financial statements of the Company for the three and nine month periods ended September 30, 2004 and 2003. We performed our review in accordance with Canadian generally accepted standards for a review of interim financial statements by an entitys auditors. Such an interim review consists principally of applying analytical procedures to financial data, and making enquiries of, and having discussions with, persons responsible for financial and accounting matters. An interim review does not provide assurance that we would become aware of any or all significant matters that might be identified in an audit.
Based on our review, we are not aware of any material modification that needs to be made for these interim financial statements to be in accordance with Canadian generally accepted accounting principles.
This letter is provided solely for the purpose of assisting the securities regulatory authorities to which it is addressed in discharging their responsibilities and should not be used for any other purpose. Any use that a third party makes of this letter, or any reliance or decisions made based on it, are the responsibility of such third parties. We accept no responsibility for loss, or damages, if any, suffered by any third party as a result of decisions made or actions taken based on this letter.
Yours very truly,
signed (PricewaterhouseCoopers LLP)
Chartered Accountants
(2)
EnCana Corporation
Supplemental Financial Information (unaudited)
Exhibit to September 30, 2004 Consolidated Financial Statements
CONSOLIDATED FINANCIAL RATIOS - MEDIUM TERM NOTES & DEBT SECURITIES
The following ratios, based on the consolidated financial statements, are provided in connection with the Companys continuous offering of medium-term notes and debt securities and are for the 12-month period then ended.
September 30 |
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2004 |
2003 |
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Restated | ||||||||
Interest coverage on long-term debt: |
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Net earnings |
5.5 | 10.1 | ||||||
Cash flow |
15.8 | 14.5 |
Note: | The Company has retroactively adopted the amendment made to the Canadian Institute of Chartered Accountants Handbook section 3860 Financial Instruments - Disclosure and Presentation. As a result, the preferred securities issued by the Company are now recorded as a liability and included in long-term debt and the related carrying charges have been included as interest expense. |
Form 52-109FT2
Certification of Interim Filings during Transition Period
I, Gwyn Morgan, President & Chief Executive Officer of EnCana Corporation, certify that:
1. | I have reviewed the interim filings (as this term is defined in Multilateral Instrument 52-109 Certification of Disclosure in Issuers Annual and Interim Filings) of EnCana Corporation (the issuer) for the interim period ending September 30, 2004; | |||
2. | Based on my knowledge, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings; and | |||
3. | Based on my knowledge, the interim financial statements together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date and for the periods presented in the interim filings. |
Date: October 26, 2004
/s/ Gwyn Morgan | ||||
Gwyn Morgan | ||||
President & Chief Executive Officer |
Form 52-109FT2
Certification of Interim Filings during Transition Period
I, John D. Watson, Executive Vice-President & Chief Financial Officer of EnCana Corporation, certify that:
1. | I have reviewed the interim filings (as this term is defined in Multilateral Instrument 52-109 Certification of Disclosure in Issuers Annual and Interim Filings) of EnCana Corporation (the issuer) for the interim period ending September 30, 2004; | |||
2. | Based on my knowledge, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings; and | |||
3. | Based on my knowledge, the interim financial statements together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date and for the periods presented in the interim filings. |
Date: October 26, 2004
/s/ John D. Watson | ||||
John D. Watson | ||||
Executive Vice-President & | ||||
Chief Financial Officer |