EnCana's second quarter oil and gas production up 26 percent to 775,000 BOE per day; cash flow exceeds US$1.1 billion

CALGARY, July 27 /CNW/ - EnCana Corporation (TSX & NYSE: ECA) today
reports production growth of more than 25 percent in the second quarter, cash
flow growth surpassing 10 percent and operating earnings up more than
35 percent. Cash flow in the second quarter of 2004 was $1,131 million, or
$2.43 per share diluted, up 12 percent from the same period in 2003. Operating
earnings were $379 million, or $0.81 per share diluted, up 38 percent from
$275 million in the second quarter of 2003 due mainly to increased sales along
with stronger natural gas and oil prices. Second quarter production of oil,
natural gas and natural gas liquids (NGLs) was 775,000 barrels of oil
equivalent (BOE) per day, up 26 percent from the second quarter of 2003.
Second quarter natural gas production was up more than 23 percent to average
3.04 billion cubic feet per day, while oil and NGLs sales rose 31 percent to
270,000 barrels of oil per day, compared to the second quarter of 2003.

EnCana reports in U.S. dollars and according to U.S. protocols in order
to facilitate a more direct comparison to other North American upstream oil
and natural gas exploration and development companies. Reserves and production
are reported on an after-royalty basis. All figures are in U.S. dollars unless
otherwise noted.

"EnCana achieved strong financial and operating performance in the second
quarter, driven principally by expanded natural gas resource plays and higher
crude oil production. We are on track to deliver 15 percent production growth
in 2004, 80 percent of which is organic. On a per share basis, that is year-
over-year production growth of about 20 percent. Looking longer term, we
believe our existing asset base is capable of delivering at least 10 percent
annual growth per share through the next five years," said Gwyn Morgan,
EnCana's President & Chief Executive Officer.

Second quarter operating earnings reach $379 million, up 38 percent
EnCana's second quarter operating earnings of $379 million were up
38 percent compared to the same period in 2003. Operating earnings exclude an
after-tax unrealized mark-to-market loss of $104 million related to price
hedges and an after-tax unrealized $25 million loss due to changes in foreign
exchange on translation of U.S. dollar denominated debt issued in Canada.
After inclusion of these non-cash items, net earnings in the second quarter
were $250 million, or 54 cents per share diluted. Second quarter pre-tax cash
flow was $1,334 million, up 40 percent from 2003. Second quarter after-tax
cash flow of $1,131 million includes a cash tax provision of $203 million,
compared with a $54 million cash tax recovery in 2003. This is consistent with
the company's earlier statements that the merger transaction resulted in a
significant cash tax deferral from 2003 to 2004. Second quarter revenues net
of royalties were $2,718 million.

Second quarter gas production up 23 percent in past year; oil and NGLs
sales up 31 percent
EnCana's second quarter natural gas production was 3.04 billion cubic
feet per day, up 23 percent from the second quarter of 2003. The increase is
mainly driven by strong growth from Greater Sierra, Cutbank Ridge and Southern
Plains shallow gas in Canada and Mamm Creek in the U.S. Rockies. Gas sales
include production as of May 19th from the Tom Brown acquisition, which added
an average of 132 million cubic feet per day over the quarter. Oil and NGLs
sales grew 31 percent to 270,000 barrels per day driven largely by growth from
Canadian oilsands, Ecuador and the U.K. Operating costs were $3.29 per BOE,
down 7 percent from the first quarter, and in line with the full year 2004
operating cost forecast of between $3.30 and $3.50 per BOE. EnCana drilled
1,065 net wells in the second quarter. Core capital investment, excluding
acquisitions and divestitures, was approximately $1.2 billion.

Second quarter oil and gas price realizations, excluding hedging impact
EnCana's second quarter realized pre-hedging North American natural gas
prices were up about 9 percent from the second quarter of 2003 to $5.34 per
thousand cubic feet. Realized pre-hedging oil and NGLs prices were up about
22 percent from the second quarter of 2003 to $28.00 per barrel. Canadian
heavy oil price differentials widened to average $11.02 per barrel compared to
$6.55 per barrel one year earlier. Ecuadorian NAPO blend, shipped on the new
OCP Pipeline, also experienced a wider price differential from WTI in the
second quarter of 2004, averaging $12.17 per barrel, compared to $8.06 per
barrel at year-end 2003. OCP began full operations in the fourth quarter of
2003.

Production growth on track
EnCana is on track to achieve its 2004 sales guidance of between 725,000
and 765,000 BOE per day, which at the midpoint is a 15 percent increase from
2003 sales volumes. Projected sales are comprised of between 2.95 billion and
3.05 billion cubic feet of natural gas per day and between 235,000 and 255,000
barrels of oil and NGLs per day. Upstream core capital is expected to be in
the range of $4,550 million and $4,850 million for 2004.

Cash flow exceeds $2 billion in first six months, sales up 20 percent
EnCana's first half 2004 cash flow, before tax, was $2,561 million, up
17 percent from the same 2003 period. After-tax, EnCana generated
$2,126 million of first half cash flow, or $4.55 per share diluted. This
includes a first half cash tax provision of $435 million, compared with a cash
tax recovery of $34 million in the first half of 2003. EnCana's first half
daily sales averaged 746,500 BOE, up 20 percent from the first half of 2003.
Daily sales were comprised of 2.9 billion cubic feet of gas and 267,000
barrels of oil and NGLs. In the first six months, EnCana drilled 2,684 net
wells, about half of the 5,500 net wells planned for 2004.

First half operating earnings were $844 million, up 8 percent
First half 2004 operating earnings were $844 million, or $1.81 per share
diluted, up about 8 percent from the first half of 2003. Net earnings in the
first six months were $540 million, or $1.16 per share diluted, which includes
three non-cash items: an after-tax unrealized mark-to-market loss of
$356 million, an after-tax unrealized loss on foreign exchange on US$
denominated debt issued in Canada of $57 million, and a $109 million gain due
to tax rate changes. First half 2004 revenues net of royalties were
$5,568 million.

Earnings impacted by change in accounting policy for unrealized hedging
losses
On January 1, 2004, EnCana was required to adopt the new accounting
standard governing oil and gas price hedging activities. EnCana expects that
this new standard will continue to result in greater volatility in its
reported net earnings. A complete discussion of the impact of this new
accounting standard is contained in Notes 2 and 14 of the unaudited second
quarter consolidated financial statements.

Resource play focus advanced with Tom Brown acquisition and conventional
asset sales
In recent months, EnCana has advanced its strategic focus on natural gas
resource growth plays. These plays are characterized by long-life, low-decline
production performance. With the acquisition of Tom Brown, Inc. in May, EnCana
initiated a two-step process that will see its proportion of anticipated
production from North American resource plays increase from 60 to
approximately 75 percent during 2004. In the first step, the company acquired
Tom Brown, a Denver-based, resource-play focused, gas exploration and
production company. Tom Brown's assets are an excellent fit with EnCana's
leading position in the Piceance Basin of the U.S. Rockies. The second step
will see the divestiture of between 40,000 and 60,000 BOE per day of
conventional oil and gas production. Since announcing the offer for Tom Brown
in April, EnCana has reached agreements on the divestiture of about 28,000 BOE
of daily production, the sale of Sauer Drilling Company of Casper, Wyoming and
the divestiture of two undeveloped oilsands leases in northeast Alberta for
total proceeds of about $940 million. EnCana expects to conclude these
transactions by early September. Additional asset packages have been
identified for divestiture in the near term. To date in 2004, EnCana has
divested of, or agreed to divest of, conventional, non-core properties
producing about 50,000 barrels of oil equivalent per day for total proceeds of
approximately $1.35 billion.
"North American conventional reservoirs are generally experiencing
increasing decline rates and decreasing reserve life - the combination of
which creates a treadmill effect that makes profitable production growth
difficult. EnCana's strategy of investing in unconventional North American
resource plays, while divesting of conventional assets, is expected to
continually slow our treadmill and enable us to focus on strong return
investments in long-life, low-decline assets. Based on reserve reports
prepared by independent qualified reserve evaluators at year-end 2003, the
decline rate of all of EnCana's proved developed reserve base was about
20 percent, which is expected to fall to less than 15 percent over the next
several years. Year-end 2004 booked reserves will reflect the acquisition of
Tom Brown and the divestiture of conventional reserves, further improving this
go forward picture," Morgan said.

Unbooked Resource Potential underpins EnCana's long-term, resource play
growth plan
Exploitation-style drilling activities and shallowing production decline
profiles are characteristics of resource plays. Hence, as more and more of
EnCana's production comes from the company's inventory of resource plays, the
reliability and predictability of the company's resource and production growth
forecasts continues to increase.
"Currently, about 17,000 long-life, shallow-decline, North American
natural gas resource play wells serve as the backbone of our production, and
their number continues to grow," Morgan said.
Reported proved reserves at year-end 2003 were about 2.4 billion BOE,
yielding a reserve life index of about 8.5 years based on current production
rates, which excludes proved reserves that have since been added via ongoing
field activities and the Tom Brown acquisition. Beyond that, EnCana estimates
that 3.5 billion BOE of Unbooked Resource Potential may be added to proved
reserves over the next five years. This Unbooked Resource Potential is largely
associated with our resource plays and therefore EnCana's investments are
mainly focused on low-risk exploitation rather than high risk exploration.
EnCana estimates this Unbooked Resource Potential to be about 16 trillion
cubic feet of natural gas and about 850 million barrels of oil and natural
gas, up approximately 60 percent over the past year due mainly to the addition
of the Cutbank Ridge resource play in British Columbia and the Tom Brown
acquisition. This means that, after production, proved reserves on existing
company lands are expected to increase about 75 percent over the next five
years. EnCana also has substantial conventional exploration potential on its
20 million net acres of undeveloped North American land that is not included
in its assessment of its Unbooked Resource Potential.
"It is the repeatable nature of the low-risk exploitation of both our
proved reserves and Unbooked Resource Potential that enables us to confidently
say that we expect our future production growth to average an annual rate of
at least 10 percent per share. In fact, we are projecting our gas production
will grow by 35 percent over the two-year period 2003 to 2005. This projected
resource play growth stands in stark contrast to weakening industry-wide,
conventional natural gas and oil production in North America," Morgan said.

Risk management strategy
EnCana's market risk mitigation strategy is designed to deliver greater
predictability of cash flow and returns on investment. Approximately half of
the company's projected 2004 gas sales, after royalties, is hedged at an
average effective NYMEX price of about $5.36 per thousand cubic feet. In
addition, the company has entered into longer term basis and pricing hedges
specifically for the purpose of protecting against high U.S. Rockies gas price
basis differentials. About half of EnCana's projected 2004 oil sales are
hedged with swaps or costless collars between $20 and $26 per barrel of WTI.
Detailed risk management positions at June 30, 2004 are presented in Note 14
to the unaudited second quarter consolidated financial statements for the
financial contracts and in Management's Discussion and Analysis for the
physical contracts. In the second quarter, EnCana's financial commodity and
currency risk management measures resulted in gross revenue being lower by
approximately $234 million, comprised of $164 million on oil sales and
$70 million on gas sales.

<<

Consolidated EnCana Highlights
------------------------------
US$ and U.S. protocols
----------------------

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Financial Highlights
(as at and for the
period ended June 30) 6 6
(US$ millions, except Q2 Q2 % months months %
per share amounts) 2004 2003 change 2004 2003 change
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Revenues, net of
royalties 2,718 2,332 + 17 5,568 5,075 + 10

Operating EBITDA(1) 1,399 1,016 + 38 2,704 2,289 + 18

Cash flow 1,131 1,007 + 12 2,126 2,228 - 5
Per share - basic 2.46 2.10 + 17 4.62 4.64 -
Per share - diluted 2.43 2.08 + 17 4.55 4.61 - 1
Add back:
---------
Cash tax 203 (54) n/a 435 (34) n/a

Pre-tax cash flow 1,334 953 + 40 2,561 2,194 + 17

Capital investment
Core capital 1,201 862 + 39 2,605 1,843 + 41
Net acquisitions
and divestitures 2,235 208 + 975 2,056 347 + 493
Net capital
investment
- continuing
operations 3,436 1,070 + 221 4,661 2,190 + 113

Net earnings 250 807 - 69 540 1,644 - 67
Per share - basic 0.54 1.68 - 68 1.17 3.42 - 66
Per share - diluted 0.54 1.67 - 68 1.16 3.40 - 66

Net earnings from
continuing operations 250 805 - 69 540 1,455 - 63
Per share - basic 0.54 1.67 - 68 1.17 3.03 - 61
Per share - diluted 0.54 1.66 - 67 1.16 3.01 - 61
Add back:
---------
Mark-to-market price
hedging impact,
after-tax 104 - n/a 356 - n/a
Add back:
---------
Foreign exchange
translation of
U.S. dollar debt
issued in Canada,
after-tax 25 (168) - 115 57 (308) - 119
Less:
-----
Tax rate change - (362) n/a (109) (362) - 70

Operating earnings 379 275 + 38 844 785 + 8
Per share - basic 0.82 0.57 + 44 1.83 1.63 + 12
Per share - diluted 0.81 0.56 + 45 1.81 1.62 + 12
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Common shares at
June 30 (millions)
Weighted average
(basic) 460.3 480.6 - 4 460.6 480.3 - 4
Weighted average
(diluted) 465.5 484.4 - 4 466.8 483.8 - 4
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(1) Operating EBITDA is net earnings from continuing operations before
interest, income taxes, depreciation, depletion and amortization
(DD&A), accretion of asset retirement obligation, foreign exchange
loss (gain), gain on disposition and unrealized loss on risk
management ($531 million, year-to-date, before tax).



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Operating Highlights
(for the period
ended June 30) 6 6
Q2 Q2 % months months %
2004 2003 change 2004 2003 change
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(After royalties)
Natural Gas (MMcf/d)
Production
(excluding TBI) 2,905 2,469 + 18 2,810 2,468 + 14
TBI production 132 - n/a 65 - n/a
Produced gas withdrawn
from storage - - - - 60 n/a
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Total natural gas
sales (MMcf/d) 3,037 2,469 + 23 2,875 2,528 + 14
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Oil and NGLs sales
(bbls/d)
North America 170,687 159,668 + 7 168,283 157,991 + 7
International 99,031 46,240 + 114 99,051 44,073 + 125
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Total oil and NGLs
sales (bbls/d) 269,718 205,908 + 31 267,334 202,064 + 32
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Total sales
(BOE/d) 775,885 617,408 + 26 746,501 623,397 + 20
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Per share sales
growth + 31 + 26
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Resource plays continue to deliver strong growth
In North America, EnCana's growth continues to be delivered from its low
decline resource plays. Second quarter oil and gas production from EnCana's
key North American resource plays has increased more than 33 percent since the
second quarter of 2003. This was driven principally by increases in gas
production at Mamm Creek in Colorado, Greater Sierra in northeast B.C., and
Southern Plains shallow gas on legacy Suffield and Palliser Blocks in southern
Alberta, plus increases in oil production at Foster Creek and Pelican Lake in
northeast Alberta.

Growth from key North American resource plays

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Resource play Daily Production
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2004 2003
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Natural gas (MMcf/d) YTD Q2 Q1 Q4 Q3 Q2 Q1
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Canada
Southern Plains
shallow gas 572 590 554 538 509 499 483
Greater Sierra 231 247 216 175 144 136 118
Cutbank Ridge 32 41 22 6 2 2 2
Coalbed methane 10 11 10 7 3 3 2
U.S.A.
Jonah 390 387 394 389 376 356 375
Mamm Creek 197 203 191 175 126 112 86
North Texas 22 23 21 19 12 - -
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Oil (Mbbls/d) (Canada)
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Foster Creek 29 30 28 26 22 20 19
Pelican Lake 15 15 15 15 16 17 15
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---------------------------------------------------
Resource play Net Wells Drilled
----------------------------------------------------
2004 2003
----------------------------------------------------
Full
Natural gas (MMcf/d) YTD Q2 Q1 year
----------------------------------------------------
Canada
Southern Plains
shallow gas 946 416 530 2,366
Greater Sierra 156 21 135 199
Cutbank Ridge 21 4 17 20
Coalbed methane 179 98 81 267
U.S.A.
Jonah 32 21 11 59
Mamm Creek 131 65 66 259
North Texas 18 10 8 5
----------------------------------------------------
----------------------------------------------------
Oil (Mbbls/d) (Canada)
----------------------------------------------------
Foster Creek 4 - 4 8
Pelican Lake 59 30 29 134
----------------------------------------------------
----------------------------------------------------


Corporate developments
----------------------

Dividend $0.10 per share
EnCana's board of directors has declared a quarterly dividend of $0.10
per share payable on September 30, 2004 to common shareholders of record as of
September 15, 2004.

Normal Course Issuer Bid purchases
To date in 2004, EnCana has purchased for cancellation 5.5 million of its
shares at an average price of C$55.37 per share under its current Normal
Course Issuer Bid and 5.9 million shares were issued to employees under the
company's stock option plan. The company had approximately 461.0 million
shares outstanding at June 30, 2004.

Financial strength
------------------

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Balance Sheet Highlights
(US$ millions, except percent and June 30 December 31
ratio amounts) 2004 2003
-------------------------------------------------------------------------
Total assets 28,976 24,110
Long-term debt 8,582 6,088
Shareholders' equity 11,405 11,278

Net debt-to-capitalization ratio 45% 34%
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(Pro forma impact of announced third quarter
asset sales)
Long-term debt 7,642 n/a
Net debt-to-capitalization ratio 43% n/a
Debt/Trailing EBITDA 2.0 times n/a
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Following the announcement of the all cash Tom Brown acquisition, credit
rating agencies adjusted EnCana's long term credit ratings. On July 14, 2004,
Moody's lowered EnCana's rating from Baa1 to Baa2 (Stable). Standard and
Poor's modified EnCana's A- rating noting that the company is under a
"CreditWatch with negative implications." Its review is ongoing. Dominion Bond
Rating Service has confirmed EnCana's A(low) rating noting a trend change from
"Stable" to "Negative." EnCana has ongoing discussions with the rating
agencies to update them on general corporate matters including the positive
balance sheet impact of current and planned divestiture programs. The company
also has a $3 billion committed credit facility with a syndicate of major
banks and lending institutions, of which about $850 million remains
unutilized. To fund the Tom Brown acquisition, EnCana arranged a further
$3 billion non-revolving bridge financing. The financing was reduced to
$1.8 billion, of which $1.74 billion was drawn. On May 13, EnCana Holdings
Finance Corp., an EnCana subsidiary, completed a public offering for
$1 billion, 5.8% Notes due 2014, to fund the remaining cash requirement for
the Tom Brown acquisition.
In the second quarter of 2004, EnCana invested $1,201 million of core
capital, acquisitions totaled $2,341 million and divestitures were
$106 million, resulting in net capital investment of $3,436 million. This
includes the Tom Brown acquisition cost. Subsequent to the end of the second
quarter, agreements were reached on asset sales totaling about $660 million.
Additional asset sales are expected in the near term.

----------------------------------------------------------
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EnCana 2004 capital investment forecast

Figures are based on midpoint of the ranges
outlined in EnCana's capital investment guidance

Upstream (US$ MM)
---------
Core capital 4,700
Acquisition of Tom Brown 2,700

Acquisitions and Divestitures
Divestitures, completed and pending
Petrovera (288)
New Mexico assets (243)
July 15 oil assets (395)
July 20 gas assets (219)
Other minor sales (195)
---------
(1,340) (1,340)
Acquisitions, minor 140
Planned additional divestitures (550)
---------
(1,750)
Total Upstream net capital 5,650
Midstream, marketing & corporate 150
---------
Net capital investment 5,800
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CONFERENCE CALL TODAY
EnCana Corporation will host a conference call today, Tuesday, July 27,
2004 starting at 11 a.m., Mountain Time (1 p.m. Eastern Time), to discuss
EnCana's second quarter 2004 financial and operating results.
To participate, please dial (719) 457-2692 approximately 10 minutes prior
to the conference call. An archived recording of the call will be
available from approximately 5 p.m. on July 27, 2004 until midnight
August 2, 2004 by dialing (888) 203-1112 or (719) 457-0820 and entering
pass code 494954.
A live audio Web cast of the conference call will also be available via
EnCana's Web site, www.encana.com, under Investor Relations. The Web cast
will be archived for approximately 90 days.
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Non-GAAP measures
This news release contains references to cash flow, pre-tax cash flow,
operating EBITDA (net earnings from continuing operations before interest,
income taxes, DD&A, accretion of asset retirement obligation, foreign exchange
loss (gain), gain on disposition and unrealized loss on risk management),
EBITDA and operating earnings, and the related basic and diluted per common
share amounts as applicable, which are not measures that have any standardized
meaning prescribed by Canadian GAAP and 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
press release in order to provide shareholders and potential investors with
additional information regarding EnCana's liquidity and its ability to
generate funds to finance its operations.

EnCana Corporation
With an enterprise value of approximately $28 billion, EnCana is one of
the world's leading independent oil and gas companies and North America's
largest independent natural gas producer and gas storage operator. Ninety
percent of the company's assets are located in North America. EnCana is the
largest producer and landholder in Western Canada and is a key player in
Canada's emerging offshore East Coast basins. Through its U.S. subsidiaries,
EnCana is one of the largest gas explorers and producers in the Rocky Mountain
states and has a strong position in the deep water Gulf of Mexico.
International subsidiaries operate two key high potential international growth
regions: Ecuador, where it is the largest private sector oil producer, and the
U.K., where it is the operator of a large oil discovery. EnCana and its
subsidiaries also conduct high upside potential new ventures exploration in
other parts of the world. EnCana is driven to be the industry's high
performance benchmark in production cost, per-share growth and value creation
for shareholders. EnCana common shares trade on the Toronto and New York stock
exchanges under the symbol ECA.

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

EnCana Corporation resource descriptions
EnCana uses the terms resource play, estimated ultimate recovery,
resource potential and Unbooked 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 (EUR) 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. EnCana's current stated estimates of Unbooked Resource Potential uses a
five year time frame for their specified period of time.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - In the interests of
providing EnCana shareholders and potential investors with information
regarding EnCana, including management's assessment of EnCana's and its
subsidiaries' future plans and operations, certain statements contained in
this news release are forward-looking statements within the meaning of the
"safe harbour" provisions of the United States Private Securities Litigation
Reform Act of 1995. Forward-looking statements in this news release include,
but are not limited to: production, sales and growth estimates for crude oil,
natural gas and NGLs for 2004 and the next 5 years, including estimates
calculated on a per share basis; the Company's projections with respect to the
percentage of production from resource plays in the future and the impact of
increasing the Company's proportion of resource play assets on future decline
rates and the reliability and predictability of resource and production
growth; the resource potential, Unbooked Resource Potential, production and
growth potential, including the Company's plans therefor, and capital costs
associated therewith with respect to EnCana's various assets and initiatives,
including assets and initiatives in North America, Ecuador, the U.K. central
North Sea, the Gulf of Mexico and potential international exploration;
estimates of resource life; the Company's projections relating to regulatory
approvals; potential dispositions of assets in 2004 and beyond, including
anticipated proceeds therefrom and the dates for receipt thereof; the
Company's projected capital investment levels for 2004 and 2005, and the
source of funding therefor; projected additional production from the Tom
Brown, Inc. acquisition and the impact on production levels of proposed asset
dispositions; the effect of the Company's risk management program, including
the impact of derivative financial instruments; projected levels of hedging
for Tom Brown, Inc. production in 2004 through 2006; the Company's projections
for reductions in net debt and net debt to capitalization by the end of 2004;
projected operating and administrative costs for 2004; projected DD&A rates
for 2004 and beyond; projected levels of, and volatility of, crude oil and
natural gas prices in 2004 and beyond and the potential causes therefor,
including the impact which weather, the timing of new production, economic
activity levels and political instability may have on commodity prices in the
near term; projected tax rates and projected current taxes payable for 2004
and the impact of future unrealized foreign exchange gains and losses thereon
and the adequacy of the Company's provision for taxes; the impact of the AEUB
ruling on natural gas production for 2004 and beyond; projections with respect
to the number of wells drilled and well tie-ins made in 2004; the impact of
new oil and natural gas price hedging accounting standards, including their
impact on the volatility of future reported net earnings; Unbooked Resource
Potential which may be recognized as proved reserves in the future;
projections with respect to anticipated future cash flow levels; projections
with respect to potential future drilling and service cost escalations and the
impact of the Company's divestitures and potential divestitures on operating
costs, netbacks and decline rates. Readers are cautioned not to place undue
reliance on forward-looking statements, as there can be no assurance that the
plans, intentions or expectations upon which they are based will occur. By
their nature, forward-looking statements involve numerous assumptions, known
and unknown risks and uncertainties, both general and specific, that
contribute to the possibility that the predictions, forecasts, projections and
other forward-looking statements will not occur, which may cause the
company's actual performance and financial results in future periods to differ
materially from any estimates or projections of future performance or results
expressed or implied by such forward-looking statements. These 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 company's marketing operations, including
credit risks; imprecision of reserves estimates and estimates of recoverable
quantities of oil, natural gas and liquids from resource plays and other
sources not currently classified as proved reserves; the company's ability to
replace and expand oil and gas reserves; its ability to generate sufficient
cash flow from operations to meet its current and future obligations; its
ability to access external sources of debt and equity capital; the timing and
the costs of well and pipeline construction; the company's ability to secure
adequate product transportation; changes in environmental and other
regulations; political and economic conditions in the countries in which the
company operates, including Ecuador; the risk of war, hostilities, civil
insurrection and instability affecting countries in which the company operates
and terrorist threats; risks associated with existing and potential future
lawsuits and regulatory actions made against the company; and other risks and
uncertainties described from time to time in the reports and filings made with
securities regulatory authorities by EnCana. Although EnCana believes that the
expectations represented by such forward-looking statements are reasonable,
there can be no assurance that such expectations will prove to be correct.
Readers are cautioned that the foregoing list of important factors is not
exhaustive.
Furthermore, the forward-looking statements contained in this news
release are made as of the date of this news release, 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 news
release are expressly qualified by this cautionary statement.



Interim Consolidated Financial Statements
(unaudited)
For the period ended June 30, 2004


EnCana Corporation


U.S. DOLLARS




Interim Report PREPARED IN US$
For the period ended June 30, 2004

EnCana Corporation
CONSOLIDATED STATEMENT OF EARNINGS (unaudited)

June 30
---------------------------------------
Three Months Ended Six Months Ended
(US$ millions, except ---------------------------------------
per share amounts) 2004 2003 2004 2003
-------------------------------------------------------------------------

REVENUES, NET OF
ROYALTIES (Note 5)
Upstream $ 1,975 $ 1,492 $ 3,783 $ 3,142
Midstream & Marketing 898 839 2,317 1,932
Corporate (155) 1 (532) 1
-------------------------------------------------------------------------
2,718 2,332 5,568 5,075

EXPENSES (Note 5)
Production and
mineral taxes 96 48 161 98
Transportation
and selling 162 125 324 250
Operating 346 325 699 638
Purchased product 822 769 2,109 1,714
Depreciation, depletion
and amortization 733 501 1,357 972
Administrative 44 43 93 80
Interest, net 96 67 175 131
Accretion of asset
retirement
obligation (Note 10) 5 5 12 10
Foreign exchange
loss (gain) (Note 7) 21 (206) 79 (416)
Stock-based
compensation 4 6 9 6
Gain on dispositions (Note 4) (1) - (35) -
-------------------------------------------------------------------------
2,328 1,683 4,983 3,483
-------------------------------------------------------------------------
NET EARNINGS BEFORE
INCOME TAX 390 649 585 1,592
Income tax expense
(recovery) (Note 8) 140 (156) 45 137
-------------------------------------------------------------------------
NET EARNINGS FROM
CONTINUING OPERATIONS 250 805 540 1,455
NET EARNINGS FROM
DISCONTINUED
OPERATIONS (Note 6) - 2 - 189
-------------------------------------------------------------------------
NET EARNINGS $ 250 $ 807 $ 540 $ 1,644
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS FROM
CONTINUING OPERATIONS
PER COMMON SHARE (Note 13)
Basic $ 0.54 $ 1.67 $ 1.17 $ 3.03
Diluted $ 0.54 $ 1.66 $ 1.16 $ 3.01
-------------------------------------------------------------------------
-------------------------------------------------------------------------

NET EARNINGS
PER COMMON SHARE (Note 13)
Basic $ 0.54 $ 1.68 $ 1.17 $ 3.42
Diluted $ 0.54 $ 1.67 $ 1.16 $ 3.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------



CONSOLIDATED STATEMENT OF RETAINED EARNINGS
-------------------
Six Months Ended
June 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 540 1,644
Dividends on Common Shares (92) (68)
Charges for Normal Course Issuer Bid (Note 11) (126) (6)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 5,598 $ 5,093
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.




Interim Report PREPARED IN US$
For the period ended June 30, 2004

EnCana Corporation
CONSOLIDATED BALANCE SHEET (unaudited)

As at As at
June December
30, 31,
(US$ millions) 2004 2003
-------------------------------------------------------------------------

ASSETS
Current Assets
Cash and cash equivalents $ 202 $ 148
Accounts receivable and accrued revenues 1,953 1,367
Risk management (Note 14) 64 -
Inventories 545 573
Assets held for sale (Note 3) 278 -
-------------------------------------------------------------------------
3,042 2,088
Property, Plant and Equipment, net (Note 5) 22,963 19,545
Investments and Other Assets 582 566
Risk Management (Note 14) 91 -
Goodwill 2,298 1,911
-------------------------------------------------------------------------
(Note 5) $ 28,976 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------


LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 2,004 $ 1,579
Risk management (Note 14) 597 -
Income tax payable 408 65
Current portion of long-term debt (Note 9) 733 287
-------------------------------------------------------------------------
3,742 1,931
Long-Term Debt (Note 9) 8,582 6,088
Other Liabilities 101 21
Risk Management (Note 14) 122 -
Asset Retirement Obligation (Note 10) 467 430
Future Income Taxes 4,557 4,362
-------------------------------------------------------------------------
17,571 12,832
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 11) 5,382 5,305
Share options, net 25 55
Paid in surplus 37 18
Retained earnings 5,598 5,276
Foreign currency translation adjustment 363 624
-------------------------------------------------------------------------
11,405 11,278
-------------------------------------------------------------------------
$ 28,976 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



Interim Report PREPARED IN US$
For the period ended June 30, 2004

EnCana Corporation
CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)

June 30
---------------------------------------
Three Months Ended Six Months Ended
---------------------------------------
(US$ millions) 2004 2003 2004 2003
-------------------------------------------------------------------------

OPERATING ACTIVITIES
Net earnings from
continuing operations $ 250 $ 805 $ 540 $ 1,455
Depreciation, depletion
and amortization 733 501 1,357 972
Future income taxes (Note 8) (63) (102) (390) 171
Unrealized loss on
risk management (Note 14) 155 - 531 -
Unrealized foreign
exchange loss (gain) (Note 7) 32 (211) 71 (389)
Accretion of asset
retirement
obligation (Note 10) 5 5 12 10
Gain on dispositions (Note 4) (1) - (35) -
Other 20 41 40 11
-------------------------------------------------------------------------
Cash flow from
continuing operations 1,131 1,039 2,126 2,230
Cash flow from
discontinued operations - (32) - (2)
-------------------------------------------------------------------------
Cash flow 1,131 1,007 2,126 2,228
Net change in other
assets and liabilities (41) 17 (46) 29
Net change in non-cash
working capital from
continuing operations (294) 10 173 41
Net change in non-cash
working capital from
discontinued operations - 46 - 57
-------------------------------------------------------------------------
796 1,080 2,253 2,355
-------------------------------------------------------------------------

INVESTING ACTIVITIES
Business combination
with Tom Brown, Inc. (Note 3) (2,335) - (2,335) -
Capital expenditures (Note 5) (1,207) (1,082) (2,745) (2,093)
Proceeds on disposal
of property, plant
and equipment 106 12 131 19
Dispositions
(acquisitions) (Note 4) - - 288 (116)
Equity investments (Note 4) - (88) 44 (133)
Net change in
investments and other (20) (4) (22) (27)
Net change in non-cash
working capital from
continuing operations (131) (24) (46) (158)
Discontinued operations - (11) - 1,278
-------------------------------------------------------------------------
(3,587) (1,197) (4,685) (1,230)
-------------------------------------------------------------------------

FINANCING ACTIVITIES
Issuance of
long-term debt 3,195 361 3,195 361
Repayment of
long-term debt (433) - (536) (892)
Issuance of common
shares (Note 11) 43 54 154 83
Purchase of common
shares (Note 11) (12) (122) (230) (122)
Dividends on common
shares (46) (35) (92) (68)
Other (4) (12) (5) (13)
Discontinued operations - - - (282)
-------------------------------------------------------------------------
2,743 246 2,486 (933)
-------------------------------------------------------------------------

DEDUCT: FOREIGN EXCHANGE
LOSS ON CASH AND CASH
EQUIVALENTS HELD IN
FOREIGN CURRENCY - 6 - 8
-------------------------------------------------------------------------

INCREASE (DECREASE) IN
CASH AND CASH EQUIVALENTS (48) 123 54 184
CASH AND CASH EQUIVALENTS,
BEGINNING OF YEAR 250 177 148 116
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 202 $ 300 $ 202 $ 300
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.





Interim Report PREPARED IN US$
For the period ended June 30, 2004

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
June 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 Company's 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 June 30, 2004, it is estimated that over the following
12 months, $102 million ($72 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 3 $ (51)
Quarter 4 (64)
-------------------------------------------------------------------------
Total remaining to be recognized in 2004 $ (115)
-------------------------------------------------------------------------

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 $ (44)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At June 30, 2004, the remaining net deferred loss totalled $44 million of
which $139 million was recorded in Accounts receivable and accrued
revenues, $3 million in Investments and other assets, $37 million in
Accounts payable and accrued liabilities and $61 million in Other
liabilities.


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 transactions are expected to
close in the third quarter of 2004.


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 $288 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 $541 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. This purchase was accounted for using the purchase method
with the results reflected in the consolidated results of EnCana from the
date 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 Company's exploration for, and development and
production of, natural gas, natural gas liquids and crude oil and
other related activities. The majority of the Company's 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 Company's 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 Company's 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.


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

Midstream &
Upstream Marketing
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 1,975 $ 1,492 $ 898 $ 839

Expenses
Production and mineral taxes 96 48 - -
Transportation and selling 154 110 8 15
Operating 280 242 69 83
Purchased product - - 822 769
Depreciation, depletion and
amortization 674 483 45 7
-------------------------------------------------------------------------
Segment Income $ 771 $ 609 $ (46) $ (35)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties (*) $ (155) $ 1 $ 2,718 $ 2,332

Expenses
Production and mineral taxes - - 96 48
Transportation and selling - - 162 125
Operating (3) - 346 325
Purchased product - - 822 769
Depreciation, depletion and
amortization 14 11 733 501
-------------------------------------------------------------------------
Segment Income $ (166) $ (10) 559 564
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 44 43
Interest, net 96 67
Accretion of asset retirement
obligation 5 5
Foreign exchange loss (gain) 21 (206)
Stock-based compensation 4 6
Gain on dispositions (1) -
-------------------------------------------------------------------------
169 (85)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 390 649
Income tax expense (recovery) 140 (156)
-------------------------------------------------------------------------
Net Earnings from Continuing Operations $ 250 $ 805
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) Corporate revenue primarily reflects unrealized gains or losses
recorded on derivative instruments. See also Note 14.


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

Upstream Canada United States Ecuador
-----------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of
Royalties $1,266 $1,084 $ 443 $ 253 $ 147 $ 75
Expenses
Production and
mineral taxes 18 20 65 24 13 4
Transportation
and selling 84 80 45 19 14 8
Operating 161 158 28 15 29 19
Depreciation, depletion
and amortization 435 365 117 67 69 31
-------------------------------------------------------------------------
Segment Income $ 568 $ 461 $ 188 $ 128 $ 22 $ 13
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Transportation and selling in 2004 for the United States includes a
one-time payment of $21 million made 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 $ 65 $ 24 $ 54 $ 56 $1,975 $1,492
Expenses
Production and
mineral taxes - - - - 96 48
Transportation
and selling 11 3 - - 154 110
Operating 14 4 48 46 280 242
Depreciation, depletion
and amortization 34 19 19 1 674 483
-------------------------------------------------------------------------
Segment Income $ 6 $ (2) $ (13) $ 9 $ 771 $ 609
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total Midstream
Midstream & Marketing Midstream Marketing & Marketing
-----------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues $ 172 $ 151 $ 726 $ 688 $ 898 $ 839
Expenses
Transportation and
selling - - 8 15 8 15
Operating 56 52 13 31 69 83
Purchased product 118 107 704 662 822 769
Depreciation, depletion
and amortization 43 7 2 - 45 7
-------------------------------------------------------------------------
Segment Income $ (45) $ (15) $ (1) $ (20) $ (46) $ (35)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Midstream Depreciation, depletion and amortization in 2004 includes a
$35 million impairment charge on the Company's interest in Oleoducto
Trasandino in Argentina and Chile.


Upstream Geographic and Product Information
(For the three months ended June 30)


Produced Gas Produced Gas
--------------------------------------------------------
United U.K.
Canada States North Sea Total
-------------------------------------------------------------------------
2004 2003 2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net
of Royalties $ 981 $ 803 $ 406 $ 230 $ 13 $ 3 $1,400 $1,036
Expenses
Production and
mineral taxes 13 14 60 24 - - 73 38
Transportation
and selling 69 61 45 19 8 3 122 83
Operating 97 82 28 15 - - 125 97
-------------------------------------------------------------------------
Operating Cash
Flow $ 802 $ 646 $ 273 $ 172 $ 5 $ - $1,080 $ 818
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Transportation and selling in 2004 for the United States includes a
one-time payment of $21 million made to terminate a long-term physical
delivery contract.


Oil & NGLs Oil & NGLs
-----------------------------------------------
Canada United States Ecuador
-------------------------------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 285 $ 281 $ 37 $ 23 $ 147 $ 75
Expenses
Production and
mineral taxes 5 6 5 - 13 4
Transportation
and selling 15 19 - - 14 8
Operating 64 76 - - 29 19
-------------------------------------------------------------------------
Operating Cash Flow $ 201 $ 180 $ 32 $ 23 $ 91 $ 44
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Oil & NGLs
-------------------------------
U.K. North Sea Total
-------------------------------------------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 52 $ 21 $ 521 $ 400
Expenses
Production and mineral taxes - - 23 10
Transportation and selling 3 - 32 27
Operating 14 4 107 99
-------------------------------------------------------------------------
Operating Cash Flow $ 35 $ 17 $ 359 $ 264
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other & Total Upstream Other Total Upstream
-------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 54 $ 56 $1,975 $1,492
Expenses
Production and mineral taxes - - 96 48
Transportation and selling - - 154 110
Operating 48 46 280 242
-------------------------------------------------------------------------
Operating Cash Flow $ 6 $ 10 $1,445 $1,092
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Results of Operations (For the six months ended June 30)

Midstream &
Upstream Marketing
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 3,783 $ 3,142 $ 2,317 $ 1,932

Expenses
Production and mineral taxes 161 98 - -
Transportation and selling 308 217 16 33
Operating 557 461 147 177
Purchased product - - 2,109 1,714
Depreciation, depletion and
amortization 1,275 942 52 12
-------------------------------------------------------------------------
Segment Income $ 1,482 $ 1,424 $ (7) $ (4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Corporate Consolidated
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties (*) $ (532) $ 1 $ 5,568 $ 5,075

Expenses
Production and mineral taxes - - 161 98
Transportation and selling - - 324 250
Operating (5) - 699 638
Purchased product - - 2,109 1,714
Depreciation, depletion
and amortization 30 18 1,357 972
-------------------------------------------------------------------------
Segment Income $ (557) $ (17) $ 918 $ 1,403
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Administrative 93 80
Interest, net 175 131
Accretion of asset retirement
obligation 12 10
Foreign exchange loss (gain) 79 (416)
Stock-based compensation 9 6
Gain on dispositions (35) -
-------------------------------------------------------------------------
333 (189)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 585 1,592
Income tax expense (recovery) 45 137
-------------------------------------------------------------------------
Net Earnings from Continuing
Operations $ 540 $ 1,455
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(*) Corporate revenue primarily reflects unrealized gains or losses
recorded on derivative instruments. See also Note 14.


Results of Operations (For the six months ended June 30)


Upstream
Canada United States Ecuador
-----------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of
Royalties $2,487 $2,271 $ 801 $ 564 $ 273 $ 162
Expenses
Production and
mineral taxes 38 29 99 53 24 16
Transportation
and selling 186 161 70 34 33 15
Operating 335 312 48 25 59 34
Depreciation, depletion
and amortization 851 712 199 133 134 54
-------------------------------------------------------------------------
Segment Income $1,077 $1,057 $ 385 $ 319 $ 23 $ 43
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Transportation and selling in 2004 for the United States includes a
one-time payment of $21 million made 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 $ 118 $ 56 $ 104 $ 89 $3,783 $3,142
Expenses
Production and
mineral taxes - - - - 161 98
Transportation
and selling 19 7 - - 308 217
Operating 20 7 95 83 557 461
Depreciation, depletion
and amortization 67 41 24 2 1,275 942
-------------------------------------------------------------------------
Segment Income $ 12 $ 1 $ (15) $ 4 $1,482 $1,424
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Total Midstream
Midstream & Marketing Midstream Marketing & Marketing
-----------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues $ 723 $ 469 $1,594 $1,463 $2,317 $1,932
Expenses
Transportation
and selling - - 16 33 16 33
Operating 127 131 20 46 147 177
Purchased product 567 311 1,542 1,403 2,109 1,714
Depreciation, depletion
and amortization 50 11 2 1 52 12
-------------------------------------------------------------------------
Segment Income $ (21) $ 16 $ 14 $ (20) $ (7) $ (4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Midstream Depreciation, depletion and amortization in 2004 includes a
$35 million impairment charge on the Company's interest in Oleoducto
Trasandino in Argentina and Chile.


Upstream Geographic and Product Information
(For the six months ended June 30)

Produced Gas Produced Gas
--------------------------------------------------------
United U.K.
Canada States North Sea Total
-------------------------------------------------------------------------
2004 2003 2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net
of Royalties $1,917 $1,728 $ 736 $ 517 $ 26 $ 6 $2,679 $2,251
Expenses
Production and
mineral taxes 28 18 91 52 - - 119 70
Transportation
and selling 150 122 70 34 12 5 232 161
Operating 198 169 48 25 - - 246 194
-------------------------------------------------------------------------
Operating
Cash Flow $1,541 $1,419 $ 527 $ 406 $ 14 $ 1 $2,082 $1,826
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Transportation and selling in 2004 for the United States includes a
one-time payment of $21 million made to terminate a long-term physical
delivery contract.

Oil & NGLs Oil & NGLs
-----------------------------------------------
Canada United States Ecuador
-------------------------------------------------------------------------
2004 2003 2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of
Royalties $ 570 $ 543 $ 65 $ 47 $ 273 $ 162
Expenses
Production and
mineral taxes 10 11 8 1 24 16
Transportation
and selling 36 39 - - 33 15
Operating 137 143 - - 59 34
-------------------------------------------------------------------------
Operating Cash Flow $ 387 $ 350 $ 57 $ 46 $ 157 $ 97
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Oil & NGLs
-------------------------------
U.K. North Sea Total
-------------------------------------------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 92 $ 50 $1,000 $ 802
Expenses
Production and mineral taxes - - 42 28
Transportation and selling 7 2 76 56
Operating 20 7 216 184
-------------------------------------------------------------------------
Operating Cash Flow $ 65 $ 41 $ 666 $ 534
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Other & Total Upstream Other Total Upstream
-------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 104 $ 89 $3,783 $3,142
Expenses
Production and mineral taxes - - 161 98
Transportation and selling - - 308 217
Operating 95 83 557 461
-------------------------------------------------------------------------
Operating Cash Flow $ 9 $ 6 $2,757 $2,366
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Capital Expenditures
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Upstream
Canada $ 675 $ 679 $ 1,703 $ 1,386
United States 316 196 526 346
Ecuador 56 34 110 107
United Kingdom 116 10 329 26
Other Countries 19 31 34 48
-------------------------------------------------------------------------
1,182 950 2,702 1,913
Midstream & Marketing 16 113 25 149
Corporate 9 19 18 31
-------------------------------------------------------------------------
Total $ 1,207 $ 1,082 $ 2,745 $ 2,093
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Property, Plant and Equipment and Total Assets

Property, Plant
and Equipment Total Assets
---------------------------------------
As at As at
---------------------------------------
June December June December
30, 31, 30, 31,
2004 2003 2004 2003
-------------------------------------------------------------------------

Upstream $ 21,980 $ 18,532 $ 26,373 $ 21,742
Midstream & Marketing 768 784 1,763 1,879
Corporate 215 229 840 489
-------------------------------------------------------------------------
Total $ 22,963 $ 19,545 $ 28,976 $ 24,110
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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
June 30, 2003
-----------------------------
Midstream -
Syncrude Pipelines Total
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 19 $ - $ 19

Expenses
Transportation and selling 1 - 1
Operating 14 - 14
Depreciation, depletion and amortization 1 - 1
Gain on discontinuance - - -
-------------------------------------------------------------------------
16 - 16
-------------------------------------------------------------------------
Net Earnings Before Income Tax 3 - 3
Income tax expense 1 - 1
-------------------------------------------------------------------------
Net Earnings from Discontinued Operations $ 2 $ - $ 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Consolidated Statement of Earnings For the six months ended
June 30, 2003
-----------------------------
Midstream -
Syncrude Pipelines Total
-------------------------------------------------------------------------

Revenues, Net of Royalties $ 79 $ - $ 79
-------------------------------------------------------------------------

Expenses
Transportation and selling 2 - 2
Operating 42 - 42
Depreciation, depletion and amortization 6 - 6
Gain on discontinuance - (220) (220)
-------------------------------------------------------------------------
50 (220) (170)
-------------------------------------------------------------------------
Net Earnings Before Income Tax 29 220 249
Income tax expense 9 51 60
-------------------------------------------------------------------------
Net Earnings from Discontinued Operations $ 20 $ 169 $ 189
-------------------------------------------------------------------------
-------------------------------------------------------------------------


7. FOREIGN EXCHANGE LOSS (GAIN)

Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Unrealized Foreign Exchange Loss
(Gain) on Translation of U.S.
Dollar Debt Issued in Canada $ 32 $ (211) $ 71 $ (389)
Realized Foreign Exchange Loss
(Gain) (11) 5 8 (27)
-------------------------------------------------------------------------
$ 21 $ (206) $ 79 $ (416)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


8. INCOME TAXES

The provision for income taxes is as follows:

Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Current
Canada $ 160 $ (61) $ 365 $ (49)
United States 7 - 15 -
Ecuador 35 5 54 13
United Kingdom - 2 - 2
Other 1 - 1 -
-------------------------------------------------------------------------
Total Current Tax 203 (54) 435 (34)

Future (63) 260 (281) 533
Future Tax Rate Reductions(*) - (362) (109) (362)
-------------------------------------------------------------------------
Total Future Tax (63) (102) (390) 171
-------------------------------------------------------------------------
$ 140 $ (156) $ 45 $ 137
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) 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 Six Months Ended
June 30, June 30,
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Net Earnings Before Income Tax $ 390 $ 649 $ 585 $ 1,592
Canadian Statutory Rate 39.1% 41.0% 39.1% 41.0%
-------------------------------------------------------------------------

Expected Income Taxes 153 266 229 652

Effect on Taxes Resulting from:
Non-deductible Canadian crown
payments 51 54 103 132
Canadian resource allowance (59) (45) (116) (150)
Canadian resource allowance on
unrealized risk management losses 6 - 27 -
Statutory and other rate
differences (21) (13) (30) (24)
Effect of tax rate changes - (362) (109) (362)
Non-taxable capital gains 7 (36) 14 (70)
Previously unrecognized capital
losses 2 - 15 -
Tax recovery on dispositions (23) - (103) -
Large corporations tax 3 10 7 17
Other 21 (30) 8 (58)
-------------------------------------------------------------------------
$ 140 $ (156) $ 45 $ 137
-------------------------------------------------------------------------
Effective Tax Rate 35.9% (24.0%) 7.7% 8.6%
-------------------------------------------------------------------------
-------------------------------------------------------------------------



9. LONG-TERM DEBT
As at As at
June 30, December 31,
2004 2003
-------------------------------------------------------------------------

Canadian Dollar Denominated Debt
Revolving credit and term loan borrowings $ 1,660 $ 1,425
Unsecured notes and debentures 1,250 1,335
Preferred securities 149 252
-------------------------------------------------------------------------
3,059 3,012
-------------------------------------------------------------------------

U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings 2,306 417
Unsecured notes and debentures 3,722 2,713
Preferred securities 150 150
-------------------------------------------------------------------------
6,178 3,280
-------------------------------------------------------------------------

Increase in Value of Debt Acquired(*) 78 83
Current Portion of Long-Term Debt (733) (287)
-------------------------------------------------------------------------
$ 8,582 $ 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 27 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 Company's
lenders. Currently the facility size has been reduced to $1.8 billion
with a drawn amount of $1.7 billion. Amounts borrowed under the facility
are to be repaid as follows: 25 percent within nine months of initial
drawdown, a further 50 percent within 15 months of the initial drawdown
and the final 25 percent within 24 months of initial drawdown.


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
June 30, December 31,
2004 2003
-------------------------------------------------------------------------

Asset Retirement Obligation, Beginning of Year $ 430 $ 309
Liabilities Incurred 55 64
Liabilities Settled (6) (23)
Liabilities Disposed (13) -
Accretion Expense 12 19
Other (11) 61
-------------------------------------------------------------------------
Asset Retirement Obligation, End of Period $ 467 $ 430
-------------------------------------------------------------------------
-------------------------------------------------------------------------


11. SHARE CAPITAL

June 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 5.9 154 5.5 114
Shares Repurchased (5.5) (77) (23.8) (320)
-------------------------------------------------------------------------
Common Shares Outstanding,
End of Period 461.0 $ 5,382 460.6 $ 5,305
-------------------------------------------------------------------------
-------------------------------------------------------------------------

To June 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 June 30, 2004:
Weighted
Stock Average
Options Exercise
(millions) Price (C$)
-------------------------------------------------------------------------

Outstanding, Beginning of Year 28.8 43.13
Exercised (5.9) 34.71
Forfeited (0.5) 47.06
-------------------------------------------------------------------------
Outstanding, End of Period 22.4 45.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable, End of Period 14.1 43.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Outstanding Options Exercisable
Options
------------------------------- -------------------
Weighted Number
Average Weighted of Weighted
Number of Remaining Average Options Average
Options Contractual Exercise Out- Exercise
Range of Exercise Outstanding Life Price standing Price
Price (C$) (millions) (years) (C$) (millions) (C$)
-------------------------------------------------------------------------

13.50 to 19.99 0.5 0.8 18.63 0.5 18.63
20.00 to 24.99 0.9 1.2 22.50 0.9 22.50
25.00 to 29.99 0.8 1.4 26.23 0.8 26.23
30.00 to 43.99 0.7 1.9 39.45 0.7 38.92
44.00 to 53.00 19.5 3.3 47.96 11.2 47.38
-------------------------------------------------------------------------
22.4 2.6 45.20 14.1 43.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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. 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
June 30, 2004 would have been $241 million; $0.52 per common share -
basic; $0.52 per common share - diluted (2003 - $798 million; $1.66 per
common share - basic; $1.65 per common share - diluted). Pro forma Net
Earnings and Net Earnings per Common Share for the six months ended
June 30, 2004 would have been $522 million; $1.13 per common share -
basic; $1.12 per common share - diluted (2003 - $1,627 million; $3.39 per
common share - basic; $3.36 per common share - diluted).

The fair value of each option granted is estimated on the date of grant
using the Black-Scholes option-pricing model with weighted average
assumptions for grants as follows:

June 30,
2003
-------------------------------------------------------------------------

Weighted Average Fair Value of Options Granted (C$) $ 12.18
Risk Free Interest Rate 3.96%
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 Company's
compensation plans at June 30, 2004. Additional information is contained
in Note 16 of the Company's 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 Six Months Ended
June 30, June 30,
---------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------

Current Service Cost $ 1 $ 2 $ 3 $ 3
Interest Cost 3 3 6 6
Expected Return on Plan Assets (3) (3) (6) (5)
Amortization of Net Actuarial Loss 2 1 2 2
Amortization of Transitional
Obligation (1) (1) (1) (1)
Amortization of Past Service Cost 1 1 1 1
Expense for Defined Contribution
Plan 4 3 7 6
-------------------------------------------------------------------------
Net Benefit Plan Expense $ 7 $ 6 $ 12 $ 12
-------------------------------------------------------------------------
-------------------------------------------------------------------------

At June 30, 2004, $9 million has been contributed to the pension plans
and the Company expects to make additional contributions of $8 million in
2004.

B) Share Appreciation Rights ("SAR's")

The following table summarizes the information about SAR's at June 30,
2004:
Weighted
Average
Outstanding Exercise
SAR's Price ($)
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 1,175,070 35.87
Exercised (434,342) 35.48
Forfeited (11,040) 29.25
-------------------------------------------------------------------------
Outstanding, End of Period 729,688 36.18
-------------------------------------------------------------------------
Exercisable, End of Period 729,688 36.18
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year 753,417 28.98
Exercised (249,358) 29.26
Forfeited (1,472) 24.08
-------------------------------------------------------------------------
Outstanding, End of Period 502,587 28.86
-------------------------------------------------------------------------
Exercisable, End of Period 502,587 28.86
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The following table summarizes the information about Tandem SAR's at
June 30, 2004:

Weighted
Outstanding Average
Tandem Exercise
SAR's Price(C$)
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year - -
Granted 897,850 54.44
Forfeited (7,400) 53.01
-------------------------------------------------------------------------
Outstanding, End of Period 890,450 54.45
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

C) Deferred Share Units ("DSU's")

The following table summarizes the information about DSU's at
June 30, 2004:

Weighted
Average
Outstanding Exercise
DSU's Price(C$)
-------------------------------------------------------------------------


Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 319,250 48.68
Granted, Directors 56,295 53.98
Granted, Senior Executives 1,145 55.71
-------------------------------------------------------------------------
Outstanding, End of Period 376,690 49.49
-------------------------------------------------------------------------
Exercisable, End of Period 295,472 50.86
-------------------------------------------------------------------------
-------------------------------------------------------------------------


D) Performance Share Units ("PSU's")

The following table summarizes the information about PSU's at
June 30, 2004:
Weighted
Average
Outstanding Exercise
PSU's Price ($)
-------------------------------------------------------------------------

Canadian Dollar Denominated (C$)
Outstanding, Beginning of Year 126,283 46.52
Granted 1,669,150 53.97
Forfeited (34,768) 53.61
-------------------------------------------------------------------------
Outstanding, End of Period 1,760,665 53.44
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

U.S. Dollar Denominated (US$)
Outstanding, Beginning of Year - -
Granted 248,529 41.12
Forfeited (6,599) 41.12
-------------------------------------------------------------------------
Outstanding, End of Period 241,930 41.12
-------------------------------------------------------------------------
Exercisable, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------


13. PER SHARE AMOUNTS

The following table summarizes the Common Shares used in calculating Net
Earnings per Common Share:

Three Months Ended Six Months Ended
March 31, June 30, June 30,
-------------------------------------------------
(millions) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------

Weighted Average Common
Shares Outstanding
- Basic 460.9 460.3 480.6 460.6 480.3
Effect of Dilutive
Securities 6.2 5.2 3.8 6.2 3.5
-------------------------------------------------------------------------
Weighted Average Common
Shares Outstanding
- Diluted 467.1 465.5 484.4 466.8 483.8
-------------------------------------------------------------------------
------------------------------------------------------------------------


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 June 30, 2004:

Net Deferred
Amounts Total
Recognized Fair Unrealized
on Market Gain/
Acquired Transition Value (Loss)
-------------------------------------------------------------------------

Fair Value of Contracts,
January 1, 2004 (Note 2) $ - $ 235 $ (235) $ -
Fair Value of Contracts
Acquired with
Tom Brown, Inc. 16 - (16) -
Change in Fair Value of
Contracts Still
Outstanding at June 30,
2004 - - (267) (267)
Fair Value of Contracts
Realized During the Period - (191) 191 -
Fair Value of Contracts
Entered into During
the Period - - (264) (264)
-------------------------------------------------------------------------
Fair Value of Contracts
Outstanding 16 44 (591) (531)
Premiums Paid on Collars
and Options - - 27 -
-------------------------------------------------------------------------
Fair Value of Contracts
Outstanding and Premiums
Paid, End of Period $ 16 $ 44 $ (564) $ (531)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

The total realized loss recognized in net earnings for the quarter and
year-to-date ended June 30, 2004 was $263 million ($177 million, net of
tax) and $408 million ($276 million, net of tax), respectively.

At June 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
June 30, 2004
-------------------------------------------------------------------------

Deferred Amounts Recognized on Transition
Accounts receivable and accrued revenues $ 139
Investments and other assets 3

Accounts payable and accrued liabilities 37
Other liabilities 61
-------------------------------------------------------------------------
Total Net Deferred Loss $ 44
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Risk Management
Current asset $ 64
Long-term asset 91

Current liability 597
Long-term liability 122
-------------------------------------------------------------------------
Total Net Risk Management Liability $ (564)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

A summary of all unrealized estimated fair value financial positions is
as follows:
As at
June 30, 2004
-------------------------------------------------------------------------

Commodity Price Risk
Natural gas $ (197)
Crude oil (400)
Power 8
Foreign Currency Risk -
Interest Rate Risk 25
-------------------------------------------------------------------------
$ (564)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 Company's annual audited Consolidated Financial Statements. No
significant new contracts have been entered into as at June 30, 2004.

Natural Gas

At June 30, 2004, the Company's gas risk management activities for
financial contracts had an unrealized loss of $(181) million and a fair
market value position of $(197) million. The contracts were as follows:


Notional Fair
Volumes Average Market
(MMcf/d) Term Price Value
-------------------------------------------------------------------------

Sales Contracts
Fixed Price Contracts
Fixed AECO price 457 2004 6.19 C$/Mcf $ (61)
NYMEX Fixed price 753 2004 5.13 US$/Mcf (159)
Chicago Fixed price 40 2004 5.42 US$/Mcf (7)
Colorado Interstate
Gas (CIG) 53 2004 5.51 US$/Mcf 2
Houston Ship Channel
(HSC) 60 2004 5.92 US$/Mcf (3)
Mid-Continent 5 2004 4.62 US$/Mcf (1)
Rockies 20 2004 5.36 US$/Mcf -
San Juan 17 2004 4.98 US$/Mcf (2)
Texas Oklahoma 5 2004 4.80 US$/Mcf (1)
Waha 25 2004 5.50 US$/Mcf (2)

NYMEX Fixed Price 170 2005 5.65 US$/Mcf (30)
Colorado Interstate
Gas (CIG) 114 2005 4.87 US$/Mcf (18)
Houston Ship Channel
(HSC) 40 2005 5.46 US$/Mcf (7)
Rockies 30 2005 4.95 US$/Mcf (5)
Waha 40 2005 5.16 US$/Mcf (7)

NYMEX Fixed Price 195 2006 5.23 US$/Mcf (24)
Colorado Interstate
Gas (CIG) 100 2006 4.44 US$/Mcf (12)
Houston Ship Channel
(HSC) 90 2006 5.08 US$/Mcf (12)
Rockies 35 2006 4.45 US$/Mcf (5)
San Juan 16 2006 4.50 US$/Mcf (2)
Waha 30 2006 4.79 US$/Mcf (4)

Collars and Other Options
AECO Collars 73 2004 5.34 - 7.52 C$/Mcf (4)
NYMEX Collars 38 2004 4.40 - 5.79 US$/Mcf (4)
Purchased NYMEX Put
Options 10 2004 5.00 US$/Mcf -
Other (1) 65 2004 4.21- 6.16 US$/Mcf (2)

Purchased NYMEX
Put Options 47 2005 5.00 US$/Mcf -
NYMEX 3-Way Call
Spread 180 2005 5.00/6.69/7.69 US$/Mcf (10)

Basis Contracts
Fixed NYMEX to
AECO Basis 345 2004 (0.55) US$/Mcf 27
Fixed NYMEX to
Rockies Basis 299 2004 (0.50) US$/Mcf 19
Fixed NYMEX to
Chicago Basis 10 2004 0.09 US$/Mcf -
Fixed NYMEX to
San Juan Basis 71 2004 (0.63) US$/Mcf 2
Fixed NYMEX to
CIG Basis 37 2004 (0.77) US$/Mcf 2
Fixed Rockies to
CIG Basis 50 2004 (0.10) US$/Mcf -
Other(1) 44 2004 (0.36) US$/Mcf -

Fixed NYMEX to
AECO basis 877 2005 (0.66) US$/Mcf 51
Fixed NYMEX to
Rockies basis 268 2005 (0.49) US$/Mcf 24
Fixed NYMEX to
San Juan basis 90 2005 (0.63) US$/Mcf 1
Fixed NYMEX to
CIG basis 137 2005 (0.77) US$/Mcf 3
Fixed Rockies to
CIG basis 50 2005 (0.10) US$/Mcf -
Other(1) 118 2005 (0.26) US$/Mcf -

Fixed NYMEX to
AECO basis 402 2006-2008 (0.65) US$/Mcf 31
Fixed NYMEX to
Rockies basis 162 2006-2008 (0.56) US$/Mcf 21
Fixed NYMEX to
San Juan basis 62 2006 (0.63) US$/Mcf 1
Fixed Rockies to
CIG basis 31 2006-2007 (0.10) US$/Mcf -
Fixed NYMEX to
CIG basis 279 2006 (0.83) US$/Mcf (1)
Other(1) 70 2006 (0.30) US$/Mcf -
-------------------------------------------------------------------------
Total Sales Contracts $ (199)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) For the Collars and Other Options, these Other contracts relate to
various price points at Permian, San Juan, Waha, Colorado Interstate
Gas (CIG), Houston Ship (HSC), Mid-Continent, Rockies and Texas
Oklahoma while for the Basis Contracts, they relate to HSC,
Mid-Continent, Waha and Ventura.

Purchase Contracts
Basis Contracts
Fixed NYMEX
to AECO Basis 112 2004 (0.96) US$/Mcf (2)

Premiums Paid on
3-Way Call Spread 1
-------------------------------------------------------------------------
Total Natural Gas
Financial Positions (200)
Gas Storage
Financial Positions (4)
Gas Marketing
Financial Positions(2) 7
-------------------------------------------------------------------------
Total Fair Value
Positions (197)
Contracts Acquired 16
-------------------------------------------------------------------------
Total Unrealized Loss
on Financial Contracts $ (181)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(2) The gas marketing activities are part of the daily ongoing operations
of the Company's proprietary production management.


Crude Oil

At June 30, 2004, the Company's oil risk management activities for all
financial contracts had an unrealized loss of $(426) million and a fair
market value position of $(400) million. The contracts were as follows:


Notional Average Fair
Volumes Price Market
(bbl/d) Term (US$/bbl) Value
-------------------------------------------------------------------------

Fixed WTI NYMEX
Price 62,500 2004 23.13 $ (156)
Collars on WTI
NYMEX 62,500 2004 20.00-25.69 (127)
Purchased WTI NYMEX
Call Options 111,000 2004 46.64 (10)

Fixed WTI NYMEX
Price 45,000 2005 28.41 (105)
3-Way Put Spread 10,000 2005 20.00/25.00/28.78 (25)
Purchased WTI NYMEX
Call Options 38,000 2005 49.76 (4)
-------------------------------------------------------------------------
(427)
Crude Oil Marketing
Financial
Positions(1) 1
-------------------------------------------------------------------------
Total Unrealized Loss
on Financial Contracts (426)
Premiums Paid on
Call Options 26
-------------------------------------------------------------------------
Total Fair Value
Positions $ (400)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) The crude oil marketing activities are part of the daily ongoing
operations of the Company's proprietary production management.


15. SUBSEQUENT EVENT

In July 2004, the Company entered into agreements to sell certain crude
oil and natural gas assets in Canada for total proceeds of approximately
$660 million. These sales are expected to close in the third quarter.


16. RECLASSIFICATION

Certain information provided for prior periods has been reclassified to
conform to the presentation adopted in 2004.

Further information on EnCana Corporation is available on the company's Web site, www.encana.com, or by contacting:

Investor contact:
EnCana Corporate Development
Sheila McIntosh
Vice-President, Investor Relations
403-645-2194

Tracy Weeks
Manager, Investor Relations
403-645-2007

Media contact:
Alan Boras
Manager, Media Relations
403-645-4747
investor.relations@encana.com

ECA stock price

TSX $14.27 Can -0.540

NYSE $11.11 USD -0.510

As of 2017-12-15 16:03. Minimum 15 minute delay