EnCana Corporation (TSX & NYSE: ECA) achieved strong increases in 2007 cash flow and operating earnings during a year of solid growth in natural gas and oil production. Financial results were enhanced by EnCana's favourable gas price hedges, which offset weaker gas prices, and excellent performance from the company's downstream segment of the integrated oil business. EnCana also achieved very strong proved reserves additions at competitive costs.
"EnCana delivered tremendous operational and financial performance in 2007, a direct result of our sharpened focus on North American unconventional natural gas and integrated oil resource plays. The sustainable value creation capacity of our resource play strategy is becoming increasingly evident. With strong production growth of 11 percent per share and successful price hedges that delivered a $1 billion benefit to 2007 cash flow, our company's cash flow, operating earnings and free cash flow all increased substantially in a year when our industry faced many challenges. In 2007, production from our key natural gas resource plays grew 14 percent, while production from our integrated oil projects increased 25 percent. Our newly established refining business also delivered great results, achieving twice the cash flow we expected during its inaugural year. Completing the year's success story, proved reserves additions were also substantial, replacing more than two times the amount of oil and gas we produced. Most importantly, these reserves additions were achieved at a highly-competitive finding and development cost of $1.65 per thousand cubic feet equivalent," said Randy Eresman, EnCana's President & Chief Executive Officer.
"EnCana's energy resources lie beneath its more than 25 million net acres of land in North America, largely in the heart of the unconventional fairway. Our low-risk, long-life resource play assets hold the potential to deliver strong shareholder value creation for many years ahead. As a reflection of the company's confidence in the sustainability of its business model, EnCana's board of directors has approved a doubling of our quarterly dividend to 40 cents per share," Eresman said.
IMPORTANT NOTE: Effective January 2, 2007, EnCana established an
integrated oil business with ConocoPhillips, which resulted in EnCana
contributing its interests in Foster Creek and Christina Lake into an
upstream partnership owned 50-50 by the two companies. Unless otherwise
noted in this news release, EnCana's proved reserves and production in
2007 are reported on a post integrated oil basis. Production and wells
drilled from 2006 have also been adjusted on a pro forma basis to reflect
the integrated oil transaction. Per share amounts for cash flow and
earnings are on a diluted basis. EnCana reports in U.S. dollars unless
otherwise noted and follows U.S. protocols, which report production,
sales and reserves on an after-royalties basis. The company's financial
statements are prepared in accordance with Canadian generally accepted
accounting principles (GAAP).
2007 Highlights
---------------
Financial - US$
- Cash flow per share increased 29 percent to $11.06, or
$8.5 billion
- Operating earnings per share were up 37 percent to $5.36, or
$4.1 billion
- Net earnings per share were down 23 percent to $5.18, or
$4.0 billion, primarily due to the after-tax change in the
unrealized mark-to-market impact of EnCana's financial hedges
- Operating cash flow from the integrated oil business was
$1.3 billion in 2007 compared to $276 million in 2006, including
$1.1 billion of operating cash flow generated from the U.S.
refineries
- Total capital investment was down 4 percent to $6.0 billion
- Generated $2.4 billion of free cash flow (as defined in Note 1 on
page 10), up 171 percent
- Purchased 38.9 million EnCana shares at an average price of $52.05
under the Normal Course Issuer Bid, for a total cost of
$2.0 billion
- Reduced shares outstanding at year-end by 4 percent, net of share
option exercises, to a year-end total of 750.2 million
- Doubled quarterly dividend in March 2007 to 20 cents per share,
which amounts to 80 cents per share on an annual basis
- At year end, net debt-to-adjusted-EBITDA was 1.2 times and net
debt-to-capitalization was 34 percent
Operating - Upstream
- Natural gas production increased 6 percent to 3.6 billion cubic
feet per day (Bcf/d), up 15 percent per share
- Increased production from natural gas key resource plays by 14
percent
- Oil and natural gas liquids (NGLs) production decreased 9 percent
to about 134,000 barrels per day (bbls/d), or down about 2 percent
per share, primarily due to the sale of EnCana's Ecuador assets in
the first quarter of 2006
- Integrated oil production grew 25 percent to 26,814 bbls/d at
Foster Creek and Christina Lake
- Operating and administrative costs of $1.17 per thousand cubic
feet equivalent (Mcfe)
Operating - Downstream
- Refined products averaged 457,000 bbls/d (228,500 bbls/d net to
EnCana)
- Refinery crude utilization of 96 percent or 432,000 bbls/d crude
throughput (216,000 bbls/d net to EnCana)
Reserves
- Total proved reserves increased 12 percent to 18.9 trillion cubic
feet equivalent (Tcfe)
- Added 3.6 Tcfe of proved reserves, compared to production of
1.6 Tcfe, for a production replacement of 227 percent
- Proved natural gas reserves increased 7 percent to 13.3 trillion
cubic feet (Tcf)
- Proved oil and NGLs reserves increased 26 percent to 927 million
barrels (MMbbls)
- Proved reserves additions included approximately 2.2 Tcf of
natural gas reserves, led by the Cutbank Ridge, Jonah and Piceance
resource plays, and 241 million bbls of oil and NGLs, primarily
from the Foster Creek and Christina Lake key resource plays
- Finding and Development (F&D) costs were $1.65 per Mcfe
- Three-year (2005-2007) F&D costs averaged $1.59 per Mcfe
- F&D costs for natural gas and associated liquids were
approximately $2.40 per Mcfe
- Proved reserves life index of 12 years
- Reserves replacement costs are outlined on page 8
2007 strategic results
- Completed first full year of integrated oil business with
ConocoPhillips composed of two 50-50 entities - one upstream and
one downstream - which became effective January 2, 2007
- Acquired the remaining 50 percent interest in the Deep Bossier
natural gas play in East Texas for $2.55 billion, before closing
adjustments
- Approved the development of the Deep Panuke natural gas project
offshore Nova Scotia
- Completed the sale of interests in Chad for $208 million, assets
in the Mackenzie Delta and Beaufort Sea for $159 million and
assets in Australia for $31 million, before closing adjustments
- Announced an agreement to sell remaining interests in Brazil for
approximately $165 million, before closing adjustments. The sale
is expected to close in the first half of 2008, pending certain
conditions and regulatory approvals.
Strong natural gas production in 2007 led by U.S. resource plays
Total natural gas production averaged about 3.6 Bcf/d in 2007, an increase of 6 percent - roughly twice the company's original forecast - principally due to strong performance from the Jonah and East Texas properties. Gas production growth was led by a 14 percent increase in U.S. production. In 2007, U.S. natural gas production represented about 40 percent of EnCana's total natural gas portfolio. That share is expected to increase to almost 45 percent in 2008.
Integrated oil adds strong cash flow
EnCana saw strong financial performance from the first full year of its integrated oil business. Regional and local market factors have an impact on refining crack spreads. The Wood River and Borger refineries are located in markets influenced by U.S. Mid-Continent and Chicago 3-2-1 crack spreads, which for most of the year were strong relative to U.S. Gulf Coast and NYMEX crack spreads. Refining margins tracked well above historical levels through the middle of 2007, helping the integrated oil business generate about $1.3 billion in operating cash flow.
Deep Panuke gas project offshore Nova Scotia approved
Following the receipt of regulatory approval to develop the Deep Panuke natural gas project, EnCana sanctioned the $700 million project. Deep Panuke, located about 175 kilometres offshore Nova Scotia, is scheduled to start production in late 2010 and is expected to deliver between 200 million and 300 million cubic feet of natural gas per day to markets in Canada and the northeast United States.
Fourth quarter production continues strong growth
EnCana's fourth quarter natural gas production increased 9 percent, with production at 3.7 Bcf/d, compared to the same quarter in 2006. Oil and natural gas liquids production increased 4 percent, with production at 136,000 bbls/d. Fourth quarter cash flow per share increased 17 percent to $2.56 or $1.9 billion and operating earnings per share increased 33 percent to $1.12, or $849 million.
-------------------------------------------------------------------------
Financial Summary - Total Consolidated
-------------------------------------------------------------------------
(for the period
ended December 31)
($ millions, except Q4 Q4 % %
per share amounts) 2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Cash flow(1) 1,934 1,761 + 10 8,453 7,161 + 18
Per share diluted 2.56 2.18 + 17 11.06 8.56 + 29
-------------------------------------------------------------------------
Net earnings 1,082 663 + 63 3,959 5,652 - 30
Per share diluted 1.43 0.82 + 74 5.18 6.76 - 23
-------------------------------------------------------------------------
Operating earnings(1) 849 675 + 26 4,100 3,271 + 25
Per share diluted 1.12 0.84 + 33 5.36 3.91 + 37
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings Reconciliation Summary - Total Consolidated
-------------------------------------------------------------------------
Net earnings 1,082 663 + 63 3,959 5,652 - 30
(Add back losses &
deduct gains)
Unrealized mark-to-
market hedging gain
(loss), after-tax (366) 95 (811) 1,370
Non-operating foreign
exchange gain (loss),
after-tax 267 (128) 217 -
Gain (loss) on
discontinuance,
after-tax 68 21 152 554
Future tax recovery
due to tax rate
reductions 264 - 301 457
-------------------------------------------------------------------------
Operating earnings(1) 849 675 + 26 4,100 3,271 + 25
Per share diluted 1.12 0.84 + 33 5.36 3.91 + 37
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash flow and operating earnings are non-GAAP measures as defined in
Note 1 on Page 10.
-------------------------------------------------------------------------
2007 Cash Flow Information
(for the period ended December 31, $ millions) Q4 2007
-------------------------------------------------------------------------
Cash from operating activities 2,193 8,429
Deduct (Add back):
Net change in other assets and liabilities (21) (16)
Net change in non-cash working capital from continuing
operations 280 (8)
-------------------------------------------------------------------------
Cash flow(1) 1,934 8,453
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash flow as defined in Note 1 on Page 10.
-------------------------------------------------------------------------
Production & Drilling Summary
-------------------------------------------------------------------------
Total Consolidated
-------------------------------------------------------------------------
(for the period ended
December 31) Q4 Q4 % %
(After royalties) 2007 2006(1) change 2007 2006(1) change
-------------------------------------------------------------------------
Natural Gas production
(MMcf/d) 3,722 3,406 + 9 3,566 3,367 + 6
-------------------------------------------------------------------------
Natural gas
production per
1,000 shares (Mcf) 457 395 + 16 1,720 1,499 + 15
-------------------------------------------------------------------------
Oil and NGLs
production (Mbbls/d) 136 131 + 4 134 148 - 9
-------------------------------------------------------------------------
Oil and NGLs
production per
1,000 shares (Mcfe) 100 91 + 10 388 395 - 2
-------------------------------------------------------------------------
Total production
(MMcfe/d) 4,539 4,194 + 8 4,371 4,254 + 3
-------------------------------------------------------------------------
Total production
per 1,000 shares
(Mcfe) 557 487 + 14 2,108 1,894 + 11
-------------------------------------------------------------------------
Net wells drilled 1,313 809 + 62 4,484 3,657 + 23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Continuing Operations
-------------------------------------------------------------------------
Natural Gas
production (MMcf/d) 3,722 3,406 + 9 3,566 3,367 + 6
-------------------------------------------------------------------------
North America Oil
and NGLs (Mbbls/d) 136 131 + 4 134 136 - 1
-------------------------------------------------------------------------
Total production
(MMcfe/d) 4,539 4,194 + 8 4,371 4,182 + 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net wells drilled 1,313 809 + 62 4,484 3,650 + 23
-------------------------------------------------------------------------
(1) 2006 information has been adjusted on a pro forma basis to reflect
the integrated oil transaction; 2006 includes production from
EnCana's Ecuador assets, which were sold in the first quarter of
2006.
Key natural gas resource play production up 14 percent
Natural gas production from EnCana's key resource plays increased 14 percent in 2007 to 2.7 Bcf/d, up from 2.4 Bcf/d in 2006. The increase was led by strong results in the U.S., where total gas production was up 14 percent, with the strongest growth in East Texas at 44 percent, Fort Worth in Texas at 23 percent and Jonah in Wyoming at 20 percent. In the fourth quarter, the company also saw the benefit of incremental production gains from the Deep Bossier acquisition. In 2007, total gas production in Canada increased 2 percent. Growth was strong at Cutbank Ridge in northeast British Columbia at 38 percent, the company's coalbed methane (CBM) production in central and southern Alberta at 34 percent, and Bighorn in west central Alberta at 31 percent. Drilling successes in Canada were offset by natural declines at conventional properties.
Oil production from Foster Creek and Christina Lake was up 25 percent to 26,814 bbls/d. Overall, key resource play gas and oil production for the year was up 13 percent.
Growth from key North American resource plays
-------------------------------------------------------------------------
Daily Production
-----------------------------------------------
Resource Play 2007
-----------------------------------------------
(After royalties) Full
Year Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Natural gas (MMcf/d)
Jonah 557 612 588 523 504
Piceance 348 351 354 349 334
East Texas 143 187 144 139 103
Fort Worth 124 138 128 124 106
Greater Sierra 211 221 220 219 186
Cutbank Ridge 234 254 245 226 210
Bighorn 119 130 128 115 104
CBM 259 283 256 245 251
Shallow Gas(1) 726 727 713 729 735
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total natural gas (MMcf/d) 2,721 2,903 2,776 2,669 2,533
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster Creek(2) 24 25 26 25 20
Christina Lake(2) 3 2 3 3 3
Pelican Lake(3) 23 24 24 23 23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total oil (Mbbls/d) 50 51 53 51 46
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total (MMcfe/d) 3,021 3,209 3,090 2,972 2,811
-------------------------------------------------------------------------
% change from prior period +13.3 +3.9 +4.0 +5.7 +2.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Daily Production
-----------------------------------------------
Resource Play 2006 2005
-----------------------------------------------
(After royalties) Full Full
Year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural gas (MMcf/d)
Jonah 464 487 455 450 461 435
Piceance 326 335 331 324 316 307
East Texas 99 95 106 93 99 90
Fort Worth 101 99 104 108 93 70
Greater Sierra 213 212 209 224 208 219
Cutbank Ridge 170 199 167 173 140 92
Bighorn 91 99 97 95 72 55
CBM 194 211 209 179 177 112
Shallow Gas(1) 739 737 734 730 756 765
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total natural gas (MMcf/d) 2,397 2,474 2,412 2,376 2,322 2,145
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil (Mbbls/d)
Foster Creek(2) 18 21 19 16 18 14
Christina Lake(2) 3 3 3 3 3 3
Pelican Lake(3) 24 20 23 22 29 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total oil (Mbbls/d) 45 44 45 41 50 43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total (MMcfe/d) 2,667 2,736 2,680 2,624 2,624 2,403
-------------------------------------------------------------------------
% change from prior period +11.0 +2.1 +2.1 - -2.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Shallow Gas volumes in 2006 and 2005 were restated in the first
quarter 2007 to report commingled volumes from multiple zones within
the same geographic area based upon regulatory approval.
(2) Foster Creek and Christina Lake volumes in 2006 and 2005 were
restated in the first quarter 2007 on a pro forma basis to reflect
the integrated oil transaction.
(3) Pelican Lake reached royalty payout in April 2006.
Drilling activity in key North American resource plays
-------------------------------------------------------------------------
Net Wells Drilled
-----------------------------------------------
Resource Play 2007
-----------------------------------------------
Full
Year Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Natural gas
Jonah 135 23 31 42 39
Piceance 286 77 72 72 65
East Texas 35 8 9 11 7
Fort Worth 75 15 17 29 14
Greater Sierra 109 27 27 32 23
Cutbank Ridge 81 11 18 25 27
Bighorn 58 6 15 9 28
CBM 1,079 330 323 18 408
Shallow Gas(1) 1,914 649 608 241 416
-------------------------------------------------------------------------
Total gas wells 3,772 1,146 1,120 479 1,027
-------------------------------------------------------------------------
Oil
Foster Creek(2) 23 6 8 1 8
Christina Lake(2) 3 - 1 2 -
Pelican Lake - - - - -
-------------------------------------------------------------------------
Total oil wells 26 6 9 3 8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 3,798 1,152 1,129 482 1,035
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Wells Drilled
-----------------------------------------------
Resource Play 2006 2005
-----------------------------------------------
Full Full
year Q4 Q3 Q2 Q1 Year
-------------------------------------------------------------------------
Natural gas
Jonah 163 41 48 48 26 104
Piceance 220 50 48 59 63 266
East Texas 59 11 12 17 19 84
Fort Worth 97 19 22 27 29 59
Greater Sierra 115 5 16 34 60 164
Cutbank Ridge 116 19 35 36 26 135
Bighorn 52 7 7 18 20 51
CBM 729 157 156 35 381 1,245
Shallow Gas(1) 1,310 389 475 217 229 1,389
-------------------------------------------------------------------------
Total gas wells 2,861 698 819 491 853 3,497
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil
Foster Creek(2) 3 - - - 3 20
Christina Lake(2) 1 - - - 1 -
Pelican Lake - - - - - 52
-------------------------------------------------------------------------
Total oil wells 4 - - - 4 72
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 2,865 698 819 491 857 3,569
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Shallow Gas net wells drilled in 2006 and 2005 were restated in the
first quarter 2007 as a result of reporting commingled volumes from
multiple zones within the same geographic area based upon regulatory
approval.
(2) Foster Creek and Christina Lake net wells drilled in 2006 and 2005
were restated in the first quarter 2007 on a pro forma basis to
reflect the integrated oil transaction.
2007 proved reserves
EnCana achieved 12 percent growth in proved reserves at a competitive finding and development cost of $1.65 per Mcfe
All of EnCana's proved reserves are evaluated by independent qualified reserves evaluators.
-------------------------------------------------------------------------
2007 Proved Reserves Reconciliation
-------------------------------------------------------------------------
Crude oil
and Natural
Natural gas Gas Liquids
(Bcf) (MMbbls)
-------------------------------------------------------------------------
Canada USA Total Canada Canada
Conv. Bitumen
-------------------------------------------------------------------------
Start of 2007 7,028 5,390 12,418 279.8 799.6
Partnership contribution(2) - - - - (398.0)
-------------------------------------------------------------------------
Effective Jan. 2, 2007 7,028 5,390 12,418 279.8 401.6
-------------------------------------------------------------------------
Revisions and improved
recovery 87 78 165 12.8 62.7
Extensions & discoveries 949 827 1,776 13.8 142.0
Purchase of reserves in place 63 211 274 0.2 -
Sale of reserves in place (24) (7) (31) (0.2) -
Production (811) (491) (1,302) (33.0) (10.8)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
End of Year 7,292 6,008 13,300 273.4 595.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
% Change(3) + 4 + 11 + 7 - 2 + 48
Developed 4,868 3,368 8,236 217.8 71.7
Undeveloped 2,424 2,640 5,064 55.6 523.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 7,292 6,008 13,300 273.4 595.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-----------------------------------------------------------------
2007 Proved Reserves Reconciliation
-----------------------------------------------------------------
Crude oil and Natural Gas Equiv-
Gas Liquids alent(1)
(MMbbls) (Bcfe)
-----------------------------------------------------------------
Canada USA Total Total
Total
-----------------------------------------------------------------
Start of 2007 1,079.4 54.0 1,133.4 19,218
Partnership contribution(2) (398.0) - (398.0) (2,388)
-----------------------------------------------------------------
Effective Jan. 2, 2007 681.4 54.0 735.4 16,830
-----------------------------------------------------------------
Revisions and improved
recovery 75.5 3.6 79.1 640
Extensions & discoveries 155.8 5.9 161.7 2,746
Purchase of reserves in place 0.2 - 0.2 275
Sale of reserves in place (0.2) - (0.2) (32)
Production (43.8) (5.2) (49.0) (1,596)
-----------------------------------------------------------------
-----------------------------------------------------------------
End of Year 868.9 58.3 927.2 18,863
-----------------------------------------------------------------
-----------------------------------------------------------------
% Change(3) + 28 + 8 + 26 + 12
-----------------------------------------------------------------
-----------------------------------------------------------------
Developed 289.5 37.0 326.5 10,195
Undeveloped 579.4 21.3 600.7 8,668
-----------------------------------------------------------------
-----------------------------------------------------------------
Total 868.9 58.3 927.2 18,863
-----------------------------------------------------------------
-----------------------------------------------------------------
(1) Gas equivalency has been calculated by EnCana. See the Advisory
Regarding Reserves Data and Other Oil and Gas Information
accompanying this release.
(2) Effective January 2, 2007, EnCana established an integrated oil
business with ConocoPhillips, which resulted in EnCana contributing
its interests in Foster Creek and Christina Lake to an upstream
partnership owned 50-50 by the two companies.
(3) EnCana's growth in proved reserves is expressed as the percentage
change from January 2, 2007 to the end of the year.
-------------------------------------------------------------------------
Proved Reserves Costs
-------------------------------------------------------------------------
2007 2006 2005 3 Years
-------------------------------------------------------------------------
Capital investment ($millions)
-------------------------------------------------------------------------
Finding and development 5,587 6,107 6,231 17,925
Acquisitions 2,708 368 472 3,548
-------------------------------------------------------------------------
Finding, development and
acquisitions 8,295 6,475 6,703 21,473
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Reserves additions (Bcfe)
Finding and development 3,386 3,064 4,849 11,299
Acquisitions 275 69 85 429
-------------------------------------------------------------------------
Finding, development and
acquisitions 3,661 3,133 4,934 11,728
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved reserves costs ($/Mcfe)
Finding and development 1.65 1.99 1.29 1.59
Finding, development and
acquisitions 2.27 2.07 1.36 1.83
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Finding and development costs by commodity
In 2007, F&D costs for natural gas and associated liquids were approximately $2.40 per Mcfe, down from about $2.70 per Mcfe in 2006. Natural gas and associated liquids reserves additions were approximately 2.0 Tcfe with capital investments of $4.7 billion in 2007, compared to 2006 reserves additions of about 1.9 Tcfe with capital investments of $5 billion.
In 2007, F&D costs for crude oil were approximately $3.60 per bbl, down from about $5.45 per bbl in 2006. Crude oil reserves additions were approximately 233 million bbls and capital investments were $840 million in 2007, compared to 2006 reserves additions of about 199 million bbls and capital investments of $1.1 billion.
For the three years, 2005-2007, EnCana's F&D costs for natural gas and associated liquids averaged approximately $2.35 per Mcfe based on total reserves additions of about 6.4 Tcfe and total capital investments of $15 billion. For the same period, F&D costs for crude oil averaged approximately $3.60 per bbl based on total reserves additions of about 820 million bbls and total capital investments of $3 billion.
Reserves replacement cost in 2007
Reserves replacement cost for 2007 post integrated oil was approximately $2.20 per Mcfe, which includes divestitures of 32 Bcfe for proceeds of $382 million. EnCana's three-year (2005 - 2007) reserves replacement cost was approximately $1.60 per Mcfe.
-------------------------------------------------------------------------
2007 Natural Gas and Oil Prices
-------------------------------------------------------------------------
Q4 Q4 % %
2007 2006 change 2007 2006 change
-------------------------------------------------------------------------
Natural gas
($/Mcf, realized
prices include
hedging)
NYMEX 6.96 6.55 + 6 6.86 7.22 - 5
EnCana realized gas
price 7.32 6.70 + 9 7.22 6.72 + 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Oil and NGLs
($/bbl, realized
prices include
hedging)
WTI 90.50 60.17 + 50 72.41 66.25 + 9
Western Canadian
Select (WCS) 56.82 39.08 + 45 49.50 44.69 + 11
Differential WTI/WCS 33.68 21.09 + 60 22.91 21.56 + 6
EnCana realized
liquids price 50.84 35.39 + 44 47.00 40.39 + 16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
3-2-1 crack spread
($/bbl)
U.S. Gulf Coast 6.55 6.77 - 3 13.16 10.83 + 22
U.S. Mid-Continent 9.37 10.11 - 7 19.10 14.32 + 33
Chicago 9.17 9.70 - 5 17.67 13.38 + 32
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Price risk management
Risk management positions at December 31, 2007 are presented in Note 19 to the unaudited Interim Consolidated Financial Statements for the fourth quarter 2007. In 2007, EnCana's commodity price risk management measures resulted in realized gains of approximately $1.0 billion after-tax, composed of a $1.1 billion after-tax gain on gas price and basis hedges and a $0.1 billion after-tax loss on oil price hedges and other hedges.
Half of expected 2008 gas production hedged during first 10 months of
2008
EnCana has hedged about 1.9 billion Bcf/d of expected gas production from January to October 2008 at an average NYMEX equivalent price of $8.21 per Mcf. EnCana has about 23,000 bbls/d of expected 2008 oil production hedged at a fixed price of WTI $70.13 per bbl. This price hedging strategy helps reduce uncertainty in cash flow during periods of commodity price volatility.
U.S. Rockies basis differential hedges
For 2008, EnCana has hedged 100 percent of its expected U.S. Rockies basis exposure using a combination of downstream transportation and basis hedges, including some hedges that are based on a percentage of NYMEX prices. At December 31, 2007, U.S. basis hedges, a combination of Rockies, Mid-Continent and San Juan instruments, had an effective annual average differential of NYMEX less $1.03 per Mcf.
2008 gas production forecast to increase 6 percent
In 2008, natural gas production, which represents more than 80 percent of EnCana's production, is expected to increase about 6 percent to about 3.8 Bcf/d. Oil and NGLs production is expected to average 132,000 bbls/d, down 1 percent, mostly due to natural decline in mature properties. Total production in 2008 is expected to increase 5 percent to average 4.6 Bcfe/d. EnCana has updated its corporate guidance on its website: www.encana.com to reflect actual results for 2007.
Corporate developments
Quarterly dividend increased 100 percent to 40 cents per share
Consistent with the company's focus on shareholder value creation, EnCana's board of directors declared a quarterly dividend of 40 cents per share, which is payable on March 31, 2008 to common shareholders of record as of March 14, 2008. This is double the amount of the previous quarterly dividend.
Normal Course Issuer Bid
In 2007, EnCana purchased 38.9 million shares, or about 5 percent, of the outstanding shares at an average price of $52.05 per share under the company's Normal Course Issuer Bid program. The average diluted shares for the year were 764.6 million and the shares outstanding at year end were 750.2 million. In January 2008, the company purchased 3.0 million shares at an average price of $63.29 for a cost of $191 million. During 2008, the company plans to purchase approximately 2 percent of the shares outstanding (about 15 million shares).
Financial strength
EnCana maintains a strong balance sheet, targeting a net debt-to-capitalization ratio between 30 and 40 percent. At December 31, 2007, the company's net debt-to-capitalization ratio was 34 percent and net debt-to-adjusted-EBITDA multiple, on a trailing 12-month basis, was 1.2 times. The increase in the net-debt-to-capitalization ratio from the end of the third quarter 2007 is primarily due to EnCana's $2.55 billion Deep Bossier acquisition in Texas in November 2007.
In 2007, EnCana invested $6.0 billion in capital. Net acquisitions were $2.3 billion, resulting in net capital investment in continuing operations of $8.3 billion.
-------------------------------------------------------------------------
CONFERENCE CALL TODAY
11 a.m. Mountain Time (1 p.m. Eastern Time)
EnCana will host a conference call today Thursday, February 14, 2008
starting at 11:00 a.m. MT (1:00 p.m. ET). To participate, please dial
(866) 321-6651 (toll-free in North America) or (416) 642-5212
approximately 10 minutes prior to the conference call and quote
confirmation code 6891314. An archived recording of the call will be
available from approximately 3:00 p.m. MT on February 14 until midnight
February 21, 2008 by dialling (888) 203-1112 or (647) 436-0148 and
entering access code 6891314.
A live audio webcast of the conference call will also be available via
EnCana's website, www.encana.com, under Investor Relations. The webcast
will be archived for approximately 90 days.
-------------------------------------------------------------------------
NOTE 1: Non-GAAP measures
This news release contains references to cash flow, pre-tax cash flow, operating earnings and free cash flow.
- Cash flow is a non-GAAP measure defined as excluding net change in
other assets and liabilities, net change in non-cash working capital
from continuing operations and net change in non-cash working capital
from discontinued operations, all of which are defined on the
Consolidated Statement of Cash Flows.
- Pre-tax cash flow is calculated as cash flow before cash taxes.
- Operating earnings is a non-GAAP measure that shows net earnings
excluding non-operating items such as the after-tax impacts of a
gain/loss on discontinuance, the after-tax gain/loss of unrealized
mark-to-market accounting for derivative instruments, the after-tax
gain/loss on translation of U.S. dollar denominated Notes issued from
Canada and the partnership contribution receivable, the after-tax
foreign exchange gains/losses on settlement of intercompany
transactions and the effect of the reduction in income tax rates.
Management believes that these excluded items reduce the
comparability of the company's underlying financial performance
between periods. The majority of the unrealized gains/losses that
relate to U.S. dollar denominated Notes issued from Canada are for
debt with maturity dates in excess of five years.
- Free cash flow is a non-GAAP measure that EnCana defines as cash flow
in excess of total capital investment, excluding acquisitions, and is
used to determine the funds available for other investing and/or
financing activities.
These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding EnCana's liquidity and its ability to generate funds to finance its operations.
EnCana Corporation
With an enterprise value of approximately $65 billion, EnCana is a leading North American unconventional natural gas and integrated oil company. By partnering with employees, community organizations and other businesses, EnCana contributes to the strength and sustainability of the communities where it operates. EnCana common shares trade on the Toronto and New York stock exchanges under the symbol ECA.
RESERVES COST DEFINITIONS - Production replacement is calculated by dividing reserves additions by production in the same period. Reserves additions over a given period, in this case 2007, are calculated by summing one or more of revisions and improved recovery, extensions and discoveries, acquisitions and divestitures. Reserves replacement cost is calculated by dividing total capital invested in finding, development and acquisitions net of divestitures by reserves additions in the same period. Finding and development cost is calculated by dividing total capital invested in finding and development activities by additions to proved reserves, before acquisitions and divestitures, which is the sum of revisions, extensions and discoveries. Finding, development and acquisition cost is calculated by dividing total capital invested in finding, development and acquisition activities by additions to proved reserves, before divestitures, which is the sum of revisions, extensions, discoveries and acquisitions. Proved reserves added in 2007 included both developed and undeveloped quantities. Additions to EnCana's proved undeveloped reserves were consistent with EnCana's resource play focus. The company estimates that approximately 70 percent of its proved undeveloped reserves will be developed within the next four years. 2007 finding, development and acquisition capital includes investment in long lead time projects. EnCana uses the aforementioned metrics as indicators of relative performance, along with a number of other measures. Many performance measures exist, all measures have limitations and historical measures are not necessarily indicative of future performance.
ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION - EnCana's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to EnCana by Canadian securities regulatory authorities which permits it to provide such disclosure in accordance with U.S. disclosure requirements. The information provided by EnCana may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). EnCana's reserves quantities represent net proved reserves calculated using the standards contained in Regulation S-X of the U.S. Securities and Exchange Commission. Further information about the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading "Note Regarding Reserves Data and Other Oil and Gas Information" in EnCana's Annual Information Form.
In this news release, certain crude oil and NGLs volumes have been converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). Also, certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the same basis. BOE and cfe may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - In the interests of providing EnCana shareholders and potential investors with information regarding EnCana, including management's assessment of EnCana's and its subsidiaries' future plans and operations, certain statements contained in this news release are forward-looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as "forward-looking statements." Forward-looking statements in this news release include, but are not limited to: future economic and operating performance (including per share growth, net debt-to-capitalization ratio, sustainable growth and returns, cash flow, free cash flow, cash flow per share and increases in net asset value); anticipated ability to meet the company's guidance forecasts; anticipated life of proved reserves; anticipated growth and success of resource plays and the expected characteristics of resource plays; the anticipated production, timing thereof, and expenditures associated with the Deep Panuke Project; planned expansion of in-situ oil production; anticipated crude oil and natural gas prices, including basis differentials for various regions; anticipated expansion and production at Foster Creek and Christina Lake; anticipated increased capacity for the Borger and Wood River refineries; anticipated integrated oil cash flow; projections for future crack spreads and anticipated refining profits; anticipated drilling inventory; expected proportion of total production and cash flows contributed by natural gas; anticipated success of EnCana's market risk mitigation strategy; anticipated purchases pursuant to the Normal Course Issuer Bid and the source of funding therefore; potential demand for natural gas; anticipated bitumen production in 2008 and beyond; anticipated drilling; potential capital expenditures and investment; potential oil, natural gas and NGLs production in 2008 and beyond; anticipated costs and inflationary pressures; potential risks associated with drilling and references to potential exploration. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the company's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions based upon the company's current guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the company's marketing operations, including credit risks; imprecision of reserves estimates and estimates of recoverable quantities of oil, natural gas and liquids from resource plays and other sources not currently classified as proved reserves; the ability of the company and ConocoPhillips to successfully manage and operate the integrated North American oil business and the ability of the parties to obtain necessary regulatory approvals; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with technology; the company's ability to replace and expand oil and gas reserves; its ability to generate sufficient cash flow from operations to meet its current and future obligations; its ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; the company's ability to secure adequate product transportation; changes in royalty, tax, environmental and other laws or regulations or the interpretations of such laws or regulations; political and economic conditions in the countries in which the company operates; the risk of war, hostilities, civil insurrection and instability affecting countries in which the company operates and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the company; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by EnCana. Although EnCana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive.
Furthermore, the forward-looking statements contained in this news release are made as of the date of this news release, and, except as required by law, EnCana does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this news release are expressly qualified by this cautionary statement.
Interim Consolidated Financial Statements
(unaudited)
For the period ended December 31, 2007
EnCana Corporation
U.S. DOLLARS
CONSOLIDATED STATEMENT OF EARNINGS (unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
($ millions, except per ---------------------------------------
share amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------
REVENUES, NET OF ROYALTIES (Note 6)
Upstream $ 3,161 $ 2,552 $ 11,758 $ 10,369
Integrated Oil 2,369 260 7,983 973
Market Optimization 837 735 2,944 3,007
Corporate - Unrealized gain
(loss) on risk management (566) 129 (1,239) 2,050
-------------------------------------------------------------------------
5,801 3,676 21,446 16,399
EXPENSES (Note 6)
Production and mineral taxes 63 80 291 349
Transportation and selling 278 275 1,010 1,070
Operating 632 428 2,278 1,655
Purchased product 2,704 702 8,583 2,862
Depreciation, depletion and
amortization 1,086 766 3,816 3,112
Administrative 121 84 384 271
Interest, net (Note 9) 131 142 428 396
Accretion of asset
retirement obligation (Note 15) 18 13 64 50
Foreign exchange (gain)
loss, net (Note 10) (233) 172 (164) 14
(Gain) loss on
divestitures (Note 8) 22 (2) (65) (323)
-------------------------------------------------------------------------
4,822 2,660 16,625 9,456
-------------------------------------------------------------------------
NET EARNINGS BEFORE INCOME TAX 979 1,016 4,821 6,943
Income tax expense (Note 11) (28) 373 937 1,892
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS 1,007 643 3,884 5,051
NET EARNINGS FROM DISCONTINUED
OPERATIONS (Note 7) 75 20 75 601
-------------------------------------------------------------------------
NET EARNINGS $ 1,082 $ 663 $ 3,959 $ 5,652
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS FROM CONTINUING
OPERATIONS PER COMMON
SHARE (Note 18)
Basic $ 1.34 $ 0.81 $ 5.13 $ 6.16
Diluted $ 1.33 $ 0.80 $ 5.08 $ 6.04
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS PER COMMON
SHARE (Note 18)
Basic $ 1.44 $ 0.84 $ 5.23 $ 6.89
Diluted $ 1.43 $ 0.82 $ 5.18 $ 6.76
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF RETAINED EARNINGS (unaudited)
Twelve Months Ended
December 31,
-------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
RETAINED EARNINGS, BEGINNING OF YEAR $ 11,344 $ 9,481
Net Earnings 3,959 5,652
Dividends on Common Shares (603) (304)
Charges for Normal Course Issuer Bid (Note 16) (1,618) (3,485)
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF YEAR $ 13,082 $ 11,344
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
---------------------------------------
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
NET EARNINGS $ 1,082 $ 663 $ 3,959 $ 5,652
OTHER COMPREHENSIVE INCOME, NET
OF TAX
Foreign Currency Translation
Adjustment (110) (418) 1,688 113
-------------------------------------------------------------------------
COMPREHENSIVE INCOME $ 972 $ 245 $ 5,647 $ 5,765
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME
(unaudited)
Twelve Months Ended
December 31,
-------------------
($ millions) 2007 2006
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME, BEGINNING
OF YEAR $ 1,375 $ 1,262
Foreign Currency Translation Adjustment 1,688 113
-------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME, END OF YEAR $ 3,063 $ 1,375
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEET (unaudited)
As at As at
December 31, December 31,
($ millions) 2007 2006
-------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 553 $ 402
Accounts receivable and accrued
revenues 2,381 1,721
Current portion of partnership
contribution receivable (Notes 5, 12) 297 -
Risk management (Note 19) 385 1,403
Inventories (Note 13) 828 176
-------------------------------------------------------------------------
4,444 3,702
Property, Plant and Equipment, net (Note 6) 35,865 28,213
Investments and Other Assets 607 533
Partnership Contribution
Receivable (Notes 5, 12) 3,147 -
Risk Management (Note 19) 18 133
Goodwill 2,893 2,525
-------------------------------------------------------------------------
(Note 6) $ 46,974 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued
liabilities $ 3,982 $ 2,494
Income tax payable 1,150 926
Current portion of partnership
contribution payable (Notes 5, 12) 288 -
Risk management (Note 19) 207 14
Current portion of long-term debt (Note 14) 703 257
-------------------------------------------------------------------------
6,330 3,691
Long-Term Debt (Note 14) 8,840 6,577
Other Liabilities 242 79
Partnership Contribution
Payable (Notes 5, 12) 3,163 -
Risk Management (Note 19) 29 2
Asset Retirement Obligation (Note 15) 1,458 1,051
Future Income Taxes 6,208 6,240
-------------------------------------------------------------------------
26,270 17,640
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (Note 16) 4,479 4,587
Paid in surplus 80 160
Retained earnings 13,082 11,344
Accumulated other comprehensive
income 3,063 1,375
-------------------------------------------------------------------------
Total Shareholders' Equity 20,704 17,466
-------------------------------------------------------------------------
$ 46,974 $ 35,106
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
---------------------------------------
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings from
continuing operations $ 1,007 $ 643 $ 3,884 $ 5,051
Depreciation, depletion
and amortization 1,086 766 3,816 3,112
Future income taxes (Note 11) (608) 260 (617) 950
Cash tax on sale of
assets (Note 8) - - - 49
Unrealized (gain) loss
on risk management (Note 19) 569 (141) 1,235 (2,060)
Unrealized foreign
exchange (gain) loss (52) 155 41 -
Accretion of asset
retirement obligation (Note 15) 18 13 64 50
(Gain) loss on
divestitures (Note 8) 22 (2) (65) (323)
Other (108) 48 95 214
Cash flow from
discontinued operations - 19 - 118
Net change in other
assets and liabilities (21) 90 (16) 138
Net change in non-cash
working capital from
continuing operations 280 39 (8) 3,343
Net change in non-cash
working capital from
discontinued operations - (193) - (2,669)
-------------------------------------------------------------------------
Cash From Operating
Activities 2,193 1,697 8,429 7,973
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (Note 6) (4,408) (1,250) (8,737) (6,600)
Proceeds from
divestitures (Note 8) (24) 55 481 689
Cash tax on sale of
assets (Note 8) - - - (49)
Net change in investments
and other (31) 40 (5) 2
Net change in non-cash
working capital from
continuing operations 120 188 86 19
Discontinued operations - 180 - 2,557
-------------------------------------------------------------------------
Cash (Used in) Investing
Activities (4,343) (787) (8,175) (3,382)
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Net issuance (repayment)
of revolving long-term debt 1,090 646 181 134
Issuance of long-term
debt (Note 14) 1,485 - 2,409 -
Repayment of long-term
debt (257) - (257) (73)
Issuance of common
shares (Note 16) 18 39 176 179
Purchase of common
shares (Note 16) - (1,246) (2,025) (4,219)
Dividends on common shares (150) (78) (603) (304)
Other 1 (3) - (11)
-------------------------------------------------------------------------
Cash From (Used in)
Financing Activities 2,187 (642) (119) (4,294)
-------------------------------------------------------------------------
FOREIGN EXCHANGE GAIN (LOSS)
ON CASH AND CASH
EQUIVALENTS HELD IN FOREIGN
CURRENCY 1 - 16 -
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 38 268 151 297
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 515 134 402 105
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 553 $ 402 $ 553 $ 402
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)
1. BASIS OF PRESENTATION
The interim Consolidated Financial Statements include the accounts of
EnCana Corporation and its subsidiaries ("EnCana" or the "Company"), and
are presented in accordance with Canadian generally accepted accounting
principles. EnCana's continuing operations are in the business of
exploration for, and development, production and marketing of natural
gas, crude oil and natural gas liquids, refining operations and power
generation operations.
The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as the
annual audited Consolidated Financial Statements for the year ended
December 31, 2006, 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, 2006.
2. CHANGES IN ACCOUNTING POLICIES AND PRACTICES
As disclosed in the December 31, 2006 annual audited Consolidated
Financial Statements, on January 1, 2007, the Company adopted the
Canadian Institute of Chartered Accountants ("CICA") Handbook Section
1530, "Comprehensive Income", Section 3251, "Equity", Section 3855,
"Financial Instruments - Recognition and Measurement", and Section 3865,
"Hedges". As required by the new standards, prior periods have not been
restated, except to reclassify the foreign currency translation
adjustment balance as described under Comprehensive Income.
The adoption of these standards has had no material impact on the
Company's net earnings or cash flows. The other effects of the
implementation of the new standards are discussed below.
Comprehensive Income
The new standards introduce comprehensive income, which consists of net
earnings and Other Comprehensive Income ("OCI"). The Company's
Consolidated Financial Statements now include a Statement of
Comprehensive Income, which includes the components of comprehensive
income. For EnCana, OCI is currently comprised of the changes in the
foreign currency translation adjustment balance.
The cumulative changes in OCI are included in Accumulated Other
Comprehensive Income ("AOCI"), which is presented as a new category
within shareholders' equity in the Consolidated Balance Sheet. The
accumulated foreign currency translation adjustment, formerly presented
as a separate category within shareholders' equity, is now included in
AOCI. The Company's Consolidated Financial Statements now include a
Statement of Accumulated Other Comprehensive Income, which provides the
continuity of the AOCI balance.
The adoption of comprehensive income has been made in accordance with the
applicable transitional provisions. Accordingly, the December 31, 2007
year end accumulated foreign currency translation adjustment balance of
$3,063 million is now included in AOCI (December 31, 2006 - $1,375
million). In addition, the change in the accumulated foreign currency
translation adjustment balance for the three months and twelve months
ended December 31, 2007 of $(110) million and $1,688 million,
respectively, is now included in OCI in the Statement of Comprehensive
Income (three months and twelve months ended December 31, 2006 - $(418)
million and $113 million, respectively).
Financial Instruments
The financial instruments standard establishes the recognition and
measurement criteria for financial assets, financial liabilities and
derivatives. All financial instruments are required to be measured at
fair value on initial recognition of the instrument, except for certain
related party transactions. Measurement in subsequent periods depends on
whether the financial instrument has been classified as "held-for-
trading", "available-for-sale", "held-to-maturity", "loans and
receivables", or "other financial liabilities" as defined by the
accounting standard.
Financial assets and financial liabilities "held-for-trading" are
measured at fair value with changes in those fair values recognized in
net earnings. Financial assets "available-for-sale" are measured at fair
value, with changes in those fair values recognized in OCI. Financial
assets "held-to-maturity", "loans and receivables" and "other financial
liabilities" are measured at amortized cost using the effective interest
method of amortization.
Cash and cash equivalents are designated as "held-for-trading" and are
measured at fair value. Accounts receivable and accrued revenues and the
partnership contribution receivable are designated as "loans and
receivables". Accounts payable and accrued liabilities, the partnership
contribution payable and long-term debt are designated as "other
financial liabilities".
The adoption of the financial instruments standard has been made in
accordance with its transitional provisions. Accordingly, at January 1,
2007, $52 million of other assets were reclassified to long-term debt to
reflect the adopted policy of capitalizing long-term debt transaction
costs, premiums and discounts within long-term debt. The costs
capitalized within long-term debt will be amortized using the effective
interest method. Previously, the Company deferred these costs within
other assets and amortized them straight-line over the life of the
related long-term debt. The adoption of the effective interest method of
amortization had no effect on opening retained earnings.
Risk management assets and liabilities are derivative financial
instruments classified as "held-for-trading" unless designated for hedge
accounting. Additional information on the Company's accounting treatment
of derivative financial instruments is contained in Note 1 of the
Company's annual audited Consolidated Financial Statements for the year
ended December 31, 2006.
3. UPDATE TO ACCOUNTING POLICIES AND PRACTICES
As a result of the new joint venture with ConocoPhillips, EnCana has
updated the following significant accounting policies and practices to
incorporate the refining business (See Note 5):
Revenue Recognition
Revenues associated with the sales of EnCana's natural gas, crude oil,
NGLs and petroleum and chemical products are recognized when title passes
from the Company to its customer. Natural gas and crude oil produced and
sold by EnCana below or above its working interest share in the related
resource properties results in production underliftings or overliftings.
Underliftings are recorded as inventory and overliftings are recorded as
deferred revenue. Realized gains and losses from the Company's natural
gas and crude oil commodity price risk management activities are recorded
in revenue when the product is sold.
Market optimization revenues and purchased product are recorded on a
gross basis when EnCana takes title to product and has risks and rewards
of ownership. Purchases and sales of inventory with the same counterparty
that are entered into in contemplation of each other are recorded on a
net basis. Revenues associated with the services provided where EnCana
acts as agent are recorded as the services are provided. Revenues
associated with the sale of natural gas storage services are recognized
when the services are provided. Sales of electric power are recognized
when power is provided to the customer.
Unrealized gains and losses from the Company's natural gas and crude oil
commodity price risk management activities are recorded as revenue based
on the related mark-to-market calculations at the end of the respective
period.
Inventory
Product inventories, including petroleum and chemical products, are
valued at the lower of average cost and net realizable value on a first-
in, first-out basis.
Property, Plant and Equipment
Upstream
EnCana accounts for natural gas and crude oil properties in accordance
with the Canadian Institute of Chartered Accountants' guideline on full
cost accounting in the oil and gas industry. Under this method, all
costs, including internal costs and asset retirement costs, directly
associated with the acquisition of, exploration for, and the development
of natural gas and crude oil reserves, are capitalized on a country-by-
country cost centre basis.
Costs accumulated within each cost centre are depreciated, depleted and
amortized using the unit-of-production method based on estimated proved
reserves determined using estimated future prices and costs. For purposes
of this calculation, oil is converted to gas on an energy equivalent
basis. Capitalized costs subject to depletion include estimated future
costs to be incurred in developing proved reserves. Proceeds from the
divestiture of properties are normally deducted from the full cost pool
without recognition of gain or loss unless that deduction would result in
a change to the rate of depreciation, depletion and amortization of 20
percent or greater, in which case a gain or loss is recorded. Costs of
major development projects and costs of acquiring and evaluating
significant unproved properties are excluded, on a cost centre basis,
from the costs subject to depletion until it is determined whether or not
proved reserves are attributable to the properties, or impairment has
occurred. Costs that have been impaired are included in the costs subject
to depreciation, depletion and amortization.
An impairment loss is recognized in net earnings when the carrying amount
of a cost centre is not recoverable and the carrying amount of the cost
centre exceeds its fair value. The carrying amount of the cost centre is
not recoverable if the carrying amount exceeds the sum of the
undiscounted cash flows from proved reserves. If the sum of the cash
flows is less than the carrying amount, the impairment loss is limited to
the amount by which the carrying amount exceeds the sum of:
i. the fair value of proved and probable reserves; and
ii. the costs of unproved properties that have been subject to a separate
impairment test.
Downstream
The initial acquisition costs of refinery property, plant and equipment
are capitalized when incurred. Costs include the cost of constructing or
otherwise acquiring the equipment or facilities, the cost of installing
the asset and making it ready for its intended use and the associated
asset retirement costs. Capitalized costs are not subject to depreciation
until the asset is put into use, after which they are depreciated on a
straight-line basis over their estimated service lives of approximately
25 years.
An impairment loss is recognized on refinery property, plant and
equipment when the carrying amount is not recoverable and exceeds its
fair value. The carrying amount is not recoverable if the carrying amount
exceeds the sum of the undiscounted cash flows from expected use and
eventual disposition. If the carrying amount is not recoverable, an
impairment loss is measured as the amount by which the refinery asset
exceeds the discounted future cash flows from the refinery asset.
Market Optimization
Midstream facilities, including natural gas storage facilities, natural
gas liquids extraction plant facilities and power generation facilities,
are carried at cost and depreciated on a straight-line basis over the
estimated service lives of the assets, which range from 20 to 25 years.
Capital assets related to pipelines are carried at cost and depreciated
using the straight-line method over their economic lives, which range
from 20 to 35 years.
Corporate
Costs associated with office furniture, fixtures, leasehold improvements,
information technology and aircraft are carried at cost and depreciated
on a straight-line basis over the estimated service lives of the assets,
which range from three to 25 years. Assets under construction are not
subject to depreciation until put into use. Land is carried at cost.
Asset Retirement Obligation
The fair value of estimated asset retirement obligations is recognized in
the Consolidated Balance Sheet when identified and a reasonable estimate
of fair value can be made.
Asset retirement obligations include those legal obligations where the
Company will be required to retire tangible long-lived assets such as
producing well sites, offshore production platforms, natural gas
processing plants and refining facilities. These obligations also include
items for which the Company has made promissory estoppel. The asset
retirement cost, equal to the initially estimated fair value of the asset
retirement obligation, is capitalized as part of the cost of the related
long-lived asset. Changes in the estimated obligation resulting from
revisions to estimated timing or amount of undiscounted cash flows are
recognized as a change in the asset retirement obligation and the related
asset retirement cost.
Amortization of asset retirement costs are included in depreciation,
depletion and amortization in the Consolidated Statement of Earnings.
Increases in the asset retirement obligation resulting from the passage
of time are recorded as accretion of asset retirement obligation in the
Consolidated Statement of Earnings.
Actual expenditures incurred are charged against the accumulated
obligation.
4. RECENT ACCOUNTING PRONOUNCEMENT
As of January 1, 2008, EnCana is required to adopt the CICA Handbook
Section 3031, "Inventories", which will replace the existing inventories
standard. The new standard requires inventory to be valued on a first-in,
first-out or weighted average basis, which is consistent with EnCana's
current treatment. The adoption of this standard should not have a
material impact on EnCana's Consolidated Financial Statements.
5. JOINT VENTURE WITH CONOCOPHILLIPS
On January 2, 2007, EnCana became a 50 percent partner in an integrated,
North American oil business with ConocoPhillips which consists of an
upstream and a downstream entity. The upstream entity contribution
included assets from EnCana, primarily the Foster Creek and Christina
Lake properties, with a fair value of $7.5 billion and a note receivable
from ConocoPhillips of an equal amount. For the downstream entity,
ConocoPhillips contributed its Wood River and Borger refineries, located
in Illinois and Texas respectively, for a fair value of $7.5 billion and
EnCana contributed a note payable of $7.5 billion. Further information
about these notes is included in Note 12.
In accordance with Canadian generally accepted accounting principles,
these entities have been accounted for using the proportionate
consolidation method with the results of operations shown in a separate
business segment, Integrated Oil (See Note 6).
6. SEGMENTED INFORMATION
The Company has defined its continuing operations into the following
segments:
- Canada, United States and Other includes the Company's upstream
exploration for, and development and production of natural gas, crude
oil and natural gas liquids and other related activities. The
majority of the Company's upstream operations are located in Canada
and the United States. Offshore and international exploration is
mainly focused on opportunities in Atlantic Canada, the Middle East,
and Europe.
- Integrated Oil is focused on two lines of business: the exploration
for, and development and production of bitumen in Canada using in-
situ recovery methods; and the refining of crude oil into petroleum
and chemical products located in the United States. This segment
represents EnCana's 50 percent interest in the joint venture with
ConocoPhillips.
- Market Optimization is conducted by the Midstream & Marketing
division. The Marketing groups' primary responsibility is the sale of
the Company's proprietary production. The results are included in the
Canada, United States and Integrated Oil segments. Correspondingly,
the Marketing groups also undertake market optimization activities
which comprise third-party purchases and sales of product that
provide operational flexibility for transportation commitments,
product type, delivery points and customer diversification. These
activities are reflected in the Market Optimization segment.
- Corporate includes unrealized gains or losses recorded on derivative
financial instruments. Once amounts are settled, the realized gains
and losses are recorded in the operating segment to which the
derivative instrument relates.
Market Optimization markets substantially all of the Company's upstream
production to third-party customers. 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.
In 2007, as a result of the joint venture with ConocoPhillips, EnCana
redefined its business segments to those described above. All prior
periods have been restated to conform with the current presentation.
Operations that have been discontinued are disclosed in Note 7.
Results of Continuing Operations (For the three months ended December 31)
Upstream
-----------------------------------------------
Canada United States Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $1,964 $1,718 $1,110 $ 765 $ 87 $ 69
Expenses
Production and mineral
taxes 16 20 47 60 - -
Transportation and
selling 83 107 87 66 - -
Operating 292 227 95 76 82 61
Purchased product - - - - - -
Depreciation, depletion
and amortization 599 494 324 200 52 6
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Segment Income (Loss) $ 974 $ 870 $ 557 $ 363 $ (47) $ 2
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Integrated Market
Total Upstream Oil Optimization
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $3,161 $2,552 $2,369 $ 260 $ 837 $ 735
Expenses
Production and mineral
taxes 63 80 - - - -
Transportation and
selling 170 173 108 103 - (1)
Operating 469 364 151 64 9 13
Purchased product - - 1,888 - 816 702
Depreciation, depletion
and amortization 975 700 77 43 6 4
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Segment Income (Loss) $1,484 $1,235 $ 145 $ 50 $ 6 $ 17
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-------------------------------------------------------------------------
Corporate Consolidated
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $ (566) $ 129 $5,801 $3,676
Expenses
Production and mineral taxes - - 63 80
Transportation and selling - - 278 275
Operating 3 (13) 632 428
Purchased product - - 2,704 702
Depreciation, depletion and amortization 28 19 1,086 766
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Segment Income (Loss) $ (597) $ 123 1,038 1,425
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Administrative 121 84
Interest, net 131 142
Accretion of asset retirement obligation 18 13
Foreign exchange (gain) loss, net (233) 172
(Gain) loss on divestitures 22 (2)
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59 409
-------------------------------------------------------------------------
Net Earnings Before Income Tax 979 1,016
Income tax expense (28) 373
-------------------------------------------------------------------------
Net Earnings From Continuing Operations $1,007 $ 643
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Results of Continuing Operations (For the three months ended
December 31)
Geographic and Product Information (Continuing Operations)
Produced Gas
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $1,510 $1,401 $1,011 $ 706 $2,521 $2,107
Expenses
Production and mineral
taxes 8 11 40 54 48 65
Transportation and
selling 72 66 87 66 159 132
Operating 214 166 95 76 309 242
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Operating Cash Flow $1,216 $1,158 $ 789 $ 510 $2,005 $1,668
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Oil & NGLs
-------------------------------------------------------------------------
Canada United States Total
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 454 $ 317 $ 99 $ 59 $ 553 $ 376
Expenses
Production and mineral
taxes 8 9 7 6 15 15
Transportation and
selling 11 41 - - 11 41
Operating 78 61 - - 78 61
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Operating Cash Flow $ 357 $ 206 $ 92 $ 53 $ 449 $ 259
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Integrated Oil
-------------------------------------------------------------------------
Downstream
Oil Refining Other
-------------------------------------------------------------------------
2007 2006 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenues, Net of
Royalties $ 186 $ 248 $2,206 $ - $ (23) $ 12
Expenses
Transportation and
selling 108 103 - - - -
Operating 36 56 111 - 4 8
Purchased product - - 1,915 - (27) -
-------------------------------------------------------------------------
Operating Cash Flow $ 42 $ 89 $ 180 $ - $ - $ 4
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-------------------------------------------------------------------------
Integrated Oil
-------------------------------------------------------------------------
Total
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Revenues, Net of Royalties $2,369 $ 260
Expenses
Transportation and selling 108 103
Operating 151 64
Purchased product 1,888 -
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Operating Cash Flow $ 222 $ 93
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FIRST AND FINAL ADD TO FOLLOW
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