"EnCana delivered outstanding financial and operating results in 2003 and built an even stronger asset base from which to deliver top performance over the long haul. We have increased the intrinsic value of each EnCana share by growing oil and gas sales by an average of 9 percent and increasing proved reserves by 12 percent. The sale of higher cost non-operated assets, combined with the addition of high-quality, long-term growth assets such as Cutbank Ridge, is evidence of our focus on reducing unit costs, growing sales and improving returns," said Gwyn Morgan, EnCana's President & Chief Executive Officer.
"With our 203 percent production replacement coming almost entirely through the drill bit, EnCana added 533 million BOE of proved reserves at a finding, development and acquisition cost of $8.75 per BOE. Our operating and administrative costs of $4.11 per BOE are below our 2003 guidance range and one of the lowest among our large capitalization independent peers," Morgan said.
Solid fourth quarter earnings and cash flow; oil and NGLs sales up 32 percent
In the fourth quarter of 2003, EnCana's earnings increased 51 percent from the same period in 2002 to $426 million, or $0.91 per common share diluted. Earnings from continuing operations, excluding gains due to foreign exchange translation of U.S. dollar debt issued in Canada (after tax) and tax rate changes, increased 32 percent in the fourth quarter of 2003 compared to the same 2002 period to $316 million, or $0.68 per common share diluted. Fourth quarter cash flow increased 34 percent from the fourth quarter of 2002 to $1.25 billion, or $2.69 per common share diluted. Fourth quarter oil, natural gas and NGLs sales averaged 713,900 BOE per day, up 13 percent from 632,700 BOE per day in the same period in 2002. Natural gas sales averaged 2.68 billion cubic feet per day. Gas production was up 9 percent after adjusting for higher levels of withdrawal from storage in the fourth quarter of 2002. Oil and NGLs sales in the fourth quarter of 2003 averaged 266,900 barrels per day, up 32 percent from the same 2002 period. Revenues, net of royalties, were $2.85 billion, up 35 percent from the fourth quarter of 2002. EnCana drilled 1,517 net wells in the fourth quarter of 2003, comprised of 1,306 development wells and 211 exploration wells.
EnCana confirms 10 percent 2004 organic sales growth target
In 2004, EnCana is forecasting daily sales of between 690,000 and 735,000 BOE, comprised of sales between 2.7 billion and 2.85 billion cubic feet of gas per day and 240,000 and 260,000 barrels of oil and NGLs per day. Achieving the middle of these ranges would result in 10 percent sales growth. The company recently increased its oil sales guidance due to strong field performance and the recent acquisition of additional interests in the Scott and Telford oil fields in the U.K. central North Sea. Natural gas sales guidance remains the same and accounts for modest well freeze-offs in January, sales of non-core properties and expected shut-ins due to regulatory rulings in the gas over bitumen issue in northeast Alberta.
"The end of 2003 was marked by an early freeze up that enabled us to advance our drilling programs, taking 2003 drilling to more than 5,600 net wells and giving us a jump on our 2004 program. Natural gas sales exited the year at about 2.7 billion cubic feet per day, near the low end of our 2004 guidance. We have about 1,200 wells, approximately double our normal inventory, drilled across western North America that are awaiting tie in. Most of these wells are in southern Alberta. The tie-in work is planned to occur following spring break-up when additional rigs and crews from northern regions are expected to become available. These well tie-ins, plus substantial field activity elsewhere in North America, are expected to continue to increase gas sales growth as we move through the year," said Randy Eresman, EnCana's Chief Operating Officer.
EnCana's proved reserves grow 12 percent in 2003; production replacement is 203 percent
On February 10, 2004, EnCana announced that proved reserves increased to 2.36 billion BOE, up 12 percent from year-end 2002. This resulted in a 203 percent production replacement, of which essentially all was organically generated through a successful drilling program and positive revisions. The company added 478 million BOE of proved reserves internally, 55 million BOE by acquisition and divested of 51 million BOE for total additions of 482 million BOE before production. By commodity, EnCana added 1.7 trillion cubic feet of natural gas reserves and 204 million barrels of crude oil and NGLs reserves. EnCana's proved reserves at year-end were 8.4 trillion cubic feet of natural gas and 957 million barrels of crude oil and NGLs. The company's proved reserve life index remained at 10 years. All of EnCana's proved reserves are based on reports prepared by independent qualified reserves evaluators using the fundamental geological and engineering data. The process is supervised by a committee of independent directors. EnCana believes this is the most stringent standard of reserves governance available to the industry, and that it goes well beyond external reviews or audits of reserves.
"Our reserve additions, two barrels of oil equivalent for every barrel produced, clearly demonstrate the continuous, reliable drill bit growth available through relatively low risk, repeatable development drilling on our huge resource play dominated asset base. We added 1.7 trillion cubic feet of North American gas at a time when overall industry gas reserves and production growth is faltering. We have clearly identifiable captured resource potential on our existing land base which should allow similar organic reserves and production growth for years to come," Morgan said.
Finding, development and acquisition capital
EnCana invested about $4,650 million of finding, development and acquisition capital, which added 533 million BOE of proved reserves. This resulted in a finding, development and acquisition cost of $8.75 per BOE. During 2003, the average exchange rate was $0.716 to one Canadian dollar, which is a 12 percent increase from the average 2002 rate of $0.637 to one Canadian dollar. As a result of the conversion from Canadian to U.S. dollars, approximately $350 million was added to EnCana's U.S. dollar finding, development and acquisition capital compared to the previous year. Excluding this estimated appreciation in the Canadian dollar, EnCana's 2003 finding, development and acquisition costs would be lower by about $0.65 per BOE and result in a marginal increase from the 2002 cost of about $7.95 per BOE.
North American natural gas prices rise in 2003
Natural gas prices across North America rebounded over weaker 2002 prices. The average benchmark NYMEX index price in 2003 was $5.39 per thousand cubic feet, up 67 percent from the average price in 2002, driven by lower levels of natural gas in storage and continued concerns about North American supply. EnCana's average realized natural gas price, excluding hedging, was $4.87 per thousand cubic feet; including hedging it was $4.77 per thousand cubic feet. This represents an increase of 66 percent over the average pro forma 2002 price including hedging. In the fourth quarter the average benchmark NYMEX index price was $4.58 per thousand cubic feet, an increase of 15 percent from the fourth quarter of 2002. The company's fourth quarter average realized natural gas price, including hedging, was $4.65 per thousand cubic feet, up 29 percent compared to the fourth quarter of 2002.
World oil prices strong in 2003; Canadian heavy oil price differentials widen
World oil prices improved during 2003 as strong Asian demand, supply disruptions in Venezuela and Nigeria, the slow return of Iraqi oil production and OPEC's production management, kept crude oil inventories low. During the year, the average benchmark West Texas Intermediate (WTI) crude oil price was $30.99 per barrel, up 19 percent over 2002. Canadian and Ecuadorian heavy oil price differentials widened during the year primarily in response to the higher WTI price. In September 2003, the OCP Pipeline began operations and the shippers created a new Ecuadorian crude oil stream called NAPO blend. The NAPO blend is a heavier crude oil than the Oriente blend. It received a WTI differential that averaged $8.06 per barrel in 2003, compared to the average Oriente differential of $5.59 per barrel. In 2003, EnCana's average realized oil and NGLs price, excluding hedging, was $23.25 per barrel; including hedging it was $20.71 per barrel. In the fourth quarter, the company's average realized oil and NGLs price, excluding hedging, was $22.51 per barrel; including hedging it was $20.36 per barrel.
Risk management programs help reduce cash flow risk
EnCana's risk management program is designed to partially mitigate the volatility associated with commodity prices, exchange rates and interest rates. From time to time, EnCana will fix prices on future oil and gas sales to reduce the market risk associated with forecasted cash flows. EnCana has about 45 percent of projected 2004 gas sales, after royalties, hedged at an average effective NYMEX price of about $5.24 per thousand cubic feet, based upon an exchange rate of $0.758 to one Canadian dollar and a $0.73 per thousand cubic feet AECO basis for Canadian conversions. About half of EnCana's projected 2004 oil sales are hedged with swaps or subject to costless collars between $20 and $26 WTI. The detailed risk management positions at December 31, 2003 are presented in Note 12 to the unaudited fourth quarter Consolidated Financial Statements. EnCana's financial commodity price and currency risk management measures resulted in revenue being lower in the fourth quarter by approximately $15 million, comprised of $53 million of lower revenue on oil sales and $38 million of higher revenue on gas sales. For the full year, EnCana's financial commodity and currency risk management measures resulted in revenue being lower by approximately $297 million, comprised of $206 million on oil sales and $91 million on gas sales.
EnCana maintained its strong balance sheet in 2003. At December 31, 2003, the company's net debt-to-capitalization ratio was 34:66. EnCana's net debt-to-EBITDA multiple, on a trailing 12-month basis, was 1.3 times.
On October 2, 2003, EnCana completed a public offering in the United States of $500 million of 4.75% Notes due October 15, 2013. The net proceeds of the offering have been used to repay existing floating-rate bank and commercial paper indebtedness. As at December 31, 2003, approximately 52 percent of EnCana's outstanding debt was in U.S. dollars and 65 percent of total debt was long-term fixed rate. EnCana maintains strong investment grade credit ratings from three rating services: A(low) by Dominion Bond Rating Service Limited; Baa1 by Moody's Investors Service and A- by Standard and Poor's Ratings Services. At December 31, 2003, the company also had a $3.1 billion credit facility with a syndicate of major banks and lending institutions, of which more than $1.3 billion was unutilized.
EnCana generated 2003 cash flow of $4,459 million; of that amount approximately $1,900 million was reinvested to maintain production at previous levels, resulting in free cash flow of $2,559 million available for dividends, share purchases and reinvestment in growth opportunities. Core capital investment was $4,502 million, $1,319 million of which was invested in the fourth quarter. Asset and corporate acquisitions in the year were $820 million and proceeds from asset and corporate dispositions were $2,285 million, including the assumption of $385 million of debt by a purchaser, resulting in net capital investment of $3,037 million.
Strong sales growth, international achievements and strategic refinement in 2003
EnCana's 2003 upstream operations were marked by continued strong growth in daily sales and year-over-year proved reserves additions, plus some significant strategic developments. Sale of the company's interest in Syncrude, plus the recent divestiture of its interest in Petrovera Resources, narrowed the company's Canadian oil focus towards developing its low-cost, 100 percent owned and operated heavy oil reserves, primarily through steam- assisted gravity drainage (SAGD) projects at Foster Creek and Christina Lake, its Pelican Lake water flood project, all in northeast Alberta and its heavy oil property at Suffield in southern Alberta. In the fourth quarter SAGD production reached more than 35,000 barrels per day following the completion of the successful expansion of the Foster Creek project. Pelican Lake production averaged 16,000 barrels of oil per day in 2003 as a result of a successful water flood and Suffield production averaged 27,000 barrels per day in 2003, an 18 percent increase from 2002 levels. EnCana's other major oil development this year was the completion and opening of the OCP Pipeline in Ecuador, a five-year project that enabled EnCana to double its production to more than 70,000 barrels of oil per day in the fourth quarter. In the U.K. central North Sea, the acquisition of interests in the Scott and Telford fields from Amerada Hess and Shell has brought current production to about 21,000 BOE per day. Development of the Buzzard oil field is progressing as planned following the receipt of regulatory approval. First oil from Buzzard is expected in late 2006.
In natural gas, EnCana achieved strong growth from its prolific resource plays in the U.S. Rockies, acquired a new, high potential resource play at Cutbank Ridge in British Columbia and extended shallow gas development in southern Alberta to include commercial production from coalbed methane (CBM). In 2003, the company drilled 5,632 net wells, about 13 percent more than forecast, which included 5,016 development wells and 616 exploration wells.
EnCana currently has about 25 rigs running in the U.S. Rockies and about 100 rigs across Western Canada.
U.S.A. region grows 2003 natural gas production by 49 percent
U.S.A. production averaged 588 million cubic feet in 2003, up 49 percent from pro forma 2002. Fourth quarter production averaged 654 million cubic feet per day, up 27 percent from the same period in 2002. Current U.S.A. production is averaging 675 million cubic feet per day. In order to help mitigate pricing risk due to gas transportation constraints out of the U.S. Rockies, EnCana has fixed the price differential between NYMEX and the Rockies on an average of 645 million cubic feet per day of forecast gas sales for 2004 through 2007 at an average basis of $0.52 per thousand cubic feet.
"We've made strong progress during 2003 developing our two core properties, Jonah in Wyoming and Mamm Creek in Colorado, where production has increased approximately 50 percent in the past year. In 2004, we look forward to the completion of the regulatory review of our infill drilling plans at Jonah, plus advancing the development of promising new resource plays in Colorado and Texas," said Roger Biemans, President of EnCana's U.S.A. region.
Continued drilling success at Greater Sierra
EnCana ramped up production at the Greater Sierra resource play in 2003 by drilling 207 net wells in the area. Greater Sierra production exited 2003 at about 215 million cubic feet per day. Favourable changes in the B.C. government's royalty regime for summer drilling and the province's commitment to improve road infrastructure, combined with early winter drilling conditions in the fourth quarter, enabled EnCana to step up its development at Greater Sierra. Construction of EnCana's new Ekwan Pipeline started in December. This 80 kilometre link to the Alberta gas transmission system has a planned capacity of more than 400 million cubic feet per day. With start-up planned during the second quarter of 2004, the Ekwan Pipeline is expected to facilitate continued sales growth from northeast B.C., where the company currently has about 32 rigs drilling this winter.
EnCana plans to drill 300 coalbed methane wells in 2004
In 2003, the company drilled about 270 CBM wells; about half are on production. CBM production exited the year at about 10 million cubic feet per day. EnCana is expanding CBM development on its 700,000 acres of 100 percent owned royalty-free lands in southern Alberta. EnCana expects to drill approximately 300 wells in 2004, taking production to about 30 million cubic feet per day by year-end 2004. Over the next five years, EnCana expects to increase natural gas production from coal seams to more than 200 million cubic feet per day.
Cold January weather and regulatory ruling trim gas production
Extremely cold weather across Western Canada in January 2004 caused some EnCana gas wells to freeze, resulting in the shut in, on average, of about 100 million cubic feet of daily gas production during January. In addition, the Alberta Energy and Utilities Board recently ordered some additional shut-ins of certain gas wells located in areas of northeast Alberta where bitumen is also produced from deeper geological formations. In September 2003, the regulator shut in about 10 million cubic feet of EnCana's daily gas production. The most recent ruling could take that total to about 20 million cubic feet per day. The shut-in rulings are subject to additional AEUB hearings in the weeks ahead that will determine their finality. Also, about 15 million cubic feet per day of non-core Canadian gas production has been sold so far in 2004. These gas production reductions have been accounted for in the company's 2004 sales forecast range.
Sharpening heavy oil focus - sale of 53.3 percent interest in Petrovera
On February 18, 2004, EnCana sold its 53.3 percent interest in Petrovera Resources for approximately $285 million, before working capital adjustments. In 2003, EnCana's share of Petrovera's production represented about 20,000 BOE per day. This divestiture is consistent with EnCana's strategy to have high working interest, operated assets where it is able to apply core competencies and manage operating costs.
New plan being developed for Deep Panuke
EnCana has initiated work on a new plan for a potential offshore development at Deep Panuke. Two successful exploration wells near the Deep Panuke natural gas field - Margaree and Marcoh, have increased the company's confidence in the commercial potential of this discovery located about 250 kilometres southeast of Halifax, Nova Scotia. Given the numerous changes at Deep Panuke, the original development plan was no longer appropriate. Consequently, on December 3, 2003, EnCana withdrew the original Deep Panuke development applications filed with the National Energy Board and the Canada- Nova Scotia Offshore Petroleum Board in March 2002.
International sales up 113 percent in the fourth quarter
Sales from EnCana's international operations averaged 95,800 BOE per day in the fourth quarter, up 113 percent from sales of about 45,000 BOE per day in the same period last year. This doubling of sales results from the opening of the OCP Pipeline in Ecuador in early September 2003 and increased ownership in the Scott and Telford fields in the U.K. central North Sea.
Ecuador production reaches full stride
EnCana has completed its first full quarter of unrestrained production from its Ecuador oil fields, selling 77,400 barrels of oil per day in the fourth quarter of 2003, up 115 percent from the same period in 2002. For the full year, Ecuador sales reached about 46,500 barrels per day, up 27 percent compared to pro forma 2002 sales. The majority of EnCana's Ecuador production growth in 2003 was from EnCana's 100 percent owned Tarapoa block and the company's 40 percent non-operated interest in Block 15. In 2004, EnCana is focused on achieving operating cost efficiencies in all Ecuador operations and examining additional exploration opportunities on its expanded base of more than 800,000 acres of net undeveloped land.
Buzzard field development plan receives approval
On November 27, 2003, the U.K. Department of Trade and Industry granted regulatory approval of EnCana's development plan for the North Sea's Buzzard oil field. Production from the field is expected to start in late 2006, reaching a plateau of about 180,000 barrels of oil per day in 2007. The $2 billion Buzzard development will consist of three bridge-linked steel platforms supporting facilities for drilling, production, and utilities and accommodation respectively. The facilities include two subsea water injection manifolds located about two kilometers from the platform. The crude oil is expected to be transported to the mainland via a pipeline tie-in to the nearby Forties Pipeline System. The natural gas is expected to flow to market via the Frigg Pipeline System. Buzzard is located in about 100 meters of water, approximately 100 kilometers northeast of Aberdeen, Scotland and about 55 kilometers from the coast at Peterhead. EnCana is the operator of Buzzard, holding approximately 43 percent of the field, which is expected to produce about 75,000 barrels per day of light, royalty-free oil net to EnCana once the field reaches plateau level.
EnCana increased interests in Scott & Telford fields and takes over operatorship
EnCana has more than doubled its ownership of the Scott and Telford oilfields in the U.K. central North Sea. In October 2003, EnCana acquired an additional 14 percent interest in the Scott and Telford fields and subsequently took over operatorship. U.K. sales averaged 18,400 BOE per day in the fourth quarter, an increase of 102 percent over the fourth quarter of 2002. In early 2004, EnCana closed a second transaction, increasing its interests to 41 percent of Scott and 54.3 percent of Telford. EnCana is focusing its efforts on reducing the per-unit operating costs at Scott-Telford and accumulating substantial operating experience that it intends to apply in the development and daily operations of the Buzzard project.
Midstream & Marketing
EnCana's Midstream & Marketing division achieved $53 million of operating cash flow in 2003, which was within the company's 2003 revised guidance range of $48 million to $55 million. Lower than expected seasonal price differentials during much of the year resulted in lower prices bid for storage capacity and reduced opportunities for storage optimization as compared to previous years.
Expansion of independent gas storage in Alberta and California
In 2003, EnCana completed construction of its Countess gas storage facility and injected 11 billion cubic feet of gas over the year. Future expansion plans at Countess are expected to take capacity to 30 billion cubic feet in the summer of 2004 and 40 billion cubic feet in 2005, when maximum withdrawal capability is expected to reach 1.2 billion cubic feet per day. Completion of a 10 billion cubic feet expansion of the Wild Goose facility in northern California is expected in April 2004, bringing the total working gas capacity to 24 billion cubic feet. The expansion is expected to more than double the facility's withdrawal capability to 480 million cubic feet per day and expand daily injection capability from 80 million to 450 million cubic feet per day. With the company's recently expanded storage network, plus other projects underway or in planning, EnCana expects to fortify its position as a North American leader in independent gas storage.
Expansion of U.S. Rockies gas transmission capacity planned
Entrega Gas Pipeline Inc., an affiliate of EnCana Oil & Gas (USA) Inc., plans to file a letter with the U.S. Federal Energy Regulatory Commission outlining preliminary plans to build a natural gas pipeline from northwest Colorado to the Cheyenne gas trading hub in northeast Colorado. Entrega is developing this proposed pipeline based on the industry's growth forecast for gas production and the need to expand gas transportation capacity from the U.S. Rockies to major American markets. The Entrega Pipeline, with an expected initial capacity of 1.3 billion cubic feet per day, is planned to begin service in 2005. The project is subject to approval by the EnCana board of directors and regulatory approval by federal and state agencies. The company plans to hold an open season seeking shippers to contract for capacity on the proposed Entrega Pipeline.
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