BTU Convergence Spawning Gas Market Opportunities In North America

Status of US Electricity Deregulation Initiatives [60,321 bytes]
Planned New/Replacement US Power Capacity [34,557 bytes]
US Natural Gas Outlook [60,993 bytes]
US Northeast Outlook for Gas [69,524 bytes]

Changing North American Gas Supply Status [112,302 bytes]

The so-called BTU convergence of U.S. electric power and natural gas sectors is spawning a boom in market opportunities in the U.S. Northeast that ensure the region will be North America's fastest growing gas market.

That's the view of Catherine Good Abbott, CEO of Columbia Gas Transmission Corp., who told a Ziff Energy conference in Calgary that U.S. Northeast gas demand is expected to increase to almost 10 bcfd in 2000 and more than 12 bcfd in 2010 from about 8 bcfd in 1995 and only 3 bcfd in 1985.

The fastest growth will be in the U.S. Northeast's electrical sector, where demand for gas is expected to double to 4 bcfd in 2010 from about 2 bcfd in 1995.

In other presentations at the Ziff Energy conference, speakers voiced concerns about the complexity and speed of the BTU convergence phenomenon and offered assurances about the adequacy of gas supplies in North America to meet demand growth propelled by the BTU convergence boom.

Power driving gas demand

The amount of electricity generated from burning natural gas in the U.S. Northeast is expected to increase 140% from current levels by 2010, Abbott said.

Strong economic growth in the region is projected until 2010. Other growth drivers include environmental policies favoring gas, nuclear plant shutdowns, and electrical industry restructuring.

Nuclear plants with capacity of 4,200 MW have been closed, translating into an equivalent demand for gas of 450 MMcfd. Expected nuclear closures during 2000-09 involving 3,900 MW would translate into 420 MMcfd of gas for a total of 870 MMcfd needed to replace nuclear capacity, Abott said.

Several studies indicate additional U.S. Northeast gas demand to 2000, driven mainly by power growth, will be about 1.4-1.9 bcfd.

She noted that North American gas supply growth will come from several main areas: Western Canada, Sable Island area off Nova Scotia (which recently received initial development approval), Gulf of Mexico, and the U.S. Rocky Mountains.

Abbott said Canadian gas captured 74% of incremental U.S. Northeast demand between 1980 and 1996 and now meets almost 25% of total demand in the region.

She said that new pipeline capacity from Western Canada to 1999 has targeted the Chicago market, but excess supply can be moved into the U.S. Northeast by a number of projects east out of Chicago. (Columbia Gas is a partner in the proposed Millennium Pipeline project, which is part of a link to move gas from Western Canada and Chicago to New York, Pennsylvania, and other Eastern Seaboard states. The 380-mile, 36-in. line would connect with the TransCanada PipeLines Ltd. system at a new Lake Erie border point and move gas to a terminus in Westchester County, N.Y.)

BTU convergence outlook

Paula G. Rosput, president of Duke Energy Power Services, said the electrical generation industry is in year 5 or 6 of a convergence and deregulation process that will play out over 15 years.

She said that the process-previously experienced by the airlines, telecommunications, and natural gas indsutries-involves several phases. It is characterized by growing merger and acquisition activity and convergence towards a one-stop energy utility supplying fuels ranging from electricity and gas, to coal, fuel oil, and propane.

The investment life cycle of deregulation involves a statutory regulatory process, increase in capacity factor of existing capital stock, then retirement of obsolete units and deployment of new capital stock.

Aging U.S. electrical generation plant capacity will be increasingly retired under deregulation, and there will be a tremendous turnover in capital stock, Rosput said.

Small and old is ugly when it comes to electrical plants, she said, because they won't be competitive against new, more efficient capital stock. A low delivered gas price is the key to repatriation of capital for new gas-fired units. Grassroots project economics will strongly favor gas.

Coal will take a relatively larger share of market growth during 1995-2000. After 2000, economics will favor natural gas, which is competitive over time. The inherently lower cost of coal provides a potential long-term cap on expansion of natural gas market share in electric generation, Rosput said. Natural gas will first force the retirement of oil-based electrical generation plants over the next several years, particularly in the U.S. Northeast, which will develop a substantial amount of gas-fired generation.

The coal industry would have to make a step change in technology to compete with gas and would have to work with policy-makers to overcome the huge barriers that are associated with coal-fired generation.

The process of industry deregulation is under way in many states but activity varies. California is now implementing deregulation, while there has been little deregulation activity in Florida or the Dakotas. There are niche opportunities in states such as Florida-even though deregulation has not occurred there-for companies to come in with new technology.

The Northeast is the best market for natural gas conversions, Rosput said, and everyone believes they can repatriate their capital on new generation over the next couple of years. This is particularly true if some nuclear generation capacity does not come back on line.

Electric power demand

Mary J. Hutzler, director, U.S. Department of Energy office of integrated analysis and forecasting, said U.S. demand for electricity is expected to grow 1.5-2%/year over the next 10-20 years.

Electricity producers will rely mainly on coal and natural gas to meet increased demand, she said. Coal use will grow as currently underutilized plants increase output to meet market demands. Increased natural gas use will come as new combustion turbine and combined-cycle plants are built to meet needs for new capacity. Over the next 10-15 years, natural gas-fired plants are expected to dominate new capacity additions.

Increased consumption will be driven by continued growth in new uses for energy in all sectors, Hutzler said. Dampening of demand by increased efficiency of traditional appliances will be offset by growth in new uses such as computers, fax machines, copiers, scanners, and cell phone chargers.

Hutzler cites two main factors that could change these expectations: global climate change accords and the implementation of renewable portfolio standards that are included in several electricity restructuring bills now being considered by the U.S. Congress. Both of these issues could significantly affect coal and gas use.

Any effort to reduce or stabilize greenhouse gas emissions would have a very serious effect on the fuels used to generate electricity, she noted.

Canadian production

Canadian well productivity is steady and adequate to meet both domestic and export demand growth, and producers can maintain drilling levels to meet demand growth. Western Canada gas well completions averaged 3,986 wells/year during 1993-96 and remain steady. Western Canada production of 15 bcfd in 1995 is expected to rise to 19 bcfd in 2000 and 22 bcfd by 2005. This will support growth in domestic demand and an additional 2 bcfd in exports.

Tom Woods, vice-president, U.S. gas services, for Ziff Energy Group, said annual production per well in Western Canada has remained constant above 100 MMcf since 1980, compared with 60 MMcf/year for the same period in the Lower 48.

Woods said that North American gas demand could exceed 30 tcf/year before 2005 and approach 40 tcf/year around 2015, with modest increases overall in electric utility demand for gas. Power demand for gas is growing rapidly in the U.S. Northeast.

There is no indication of upward pressures on gas prices due to resource depletion, he contends.

With the exception of the western Lower 48, North American pipeline capacity is largely at or near capacity. Many lines are operating at load factors of 80-90%, and some at more than 90%. Large-scale new pipeline projects to add incremental capacity will be needed on a regular basis to meet demand and sustain future growth.

The challenge for the industry over the next 20 years will be building new lines with 500 MMcfd or less capacity to meet demand, Woods said.

Canadian supply

Phil Prince of the Alberta Energy and Utilities Board (AEUB), said that the supply picture is positive for Canadian marketable gas based on earlier studies by the Energy Resources Conservation Board and work this year by the Canadian Potential Gas Committee.

AEUB's initial gas in-place estimate for Canada is 600 tcf, of which about 400 tcf is marketable, and remaining marketable gas in Canada is estimated at about 300 Tcf. Prince said that unconventional resources, including tight gas and coalbed methane, could easily match-and possibly greatly exceed-these numbers, but economic viability of these resources has not been established.

In frontier areas, exploration activity resumed last year in the Mackenzie Valley, Scotian Shelf, and Grand Banks for the first time in 5 years.

Gas potential has been assessed in the Mackenzie Valley, the Beaufort basin, the Sverdrup basin, and the Sable subbasin. Offshore Newfoundland and Labrador also have significant potential but were not specifically assessed by the committee. Total initial gas-in-place in these basins is estimated at more than 50 tcf and, in the four areas that were assessed, another 78 tcf of undiscovered potential is expected. Production and transportation infrastructure would be needed to turn this gas into a marketable resource, Prince said.

Total volume of conventional gas in the Western Canadian Sedimentary Basin (WCSB), which covers the Beaufort Sea, the Mackenzie Delta, and Western Canada is estimated at 444 tcf of which 207 tcf, or 47%, is undiscovered. The Canadian Potential Gas Committee estimates that 122 tcf of the undiscovered gas will be marketable. Combined with 62 tcf of remaining reserves, the potential for remaining marketable gas in the WCSB is estimated at 184 tcf. Several other studies place conventional marketable gas in the WCSB at 170 -282 tcf. About 80% of the undiscovered gas potential is in Alberta, and 15% is in British Columbia. Ultimate marketable gas in Alberta is estimated at 200 tcf. That is made up of 75 tcf of cumulative production, remaining marketable gas of 55 tcf and, yet-to-be discovered reserves of 70 tcf.

U.S. overview

Randy Mundt, executive vice-president, marketing, for Burlington Resources, said the major focus in U.S. exploration and development activity should shift from onshore to offshore areas.

There is a gas surplus in the Western U.S., strong demand for Gulf Coast production in the Central U.S., and booming markets for gas in the Northeast. Mundt said that the quality of drillable projects has been decreasing in the past several years, and there is a conviction that the best bets are offshore. Offshore discoveries have shown high decline rates.

Proven reserves have declined in the U.S., and a critical statistic is that only 65% of U.S. additions came from field extensions.

U.S. production in the past decade increased from 15.3 tcf/year to 18.4 tcf, total proved reserves declined slightly from 158.9 tcf to 157.2 tcf, and the reserves-to-production ratio dropped from 10.4 in 1986 to 8.5 in 1996 (see chart).

The Gulf Coast region onshore and offshore, with production of 30 bcfd, is the largest producing basin, but finding costs are rising in the Gulf of Mexico because of increasing costs for drilling, seismic and well servicing, Mundt noted.

Current production estimates for major U.S. basins, in bcfd, are: Rockies 3.7, San Juan 3.9, Permian 5, Gulf Coast 15.6 offshore and 12.8 onshore, and Anadarko 8.6.

Gas reserve estimates at the end of 1996, in tcf, were: Rockies 21.7, San Juan 13.7, Permian 26.4, Gulf offshore 29 and onshore 22.2, and Anadarko 20.8.

The pipeline system in the U.S. today is not flexible enough to move gas to areas of demand in peak periods, Mundt contends, and there is a growing strain on the transmission structure.

Mundt said the outlook is optimistic for gas prices. There is a continued pattern of increased activity and money to finance projects. The major focus of E&D for gas in the U.S. will be in the Gulf of Mexico, particularly deepwater plays. Basin differentials will continue to decline as new infrastructure is developed.