STATEMENT OF

JAY HAKES

ADMINISTRATOR, ENERGY INFORMATION ADMINISTRATION

DEPARTMENT OF ENERGY

BEFORE THE

ENERGY AND NATURAL RESOURCES COMMITTEE

U.S. SENATE

APRIL 21, 1999

 

 

Mr. Chairman and Members of the Committee:

I appreciate the opportunity to appear before you today to discuss the Energy Information Administration's (EIA) views on prospects for natural gas demand, supply, and transportation..

EIA is an independent statistical and analytical agency within the Department of Energy. We are charged with providing objective, timely, and relevant data, analysis, and projections for the use of the Energy Department, other agencies, the Congress, and the public. We do not take positions on policy issues, but we do produce data and analysis reports that are meant to help policy makers decide energy policy. Because we have an element of statutory independence with respect to the analyses that we publish, our views are strictly those of EIA. We do not speak for the Department, nor for any particular point of view with respect to energy policy, and our views should not be construed as representing those of the Department or the Administration.

Today's analysis is based on EIA's Annual Energy Outlook, which provides projections and analysis of domestic energy consumption, supply, prices, and carbon emissions through 2020. These projections are not meant to be exact predictions of the future but represent a likely future, assuming known trends in demographics and technology improvements, and also assuming no change in current law, regulation, and policy. EIA does not propose, advocate, or speculate on changes in laws and regulations. So, one of our key assumptions is that all current laws and regulations remain as enacted. That means, for example, that no new initiatives are assumed for the control of greenhouse gas emissions, even though the United States signed the Kyoto treaty in November.

A 30-trillion-cubic-foot Market

The prospect of a 30-trillion-cubic-foot (tcf) market for natural gas may be daunting to some participants in the natural gas industry. After all, the record U.S. consumption of natural gas occurred a generation ago in 1972. And, as close as we came in 1996 and 1997, that record of 22.1 tcf still stands. Our current Short-Term Energy Outlook projects that the record will continue to stand this year, and be broken next year.

Yet, we believe that it's a question of when and how--not if--a 30 tcf market will be achieved. We project that demand for natural gas, with increases principally from the electric generation sector, will reach almost 30 tcf in 2013 and continue to rise to more than 32 tcf in 2020. As demand increases, pressure on natural gas supply and the transportation infrastructure will grow. These demand-side pressures will begin to raise questions like:

And ultimately:

Last year U.S. natural gas consumption was just over 21 tcf and accounted for 24 percent of domestic energy consumption. Gas consumption is expected to grow 1.7 percent annually from 1997 to 2020--faster than any other major fuel source, mainly because of the growth in gas-fired electricity generation. (Figure 1) This increase occurs with a relatively moderate impact on gas wellhead prices, which are expected to only rise slowly through the end of the forecast.

Domestic gas production is expected to increase a bit more slowly than consumption over the forecast, rising from 19 Tcf in 1997 to 27 Tcf in 2020. Growing production reflects rising wellhead prices, relatively abundant natural gas resources, and improvements in technologies, particularly for offshore and unconventional gas.

Net imports rise to make up the difference between production and consumption, because they are generally expected to be better priced than competing domestic sources. Net imports are expected to climb from 2.8 Tcf in 1997 to 5.0 Tcf in 2020--faster than the growth in consumption. Imports continue to be dominated by pipeline imports from Canada over the forecast. LNG imports are projected to increase from 80 to 360 billion cubic feet from 1997 to 2020, and exports to Mexico are expected to continue through the forecast period.

Rising Natural Gas Demand

The industrial sector is the largest gas-consuming sector, with significant amounts of gas used in the bulk chemical, refining, and metal durables sectors. Industrial as consumption increases by 1.8 Tcf over the forecast--less than 1 percent a year--particularly in the refining and metal durables sectors, because of relatively low and stable gas prices. (Figure 2)

Combined, the residential and commercial sectors add 1.4 trillion cubic feet from 1997 to 2020. Gas demand in the residential and commercial sectors is driven by increasing population and declining consumer prices. The declines in prices paid by the consumer reflect increased gas distribution efficiencies in an increasingly competitive market. Because natural gas prices are lower than the prices of other fuels, the number of homes heated by natural gas is projected to increase faster than those heated by electricity and oil. However, gas loses market share to electricity in the residential sector, because of a rise both in the number of homes in the South and in the demand for consumer electronics. Residential and commercial gas consumption are expected to grow more slowly than industrial gas consumption.

Gas consumption by electric generators, not including industrial cogenerators, increases more than 2 times during the forecast, from 3.3 trillion cubic feet in 1997 to 9.2 trillion cubic feet in 2020. The significant growth in gas-fired generation is partly driven by electric industry restructuring, but is mainly spurred by the addition of new gas turbines and combined-cycle facilities and increased utilization of existing gas-fired power plants. Lower capital costs, short lead times, and projected improvements in gas turbine heat rates give gas an advantage over coal, for new generation in most regions of the United States.

In 1997 electricity generators were the third-largest natural gas consuming sector, just exceeding levels in the commercial sector. By 2020, however, the projected enormous growth in gas-fired generation makes electricity generators the second largest gas-consuming sector--rising to within 1 tcf of the industrial sector. As natural gas is increasingly used in baseload generation, electricity generators can be expected to take a greater interest in natural gas pipeline capacity expansion by signing up for more guaranteed service.

The total expected increase in consumption from 1997 through 2013 is almost 8 tcf. More than half of the increase in consumption, 4 tcf, is expected in the electric generation sector.

After 2013 natural gas consumption continues to increase, though not nearly as fast as before reaching 30 tcf. Electric generator consumption continues to grow faster than the other sectors after 2013. Over the entire forecast, natural gas consumption is projected to grow by more than 10 tcf, and more than half of the increase comes from the electric generation sector.

Over the forecast, the share of electricity produced with natural gas share rises from 14 to 33 percent from 1997 to 2020, while the coal share declines from 53 to 49 percent. Nuclear power declines as a source of electric power--from 18 to 7 percent of electricity generation.

Before the advent of natural gas combined-cycle plants, fossil-fired baseload capacity additions were limited primarily to pulverized-coal steam units; today, however, new combined-cycle plants cost less than half and are 1 times as efficient as new coal plants. The lower capital costs and higher efficiencies of combined-cycle plants offset their higher fuel costs. (Figure 3)

To meet the new demand growth, utilities can be expected to use existing plants more intensively, import power from Canada and Mexico, and purchase power from cogenerators and exempt wholesale generators. Even so, 363 gigawatts of new capacity will be needed from 1996 to 2020, a capacity increase of approximately 50 percent. Of that new capacity, 88 percent is projected to be combined-cycle or combustion turbine technology fueled primarily by natural gas. In other words, more than 1,000 of the 1,200 new power plants--assuming an average plant capacity of 300 megawatts--that are expected to be built between now and 2020 are projected to be gas-fired.

In our analysis new coal plants are not competitive until 2010, when rising natural gas prices are expected to lead to the construction of a few new coal-steam power plants in some regions. This is when the price of natural gas exceeds the price of coal by $2 per million BTU.

Many of the new gas-fired plants built over the next 20 years will replace nuclear power plants. In AEO99 more than half of the existing nuclear capacity is expected to be taken out of service by 2020. No new nuclear units are expected to become operable by 2020, because natural gas and coal-fired plants are projected to be more economical.

The nuclear power plants now in operation are aging, and many will reach the end of their operating licenses in the forecast period. Some early retirements are included in the forecast, based on the assumption that major capital investments will be needed after 30 years of operation and will be made only if they are more economical than building new capacity. In all, 27 nuclear units are projected to be retired early in the reference case. On the other hand, a few nuclear plants are expected to operate longer than their current license terms. In 1998, two utilities--Baltimore Gas and Electric and Duke Power--submitted license renewal applications. Six units with license expiration dates before 2020 are expected to continue operating after license renewals.

Growing Natural Gas Supply

Domestic gas production is expected to increase more slowly than consumption over the forecast, from 19 Tcf in 1997 to 27 Tcf in 2020. (Figure 4) To satisfy a 30 tcf market in 2013, annual domestic natural gas production will need to increase by 6 tcf. This means that over the next 16 years production increases must average about 400 billion cubic feet (bcf) per year. One obvious question is whether the natural gas industry has ever sustained such an increase before? In fact, from 1955 to 1971 the industry has managed to increase production at nearly twice the projected rate required. Over those 16 years gas production more than doubled, increasing by about 12 tcf.

Of course, conditions are different from those earlier years. Undiscovered field sizes in mature producing areas are smaller, and larger prospects are located in more remote areas. On the other hand, the real price of natural gas is much higher than it was in 1955, exploration and production costs are lower in real terms, technology is better, and the regulatory environment is much more favorable to gas production. All these conditions make EIA optimistic about increasing production by 6 tcf through 2013 and by 2 more tcf from 2013 to 2020.

The regulatory environment has changed considerably for natural gas producers since 1955. In the past, producers have been constrained by price controls and the market was unable to send clear signals about the consumers' interest in purchasing and the suppliers' willingness to sell. As a result, during some periods curtailments in supply were of great concern. In today's competitive market, improved price signals are sent to sellers and purchasers allowing for the setting of market clearing prices. The question is less "Will the gas be there?" and more "How much will it cost?"

Current estimates of technically-recoverable natural gas resources indicate that resource base is expected to be adequate to sustain growing production volumes for many years. Resources include not only proved reserves, which were 166 tcf as of January 1, 1997, but inferred reserves from known fields, and undiscovered resources from new fields. Resource estimates come primarily from the assessments done by the U.S. Geological Survey for onshore regions and by the Minerals Management Service for the offshore. (Figure 5)

As technology improves, it becomes economical to produce a larger share of the technically recoverable resource. As of January 1, 1997, technically recoverable resources were 1,176 tcf. Resources in Lower 48 undiscovered fields not associated with oil deposits accounted for 269 tcf of the total. Inferred reserves, representing the expected growth from previously discovered fields, totaled 233 tcf, most of that located in onshore areas. Of all the undeveloped resources, the largest share belongs to unconventional gas from tight sands formations, coalbeds, and shales at 372 tcf. Gas associated with oil makes up most of the balance of the total technically recoverable resource base.

Production currently flows from these categories of gas and is expected to continue to flow in the future. Over the forecast period, increased U.S. natural gas production comes primarily from lower 48 onshore conventional nonassociated sources. Conventional onshore production accounted for 39 percent of total U.S. domestic production in 1997 and is expected to increase to 45 percent in 2020. (Figure 6)

Offshore production, mainly from wells in the Gulf of Mexico, also rises. Innovative, cost-saving technology and large finds, particularly in the deep waters of the Gulf, have encouraged interest in this area. Lower-48 offshore Gulf Coast increased to 5.7 tcf in 1997--the highest yet recorded.

Unconventional gas production increases at the fastest rate of any other source over the forecast period, largely because of expanded tight sands gas production in the Rocky Mountain region.

Alaska natural gas production rises gradually over the forecast. But Alaskan gas is not expected to affect the lower-48 markets, because prices are not high enough to cover delivery costs, including transportation, to the lower-48 States. Gas production associated with oil production is expected to decline over the forecast, as oil production declines.

The Rocky Mountain (primarily unconventional sources) and offshore Gulf of Mexico regions account for just under half of the incremental production needed between 1997 to 2013, as improvements in both unconventional and offshore technologies continue. Increased production from conventional resources in the onshore Gulf Coast and Midcontinent regions account for almost a third of the total increase in the same period because of the relatively large resources. In the 2013 to 2020 period, onshore natural gas production continues to increase primarily driven by unconventional supplies in the Rocky Mountains and deep conventional supplies in the onshore Gulf Coast region. Production from the offshore Gulf of Mexico is 0.67 tcf lower in 2020 than in 2013 because of resource limits. Alaskan gas is not expected to be transported to the lower 48 States through 2020, because prices are not high enough to support the required transportation system.

One of the key activities in producing natural gas is drilling. With rising prices and generally declining drilling costs, successful lower 48 natural gas well completions in the reference case are expected to reach 12,200 in 2020. This level of drilling is far below the level reached in 1981 of more than 20,000 successful gas wells, but represents approximately a 15-percent increase over current levels. (Figure 7)

Although the number of available drilling rigs has been declining since 1982, price increases are a powerful incentive for increased drilling and the purchase of new drilling equipment. The number of available drilling rigs increased by almost 14 percent annually between 1974 and 1982--from 1,767 to 5,644--as natural gas prices more than quadrupled in real terms and oil prices more than doubled. About 1,600 drilling rigs were available in the United States in 1996. Given the historical response to rising prices, even a modest increase in prices is likely to make drilling rigs available.

Technological Development

Technology improvements have both reduced effective exploration and development costs, and increased the recoverability of in-place resources. Major advances in data acquisition, data processing, and the technology of displaying and integrating seismic data with other geologic data-combined with lower cost computer power and experience gained using new techniques-have exerted downward pressure on costs. One significant cost-saving technology, adopted in the later part of the 1980's, was horizontal drilling. Drilling a horizontal, as opposed to a conventional vertical well, enables more of the reservoir to be exposed to the wellbore since most reservoirs are wider than they are deep. Additionally, the introduction of subsea well technologies, tension leg platforms, and production spars have opened up vast new and promising areas for exploration in the deepwater areas of the offshore that had been inaccessible. Effective use of improved exploration and production technologies to aid in the discovery and development of resources--particularly, unconventional gas and offshore deep water fields--will be needed if new reserves are to replace those depleted by production. (Figure 8)

Uncertainties about the pace of technological development are one of the key factors that could affect gas production and prices. Alternative cases were used to assess the sensitivity of the projections to changes in success rates, exploration and development costs, and finding rates as a result of technological progress. The assumed technology improvement rates were increased and decreased by approximately 50 percent in rapid and slow technology cases. All other parameters were kept at their reference case values, including technology parameters for other modules, parameters affecting foreign oil supply, and assumptions about foreign natural gas trade.

Changes in production in the alternative technology cases reflect the benefits of lower costs and higher productivity for conventionally recoverable gas, as well as an array of technological enhancements for unconventional gas recovery. The changes in supply lead to price changes that affect new investment in gas-fired technologies, especially in the industrial and electricity generation sectors. Rapid technology improvements yield benefits in the form of both lower prices and increased production to meet higher consumption requirements

In the rapid technology case, the share of electricity generated with natural gas in 2020 is 36 percent, compared with 29 percent in the slow technology case. The higher level of gas consumption comes largely at the expense of coal. There is little additional displacement of petroleum products in the rapid technology case, because natural gas captures the bulk of the dual-fired boiler market in the reference case. In contrast, in the slow technology case, natural gas loses market share to both coal and petroleum products in the electricity generation sector.

Production from unconventional gas resources (tight sands, shales, and coalbeds) is particularly responsive to changes in the assumed levels of technological progress. In the rapid technology case, the unconventional gas share of total lower-48 natural gas production in 2020 is projected to be 33 percent, compared with 25 percent in the reference case, and 19 percent in the slow technology case.

At the higher prices prevailing in the slow technology case, consumption does not reach 30 tcf until 2015, instead of 2013, and consumption rises to 31 tcf by the end of the forecast, rather than 32 tcf. Likewise, production manages to rise the necessary 6 tcf by 2015, rather than by 2013.

Slowly Rising Natural Gas Wellhead Prices

Wellhead prices for natural gas in the lower 48 States increase on average by 0.8 percent a year in the reference case to $2.68 per thousand cubic feet in 1997 dollars.. The increase reflects rising demand for natural gas and the impact of the progressions of discoveries from larger and more profitable fields to smaller, less economical ones. The natural gas price projections are highly sensitive to changes in the assumptions about technological progress. Over the projection period, lower 48 wellhead prices increase at an average annual rate of 1.3 percent in the slow technology case, rising fairly steadily to $2.99 per thousand cubic feet in 2020. In the rapid technology case, average natural gas wellhead prices in any forecast years do not exceed the 1997 level by more than 3.5 percent, and by 2020 they are back to the 1997 price of $2.23 per thousand cubic feet. (Figure 9)

Through 2000, both price and production levels for lower 48 oil and natural gas are almost identical in the reference case and the two technological progress cases. By 2020, however, natural gas prices are 12 percent higher (at $2.99 per thousand cubic feet) in the slow technology case and 17 percent lower (at $2.23 per thousand cubic feet) in the rapid technology case than in the reference case ($2.68 per thousand cubic feet).

Natural Gas Imports

Net natural gas imports are expected to grow in the forecast from 13 percent of total gas consumption in 1997 to 16 percent in 2020. Most of the increase is attributable to imports from Canada, primarily from western Canada, although some new gas is also expected from Sable Island in the offshore Atlantic. As in the United States, resources are adequate to sustain production for many years. The Canadian Gas Potential Committee indicates that there is an estimated 570 tcf of discovered and undiscovered natural gas in Canada, both in conventional and unconventional reservoirs.(1) Mexico also has a considerable natural gas resource base, but gas trade with Mexico is expected to consist primarily of exports. Conversion of power plants from heavy fuel oil to natural gas, in compliance with Mexico's new environmental regulations, is expected to gain momentum and it is uncertain whether indigenous production can be increased enough to satisfy rising demand. LNG provides another source of gas imports; however, given the projected low natural gas prices in the lower 48 markets, LNG is expected to supply less than 1 percent of U.S. gas consumption in 2020.

Natural Gas Pipeline Infrastructure

AEO99 projects a 32 percent increase in interregional pipeline capacity through 2020. Pipeline capacity crossing the 12 regions used for this analysis, including import/export capacity, is projected to increase from 116 bcf per day of design capacity in 1997 to 153 bcf per day in 2020. However, more than half of the pipeline capacity expected by 2020 is likely to occur between 1997 and 2001. (Figure 10)

Much of this expansion is already either under construction or far enough along in the planning and approval process to be deemed likely to occur. Substantial investment has also already been made in pipeline expansion. The added capacity will provide access to new and expanding production areas, such as Canada and the deep offshore, and will accommodate shifts in demand patterns, such as new demand for natural gas to replace electricity generation capacity lost as a result of nuclear retirements.

In the near term, proposed additional capacity from Canada will bring significantly greater volumes of gas to the Midwestern marketplace, although several pipelines from the South Central region already have the capacity to move large volumes of gas to the Midwest. Thus, in the near term, there is a potential for surplus supply to develop in the Chicago area and for pipelines from the South Central region to become underutilized. To alleviate the situation, and to address the growing demand for natural gas in the Northeast, several projects have been proposed that would tap into the expanding Chicago hub and redirect some of its supplies eastward. Other near-term projects are proposed and under construction to bring newly-developed gas from Sable Island in Canada to the northeastern United States.

Much of the new capacity that has been added since 1990 or is to be completed by 2001 consists of long-haul pipelines from growing supply areas. By 2001, much of the projected new capacity will be able to link with nearby major long-haul pipelines already in operation, so that the primary short-term requirements will be for feeder lines to tap into the existing pipelines or compression and looping along existing routes where capacity needs to be augmented. Compression and looping are much less expensive than laying pipe along new routes and usually require less lead time.

In recent history, the largest recent annual increase in pipeline capacity was 4.7 billion cubic feet per day from 1992 to 1993, partly because of the construction of four major pipelines into California from the Mountain States (Kern River, Mohave, El Paso, and Transwestern) and two major pipelines out of Canada (Great Lakes into the Midwest and Iroquois into the New York/New England area). In view of the historical and expected near-term increases in capacity peaking at 8.2 billion cubic feet per day of capacity additions next year, capacity expansion is not likely to be a problem in developing a 30 tcf market. In addition, the increasing consumption by electric generators, traditionally dominating the offpeak summer months, should serve to levelize the load, increase the annual utilization, and improve pipeline efficiency.

In addition, Government policy supports an optimistic outlook for the post-2000 pipeline expansion forecast. FERC policy supports more ready approval of expansion by the pipelines as long as they are willing to assume more risk rather than requiring firm contracts to be in place before approving an expansion, and the Council on Environmental Quality has recently allocated funding to promote interagency cooperation in the review of pipeline permits, with the primary intention of speeding up the process. The FERC has responded positively to issues raised by the pipeline industry regarding its method of determining allowed rates of return by evaluating possible changes in the method it uses to calculate them. Finally, FERC will be evaluating proposals due tomorrow (April 22) that are being submitted under its mega-notice of proposed rulemaking on short-term capacity issues and notice of inquiry on long-term transportation issues, in its effort to encourage a competitive and efficient market for pipeline capacity.

Summary

In summary, over the next 20 years the U.S. natural gas market is expected to be largely driven by the demand for electricity. From now through 2020 we expect gas consumption by electricity generators to increase more than 2 times. Total gas consumption is expected to rise to 30 tcf in 2013 and to 32 tcf in 2020. U.S. production is expected to increase to 27 tcf and net imports to 5 tcf by 2020. Gas supplies and pipeline infrastructure are expected to be adequate to allow wellhead prices to rise to $2.55 per mcf in 2013 and $2.68 in 2020.

1. Canadian Gas Potential Committee, Natural Gas Potential in Canada (Calgary: University of Calgary, 1997), p. 1.

 

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