Copyright 2000 Federal News Service, Inc.
Federal News Service
December 12, 2000, Tuesday
SECTION: PREPARED TESTIMONY
LENGTH: 2460 words
HEADLINE:
PREPARED TESTIMONY OF MARK J. MAZUR ACTING ADMINISTRATOR ENERGY INFORMATION
ADMINISTRATION, DEPARTMENT OF ENERGY
BEFORE THE
SENATE COMMITTEE ON ENERGY AND NATURAL RESOURCES
BODY:
Mr. Chairman and Members of the Committee:
I appreciate the opportunity to appear before you today to discuss the
views of the Energy Information Administration (EIA) on natural gas supply and
demand.
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
policymakers 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, we will focus on the recent surge in natural gas prices, discussing some
of the potential reasons for this rapid price movement. We also will consider
what this price increase means for American consumers of natural gas and how we
expect markets to respond to this runup in prices. Since late May 2000, spot
wellhead prices generally have been above $4 per MMBtu (million
Btu) at the Henry Hub. For most of September through early December, these
prices have been above $5 per MMBtu, more than double the price
of one year ago, and recently spot prices approached $9 per
MMBtu. Spot gas prices for the past 8 months therefore have consistently
exceeded the normal range exhibited in 1998 and 1999, which generally was below
$3 per MMBtu (Figure 1).
In late November, gas spot
prices surged past $6 per MMBtu, reaching
$8.86 per MMBtu on December 6, 2000. Although spot prices at
certain cash markets have been at comparable levels in the past, the present
experience is unusual in that gas prices previously had not remained this high
for a sustained period of time.
In addition to higher prices nationally,
California has been experiencing particularly high natural gas spot prices (more
than four times as high as recent national averages). High demand for gas-fired
electricity generation and for heating, coupled with low storage levels and low
hydro and nuclear generation output, have severely strained the system in that
State. Available supplies of gas from outside the State to meet strong gas
demand are limited due to lingering operational difficulties along the El Paso
system entering southern California, and the lack of available capacity along
pipeline routes from the Canadian border in the State of Washington and from the
Rocky Mountain producing areas. The El Paso system is constrained below normal
flow levels while it is recovering from the pipeline rupture in August. The
limited spare capacity into California elsewhere is because these systems
typically have run at high rates of utilization.
Recent surges in
natural gas demand underscore the importance of gas in storage as part of the
U.S. supply picture. The American Gas Association (AGA) estimated net
withdrawals at 73 Bcf for the week ended Friday, December 1. Based on these
withdrawals, nationwide natural gas inventories are at an EIA-estimated 2,414
Bcf, which is 394 bcf or 14 percent below EIA's average of 2,808 Bcf for this
point during the previous 5 years (1995-1999) (Figure 2). While this withdrawal
estimate is half the amount from the previous week, it is nonetheless relatively
large for this point in the year. It was driven largely by the heavy
gas-consuming East region, where estimated withdrawals were 57 Bcf-the second
largest draw for that region in this particular week of the heating season over
the past 5 years. As of December 1, East region stocks were 7.3 percent below
the 5-year average (1,714 Bcf), while the 254 and 571 Bcf in the West region and
the producing region stocks are 31 and 21 percent below normal. EIA expects that
high and volatile gas prices will prevail until significantly more gas supplies
enter the market, although the likelihood of that in the near future is not
high. Natural gas' consumption this winter (October 2000 through March 2001) is
expected to be 5.9 percent greater than last winter's level, assuming normal
temperatures in the remainder of the season. Normal weather implies an 11
percent rise in gas-weighted heating degree-days compared with last winter,
which was much warmer than normal. Under normal weather assumptions, estimated
residential and commercial sector consumption would be up by around 10 percent
over the same period last year. Natural gas demand in the industrial sector is
expected to increase by 7.4 percent in 2000, with gas-fired electricity
generation by merchant plants and cogenerators combined expected to be up by
18.6 percent. Electric utility gas demand is expected to remain about level with
consumption rates seen in 2000. This distinction is due in part to sales of
electric generating plants by electric utilities to unregulated generating
companies, fuel consumption that currently is recorded by EIA in the industrial
sector.
During the winter months, net imports of natural gas are about
10 percent higher than during the rest of the year and usually increase to full
pipeline capacity. While it is unlikely that export capacity will be fully
utilized this winter, EIA expects net imports to rise by 7.3 percent over last
winter's imports. The Alliance Pipeline began carrying gas from western Canada
to the Midwest on December 1. Even if Alliance is near capacity at mid winter,
it is highly likely that a substantial portion of the volumes contracted for
delivery on the system will have been redirected from other systems,
particularly the TransCanada Pipeline System. Thus, the Alliance pipeline may
not add significantly to total gas supply from Canada this winter.
Assuming normal weather for the remainder of the heating season, EIA is
projecting that natural gas prices at the wellhead this winter (October-March)
will average about $5.60 per thousand cubic feet, more than
double the price of last winter (Figure 3). Cold weather for prolonged periods
this winter would strain supplies and could result in even higher spot prices.
Given the recent variability in the natural gas spot market, spot prices of
natural gas are likely to hit or breach the upper level of the uncertainty bands
of the forecast (shown as dotted lines in Figure 3) if the cold weather in the
gas consuming regions of the country mms out to be unexpectedly severe. On the
other hand, the market experience in October shows that spot gas prices could
still plunge sharply if the weather mms warm for any lengthy period of time in
the gas consuming regions. In addition to expected supply and demand conditions
this winter, continued increases in natural gas demand from new gas generating
plants next year will probably prolong the much-above-normal price environment
through 2001, even if further gains in U.S. and Canadian production materializes
for 2001, which EIA anticipates.
In 2001, utility gas-fired electricity
demand is expected to remain about flat, while industrial gasfired electricity
generation growth continues at 5.1 percent, down from the 7.4 percent expected
to be realized in 2000, These reduced growth rates next year represent the net
effect of increased growth in gas-fired capacity being offset by the reversal in
prices of natural gas relative to oil and a slowing in the growth rate of
electricity demand.
Gas supplies available to U.S. markets are expected
to expand by 1.3 trillion cubic feet .(Tcf) between 2000 and 2001. Domestic gas
production for 2000 and 2001 is expected to increase as production begins to
respond to the high rates of drilling experienced over the past year, during
which the number of rigs drilling gas wells have hit record levels (running in
excess of 800 rigs since the end of August 2000, versus a low of 362 in the
third week of April 1999). Annual production is projected to rise by 0.7 percent
in 2000 but by a significantly higher 3.9 percent rate in 2001. Net imports of
natural gas are projected to rise by about 16 percent in 2001, from 3.5 to 4.0
Tcf.
For the entire year 2000, the average wellhead price for natural
gas is projected to average $3.60 per thousand cubic feet, an
increase of 73 percent from the previous year. Higher end-use prices will result
from higher projected wellhead prices. Given the EIA base case projections,
residential prices for natural gas this winter would be about 40 percent higher
than last year during that period. Expected average winter residential prices
averaging about $9.21 per thousand cubic feet, combined with
temperature-driven higher consumption rates, would result in an increase in
gas-heated household heating bills for the typical consumer of around 50 percent
this winter (Figure 4).
Prices in the spring of next year should descend
from their winter highs by about $1 per thousand cubic feet as
the weather-related demand recedes. EIA expects a continued price decline
through the summer. Nevertheless, for the year 2001, assuming continued normal
weather and slightly higher world oil prices, EIA does not expect gas wellhead
prices to drop below $4 per thousand cubic feet.
Increases in production and imports of natural gas needed to keep pace
with the rapidly growing demand for natural gas will result, at least in the
short-term, in more expensive supplies for gas because of rising production
costs and capacity constraints on the pipelines.
The current short-term
supply difficulties are expected to be resolved over the longer term, moving the
market back toward an improved demand and supply balance, yielding wellhead
prices closer to long-term historical trends. In EIA's Annual Energy Outlook
(AEO2001) reference case, average natural gas wellhead prices are projected to
return to the historical trend by 2004 and gradually increase thereafter, driven
by natural gas demand growth, particularly in electric generation, and the
natural progression of the discovery process from larger and more profitable
fields to smaller, more costly ones. However, available natural gas resources in
the United States combined with supplies from foreign sources are believed to be
adequate to meet demand increases expected through 2020. In addition, continued
improvements in exploration and production technologies to aid in the discovery
and development in resources-particularly offshore deepwater and onshore
unconventional gas (tight sands, coalbed methane, and gas
shales) fields-are expected to help keep wellhead prices from
rising rapidly. Wellhead prices for natural
gas in the lower 48 States (in 1999 dollars) are projected to
reach $3.13 per thousand cubic feet in 2020 (1999 dollars) or
$5.03 in nominal dollars.
Domestic consumption is
expected to increase at a faster rate than domestic production over the 20-year
forecast period, with' imports making up the difference. Natural gas consumption
is projected to increase from 21.4 trillion cubic feet in 1999 to almost 35
trillion cubic feet by 2020 (a 62 percent increase) and production is projected
to increase from 18.8 trillion cubic feet in 1999 to 29.1 trillion cubic feet in
2020 (an increase of 55 percent). Natural gas imports, particularly from Canada,
have been rising significantly in recent years, and in percentage terms they are
expected to outpace domestic production over the forecast period. Net natural
gas imports are projected to grow from 3.4 trillion cubic feet in 1999 to 5.8
trillion cubic feet by 2020, an increase of more than 70 percent. Imports from
Canada are projected to remain competitive with U.S. domestic supplies in the
outlook because most Canadian gas producing regions are less mature than those
in the United States, so they benefit from a better potential for additional
low-cost production. Net imports from Canada increase from 3.3 trillion cubic
feet in 1999 to 5.5 trillion cubic feet in 2020 at an average annual rate of 2.4
percent.
Expected Alaskan natural gas production in the EIA long-term
outlook does not include gas from the North Slope, which primarily is being
reinjected to support oil production. Alaskan gas is not expected to be
transported to the lower 48 States because the projected prices in the mid- to
long-term forecast period are not believed to be high enough to support the
required transport system. A sustained U.S./Canada border price of about
$4 per thousand cubic feet in 1999 dollars is assumed to be
necessary to bring natural gas from the North Slope to the lower 48 States.
Production from the North Slope could be substantial and, if transported by
pipeline to the lower 48 States, would most likely displace future expected
Canadian imports.
Resources in restricted areas (where drilling is
presently constrained or prohibited) also are not included in the natural gas
resource base underlying the AEO2001 projections. An estimated 551 trillion
cubic feet of the remaining untapped natural gas resource base in the United
States underlies Federally-owned lands and approximately 215 trillion cubic feet
of that gas is estimated to be unavailable for development due to moratoria
and/or restrictions. The Rocky Mountain region has significant resources from
unconventional sources that are currently restricted. An estimated 45 percent of
the technically recoverable unconventional gas resource base in the Rocky
Mountain region, or roughly 108 trillion cubic feet, is off limits due to
environmental and access constraints. Increased access to these areas could
provide new fields to replace older fields and serve to mitigate future natural
price increases. However, the importance of these resources should not be
overstated, as many of these technically recoverable resources are expected to
be quite costly to develop.
Conclusion
Natural gas spot prices
have been sustained at extraordinarily high levels in November after a taste of
winter weather arrived in major heating demand areas, and they have surged to
even higher levels in December. Several factors have combined to push spot
prices up since early this year, including:
-- increased natural gas
demand driven by new electric generation capacity and the expanding economy;
-- relatively flat domestic gas production for the past several years;
-- expectations for normal winter weather that would be colder than in
recent years, resulting in greater winter demand for heating;
-- below
normal gas storage levels; and
-- tight supply conditions in alternative
fuel markets (e.g., distillate fuel oil).
END
LOAD-DATE: December 16, 2000 
