Fourth Power Plan
Chapter 4: The Existing Northwest Power System
The makeup of the Northwest's electric power system continues to
evolve in response to a variety of forces and trends. The existing system
and its capability are described in detail in Appendix A. Figure 4-1 shows
the composition of generating resources in the region. Generating
resources in the Northwest amount to more than 17,000 average megawatts.
The majority of regional generation, about 66 percent, comes from the
hydroelectric system. Coal resources are the next largest component,
representing 18 percent of all generating resources, followed by natural
gas, nuclear and biomass resources.
4-A. Resources Added Since 1991
Beginning in the late 1980s, increased economic activity and
accompanying electrical load growth initiated a period of active resource
acquisition in the Northwest. For most of this period, utilities relied on
competitive bidding, conservation activities and the development of
utility-owned projects for meeting growing resource needs. Competitive
bidding appeared well-suited both to secure low-cost generating resources
and to account for environmental externalities, resource diversity
objectives and other non-market societal objectives.
Some conservation also was acquired through competitive bidding, but
utility programs, building-and appliance-efficiency standards, market
transformation initiatives and other efforts were generally more effective
for securing conservation. Since 1980, the Northwest has secured more than
1,200 megawatts of electricity savings. About 520 megawatts of that total
have been saved since 1991.
Figure 4-1. Generating Resources of the Northwest Power System (Firm
Energy Basis)
[graphic doesn't display correctly]
Conservation and generating projects totaling about 2,470 average
megawatts of energy were secured during the 1991 through 1995 period
(Figure 4-2). Declining natural gas price forecasts, improving combustion
turbine technology, declining capital costs, and relative ease and speed
of construction continued to improve the attractiveness of gas-fired
combined-cycle power plants. Natural gas-fired projects providing about
1,400 average megawatts of energy were acquired during this period,
comprising about 57 percent of total acquisitions on an energy basis.
About 520 average megawatts of conservation were acquired since 1991,
representing about 21 percent of total new acquisitions. Renewable energy
projects, primarily hydroelectric and projects using biomass residue
fuels, provided about 420 megawatts of resources that were committed to
during this period. The balance of acquisitions include upgrades to
existing thermal projects and projects using coal or petroleum coke.
Natural gas resources have increased the most in the last five years,
from 3 percent in 1991 to 7 percent in 1996, primarily due to the fact
that natural gas is among the least expensive and most flexible new
generating options available. Although concerns have been expressed about
what some have termed an "over-reliance" on gas-fired new
generating resources, overall resource diversity is probably greater than
it ever has been because of the new gas-fired resources. Furthermore,
because of the increasing importance of the Western wholesale electricity
market, resource diversity in the Pacific Northwest will probably be of
lesser significance than West Coast resource diversity. The Northwest and
California systems combined provide significant resource diversity.
Figure 4-2. Resource Acquisitions: 1991 through 1995 (average
megawatts)
[Projects completed during the 1991 through 1995 period, or under
construction at the close of 1995. Planned projects for which construction
has not commenced are not included in Figure 4-2. Graphic doesn't display
correctly.]
Although regional electrical load growth continues, there have been no
solicitations for new power plants within the past year. Declining natural
gas prices and an increasingly active wholesale market have made the
surplus of capacity on the interconnected Western system less expensive,
more evident and more accessible. Utilities and large consumers are
purchasing inexpensive wholesale power produced by existing plants on the
Western system rather than building or purchasing the output of new power
generating facilities. Low-price wholesale power has even led to
suspension of construction for several projects, most notably the
248-megawatt Tenaska Washington II gas-fired combined-cycle plant.
Conservation activities, too, have declined. Conservation acquisitions
in 1996 are expected to amount to only 70 average megawatts, about 60
percent of the region's 1995 acquisitions.
The Northwest power system has also lost resources over the last five
years, including:
- Reduction of the operational flexibility and generating capability
of the Columbia River Basin hydroelectric system as a result of
changes in the pattern of reservoir storage and water releases
intended to improve the survival of anadromous and resident fish. This
has resulted in an estimated reduction of 850 average megawatts of
firm energy capability;
- Closure of the Trojan nuclear power plant in the face of a
requirement for significant additional capital investment to remedy
problems encountered at the plant. This has meant the loss of 725
average megawatts of energy.
The changes in Northwest electricity resources since 1991 have probably
resulted in a net increase in the emissions of carbon dioxide, a gas
implicated in global warming. Factors that would increase carbon dioxide
production include the closing of the Trojan nuclear power plant and the
loss of hydroelectric generation due to spilling water to enhance fish
passage.
Fish mitigation activities that shift power production seasonally or
from firm to nonfirm periods do not necessarily increase carbon dioxide
production. Power produced during fish flow periods, for example, may
displace carbon-dioxide emitting fossil-fuel plants in the Southwest. But,
foregone hydropower during other seasons and the lost power from Trojan
will be replaced by higher carbon-dioxide emitting generation, except to
the extent the losses are replaced by conservation, hydroelectricity or
biomass generation. The net effect of emissions from new gas-fired
combustion turbines is difficult to ascertain because the turbines may
displace the operation of power plants that emit even more carbons, such
as coal-fired plants.
The remainder of this chapter describes the major electricity resources
in use in the Northwest.
4-B. The Hydroelectric System
The Northwest's hydroelectric system, although reduced in its
capability and flexibility, is still an adaptable and low-cost resource.
It produces more than two-thirds of the electricity in the region. In the
near term, the region's advantageous position with respect to gas
markets and the relative flexibility of gas-fired generation are important
complements to the hydroelectric system. The flexibility of the
hydroelectric system may also prove valuable when intermittent renewable
resources are integrated into the power system. The challenge is to
maintain and enhance the value of the hydroelectric system, while at the
same time providing for non-power uses such as flood control, irrigation,
recreation, transportation and fish and wildlife.
The hydroelectric system differs from thermal
generating resources in that its instantaneous generating capacity far
exceeds the amount of energy it can produce over the course of a year.
This is because reservoirs cannot store enough water to keep turbines
running at full capacity all year. Consequently, Northwest utilities have
traditionally focused on meeting annual average energy needs as
opposed to daily peak electricity demands.
The Columbia River hydroelectric system's sustained peaking capacity
[Sustained peaking capacity is the power system's ability to meet
electricity demands during the peak hours of the day for a sustained
period of time, usually the five working days of the week. The peak demand
period per workday typically lasts 10 hours.] is about 25,000 megawatts,
[1995 Pacific Northwest Loads and Resources Study, Bonneville
Power Administration " The White Book ," December 1995.] but
limitations on the storage capacity of the system result in significant
variations in the system's energy output from year to year, depending on
annual rainfall and snowpack accumulation. In the driest years, the
hydroelectric system produces only about 11,700 average megawatts of
energy. Utility planners can expect at least that much energy in any given
year, so it is considered guaranteed or "firm" energy. In the
wettest years, the hydroelectric system produces about 20,000 average
megawatts. In average water years, the dams generate approximately 16,500
average megawatts.
Generation in excess of what can be guaranteed is commonly referred to
as "nonfirm" or "secondary" energy. Nonfirm energy is
sold on the spot market or under short-term contracts at lower prices than
is obtained for firm energy. It is used to serve interruptible loads or to
displace more expensive resources both in and out of the region.
Accommodating Fish and Power
The Columbia River historically supported one of the world's largest
salmon populations. Over the years, however, the number of salmon and
steelhead in the river has decreased dramatically. Several Columbia River
Basin salmon species are now extinct. Others have declined nearly to the
point of extinction. Hydroelectric development has been an important
factor in that decline. The natural flow of the Columbia River peaks in
spring and early summer, when the snowpacks melt. Energy production from
the hydroelectric system depends on this flow of water. If reservoirs were
not available to store water for later use, the energy derived from the
hydroelectric system would rise and fall with the natural flow of the
river. This would not be a very reliable or valuable source of electricity
because peak river flows (in spring) do not coincide with peak electricity
demands (in winter). Figure 4-3 illustrates the monthly pattern of river
flows under natural conditions, before hydroelectric development, and
under current conditions, which include changes in dam operations to
protect salmon and other fish and wildlife. [Natural flow data was
obtained from the Bonneville Power Administration's document
"Seasonal Volumes and Statistics, Columbia River Basin
1928-1989," July 1993.]
By building dams to hold back some of the spring runoff for use the
following winter, the output from the hydroelectric system can better meet
the seasonal fluctuations in electricity use in the Northwest. Although
this shifting of river flows makes the hydroelectric system a more
valuable source of power, it also creates a more hostile environment for
migrating juvenile salmon. Inundation of spawning and rearing habitat and
hazards created at the dams themselves have also affected salmon
production and survival.
But the dams were not built for electricity alone. They also help
control flooding, provide water for irrigation and industrial use, improve
navigation on the river and expand recreational opportunities in the
Pacific Northwest. All these uses can have adverse impacts on both fish
and power. In addition, salmon populations have been affected by
commercial and sport fishing, ocean conditions, hatcheries and
hatchery-bred fish, habitat destruction caused by logging, grazing and
other developments, and a host of other factors that are not well
understood. The Council's Columbia River Basin Fish and Wildlife Program
addresses all of these impacts.
Because the hydroelectric system is one of the important factors
affecting fish and wildlife survival, its operation has been modified
since the early 1980s in an attempt to create a better balance between the
generation of electricity and protection for fish and wildlife. As at-risk
fish stocks have weakened, further constraints on the operation of the
hydroelectric system have been implemented. The effect of most of these
changes is to shift the release of water back toward the spring and early
summer to more closely approximate the natural flows of the river. By
releasing less water from headwater storage projects during the winter
months, more is available for later release during the spring smolt
migration period.
Figure 4-3. Average River Flows at The Dalles Dam
However, this action reduces the amount of energy available from the
hydroelectric system during the winter months and forces the production of
energy during a time when it is not in great demand. This effectively
reduces the firm energy generating capability of the hydroelectric system.
During dry years, lost winter energy must be replaced if all firm energy
demands are to be served.
The Council's 1982 Fish and Wildlife Program included measures that
reduced the firm energy generating capability of the hydroelectric system
by an estimated 300 average megawatts. In addition, water laden with
juvenile salmon was spilled over dams to divert the young fish from the
turbines. The spills further reduced the firm energy generating capability
of the system by about 50 average megawatts. This was the river operation
that was used as the basis for resource analysis in the 1991 Power Plan.
Since 1991, more fish and wildlife protection measures have been
implemented. Changes in river operations since 1991, including those
enacted by the National Marine Fisheries Service to protect endangered
Snake River salmon, have reduced the firm generating capability by an
additional estimated 850 average megawatts (about a 7-percent loss).
Consequently, the total reduction in firm energy generating capability of
the hydroelectric system since the Council adopted its first fish and
wildlife program amounts to approximately 1,200 average megawatts,
representing a 10-percent loss. Figure 4-4 illustrates the average monthly
change in hydroelectric generation due to fish and wildlife measures.
Under current operations, the hydroelectric system produces an average
of nearly 10,000 megawatt-months less energy in the fall and winter
compared to 1991 operations. About 4,000 megawatt-months are shifted into
spring and summer months, and nearly 6,000 megawatt-months of energy are
spilled or lost due to efficiency losses. [Efficiency losses occur when
power is generated at lower reservoir elevations. Reservoirs are operated
at lower elevations in order to increase the velocity of the river.]
Figure 4-4. Changes in Hydroelectric Generation by Month Since 1991
In some fall or winter months, it can be necessary to purchase
electricity from outside the region to provide adequate water for spring
flow augmentation and serve firm Northwest electricity demands. The total
cost to the power system of operations to protect fish and wildlife are
calculated by combining power purchase costs, lost revenues due to
reductions in firm power production and changes in the amount and value of
nonfirm power.
A more constrained operation of the mainstem Columbia and Snake river
reservoirs also results in capacity losses. For example, prior to the
1980s, the elevation of the lower Snake run-of-river projects varied five
feet or more on a daily basis. These dams are drafted during the
peak-demand hours of the day and refilled during the light-load hours of
the night. If these reservoirs are now constrained to fluctuate only about
a foot to benefit various fish populations, they lose much of their
ability to meet daily peak-demand swings. This limited operation may also
result in the loss of nonfirm energy. If reservoirs are not allowed to
fill completely during the lightly loaded hours of the night due to
elevation limitations, some water may have to be spilled, resulting in
lost generation.
4-C. Other Generating Resources
In addition to the hydroelectric system, other sources of bulk electric
power in the Northwest include large coal-fired power plants, the
Washington Public Power Supply System's WNP-2, and simple-cycle and
combined-cycle natural gas combustion turbines. Electricity is also
produced by industrial cogeneration plants, small biomass plants and
numerous small hydroelectric projects. A table and map of individual
Northwest power generating projects is provided in Appendix
A.
Coal-fired Power Plants
Following the development of the Columbia River hydroelectric system,
coal and nuclear power were viewed as the most economical new sources of
electricity. Abundant supplies of low-cost, low-sulfur coal are available
from the Rocky Mountain states and western Canada fields, and more limited
supplies of lesser quality from Washington fields. Accordingly, between
1968 and 1986, 14 coal-fired power units at six sites were brought into
service by Northwest utilities. These large plants can serve about 6,660
megawatts of winter peak load, of which about 3,990 megawatts are
currently dedicated to Northwest loads. These plants can produce about
5,520 average megawatts of energy, of which 3,395 average megawatts are
dedicated to Northwest loads. Because the minemouth units have low
operating costs, they are operated under nearly all conditions. Units that
use coal supplied by rail are more expensive to operate and currently
compete with natural gas combined-cycle power plants and off-peak power
from Southwestern plants.
Nuclear Power Plants
Concurrent with the development of the region's large coal-fired
power plants, regional utilities initiated construction of 10 nuclear
plants. Only two, Trojan, in Oregon, and WNP-2, in Washington, were
eventually completed. [Trojan was completed in 1976 and WNP-2 in 1984. The
Hanford Generating Project operated on steam from the N-reactor, a Hanford
Production Reactor, until 1988, when it was shut down upon termination of
plutonium production operations at Hanford. ] Two partially completed
plants, WNP-1 and WNP-3, were preserved for many years for completion, if
needed. With the continuing decline in gas prices, they have been
terminated. Nuclear plant operating costs have generally been higher and
plant availabilities lower than anticipated when these plants were
ordered.
Trojan was permanently shut down in 1993, when it was concluded that
the cost of a needed steam generator replacement would result in
production costs barely competitive with the cost of power from new
resources. WNP-2, upgraded from its original peak capacity, can now serve
about 1,170 megawatts of winter peak load. The plant produced 822 average
megawatts of energy in Bonneville's 1995 Fiscal Year and was available
to produce 890 average megawatts. WNP-2 currently has operating costs that
are above market prices. The Washington Public Power Supply System, owner
and operator of the plant, has established aggressive cost reduction
targets. However, continued low market prices pose a risk for the
continued operation of WNP-2.
Natural Gas-Fired Combined-Cycle Power Plants
The abundant gas resources of Western Canada and the Rocky Mountain
states are accessible to the Northwest by two interstate pipelines.
Declining natural gas prices and improving combustion turbine technology
have made gas-fired combined-cycle power plants the least-costly new
resource for bulk power production. Most of these projects consist of one
or two combined-cycle combustion turbine units, and many serve modest
cogeneration loads.
Six gas-fired combined-cycle projects were in service in the Northwest
by the end of 1995. Two additional projects are under construction.
[Combined-cycle power plants in operation in the Northwest by the end of
1995 include Beaver, March Point, Sumas Energy, Tenaska Washington I,
Encogen and Coyote Springs 1. Hermiston Generating Project is scheduled
for service in 1996. Construction of the River Road project commenced in
February 1996. Additional information regarding these projects is supplied
in Appendix A.] Projects in service or under construction at the end of
1995 will serve about 1,900 megawatts of winter peak load and can produce
about 1,460 average megawatts of energy. Some of these projects are owned
by independent developers and others by utilities.
Additional projects totaling about 930 megawatts of capacity are
currently permitted for construction. One of these projects is partially
constructed, but further construction has been suspended. Construction on
the other projects is not scheduled. License applications for additional
projects of about 2,700 megawatts total capacity are being considered by
licensing agencies. Developers have indicated that they will apply for
licenses for several additional projects.
Three of the projects for which licenses are being sought are part of
Bonneville's Resource Contingency Program. This program responded to the
1991 Power plan's call for obtaining "options" on the
development of 2,450 average megawatts of new generating resources. By
taking projects through the siting and licensing process, but delaying the
actual construction until the market for the power is clear, it is
possible to reduce the risk of investing in generation in advance of need.
The options concept was devised primarily for long lead time resources and
a regulated generation market. The value of options with resources that
have much shorter lead times and a competitive generation market may not
be as great as it was under those earlier conditions. On the other hand,
siting and licensing some projects in advance of market demand may
continue to provide some benefits for both prospective developers and the
public.
Industrial Cogeneration
Industrial cogeneration in the forest products industry has long been a
component of Northwest electric power generation. These plants include
chemical recovery boilers in the pulp and paper industry, and power
boilers fired by wood residues, fuel oil and gas in both the pulp and
paper and lumber and wood products sectors. More recently, gas-fired
combustion turbines have been installed as industrial cogeneration units.
Because of the many mill closures of recent years, and because many
industrial cogeneration plants do not sell power offsite or generate power
only when fuel costs are favorable, a precise inventory of operating
industrial cogeneration plants is difficult to obtain. There are estimated
to be approximately 70 plants in operation. These total in excess of 770
megawatts of capacity and are capable of producing in excess of 600
average megawatts of energy. Most industrial cogeneration plants in the
Northwest are owned by the host facility, but recently several have been
developed by utilities.
Other Renewable Resource Projects
Biomass: Many of the cogeneration plants described above
use wood residues, spent pulping liquor and other biomass fuels. The
number and diversity of small biomass plants has expanded in recent years
and now includes plants using pulping liquor, wood residues, landfill gas,
municipal solid waste and wastewater treatment plant gas.
Hydroelectric: Many hydroelectric projects have been
developed on coastal streams, tributaries of Puget Sound and tributaries
of the Columbia River. Most suitable large-scale sites have been
developed, and recent development has focused on headwater diversion
projects, projects on irrigation systems and upgrades of older
hydroelectric projects.
Geothermal: There has been no commercial development of
the potentially abundant geothermal resources of the Northwest for
electric power generation. [Small demonstration projects operated briefly
at Raft River, Idaho, and Lakeview, Oregon. Numerous direct applications
of geothermal energy for space or process heating are found in the
region.] Pilot projects are being developed at Newberry Volcano, in
Oregon, and Glass Mountain, in Northern California, to explore the cost
and feasibility of using these resources for power generation. Though it
is unlikely that these projects will be competitive with the near-term
wholesale power market, geothermal may prove to be an important source of
renewable power in the long term.
Wind: Four commercial-scale wind projects are being
developed to explore the cost and feasibility of using this resource for
power generation in the Northwest. Though more expensive than electricity
from new gas-fired combined-cycle power plants, wind power is the
least-costly renewable alternative for producing large quantities of
energy.
Solar: Solar photovoltaic power is often cost-effective
for small, remote loads. Applications of this type continue to increase.
Other Projects
Several gas and oil-fired combustion turbines serve peak loads and may
generate bulk power when gas prices are low. Other gas or oil-fired small
combustion turbines, older steam plants and engine-generator sets provide
emergency electricity service.
4-D. Conservation
Conservation is the first-priority electric power resource in the
Northwest Power Act, where it is defined as "any reduction in
electric power consumption as a result of increases in the efficiency of
energy use, production, or distribution." As a result of
utility-supported conservation efforts undertaken since the passage of the
Act in 1980, the cumulative conservation savings enjoyed by the region's
electricity consumers in 1996 amounts to about 1,000 average megawatts.
This level of annual savings is equivalent to the power output of five
average-sized gas-fired combustion turbines. Utility-funded energy
conserved since the passage of the Act amounts to nearly 60 billion
kilowatt-hours, with a retail value to consumers of $2.5 billion.
An additional 200 average megawatts are estimated to have been saved
through programs, codes and standards at local, state and national levels.
Figure 4-5 depicts the annual utility-sponsored first-year conservation
savings by sector from 1978 to 1994. This information comes from Nutrak,
the Council's Northwest Utility Conservation Tracking System.
To accomplish these savings, the region has weatherized more than half
a million homes or apartments, replaced thousands of showerheads with
efficient models, installed efficiency measures for a quarter-million
irrigated farm acres, produced several hundred thousand new
high-efficiency site-built homes and 65,000 high-efficiency factory-built
homes, upgraded the residential and commercial energy codes across the
region, made conservation modifications to the aluminum refining plants,
and developed a thriving energy-efficiency industry. These accomplishments
have required perseverance, commitment, fresh thinking and hard work. They
also required an estimated outlay of more than $2 billion. The Council has
estimated that these savings were acquired at an average real levelized
utility cost of about 2 to 2.5 cents per kilowatt-hour, about half the
cost of the next most costly resource available at the time.
The pattern of conservation acquisition over time demonstrates some of
the flexibility of the resource. After a period of surplus generating
capacity in the mid-1980s, the 1991 Power Plan forecast a need for new
resources and called for the region to acquire at least 1,500 average
megawatts of energy savings by the end of the decade.
Figure 4-5. Regional Summary of First Year Conservation Savings by
Sector, 1978-1994
This meant a shift in emphasis from conservation "capability
building" to conservation resource acquisition. [Conservation
capability building in the mid to late 1980s was directed at maintaining a
viable conservation infrastructure and carrying out experimentation to
identify viable strategies for conservation acquisition. The major
exception to this was the Conservation/Modernization project carried out
with the aluminum companies in the late 1980s. The purpose of this project
was as much or more to maintain the viability of the aluminum industry in
this region in a period of depressed world aluminum prices as it was to
acquire conservation savings.] From 1991 through 1994, the region's
electric utilities acquired about 400 average megawatts of energy savings,
exceeding the expectations of the 1991 plan. Since 1980, the region's
public utilities, including Bonneville, have delivered about 56 percent of
the total savings, and the investor-owned utilities delivered about 44
percent. The figure below charts the public/investor-owned utility split.
The ups and downs of annual conservation efforts shown in Figure 4-6
are due to the fact that the region was in need of electricity in the late
1970s and early 1980s, and conservation efforts were accelerated. In the
early to middle 1980s, the region was in a period of surplus capacity, and
conservation efforts were slowed. In the early 1990s, there was again a
need for resources, and the region responded once again by increasing
conservation efforts. In the mid-1990s, conservation is again being
slowed, as utilities see an uncertain future, and inexpensive energy is
abundant in the West Coast market.
Fuel Choice
The issue of fuel choice is related to electricity efficiency. The
specific issue raised for the Council has been direct use of natural gas
in homes and businesses as an alternative to the use of electricity
generated by burning natural gas. In 1994, the Council studied the direct
use of natural gas in homes. The study found that, although in many cases
direct use of natural gas is more energy efficient than electricity
use, the most economically efficient resource is very
application-specific.
In general, conversion to natural gas is most cost-effective in homes
that use a lot of energy. Thus, large homes, poorly insulated homes, or
homes in colder climates tend to be the most promising conversion
candidates. The Council estimated there might be 730 average megawatts of
cost-effective residential fuel conversion savings available in the
region. This was primarily from conversions of electric water heaters or
electric forced-air furnaces to natural gas. Just as lower avoided
electricity costs have reduced the potential amount of cost-effective
electricity conservation, so would it reduce the amount of cost-effective
fuel conversions.
The Council adopted a policy of considering direct use of natural gas
as an alternative to conservation or electricity generation. The policy
further stated that market-based approaches were the preferred method of
pursuing cost-effective direct gas use. The primary methods of
implementing this policy were thought to be encouraging the efficient
pricing of electricity and ensuring that conservation incentive payments
were not distorting market decisions away from direct use of natural gas
where that is the more cost-effective option.
Both of these market-distorting problems are being substantially solved
by the restructuring of the electricity industry. Low-priced natural gas
generation alternatives have reduced the marginal cost of electricity to
near the average cost-based electricity price. As a result, much more
accurate price signals are evolving in the electricity market. Electricity
market restructuring may also substantially eliminate the ability of
electric utilities to make incentive payments for increased electric
efficiency. Even before these changes, the market penetration of natural
gas had been quite strong in areas where gas is available. With the
restructuring of the electricity industry, there is no longer a convincing
need to intervene in the fuel-choice market, nor is there really any
effective way to do so.
Figure 4-6. First Year Conservation Savings by Utility Type
(Public/Investor-Owned)
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