Electricity Market Module
The NEMS Electricity Market Module (EMM) represents the capacity planning,
dispatching, and pricing of electricity. It is composed of four submoduleselectricity
capacity planning, electricity fuel dispatching, load and demand electricity,
and electricity finance and pricing. It includes nonutility capacity and
generation, and electricity transmission and trade. A detailed description
of the EMM is provided in the EIA publication, Electricity Market Module
of the National Energy Modeling System 2008, DOE/EIA-M068(2008).
Based on fuel prices and electricity demands provided by the other modules
of the NEMS, the EMM determines the most economical way to supply electricity,
within environmental and operational constraints. There are assumptions
about the operations of the electricity sector and the costs of various
options in each of the EMM submodules. This section describes the model
parameters and assumptions used in EMM. It includes a discussion of legislation
and regulations that are incorporated in EMM as well as information about
the climate change action plan. The various electricity and technology
cases are also described.
EMM Regions
The supply regions used in EMM are based on the North American Electric
Reliability Council regions and subregions shown in Figure 6 (region definitions
as of 2004).
Model Parameters and Assumptions
Generating Capacity Types
The capacity types represented in the EMM are shown in Table 37.
New Generating Plant Characteristics
The cost and performance characteristics of new generating technologies
are inputs to the electricity capacity planning submodule (Table 38). These
characteristics are used in combination with fuel prices from the NEMS
fuel supply modules and foresight on fuel prices, to compare options when
new capacity is needed. Heat rates for fossil-fueled technologies are assumed
to decline linearly through 2025.
The overnight costs shown in Table 38 are the cost estimates to build a
plant in a typical region of the country. Differences in plant costs due
to regional distinctions are calculated by applying regional multipliers
that represent variations in the cost of labor. The base overnight cost
is multiplied by a project contingency factor and a technological optimism
factor (described later in this chapter), resulting in the total construction
cost for the first-of-a-kind unit used for the capacity choice decision.
Technological Optimism and Learning
Overnight costs for each technology are calculated as a function of regional
construction parameters, project contingency, and technological optimism
and learning factors.
The technological optimism factor represents the demonstrated tendency
to underestimate actual costs for a first-of-a-kind, unproven technology.
As experience is gained (after building 4 units) the technological optimism
factor is gradually reduced to 1.0.
The learning function in NEMS is determined at a component level. Each
new technology is broken into its major components, and each component
is identified as revolutionary, evolutionary or mature. Different learning
rates are assumed for each component, based on the level of experience
with the design component (Table 39). Where technologies use similar components,
these components learn at the same rate as these units are built. For
example, it is assumed that the underlying turbine generator for a combustion
turbine, combined cycle and integrated coal-gasification combined cycle
unit is basically the same. Therefore construction of any of these technologies
would contribute to learning reductions for the turbine component.
The learning function has the nonlinear form:
OC(C) = a*C-b,
where C is the cumulative capacity for the technology component.
The progress ratio (pr) is defined by speed of learning (e.g., how much
costs decline for every doubling of capacity). The reduction in capital
cost for every doubling of cumulative capacity (f) is an exogenous parameter
input for each component (Table 39). Consequently, the progress ratio
and f are related by:
pr = 2-b = (1 - f)
The parameter b is calculated by (b =-(ln(1-f)/ln(2)). The parameter
a can be found from initial conditions. That is,
a =OC(C0)/C0-b
where C0 is the cumulative initial capacity. Thus, once the rates of learning
(f) and the cumulative capacity (C0) are known for each interval, the corresponding
parameters (a and b) of the nonlinear function are known. Three learning
steps were developed, to reflect different stages of learning as a new
design is introduced to the market. New designs with a significant amount
of untested technology will see high rates of learning initially, while
more conventional designs will not have as much learning potential. All
design components receive a minimal amount of learning, even if new capacity
additions are not projected. This represents cost reductions due to future
international development or increased research and development.
Once the learning rate by component is calculated, a weighted average learning
factor is calculated for each technology. The weights are based on the
share of the initial cost estimate that is attributable to each component
(Table 40). For technologies that do not share components, this weighted
average learning rate is calculated exogenously, and input as a single
component. These technologies may still have a mix of revolutionary components
and more mature components, but it is not necessary to include this detail
in the model unless capacity from multiple technologies would contribute
to the component learning.
Table 41 shows the capacity credit toward component learning for the various
technologies. It was assumed that for all combined-cycle technologies,
the turbine unit contributed two-thirds of the capacity, and the steam
unit one-third. Therefore, building one gigawatt of gas combined cycle
would contribute 0.67 gigawatts toward turbine learning, and 0.33 gigawatts
toward steam learning. All non-capacity components, such as the balance
of plant category, contribute 100 percent toward the component learning.
International Learning. In AEO2008, capital costs for all new electricity
generating technologies (fossil, nuclear, and renewable) decrease in response
to foreign and domestic experience. Foreign units of new technologies
are assumed to contribute to reductions in capital costs for units that
are installed in the United States to the extent that (1) the technology
characteristics are similar to those used in U.S. markets, (2) the design
and construction firms and key personnel compete in the U.S. market, (3)
the owning and operating firm competes actively in the U.S. market, and
(4) there exists relatively complete information about the status of the
associated facility. If the new foreign units do not satisfy one or more
of these requirements, they are given a reduced weight or not included
in the domestic learning effects calculation.
AEO2008 includes 5,000 megawatts of advanced coal gasification combined-cycle
capacity, 5,244 megawatts of advanced combined-cycle natural gas capacity,
11 megawatts of biomass capacity and 47 megawatts each of traditional
wind and offshore wind capacity to be built outside the United States from
2000 through 2003. The learning function also includes 7,200 megawatts
of advanced nuclear capacity, representing two completed units and four
additional units under construction in Asia.
Distributed Generation
Distributed generation is modeled in the end-use sectors as well as in
the EMM, which is described in the appropriate chapters. This section describes
the representation of distributed generation in the EMM only. Two generic
distributed technologies are modeled. The first technology represents peaking
capacity (capacity that has relatively high operating costs and is operated
when demand levels are at their highest). The second generic technology
for distributed generation represents base load capacity (capacity that
is operated on a continuous basis under a variety of demand levels). See
Table 38 for costs and performance assumptions. It is assumed that these
plants reduce the costs of transmission upgrades that would otherwise be
needed.
Representation of Electricity Demand
The annual electricity demand projections from the NEMS demand modules
are converted into load duration curves for each of the EMM regions (based
on North American Electric Reliability Council regions and subregions)
using historical hourly load data. The load duration curve in the EMM is
made up of 9 time slices. First, the load data is split into three seasons,
(winter - December through March, summer - June through September, and
fall/spring). Within each season the load data is sorted from high to
low, and three load segments are created - a peak segment representing
the top 1 percent of the load, and then two off-peak segments representing
the next 33 percent and 66 percent, respectively. The seasons were defined
to account for seasonal variation in supply availability.
Reserve marginsthe percentage of capacity required in excess of peak demand
needed for unforeseeable outagesare determined within the model through
an interative approach comparing the marginal cost of capacity and the
cost of unserved energy. The target reserve margin is adjusted each model
cycle until the two costs converge. The resulting reserve margins from
the AEO2008 reference case range from 10 to 14 percent.
Fossil Fuel-Fired and Nuclear Steam Plant Retirement
Fossil-fired steam plant retirements and nuclear retirements are calculated
endogenously within the model. Plants are assumed to retire when it is
no longer economical to continue running them. Each year, the model determines
whether the market price of electricity is sufficient to support the continued
operation of existing plants. If the expected revenues from these plants
are not sufficient to cover the annual going forward costs, the plant is
assumed to retire if the overall cost of producing electricity can be lowered
by building new replacement capacity. The going-forward costs include
fuel, operations and maintenance costs and annual capital additions, which
are plant specific based on historical data. The average capital additions
for existing plants are $8 per kilowatt (kW) for oil and gas steam plants,
$16 per kW for coal plants and $20 per kW for nuclear plants (in 2006 dollars).
These costs are added to existing plants regardless of their age. Beyond
30 years of age an additional $6 per kW capital charge for fossil plants,
and $30 per kW charge for nuclear plants is included in the retirement
decision to reflect further investment to address impacts of aging. Age
related cost increases are due to capital expenditures for major repairs
or retrofits, decreases in plant performance, and/or increased maintenance
costs to mitigate the effects of aging.
Biomass Co-firing
Coal-fired power plants are allowed to co-fire with biomass fuel if it
is economical. Co-firing requires a capital investment for boiler modifications
and fuel handling. This expenditure ranges from about $115 to $265 per
kilowatt of biomass capacity, depending on the type and size of the boiler.
A coal-fired unit modified to allow co-firing can generate up to 15 percent
of the total output using biomass fuel, assuming sufficient residue supplies
are available. Larger units are required to pay additional transportation
costs as the level of co-firing increases, due to the concentrated use
of the regional supply.
New Nuclear Plant Orders
A new nuclear technology competes with other fossil-fired and renewable
technologies as new generating capacity is needed to meet increasing demand,
or replace retiring capacity, throughout the projection period. The cost
assumptions for new nuclear units are based on an analysis of recent cost
estimates for nuclear designs available in the United States and worldwide.
The capital cost assumptions in the reference case represent the expense
of building a new single unit nuclear plant of approximately 1,000 megawatts
at a new Greenfield site. Since no new nuclear plants have been built
in the US in many years, there is a great deal of uncertainty about the
true costs of a new unit. The estimate used for AEO2008 is an average
of the construction costs incurred in completed advanced reactor builds
in Asia, adjusting for expected learning from other units still under construction.
Nuclear Uprates
The AEO2008 nuclear power projection also assumes capacity increases at
existing units. Nuclear plant operators can increase the rated capacity
at plants through power uprates, which are license amendments that must
be approved by the U.S. Nuclear Regulatory Commission (NRC). Uprates can
vary from small (less than 2 percent) increases in capacity, which require
very little capital investment or plant modifications, to extended uprates
of 15-20 percent, requiring significant modifications. Historically, most
uprates were small, and the AEO projections accounted for them only after
they were implemented and reported, but recent surveys by the NRC and EIA
have indicated that more extended power uprates are expected in the near
future. AEO2008 assumes that all of those uprates approved, pending or
expected by the NRC will be implemented, for a capacity increase of 2.7
gigawatts between 2007 and 2030. Table 42 provides a summary of projected
uprate capacity additions by region. In cases where the NRC did not specifically
identify the unit expected to uprate, EIA assumed the units with the lowest
operating costs would be the next likely candidates for power increases.
Interregional Electricity Trade
Both firm and economy electricity transactions among utilities in different
regions are represented within the EMM. In general, firm power transactions
involve the trading of capacity and energy to help another region satisfy
its reserve margin requirement, while economy transactions involve energy
transactions motivated by the marginal generation costs of different regions.
The flow of power from region to region is constrained by the existing
and planned capacity limits as reported in the National Electric Reliability
Council and Western Electric Coordinating Council Summer and Winter Assessment
of Reliability of Bulk Electricity Supply in North America. Known firm
power contracts are obtained from NERCs Electricity Supply and Demand
Database 2004. They are locked in for the term of the contract. Contracts
that are scheduled to expire by 2013 are assumed not to be renewed. Because
there is no information available about expiration dates for contracts
that go beyond 2013, they are assumed to be phased out by 2022. In addition,
in certain regions where data show an established commitment to build plants
to serve another region, new plants are permitted to be built to serve
the other regions needs. This option is available to compete with other
resource options.
Economy transactions are determined in the dispatching submodule by comparing
the marginal generating costs of adjacent regions in each time slice. If
one region has less expensive generating resources available in a given
time period (adjusting for transmission losses and transmission capacity
limits) than another region, the regions are allowed to exchange power.
International Electricity Trade
Two components of international firm power trade are represented in the
EMMexisting and planned transactions, and unplanned transactions. Existing
and planned transactions are obtained from the North American Electric
Reliability Councils Electricity Supply and Demand Database 2004. Unplanned
firm power trade is represented by competing Canadian supply with U.S.
domestic supply options. Canadian supply is represented via supply curves
using cost data from the Department of Energy report Northern Lights: The
Economic and Practical Potential of Imported Power from Canada, (DOE/PE-0079).
International economy trade is determined endogenously based on surplus
energy expected to be available from Canada by region in each time slice.
Canadian surplus energy is determined using Canadian electricity supply
and demand projections from the MAPLE-C model developed for Natural Resources
Canada.
Electricity Pricing
The reference case assumes a transition to full competitive pricing in
New York, Mid-Atlantic Area Council, and Texas, and a 95 percent transition
to competitive pricing in New England (Vermont being the only fully-regulated
State in that region). California returned to almost fully regulated pricing
in 2002, after beginning a transition to competition in 1998. In addition
electricity prices in the East Central Area Reliability Council, the Mid-American
Interconnected Network, the Southeastern Electric Reliability Council,
the Southwest Power Pool, the Northwest Power Pool, and the Rocky Mountain
Power Area/Arizona are a mix of both competitive and regulated prices.
Since some States in each of these regions have not taken action to deregulate
their pricing of electricity, prices in those States are assumed to continue
to be based on traditional cost-of-service pricing. The price for mixed
regions is a load-weighted average of the competitive price and the regulated
price, with the weight based on the percent of electricity load in the
region that has taken action to deregulate. The reference case assumes
that State-mandated price freezes or reductions during a specified transition
period will occur based on the terms of the legislation. In general, the
transition period is assumed to occur over a ten-year period from the effective
date of restructuring, with a gradual shift to marginal cost pricing. In
regions where none of the states in the region have introduced competitionFlorida
Reliability Coordinating Council and Mid-Continent Area Power Poolelectricity
prices are assumed to remain regulated and the cost-of-service calculation
is used to determine electricity prices.
The price of electricity to the consumer is comprised of the price of generation,
transmission, and distribution including applicable taxes. Transmission
and distribution are considered to remain regulated in the AEO; that is,
the price of transmission and distribution is based on the average cost.
In competitive regions, an algorithm in place allows customers to compete
for better rates among rate classes as long as the overall average cost
is met. The price of electricity in the regulated regions consists of the
average cost of generation, transmission, and distribution for each customer
class. In the competitive regions, the generation component of price is
based on marginal cost, which is defined as the cost of the last (or most
expensive) unit dispatched. The marginal cost includes fuel, operation
and maintenance, taxes, and a reliability price adjustment, which represents
the value of capacity in periods of high demand. The price of electricity
in the regions with a competitive generation market consists of the marginal
cost of generation summed with the average costs of transmission and distribution.
In recent years, the move towards competition in the electricity business
has led utilities to make efforts to reduce costs to improve their market
position. These cost reduction efforts are reflected in utility operating
data reported to the Federal Energy Regulatory Commission (FERC) and these
trends have been incorporated in the AEO2008. Both General and Administrative
(G&A) expenses and Operations and Maintenance (O&M) expenses have shown
declines in recent years. The O&M declines show variation based on the
plant type. A regression analysis of recent data was done to determine
the trend, and the resulting function was used to project declines throughout
the projection. The analysis of G&A costs used data from 1992 through 2001,
which had a 15 percent overall decline in G&A costs, and a 1.8 percent
average annual decline rate. The AEO2008 projection assumes a further decline
of 18 percent by 2025 based on the results of the regression analysis.
The O&M cost data was available from 1990 through 2001, and showed average
annual declines of 2.1 percent for all steam units, 1.8 percent for combined
cycle and 1.5 percent for nuclear. The AEO2008 assumes further declines
in O&M expenses for these plant types, for a total decline through 2025
of 17 percent for combined cycle, 15 percent for steam and 8 percent for
nuclear.
There have been ongoing changes to pricing structures for ratepayers in
competitive States since the inception of retail competition. The AEO
has incorporated these changes as they have been incorporated into utility
tariffs. These have included transition period rate reductions and freezes
instituted by various States, and surcharges in California relating to
the 2000-2001 energy crisis there. Since price freezes for most customers
have ended or will end in the next year or two, a large survey of utility
tariffs found that many costs related to the transition to competition
were now explicitly added to the distribution portion, and sometimes the
transmission portion of the customer bill regardless of whether or not
the customer bought generation service from a competitive or regulated
supplier. There are some unexpected costs relating to unforeseen events.
For instance, as a result of volatile fuel markets, State regulators have
had a hard time enticing retail suppliers to offer competitive supply to
residential and smaller commercial and industrial customers. They have
often resorted to procuring the energy themselves through auction or competitive
bids or have allowed distribution utilities to procure the energy on the
open market for their customers for a fee. For AEO2008, typical charges
that all customers must pay on the distribution portion of their bill (depending
on where they reside) include: transition charges (including persistent
stranded costs), public benefits charges (usually for efficiency and renewable
energy programs), administrative costs of energy procurement, and nuclear
decommissioning costs. Costs added to the transmission portion of the
bill include the Federally Mandated Congestion Charges (FMCC), a bill pass-through
associated with the Federal Energy Regulatory Commission passage of Standard
Market Design (SMD) to enhance reliability of the transmission grid and
control congestion.
Transmission costs for the AEO are traditionally projected based on regressions
of historical spending per non-coincident peak time electricity use to
ensure that the model builds enough transmission infrastructure to accommodate
growth in peak electricity demand. However, since spending decreased throughout
the 1990s we have had to add in extra spending on transmission. Our additions
were based on several large studies, such as the Department of Energys
National Transmission Grid Study, which set out to document how much spending
would be needed to keep the national grid operating efficiently. Transmission
spending has in fact been increasing very recently. We will be monitoring
transmission spending closely over the next several years and updates will
be made as new information becomes available.
Fuel Price Expectations
Capacity planning decisions in the EMM are based on a life cycle cost analysis
over a 20-year period. This requires foresight assumptions for fuel prices.
Expected prices for coal, natural gas and oil are derived using rational
expectations, or perfect foresight. In this approach, expectations for
future years are defined by the realized solution values for these years
in a prior run. The expectations for the world oil price and natural gas
wellhead price are set using the resulting prices from a prior run. The
markups to the delivered fuel prices are calculated based on the markups
from the previous year within a NEMS run. Coal prices are determined using
the same coal supply curves developed in the Coal Market Module. The supply
curves produce prices at different levels of coal production, as a function
of labor productivity, and costs and utilization of mines. Expectations
for each supply curve are developed in the EMM based on the actual demand
changes from the prior run throughout the projection horizon, resulting
in updated mining utilization and different supply curves.
The perfect foresight approach generates an internally consistent scenario
for which the formation of expectations is consistent with the projections
realized in the model. The NEMS model involves iterative cycling of runs
until the expected values and realized values for variables converge between
cycles.
Legislation and Regulations
Clean Air Act Amendments of 1990 (CAAA90) and Clean Air Interstate Rule
(CAIR)
It is assumed that electricity producers comply with the CAIR, which mandates
limits on sulfur dioxide (SO2) and /or nitrogen oxide (NOx) in 28 eastern
states and the District of Columbia. The annual limits for SO2 emissions
are 3.6 million tons beginning in 2010 and 2.5 million tons starting in
2015. The corresponding limits of NOx emissions are 1.5 million tons in
2009 and 1.3 million tons in 2015.
Prior to the implementation of these targets, generators are still required
to comply with the SO2 and NOx limits specified by the CAAA90. The western
states not covered by the CAIR are assumed to comply with the CAAA90 throughout
the projection period. By 2010, the CAAA90 assigns an annual limit of
1.7 million tons for SO2 in these areas. Utilities are assumed to satisfy
the limits on sulfur emissions by retrofitting units with flue gas desulfurization
(FGD) equipment, transferring or purchasing sulfur emission allowances,
operating high-sulfur coal units at a lower capacity utilization rate,
or switching to low-sulfur fuels. It is assumed that the market for trading
emission allowances is allowed to operate without regulation and that the
States do not further regulate the selection of coal too be used.
As specified in the CAAA90, EPA has developed a two-phase nitrogen oxide
(NOx) program, with the first set of standards for existing coal plants
applied in 1996 while the second set was implemented in 2000. Dry bottom
wall-fired, and tangential fired boilers, the most common boiler types,
referred to as Group 1 Boilers, were required to make significant reductions
beginning in 1996 and further reductions in 2000. Relative to their uncontrolled
emission rates, which range roughly between 0.6 and 1.0 pounds per million
Btu, they are required to make reductions between 25 and 50 percent to
meet the Phase I limits and further reductions to meet their Phase II limits.
The EPA did not impose limits on existing oil and gas plants, but some
states have additional NOx regulations. All new fossil units are required
to meet standards. In pounds per million Btu, these limits are 0.11 for
conventional coal, 0.02 for advanced coal, 0.02 for combined cycle, and
0.08 for combustion turbines. These NOx limits are incorporated in EMM.
In addition, the EPA has issued rules to limit the emissions of NOx, specifically
calling for capping emissions during the summer season in 22 Eastern and
Midwestern states. After an initial challenge, these rules have been upheld,
and emissions limits have been finalized for 19 states and the District
of Columbia (Table 43). Within EMM, electric generators in these 19 states
must comply with the limit either by reducing their own emissions or purchasing
allowances from others who have more than they need.
The costs of adding flue gas desulfurization equipment (FGD) to remove
sulfur dioxide (SO2) and selective catalytic reduction (SCR) equipment
to remove nitrogen oxides (NOx) are given below for 300, 500, and 700-megawatt
coal plants. FGD units are assumed to remove 95 percent of the SO2, while
SCR units are assumed to remove 90 percent of the NOx. The costs per megawatt
of capacity decline with plant size and are shown in Table 44.
Clean Air Mercury Rule (CAMR)1
The CAMR establishes a cap-and-trade program with a two-phase implementation.
The regulation specifies a limit of 38 tons beginning in 2010 and 15 tons
starting in 2018. To reduce mercury, power companies can change their
fuels, redispatch their units, change the configuration of their units
or add mercury specific controls. To represent this, the EMM allows plants
to alter their configuration by adding equipment, such as an SCR to remove
NOx or an SO2 scrubber. They can also add activated carbon injection systems
specifically designed to remove mercury. Activated carbon can be injected
in front of existing particulate control devices or a supplemental fabric
filter can be added with activated carbon injection capability.
The equipment to inject activated carbon in front of an existing particulate
control device is assumed to cost approximately $5 (2006 dollars) per kilowatt
of capacity, while the cost of a supplemental fabric filter with activated
carbon injection (often referred as a COPAC unit) is approximately $64
per kilowatt of capacity.2 The amount of activated carbon required to
meet a given percentage removal target is given by the following equations.3
For a unit with a CSE, using subbituminous coal, and simple activated carbon injection:
- Hg Removal (%) = 65 (65.286 / (ACI + 1.026))
For a unit with a CSE, using bituminous coal, and simple activated carbon
injection:
- Hg Removal (%) = 100 (469.379 / (ACI + 7.169))
For a unit with a CSE, and a supplemental fabric filter with activated
carbon injection:
- Hg Removal (%) = 100 (28.049 / (ACI + 0.428))
For a unit with a HSE/Other, and a supplemental fabric filter with activated
carbon injection:
- Hg Removal (%) = 100 (43.068 / (ACI + 0.421))
ACI = activated carbon injected in pounds per million actual cubic feet.
Power Plant Mercury Emissions Assumptions
The Electricity Market Module (EMM) of the National Energy Modeling System
(NEMS) represents 35 coal plant configurations and assigns a mercury emissions
modification factor (EMF) to each configuration Each configuration represents
different combinations of boiler types, particulate control devices, sulfur
dioxide (SO2) control devices, nitrogen oxide (NOx) control devices, and
mercury control devices. An EMF represents the amount of mercury that
was in the fuel that remains after passing through all the plants systems.
For example, an EMF of 0.60 means that 40 percent of the mercury that
was in the fuel is removed by various parts of the plant. Table 45 provides
the assumed EMFs for existing coal plant configurations without mercury
specific controls.
Planned SO2 Scrubber and NOx Control Equipment Additions
In recent years, in response to state emission reduction programs and compliance
agreements with the Environmental Protection Agency, some companies have
announced plans to add scrubbers to their plants to reduce sulfur dioxide
and particulate emissions. Where firm commitments appear to have been
made these plans have been represented in NEMS. Based on EIA analysis
of announced plans, 46.9 gigawatts of capacity are assumed to add these
controls (Table 46). The greatest number of retrofits is expected to occur
in the Midwestern States, where there is a large base of coal capacity
impacted by the SO2 limit in CAIR, as well as in the Southeastern Electric
Reliability Council because of the Clean Smokestacks bill passed by the
North Carolina General Assembly.
Companies are also announcing plans to retrofit units with controls to
reduce NOx emissions to comply with emission limits in certain states.
In the reference case planned post-combustion control equipment amounts
to 35.5 gigawatts of selective catalytic reduction (SCR) and another 1.6
gigawatts of selective non-catalytic reduction (SNCR) equipment.
Energy Policy Acts of 1992 (EPACT92) and 2005 (EPACT05)
The provisions of the EPACT92 include revised licensing procedures for
nuclear plants and the creation of exempt wholesale generators (EWGs).
The EPACT05 provides a 20-percent investment tax credit for Integrated
Coal-Gasification Combined Cycle capacity and a 15-percent investment tax
credit for other advanced coal technologies. These credits are limited
to 3 gigawatts in both cases. It also contains a production tax credit
(PTC) of 1.8 cents (nominal) per kilowatthour for new nuclear capacity
beginning operation by 2020. This PTC is specified for the first 8 years
of operation, is limited to $125 million (per gigawatt) annually, and is
limited to 6 gigawatts of new capacity. However, this credit may be shared
to additional units if more than 6 gigawatts are under construction by
January 1, 2014. In the AEO2008 Reference case it is projected that 8
gigawatts of new nuclear capacity will be built by 2020, each receiving
a credit worth 1.35 cents per kilowatthour. EPACT05 extended the PTC for
qualifying renewable facilities by 2 years, or December 31, 2007. It also
repealed the Public Utility Holding Company Act (PUHCA).
FERC Orders 888 and 889
FERC has issued two related rules (Orders 888 and 889) designed to bring
low cost power to consumers through competition, ensure continued reliability
in the industry, and provide for open and equitable transmission services
by owners of these facilities. Specifically, Order 888 requires open access
to the transmission grid currently owned and operated by utilities. The
transmission owners must file nondiscriminatory tariffs that offer other
suppliers the same services that the owners provide for themselves. Order
888 also allows these utilities to recover stranded costs (investments
in generating assets that are unrecoverable due to consumers selecting
another supplier). Order 889 requires utilities to implement standards
of conduct and an Open Access Same-Time Information System (OASIS) through
which utilities and non-utilities can receive information regarding the
transmission system. Consequently, utilities are expected to functionally
or physically unbundle their marketing functions from their transmission
functions.
These orders are represented in EMM by assuming that all generators in
a given region are able to satisfy load requirements anywhere within the
region. Similarly, it is assumed that transactions between regions will
occur if the cost differentials between them make it economic to do so.
Electricity Alternative Cases
Low and High Cost Fossil Cases
The high cost fossil case assumes that the costs of advanced fossil generating
technologies (integrated coal- gasification combined-cycle, advanced natural
gas combined-cycle and turbines) will remain at current costs during the
projection period, that is, no learning reductions are applied to the cost.
Operating efficiencies for advanced technologies are assumed to be constant
at 2008 levels. Capital costs of conventional generating technologies
are the same as those assumed in the reference case (Table 47).
In the low cost fossil case, capital costs, heat rates and operating costs
for the advanced coal and gas technologies are assumed to be ten percent
lower than Reference case levels in 2030. Since learning occurs in the
Reference case, costs and performance in the high case are reduced from
initial levels by more than ten percent. Heat rates for advanced fossil
technologies, in the high fossil case, fall to 16 to 31 percent below initial
levels, while capital costs are reduced by 19 percent to 25 percent between
2008 and 2030.
The low and high cost fossil cases are fully-integrated runs, allowing
feedback from the end-use demand and fuel supply modules.
Nuclear Cost Cases
For nuclear power plants, two nuclear cost cases analyze the sensitivity
of the projections to lower and higher costs for new plants. The cost assumptions
for the low nuclear cost case reflect a ten percent reduction in the capital
and operating cost for the advanced nuclear technology in 2030, relative
to the reference case. Since the reference case assumes some learning occurs
regardless of new orders and construction, the reference case already projects
a 18 percent reduction in capital costs between 2008 and 2030. The low
nuclear cost case therefore assumes a 26 percent reduction between 2008
and 2030. The high nuclear cost case assumes that capital costs for the
advanced nuclear technology do not decline from 2008 levels (Table 48).
Cost and performance characteristics for all other technologies are as
assumed in the reference case.
Low and High Energy Project Cost Cases
The AEO2008 Issues in Focus article, Impacts of Uncertainties in Energy
Project Costs, examines two scenarios that vary cost assumptions in the
power sector as well as the oil and gas and petroleum submodules. This
section will discuss the assumptions used in the EMM for these two cases.
Additional assumptions for these integrated cases can be found in the relevant
oil and natural gas chapters of this document.
The reference case assumes that investment costs are based on the latest
cost data, including any commodity price increases over the past few years,
and that they will remain at these levels throughout the forecast. The
base costs for all technologies in the reference case were increased by
15 percent relative to AEO2007 to reflect recent cost increases.
The high energy project cost case assumes that the factor costs continue
to rise, leading to increasing investment costs in the energy industry.
In the power sector, it is assumed that the base costs of new generating
construction increase by 2.5 percent per year from 2007 through 2030, a
rate based on the construction cost growth of the past five years. Although
changes in learning rates can also impact the cost projections, in general,
costs for most technologies in 2030 are about 75 percent higher in the high energy project cost case than in the reference case.
The low energy project cost case assumes that the underlying factor cost
markets gradually see cost declines back to the levels of the early 2000s,
before the spikes. In the power sector, it is assumed that the base costs
of new generating construction decline by 15 percent over the next ten
years.
Limited Electricity Generation Supply and Limited Natural Gas Supply Cases
The AEO2008 Issues in Focus article, Limited Electricity Generation Supply
and Limited Natural Gas Supply Cases, examines cases where severe pressure
is put on the natural gas industry. Three cases were developed to analyze
the uncertainties surrounding the availability of non-natural gas-fired
power plants and the potential for new natural gas supplies. This section
describes the assumptions used in the case restricting electricity technologies.
The assumptions for the second case can be found in the natural gas chapter
of this document. A combined case was also run for the article, and uses
the assumptions from both the electricity and natural gas models.
The limited electricity generation supply case focuses on the potential
challenges in the power sector facing non-natural gas-fired technologies.
This case assumes that no new coal plants will be built unless they include
carbon sequestration, due to uncertainty surrounding future environmental
requirements. This case also assumes that new builds of nuclear, wind and
biomass will be restricted to reference case levels. New non-natural gas-fired
capacity, including sequestration and other renewables, is assumed to cost
25 percent more than in the reference case. Output from existing nuclear
capacity is also assumed to decline after plants reach 40 years of age
due to uncertainties surrounding the ability of older plants to maintain
high capacity factors.
Electricity Notes |