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<td width="33%"><p align="center"><a href="ceca.htm"><small>The Bill</small></a></td>
<td width="33%"><p align="center"><a href="cecasum.htm"><small>Supporting Analysis</small></a></td>
<td><a href="appndixa.htm"><small>Appendix</small></a></td>
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<p ALIGN="left"><font FACE="Arial"><b>DOE/PO-0057</b></font></p>
<p ALIGN="left"> </p>
<p ALIGN="center"></font><font FACE="Arial" size="6"><b>COMPREHENSIVE ELECTRICITY
COMPETITION ACT:</b></font><font FACE="Arial" SIZE="3"></p>
<p ALIGN="center"></font><font FACE="Arial" size="6"><b>SUPPORTING ANALYSIS</b></font><font FACE="Arial" SIZE="3"></p>
<p ALIGN="center"><img src="../images/cecasuma.gif" alt="cecasuma.gif (2645 bytes)" WIDTH="149" HEIGHT="147"></p>
<p ALIGN="center"></font><font FACE="Arial" size="4"><strong>Office of Economic,
Electricity and Natural Gas Analysis</strong></p>
<p ALIGN="center"><strong>Office of Policy and International Affairs</strong></p>
<p ALIGN="center"><strong>July 1998</strong></font><font FACE="Arial" SIZE="3"></p>
<p ALIGN="CENTER"> </p>
<p ALIGN="CENTER"> </p>
<p ALIGN="CENTER"> </p>
<p ALIGN="CENTER"></font><font FACE="Arial" size="5"><b>SUPPORTING ANALYSIS: COMPREHENSIVE
ELECTRICITY COMPETITION ACT</b></font><font FACE="Arial" SIZE="3"></p>
<p></font><font FACE="Arial"><b> </p>
</b></font>
<p><font FACE="Arial"><b>Section 1. Introduction and Overview</b></font></p>
<font FACE="Arial" SIZE="3">
<p>In 1996, residential, commercial, and industrial consumers spent $212 billion on
electricity, making the market for electricity larger than those for telecommunications,
trucking, or airline transportation services. Unlike other network industries that have
been opened to competitive market forces over the past two decades, retail electricity
markets have continued as regulated monopolies. However, recent advances in generating
technology and the successful, if limited, participation of non-utility generators on the
grid have made the characterization of electricity generation as a "natural
monopoly" increasingly tenuous. Experience in wholesale electric markets and other
formerly-regulated sectors of the economy suggests that increased reliance on competition
could bring significant tangible benefits to all electricity consumers (residential,
commercial, industrial, and government) and to the economy at large.</p>
<p>This paper quantifies the economic and environmental benefits of retail competition in
electric markets taking into account the specific features of the Administration’s
Comprehensive Electricity Competition Act (CECA).</p>
<i>
<p><strong> Comprehensive Electricity Competition Act: Overview of
Benefits</strong></i></p>
<p>The Comprehensive Electricity Competition Act was formulated to obtain the economic
benefits of competition in a manner that is fair to all Americans and improves the
environmental performance of the electricity industry. The Act: (1) encourages States to
implement retail competition, (2) protects consumers by facilitating competitive markets,
(3) assures access to and reliability of the transmission system, (4) promotes and
preserves public benefits, including renewable energy and energy-efficiency, and (5)
amends existing federal statutes to clarify federal and state authority.</p>
<p>The expected economic benefits of the Administration’s legislative proposal fall
into three main categories. First, competition will provide strong economic incentives to
raise productivity through more efficient use of resources. Second, increased competition
will make it worthwhile for electricity sellers to pursue more nimble pricing practices,
which in turn will enable power producers to make more intensive use of their substantial
investment in generation capacity. Third, and perhaps most significantly, increased
competition will call forth a wide range of innovative products and services that will add
value and better meet customer needs. All three categories of benefits identified above
represent real efficiencies expected from competition, not a simple redistribution of
existing financial flows that benefit one set of electricity interests at the expense of
another. It is the real efficiencies from restructuring -- increased productivity, better
use of resources, new products and services -- that will provide sustained long-run net
benefits to U.S. electricity consumers.</p>
<p>The expected environmental benefits of the Administration’s legislative proposal
result from environment-friendly aspects of competition augmented by specific provisions
that directly benefit the environment. Increased competition spurred by this proposed
legislation will itself strengthen incentives to use fuel more efficiently at both
existing and new generating plants thereby cutting emissions, costs, and fuel use.
Additional emissions reductions will be provided to the extent that competitive sellers
attract or retain customers by offering energy-efficiency and management services or
"green power" from renewable sources in order to add value and distinguish their
products from those of other suppliers. The initial experience in nascent competitive
markets suggests that efficiency and management services are already a key strategy used
to attract commercial and industrial customers, while the prospects for green power appear
to be strongest in residential markets.</p>
<p>The Act does not rely solely on the operation of the market to produce a positive
environmental result. Specific provisions of the Administration’s proposed
legislation also provide direct environmental benefits. These include a renewable
portfolio standard to ensure a minimum level of generation from non-hydroelectric
renewable energy sources; consumer information provisions to help consumers identify and
choose environmentally friendly generators; a public benefits fund to match State
commitments for financing energy efficiency, renewable energy, and other public benefits
programs; and a net metering provision encouraging the installation of small renewable
energy systems.</p>
<i>
<p><strong> Quantifying the Economic and Environmental Benefits of
Competition</strong></i></p>
<p>This paper presents modeling results that compare scenarios for electricity markets in
the continental United States under cost-of-service regulation and competition. The
scenarios were developed using the Policy Office Electricity Modeling System (POEMS).
POEMS is a system that integrates two existing models, the Energy Information
Administration’s (EIA) National Energy Modeling System (NEMS) and TRADELEC</font><b><font FACE="Arial" size="2"><sup>TM</sup></font><font FACE="Arial" SIZE="3"> </b>an electricity
model developed to evaluate competitive electricity markets in more detail than the
standard NEMS electricity module (see Appendix D for an overview of the POEMS model).</p>
<p>The POEMS analysis examines the economic and environmental impacts of a transition to
retail competition. However, the analysis does not attempt to explicitly account for state
actions that are already beginning the transition to competition or reflect the timing of
future actions that states might take to implement competition consistent with the
Administration’s proposed "flexible mandate" for retail competition. From
an analytical perspective, it is difficult to isolate the economic and environmental
effects of the Administration’s proposed legislation from the effects of state
actions alone. Moreover, the Administration’s proposal will benefit consumers even in
states where the transition to competitive markets is already underway by providing
additional authority to help assure that potential gains from competition are actually
realized.
<ul>
<li>On the economic side, the Act strengthens the Federal Energy Regulatory
Commission’s (FERC) ability to require utilities’ participation in regional
independent system operators, enhances FERC’s authority to remedy market power,
requires strong consumer information disclosure, allows states to condition market access
on reciprocal treatment, and clarifies state-federal jurisdictional boundaries to promote
competition and maintain reliability.<br>
</li>
<li>Similarly, provisions that provide important environmental benefits, such as the
renewable portfolio standard and the public benefit fund, apply to all states, including
those where the transition to competitive markets is already underway.</li>
</ul>
<p>The focus of the POEMS analysis is the impact of full retail competition nationally
compared to a continuation of cost of service regulation that includes wholesale
competition<b>. </b>The main results of the analysis are as follows:
<ul>
<li>The delivered cost of electricity to all consumers in 2010 in the Competitive Scenario
is estimated to be $30.7 billion lower than in the Reference (cost-of-service) Scenario.<br>
</li>
<li>The average national price of electricity is estimated to be 12 percent lower under
competition in 2010. The largest reductions are realized in areas of the country with the
highest cost-of-service rates. However, all regions of the country benefit from
competition if, as under the Administration’s proposed legislation, existing
mechanisms for pricing and allocating power produced at federal facilities (preference
power) are maintained.<br>
</li>
<li>Projected emissions of carbon dioxide from the electricity sector are reduced by between
25 and 40 million metric tons, measured in terms of carbon content. This estimate reflects
the net impact of the emissions-increasing and emissions-reducing effects of retail
competition itself, as enhanced by specific environment-friendly provisions of the
Administration’s plan, such as the Renewable Portfolio Standard, the Public Benefit
Fund, and the Consumer Information Provisions.</li>
</ul>
<p>The POEMS analysis was informed by an effort to identify potential cost savings from
restructuring, a summary of which is provided as Appendix C. Using information from
reports filed by investor-owned and public utilities, quantifiable potential cost
reductions resulting from competition in operations and maintenance costs, administrative
and general costs, more efficient use of the transmission and distribution system, and
capital cost savings at existing facilities are estimated to exceed $20 billion annually.
This estimate does not include: the savings that would result from a reduction in the need
for new capacity due to more efficient pricing, the benefit to consumers of avoiding the
costs of any future mistakes with respect to capacity planning, technology choice, or
project management that have in the past raised the cost of power to consumers; or the
greater economic value to consumers of new products and services that will be created in a
competitive environment.</p>
<p>The remainder of this document summarizes the POEMS analysis. Section 2 presents the
results. Section 3 presents key assumptions used in the analysis and the rationale for the
scenario formulation. Section 4 discusses future direction of the modeling and analytic
efforts. Appendix A provides supplementary figures and graphs. Appendix B provides a
summary table of results. Appendix C summarizes an analysis of costs at existing plants
that was used to derive projected efficiency improvements for the Competitive Scenario.
Appendix D provides documentation for the POEMS.</p>
<b>
<p>Section 2. Results of the POEMS Analysis</b><i></p>
<p><strong> Electricity Prices and Stranded Costs</strong></i></p>
<p>The introduction of retail competition is projected to lead to lower electricity rates
for customers in all regions of the country. Figure 1 illustrates the projected average
electricity prices in 2010. These prices are the average across all customer classes and
include generation, transmission, and distribution costs, and stranded cost recovery.</p>
<p ALIGN="CENTER"><img src="../images/cecasum1.gif" alt="cecasum1.gif (10786 bytes)" WIDTH="441" HEIGHT="303"></p>
<p>Both the Reference and Competitive scenarios include projections of declining
electricity rates. In 1995, the national average delivered price was 6.9 cents per
kilowatt-hour (kWh). With continued cost of service regulation, the price in 2010 is
projected to be 5.9 cents per kWh. The decline is the result of capital cost depreciation
of existing high cost plants, as well as the continued entrance of more efficient
capacity. With retail competition, greater efficiencies and marginal cost pricing lead to
larger price reductions, and the national average price is projected to be about 12
percent lower, or 5.2 cents per kWh in 2010.</p>
<p>As shown in Figure 1, there is a wide range of projected prices with continued cost of
service regulation, ranging from 4.3 cents/kWh in the Pacific Northwest to 8.6 cents/kWh
in New York. With competition, the variation in price is likely to be smaller, ranging
from 4.2 cents/kWh in the Pacific Northwest to 7.5 cents/kWh in New York<sup> 1</sup> . In
general, the regions projected to have the highest prices under cost of service regulation
are those that are likely to see the largest decrease in prices under competition. The
remaining regional variation is due to differences in fuel prices, operating costs,
transmission costs, transmission constraints, distribution costs, and stranded cost
recovery. Differences in transmission and distribution costs are the most important
factors.</p>
<p>Consumer savings are projected for all classes of customers: residential, commercial,
and industrial. A comparison of 2010 national cost of service and competitive rates by
customer class is shown in Figure 2. Residential customers are projected to see the
largest price decreases in 2010 with competition. In part, this is because historical
capacity costs were allocated to customer classes based on their contribution to peak
demand. Residential customer demand tends to have more variation by time of day and season
than industrial and commercial; therefore, it receives a relatively greater share of the
costs under peak demand allocation than if costs were allocated based on sales. Although
the energy costs associated with peak demands are generally high, the capital costs for
peaking turbines is relatively low compared to baseload units. In the competitive market,
higher marginal costs at peak periods will lead to higher average generation prices for
residential customers than for customer classes with flatter load profiles, but with less
of an average premium than under the previous capital cost allocation. </p>
<p ALIGN="CENTER"><img src="../images/cecasum2.gif" alt="cecasum2.gif (5802 bytes)" WIDTH="447" HEIGHT="283"></p>
<p>The competitive prices include the recovery of a projected $85 billion in stranded
costs for existing and productive generating assets. When stranded costs for existing and
productive generating assets are recovered over a 10-year period as described below, the
national average additional charge to the average electricity price is 0.2 cents per kWh
in 2010. On a regional average basis, stranded cost recovery factors are projected to
range from 0.03 to 0.5 cents per kWh. Within regions, stranded cost recovery factors will
vary across individual utilities due to differences in generating asset portfolios and
price differences across power control areas.</p>
<p>The Competitive Scenario also provides for recovery of regulatory assets and
decommissioning costs. The pace of recovery in these categories for both scenarios
reflects recent state-level practices, and is assumed to be similar to projected recovery
in the Reference Scenario. Provision for recovery of regulatory assets and decommissioning
costs adds 0.1 cents per kWh to the estimated national average price of electricity in
2010.</p>
<i>
<p><strong> Electricity Demand</strong></i></p>
<p>The underlying electricity demand forecast, which is taken from the EIA Annual Energy
Outlook, projects electricity growth of 1.5 percent per year from 1995 to 2010. There are
several elements of the Act that will affect this demand. Lower electricity prices
resulting from competition are likely to stimulate additional demand for electricity. This
is dampened to some extent by lower projected natural gas prices that result from overall
lower gas demand. The proposed provision for a Public Benefits Fund and the expectation
that competition will spur efforts to package energy efficiency (and other energy service
products) with power sales, also are projected to reduce demands. The net result is
slightly higher electricity demand in the near term and lower demand as the Act comes into
full effect. By 2010, projected electricity demand is 2.4 percent lower with the Act than
in the Reference Scenario.</p>
<i>
<p><strong> Generation Capacity</strong></i></p>
<p>Most of the generation capacity used in 2010 will be capacity that exists today. For
example, in the Reference Scenario in 2010 only 20 percent of the projected total capacity
are new additions. Currently, coal plants account for 41 percent of all capacity. Other
major types of capacity are: other fossil (oil and gas) steam at 19 percent, nuclear at 14
percent, hydroelectric at 13 percent, and combustion turbines at 8 percent. Gas-fired
combined cycle plants and all other renewables have relatively small shares, at 4 and 1
percent respectively. In the future, this mix is projected to shift more towards gas
technologies and away from coal and nuclear plants.</p>
<p>In both the Reference and Competitive scenarios, the greatest share of new construction
is projected to be gas-fired combined cycle plants. This result reflects the combined
effect of high efficiencies, short construction periods, modularity, and modest projected
increases in natural gas prices. In the Reference Scenario, they are projected to
represent 59 percent of the cumulative new plants from 1995 to 2010, with gas-fired
combustion turbines that serve peaking requirements capturing an additional 27 percent of
total capacity additions.</p>
<p>The dominant change in the mix of future generating capacity in the Competitive
Scenario is the increase in the share of renewable capacity (see Figure 3) that results
from the Renewable Portfolio Standard included in the Administration's proposal and
consumers’ interest in green power. Less capacity of other types of plants are needed
as a result. However, much of additional renewable capacity is intermittent. For example,
generation from wind power is dependent on when the wind is blowing and therefore operates
less than a plant that can be run 24 hours a day. Because of this, much of the renewable
capacity added receives only a partial credit towards meeting capacity requirements. This
results in more installed capacity under the Administration’s proposal than in the
Reference Scenario, even though demand is slightly lower.</p>
<i>
<p><strong> Electricity Generation</strong></i></p>
<p>The differences in generation by fuel type across the Reference and Competitive
scenarios (see Figure 4) do not directly track the differences in capacity additions
outlined above. Because competition will provide strong incentives to run low-cost plants
more efficiently and to shorten scheduled outage periods, existing coal and nuclear plants
are run more often in the Competitive Scenario. As a result, even though there is slightly
less coal capacity, coal generation in the Competitive Scenario is actually slightly above
the Reference Scenario level. The change in non-hydroelectric renewable generation under
the Administration’s proposal is significant, as shown in Figure 5. Because of the
proposed Renewable Portfolio Standard and consumers’ interest in green power,
non-hydro renewables generation in 2010 is projected to be 6.3 percent of total generation
in the Competitive Scenario, approximately twice its share in the Reference Scenario. All
of other types of generation are below the Reference Scenario levels in the Competitive
Scenario.</p>
<i>
<p align="center"><img src="../images/cecasum3.gif" alt="cecasum3.gif (4447 bytes)" WIDTH="439" HEIGHT="233"></i></p>
<div align="center"><center>
<table border="0" width="440" cellspacing="0" cellpadding="0">
<tr>
<td width="7"></td>
<td width="6"></td>
<td width="29"></td>
<td width="59"><p align="center"></font><font FACE="Arial" size="1"><strong>Gas Fired
Combined Cycle</strong></font><font FACE="Arial" SIZE="3"></font></td>
<td width="44" valign="top"><p align="center"><font FACE="Arial" size="1"><strong>Coal</strong></font><font FACE="Arial" SIZE="3"></font></td>
<td width="70"><font FACE="Arial" size="1"><strong>Gas-Fired Combustion Turbine</strong></font><font FACE="Arial" SIZE="3"></font></td>
<td width="60" valign="top"><font FACE="Arial" size="1"><strong>Other Fossil</strong></font><font FACE="Arial" SIZE="3"></font></td>
<td width="48" valign="top"><font FACE="Arial" size="1"><strong>Nuclear</strong></font><font FACE="Arial" SIZE="3"></font></td>
<td width="63" valign="top"><font FACE="Arial" size="1"><strong>Renewable</strong></font><font FACE="Arial" SIZE="3"></font></td>
</tr>
</table>
</center></div>
<p align="center"><img src="../images/cecasum4.gif" alt="cecasum4.gif (5231 bytes)" WIDTH="497" HEIGHT="239"></p>
<p align="center"><img src="../images/cecasum5.gif" alt="cecasum5.gif (4974 bytes)" WIDTH="431" HEIGHT="291"></p>
<p><strong><i> Carbon Emissions</i></strong></p>
<p>Carbon emissions from electricity generation are projected to increase by 166 million
metric tons of carbon equivalent (MMTCE) between 1995 and 2010 in the Reference Scenario.
In the Competitive Scenario, carbon emissions are projected to be 39 MMTCE lower than the
Reference Scenario in 2010.</p>
<p>Recognizing the inherent uncertainty of future market developments, the Administration
estimates that its proposal will lead to emissions reduction of between 25 and 40 MMTCE in
2010. This approach parallels the conservative approach used in evaluating economic
benefits, which recognizes that the impacts of the Administration’s proposed
legislation and those of competition itself are not easily separated. Emissions reductions
in this range are likely to be achieved even if most of the uncertainties discussed below
are ultimately resolved in a direction that tends to increase emissions beyond the modeled
level.</p>
<p>As shown in Figure 6, carbon emissions may rise slightly in the early years of
competition compared to the Reference Scenario with continued regulation. However, as
existing coal plants become fully utilized, the Renewable Portfolio Standard requirements
increase, and additional energy efficiency investments take place, emissions grow more
slowly. Another factor leading to lower emissions is the improved efficiency in power
generation, as generators faced with competition have a direct financial incentive to
reduce their input costs.</p>
<i>
<p><strong> Key Uncertainties Affecting Carbon Emissions</strong></p>
<p><strong> Improvement in heat rates and capacity availability</i>.</strong>
There is considerable uncertainty regarding the extent of heat rate or capacity
availability improvements likely to occur at existing plants in a competitive scenario.
Heat rate improvements and capacity availability improvements at fossil-fired plants work
in opposing directions, with the former tending to reduce carbon emissions and the latter
tending to increase them. Should either of these improvements in a competitive environment
diverge from the estimates used in the Competitive Scenario, carbon emissions would be
directly affected.</p>
<p ALIGN="CENTER"><img src="../images/cecasum6.gif" alt="cecasum6.gif (4827 bytes)" WIDTH="435" HEIGHT="273"></p>
<i>
<p>Other state-level and private decisions under competition</i>. Decisions that could
result in lower-than- modeled emissions include higher energy-efficiency spending due to
either competition among retail electricity suppliers or the operation of the Public
Benefits Fund (the results presented here assume an incremental $2 billion annually in
efficiency spending due to the public benefit fund), more consumer interest in green
power, fewer nuclear retirements due to competition, or lower than assumed availabilities
for coal-fired power plants. Forces that could result in higher-than- modeled emissions
include additional nuclear retirements attributable to competition, greater responsiveness
of demand to price reductions than provided for in the demand modules of the National
Energy Modeling System, or a binding Renewable Portfolio Standard cost cap that is not
offset by increased green power demand.</p>
<i>
<p><strong> Emissions of Nitrogen Oxides and Sulfur Dioxide</strong></i></p>
<p>The Administration’s proposal includes provisions that clarify Environmental
Protection Agency (EPA) authority to require a cost-effective interstate trading system
for nitrogen oxide (NOx) pollutant reductions addressing the regional transport
contributions needed to attain and maintain the ozone ambient air quality standard.
However, no change is proposed to existing EPA authority to determine geographic coverage
or level of reductions required in addressing regional transport contributions.</p>
<p>Consistent with these provisions, the projected level of nitrogen oxide emissions will
primarily be determined by past, pending and future actions taken by EPA under its
existing regulatory authorities. For example, the emissions level in 2000 and beyond are
significantly below the 1995 level in both the Reference and Competitive scenarios due to
the Phase 2 Clean Air Act NOx standards, which were included in both cases. Starting from
existing emissions rates as modified by the Phase 2 standards in 2000, both annual and
summer season NOx emissions in the Competitive Scenario are projected to be roughly 4
percent below projected levels in the Reference Scenario in 2010. The projected reduction
in NOx due to competition generally results from the same set of factors that provides the
reduction in carbon dioxide emissions discussed in the previous section.</p>
<p>These POEMS model results do not reflect the Environmental Protection Agency's pending
proposal to establish absolute caps on ozone season NOx emissions for 22 States and the
District of Colombia or the reductions currently being undertaken within the eastern
States comprising the Ozone Transport Commission. As noted above, such actions under
existing regulatory authority will be the primary determinant of future emissions levels.
For example, in regions and seasons where regulatory actions take the form of an absolute
cap on the level of emissions, the cap itself would determine the level of NOx emissions
independent of the price of electricity or the structure of electricity markets for those
regions and seasons in which it was applicable.</p>
<p>This observation may be applied directly in the case of sulfur dioxide emissions, since
an annual nationwide cap on sulfur dioxide emissions from the electric utility sector has
already been established pursuant to the 1990 Clean Air Act Amendments. For this reason,
emissions of this pollutant are projected to be the same in both scenarios.</p>
<b>
<p>Section 3. Model Assumptions</b><i></p>
<p><strong> Scenario Definition and Baseline Assumptions</strong></i></p>
<p>In order to measure the impacts of the retail competition, a baseline must first be
established. As with any forecasting exercise, this Reference Scenario is meant to be a
reasonable expectation of possible future events and not a statement of what will happen.
For this analysis, the Reference Scenario assumes a continuation of existing forms of
utility regulation and cost-of-service pricing. The Competitive Scenario represents
implementation of retail competition as envisioned in the CECA.</p>
<p>The Reference Scenario assumes wholesale competition as achieved through open
transmission access under FERC Order 888. All new capacity is assumed to be built by
exempt wholesale generators and not included in the rate base of utilities. In addition,
transmission fees are <i>pancaked</i>. In other words if power is wheeled across two
transmission systems, each will charge a separate fee for providing the transmission
service.</p>
<p>The Reference and Competitive scenarios share the same underlying macroeconomic and
energy sector assumptions, which are taken from EIA's Annual Energy Outlook 1997. However,
the electricity demand and fuel price projections are not identical between scenarios,
because of the feedback with electricity prices, fuel demands of the electric sector, and
other sectors fuel prices due to the transition to competition and specific provisions of
the CECA.</p>
<p>The Administration’s proposal was represented in the POEMS model through a range
of assumptions that represent a vision of how a full retail competition market might
emerge as a result of the Administration's proposed policies. Table 1 outlines the major
set of assumptions and provides a comparison with the Reference Scenario. Each of these
assumptions is discussed below in the context of the Act.</p>
<i>
<p><strong> Electricity Pricing, Stranded Assets, and Plant Retirements</strong></i></p>
<p>The generation price in the Competitive Scenario is composed of the marginal generation
cost, ancillary charges, a renewable portfolio standard (RPS) premium (if applicable), and
stranded cost recovery charges. Marginal generation cost is established in each power
control area (PCA) based on the bid price of the last unit running in each time/season
period. The last unit could be native to the PCA or determined through trade with other
PCAs. In accord with the standard economic model of perfect competition, the bid price for
each unit is assumed to be its marginal cost -- the sum of fuel cost and the variable
portion of operating and maintenance (O&M) costs.</p>
<p>As stated in the Comprehensive Electricity Competition Plan (announced March 25, 1998),
the Administration "endorses the principle that utilities should be able to recover
prudently incurred, legitimate and verifiable retail stranded costs that cannot be
reasonably mitigated". The Competitive Scenario assumes that stranded costs
associated with productive generating assets are recovered over a ten-year period
following the introduction of competition. Recovery of regulatory assets and
decommissioning costs in the Competitive Scenario is assumed to be similar to that in the
Reference Scenario, with the pace of recovery in these categories for both scenarios
reflecting recent state-level practices.</p>
<p>Retirement of plants is economically driven. The economic retirement decision for all
generating plants is based on both short-term and long-term criteria. The short-term
requirement is that plants can cover their "going-forward" costs, which includes
all fixed and variable O&M costs as well as recovery of the annualized value of new
capital additions. If a plant cannot cover these costs, it becomes a candidate for early
retirement. The second consideration is the cost of building new generating capacity. In
the capacity-planning module, all existing units must pay their going-forward costs if the
capacity is to be used over the full planning horizon. Thus the planning module has the
opportunity to "decide" to economically retire any or all of the existing units
and instead build new capacity. If the planning module does decide to economically retire
a unit and this same unit did not cover its variable costs in the last forecast year, it
is retired. A plant must be uneconomic in both the short-term and long-term to be retired.</p>
<p align="center"><img src="../images/cecasum7.gif" alt="cecasum7.gif (16654 bytes)" WIDTH="493" HEIGHT="651"></p>
<i>
<p><strong> Operating Costs: Generation, Transmission and Distribution</strong></i></p>
<p>As the electric power industry is transformed into a more competitive, market-based
industry, the historical level of costs are expected to be reduced due to the pressures of
competition. In the generation segment of the industry, costs per unit of output will
decrease due to the changing mix of capacity, i.e., more expensive generating units are
replaced by new, more efficient generating technology (typically natural gas fueled). In
the Competitive Scenario, competitive pressures are expected to lower costs at existing
generating facilities as well, as they begin to compete with other existing and new
facilities. Competitive pressures are assumed to also spill over into the regulated
segment of the industry. Transmission productivity improves by 0.75 percent per year and
distribution productivity improves by 1.5 percent per year to 2010 due to the introduction
of performance incentives to improve productivity in these functions.</p>
<i>
<p><strong> Cost of Capital</strong></i></p>
<p>Under competition, electricity generators will not be guaranteed a fixed rate of return
on their investments. As a result, plant owners will demand a greater expected return to
compensate for the risk associated with their revenues. They will also need to finance
their investments with less reliance on debt and more on equity. The weighted cost of
capital is 12.8 percent in the Reference Scenario and 14 percent in the Competitive
Scenario.</p>
<i>
<p><strong> Heat Rate Improvement</strong></i></p>
<p>Historically, utilities were not rewarded for reducing their fuel costs. In fact, in
many states, fuel costs were directly passed through to consumer bills. As long as a
utility was acting "prudently," regulators would provide little pressure to
reduce these costs. This is likely to explain in part why there is currently a very wide
range of heat rates in power plants of the same type, size, and age. With intense
competitive pressures, generator owners are likely to make cost-effective improvements and
change their operations to improve the efficiencies of these existing plants. Any
improvements will lead either directly to increased profits or allow the plant to continue
to operate where it might otherwise be priced out of the market. Based on an analysis of
existing heat rates, the Competitive Scenario assumes that existing plants will make
significant strides towards achieving heat rates closer to those of the top 25 percent of
comparable plants.</p>
<i>
<p><strong> Capacity Availability Improvement</strong></i></p>
<p>Competition will also give generators an incentive to maximize the availability of
their facilities because they will only receive revenue when they are operating. In the
Reference Scenario, fossil-fuel- fired steam units are assumed to have availabilities of
85 percent. Nuclear availabilities vary by region and are based on EIA’s AEO98
assumptions. In the Competitive Scenario, the steam units are assumed to have 90 percent
availabilities, which is equivalent to a one-third reduction in the outage times. A
one-third improvement was applied to the nuclear units as well, with a maximum of 90
percent availability. For most regions, the resulting nuclear availabilities fall below
the 90 percent cap.</p>
<i>
<p><strong> Transmission System</strong></i></p>
<p>The Federal Energy Regulatory Commission, in its Order No. 888, required <i>that
"…seller(s) (and each of its affiliates) must not have, or must have mitigated,
market power in generation and transmission and not control other barriers to entry."
</i><sup>2</sup> For transmission owning utilities, this meant that the utility must have
on file with the Commission an open access tariff for the provision of comparable service.
The Competitive Scenario assumes that all transmission owners have an open access tariff
over which retail and wholesale sales can occur. The Competitive Scenario, as in the
Reference Scenario, assumes that exempt wholesale generators (EWGs) will provide all new
generation capacity. The Competitive Scenario assumes that all consumers (i.e.,
residential, commercial and industrial) will have equal access to the power exchanges.<sup>3</sup>
To assure that consumers of all types have the necessary information to make these
informed decisions, the Administration’s proposal provides for a uniform label
information on price, terms and conditions of service.</p>
<p>Transmission fees were computed using a formula similar to the pro forma tariff
described in Order No. 888. In the Reference Scenario, the transmission fees were assumed
to be <i>pancaked<sup> 4</sup> . </i>In the Competitive Scenario, the assumption is that
regional transmission groups (RTG), tied together by an independent system operator (ISO)
would operate the transmission grid(s). The transmission fees in the Competitive Scenario
were therefore assumed to be the same for moving power across the entire RTG region (i.e.,
a postage stamp rate). Since the bulk of the costs associated with the transmission system
are allocated to the native load customers, the transmission fees used were discounted. In
the Reference Scenario the discount was 20 percent and in the Competitive Scenario, the
discount was 50 percent.</p>
<i>
<p><strong> Renewable Portfolio Standard and Green Power</strong></i></p>
<p>A Renewable Portfolio Standard (RPS) was included as a national standard with potential
trading of credits. This means that renewable generation can be constructed wherever it is
most cost-effective, rather than requiring it to be spread evenly across the nation. The
standard was expressed as a percent of sales that must be met with renewables and was
assumed to increase gradually over the 2001 to 2010 period. In 2010, the RPS was set at
5.5 percent. All non-hydro renewable generation qualifies to meet the standard, including
industrial cogeneration. Because of the ability to trade credits, renewables will command
the same price premium nationally, equivalent to the marginal cost. The premium is paid by
all customer classes on a cents per kilowatt-hour basis.</p>
<p>The Competitive Scenario assumes that in addition to the RPS standard, 5 percent of
residential customers nationwide would be willing to pay for additional Green Power, which
is comprised of 50 percent new non-hydro renewables, above what the RPS requires.<sup>5</sup>
The labeling provisions of the CECA will provide consumers with the information that they
need to be able to choose their generation suppliers based on price and the environmental
factors important to them. Pilot programs in various states, as well as activity in
California, support the assumption that a segment of consumers will value these qualities.</p>
<i>
<p><strong> Public Benefit Fund and Integrated Energy Services</strong></i></p>
<p>The Administration’s proposal calls for the creation of a $3 billion Public
Benefits Fund to be matched by states and used for energy efficiency programs, technology
research projects, low-income assistance, and consumer education. In addition, with
electricity suppliers competing to meet the needs of customers, they are likely to offer a
full range of energy services in order to be competitive. Energy efficiency improvements
are already being offered in some of the nascent retail competition areas. Together these
efficiency improvements are assumed to reduce electricity demand by 2 percent in 2010. The
modeled scenario was developed in the context of a $2 billion increment to annual baseline
energy-efficiency expenditures over the 2000 to 2010 period. Additional expenditures in
energy efficiency would reduce electricity demand further.</p>
<b>
<p>Section 4. Next Steps</b></p>
<p>This paper is intended to inform discussions of restructuring policy by comparing a
generic cost-of- service scenario to a retail competition scenario that is consistent with
the main elements of the Administration’s Comprehensive Electricity Competition Act.
Further analyses can provide additional insights as these discussions unfold. While some
future analyses will be driven by the specific elements of alternative proposals, some
issues that have already been identified as potential subjects of future analysis are
briefly summarized below:</p>
<i>
<p><strong> Transmission constraints</i>: </strong>Transmission plays an
important role in the modeling analysis of competition, since only in the presence of
transmission constraints will prices in adjacent competitive markets differ by more than
the transmission fee plus line losses. Electricity flows on the transmission system do not
generally follow the contract path, and the available capacity between two market areas
may be influenced by power flows throughout the system. For this reason, it is important
to verify the POEMS representation of transmission constraints using tools that can follow
physical flows. Work in this area is underway in cooperation with the North American
Electric Reliability Council and other transmission experts.</p>
<i>
<p><strong> The timing and scope of competition</i>: </strong>Notwithstanding
the difficulty of separating the projected effects of the Administration’s proposal
from those attributable to other steps towards competition, sensitivity scenarios
addressing this issue could provide useful insight into the likely impact of alternative
transition paths.</p>
<i>
<p><strong> Nuclear retirements</i>:</strong> For both emissions and
economic reasons, there is considerable interest in the implications of competition for
continued utilization of existing nuclear plants. A further assessment in this area would
review the characterization of retirements in the Reference Scenario and the criteria used
to drive retirements in the Competitive Scenario. The role of risk relative to expected
profitability in driving retirement decisions should plant owners be called upon to make
an early declaration regarding their intended retirement decisions also merits further
attention. Finally, the implications of a scenario in which competition results in a
concentration of nuclear operations in the hands of firms with a proven record of
efficient, safe, and economical operation of these facilities should also be considered.</p>
<i>
<p><strong> Alternative Allocations of Stranded Costs: </strong></i>In
the same manner that rates under cost-of-service regulation are affected by the allocation
of new capacity costs across customer classes, prices in the transition to competition
will depend on how the costs of uneconomic generating assets are allocated. Sensitivity
analyses could scope out the range of possible outcomes.</p>
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