EXHIBIT 99.4
ANNEX B
Mirant Americas
Generation, Inc.
(Formerly operating as Southern Energy
North America Generating, Inc.)
Independent Market Expert's Report for the
MAGI Portfolio of Generating Assets
March 12, 2001
Mirant Americas
Generation, Inc.
(Formerly operating as Southern Energy
North America Generating, Inc.)
Independent Market Expert's Report for the
MAGI Portfolio of Generating Assets
March 12, 2001
COMPANY CONFIDENTIAL
(C) PA Consulting Group 2001
PA Consulting Group
1881 Ninth Street
Prepared by: Todd Filsinger Suite 302
Boulder
Colorado 80302
Tel: +1 303 449 5515
Fax: +1 303 443 5684
www.paconsulting.com
Version: 1.0
DISCLAIMER
- --------------------------------------------------------------------------------
This report presents the analysis of PA Consulting Group (PA) for the following
North American Electric Reliability Council (NERC) regions:
- - PJM -- the Pennsylvania-New Jersey-Maryland Interconnection LLC
- - MAIN/ECAR -- Mid-America Interconnected Network/East Central Area
Reliability Coordination Agreement
- - WSCC-CALIFORNIA -- California (in the Western Systems Coordinating Council
region)
- - NPCC-NEW YORK -- New York Power Pool (in the Northeast Power Coordinating
Council region)
- - NPCC-NEPOOL -- New England Power Pool (in the Northeast Power Coordinating
Council region)
- - ERCOT -- Electric Reliability Council of Texas.
(i) some information in the report is necessarily based on predictions and
estimates of future events and behaviors,
(ii) such predictions or estimates may differ from that which other experts
specializing in the electricity industry might present,
(iii) the provision of a report by PA does not obviate the need for potential
investors to make further appropriate inquiries as to the accuracy of the
information included therein, or to undertake an analysis of their own,
(iv) this report is not intended to be a complete and exhaustive analysis of
the subject issues and therefore will not consider some factors that are
important to a potential investor's decision making, and
(v) PA and its employees cannot accept liability for loss suffered in
consequence of reliance on the report. Nothing in PA's report should be
taken as a promise or guarantee as to the occurrence of any future events.
i
TABLE OF CONTENTS
1. INTRODUCTION 1-1
1.1 Background 1-1
1.2 Asset Portfolio Description 1-1
1.3 Portfolio Results Summary 1-1
1.4 Methodology 1-2
1.5 Report Structure 1-2
2. REGIONAL ANALYSIS 2-1
2.1 Introduction 2-1
2.2 Risk Issues and Sensitivity Cases 2-1
2.2.1 Higher or Lower Fuel Prices 2-1
2.2.2 Overbuild 2-1
2.2.3 High Hydro 2-2
2.3 Overview of the Regional Markets 2-2
2.4 Retail Market Competition 2-2
2.5 PJM 2-3
2.5.1 Background 2-3
2.5.2 Power Markets 2-4
2.5.3 Market Dynamics 2-8
2.5.4 Transmission System 2-8
2.5.5 Price Forecasts for the PJM Market 2-9
2.5.6 Dispatch Curves 2-11
2.6 MAIN/ECAR 2-12
2.6.1 Background 2-12
2.6.2 Power Markets 2-13
2.6.3 Market Dynamics 2-13
2.6.4 Transmission System 2-14
2.6.5 Price Forecasts for the MAIN Market 2-15
2.6.6 Dispatch Curves 2-17
2.7 WSCC-California 2-18
2.7.1 Background 2-18
2.7.2 Power Markets 2-19
2.7.3 Market Dynamics 2-21
2.7.4 Transmission System 2-22
2.7.5 Ancillary Services Markets 2-22
2.7.6 Price Forecasts for the WSCC-California Market 2-23
2.7.7 Dispatch Curves 2-25
2.8 NPCC-New York 2-26
2.8.1 Background 2-26
2.8.2 Power Markets 2-27
2.8.3 Market Dynamics 2-31
2.8.4 Transmission System 2-32
2.8.5 Price Forecasts for the New York Market 2-33
2.8.6 Dispatch Curves 2-35
2.9 NPCC-NEPOOL 2-36
2.9.1 Background 2-36
2.9.2 Power Markets 2-37
ii
2.9.3 Market Dynamics 2-42
2.9.4 Transmission System 2-42
2.9.5 Price Forecasts for the NEPOOL Market 2-43
2.9.6 Dispatch Curves 2-45
2.10 ERCOT 2-46
2.10.1 Background 2-46
2.10.2 Power Markets 2-46
2.10.3 Market Dynamics 2-48
2.10.4 Transmission System 2-48
2.10.5 Price Forecasts for the ERCOT Region 2-50
2.10.6 Dispatch Curves 2-52
3. FORECASTING METHODOLOGY 3-1
3.1 Overview of the PA Valuation Process 3-1
3.2 Fundamental Analysis 3-1
3.3 Volatility Analysis 3-2
4. KEY ASSUMPTIONS 4-1
4.1 Introduction 4-1
4.2 Capacity and Energy Forecasts 4-1
4.3 Fuel Prices 4-1
4.3.1 Natural Gas 4-1
4.3.2 Fuel Oil 4-3
4.3.3 Coal 4-4
4.4 SO(2)/NOx Emission Costs 4-5
4.4.1 Sulfur Dioxide Emission Costs 4-5
4.4.2 Development of NOx Control Costs and Emission Rates 4-6
4.5 Hydroelectric Units 4-7
4.6 Capacity Additions and Retirements 4-7
4.7 Financial Assumptions 4-13
4.7.1 Generic Plant Characteristics 4-13
4.7.2 Other Expenses 4-13
4.7.3 Economic and Financial Assumptions 4-13
APPENDIX A HISTORICAL AND PROJECTED ENERGY PRICES
iii
1. INTRODUCTION
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1.1 BACKGROUND
PA Consulting Group (PA) was retained by Southern Energy North America
Generating, Inc., now operating as Mirant Americas Generation, Inc. (MAGI),
to provide an Independent Market Expert Report on behalf of Representative of
the Initial Purchasers for MAGI's generating assets located in the following
markets: Pennsylvania-New Jersey-Maryland Interconnection LLC (PJM),
Mid-America Interconnected Network (MAIN), East Central Area Reliability
Coordination Agreement (ECAR), Western Systems Coordinating Council (WSCC)
California, New York Power Pool (New York), New England Power Pool (NEPOOL),
and Electric Reliability Council of Texas (ERCOT). This report assesses the
price projections based on stated assumptions for electric prices in the
markets mentioned above and presents the results of PA's analysis.
1.2 ASSET PORTFOLIO DESCRIPTION
The generating facilities total approximately 12,481 MW of generation as
summarized in Table 1-1.
-------------------------------------------------------------
TABLE 1-1
REGIONAL MARKET LOCATION
OF MAGI GENERATING ASSETS
---------------------- ------------------ -------------------
GENERATING TOTAL CAPACITY(1)
REGIONAL MARKET ASSETS (MW)
---------------------- ------------------ -------------------
PJM Chalk Point 5,154
Dickerson
Morgantown
Potomac River
---------------------- ------------------ -------------------
MAIN/ECAR Neenah 824
State Line
---------------------- ------------------ -------------------
WSCC-California Contra Costa 2,963
Pittsburg
Potrero
---------------------- ------------------ -------------------
NPCC-New York Bowline 1,764
Grahamsville
Hilburn
Lovett
Mongaup
Rio
Shoemaker
Swinging Bridge
---------------------- ------------------ -------------------
NPCC-NEPOOL Canal 1,232
Kendall
WF Wyman
---------------------- ------------------ -------------------
ERCOT Bosque(2) 544
---------------------- ------------------ -------------------
(1) Based on summer capacity ratings provided by R.W.
Beck, Inc.
(2) Includes 236 MW which is under construction and expected
to be completed in June 2001.
-------------------------------------------------------------
1.3 PORTFOLIO RESULTS SUMMARY
PA modeled the generation asset portfolio under five scenarios: base case, high
and low fuel cases, PJM and NPCC generation overbuild, and above normal hydro
conditions for California. The base case is constructed using generation and
load growth data stated in the EIA Form 411s combined with PA's merchant plant
and in-house fuel forecast. These assumptions and other key drivers are
described in detail in Chapter 4. The high fuel case assumes that gas costs
based upon the 2001 NYMEX futures are extended throughout the study period and
the low fuel case assumes a $0.50/MMBtu reduction from the base case in 2001,
and then follows the same escalation as the base case 2001 price with no change
to escalation. The generation overbuild case assumes that 7,280 MW of excess
capacity is constructed in the Northeast markets in 2004, 4,160 MW of which is
in PJM. In the high-hydro case it is assumed that hydro generation in WSCC is
approximately 20% higher than the base case for 2001 to 2004.
A summary of the total revenues for the base case is shown in Figure 1-1.
FIGURE 1-1
SUMMARY OF TOTAL REVENUES(1) ($ BILLIONS)
[GRAPH]
[KEY]
(1) Revenues do not reflect the effect of contracts with the exception of
Reliability-Must-Run contracts in California.
1-1
Figure 1-2 shows the proportion of projected revenues from each region averaged
over 20 years. Total projected revenues for all of MAGI's assets for each
sensitivity case for the period 2002-2020 are compared in Figure 1-3.
1.4 METHODOLOGY
PA employs its proprietary market valuation process, MVP(SM), to estimate the
value of electric generation units based upon the level of energy prices and
their volatility. MVP(SM) is a three-step process. The first step is to
conduct a "fundamental analysis" to examine how the LEVEL of prices responds
to changes in the fundamental drivers of supply and demand. The fundamental
analysis is conducted with a production-cost model that provides insights
into the basic market drivers: fuel prices, demand, entry, and exit. The
second step utilizes the results of the fundamental analysis to derive a
"REAL MARKET" price shape from the fundamental price levels. This step also
characterizes the hourly volatility in the fundamental prices. The third step
examines how a generation unit responds to those prices and derives value
from operational decisions. Through the three-step process MVP(SM) integrates
the fundamental and volatility approaches to create a better estimate of the
value of a generating unit by accounting for volatility effects and changes
in the fundamental drivers of electricity prices. The WSCC, New York, NEPOOL,
and PJM markets are modeled using the MVP(SM) method. The ERCOT, ECAR, and
MAIN regions are modeled using the fundamental analysis due to the nature of
the assets and their contractual arrangements.
1.5 REPORT STRUCTURE
Chapter 2 contains a discussion of each of the relevant generation markets
organized by NERC transmission regions and subregions. Each market discussion
includes an overview of the market with a discussion of the current generation
mix and a summary of PA's fundamental load and generation requirements forecast
for the period of 2001-2020. The forecasts of energy prices and capacity
compensation for the base case as well as associated sensitivity cases are
provided. Dispatch curves are provided for 2001 and 2010. These curves
illustrate the marginal cost of the last generator for the given load shown on
the horizontal axis. The location of the assets in the generating portfolio are
identified on the curves.
FIGURE 1-2
AVERAGE TOTAL REVENUES (2001-2020)
[GRAPH]
FIGURE 1-3
SUMMARY OF TOTAL REVENUES
FOR SENSITIVITY CASES(1) ($ BILLIONS)
[GRAPH]
[KEY]
(1) Revenues do not reflect the effect of contracts with the exception of
Reliability-Must-Run contracts in California.
1-2
Chapter 3 reviews the methodology used to develop the forecasts presented in
Chapter 2. Key assumptions that drive the forecast results are provided in
Chapter 4.
1-3
2. REGIONAL ANALYSIS
- --------------------------------------------------------------------------------
2.1 INTRODUCTION
Over the past two decades, the structure of the electric power industry has been
dramatically changed by the emergence of a networked industry. A market trend
that has paralleled the integration of the transmission network is the
introduction of wholesale and retail competition in formerly regulated markets.
These market developments have added new dimensions to the risk of owning and
operating generation plants. This chapter describes the relevant wholesale
competitive markets and the results from the regions where the MAGI assets are
located. One mechanism for understanding risk is to examine how market prices
and generation requirements could change under different scenarios. These
scenarios, termed sensitivity cases, are described in this chapter as well as
their effect on the projected market power prices.
The regions analyzed in this chapter include:
- - PJM
- - MAIN/ECAR
- - WSCC-California
- - NPCC-New York
- - NPCC-NEPOOL
- - ERCOT.
2.2 RISK ISSUES AND SENSITIVITY CASES
Analysis of possible variances in fundamental variables is essential when
forecasting market prices in the United States today. Initially a base case was
developed for each region using the assumptions outlined in Chapter 4. The base
case is not defined as the most likely case. Four sensitivity cases were then
developed to aid in understanding some of the downside risks of operating
generation assets. The cases presented herein are:
- - HIGH FUEL: an upward shift in prices of oil and gas
- - LOW FUEL: a downward shift in prices of oil and gas
- - OVERBUILD: the potential for generation capacity overbuild in the Northeast
region resulting from market over exuberance
- - HIGH HYDRO: the possibility of surplus energy and capacity resulting from
above average hydro conditions in the WSCC region.
These variances from the base case influence the resulting projections of market
price forecasts and subsequent valuation of generation plants. More detailed
descriptions of each of these sensitivity cases analyzed by PA are provided
below. It should be noted that the level of the sensitivities can vary and that
there are other areas that can vary in the forecast including, but not limited
to: demand forecasts, new entrant technologies and construction costs,
environmental costs and regulatory structures.
2.2.1 HIGHER OR LOWER FUEL PRICES
Currently the markets are experiencing high natural gas and fuel oil prices.
There has also been a tremendous amount of volatility in prices over the past
couple of years. Three years ago gas prices were around $2.00/MMBtu, whereas
this year they have exceeded $8.00/MMBtu. As a result of the fluctuation in
prices, PA created cases for the possibility of higher or lower fuel prices with
an increase or decrease of fuel prices. The high fuel case assumed that the 2001
NYMEX futures prices for gas and oil were held constant, on a real basis, for
the study period. The low fuel price assumed a $0.50/MMBtu reduction from the
base case in 2001 for gas and oil with the same real escalation rates used in
the base case.
2.2.2 OVERBUILD
PA's forecast of market prices is based upon long-run economic equilibrium.
While this is a reasonable assumption, actual markets may not follow economic
equilibrium. Many capital intensive industries have shown cycling returns, where
high returns are followed by excess entry resulting in low returns. These low
returns are followed by a disincentive to invest which results in high returns.
While such cycling is often a characteristic of commodity markets, these markets
are, in general, attempting to adjust to a level commensurate with economic
equilibrium - that is, they cycle around the price level suggested by economic
equilibrium.
PA constructed an overbuild case in the Northeast where excess entry is presumed
in order to explore the adverse economic implications of such "disequilibrium"
conditions. The Northeast was selected as PJM and NPCC make up almost 75% of the
forecasted portfolio revenues (see Figure 1-2). For purposes of this case,
excess entry is presumed to occur early in the study period in the Northeast
markets. In the development of this case, PA assumed an additional 2,080 MW and
4,160 MW of
2-1
new capacity in 2004 in New York and PJM respectively. New England exceeds
the target reserve margins in the base case; however, an additional 1,040 MW
of capacity was added in 2004. Subsequent to this period of capacity
abundance, as the regions experience load growth, we assume the markets
eventually return to economic equilibrium.
2.2.3 HIGH HYDRO
The hydro case was conducted for the WSCC region. During the assumed high hydro
years, the amount of hydro energy available is significantly higher, depressing
capacity and energy prices. In the high hydro sensitivity analysis, we increase
hydro generation from existing hydro capacity by approximately 20% for the years
2001 to 2004.
2.3 OVERVIEW OF THE REGIONAL MARKETS
Competition and deregulation is progressing piecemeal in the United States and
there are significant differences between regions. These differences are largely
due to the division of authority over various aspects of the electric power
industry between state and federal legislative and regulatory bodies.
Competition in the wholesale markets is, in part, defined and shaped by the
North American Electric Reliability Council (NERC) regions. There are nine major
regions. WSCC, the biggest geographic region, is subdivided into four regions.
In the Northeast, the NPCC region is subdivided into two regions (New York and
NEPOOL). Figure 2-1 shows the boundaries of the major regions, along with MAGI's
generation capacity in each of these regions. The remainder of this chapter
reviews the regions where the MAGI assets are located.
2.4 RETAIL MARKET COMPETITION
Competition in the retail markets has not been a major force to date due to a
combination of checkerboard adoption of competition and the relatively low
number of customers selecting non-utility companies as their energy service
provider. However, the recent events in California have caused many states to
delay implementation. For example, New York, Nevada, Oklahoma, and Arkansas are
considering formal proposals to delay retail competition and New Mexico has
recently passed such legislation.
The remaining sections of this chapter provide descriptions of the current power
market structure in each of the relevant NERC regions and a brief description of
the region's characteristics. Results for each region follow the summaries. Our
discussion of WSCC is limited to the California region while NPCC has been
subdivided into New York and NEPOOL.
FIGURE 2-1
MAGI ASSETS IN GENERATION PORTFOLIO BY NERC REGION
[GRAPH]
2-2
2.5 PJM
2.5.1 BACKGROUND
PJM is the only control region in the Mid-Atlantic Area Council. It covers
all or part of the states of Pennsylvania, New Jersey, Maryland, Delaware,
Virginia, and the District of Columbia. Its members include investor-owned
utilities (IOUs), public utilities, independent power marketers, and
regulators. PJM was the first centrally dispatched power pool in the United
States and is currently the largest, handling about 8% of the electricity in
the United States with a combined capacity of over 56,000 MW. In addition, it
is one of the largest power pools in the world. A map of the PJM area and
location of the financing generation assets is shown in Figure 2-2. The focus
of this report is the location of the MAGI assets, the PJM-Central region
which includes Allegheny Electric Cooperative, Inc., Baltimore Gas & Electric
Company, Metropolitan Edison Company, Pennsylvania Power & Light Company,
Potomac Electric Power Cooperative, Southern Maryland Electric Cooperative,
and UGI Corporation.
Figure 2-2
PJM Region
[GRAPH]
Figure 2-3
PJM Energy - Year 2001
[GRAPH]
Figure 2-4
PJM Capacity - Year 2001
[GRAPH]
PJM was certified as an ISO by the Federal Energy Regulatory Commission
(FERC) on November 25, 1997, and it began operations on April 1, 1998. PJM's
stated objectives are to ensure reliability of the bulk power transmission
system and to facilitate an open, competitive wholesale electricity market.
To achieve these objectives, PJM manages the PJM Open Access Transmission
Tariff (the first power pool open access tariff approved by FERC), which
provides comparative pricing and access to the transmission system. PJM
operates the PJM Interchange Energy Market, which is the region's spot market
(power exchange or PX) for wholesale electricity. PJM also provides ancillary
services for its transmission customers and performs transmission planning
for the region.
The relative mix of the energy generation and capacity in PJM is illustrated
in Figures 2-3 and 2-4. Coal dominates the baseload generation in PJM,
accounting for 52% of the total energy produced. Nuclear units also comprise
a large portion of the
2-3
energy produced in PJM, accounting for 39% of the total energy produced. On
an installed capacity basis, gas- and oil-fired generation units represent
37% of PJM's total installed capacity, while coal represents 32% of PJM's
total installed capacity. Nuclear facilities account for 22% of PJM's
installed capability.
2.5.2 POWER MARKETS
A. MARKETS
The PJM wholesale market structure includes the following markets for the
services of generators:
i. Energy Market
ii. Day-Ahead Market
iii. Balancing Market (Real Time)
iv. Regulation Market
v. Capacity Credit Market
vi. Daily Market Operation
vii. Monthly Market Operation
viii. Fixed Transmission Rights.
Until recently, payments for providing ancillary services were grounded in
cost-based formulas. PJM has now implemented new market-based pricing for the
ancillary services. Payments for providing operating reserves are included in
daily energy market reconciliation.
Load Serving Entities (LSEs) have the obligation to provide or acquire
installed capacity, regulation, and operating reserves. In addition to PJM
market purchases, bilateral transactions are also allowed. While bilateral
transactions are not subject to the market-clearing prices, they are subject
to the same charges for transmission congestion included in the
market-clearing prices.
Generators are compensated for providing energy and ancillary services
through the PJM PX as follows:
o Locational Marginal Prices (LMPs) are determined based on the applicable
energy bids.
o Regulation prices that generators receive are based on their Unit
Regulation Offer and estimated opportunity cost for being available for
regulation.
o Energy imbalance and operating reserves are compensated according to bids
submitted to the PJM PX.
o Other ancillary services are compensated based on cost.
o Any shortfall payments continue to be determined based on the difference
between total revenue and total revenue requirement.
i. ENERGY MARKET
On June 1, 2000, PJM implemented a new system for its interchange Energy
Market. PJM's Energy Market has been converted from a real-time transaction
market into a dual settlement operation. The new market is split into
essentially two pieces: The Day-Ahead Market and the Balancing (Real-time)
market.
ii. THE DAY-AHEAD MARKET
The advantage of this new system is that it allows participants to achieve
greater price certainty by being able to buy and sell energy and capacity at
binding day-ahead (future) prices. It also allows for the scheduling of
congestion charges a day in advance. Bilateral agreements will also be able
to schedule congestion charges in the Day-Ahead Market. The congestion
charges can be calculated by taking the difference in LMP between the load
bus and generation bus.
LSEs submit hourly demand schedules for the next day. All bids and offers
must be made by noon the day before the day of operations. By 16:00, all
prices are posted and the real-time market bidding is then opened.
Generators must submit their schedules if they are capacity resources, unless
they are self-scheduled or have planned outages. All other generators can bid
into the market as they wish. The PJM ISO will calculate, based on bids,
offers and market conditions, the LMPs for each hour of the day.
A bid to supply generation consists of an incremental energy bid curve
composed of three parts: start-up costs, no load costs, and operating costs.
For each generation level, the bid curve represents the minimum price a
bidder is willing to accept to be dispatched at the generation level. The bid
curve is specified by up to 10 price-quantity pairs.
iii. THE BALANCING MARKET (REAL-TIME)
After all bids and offers are settled and the marginal prices have been
calculated, generators that were not used can bid into this market at new
prices. Prices are again determined by market conditions.
2-4
Essentially because the actual demand that will occur in real time is not
known the previous day, scheduled generation will often differ from actual
generation dispatch and so the balancing market corrects for the differences.
LSEs will pay balancing prices for any unscheduled demand and receive revenue
for demand less than the scheduled quantity from the Day-Ahead Market.
Generators will be paid for generation above their scheduled obligations at
balancing prices and are not compensated for unused generation. Transmission
customers pay for congestion charges for any quantity deviations.
Transmission customers may submit external bilateral transaction schedules
and may indicate willingness to pay congestion charges into either the
Day-Ahead Market or Balancing Market. In the Day-Ahead Market, a customer
shall indicate willingness to pay congestion charges by submitting the
transaction as an "up to" congestion bid.
In the past, bids into the market were capped at cost. Thus, generators
bidding into the market were forced to cap their energy bid at the marginal
operating cost of producing energy, which would generally consist of fuel
costs plus variable operation and maintenance costs. The start-up cost bid
was capped at the costs, mostly fuel costs, incurred to bring a generator
online. The no load cost bid, also mostly fuel costs, was capped at the costs
incurred to maintain a generator at minimum load after it had been started
and synchronized with the system. Any shortfall between the revenue
requirement of the generator and the revenue received through the market was
compensated through a make whole payment.
On April 1, 1999, the spot market replaced its cost-based pricing system with
a market-based pricing approach, and starting June 2000 the spot market was
switched to the Two-Settlement Market. Generators continue to provide
three-part bids, but these bids are not necessarily capped at cost. While
bids are no longer capped at cost, they are subject to a $1,000/MWh ceiling
cap. The PJM PX bidding rules allow generators to submit different energy
bids for each hour, and generators can submit a new set of bids daily.
However, a generator's start-up and no-load bids, once submitted, remain in
effect for six months at a time.
PJM also uses the energy bids to determine in real time the LMPs for each
point of energy injection/withdrawal on the system for each hour. LMPs
reflect the costs associated with the out-of-order dispatch due to
transmission congestion. Congestion occurs when the transmission system
becomes constrained, and some generating capacity is dispatched while other
generating capacity with lower bids is not dispatched. The result is that the
market-clearing prices may differ from location to location. LMPs are quoted
in dollars per megawatt-hour ($/MWh) and are based on bids for generation,
actual loads, scheduled bilateral transactions, and transmission congestion.
iv. REGULATION MARKET
PJM has just created a market for providing regulation of the system. For
these units made available to meet performance standards and the short-term
load fluctuations in the PJM control area they are now able to realize
benefits above their opportunity costs for being a regulating generator. To
be eligible for regulation, generators must be within the PJM control area.
Information about regulating status, capability, limits, and price (capped at
$100/MWh) applicable for the entire 24 hour period for which it is submitted,
must be provided by 18:00 through the Two-Settlement Market User Interface
(MUI). The offer of the last unit needed to fulfill the MW regulation
requirement (the marginal unit) will set the market price for that hour.
The PJM Regulation Requirement is 1.1% of the day-ahead peak load forecast
for the on-peak period and the valley load forecast for the off-peak period.
LSEs may fulfill their regulation obligations by self-scheduling their own
resources, entering into contractual arrangements with other market
participants, or purchasing regulation from the regulation market just
described. The regulation obligation for each LSE is determined by its load
ratio share.
v. CAPACITY CREDIT MARKET
To ensure that sufficient capacity is available in the market to meet
reliability standards, PJM requires LSEs to own or contract with the owner of
generation capacity to cover their peak demand and reserve margins.
There are two capacity obligations. An LSE's installed capacity obligation is
determined two years in advance by PJM based on forecast conditions. This
obligation remains in place and is known as the "planned-for" obligation. The
"planned-for" obligation is then adjusted for actual conditions. This
adjusted obligation is known as the "accounted-for" obligation.
The amount of capacity each generator can supply is determined by a
twelve-month rolling average of
2-5
availability, calculated two months in advance of the period for which the
capacity is supplied. Availability statistics are kept by PJM. These
statistics are averaged over the past twelve months and applied to the
"planned-for" obligation two months hence.
External resources may be designated as resources to meet the capacity
requirement. These resources, however, must: (1) be rated on the extent to
which they improve the ability of the PJM pool to obtain emergency assistance
from other control areas and (2) be made available to PJM for scheduling and
dispatch. Should the resource not be made available to PJM, it adversely
affects the resource's availability rating. If an LSE fails to meet its
capacity requirement, a penalty will be assessed.
The PJM Capacity Credit Market allows Market Participants to buy and sell
Capacity Credits through a process that establishes a market-clearing price.
Capacity acquired in the Capacity Credit Market satisfies the "accounted-for"
obligation. The PJM Capacity Credit Market consists of both the Daily and
Monthly Markets. Each installed capacity market has a single market-clearing
price for each day the market is in operation.
vi. DAILY MARKET OPERATION
The Daily Market is a Day-Ahead Market (i.e., the bids are for the following
day). Currently, a mandatory aspect to the Day-Ahead Market is in effect. If
a participant does not submit adequate "bids to buy" or "offers to sell" to
cover its projected deficient or excess position, PJM will submit a
corresponding "bid" or "offer" to cover the projected position. Mandatory Buy
Bids will be submitted at a price equal to the prevailing Capacity Deficiency
Rate.
Buy Bids or Sell Offers are accepted between 7:00 and 10:00 on the day the
market is run. PJM strives to clear the market and post market results by
12:00 on the day the market is run.
The Daily Market is conducted based on the position of a participant for the
market day estimated at 10:05 on the day the market is run. If a participant
has a deficient position, PJM will only accept buy bids up to the deficiency
amount. If a participant has an excess position, PJM will only accept sell
offers up to the excess amount. Buy Bids or Sell Offers are accepted into the
Daily Market in order of time submitted.
vii. MONTHLY MARKET OPERATION
In addition to the Daily Market, the Capacity Credit Market currently
operates both Monthly and Multi-Monthly Markets. These Monthly Markets are
voluntary, and participants may submit Buy Bids and Sell Offers in the same
market.
Similar to the Daily Market, Buy Bids and Sell Offers are accepted between
7:00 and 10:00 on the day that the market accepts bids. PJM strives to clear
the market and post market results by 12:00 on the same day. On three
scheduled days each month, Monthly Market bids are accepted for the three
respective succeeding months. There are currently two Multi-Monthly Markets,
a seven-month and a twelve-month. Multi-Monthly Market bids are accepted on a
scheduled day approximately four months prior to the beginning of the
multi-monthly period.
viii. FIXED TRANSMISSION RIGHTS
Fixed Transmission Rights (FTRs) are available to all PJM Firm Transmission
Service customers (Network Integration Service or Firm Point-to-Point
Service), since these customers pay the embedded cost of the PJM Transmission
System. The purpose of FTRs is to protect Firm Transmission Service customers
from increased cost due to transmission congestion when their energy
deliveries are consistent with their firm reservations. Essentially, FTRs are
financial instruments that entitle Firm Transmission customers to rebates of
congestion charges paid by the Firm Transmission Service customers. FTRs do
not represent a right for physical delivery of power. The holder of the FTR
is not required to deliver energy in order to receive a congestion credit. If
a constraint exists on the transmission system, the holders of FTRs receive a
credit based on the FTR MW reservation and the LMP difference between point
of delivery and point of receipt. This credit is paid to the holder
regardless of who delivered energy or the amount delivered across the path
designated in the FTR.
In July 1999, the first financially binding FTR auction was held in PJM.
Participants are now able to view all prices and constraints on the Internet
at the eFTR. Prices are set on the first of every month and their values are
determined based on day-ahead LMPs between generation and load busses. Each
monthly period has an auction for both the trading of FTRs for On-peak and
Off-peak periods in the week. On-peak times are from 7:00 to 23:00, Monday
through Friday, and off-peak times include all other hours and weekends.
2-6
B. STATE RESTRUCTURING STATUS
Most of the states in PJM have already begun to enact retail competition. Due
to its multi-state structure, PJM has dealt with restructuring piecemeal as
opposed to the California ISO (CA-ISO). Each state has authority to decide on
rate reductions, stranded cost recovery, and generation asset divesting. PJM
is far ahead of many of the Midwest NERC regions in implementing retail
competition and having utilities sell off their generation assets. A summary
of the restructuring status by state follows.
i. DELAWARE
In March 1999, the "Electric Utility Restructuring Act" (HB 10) was enacted.
The law included a phase in of retail competition beginning in October 1999
that is supposed to be completed by April 2001 for all consumers in
Conectiv's and Delaware Cooperative's territories. In addition, there are
provisions for a residential rate cut of 7.5% for Conectiv customers and a
rate freeze for the co-op customers. No provisions for stranded cost recovery
were included; however, the issue was left up to the Public Service
Commission (PSC). The PSC decided to allow recovery of the stranded costs
through Competitive Transition Charges.
ii. MARYLAND
In April 2000, Maryland's restructuring legislation was enacted (HB 703). The
legislation included at least a 3% rate reduction for residential consumers,
and a three year phase in for competition scheduled to begin in July 2000 and
be completed by July 2002. Stranded costs are to come from a "non-bypassable"
wires charge.
Baltimore Gas & Electric, Potomac Electric Power Company, and Allegheny Power
had their electric restructuring agreements approved by the Maryland Public
Service Commission (PSC) at the beginning of 2000. Upon the opening of retail
access across Maryland, standard offer rates for generation went into effect on
July 1, 2000. Standard offer rates for residential consumers at Allegheny Power
were 4.34 cents/kWh; Conectiv's were 4.92 cents/kWh; Potomac Electric Power's
were 4.99 cents/kWh; and Baltimore Gas & Electric's were 4.06 cents/kWh, rising
to 4.28 cents/kWh by May 2003.
iii. NEW JERSEY
Legislation on restructuring was introduced in August 1998 under the "Electric
Discount and Energy Competition Act." The law passed in February 1999 stated
that all consumers should have the choice of electricity suppliers by August
1999. Actual implementation of the retail market did not open until November 14,
1999. The law reduced current rates at that time by 5% and over the next three
years it is supposed to decrease 10%. Stranded Cost recovery is in the form of a
wires charge paid by consumers. The law does not require divestiture of
generation assets, but would give the Board of Public Utilities the right to
order divestiture if market power exists.
As of August 1, 2000, the Board of Public Utilities (BPU) reported that 73,133
of the state's 3.1 million residential customers had switched suppliers. About
410,886 commercial and industrial consumers had switched suppliers.
Approximately 13.5% of the power load in New Jersey was supplied by alternative
retail suppliers at the time.
iv. PENNSYLVANIA
Pennsylvania enacted a retail competition plan under the "Electricity Generation
Customer Choice and Competition Act of 1996". This act will phase in full retail
access for all customer classes between 1999 and 2001. Transmission and
distribution rates are capped through June 2001. Generation rates are capped
until December 31, 2005. The Public Utility Commission (PUC) requires suppliers
to own or purchase (from utilities only) installed capacity (guaranteed access
to supply). Utilities cannot be forced to sell the capacity, but the PUC holds
that if they do, they cannot charge more than the price agreed upon in their
restructuring plans ($19.72 per kW-year).
In January 2001, The Pennsylvania Office of Consumer Advocate reported number of
conversions to an alternative generation supplier. As of January 1, 2001, over
568,000 consumers were receiving power from suppliers other than the incumbent
utility. PECO Energy Company reported 46% of its industrial load, 33% of
commercial load, and 16% of residential load have switched. GPU Energy reported
16% of industrial load and 10% of commercial load have switched, while Duquesne
Light Company reported 34% of residential load has switched. In August 2000, a
Pennsylvania Department of Revenue report to Governor Ridge and the General
Assembly projected that electric competition will create more than 36,000 new
jobs in the state by 2004. The report states that
2-7
the success of electric competition will lead to new jobs because related
savings give customers more money to spend, creating a multiplier effect in
the state economy, reducing business costs, and allowing employers more money
to invest.
In January 2001, as required under PECO's restructuring plan, 300,000
residential customers that had not chosen a competitive supplier were randomly
chosen and switched to an alternate provider.
Utilities have been selling off interests in generation plants across the
state, eliminating most of their stranded costs and reducing customer bills.
Many of the utilities are already active in marketing electricity across the
PJM area.
2.5.3 MARKET DYNAMICS
MAGI's assets evaluated in this report include four existing plants
representing 5,154 MW of capacity that participate in the PJM wholesale
electric markets. Figure 2-5 illustrates the load and resource balance for
PJM through the end of the study period. During the period of 1991-2000, peak
demands have grown at an average annual rate of 1.8%. The PJM market is
forecasted to grow at an annual compound rate of approximately 1.45% per year
from 2001 through 2020. A required system-wide reserve margin of 18% is
assumed through 2001. Subsequent to 2001, the system-wide reserve margin is
assumed to be 15% as PA believes the market will mature and the required
reserve margins will be lowered. The graph illustrates that approximately 18
GW of new generation is required to meet load growth and reserve margins over
the 20 years. There are no significant capacity retirements anticipated in
the near term.
Historical prices for PJM are presented in Appendix A.
2.5.4 TRANSMISSION SYSTEM
In response to FERC Order 888, the members of the PJM Power Pool developed a
restructuring proposal and a pool-wide open-access tariff. This restructuring
proposal created an ISO to operate the regional bulk power system, maintain
system reliability, administer specified electricity markets, and facilitate
open access to the regional transmission system under the PJM tariff. The PJM
electricity market uses market pricing for various generation services,
thereby facilitating the development of a competitive bid price wholesale
electricity market.
PJM is a "fully functional" Regional Transmission Organization (RTO). It is
the security coordinator and control area operator for the PJM region, the
transmission provider responsible for all scheduling, dispatch, and ancillary
services for transmission customers, and is responsible for all regional
transmission planning. Transmission owners are required to transfer operation
of their assets over to
Figure 2-5
PJM Load and Resource Balance
[GRAPH]
the RTO. PJM operates under an ISO structure as opposed to a Transco. The ISO
is completely free of interests in all market participants, including
generation and transmission owners.
RTO characteristics and functions that PJM incorporates include: independent
operation of the generation market participants, regional scope, authority to
administer reliability requirements for the grid, pricing, congestion
management, and open access same-time information system (OASIS) management.
2-8
2.5.5 PRICE FORECASTS FOR THE PJM MARKET
A. BASE CASE
This case models near-term fuel prices (gas and oil) based on recent actual
spot prices and futures prices through December 2003, decreasing linearly to
the long-term consensus view by 2005.
The all-in price represents a combined compensation for capacity and energy
price (assuming a 100% load factor). The compensation for capacity contribution
to the all-in price ranges between approximately $6.00/MWh and $7.90/MWh.
FIGURE 2-6
PJM-CENTRAL BASE CASE COMPENSATION
FOR CAPACITY, ENERGY, AND ALL-IN PRICE FORECASTS(1)
[GRAPH]
The base case compensation for capacity, energy, and all-in market price
forecasts are presented in Figure 2-6 and Table 2-1 for the PJM-Central pricing
area.
In addition to the fundamental numbers reported in Table 2-1, PA used monthly
average daytime electricity forwards for 2001-2003. The monthly electricity
price forwards for 2001-2003 used in the volatility forecast for the PJM region
are listed in Appendix A. For the period 2004-2020, the volatility results were
calibrated to the fundamental results shown in Table 2-1.
- -----------------------------------------------------------
TABLE 2-1
PJM-CENTRAL BASE CASE FORECASTS(1)
FUNDAMENTAL ANALYSIS
- -----------------------------------------------------------
YEAR COMPENSATION ENERGY ALL-IN
FOR CAPACITY PRICE PRICE(2)
($/KW-YR) ($/MWH) ($/MWH)
- ------------- ----------------- ------------- -------------
2001(3) 69.20 29.60 37.50
- ------------- ----------------- ------------- -------------
2002(3) 52.60 27.60 33.60
- ------------- ----------------- ------------- -------------
2003(3) 52.60 28.10 34.10
- ------------- ----------------- ------------- -------------
2004 52.70 25.90 31.90
- ------------- ----------------- ------------- -------------
2005 60.50 24.00 30.90
- ------------- ----------------- ------------- -------------
2006 65.50 24.20 31.60
- ------------- ----------------- ------------- -------------
2007 65.80 24.00 31.50
- ------------- ----------------- ------------- -------------
2008 65.40 24.10 31.60
- ------------- ----------------- ------------- -------------
2009 64.80 24.40 31.80
- ------------- ----------------- ------------- -------------
2010 64.30 24.80 32.20
- ------------- ----------------- ------------- -------------
2011 63.80 24.60 31.90
- ------------- ----------------- ------------- -------------
2012 63.30 24.50 31.70
- ------------- ----------------- ------------- -------------
2013 62.70 24.60 31.80
- ------------- ----------------- ------------- -------------
2014 62.20 24.60 31.70
- ------------- ----------------- ------------- -------------
2015 61.70 24.70 31.70
- ------------- ----------------- ------------- -------------
2016 61.20 24.70 31.70
- ------------- ----------------- ------------- -------------
2017 60.80 24.80 31.80
- ------------- ----------------- ------------- -------------
2018 60.30 25.00 31.80
- ------------- ----------------- ------------- -------------
2019 59.80 25.10 31.90
- ------------- ----------------- ------------- -------------
2020 59.30 25.40 32.10
- -----------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
(2) Calculated based on 100% load factor.
(3) 2001-2003 volatility results are calibrated to the forwards prices versus
the model results presented herein.
- -----------------------------------------------------------
2-9
B. SENSITIVITY CASES ANALYSIS
A comparison of the all-in prices for three of the sensitivity cases and the
base case described in Section 2.2 are shown in Figure 2-7 and Table 2-2 for
the PJM-Central pricing area. The base case projections decrease initially as
new merchant plants come on-line and gas prices decrease to the consensus
forecast. The high fuel case results in substantially higher all-in prices
over time, as much as $14/MWh, as more gas units move on the margin for a
greater number of hours. The low fuel case results in lower all-in prices by
$1/MWh to $2/MWh. The overbuild case depresses prices in the 2004 to 2010
timeframe, after which the Northeast region recovers from the overbuild case.
FIGURE 2-7
PJM-CENTRAL SENSITIVITY CASES
ALL-IN PRICE FORECASTS ($/MWH)
[GRAPH]
- -----------------------------------------------------------
TABLE 2-2
PJM-CENTRAL SENSITIVITY CASES
ALL-IN PRICE FORECASTS(1) ($/MWH)
- -----------------------------------------------------------
YEAR BASE CASE HIGH LOW OVERBUILD
FUEL FUEL
- ----------- ----------- ---------- ----------- ------------
2001 37.50 37.50 35.70 37.50
- ----------- ----------- ---------- ----------- ------------
2002 33.60 35.50 32.60 33.60
- ----------- ----------- ---------- ----------- ------------
2003 34.10 36.80 32.70 34.10
- ----------- ----------- ---------- ----------- ------------
2004 31.90 37.00 30.90 29.80
- ----------- ----------- ---------- ----------- ------------
2005 30.90 37.60 30.20 27.10
- ----------- ----------- ---------- ----------- ------------
2006 31.60 40.10 30.30 27.60
- ----------- ----------- ---------- ----------- ------------
2007 31.50 40.20 30.20 28.60
- ----------- ----------- ---------- ----------- ------------
2008 31.60 40.70 30.30 30.10
- ----------- ----------- ---------- ----------- ------------
2009 31.80 41.70 30.20 30.80
- ----------- ----------- ---------- ----------- ------------
2010 32.20 42.80 30.30 31.10
- ----------- ----------- ---------- ----------- ------------
2011 31.90 43.50 30.10 31.40
- ----------- ----------- ---------- ----------- ------------
2012 31.70 43.70 30.10 31.10
- ----------- ----------- ---------- ----------- ------------
2013 31.80 43.70 30.10 31.10
- ----------- ----------- ---------- ----------- ------------
2014 31.70 44.40 29.90 31.10
- ----------- ----------- ---------- ----------- ------------
2015 31.70 45.10 29.90 31.20
- ----------- ----------- ---------- ----------- ------------
2016 31.70 45.20 29.90 31.20
- ----------- ----------- ---------- ----------- ------------
2017 31.80 45.50 30.00 31.30
- ----------- ----------- ---------- ----------- ------------
2018 31.80 45.70 30.00 31.50
- ----------- ----------- ---------- ----------- ------------
2019 31.90 45.50 30.00 31.40
- ----------- ----------- ---------- ----------- ------------
2020 32.10 46.10 30.20 31.50
- -----------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
- -----------------------------------------------------------
2-10
2.5.6 DISPATCH CURVES
The dispatch curves for 2001 and 2010 are shown in Figure 2-8. These curves
order generation plants based upon short run variable cost (fuel and O&M).
The relative ranking of the MAGI plants are included on the graphs.
FIGURE 2-8
PJM DISPATCH CURVES FOR 2001 AND 2010
[GRAPH]
[GRAPH]
2-11
2.6 MAIN/ECAR
2.6.1 BACKGROUND
The MAIN region includes Illinois and parts of Missouri, Wisconsin, and
Michigan. The area served over 19 million customers and accounted for over
240,000 GWh of electric generation in 1999. There is a lack of widespread
pooling of generation or transmission in the MAIN region. MAIN is a
relatively small transmission region in terms of both geographical scope and
wholesale market size. MAIN has a financial market hub for trading
electricity futures. The ComEd futures hub is operated by the Chicago Board
of Trade and provides a mechanism for hedging Midwest electricity contracts.
In addition, the Automated Power Exchange is implementing a regional spot
market for electricity in Illinois. A map showing the MAIN and ECAR regions
and the location of the generation assets being financed is shown in Figure
2-9.
The ECAR region is one of the largest regional electricity markets in the
United States. ECAR is comprised of electric utility systems covering part or
all of the following states: Indiana, Kentucky, Maryland, Michigan, Ohio,
Pennsylvania, Virginia, and West Virginia. The ECAR market is dominated by
several large, vertically integrated utilities including Allegheny Power,
American Electric Power Company, FirstEnergy, Cinergy, NiSource, CMS, Detroit
Edison, and LG&E Energy Corp. These utilities have not historically
coordinated transmission, dispatch or market operations on a widespread
scale. Limited areas, such as the Michigan Electric Coordinating System, have
provided joint utility generation dispatch, but as a whole, the ECAR region
has historically not attempted to coordinate the market through a power pool
structure. However, the spread of retail competition to several of the states
in the ECAR region through both regulatory orders and legislative acts is now
prompting the development of more structured transmission and energy markets
to ensure fair competition.
FIGURE 2-10
MAIN ENERGY - YEAR 2001
[GRAPH]
FIGURE 2-11
MAIN CAPACITY - YEAR 2001
[GRAPH]
FIGURE 2-9
GENERATION ASSETS IN THE MAIN/ECAR REGION
[GRAPH]
As illustrated in Figures 2-10 and 2-11, MAIN is largely dependent on
coal-fired and nuclear resources for baseload generation. Coal-fired
generation is the predominant resource in terms of both installed capacity
and energy production in MAIN, accounting
2-12
for 45% of the capacity in the region and 63% of the energy produced. Nuclear
facilities account for 20% of the installed capacity and produce 34% of the
energy in the region. Gas- and oil-fired generation make up 29% of the
installed capacity, but represent only 2% of the region's energy production.
This indicates that nearly all of the gas- and oil-fired generation is
utilized for peaking.
The energy generation and capacity in the ECAR market is dominated by
coal-fired generation. Gas- and oil-fired units comprise 15% of ECAR's
capacity, yet are only used for 1% of ECAR's energy production. This
indicates that most of the gas- and oil-fired generation is utilized for
peaking.
2.6.2 POWER MARKETS
The MAIN wholesale market is informally organized and characterized by
largely informal market arrangements with the majority of power sold through
bilateral agreements, not a power exchange or some other formal marketplace.
Short and long-term bilateral contracts typically include both an energy and
capacity payment. In 1996, MAIN adopted a policy suggesting its companies
maintain a minimum reserve of 17-20% for long-term planning, but there is no
strong mechanism currently in place forcing utilities in MAIN to meet these
requirements.
FIGURE 2-12
MAIN LOAD AND RESOURCE BALANCE
[GRAPH]
While there is no formalized market structure in place, MAIN is rapidly
progressing toward the formation of an ISO. It will serve the purpose of
managing regional transmission assets and establishing spot market trading
centers to serve as regional marketplaces. However, it should be noted that
there are a variety of market models that are currently being pursued in this
region.
The energy market in ECAR is also informally organized, relying extensively
on bilateral agreements. While the ECAR region lacks a formalized power
exchange, a subregional power exchange was initiated in the First Energy
region in July 1999. In addition, there is a financial market at the Cinergy
hub managed by the New York Mercantile Exchange (NYMEX) for trading futures
and options contracts for the purpose of electricity price hedging.
2.6.3 MARKET DYNAMICS
MAGI assets included in this report include one new generation plant, Neenah,
that will sell power into the MAIN market and an existing plant, State Line,
that will sell into the MAIN/ECAR markets. Figure 2-12 shows the projected
load and resource forecast for the MAIN region. Forecasted average annual
load growth in MAIN is 1.4% for the study period as
2-13
compared to the historical average annual load growth of 1.7% for the last
decade. Forecasted average annual load growth in ECAR is 1.6% for the study
period. This is consistent with the historical average annual load growth of
1.6% for the last decade.
Net capacity additions for the MAIN and ECAR regions are forecasted to be
12.8 GW and 40.1 GW respectively, over the next twenty years. Details for the
MAIN region capacity additions are provided in Section 4.5.
Historical prices for MAIN/ECAR are presented in Appendix A.
2.6.4 TRANSMISSION SYSTEM
Most of the utilities in MAIN, as well as some from Mid-continent Area Power
Pool (MAPP) and ECAR have filed and gained approval from FERC to establish a
Midwest ISO to operate and manage the transmission assets in the region. The
Midwestern states are cautiously moving along in the development of the ISO's
structure not wanting to repeat mistakes made in California.
Currently ECAR utilities offer "open access" to their individual high voltage
transmission lines as mandated by FERC Order 888. Transmission tariffs are
specific to each transmission system owner with a "pancaking" of individual
rates for moving power across systems. The "pancaking" of rates makes it
uneconomical to wheel power very far in such a system and is considered a
significant market barrier to greater competition at both the retail, and
wholesale level. In order to support retail and wholesale competition, FERC
has made the elimination of "pancaked" rates one of the principles in its
requirements for registration of new RTOs.
Most of the region's utilities are just beginning to explore new market
structures, such as the creation of a regional ISO. Dominion Resources has
joined the Alliance Regional Transmission Organization (Alliance RTO), an ISO
variant comprised mainly of utilities in ECAR. The Alliance RTO is the most
likely candidate for utilities choosing to join an RTO in the ECAR region.
2-14
2.6.5 PRICE FORECASTS FOR THE MAIN MARKET
A. BASE CASE
All-in prices are anticipated to remain relatively constant over the
twenty-year planning period. The forecasts of energy prices, capacity
compensation, and all-in prices for the base case are shown in Figure 2-13
and Table 2-3 for the two areas in MAIN where the MAGI assets are located -
Wisconsin Upper Michigan (WIUM) and Commonwealth Edison (CECO). WIUM includes
Consolidated Water Power Company, Madison Gas and Electric Company, Upper
Peninsula Power Company, Wisconsin Electric Power Company, Wisconsin Power
and Light Company, Wisconsin Public Power In., Wisconsin Public Service
Corporation, and Wisconsin River Power Company, as well as several smaller
city light and power departments.
- ---------------------------------------------------------------
TABLE 2-3
MAIN BASE CASE FORECASTS(1)
FUNDAMENTAL ANALYSIS
- ---------------------------------------------------------------
MAIN-WIUM MAIN-CECO
COMP. FOR ------------------------------------------
CAPACITY ENERGY ALL-IN ENERGY ALL-IN
YEAR ($/KW-YR) ($/MWH) ($/MWH) ($/MWH) ($/MWH)
- ---------------------------------------------------------------
2001 19.40 26.40 28.60 22.40 24.60
- ---------------------------------------------------------------
2002 13.40 25.50 27.10 24.20 25.70
- ---------------------------------------------------------------
2003 17.90 26.40 28.40 24.90 27.00
- ---------------------------------------------------------------
2004 21.30 24.60 27.10 23.00 25.40
- ---------------------------------------------------------------
2005 32.80 23.70 27.40 21.20 24.90
- ---------------------------------------------------------------
2006 34.70 23.70 27.70 21.50 25.40
- ---------------------------------------------------------------
2007 53.30 23.90 30.00 21.30 27.40
- ---------------------------------------------------------------
2008 58.00 23.40 30.00 21.30 27.90
- ---------------------------------------------------------------
2009 60.00 23.30 30.20 21.10 28.00
- ---------------------------------------------------------------
2010 59.50 22.10 28.90 21.50 28.30
- ---------------------------------------------------------------
2011 59.00 22.00 28.70 21.50 28.20
- ---------------------------------------------------------------
2012 58.60 22.10 28.70 21.80 28.50
- ---------------------------------------------------------------
2013 58.10 21.70 28.30 22.10 28.70
- ---------------------------------------------------------------
2014 57.10 22.90 29.40 22.30 28.80
- ---------------------------------------------------------------
2015 56.50 23.10 29.60 22.40 28.80
- ---------------------------------------------------------------
2016 54.80 23.30 29.60 22.60 28.90
- ---------------------------------------------------------------
2017 55.50 23.10 29.40 23.00 29.30
- ---------------------------------------------------------------
2018 53.50 23.30 29.40 23.20 29.30
- ---------------------------------------------------------------
2019 52.70 23.70 29.70 23.60 29.60
- ---------------------------------------------------------------
2020 52.90 23.80 29.80 23.60 29.70
- ---------------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
- ---------------------------------------------------------------
The price projections for the MAIN pricing areas are influenced by activities in
the ECAR region. The model used to generate the price projections incorporates
all of the midwest NERC regions. Due to the close proximity of MAIN to ECAR,
activities in ECAR do influence price projections in MAIN and their effects are
incorporated in the MAIN price forecasts that are provided.
FIGURE 2-13
MAIN BASE CASE COMPENSATION
FOR CAPACITY, ENERGY, AND ALL-IN PRICE FORECASTS1
[TWO GRAPHS]
B. SENSITIVITY CASES ANALYSIS
The all-in prices for the sensitivity cases described in Section 2.2 are
shown in Figure 2-14 and Table 2-4 for the MAIN-WIUM and MAIN-CECO pricing
areas. The high fuel case results in substantially higher prices over time as
compared to the base case due to the hours that gas sets the marginal price.
As additional gas units come into the marketplace, the effect of higher gas
prices is magnified as more gas units move to the margin in more hours. The
low fuel case results in a parallel price path to the base case.
FIGURE 2-14
MAIN SENSITIVITY CASES
ALL-IN PRICE FORECASTS(1) ($/MWH)
[GRAPH]
- -----------------------------------------------------
TABLE 2-4
MAIN SENSITIVITY CASES
ALL-IN PRICE FORECASTS(1) ($/MWH)
- -----------------------------------------------------
BASE HIGH LOW
YEAR CASE FUEL FUEL
- ------------------------------------------------------
MAIN-WIUM
- ------------------------------------------------------
2001 28.60 28.60 28.30
- -------------- ------------ ------------- ------------
2002 27.10 28.60 26.40
- -------------- ------------ ------------- ------------
2003 28.40 30.90 27.20
- -------------- ------------ ------------- ------------
2004 27.10 32.30 26.80
- -------------- ------------ ------------- ------------
2005 27.40 34.90 27.20
- -------------- ------------ ------------- ------------
2006 27.70 36.70 27.20
- -------------- ------------ ------------- ------------
2007 30.00 40.10 28.80
- -------------- ------------ ------------- ------------
2008 30.00 39.90 28.60
- -------------- ------------ ------------- ------------
2009 30.20 40.50 29.00
- -------------- ------------ ------------- ------------
2010 28.90 39.10 27.40
- -------------- ------------ ------------- ------------
2011 28.70 39.50 27.30
- -------------- ------------ ------------- ------------
2012 28.70 39.80 27.30
- -------------- ------------ ------------- ------------
2013 28.30 40.40 26.90
- -------------- ------------ ------------- ------------
2014 29.40 42.20 27.70
- -------------- ------------ ------------- ------------
2015 29.60 42.80 27.80
- -------------- ------------ ------------- ------------
2016 29.60 43.20 27.80
- -------------- ------------ ------------- ------------
2017 29.40 43.10 27.70
- -------------- ------------ ------------- ------------
2018 29.40 43.50 27.70
- -------------- ------------ ------------- ------------
2019 29.70 44.10 28.10
- -------------- ------------ ------------- ------------
2020 29.80 44.30 28.10
============== ============ ============= ============
MAIN-CECO
- ------------------------------------------------------
2001 24.60 24.60 24.30
- -------------- ------------ ------------- ------------
2002 25.70 27.20 25.10
- -------------- ------------ ------------- ------------
2003 27.00 29.50 25.70
- -------------- ------------ ------------- ------------
2004 25.40 30.70 25.20
- -------------- ------------ ------------- ------------
2005 24.90 31.70 24.80
- -------------- ------------ ------------- ------------
2006 25.40 33.90 25.00
- -------------- ------------ ------------- ------------
2007 27.40 36.60 26.30
- -------------- ------------ ------------- ------------
2008 27.90 37.40 26.60
- -------------- ------------ ------------- ------------
2009 28.00 37.80 26.70
- -------------- ------------ ------------- ------------
2010 28.30 38.40 26.90
- -------------- ------------ ------------- ------------
2011 28.20 38.80 26.90
- -------------- ------------ ------------- ------------
2012 28.50 39.60 27.20
- -------------- ------------ ------------- ------------
2013 28.70 40.80 27.40
- -------------- ------------ ------------- ------------
2014 28.80 41.20 27.20
- -------------- ------------ ------------- ------------
2015 28.80 41.40 27.20
- -------------- ------------ ------------- ------------
2016 28.90 41.80 27.20
- -------------- ------------ ------------- ------------
2017 29.30 42.60 27.60
- -------------- ------------ ------------- ------------
2018 29.30 43.30 27.70
- -------------- ------------ ------------- ------------
2019 29.60 43.70 27.90
- -------------- ------------ ------------- ------------
2020 29.70 43.70 28.00
- ------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
- ------------------------------------------------------
2-16
2.6.6 DISPATCH CURVES
Dispatch curves for the MAIN region for 2001 and 2010 are shown in Figure
2-15. The State Line generation units are shown as intermediate load units
while the Neenah plant is the marginal peaking unit.
FIGURE 2-15
MAIN DISPATCH CURVES FOR 2001 AND 2010
[GRAPH]
2-17
2.7 WSCC-CALIFORNIA
2.7.1 BACKGROUND
WSCC is the regional organization responsible for the coordination, operation
and planning of the bulk power electric systems in the western United States.
The purpose of this coordination is to maximize the efficiency of the
planning and operation of individual electric systems within the region in
order to ensure system stability and reliability. WSCC is geographically the
largest NERC region and is composed of 98 member power systems and ten
affiliate members operating in fourteen states and parts of Mexico and
Canada. The region encompasses approximately 1.8 million square miles and
serves approximately 65 million customers. The WSCC region is divided into
four subregions. Region IV includes the state of California in its entirety
and part of Mexico and represents approximately 35% of the WSCC 1999 load of
754,430 GWh. Figure 2-16 shows the WSCC region and the location of the MAGI
generation assets being financed.
As illustrated in Figures 2-17 and 2-18, the California region is largely
dependent on gas- and oil-fired resources for baseload generation, accounting
for 37% of the energy produced in California. Hydro (21%), nuclear (19%), and
coal-fired (16%) generation also play a significant role. Gas- and oil-fired
generation account for 45% of installed capacity and make up the majority of
the market.
FIGURE 2-16
GENERATION ASSETS IN THE WSCC REGION
[MAP]
FIGURE 2-17
WSCC-CALIFORNIA ENERGY - YEAR 2001
[GRAPH]
FIGURE 2-18
WSCC-CALIFORNIA CAPACITY - YEAR 2001
[GRAPH]
Sources: Figure 2-17: PA Consulting Group Regional Modeling results. Figure
2-18: Federal Energy Regulatory Commission, 1999 Form 714: Annual Electric
Control and Planning Area Report and WSCC, Summary of Estimated Loads and
Resources, Data as of January 1, 1999, April 1999; and PA Consulting Group.
Hydro capacity reflects a 25% deration in Figure 2-18 to account for limits on
its sustained peaking capability.
2-18
Hydroelectric capacity is a substantial portion (38%) of the WSCC's peak
capacity. Hydropower is different than most other types of capacity because
most of the major facilities are energy constrained - they have a limited
amount of water they can use for generation before either running out, or
reaching their operational limits due to biologic, recreation, navigation, or
other concerns. These energy constraints can limit the value of hydro
facilities as a capacity source. The additional capacity must be made up by
thermal generation. Our analysis of the ability of hydropower to generate
during the peak periods found that hydro effectively provides 25% less
capacity than its maximum rating thus PA assumed a deration of 25% for hydro
capacity in the base case, low gas case, and high gas case.
In the high hydro case, the amount of hydro energy available is significantly
higher. Our analysis of the reduction in hydro capacity due to energy
constraints showed that the effective reduction would be approximately 1%,
thus we did not derate hydro capacity in the high hydro case.
2.7.2 POWER MARKETS
This section describes the market structures for energy and ancillary
services in California as they currently exist. However, the major events
that occurred in 2000 and continue to occur through 2001 are likely to lead
to significant changes in California's deregulation paradigm. These watershed
events include: the dramatic increase in power costs, fuel costs, and supply
constraints that started in 2000 and culminated in rolling blackouts in
January 2001; the FERC Order in Docket No. EL00-95-00 on December 15, 2000
authorizing utilities to seek bilateral contracts; and failure of Southern
California Edison and PG&E to pay major power bills in January 2001 resulting
in renewed California governmental involvement. This section is divided into
two subsections. The first section summarizes the markets in place as of
January 2001 and the second section reviews the major developments that may
materially change the market.
A. INITIAL MARKET STRUCTURE
Initially, California, unlike the PJM market, did not have a separate market
for installed capacity. A generator must recover its fixed costs by selling
ancillary services and by selling energy in those hours when the market price
exceeds the generator's fuel and other variable operating costs. In order for
peaking and cycling plants to fully recover their costs, they needed to
submit offer prices that exceed their variable costs in those hours when
capacity is tight and they were reasonably assured of being dispatched. In
addition, ancillary services and Reliability Must-Run (RMR) contracts are
other sources of revenue that could offset their fixed costs.
The electric energy consisted of four markets that were interrelated and
operate in chronological order:
I. block forwards market (Cal-PX)
II. day-ahead market (Cal-PX)
III. day-of market (CA-ISO)
IV. real-time market (CA-ISO).
The block forwards, day-ahead, and day-of markets are considered forward
markets, in that the settlement prices and quantities are determined before
the physical transactions occur. At the start of deregulation the California
Power Exchange (Cal-PX) was the primary entity supporting these forward
markets. The Cal-PX indefinitely suspended operations as of January 30, 2001.
The California market was originally subdivided into two major pricing zones:
Northern California (NP15) and Southern California (SP15). Prices between
NP15 and SP15 zones differed during many hours of the year. Transmission
congestion can also occur within these two zones or at any of the various
interfaces. On February 1, 2000, the CA-ISO activated a new zone, ZP26,
located between NP15 and SP15. Because of load and generation location, the
CA-ISO has stated that ZP26's price is likely to match either NP15 or SP15
depending on the direction of the flow.
As mentioned above, an additional source of capacity compensation is
Reliability Most Run (RMR) payments. RMR requirements are developed by the
CA-ISO based upon load forecasts and transmission capacity. The CA-ISO
conducts study that identifies generators that are critical to maintaining
local area reliability. The long-term goal is to eliminate RMR payments and
instead rely on the ancillary services market.
The changing market situation, as discussed in the next section, could
dramatically change the nature of the RMR structure as a result of changes in
the market structure, the potential reintroduction of significant bilateral
contracting, and potential measures that could encourage the construction of
new generation.
2-19
B. CURRENT MARKET SITUATION
Significant market restructuring is likely to occur as a result of both state
of California and FERC action. The combination of the financial inability and
unwillingness of the major California IOUs to continue to pay PX prices for
power without a retail pass-through mechanism will force significant changes
to the market. On December 15, 2000, FERC Docket No. EL-95-00 established
four major changes. The first change was to allow 25,000 MW of utility
capacity to return to cost-of-service regulation subject to state order. The
second change was to allow utilities to enter into bilateral contracts thus
releasing an additional 40,000 MW from the spot markets. The third change was
a requirement that utilities pre-schedule at least 95% of their load. Key
excerpts from the FERC Order follows.
"Elimination of the Mandatory PX Buy-Sell Requirement. The Commission is
eliminating the requirement that the California IOUs sell all of their
generation into, and buy all their generation from, the California Power
Exchange (PX). This will release the entirety of the IOUs' 40,000 MW of
peak load from exposure to the spot market and will allow or require the
following:
(a) 25,000 MW immediately returned to State regulation. .... The state is
free as of date of issuance of this order to regulate this power on a
cost-of-service basis, subject to a cost cap, or in any way it sees
fit.
(b) Release of load to bilateral markets and prudent risk management. The
release of all 40,000 MW from mandatory exposure to the spot market
will permit the IOUs to move their purchase power needs to bilateral
long-term contracts and adopt a balanced portfolio of contracts to
mitigate cost exposure. This is critical to limiting extreme price
volatility for California consumers.
Termination of PX wholesale rate schedules. The Commission will terminate
the PX's wholesale rate schedules which enable it to continue to operate as
a mandatory power exchange. Termination will be effective as of the close
of the April 30, 2001 trading day."
Finally, FERC ordered the implementation of a $150 per MW soft price cap for the
real-time market. Under the new rules, bids over $150/MWh would not set the
market-clearing price. Each bidder over the $150 cap, up to the clearing load,
will receive their bid price. Bidders over $150/MWh will be required to
confidentially report to FERC their incremental generating costs and/or their
opportunity cost of not selling to a different market. Sellers bidding below
$150 will receive the market-clearing price up to the cap of $150.
Generators with accepted bids over $150/MWh will have their price subject to
FERC review. According to the order "Absent notification by the Commission or
its staff (e.g., a data request, order, or other written notification from
the Commission) within 60 days [of the date the report is filed with FERC]
all transactions will be considered final and will not be mitigated." If the
Commission does issue a notice, then the generator will be subject to a
refund liability as long as the issue is under investigation.
The CA ISO has challenged the FERC Order in the Ninth Circuit Court of
Appeals, and the prospects for continuing the ISO in its current capacity are
highly unlikely. The Cal-PX has announced that it will shut down in April and
has already cut its staff by 15%. Based upon the FERC Order and current state
discussions, a move toward fixed price contracts is likely as well as some
type of mechanism to ensure that additional capacity is built. It is not
clear at what price or term these contracts would be set out. However, it is
clear that politically and economically the current conditions cannot
persist. Average wholesale prices of $30/MWh in 1999 increased to over
$170/MWh in the last half of 2000.
California wholesale peak and off-peak prices continued to be in excess of
$150/MWh during the first two months of 2001 despite the FERC Orders and
intervention of the California Department of Water Resources (DWR), which
stepped in as a credit worthy counterpart to make market purchases for the
major IOUs. However, the DWR limited its purchases to "reasonably" priced
power leaving the ISO to make up the remainder of the purchases in the
real-time market. There has been considerable confusion as to who will be
responsible for losses associated with both DWR and CA-ISO purchases. The
final outcome is uncertain given the numerous legislative proposals and
possible direction provided through potential voter approved referendum.
2-20
During the month of February, after an internet solicitation for energy bids,
the DWR announced the signing of a number of long-term contracts that set the
stage for the state government to become a major wholesale market
participant. The DWR has been in discussions with a number of wholesale
generators including Mirant, Duke, Calpine, Dynegy, Enron, El Paso Energy,
and Williams. The state has already announced plans for the purchase of
approximately 9,000 MW of capacity. (The initial purchases in 2001 are lower
but ramp up with commitments for construction of new generation.) While the
specific terms are not available, significant amounts of energy are
identified as being purchased under fixed price arrangements. The average
price of power is reported to be in the $69/MWh range with the average for
the first five years about $10/MWh higher. The actual details have not been
released.
C. RMR MARKET
The Reliability Must Run (RMR) market was intended to be eventually replaced
by the ancillary services market. As a result of the recent crisis in
California, the evolution of the market may be delayed as a result of
alternative efforts to pursue contracts for most generation rather than
reliance on the day-ahead market. RMR resources are designated generators
that are required to run in order to maintain local area reliability. These
resources are designated on an area-by-area basis based upon studies of
projected area load, transmission constraints, and generation resources.
Units designated as RMR can be operated under one of two types of contracts:
o CONDITION NO. 1 - includes a fixed option payment and provisions for the
generator to keep market revenues
o CONDITION NO. 2 - incorporates full fixed cost and start-up cost recovery
but precludes retention of market revenues.
Three MAGI generation stations (Contra Costa #6-7, Pittsburg
#1-7, and Potrero #4-6) are in the Greater Bay RMR Area. The
three generation stations and all their units are identified as
RMR candidates in the 2002-2003 RELIABILITY MUST-RUN TECHNICAL
STUDY OF THE ISO-CONTROLLED GRID. These units were modeled under
Condition No. 1.
2.7.3 MARKET DYNAMICS
In the latter part of the last decade California experienced a significant
economic boom resulting in a growth in demand of 30% since 1990. At the same
time the amount of generation capacity increased only 6%. This significant
growth, coupled with strong growth in neighboring states reduced the power
available for imports. A summary of projected load growth and required capacity
is shown in Figure 2-19.
FIGURE 2-19
WSCC-CALIFORNIA LOAD AND RESOURCE BALANCE
[GRAPH]
Historical prices for WSCC-California are presented in Appendix A.
2-21
2.7.4 TRANSMISSION SYSTEM
The CA-ISO controls 75% of the California Grid and includes transmission
systems formerly operated by the three IOUs in the state (Pacific Gas &
Electric, Southern California Edison, and San Diego Gas & Electric). The
CA-ISO was formally enacted by the Legislature and the Governor to coordinate
safe and reliable delivery of power while opening access to the new, free
market for electricity. Further details on the CA-ISO are provided in the
discussion of the power markets. At the time of this report, the state of
California was negotiating with three IOUs to buy their transmission assets
as part of a deal to resolve the power crisis.
2.7.5 ANCILLARY SERVICES MARKETS
A. INTRODUCTION
MAGI's California units have the opportunity to earn revenues in the six
ancillary services categories defined by the ISO:(1)
I. regulation (up and down)
II. spinning reserve
III. non-spinning reserve
IV. replacement reserve
V. voltage support
VI. black start capability.
The ISO procures the first four of these services through competitive bidding in
day-ahead and hour-ahead auctions.
Bids were evaluated separately and sequentially in the following order:
regulation, spinning reserve, non-spinning reserve and replacement reserve.
Figure 2-20 summarizes the competitively bid ancillary services prices for
the 12-month period ending October 31, 2000. For reference, the average
unconstrained PX energy price is also shown. Prices in the California
electricity markets in this period were higher than in previous years due to
high demand and insufficient supply. In the future we believe it is unlikely
that ancillary services prices will maintain the levels seen in 2000.
PA forecasted the 2001 to 2004 revenues for the competitively bid ancillary
services from the MAGI California units using a supply curve model, assuming
MAGI will be able to continue marketing these services.
B. SUPPLY CURVE MODEL
The supply curve model, as the name suggests, relies on construction of
supply curves for the ancillary services of interest. The curves are based on
the available capacities of units with the particular service capability and
their opportunity cost to provide those services. An underlying assumption is
that unit owners will bid those opportunity costs into the ancillary service
auctions.
The marginal cost of each service is defined by the opportunity cost of the
unit at the intersection of a demand curve with the supply curve. The demand
curve is defined by the ISO's ancillary services requirements and is a
vertical line, i.e., inelastic.
Results have been provided to the Independent Engineer.
FIGURE 2-20
CALIFORNIA ANCILLARY
SERVICES PRICES
(11-01-99 THROUGH 10-21-00)
[GRAPH]
2-22
2.7.6 PRICE FORECASTS FOR THE WSCC-CALIFORNIA MARKET
A. BASE CASE
The forecasts of energy prices, capacity compensation, and all-in prices for the
base case are shown in Figure 2-21 and Table 2-5 for the WSCC-California region.
FIGURE 2-21
WSCC-CALIFORNIA BASE CASE COMPENSATION
FOR CAPACITY, ENERGY, AND ALL-IN PRICE FORECASTS(1)
[GRAPH]
[KEY]
(1) Results are expressed in real 2000 dollars.
In addition to the fundamental numbers reported in Table 2-5, PA used monthly
average daytime electricity forwards for 2001-2003. The monthly electricity
price forwards for 2001-2003 used in the volatility forecast for the
WSCC-California region are listed in Appendix A. For the period 2004-2020,
the volatility results were calibrated to the fundamental results shown in
Table 2-5.
- -----------------------------------------------------------
TABLE 2-5
WSCC-CALIFORNIA BASE CASE FORECASTS(1)
FUNDAMENTAL ANALYSIS
- -----------------------------------------------------------
COMPENSATION ENERGY ALL-IN
FOR CAPACITY PRICE PRICE
YEAR ($/KW-YR) ($/MWH) ($/MWH)
- ------------- ----------------- ------------- -------------
2001(2) 76.90 60.30 69.10
- ------------- ----------------- ------------- -------------
2002(2) 76.20 48.10 56.70
- ------------- ----------------- ------------- -------------
2003(2) 75.50 46.00 54.60
- ------------- ----------------- ------------- -------------
2004 46.50 32.00 37.30
- ------------- ----------------- ------------- -------------
2005 63.50 24.70 32.00
- ------------- ----------------- ------------- -------------
2006 65.20 24.80 32.30
- ------------- ----------------- ------------- -------------
2007 66.40 24.80 32.40
- ------------- ----------------- ------------- -------------
2008 69.80 24.50 32.50
- ------------- ----------------- ------------- -------------
2009 68.10 25.10 32.90
- ------------- ----------------- ------------- -------------
2010 70.20 25.30 33.30
- ------------- ----------------- ------------- -------------
2011 70.30 25.30 33.30
- ------------- ----------------- ------------- -------------
2012 69.90 25.10 33.00
- ------------- ----------------- ------------- -------------
2013 69.30 25.30 33.20
- ------------- ----------------- ------------- -------------
2014 68.80 25.10 32.90
- ------------- ----------------- ------------- -------------
2015 68.20 24.50 32.30
- ------------- ----------------- ------------- -------------
2016 67.60 24.70 32.40
- ------------- ----------------- ------------- -------------
2017 67.00 25.00 32.60
- ------------- ----------------- ------------- -------------
2018 66.50 25.30 32.80
- ------------- ----------------- ------------- -------------
2019 65.90 24.80 32.30
- ------------- ----------------- ------------- -------------
2020 65.40 25.10 32.60
- -----------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
(2) 2001-2003 volatility results are calibrated to the
forwards prices versus the model results presented herein.
- -----------------------------------------------------------
2-23
B. SENSITIVITY CASES ANALYSIS
The all-in prices for three of the sensitivity cases described in Section 2.2
are shown in Figure 2-22 and Table 2-6 for the WSCC-California region.
The high fuel case yields consistently higher all-in prices (in the range of
$14- to $16/MWh) compared the base case after 2004, as the percentage of gas on
the margin remains flat. Gas units are on the margin in the base, high fuel, and
low fuel cases. Thus, the all-in price differences are consistent with the fuel
price change. The low fuel case produces slightly lower all-in prices parallel
to the base case. The high hydro case's excess low cost generation and capacity
depresses prices through 2004 by $15 to $17/MWh.
FIGURE 2-22
WSCC-CALIFORNIA SENSITIVITY CASES
ALL-IN PRICE FORECASTS ($/MWH)
[GRAPH]
[KEY]
(1) Results are expressed in real 2000 dollars.
- -----------------------------------------------------------
TABLE 2-6
WSCC-CALIFORNIA SENSITIVITY CASES
ALL-IN PRICE FORECASTS(1) ($/MWH)
- -----------------------------------------------------------
YEAR BASE HIGH LOW HIGH HYDRO
CASE FUEL FUEL
- ----------- ----------- ---------- ----------- ------------
2001 69.10 69.10 63.70 52.80
- ----------- ----------- ---------- ----------- ------------
2002 56.70 62.70 52.50 41.60
- ----------- ----------- ---------- ----------- ------------
2003 54.60 64.20 50.80 40.60
- ----------- ----------- ---------- ----------- ------------
2004 37.30 50.80 35.00 31.10
- ----------- ----------- ---------- ----------- ------------
2005 32.00 48.90 30.20 32.00
- ----------- ----------- ---------- ----------- ------------
2006 32.30 49.00 30.40 32.30
- ----------- ----------- ---------- ----------- ------------
2007 32.40 48.80 30.60 32.40
- ----------- ----------- ---------- ----------- ------------
2008 32.50 48.50 30.60 32.50
- ----------- ----------- ---------- ----------- ------------
2009 32.90 48.70 30.90 32.90
- ----------- ----------- ---------- ----------- ------------
2010 33.30 48.20 31.10 33.30
- ----------- ----------- ---------- ----------- ------------
2011 33.30 48.10 31.10 33.30
- ----------- ----------- ---------- ----------- ------------
2012 33.00 48.50 30.90 33.00
- ----------- ----------- ---------- ----------- ------------
2013 33.20 48.70 31.10 33.20
- ----------- ----------- ---------- ----------- ------------
2014 32.90 47.70 30.80 32.90
- ----------- ----------- ---------- ----------- ------------
2015 32.30 46.80 30.30 32.30
- ----------- ----------- ---------- ----------- ------------
2016 32.40 46.60 30.30 32.40
- ----------- ----------- ---------- ----------- ------------
2017 32.60 46.90 30.50 32.60
- ----------- ----------- ---------- ----------- ------------
2018 32.80 46.50 30.70 32.80
- ----------- ----------- ---------- ----------- ------------
2019 32.30 46.40 30.20 32.30
- ----------- ----------- ---------- ----------- ------------
2020 32.60 46.50 30.40 32.60
- -----------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
- -----------------------------------------------------------
2-24
2.7.7 DISPATCH CURVES
Dispatch curves for 2001 and 2010 are shown in Figure 2-23.
FIGURE 2-23
WSCC-CALIFORNIA DISPATCH CURVES FOR 2001 AND 2010
WSCC-CA - 2001
[KEY]
[GRAPHS] ---------------------
A Contra Costa 6
CUMULATIVE CAPACITY (MW) B Contra Costa 7
C Pittsburg 1
PEAK DEMAND = 53,838 MW WITH RESERVE 13% = 60,323 MW D Pittsburg 2
E Pittsburg 3
F Pittsburg 4
G Pittsburg 5
WSCC-CA - 2010 H Pittsburg 6
I Pittsburg 7
[GRAPHS] J Potrero 3
K Potrero GT 4
CUMULATIVE CAPACITY (MW) L Potrero GT 5
M Potrero GT 6
PEAK DEMAND = 62,402 MW WITH RESERVE 13% = 70,514 MW ---------------------
2-25
2.8 NPCC-NEW YORK
2.8.1 BACKGROUND
This section describes the current, proposed, and potential future structure of
the power market within the New York component of the Northeast Power
Coordinating Council (NPCC). NPCC is the regional organization for the
coordination of the operation and planning of the bulk power electric systems in
New York, New England, and eastern Canadian Provinces. The purpose of this
coordination is to maximize the efficiency of the planning and operation of
individual electric systems within the region in order to ensure system
stability and reliability. The NPCC is split into two ISOs, NEPOOL and New York.
The NY-ISO, formed in 1998, is the replacement for the New York Power Pool
(NYPP). The NYPP was formed by New York's eight largest electric utilities
following the Northeast Blackout of 1965. The NYPP operated as a centrally
dispatched power pool with a "split-the-savings" pricing methodology. In
response to the FERC Open Access Rule (Order 888), the members of NYPP developed
a restructuring proposal and a pool-wide open access tariff, which were
submitted to FERC in January 1997. This restructuring proposal created the New
York ISO (NY-ISO) to operate the New York bulk power system, maintain system
reliability, administer specified electricity markets, and facilitate open
access to the New York transmission system. A map of the NPCC-New York region
and the location of the generation assets being financed is provided in Figure
2-24.
FIGURE 2-24
NPCC-NEW YORK REGION
[GRAPH]
On January 28, 1999, FERC gave conditional approval of the NY-ISO's proposed
tariff, market rules, and market-based rates with some modifications. On
November 18, 1999, the NY-ISO officially assumed control and operation of the
New York Power Pool grid and began administering the wholesale market for the
sale and purchase of electricity in the region. The NY-ISO also provides
statewide transmission service under a single tariff, which eliminates the
cumulative transmission charges for each individual utility that is involved in
a transaction.
FIGURE 2-25
NEW YORK ENERGY - YEAR 2001
[GRAPH]
FIGURE 2-26
NEW YORK CAPACITY - YEAR 2001
[GRAPH]
Sources: Figure 2-25: PA Consulting Group Regional Modeling results.
Figure 2-26: Report of the Member Electric Systems of the New York Power Pool
Load and Capacity Data, 2000; and PA Consulting Group.
2-26
As Figures 2-25 and 2-26 indicate, NY-ISO uses a balance of natural resources
for baseload generation. Production comes from nuclear (27%), coal (26%), gas
and oil (23%), and hydro-based (22%). Gas- and oil-fired units account for the
majority of NY-ISO's installed capacity, totaling 59%.
2.8.2 POWER MARKETS
A. INTRODUCTION
Activity in the wholesale power markets has been enhanced as a result of retail
market restructuring. Several of the IOUs in New York were required to divest a
portion of their generation assets. In addition, generators in New York City
were required to adopt certain market power mitigation measures. These market
power mitigation measures are intended to alleviate concerns that the divested
generation might be able to exercise localized market power due to the current
configuration of loads, generation, and transmission facilities in New York City
and related local reliability rules and transmission constraints. These market
power mitigation measures were approved by FERC in Docket No. ER98-3169-000,
issued September 22, 1998, and are being implemented by the NY-ISO.
The new wholesale market structure in New York created the following markets for
the services of generators:
i. installed capacity
ii. day-ahead energy
iii. real-time energy
iv. ancillary services (day-ahead and real-time)
v. operating reserves
vi. regulation
vii. In-City market power mitigation measures
viii. In-City unit commitment
ix. installed capacity
x. spinning reserves
B. MARKETS
i. INSTALLED CAPACITY MARKET
To ensure that sufficient installed capacity is available in the market to meet
reliability standards, the NY-ISO requires LSEs to own or contract with physical
generation capacity to cover their peak demand and a share of the installed
reserve requirement for the upcoming capability period.
Important features of the installed capacity market include the following:
- - The installed capability obligation for each participant is determined on
a semi-annual basis by the NY-ISO.
- The NY-ISO determines the minimum amount of capability that must be
obtained internal to the LSE's locality.
- The NY-ISO determines the maximum amount of capability that may be
obtained by the LSE from other zones in the New York Control Area.
- The NY-ISO determines the maximum capability that may be obtained
from all neighboring control areas.
- All resources must be either bilaterally scheduled to meet load
within the New York Control Area or be bid into the New York
day-ahead market.
- - Installed capacity may be acquired by an LSE through bilateral
transactions with generators or other LSEs.
- - An LSE may acquire installed capacity at any time during the year,
including after the occurrence of its peak load.
- - An LSE lacking installed capacity will be required to purchase it at a
special auction held by the NY-ISO.
- - If an LSE fails to meet its installed capacity requirement, a substantial
penalty will be assessed.
The NY-ISO conducts installed capacity auctions 45 days prior to both the summer
and winter capability periods (referred to as Obligation Procurement Periods).
The auction takes place in three stages. First, installed capacity is bought and
sold in six-month blocks covering the entire Obligation Procurement Period. Then
a subsequent auction facilitates transactions for specific months within the
period. In the event that any LSEs have not certified to the NY-ISO that they
have met their installed capacity requirements, the NY-ISO will conduct a third
"Deficiency Procurement Auction" to secure installed capacity credits on behalf
of the deficient LSEs.
The NY ISO conducted its first ICAP auction in April 2000. In the New York City
area, over 5,000 MW was awarded for the 6-month block covering May through
October at a market-clearing price averaging
2-27
$8.75 per kW-month. In the month-by-month auction, demand far exceeded supply
in New York City. Only 59.4 MW was offered each month, whereas demand ranged
from 308 MW in several months to nearly 2,000 MW in July and August. As a
result market-clearing prices reached the ISO-imposed ceiling of $12.50 per
kW-month in every month. Other areas in the ISO territory saw much less
activity in the auction. In some areas, no MW were offered at all, and in
others prices reached no higher than $2.25 per kW-month.
The NY-ISO also plans to conduct monthly auctions to allow LSEs that have gained
load to acquire additional installed capacity credits. If necessary, monthly
Deficiency Procurement Auctions will also be held.
ii. DAY-AHEAD ENERGY MARKET
In the day-ahead energy market, 24 separate hourly energy prices are determined
for each location. The closing time for submitting bids to the NY-ISO is 5:00
for the energy markets the following day (for example, 5:00 Tuesday morning for
bids on energy to be generated on Wednesday). A bid to supply generation
consists of an incremental energy bid curve. For each generation level, the
curve represents the minimum price a bidder is willing to accept to be
dispatched at that generation level. Distinct curves may be submitted for each
hour. Bidders may specify constraints on their units, such as minimum up time,
minimum down time, and ramp rates. Bidders are able to separately specify
start-up costs and minimum load costs.
The NY-ISO runs a security-constrained unit commitment program(2) to determine
which generating units will be committed (designated to be available for
dispatch the next day). LBMPs are determined for each hour. A location-specific
price represents the cost of serving an increment of load at that location for
that hour, as represented in the NY-ISO's day-ahead schedule. The NY-ISO
determines its day-ahead schedule by minimizing total cost (as bid) over the
course of the day, while meeting the load quantities bid day-ahead by LSEs. The
location-specific prices include any charges for transmission losses and
congestion.
- -----------------------------
(2) The security-constrained unit commitment program is a complex
mathematical optimization program that identifies a set of generation units
whose availability minimizes anticipated cost while meeting the security
(reliability) constraints.
A winning bid results in a financial forward at the location-specific day-ahead
price for the quantity accepted by the NY-ISO. If a winning bidder delivers an
amount of energy other than that accepted by the NY-ISO in the day-ahead energy
market, the difference in energy between the amount delivered and the amount bid
is paid (either to or from the generator) at the real-time energy price.
Important features of the day-ahead market include the following:
- - Only the incremental energy bid curve is used in determining the LBMPs. If
the difference between the market clearing price times the scheduled
generation and the bid price times the scheduled generation does not cover
as-bid start-up and minimum load costs, the generator receives the
shortfall as a make whole payment.
- - A generator participating in the centrally coordinated financial
settlement process is paid the hourly day-ahead price at its location for
all energy it is scheduled to produce in the day-ahead market in that
hour.
- - An LSE participating in the centrally coordinated financial settlement
process pays the hourly day-ahead price for its zone, which is an average
of locational prices within that zone, for all energy it is scheduled to
consume in the day-ahead market in that hour.
- - Bilateral transactions are not subject to the centrally coordinated
financial settlement process for energy purchases. However, participants
making bilateral transactions pay for transmission service based on the
same charges for transmission losses and transmission congestion (which
results in the differences in prices based on their location).
On August 28, 2000, the three northeast ISO's (New England, New York, and
Ontario) jointly issued a Request for Proposal (RFP). The RFP Requested a
feasibility study for a regional day-ahead electric market that would establish
energy prices and schedules for the next day. The goal is to offer additional
capability for market participants to buy and sell electricity across a broader
region than is presently available within the ISO markets. The RFP falls in line
with FERC Order 2000, which calls for the formation of RTOs. In that same order,
FERC indicated that it favors larger regional ISO markets that reduce what they
refer to as "seams" between existing markets. There are three phases to the
study. The first phase is to analyze various options and
2-28
recommend something to be approved by all three ISOs. Once the first phase is
accepted, the second phase would incorporate a system reliability study. The
third phase would then produce functional specifications based on the
outcomes of the first two phases. The first phase should be completed on or
before March 30, 2001.
In compliance with FERC's preferences stated in FERC Order 2000, the New England
and New York ISO board of directors announced the approval of a joint resolution
on January 16, 2001. The resolution establishes a joint task force on
inter-control area market coordination. The two groups have pledged that both
regions' independent system operators' cooperate to enhance interregional
coordination and reduce barriers to transactions between the two wholesale
electricity markets. The joint resolution was made in accordance to previous RTO
filings that occurred in both NEPOOL and New York.
iii. REAL-TIME ENERGY MARKET
In the real-time energy market, the closing time for submitting bids to the
NY-ISO is 90 minutes in advance of the hour; these bids are known as hour-ahead
bids. The NY-ISO uses a security-constrained dispatch program to meet load on a
5-minute basis. The locational price of energy at each location is the bid-based
cost of meeting incremental load at that location in the security-constrained
least-cost dispatch. For each 5-minute interval, a generator is paid a
location-specific price for the energy generated in that interval at the
market-clearing location-specific price for that 5-minute interval.
Important features of the real-time energy market include the following:
- - Hour-ahead bids are valid from market close through the scheduled hour of
delivery, which allows such bids to be exercised by the NY-ISO in
real-time.
- - For resources previously scheduled by the NY-ISO day-ahead, hour-ahead bids
may be no greater than the day-ahead bids.
- - Bilateral transactions involving energy purchases and sales are not settled
through the centrally coordinated process. Participants may, however,
purchase transmission on the same basis and are subject to the same charges
for transmission losses and transmission congestion.
- - Generators, loads, and bilateral transactions are subject to real-time
locational prices only to the extent that their actual injections and/or
withdrawals differ from their schedules submitted the day before.
- - The essence of real-time operation lies in the SCD (Security-Constrained
Dispatch) software package. Like SCUC, the SCD program works to identify
the winning bid and commits it to provide transmission services.
iv. ANCILLARY SERVICES MARKET
Six specific support services compose the sector known as the Ancillary
Services Market. These unbundled services support the transmission of energy
and reactive power from resources to loads; they are essential to maintain
reliable operation of the New York power system. Some of these services are
market-based, meaning they are bid for in a market much like that of
installed capacity or other previously mentioned markets. Other services are
provided by the NY-ISO at embedded costs. A summary of the NY-ISO Ancillary
Services is provided in Table 2-7.
- -----------------------------------------------------------
TABLE 2-7
NY-ISO ANCILLARY SERVICES SUMMARY
- -----------------------------------------------------------
SERVICE
LOCATION SERVICE PRICING
ANCILLARY SERVICES DEPENDENT? PROVIDER METHOD
- ------------------- -------------- ----------- ------------
Scheduling, No NY-ISO Embedded
System Control,
and Dispatch
Service
- ------------------- -------------- ----------- ------------
Voltage Support Yes NY-ISO Embedded
Service
- ------------------- -------------- ----------- ------------
Regulation and Yes NY-ISO Market-based
Frequency or
Response Third
Service Party
- ------------------- -------------- ----------- ------------
Energy No NY-ISO Market-
Imbalance based and
Service Energy
payback
- ------------------- -------------- ----------- ------------
Operating Yes NY-ISO Market-
Reserve or based
Service Third
Party
- ------------------- -------------- ----------- ------------
Black Start Yes NY-ISO Embedded
Service
- ------------------- -------------- ----------- ------------
2-29
Only a few of these services, as Table 2-7 illustrates, provide a market from
which profits can be generated. Of these market-based services, the market for
the Operating Reserve Service provides the most opportunity for profit.
v. OPERATING RESERVES MARKET
There are three types of operating reserves in the NY-ISO (ten-minute spinning,
ten-minute non-spinning, thirty-minute operating), with each occupying one-third
of the market. Each type of operating reserve has a day-ahead and real-time
market for each hour of system operations. Important features of the operating
reserves markets include the following:
- - Each day-ahead operating reserve market is bid-based, and bids are in
$/MW. A generator may submit operating reserve bids for any and all
markets for which it qualifies. Using its security-constrained unit
commitment program, the NY-ISO determines the winning bids for each
market. The market-clearing price for each day-ahead operating reserve
market is that market's highest winning bid.
- - If the NY-ISO recognizes in real-time a need for additional operating
reserves, real-time prices are determined by hour-ahead bids in each
operating reserve market. If no additional operating reserves are acquired
in real-time by the NY-ISO, the real-time prices for operating reserves
are equal to zero.
- - Spinning reserve payments to generators on security-constrained dispatch
by the NY-ISO may include lost opportunity costs if the NY-ISO directs
those units to reduce generating levels in order to provide spinning
reserves. Spinning reserve payments to non-dispatchable generators do not
include lost opportunity costs.
- - Capacity assigned to provide operating reserves, and then dispatched by
the NY-ISO to provide energy, is paid the real-time LBMP for the energy
market.
- - Generators face penalties for failure to perform.
vi. REGULATION MARKETS
Regulation service provides ramping service to follow the second-to-second
fluctuations in load and supply. Regulation service is provided by generators on
automatic generation control (AGC). There are day-ahead and real-time markets
for regulation.
Important features of the regulation market include the following:
- - Bids are in $/MW, based on a unit's regulation response rate in MW/min.
- - Compensation for regulation includes an availability component and a
component for energy used in regulation.
- - The real-time market for regulation may clear at a price of zero when
there is no additional need for regulation beyond that which is scheduled
the day before.
- - A generator that does not follow its day-ahead schedule is levied a charge
for the necessary regulation it imposes on the system.
- - Generators face penalties for failure to perform.
vii. IN-CITY (NEW YORK) MARKET POWER MITIGATION MEASURES
Energy bids are market-based and congestion management is achieved through
locational-based marginal pricing. The bid prices of In-City generators are
relied on to compute the In-City market clearing price, unless the bid prices
are 5% greater than the price at the Indian Point 2 bus (which is located
outside of the City of New York). When this happens, mitigation measures are
invoked and the In-City generator's effective bid prices are not used. In
this case, the bids are capped at the amount that those same generators have
bid during unconstrained hours in the prior 90 days.(3) Any portion of the
90-day period that reflects periods when mitigation measures were invoked is
not used in this calculation. The price is based on the unit's variable
operating costs(4) if there are not 15 days of data when mitigation measures
were not invoked.
- -----------------------------
(3) The cap is an average that is adjusted up or down by a fuel index to
account for changes in fuel costs over the 90-day period.
(4) The formula uses a fuel price index, the units heat rate, and other
operating characteristics, as well as a $1/MWh adder for operation and
maintenance costs.
2-30
viii. IN-CITY UNIT COMMITMENT
In-City generating units may be committed to meet reliability requirements. If a
unit is committed and proves to be the cheapest alternative, it is dispatched
the next day to deliver energy and, therefore, no market power mitigation
measure is necessary. However, if a unit is committed and is not dispatched the
next day to deliver energy, it is entitled to a unit commitment payment, which
is capped at the unit's variable cost.
ix. INSTALLED CAPACITY
LSEs serving load In-City may be subject to local reliability rules that
specify the portion of the installed capacity requirement that must be satisfied
from In-City generating resources. In-City installed capacity has a price cap of
$105.00/kW-yr and shall be revised only as permitted by FERC.
x. SPINNING RESERVES
All spinning reserve suppliers are paid the higher of their spinning reserve
bids or their lost opportunity costs associated with providing spinning reserves
(i.e., the revenues they would have earned had the units been dispatched to
deliver energy rather than operated as spinning reserves). All In-City
generators with spinning reserve capability are required to participate in the
spinning reserve markets and to use bid prices of zero in all hours. If directed
to supply spinning reserves, the generators are compensated as if their units
had been dispatched to make energy sales.
FIGURE 2-27
NEW YORK LOAD AND RESOURCE BALANCE
[GRAPH]
[KEY]
C. NEW YORK RESTRUCTURING STATUS
Discussion on electric competition in the state began as far back as 1993 by the
New York Public Service Commission (PSC). By May of 1996 the PSC had announced
the plans for restructuring in the state, allowing customers to choose their
electricity supplier. In 1997 and 1998, the Commission approved six rate and
restructuring orders for Consolidated Edison, Central Hudson G&E, Orange and
Rockland Utilities, NYSE&G, Niagara Mohawk, and Rochester G&E.
In Opinion 96-12, the NYPSC directed that a non-bypassable system benefits
charge be established to support investments in energy efficiency, research,
development and demonstration, low-income programs and environmental monitoring
that might not be fully supported in a competitive market.
Currently, NYSE&G, Orange and Rockland, and Niagara Mohawk have full retail
access for customers in place. The other three mentioned will have full
access by the end of 2001 if all goes smoothly.
2.8.3 MARKET DYNAMICS
MAGI's assets in this report located in New York include eight existing
generation plants totaling 1,764 MW of capacity. This represents approximately
5% of the installed capacity in New York. The market is currently in approximate
load resource balance when the reserve margin is included. The New York market
has had a historic average annual peak demand growth rate of 1.9% over the
period of 1991-2000. However, the forecast indicates that the growth will slow
to an average annual growth rate of 1% for the period of 2001-2020. The forecast
of demand and capacity is shown in Figure 2-27.
Historical prices for New York are presented in Appendix A.
2-31
2.8.4 TRANSMISSION SYSTEM
On January 17, 2001 the NY-ISO and six other transmission owners in New York
filed jointly with FERC to say the NY-ISO will comply with the FERC Order 2000
RTO. The filing states that they will be able to comply with the order to gain
approval as an RTO. A major component of the filing proposes that the NY-ISO
assume "ultimate responsibility" for planning and coordinating transmission
expansions, additions and upgrades.
The six transmission owners filing with the ISO are: Central Hudson Gas &
Electric Corporation, Consolidated Edison Company of New York, Inc., Niagara
Mohawk Power Corporation, Orange & Rockland Utilities, Inc., and Rochester Gas
and Electric Corporation. The New York Power Authority and the Long Island Power
Authority are also supporting the filing.
i. TCCS MARKET
Any market participant, including those engaging in bilateral transactions
scheduled in the day-ahead market, may hedge transmission congestion costs
through transmission congestion contracts (TCCs). TCCs are financial obligations
entitling the holder to the congestion rent between two locations, as measured
by the difference between the congestion component of the day-ahead LBMPs for
each location. TCCs thus may be used to offset the costs of transmission
congestion assessed to bilateral contracts. Entities having physical rights to
transmission have the option to convert these physical rights to TCCs. The
NY-ISO will identify the remaining transfer capability of the transmission
system and administer an auction every six months where these TCCs can be
purchased.
Currently, the NY-ISO is taking measures to augment the TCC market. Known as the
TCC Unbundling Project, this undertaking has three aims:
- - divide TCCs into more easily traded components
- - increase liquidity of TCCs
- - facilitate secondary market for TCCs.
Divided into three phases, the first phase is to identify individual
components of TCCs; currently, the NY-ISO has identified three components in
each original TCC. Recall that each TCC is a hedge against energy lost along
its transfer, thus, in an effort to divide a TCC into multiple components,
the NY-ISO has simply identified distinct paths where energy is lost along
the original transfer. These three paths include (1) bus to zone, (2) zone to
zone, and (3) zone to bus. Having identified individual component pieces for
auction, the NY-ISO is endeavoring to develop billing and reporting
procedures and software packages to automate them. The NY-ISO is currently
dividing TCCs into components that are easier to trade. Dates for
accomplishing the second and third phases, track secondary TCC holders and
automate TCC auction process (bidding & posting), respectively, have not been
set.
2-32
2.8.5 PRICE FORECASTS FOR THE NEW YORK MARKET
A. BASE CASE
The base case compensation for capacity, energy, and all-in market price
forecasts are presented in Figure 2-28 and Table 2-8 for the New York-East
pricing area, which includes Central Hudson Gas & Electric Corporation and
Orange & Rockland Utilities, Inc.
FIGURE 2-28
NEW YORK-EAST BASE CASE COMPENSATION
FOR CAPACITY, ENERGY, AND ALL-IN PRICE FORECASTS(1)
[GRAPH]
In addition to the fundamental numbers reported in Table 2-8, PA used monthly
average daytime electricity forwards for 2001-2003. The monthly electricity
price forwards for 2001-2003 used in the volatility forecast for the New York
region are listed in Appendix A. For the period 2004-2020, the volatility
results were calibrated to the fundamental results shown in Table 2-8.
- -----------------------------------------------------------
TABLE 2-8
NEW YORK-EAST BASE CASE FORECASTS(1)
FUNDAMENTAL ANALYSIS
- -----------------------------------------------------------
COMPENSATION ENERGY ALL-IN
FOR CAPACITY PRICE PRICE
YEAR ($/kW-yr) ($/MWh) ($/MWh)
- ------------- ----------------- ------------- -------------
2001(2) 30.90 35.00 38.50
- ------------- ----------------- ------------- -------------
2002(2) 30.60 32.10 35.60
- ------------- ----------------- ------------- -------------
2003(2) 29.00 30.90 34.20
- ------------- ----------------- ------------- -------------
2004 30.10 27.30 30.80
- ------------- ----------------- ------------- -------------
2005 26.60 24.70 27.80
- ------------- ----------------- ------------- -------------
2006 28.60 25.10 28.30
- ------------- ----------------- ------------- -------------
2007 33.00 24.40 28.20
- ------------- ----------------- ------------- -------------
2008 34.80 24.60 28.60
- ------------- ----------------- ------------- -------------
2009 35.60 25.10 29.10
- ------------- ----------------- ------------- -------------
2010 42.60 25.80 30.70
- ------------- ----------------- ------------- -------------
2011 45.60 25.70 30.90
- ------------- ----------------- ------------- -------------
2012 48.00 25.70 31.20
- ------------- ----------------- ------------- -------------
2013 50.60 26.10 31.90
- ------------- ----------------- ------------- -------------
2014 52.70 26.20 32.20
- ------------- ----------------- ------------- -------------
2015 55.00 26.10 32.30
- ------------- ----------------- ------------- -------------
2016 55.30 26.10 32.40
- ------------- ----------------- ------------- -------------
2017 53.60 26.00 32.10
- ------------- ----------------- ------------- -------------
2018 54.20 26.10 32.30
- ------------- ----------------- ------------- -------------
2019 53.90 26.20 32.40
- ------------- ----------------- ------------- -------------
2020 53.50 26.00 32.10
- -----------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
(2) 2001-2003 volatility results are calibrated to the forwards prices versus
the model results presented herein.
- -----------------------------------------------------------
2-33
B. SENSITIVITY CASES ANALYSIS
The all-in prices for the three of the sensitivity cases described in Section
2.2 are shown in Figure 2-29 and Table 2-9 for the New York-East pricing area.
FIGURE 2-29
NEW YORK-EAST SENSITIVITY CASES
ALL-IN PRICE FORECASTS ($/MWh)
[GRAPH]
(1) Results are expressed in real 2000 dollars.
- -----------------------------------------------------------
TABLE 2-9
NEW YORK-EAST SENSITIVITY CASES
ALL-IN PRICE FORECASTS(1) ($/MWh)
- -----------------------------------------------------------
BASE HIGH LOW
YEAR CASE FUEL FUEL OVERBUILD
- ----------- ----------- ---------- ----------- ------------
2001 38.50 38.50 35.80 38.50
- ----------- ----------- ---------- ----------- ------------
2002 35.60 38.40 33.70 35.60
- ----------- ----------- ---------- ----------- ------------
2003 34.20 38.20 32.40 34.20
- ----------- ----------- ---------- ----------- ------------
2004 30.80 38.50 29.20 29.40
- ----------- ----------- ---------- ----------- ------------
2005 27.80 39.50 27.00 26.10
- ----------- ----------- ---------- ----------- ------------
2006 28.30 40.20 27.20 26.30
- ----------- ----------- ---------- ----------- ------------
2007 28.20 39.60 27.00 26.00
- ----------- ----------- ---------- ----------- ------------
2008 28.60 40.00 27.10 26.20
- ----------- ----------- ---------- ----------- ------------
2009 29.10 40.90 28.30 26.80
- ----------- ----------- ---------- ----------- ------------
2010 30.70 42.00 29.70 27.30
- ----------- ----------- ---------- ----------- ------------
2011 30.90 43.70 30.60 27.70
- ----------- ----------- ---------- ----------- ------------
2012 31.20 45.50 30.50 27.60
- ----------- ----------- ---------- ----------- ------------
2013 31.90 47.40 30.60 28.00
- ----------- ----------- ---------- ----------- ------------
2014 32.20 47.40 30.40 28.50
- ----------- ----------- ---------- ----------- ------------
2015 32.30 47.30 30.40 30.80
- ----------- ----------- ---------- ----------- ------------
2016 32.40 47.40 30.40 31.90
- ----------- ----------- ---------- ----------- ------------
2017 32.10 47.00 30.20 31.60
- ----------- ----------- ---------- ----------- ------------
2018 32.30 47.10 30.40 31.80
- ----------- ----------- ---------- ----------- ------------
2019 32.40 47.30 30.50 32.00
- ----------- ----------- ---------- ----------- ------------
2020 32.10 46.80 30.20 31.60
- -----------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
- -----------------------------------------------------------
The spread between all-in prices for the high fuel case and base case grows from
$12/MWh in 2005, to $15/MWh by 2020 as the number of hours that gas is on the
margin increases. The low fuel case prices are $1 to $3/MWh lower throughout the
study period. The additional capacity added in the overbuild scenario pushes the
need for new builds out to 2017. During this time (2009-2017), all-in prices are
$2 to $3/MWh lower.
2-34
2.8.6 DISPATCH CURVES
Dispatch curves for the New York region for 2001 and 2010 are shown in Figure
2-30. The relative position of the plants in this report are located along the
dispatch curve.
FIGURE 2-30
NEW YORK DISPATCH CURVES FOR 2001 AND 2010
[TWO GRAPHS]
2-35
2.9 NPCC-NEPOOL
2.9.1 BACKGROUND
This section describes the New England Power Pool (NEPOOL) component of the
Northeast Power Coordinating Council (NPCC). NEPOOL was formed in November of
1971.
NEPOOL's voluntary membership includes municipal and consumer-owned systems,
IOU systems, power marketers, joint-marketing agencies, load aggregators,
independent power producers, and exempt wholesale generators. NEPOOL's main
functions are to coordinate, monitor, and direct the operations of virtually
all of the major generation and transmission bulk power supply facilities in
New England. NEPOOL's annual peak load exceeds 23,000 MW with resulting
capacity requirements over 28,000 MW (2000). NEPOOL's two primary objectives
are to assure the reliability of the bulk power supply in the New England
region while minimizing costs and fairly allocating them. It achieves these
two objectives primarily through central planning and dispatch of all of the
bulk power facilities in the region. A map of the NPCC-NEPOOL region and the
location of the generation assets being financed is provided in Figure 2-31.
FIGURE 2-32
NEPOOL ENERGY - YEAR 2001
[GRAPH]
FIGURE 2-31
NPCC-NEPOOL Region
[GRAPH]
As illustrated in Figure 2-32 and 2-33, the NEPOOL area is dependent on gas-
and oil-fired resources for baseload generation, accounting for 39% of the
energy produced in New England. Nuclear generation represents approximately
30% of the total generation and coal represents approximately 19%. Gas- and
oil-fired generation units account for 55% of the installed capacity in
FIGURE 2-33
NEPOOL CAPACITY - YEAR 2001
[GRAPH]
Sources: Figure 2-32: PA Consulting Group Regional Modeling results. Figure
2-33: NPCC Load, Capacity, Energy, Fuels, and Transmission Report, Forecast
Data as of January 1, 2000, April 1, 2000; and PA Consulting Group.
2-36
NEPOOL. 2.9.2 POWER MARKETS
A. INTRODUCTION
The MAGI assets are located in the NEPOOL-Maine and NEPOOL-Southeast regions.
NEPOOL-Maine includes many utilities in Maine such as Bangor Hydro-Electric
Company, Central Maine Power Company, Maine Cooperative, and Maine Public
Services Company. NEPOOL-Southeast includes the Boston Edison Company,
Commonwealth Energy System Companies, Eastern Utilities Associates Companies,
Hudson Light and Power Department, Massachusetts Municipal Wholesale Electric
Company, and New England Electric System Operating Companies, as well as
several smaller light plants and departments.
The NEPOOL market structure is currently going through significant changes.
The Operable Capability Market was disbanded on March 1, 2000 and the
Installed Capability Market was disbanded on August 1, 2000. As a result, the
five structures in place in NEPOOL at the close of 2000 were:
i. Energy
ii. Automatic Generation Control (AGC)
iii. Ten Minute Spinning Reserve (TMSR)
iv. Ten Minute Non-Spinning Reserve (TMNSR)
v. Thirty-Minute Operating Reserve (TMOR).
ISO-NE oversees the Internet-based trading of the five wholesale electricity
products that are bought and sold in New England daily. FERC is currently
hearing proposed changes in the NEPOOL Market presented by ISO-NE and the
generators that produce the region's power.
A bid is comprised of all the information submitted by a participant that
relates to bid price, quantity, technical bid parameters, and timing of
offers for a generator or dispatchable load to provide specific services in
one or more of the defined markets. The bid price is the amount that a
participant offers to accept in a notice furnished to the system operator, in
this case ISO-NE. The bid price is meant to compensate for:
o preparing the start up or starting up or increasing the level of operation
of a generator or units to provide energy to other participants
o having a generator or units available to provide Operating Reserve to
other participants
o having a generator or units available to provide AGC to other participants
o providing to other participants Energy, Operating Reserve, or AGC.
B. MARKETS
i. THE ENERGY MARKET
The energy market is currently structured so generators submit $/MWh hourly
bids on a day-ahead basis for the next 24 hours. Based on these bids, ISO-NE
schedules the generating units that will provide energy on the following day
with the objective of minimizing total costs in the energy market. Hourly
settlement occurs after the fact. Suppliers receive and buyers pay amounts
equal to the MWh sold and bought, respectively, multiplied by the ex post
facto energy clearing price. Compensation to the out-of-merit unit is the
higher of the bid or market clearing price. There is only one financial
settlement, based on the actual energy quantity bought/sold in real time. In
the event that transmission constraints occur, congestion costs will be
apparent in the difference in energy prices between or among nodes and will
reflect the marginal cost of supplying additional demand at each node in any
given hour. The payment that generators will receive will be the nodal price
at the point of injection into the system. Load will pay the load-weighted
average of the nodal prices in the zone in which it withdraws energy from the
system. This system is currently under review, as will be discussed in the
Anticipated Market Changes section.
ii. AUTOMATIC GENERATION CONTROL (AGC) MARKET
AGC is a measure of the ability of a generating unit to provide instantaneous
control balance between load and generation and help maintain proper tie line
bias. This is done to control frequency and to maintain currently proper
power flows into and out of the NEPOOL Control Area. In short, AGC is
basically a ramping service to follow the second-to-second fluctuations in
load and supply. AGC responds to the NEPOOL Area Control Error (calculated
every four seconds) in an effort to continuously balance the NEPOOL Control
Area's supply resources with minute to minute load variations in order to
meet the NERC and NPCC Control Performance Standards. AGC performs the
ancillary service known as regulation. In the absence of AGC services,
interconnected control area operation and control area frequency control
could not be adequately maintained. Participants give one day advance bids
2-37
for a Generator supplying AGC to the market in terms of $/hr. Each Generator
must have a separate AGC bid for each hour of the following day. An AGC Bid
may include up to four Regulating Ranges for a single Generator, each defined
by an Automatic High and Low Limit and an Automatic Response Rate.
ISO-NE calculates a lost opportunity payment and a production cost charge for
AGC if the resource is committed to AGC. The system operator ranks generators
according to their AGC bid, the generator's opportunity cost payment, and the
AGC production cost change to select resources for AGC service. Generators
successful in the AGC market are paid for the revenues they would otherwise
have received plus compensation for the loss in efficiency of their units.
However, given the large number of generators in NEPOOL that have AGC
capability, PA does not expect that the AGC market will yield substantial
margins to generators.
Operating Reserves (OR) are the necessary level of generation capability that
must be available at all times for increased generation output. ORs are
needed to maintain system reliability in the event of an instantaneous loss
of a generating unit or transmission interconnection with surrounding control
areas. NERC and NPCC require operating reserve availability in all control
areas to protect against significant contingencies such as changes or
reductions in supply sources. The three types of operating reserves are
Ten-Minute Spinning (TMS), Ten-Minute Non-Spinning (TMNS), and Thirty-Minute
Operating Reserves (TMOR). All three combine with the AGC market to produce
the four bid-based ancillary service markets. Each reserve has its own market
and bidding process.
iii. TEN-MINUTE SPINNING RESERVE (TMSR)
TMSR provides contingency protection to ISO-NE's system. TMSR is measured as
the kilowatts of Operable Capability that an electrical generating unit can
provide. This unit, unloaded during all or part of the hour, is able to load
to supply energy on demand (within ten minutes), reach its maximum generating
capacity in under ten minutes, and able to sustain the maximum output level
for over thirty minutes. A TMSR unit is also capable of providing contingency
protection by immediately reducing energy requirements within ten minutes and
maintaining the reduced requirements ISO-NE determines.
In the initial market, bidding in the ten-minute spinning reserve market is
restricted to hydroelectric, pumped storage, and dispatchable load resources.
All on-line generation that is capable of raising generation can supply TMSR.
Bidders submit hourly bids in $/MW for the next day and designate the reserve
market for their bids. The ISO-NE ranks generators from least to most
expensive. In the case of TMSR, this includes consideration of lost
opportunity cost and production cost differences should the unit be committed
to TMSR instead of the energy market.
iv. TEN-MINUTE NON-SPINNING RESERVE (TMNSR)
TMNSR is generation that can reliably be connected to the network and loaded,
or load that can reliably be removed from the network, within ten minutes of
activation on a sustainable basis. TMNSRs are any resources and requirements
that were able to be designated for the TMSR but were not designated by the
system operator for such duties during the a specific hour. Surplus TMSR can
be counted as TMNSR.
v. THIRTY-MINUTE OPERATING RESERVE (TMOR)
TMOR is generation output that is available to the system operator within 30
minutes after request or load that can reliably be removed from the network
within 30 minutes on a sustainable basis. TMORs are any resources and
requirements that were able to be designated for the TMSR and TMNSR but were
not designated by the system operator for such duties during a specific hour.
Surplus TMSR and TMNSR can be counted as TMOR. The NE-ISO may contract for
additional ancillary services as needed.
vi. ANTICIPATED MARKET CHANGES
The entire NEPOOL Market is currently undergoing significant changes. It now
claims five bid-based markets after two were laid to rest during the year
2000. Neighboring regions of PJM and New York appear to be tracked to a
highly efficient, de-regulated system. New England has built a solid market
structure over the past four years. NEPOOL is continually changing in an
effort to achieve further reliability and cost gains. ISO-NE is proposing
various market revisions be implemented as soon as possible. As of late 2000,
the optimistic estimate for when full implementation of a Congestion
Management/Multi-Settlement System (CMS/MSS) could be in place was sometime
in 2003. The completion would occur in two phases. Phase I deals with the
Congestion Management System's details and is scheduled for completion
sometime in mid-2002. Phase II's schedule deals with the forming of the Multi
Settlement System. Details are still being resolved and will not be concrete
until late 2001.
2-38
There is speculation that Phase II will take at least 12
months to fully implement after the completion of Phase I. Hence the
optimistic 2003 completion date for full implementation of the envisioned
CMS/MSS system. The CMS/MSS plans contain numerous new market design
elements. A discussion of some of the major changes follows.
A multi-settlement system (MSS) is being proposed. This will be a
two-settlement system involving a day-ahead market and a real-time market for
energy and ancillary services. It is expected to run as follows. Prices and
scheduled quantities for each product will be established based on a
day-ahead bid that binds the participant into a financial settlement on the
following day. Separate prices will be determined for real time operations,
and a second binding financial settlement will be made based on changes in
real time from the day-ahead schedule.
A permanent Congestion Management System (CMS) is expected to be implemented
sometime in 2002. ISO-NE would manage transmission congestion based on LMPs.
Hourly energy prices paid to generators would vary at each node (300 to 600
locations currently envisioned) to reflect transmission congestion. ISO-NE
would establish eight load zones based on reliability regions. Loads would
pay the weighted average of the nodal prices in the zone, based on historical
load patterns for that zone. Zonal pricing of load is needed for two reasons.
The majority of New England's distribution companies are required to provide
uniform pricing in their region of operation and the necessary metering is
not in place in all areas to implement nodal pricing of loads. Transmission
customers would not bid for transmission; instead, a customer taking
transmission service would be required to pay the applicable transmission
congestion charge. FERC accepted ISO-NE's proposal for a permanent CMS,
requiring it to contain a choice between zonal and nodal bidding by the
completion of Phase II. ISO-NE plans to have generators submit a three-part
bid on a daily basis. The three parts will be comprised of energy production,
no-load, and start-up. Generators would be scheduled over the day to minimize
total bid costs, but the energy price would be set based only on the energy
bid of the marginal supplier. The logic behind this pricing is it reflects
the marginal bid-cost of producing energy. The three-part bid should allow
generators to bid a more accurate representation of their cost functions.
This three-part bid has been approved by FERC with the requirement ISO-NE
submit an evaluation of its efficiency after the MSS has been in operation
for six months.
Proposed changes to the ancillary service markets include a system where
generators submit combined bids for both energy and spinning reserves.
Currently, generators submit separate bids for energy and each of the four
ancillary services. ISO-NE considers all of these bids jointly in determining
how to schedule and dispatch generators to meet the energy and ancillary
services requirements while minimizing total cost. Under the proposed system,
three-part bids would be submitted into the auction. ISO-NE would decide
which participant provides energy and which distributes spinning reserves.
(The ISO would continue to consider all bids jointly when developing a least
total cost schedule.) The price paid for spinning reserves would then reflect
the opportunity cost of not selling energy. The opportunity cost would be
calculated by taking the difference between the applicable energy price and
the generator's energy bid. However, until ISO-NE can demonstrate market
power exists in the spinning reserve market, this proposal was denied by FERC
on June 28, 2000.
ISO-NE is proposing to take price into consideration in determining how much of
each ancillary service to purchase in the day-ahead market. Currently, ISO-NE
purchases the required amount of ancillary services regardless of the price. It
is feasible for suppliers to set prices arbitrarily high in times of limited
excess capacity. Under the new plan, a demand curve will be derived for each
ancillary service. This would be accomplished by predicting the amount of each
ancillary service that loads would be willing to buy at numerous prices. ISO-NE
would coordinate this estimated demand curve with supply bids to determine how
much of each ancillary service to purchase daily. ISO-NE states that the demand
curves will help avoid overpaying for an ancillary service. ISO-NE is the first
independent system operator to propose using demand curves in procuring
ancillary services. Given the current plan's ambiguity (derivation of demand
curves and exact benefits of the proposal are still unclear), FERC has approved
requests to apply price or bid caps.
The four-hour reserve is a non-spinning reserve designed to encourage accurate
demand-side bidding in the day-ahead market. ISO-NE anticipates it will provide
adequate capacity in the real-time market. ISO-NE wants to make its own forecast
on demand and compare the forecast to the quantity of energy scheduled in the
day-ahead market. If ISO-NE's demand forecast exceeds the day-ahead scheduled
quantity, purchases made on the four-hour reserve market would allow them to
make up the difference. The plan calls for operating reserves to be substituted
for four-hour reserves if the cost is cheaper. The cost
2-39
of four-hour reserves is allocated to participants who underbid their load
day-ahead. ISO-NE projects the real-time price will be typically higher than
the day-ahead price, and thus will provide an adequate penalty for
non-performance. FERC has approved the proposal for four-hour reserves,
recognizing it could improve reliability. Some areas have to be worked on
before implementation, such as the fact that ISO-NE will determine the amount
of four-hour reserves based on its forecast, but it does not pay for the
reserves. ISO-NE will work with New York and PJM ISOs in designing this
market.
C. STATE RESTRUCTURING STATUS
The states in the NEPOOL region are in different stages of restructuring their
retail markets. The states of Massachusetts and Rhode Island have already
established retail competition, while Connecticut, Maine and New Hampshire are
expected to start retail competition in the near future. The New Hampshire
legislature has been in litigation with Public Service Company of New Hampshire
over recovery of stranded costs. Further hearings on this issue occurred in
2000. The state of Vermont has started an investigation into retail competition
following a voluntary plan submitted by the IOUs in March 1999.
i. CONNECTICUT
In April 1998, restructuring legislation was passed that required retail
competition for 35% of consumers by January 2000 with all customers having
retail competition by July 2000. In April 1999, the Department of Public
Utility Control (DPUC) ordered generation charges be shown as a separate
charge beginning July 1999. As of June 1999, no suppliers had yet applied for
licensing to serve Connecticut's market upon its January 2000 opening. From
January 1, 2000 through January 1, 2004, each distribution company is
required to provide a standard offer rate that is at least 10% less than the
December 31, 1996 base rates. Beginning January 1, 2004, a distribution
company will procure generation services for customers who do not have an
alternate supplier through competitive bidding. Also, electric suppliers are
required to obtain specific percentages of their power from renewable energy
sources, with percentage increases each year through 2009.
In August 2000, Northeast Utilities announced that Dominion Resources will
pay approximately $1.3 billion for its three-unit Millstone nuclear station.
The transaction is expected to be complete by April 2001, pending approval
from several state and federal agencies. This followed news of a Connecticut
restructuring law passed in 1999 that required the sale of nuclear assets by
2004.
ii. MAINE
Following legislation, Maine customers started seeing itemized billing that
separated the costs of power generation from delivery in January 1999. A bill
was passed in the early part of 2000 that delayed the startup of competitive
billing and metering until March 2003. That date is when billing services
will be subject to competition. Large IOUs are not allowed to have affiliates
sell more than 33% of the kilowatt-hours sold within their regulated service
territories. They are also not allowed to provide standard offer service for
more than 20% of their regulated-affiliates' load.
In August 2000, the Maine PUC approved a transmission/distribution rate
scheme submitted by the Maine Public Service Company and the Maine Office of
the Public Advocate. The order separates Maine Public Service Company's
overall transmission and distribution revenue requirements into a
transmission component under FERC jurisdiction and a distribution component
under the PUC's jurisdiction.
Statistics released by the Maine Public Service Commission (PSC) in September
2000 show that 26% of all electricity delivered by the State's three major
utilities is being purchased from alternative suppliers (retail competition).
However, industrial customers are purchasing the bulk of that load. In
contrast, 6% of residential and small commercial customers have switched
providers. Thus, the total number of residential and small commercial
customers served by competitive providers is 1,500 customers.
In October 2000, the Maine Public Service Commission (PSC) approved a 33%
rate increase for the 107,000 customers who use Bangor Hydro's standard
offer. The rate increase was requested by Bangor Hydro to pay for rising oil
and natural gas costs. The average residential customer will pay about 6.1
cents/kWh compared to the 4.6 cents/kWh they were paying before the increase.
The Commission said that it is possible that another increase will occur
after winter if fuel costs continue to increase.
iii. MASSACHUSETTS
Massachusetts consumers began to sign up to purchase power from competitive
suppliers in June 1998. In September 1998, Pennsylvania Gas &
2-40
Electric secured a multi-year contract with the Massachusetts High Technology
Council to provide electricity to its members. This is the largest
aggregation of customers in the United States, representing approximately 1.2
million MWh annually.
The Department of Telecommunications and Energy (DTE) established two options
for default service rates in June 2000. The first called for default service
customers (defined as those customers who have left their competitive supplier,
or are new to the utility's territory) to choose between a six-month fixed price
option and a variable monthly rate. Customers that switch between competitive
and fixed-price service during a six-month period will have their bills for all
six months adjusted. The purpose of this is to prevent customers and suppliers
from gaming the system. In July 2000, the DTE issued a rule that called for
utilities to base their rates for default service on the wholesale bid prices.
The plan for the rule was to have it implemented in January 2001. Utilities
complained that the required rate, set below the cost of wholesale power, was
causing them to lose money on default customer accounts. Utilities may begin
issuing competitive bids seeking 6-month to 1-year contracts for the power
needed to serve their default service customers. The DTE is also looking into
eliminating exclusive service territories for IOUs.
Customer migration statistics released in September 2000, show that real retail
competition has yet to begin in Massachusetts. The Massachusetts Division of
Energy Resources reported that 5,176 customers bought power from competitive
generators in July 2000 as compared to 2.5 million customers who received power
from their incumbent utility. This low switching rate was expected in
Massachusetts since competitive generators cannot offer better deals than the
incumbent utilities until the standard offer price rises over a seven-year
transition period.
iv. NEW HAMPSHIRE
New Hampshire was among the first few states in the country to enact electric
deregulation legislation. However, because of disagreements with the Public
Service Company of New Hampshire (PSNH) and the state government over the size
of rate cuts and stranded cost recovery the process had been delayed until
recently. Legislation was passed and signed into law in June 2000. PSNH will
reduce rates by an average 15.5% for businesses and 17% for residential
consumers. Residential rates will be capped for nearly three years, and
businesses' rates for nearly two years. In September 2000, the New Hampshire
Public Utilities Commission (PUC) approved a settlement of the restructuring of
PSNH. The entity can now begin refinancing $800 million in debt to be paid off
over 12 to 14 years. PSNH agreed to absorb $450 million of its $2.3 billion in
stranded costs as part of the settlement. PSNH will divest its generation assets
by July 2001, and operate as a transmission and distribution utility, regulated
by the state. In October 2000, PSNH announced the end its pilot program as of
November 30, 2000. About 3,000 customers were part of the program at the time.
In October 2000, lawsuits filed by consumer groups challenged the PSNH
restructuring settlement concerning stranded costs recovery as unconstitutional.
Competition was scheduled to begin in January 2001, with an accompanying rate
reduction of about 10.5%, but likely will be delayed further.
In June 2000, the New Hampshire Electric Cooperative voted to set their rates
and approve financing without oversight of the Public Utility Commission (PUC).
The PUC will, however, continue overseeing contracts between the cooperative and
outside suppliers, IPPs, municipal utilities, and deregulation activities within
the service territory.
v. RHODE ISLAND
The state legislature opened up full customer choice on July 1, 1998. As of June
1999, roughly 2,000 customers out of the State's 456,000 had chosen alternative
generation suppliers. Retail access was implemented with 25 registered
suppliers, but the standard offer interim rates (3.2 cents/kWh) offered by the
State's IOUs were low enough that no real competition has occurred. The rates
have been increased three times to 4.5 cents/kWh because of increased wholesale
prices. As a result, competition has begun to emerge.
A 2.8 cent/kWh transition charge is assessed to customers for the first three
years in order to recover stranded costs. A standard offer rate offered to
customers who have never chosen a supplier will be based on 1996 prices plus
inflation until the year 2009.
In October 2000, the Rhode Island PUC approved a 10.6% increase request by
Narragansett Electric. Standard offer rates were increased from 4.5 cents/kWh to
75.4 cents/kWh. A typical residential customer's bill is expected to increase
about $4.50 per month. As part of its contract to purchase electricity for its
customers, Narragansett must pay a
2-41
fuel surcharge when oil and natural gas prices increase.
2.9.3 MARKET DYNAMICS
MAGI's assets in this report include three existing plants representing 1,232
MW of capacity that participate in NEPOOL's wholesale electric markets.
Figure 2-34 illustrates the load and resource balance for NEPOOL through the
end of the study period. During the period 1998-2000, peak demands have grown
at an average annual rate of 4.2%. The NEPOOL market is forecasted to grow an
annual compound growth rate of 1.47%. The system-wide reserve margin is
assumed to be 15%.
Historical prices for NEPOOL are presented in Appendix A.
2.9.4 TRANSMISSION SYSTEM
On July 1, 1997 New England's Independent System Operator (ISO-NE) was
established as a non-profit corporation responsible for the management of the
region's bulk power generation and transmission systems. Created by NEPOOL,
ISO-NE has responsibilities to its parent that are defined in an independent
system operator contract. ISO-NE administers the NEPOOL Tariff transmission
facilities in a fair and neutral manner with reliability and
cost-effectiveness as the two driving forces.
FIGURE 2-34
NEPOOL LOAD AND RESOURCE BALANCE
[GRAPH]
There are two types of transmission service. The first is known as "through"
or "out service." This covers transmission service routed through the NEPOOL
Control Area. The other transmission service is known as Regional Network
Service (RNS). This covers the remaining types of regional service routed
through the NEPOOL Control Area. The charges for these services are
determined by Schedules 8 and 9 of the Tariff. Transmission rates are
recalculated on June 1st of each year, as stated in the Tariff. There are
three transmission interfaces between New England and neighboring regions.
These are New York, Hydro-Quebec, and New Brunswick.
2-42
2.9.5 PRICE FORECASTS FOR THE NEPOOL MARKET
A. BASE CASE
The base case compensation for capacity, energy, and all-in market price
forecasts are presented in Figure 2-35 and Table 2-10 for the NEPOOL-Maine and
NEPOOL-Southeast pricing areas. The prices decline and bottom out in 2005 due
to the current level of operation expansion. Based on the assumptions presented
herein, the market begins to rebound in 2006, reaching equilibrium in 2009.
In addition to the fundamental numbers reported in Table 2-10, PA used monthly
average daytime electricity forwards for 2001-2003. The monthly electricity
price forwards for 2001-2003 used in the volatility forecast for the NEPOOL
region are listed in Appendix A. For the period 2004-2020, the volatility
results were calibrated to the fundamental results shown in Table 2-10.
FIGURE 2-35
NEPOOL BASE CASE COMPENSATION
FOR CAPACITY, ENERGY, AND ALL-IN PRICE FORECASTS(1)
[TWO GRAPHS]
(1) Results are expressed in real 2000 dollars.
- ---------------------------------------------------------------
TABLE 2-10
NEPOOL BASE CASE FORECASTS(1)
FUNDAMENTAL ANALYSIS
- ---------------------------------------------------------------
NEPOOL-MAINE NEPOOL-SOUTHEAST
COMP. FOR ----------------------------------------
CAPACITY ENERGY ALL-IN ENERGY ALL-IN
YEAR ($/KW-YR) ($/MWH) ($/MWH) ($/MWH) ($/MWH)
- ---------------------------------------------------------------
2001(2) 34.20 37.00 40.90 37.80 41.70
- ---------------------------------------------------------------
2002(2) 22.70 32.90 35.50 33.20 35.80
- ---------------------------------------------------------------
2003(2) 18.70 31.60 33.70 31.80 33.90
- ---------------------------------------------------------------
2004 26.50 27.20 30.20 27.10 30.10
- ---------------------------------------------------------------
2005 26.00 23.60 26.60 23.50 26.50
- ---------------------------------------------------------------
2006 25.50 24.20 27.10 24.00 26.90
- ---------------------------------------------------------------
2007 31.60 23.80 27.40 23.70 27.30
- ---------------------------------------------------------------
2008 38.20 24.30 28.60 24.20 28.50
- ---------------------------------------------------------------
2009 67.70 24.70 32.40 24.60 32.30
- ---------------------------------------------------------------
2010 67.10 25.20 32.80 25.00 32.70
- ---------------------------------------------------------------
2011 66.60 25.30 32.90 25.10 32.70
- ---------------------------------------------------------------
2012 66.10 25.40 33.00 25.20 32.80
- ---------------------------------------------------------------
2013 63.80 25.80 33.10 25.60 32.80
- ---------------------------------------------------------------
2014 63.50 25.90 33.10 25.60 32.80
- ---------------------------------------------------------------
2015 64.30 25.90 33.20 25.50 32.90
- ---------------------------------------------------------------
2016 63.10 25.60 32.80 25.70 32.90
- ---------------------------------------------------------------
2017 63.40 25.60 32.80 25.60 32.90
- ---------------------------------------------------------------
2018 62.90 25.70 32.90 25.60 32.80
- ---------------------------------------------------------------
2019 62.40 25.60 32.70 25.70 32.80
- ---------------------------------------------------------------
2020 61.90 25.70 32.80 25.70 32.80
- ---------------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
(2) 2001-2003 volatility results are calibrated to the forwards
prices versus the model results presented herein.
- ---------------------------------------------------------------
2-43
B. SENSITIVITY CASES ANALYSIS
The all-in prices for three of the sensitivity cases described in Section 2.2
are shown in Figure 2-36 and Table 2-11 for the NEPOOL-Maine and
NEPOOL-Southeast pricing areas. All-in prices for the high fuel case are
approximately $14- to $17/MWh higher than the base case for the majority of the
study period. Low fuel all-in prices follow a slightly lower parallel path as
compared to the base case. In the overbuild case, prices are depressed as much
as $5/MWh until 2011, when the market absorbs the excess capacity.
FIGURE 2-36
NEPOOL SENSITIVITY CASES
ALL-IN PRICE FORECASTS(1) ($/MWH)
[TWO GRAPHS]
(1) Results are expressed in real 2000 dollars.
- -----------------------------------------------------------
TABLE 2-11
NEPOOL SENSITIVITY CASES
ALL-IN PRICE FORECASTS(1) ($/MWH)
- -----------------------------------------------------------
BASE HIGH LOW
YEAR CASE FUEL FUEL OVERBUILD
- -----------------------------------------------------------
NEPOOL-MAINE
- ----------- ----------- ---------- ----------- ------------
2001 40.90 40.90 37.90 40.90
- ----------- ----------- ---------- ----------- ------------
2002 35.50 38.90 33.40 35.50
- ----------- ----------- ---------- ----------- ------------
2003 33.70 39.30 32.10 33.70
- ----------- ----------- ---------- ----------- ------------
2004 30.20 39.50 28.60 29.80
- ----------- ----------- ---------- ----------- ------------
2005 26.60 40.50 25.90 26.10
- ----------- ----------- ---------- ----------- ------------
2006 27.10 41.70 26.40 26.40
- ----------- ----------- ---------- ----------- ------------
2007 27.40 41.30 26.10 26.10
- ----------- ----------- ---------- ----------- ------------
2008 28.60 41.60 27.10 26.50
- ----------- ----------- ---------- ----------- ------------
2009 32.40 42.40 30.60 27.10
- ----------- ----------- ---------- ----------- ------------
2010 32.80 48.00 31.00 27.80
- ----------- ----------- ---------- ----------- ------------
2011 32.90 48.40 31.00 32.80
- ----------- ----------- ---------- ----------- ------------
2012 33.00 48.60 31.20 33.10
- ----------- ----------- ---------- ----------- ------------
2013 33.10 48.70 31.20 32.90
- ----------- ----------- ---------- ----------- ------------
2014 33.10 48.50 31.20 32.90
- ----------- ----------- ---------- ----------- ------------
2015 33.20 48.50 31.30 33.00
- ----------- ----------- ---------- ----------- ------------
2016 32.80 48.10 30.90 32.90
- ----------- ----------- ---------- ----------- ------------
2017 32.80 47.90 30.90 33.00
- ----------- ----------- ---------- ----------- ------------
2018 32.90 47.80 30.90 33.10
- ----------- ----------- ---------- ----------- ------------
2019 32.70 47.80 30.90 33.00
- ----------- ----------- ---------- ----------- ------------
2020 32.80 47.80 30.70 32.90
=========== =========== ========== =========== ============
NEPOOL-SOUTHEAST
- ----------- ----------- ---------- ----------- ------------
2001 41.70 41.70 38.70 41.70
- ----------- ----------- ---------- ----------- ------------
2002 35.80 39.30 33.70 35.80
- ----------- ----------- ---------- ----------- ------------
2003 33.90 39.40 32.20 33.90
- ----------- ----------- ---------- ----------- ------------
2004 30.10 39.60 28.50 29.50
- ----------- ----------- ---------- ----------- ------------
2005 26.50 40.40 25.70 25.90
- ----------- ----------- ---------- ----------- ------------
2006 26.90 41.40 26.20 26.10
- ----------- ----------- ---------- ----------- ------------
2007 27.30 41.20 26.00 25.80
- ----------- ----------- ---------- ----------- ------------
2008 28.50 41.60 27.00 26.20
- ----------- ----------- ---------- ----------- ------------
2009 32.30 42.20 30.40 26.80
- ----------- ----------- ---------- ----------- ------------
2010 32.70 47.80 30.90 27.50
- ----------- ----------- ---------- ----------- ------------
2011 32.70 48.20 30.90 32.50
- ----------- ----------- ---------- ----------- ------------
2012 32.80 48.40 30.90 32.80
- ----------- ----------- ---------- ----------- ------------
2013 32.80 48.40 31.00 32.60
- ----------- ----------- ---------- ----------- ------------
2014 32.80 48.20 30.90 32.70
- ----------- ----------- ---------- ----------- ------------
2015 32.90 48.10 31.00 32.80
- ----------- ----------- ---------- ----------- ------------
2016 32.90 48.40 31.00 33.10
- ----------- ----------- ---------- ----------- ------------
2017 32.90 48.00 31.00 33.10
- ----------- ----------- ---------- ----------- ------------
2018 32.80 47.80 30.80 33.10
- ----------- ----------- ---------- ----------- ------------
2019 32.80 47.90 30.90 33.20
- ----------- ----------- ---------- ----------- ------------
2020 32.80 48.00 30.70 32.90
- -----------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
- -----------------------------------------------------------
2-44
2.9.6 DISPATCH CURVES
Dispatch curves for the NEPOOL region for 2001 and 2010 are shown in Figure
2-37. The relative position of the plants in this report are located along the
dispatch curve.
FIGURE 2-37
NEPOOL DISPATCH CURVES FOR 2001 AND 2010
[TWO GRAPHS]
2-45
2.10 ERCOT
2.10.1 BACKGROUND
ERCOT represents a bulk electric system located totally within the state of
Texas and serves about 85% of Texas's electrical load. It has a generating
capability of about 65,000 MW and experienced a 2000 summer peak demand of
57,606 MW. Due to Texas' intrastate status, the primary regulatory authority of
ERCOT is the Public Utility Commission of Texas (PUCT), which is overseen by
FERC. ERCOT membership includes retail consumer, municipal owned generation and
transmission, and thirteen Independent Power Producers. ERCOT is currently in
the process of implementing retail transactions beginning with a trial run
starting on June 1, 2001 and full operations beginning on January 1, 2002.
While other states are reconsidering their plans to implement deregulation of
electricity markets, Texas is proceeding as planned. The Public Utility
Commission of Texas believes that the substantial amount of new and planned
generating capacity additions will provide adequate reserve margins which will
ensure Texas does not have the same problems experienced with California's
deregulation efforts. A map of the ERCOT region is provided in Figure 2-38.
As illustrated in Figure 2-39 and Figure 2-40, ERCOT is largely dependent on
gas, oil, and coal-fired resources for baseload generation. Gas/oil-fired
generation is the predominant resource in terms of both the installed capacity
and energy production accounting for 68% of the capacity in the region and 46%
of the energy produced. Coal and nuclear facilities account for the remaining
installed capacity and energy production in the region.
2.10.2 POWER MARKETS
ERCOT does not have a power exchange functioning within Texas at this time.
Power is bought and sold through bilateral agreements. The Texas Senate passed
Senate Bill 7 in March 1999. The bill specified that the Texas electric market
will open for competition on January 1, 2002 for all retail customers of IOUs.
This includes open access to transmission and distribution systems (municipal
systems and cooperatives have the option of joining).
FIGURE 2-38
ERCOT REGION
[MAP]
FIGURE 2-39
ERCOT ENERGY - YEAR 2001
[GRAPH]
FIGURE 2-40
ERCOT CAPACITY - YEAR 2001
[GRAPH]
Sources: Figure 2-39: PA Consulting Group Regional Modeling results. Figure
2-40: ERCOT 1999 EIA-411, data submittal to NERC; and PA Consulting Group.
2-46
As part of this restructuring plan, IOUs must unbundle their generation,
transmission, and distribution services. The goals of the bill include ensuring
continued system reliability, maintaining an information database, and
establishing a settlement system to account for production and delivery.
One element of the upcoming transition to a single control area is the
simplification of the settlement of the retail access market and elimination of
control area disparities. Senate Bill 7 makes it possible to perform
comprehensive grid operations, load balancing, frequency regulation, and to buy
ancillary services through bid processes. The system will also allow for
Qualified Scheduling Entities (QSEs).
No later than June 1, 2001, each IOU must offer customer choice in its service
area to 5% of its load.(5) Each utility with over 400 MW of installed capacity
will have a capacity auction, at least 60 days before customer choice.(6) In
the auctions, utilities must sell entitlements to at least 15% of their Texas
jurisdictional installed generation capacity. The duration of the entitlements
will last from one month to four years. The obligation to auction the
entitlements will continue for five years or until the date when 40% or more of
the electric power consumed by residential and small commercial customers
within the affiliated transmission and distribution utility's service area is
provided by nonaffiliated REPs. Affiliates cannot purchase entitlements from
affiliates at these auctions. In addition, electric utilities may choose to
auction entitlements in excess of the required 15%.
Data presented in ERCOT's 1999 EIA 411 report, indicated that ten Texas
utilities will be required to auction off at least 15% of their total installed
generation capacity, totaling approximately 7,530 MW.
i. LIMITATION OF OWNERSHIP
Beginning on the date of introduction to customer choice (the same date where
the auctioning off of 15% of installed capability for utilities with over 400
MW available is required), a power generation company may not own and control
more than 20% of the installed generation capacity.(7) This pertains to
utilities with over 20% capacity located in, or capable of delivering
electricity to, a power region. If a power region is not entirely within the
state, the Commission may waive or modify this requirement on a finding of good
cause. In determining the percentage shares of installed generation capacity,
the Commission will combine capacity owned and controlled by a power generation
company and any entity affiliated with that company within the power region. It
will then reduce this amount by the installed generation capacity of those
facilities that are made subject to capacity auctions. In addition, the
Commission will reduce the installed generation capacity owned and controlled
by a power generation company by the installed generation capacity of any
"grandfathered facility"(8) within an ozone non-attainment area(9) as of
September 1, 1999. However, in exchange for this concession, the grandfathered
facilities will be required to reduce total NO(x) emissions by 50% and SO(2)
emissions by 25% (from the average annual emissions in 1997) by May 1, 2003.
ii. SETTLEMENT SYSTEM
Settlement could occur between ISO-ERCOT and QSE for a day ahead, hour ahead,
and real time market. The settlement process has not been fully worked out, but
certain specifics have been agreed upon. Charges and Payments to Generators and
REPs will be settled in two phases, the Initial Settlement Phase (ISP) and the
Adjustment Settlement Phase (ASP). The Initial Settlement Phase (ISP) will
settle for Imbalance Energy, Congestion Management, and Ancillary Services on
an hour-by-hour basis for the "trade day" based on actual meter data for
generators, and estimated meter data for end use load. The data for end use
load will be estimated using customer specific historical information and load
profiles. System balance will be achieved through submission of balanced
schedules on a
- ------------------------------
(5) 20% of the load in the pilot project must be set aside for aggregated loads.
(6) The auction applies to all IOUs and only those MOUs and cooperatives that
have chosen to participate in customer choice.
(7) Senate Bill 7 defines installed generation capacity as "all potentially
marketable electric generation capacity, including the capacity of: (1)
generating facilities that are connected with a transmission or distribution
system; (2) generating facilities used to generate electricity for consumption
by the person owning or controlling the facility; and (3) generating facilities
that will be connected with a transmission or distribution system and operating
within 12 months.
(8) Those facilities that were in existence or under construction in 1971 when
the Texas Clean Air Act permitting requirements took effect.
(9) Houston/Galveston, Beaumont/Port Arthur, Dallas/Fort Worth, and El Paso.
2-47
day-ahead basis and revision of schedules on an hour-ahead basis. Congestion
costs will be paid on a load ratio basis. If congestion costs exceed $20
million in twelve-month period, a Transmission Congestion Rights system may be
implemented.
The Adjustment Settlement Phase (ASP) will settle the hour to hour differences
between the ISP Imbalance energy, congestion management, and ancillary services
calculated using estimated meter data, and the imbalance energy, congestion
management, and ancillary services calculated using the actual meter data for
end use load. The actual end use meter data for customers may be profiled using
load profiles that are different from the profiles used in the ISP. For
example, static load profiles may be used during the ISP, and dynamic profiles
may be used in the ASP.
The settlement period will be hourly or less. Ancillary services that are
capacity based will be settled based upon the generator's capacity purchased
and actual energy associated with that capacity purchased. Ancillary services
that are response-based will be settled on measurement and other criteria
established by ERCOT, NERC, and the ISO.
2.10.3 MARKET DYNAMICS
MAGI's assets evaluated in this report include one existing plant representing
544 MW of capacity that participates in the ERCOT wholesale electricity market.
Figure 2-41 illustrates the load and resource balance for ERCOT through the end
of the study period. During the period of 1992-2000, peak demands have grown at
an average annual rate of 4.5%. The ERCOT market is forecasted to grown at an
annual compound rate of 2.7% from 2001 through 2020. A required system-wide
reserve margin is assumed to be 15% as PA believes the market will mature and
the required reserve margins will be lowered. The graph illustrates that
approximately 38 GW of new generation is required to meet load growth and
reserve margins. There are no significant capacity retirements anticipated in
the near term.
Historical prices for ERCOT are presented in Appendix A.
2.10.4 TRANSMISSION SYSTEM
ERCOT is somewhat isolated electrically from the rest of the United States.
There are two high voltage direct current interconnects with the Southwest
Power Pool (SPP) (345 kV and 138 kV), with a total import/export capability of
approximately 800 MW. This represents less than 2% of ERCOT's total installed
capacity and, hence, does not have a significant impact on market prices.
Future ties to the WSCC and additional ties to SPP are not foreseen in the near
future due to the lack of economic feasibility. The PUCT has established a
Synchronous Interconnect Committee to evaluate the potential for synchronously
interconnecting ERCOT with SPP. If ERCOT were to be synchronously
interconnected with the SPP and WSCC in the future, the market for ERCOT
resources would expand, as would the number of potential sellers. Figure 2-42
represents the major transmission lines (230 kV or higher) within and
surrounding ERCOT.
FIGURE 2-41
ERCOT LOAD AND RESOURCE BALANCE
[GRAPH]
2-48
FIGURE 2-42
THE ERCOT HIGH VOLTAGE TRANSMISSION SYSTEM(1)
[MAP]
(1) ERCOT's major transmission lines (230 kV or higher).
The transmission pricing methodology established by the PUCT in 1996 is the
basis for many current practices existing in ERCOT. Transmission service can
either be planned or unplanned. Planned service is longer than thirty days in
length and given to a specified load from designated resources. Unplanned
service is less than thirty days in length and is given to a specified load and
specified resource. Unplanned service is subject to the availability of surplus
transmission capacity after planned service is allocated its required share.
All wholesale utilities in ERCOT are required to submit their annual planned
transmission service applications to the ISO by October 1st of each year. The
ISO uses these applications to calculate the next year's transmission cost of
service. Seventy percent of the planned transmission service fee is based on
the average of the load's peak for the four annual peak months. For example, if
a load's four-month average peak is 5% of the ERCOT four-month average total,
the load pays 5% of 70% of the total annual transmission cost. The total annual
transmission cost is calculated by a standard formula determined by the PUCT.
The other 30% of the planned transmission service fee is determined by a
distance sensitive Vector Absolute Megawatt Mile method. The current pricing
system results in a 70% postage-stamp charge and a 30% distance sensitive
charge. The 70/30 method produces generation close to the load with a slight
pricing advantage. ERCOT is moving toward the adoption of a 100% postage-stamp
wholesale transmission tariff that will eliminate this advantage (other than
for transmission losses). Unplanned transmission service prices are just
$0.15/MWh and attributed as a scheduling fee to the ISO.
In 1995, the Texas Legislature passed Senate Bill 7, which deregulated the
wholesale generation market. The PUCT revised its rules to incorporate the
legislative changes. The PUCT rule changes called for an ISO to have three
major areas of responsibility. The first area was the security operations of
the bulk electric systems. The second was the facilitation of the efficient use
of the electric transmission system by all market participants including
administration of one ERCOT OASIS. The third area of ISO responsibility was the
coordination of future transmission planning in ERCOT.
An industry task force devised a restructuring plan for ERCOT. After membership
approval, implementation began on September 11, 1996, with market operations
starting in January 1997. The authority and responsibilities of the ISO include:
o real-time system monitoring (i.e., spinning reserve, scheduled and actual
net interchange, and critical transmission component loading)
o long-term system monitoring (i.e., control area planning, transmission
clearance requests and generation overhaul schedules)
o response to system contingencies (i.e., line loading relief, load
shedding, re-dispatch, and ordering emergency energy schedules)
o administration of the ERCOT OASIS (i.e., calculations and updating ATC)
o coordination of regional transmission planning
o transmission tariff administration, transmission reservation approval,
ancillary service verification, energy transaction scheduling, and
transaction accounting.
2-49
2.10.5 PRICE FORECASTS FOR THE ERCOT REGION
A. BASE CASE
This case models near-term fuel prices based on recent actual spot prices and
futures prices through December 2003, decreasing linearly to the long-term
consensus view by 2005. The prices decline rapidly through 2005 due to the
assumed gas price decreases and the projected surplus capacity in ERCOT. Prices
rebound and stabilize after 2006.
The all-in price represents a combined compensation for capacity and energy
price (assuming a 100% load factor). The compensation for capacity contribution
to the all-in price ranges between $1.30/MWh and $5.40/MWh.
The base case compensation for capacity, energy, and all-in market price
forecasts are presented in Figure 2-43 and Table 2-12 for the ERCOT pricing
area.
FIGURE 2-43
ERCOT BASE CASE COMPENSATION
FOR CAPACITY, ENERGY, AND ALL-IN PRICE FORECASTS(1)
[GRAPH]
(1) Results are expressed in real 2000 dollars.
- -----------------------------------------------------------
TABLE 2-12
ERCOT BASE CASE FORECASTS(1)
- -----------------------------------------------------------
YEAR COMPENSATION ENERGY ALL-IN
FOR CAPACITY PRICE PRICE
($/KW-YR) ($/MWH) ($/MWH)
- ------------- ----------------- ------------- -------------
2001 13.70 49.50 51.00
- ------------- ----------------- ------------- -------------
2002 11.30 39.70 41.00
- ------------- ----------------- ------------- -------------
2003 14.10 36.60 38.20
- ------------- ----------------- ------------- -------------
2004 14.60 31.40 33.10
- ------------- ----------------- ------------- -------------
2005 11.90 25.30 26.70
- ------------- ----------------- ------------- -------------
2006 26.70 25.30 28.30
- ------------- ----------------- ------------- -------------
2007 29.40 25.10 28.40
- ------------- ----------------- ------------- -------------
2008 31.00 25.20 28.80
- ------------- ----------------- ------------- -------------
2009 32.80 24.90 28.60
- ------------- ----------------- ------------- -------------
2010 34.10 24.80 28.70
- ------------- ----------------- ------------- -------------
2011 35.80 24.40 28.50
- ------------- ----------------- ------------- -------------
2012 38.10 24.20 28.50
- ------------- ----------------- ------------- -------------
2013 43.20 23.80 28.70
- ------------- ----------------- ------------- -------------
2014 45.60 23.80 29.00
- ------------- ----------------- ------------- -------------
2015 45.90 23.70 28.90
- ------------- ----------------- ------------- -------------
2016 47.00 23.90 29.30
- ------------- ----------------- ------------- -------------
2017 47.10 23.70 29.00
- ------------- ----------------- ------------- -------------
2018 47.20 23.70 29.10
- ------------- ----------------- ------------- -------------
2019 47.50 23.70 29.10
- ------------- ----------------- ------------- -------------
2020 47.70 23.50 29.00
- -----------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
- -----------------------------------------------------------
2-50
B. SENSITIVITY CASES ANALYSIS
The all-in prices for two of the sensitivity cases described in Section 2.2 are
shown in Figure 2-44 and Table 2-13. All-in prices for the high fuel case do
not experience the slight decrease in 2005 associated with the drop to
consensus fuel in the base case. Since ERCOT relies on gas/oil for much of its
generation, high fuel prices escalate the all-in prices to almost $20/MWh
greater than the base case. The low fuel case results in an all-in price drop
of approximately $2/MWh throughout the study period.
The greater effect of the high fuel case as compared to the low fuel case is
largely due to the severity of the change in fuel prices. The high fuel case
assumes an average 75% increase in gas prices over the study period compared to
a 10% decrease for the low fuel case.
FIGURE 2-44
ERCOT SENSITIVITY CASES
ALL-IN PRICE FORECASTS ($/MWH)
[GRAPH]
(1) Results are expressed in real 2000 dollars.
- ---------------------------------------------------------
TABLE 2-13
ERCOT SENSITIVITY CASES
ALL-IN PRICE FORECASTS(1) ($/MWH)
- ---------------------------------------------------------
BASE HIGH LOW
YEAR CASE FUEL FUEL
- ------------- -------------- -------------- -------------
2001 51.00 51.00 46.30
- ------------- -------------- -------------- -------------
2002 41.00 46.70 37.30
- ------------- -------------- -------------- -------------
2003 38.20 46.60 34.70
- ------------- -------------- -------------- -------------
2004 33.10 48.60 30.20
- ------------- -------------- -------------- -------------
2005 26.70 48.80 24.50
- ------------- -------------- -------------- -------------
2006 28.30 48.30 26.40
- ------------- -------------- -------------- -------------
2007 28.40 47.50 26.50
- ------------- -------------- -------------- -------------
2008 28.80 47.40 26.90
- ------------- -------------- -------------- -------------
2009 28.60 45.90 26.70
- ------------- -------------- -------------- -------------
2010 28.70 45.10 26.80
- ------------- -------------- -------------- -------------
2011 28.50 44.70 26.60
- ------------- -------------- -------------- -------------
2012 28.50 44.40 26.70
- ------------- -------------- -------------- -------------
2013 28.70 45.60 26.70
- ------------- -------------- -------------- -------------
2014 29.00 46.00 26.90
- ------------- -------------- -------------- -------------
2015 28.90 45.60 26.90
- ------------- -------------- -------------- -------------
2016 29.30 46.00 27.10
- ------------- -------------- -------------- -------------
2017 29.00 45.50 27.00
- ------------- -------------- -------------- -------------
2018 29.10 45.40 27.00
- ------------- -------------- -------------- -------------
2019 29.10 45.30 27.00
- ------------- -------------- -------------- -------------
2020 29.00 44.90 26.90
- ---------------------------------------------------------
(1) Results are expressed in real 2000 dollars.
- ---------------------------------------------------------
2-51
2.10.6 DISPATCH CURVES
The dispatch curves for ERCOT for 2001 and 2010 are shown in Figure 2-45. The
relative ranking of the Bosque plant is shown on the graphs.
FIGURE 2-45
ERCOT DISPATCH CURVES FOR 2001 AND 2010
[TWO GRAPHS]
2-52
3. FORECASTING METHODOLOGY
- -------------------------------------------------------------------------------
3.1 OVERVIEW OF THE PA VALUATION PROCESS
PA employs its proprietary market valuation process, MVP(SM), to estimate the
value of electric generation units based upon the level of energy prices and
their volatility. As shown in Figure 3-1, MVP(SM) is a three-step process. The
first step is to conduct a "fundamental analysis" to examine how the LEVEL of
prices responds to changes in the fundamental drivers of supply and demand.
The fundamental analysis is conducted with a production-cost model that
provides insights into the basic market drivers: fuel prices, demand, entry,
and exit. The second step utilizes the results of the fundamental analysis to
derive a "REAL MARKET" price shape from the fundamental price levels. This
step also characterizes the hourly volatility in the fundamental prices. The
third step examines how the generation unit responds to those prices and
derives value from operational decisions. Through the three-step process
MVP(SM) integrates the fundamental and volatility approaches to create a better
estimate of the value of a generating unit by accounting for volatility
effects and changes in the fundamental drivers of electricity prices.
Additional detail on the forecast methodology is provided in the next two
sections. The fundamental analysis was prepared for MAGI's assets located in
MAIN/ECAR and ERCOT (due to the contracts the units sell power under). The
volatility analysis was prepared for MAGI's assets located in PJM, New York,
NEPOOL and WSCC-California.
FIGURE 3-1
MARKET VALUATION PROCESS
[GRAPH]
FUNDAMENTAL ANALYSIS
o What is the average level of prices given the units in the market, fuel
prices, future demand, and changes in technology?
VOLATILITY
o What is the likely pattern of electricity prices?
o What is the likely pattern of fuel prices?
DISPATCH
o Given the volatility in prices, how can plants respond to these prices
and capture margins?
3.2 FUNDAMENTAL ANALYSIS
PA's fundamental model, which is a driver of the volatility model, forecasts
hourly energy and annual capacity compensation prices.
o Energy prices are based upon the production-cost model where the hourly
energy price is set to the marginal cost of the last unit dispatched in the
given hour.
o Compensation for capacity represents the additional margin necessary to
keep an economic amount of capacity in the market.
PA uses a detailed chronological production-costing model to simulate energy
price formation in the market area of interest. This simulation of electric
generation product sales and market prices requires PA to consider not only
price formation in the market, but also the issues of market entry and exit
of
3-1
generation units. The process begins with a definition of the characteristics
of the market. Market characteristics include the electric generating units
currently in operation, their production efficiencies (including heat rate
curves), a projection of plant additions (based, in part, on announcements
and, in part, on an equilibrium evaluation of market price signals and new
investments), consumer demand and load, and generation fuel prices.
PA determines the energy margin from the energy price analysis, price minus
variable cost, attributable to each generating unit in the market. These
margins, along with estimates of "going-forward costs" (fixed costs, such as
fixed operation and maintenance (O&M), property taxes, employee benefits, and
incremental capital expenditures), are used in PA's Capacity Market
Simulation Model to predict the additional margins necessary to retain
generation capacity in the market.
Compensation for capacity may take many forms. Payments could be in the form
of a capacity price arising from a capacity market, a regulated payment fee,
bilateral contracts, payments by the ISO for ancillary services, or in the
form of prices above the marginal cost of the price-setting plant. Regardless
of the form, in market equilibrium compensation for capacity will be set to
retain the required generation capability available in the market.
Ultimately, the sum of the compensation for capacity and the market price for
energy will reflect what customers are willing to pay for reliability.
One would expect that price volatility would be higher in a market that does not
provide a meaningful stream of revenue as a capacity payment. This is because
the marginal plants (e.g., the last few generators needed to support
reliability) would need to increase their bids above their costs in order to
earn a sufficient margin when they are called upon to generate to cover their
going-forward costs. In low load hours, however, there is an abundance of
capacity present in the marketplace, and prices are more likely to be driven to
short-run marginal cost.
3.3 VOLATILITY ANALYSIS
The volatility analysis takes into account the annual trend of prices (from a
fundamental approach), and the patterns and fluctuations exhibited in the
marketplace. This process is shown graphically in Figure 3-2.
MVP(SM) uses a real options approach to value electric generating capacity,
thereby capturing the value of price volatility. An electric generating unit can
be viewed as a strip of European call options on the spread between electricity
prices and the variable
FIGURE 3-2
COMPONENTS OF A PRICE TRAJECTORY
[GRAPH]
ANNUAL TREND
o How do prices change, on average, with changes in fundamental drivers?
o Comes from the fundamental analysis.
STRUCTURE
o What are the predictable patterns in prices?
o Comes from statistical analysis of price data.
FLUCTUATIONS
o How does uncertainty manifest itself in prices?
o Comes from traded options data.
3-2
cost of production (which is largely fuel). However, unlike most option
analyses, a generation unit does not have perfect flexibility to adjust to
the price-cost spread. A generation unit may have costs that must be incurred
to start up. A unit may also have constraints placed upon its operation that
limit its ability to capture margins when the spread is positive (price is
greater than variable cost) or avoid losses when the spread is negative
(variable cost is greater than price). Hence, the third step of MVP(SM) focuses
on the ability of a generation unit to capture margins, given its cost
structure and constraints on operation.
The standard method for valuing the profitability of electric generating
units uses discounted cash flows constructed from production-cost models. By
simulating regional electricity operations, production-cost models weigh the
fundamental drivers of market supply and demand, with detailed attention to
supply. By aiming at cost, production-cost models can potentially miss the
true target, price. Further, production-cost models may underestimate the
volatility of electricity prices. This is illustrated by a comparison of
historical prices from the spot market (Figure 3-3) with forecast prices from
a production-cost model (Figure 3-4). Note that both the means and the
variations of prices from the production-cost model are lower than the actual
market for the same time period.
Electric generating units can respond to volatility in electricity prices by
increasing output (and revenues) when market conditions are favorable and
decreasing output (and costs) when market conditions are unfavorable. The
consequence is that valuation methods based on production-cost modeling tend
to underestimate the value of cycling (i.e., midmerit) and peaking electric
generating units.
The steps used to capture the change in value create by volatility are as
follows:
o The volatility in electric and fuel prices is first characterized. PA
characterizes volatility by estimating a stochastic process that
describes not only the uncertainty in prices, but also likely sequences
(evolution) of prices. Stochastic processes are estimated from
historical data on wholesale spot electricity and fuel markets. Observed
volatilities from forward-price data, or estimated volatilities from
option price data, are used when available.
o Annual average price levels of the stochastic processes are indexed to
fuel price assumptions and production-cost price projections for energy
and capacity.
o The natural gas and electricity price processes are simulated for the
time horizon of interest. The generating units of interest are
dispatched against these fuel and electricity price processes. The
result is a calculation of annual energy market net revenues.
Different generating units have different capabilities of responding to
electricity and fuel price volatility. Thus, the same price patterns for
electricity and fuel may yield different option values for different
generating units, depending on the operating costs and characteristics of the
generating units. Those generating units with the greatest flexibility to
respond to different market prices and that often set energy prices will have
the highest option values, while those plants that never set energy prices
have little or no ability to respond and will have virtually no option value.
FIGURE 3-3
PJM HOURLY ENERGY PRICES
SUMMER 1999
[GRAPH]
FIGURE 3-4
PJM HOURLY
ENERGY PRICES, PRODUCTION-COST MODEL
SUMMER 1999
[GRAPH]
3-3
4. KEY ASSUMPTIONS
- --------------------------------------------------------------------------------
4.1 INTRODUCTION
The key assumptions in this analysis are grouped into six categories: demand
growth, fuel prices, NOx and SO(2) emissions costs, capacity additions and
retirements, and financial parameters. These assumptions drive the
fundamental model of energy prices and capacity compensation.
4.2 CAPACITY AND ENERGY FORECASTS
The projected average annual demand and energy growth for the period 2001
through 2020 is summarized in Table 4-1.
- -------------------------------------------------------
TABLE 4-1
PROJECTED ANNUAL
GROWTH RATES
- -------------------------------------------------------
REGION DEMAND ENERGY
- ----------------------- ---------------- --------------
PJM 1.4% 1.5%
- ----------------------- ---------------- --------------
MAIN 1.4% 1.4%
- ----------------------- ---------------- --------------
ECAR 1.7% 1.6%
- ----------------------- ---------------- --------------
WSCC-CA 2.0% 1.8%
- ----------------------- ---------------- --------------
New York 0.8% 0.9%
- ----------------------- ---------------- --------------
NEPOOL 1.5% 1.5%
- ----------------------- ---------------- --------------
ERCOT 2.7% 2.7%
- --------------------------------------------------------------------------------
The hourly data for the analysis is based on a synthetic hourly load shape
based on five years of actual hourly data (1992-1996) provided with the
MULTISYM(TM) production-costing model to represent the native load
requirements for each of the pricing areas. The annual demand and energy
forecast values are applied to the native hourly load requirements to develop
the forecasted hourly loads for each year of the analysis.
4.3 FUEL PRICES
All fuel types were analyzed on either a regional (natural gas and oil) or
plant location (coal) basis in order to capture pricing variations among
major delivery points. The forecast prices for each fuel includes the cost of
transportation to the power plant site.
4.3.1 NATURAL GAS
The primary inputs into the analysis were forecasts from The Energy Information
Administration (EIA), The Gas Research Institute (GRI), The WEFA Group (WEFA)
and Standard and Poor's (S&P). Table 4-2 outlines the Henry Hub projection from
each of the four source forecasts as well as the consensus forecast of natural
gas prices at the Henry Hub.
----------------------------------------------------------------
TABLE 4-2
HENRY HUB PROJECTIONS (REAL 2000 $/MMBtu)
----------------------------------------------------------------
AVERAGE
ANNUAL
GROWTH
2000 2005 2010 2015 2020 RATE
--------------- ------- ------- ------ ------- ------ ----------
EIA 2.56 2.76 3.06 3.19 3.31 1.29%
--------------- ------- ------- ------ ------- ------ ----------
GRI 2.44 2.15 2.09 1.97 1.85 -1.37%
--------------- ------- ------- ------ ------- ------ ----------
WEFA 2.65 2.50 2.70 2.79 2.86 0.38%
--------------- ------- ------- ------ ------- ------ ----------
S&P 2.61 2.24 2.36 2.57 2.75 0.26%
--------------- ------- ------- ------ ------- ------ ----------
CONSENSUS 2.56 2.41 2.55 2.63 2.69 0.25%
--------------- ------- ------- ------ ------- ------ ----------
The projections above represent industry standard market information on long-run
equilibrium price. The natural gas market can exhibit extended periods where
supply and demand are not in balance and prices can fluctuate significantly. The
recent unprecedented price levels indicate that the market is currently in just
such a period of transition. Figure 4-1 shows historical gas prices for the
Henry Hub for 1999 and 2000. Gas prices have increased substantially in recent
months.
FIGURE 4-1
HENRY HUB GAS PRICES 1999-2000
[GRAPH]
4-1
As a result of the recent gas price increase, PA has modeled near-term prices
based on recent actual spot prices and futures prices through December 2003,
decreasing linearly to the long-term consensus view in 2005. Table 4-3 displays
the near-term price projection.
--------------------------------------------------------
TABLE 4-3
HENRY HUB PROJECTIONS USING NYMEX PRICES(1)
(REAL 2000 $/MMBtu)
------------------ -------------------------------------
YEAR HENRY HUB PROJECTION
------------------ -------------------------------------
2001 4.81
------------------ -------------------------------------
2002 4.19
------------------ -------------------------------------
2003 3.84
------------------ -------------------------------------
2004 3.13
--------------------------------------------------------
(1) Based on average daily closing prices from 9/13/00
to 12/12/00.
--------------------------------------------------------
Regional prices throughout the United States were projected based on this
consensus Henry Hub forecast. For all regions modeled, the delivered price is
the sum of the Henry Hub projection, the projected regional basis differential,
and other natural gas supply costs including all taxes.
A. BASIS DIFFERENTIALS
The Henry Hub forecast is used as a basis for projecting regional market center
prices. The Henry Hub forecast, plus the basis differential to a particular
region, equals the commodity component of each region's natural gas forecast.
Regional market prices for natural gas are based on this Henry Hub forecast and
historic (1994-1999) and projected spot price differentials. Projected changes
in the basis differentials are a result of increased integration of natural gas
supply centers, changes in regional demand levels, and increased deliverability
in some areas resulting from new pipeline construction.
B. ADDITIONAL NATURAL GAS SUPPLY COSTS
In addition to the regional commodity cost, natural gas price inputs also
include an additional liquidity premium designed to account for the fact that
units are not necessarily located at a major trading hub. As a result, units
are likely to pay some premium over prices available at major pipeline
intersections. For all of the regions except California, this premium is
expected to remain constant at $0.05/MMBtu ($2000) over the forecast horizon.
In California, units are assumed to pay intrastate pipeline charges.(10) In
addition, Southern California units are assumed to pay a transition charge of
$0.08/MMBtu through 2004.
As electric industry deregulation pressures generators to reduce costs, new
gas-fired applications will be located so as to minimize fuel costs. As a
result, new capacity will have an incentive to locate on the interstate pipeline
system in order to avoid both Local Distribution Company (LDC) charges and
operating pressure concerns. Therefore, it is assumed that new plants will be
sited to take advantage of direct connections to interstate pipeline systems.
Existing units in the model are assumed to incur LDC charges. For all of the
regions except California, the LDC charge is assumed to be $0.10/MMBtu in 2000
declining to $0.05/MMBtu by 2020. The LDC charge in Northern California is
assumed to be $0.02/MMBtu and no LDC charge is included in Southern California.
In addition, New York City units pay an additional tax on all natural gas
consumed.
Some baseload gas-fired plants, however, may incur fixed costs to ensure firm
natural gas supplies. The EIA projects that as industry restructuring
increasingly puts pressure on generators to reduce costs, generating stations
will rely on interruptible deliveries and will ensure fuel supplies by using oil
as a backup fuel.(11) The total delivered price of natural gas in each market
region is shown in Figure 4-2.
- -----------------------------
(10) The Northern California intrastate pipeline charges are assumed to be
$0.27/MMBtu in 2000 declining to $0.21/MMBtu by 2017. The Southern California
intrastate pipeline charges are assumed to be $0.26/MMBtu in 2000, declining
to $0.21/MMBtu by 2015.
(11) EIA, Challenges of Electric Power Industry Restructuring for Fuel
Suppliers, September 1998, p. 65.
4-2
FIGURE 4-2
DELIVERED NATURAL GAS PRICE
(2000 $/MMBtu)
[GRAPH]
[KEY]
NATURAL GAS PRICE SEASONALITY
Natural gas prices exhibit significant and predictable seasonal variation.
Consumption increases in the winter as space heating demand increases and falls
in the summer. Prices follow this pattern as well; the seasonal pattern is most
striking in cold weather locations. Dispatch prices in the model reflect the
seasonal effects based on 5-year historic price patterns exhibited at the
regional market centers.
4.3.2 FUEL OIL
The fuel oil forecast methodology is described below for No. 2 Fuel
Oil and No. 6 Fuel Oil. Prices are developed based on a consensus of crude
oil by major forecasters as presented in Table 4-4.(12) These widely used
sources present a broad perspective on the potential changes in commodity
fuel markets. Each forecast was equally weighted in an effort to arrive at
an unbiased consensus projection of fuel prices.
- ------------------------------------------------------------------
TABLE 4-4
CRUDE OIL PRICE PROJECTIONS
(REAL 2000 $/bbl)
- ------------------------------------------------------------------
AVERAGE
ANNUAL
GROWTH
2000 2005 2010 2015 2020 RATE
- --------------- ------- ------- ------- ------- ------- ----------
EIA 21.92 21.19 21.72 22.27 22.80 0.20%
- --------------- ------- ------- ------- ------- ------- ----------
GRI 18.42 18.42 18.42 18.42 18.42 0.00%
- --------------- ------- ------- ------- ------- ------- ----------
WEFA 24.22 18.74 18.84 19.80 20.81 -0.76%
- --------------- ------- ------- ------- ------- ------- ----------
S&P 21.14 16.50 17.32 19.31 20.72 -0.10%
- --------------- ------- ------- ------- ------- ------- ----------
CONSENSUS 21.42 18.71 19.07 19.95 20.68 -0.18%
- --------------- ------- ------- ------- ------- ------- ----------
As is the case with natural gas, today's oil markets are in a period of
transition as OPEC wrestles with its production targets. As a result, PA has
modeled near-term prices to reflect recent actual oil prices and futures prices
through December 2003, rather than the long-run equilibrium price. In this case,
prices return to the long-run consensus in 2005. The near-term price projection
is shown in Table 4-5.
-----------------------------------------------
TABLE 4-5
CRUDE OIL PRICE PROJECTION
USING NYMEX PRICES(1)
(REAL 2000 $/bbl)
-----------------------------------------------
YEAR PRICE PROJECTION
---------------- ------------------------------
2001 29.73
---------------- ------------------------------
2002 25.72
---------------- ------------------------------
2003 23.56
---------------- ------------------------------
2004 21.13
-----------------------------------------------
(1) Based on average daily closing prices from
9/13/00 to 12/12/00.
-----------------------------------------------
- -----------------------------
(12) The source forecasts are as follows: 2000 Annual Energy Outlook, EIA; 2000
Baseline Projection, GRI; 2000 Natural Gas Outlook, WEFA; Standard & Poor's
World Energy Service U.S. Outlook, Fall-Winter 1999-2000.
4-3
A. NO. 2 FUEL OIL
Prices for No. 2 Fuel Oil were derived from EIA data on historical
delivered-to-utility prices for the period 1994 through 1998, on a regional
basis. Fuel costs are comprised of commodity costs and transportation costs.
Each region in the analysis was assigned to a reference terminal. The commodity
component is calculated by escalating the historic reference terminal prices at
the escalation rate implicit in the crude oil forecast outlined in Tables 4-4
and 4-5.
Transportation costs are calculated as the 5-year average premium for delivered
Fuel Oil in each region above the market center price for the terminal assigned
to that region. This transportation cost is held fixed over the forecast
horizon. This methodology captures both the commodity and transportation
components of delivered costs. Representative final delivered prices for No. 2
Fuel Oil are shown in Figure 4-3.
FIGURE 4-3
DELIVERED FO(2) PRICE
(2000 $/MMBtu)
[GRAPH]
[KEY]
B. NO. 6 FUEL OIL
Prices for No. 6 Fuel Oil were derived using an identical methodology as that
employed for No. 2 Fuel Oil prices. Because residual oil is so thinly traded, it
is difficult to identify significant regional price premiums. As a result, all
eastern regions were assigned to the New York Harbor reference terminal and all
regions in WSCC were assigned to the U.S. West Coast reference terminal. As a
result, commodity prices for all regions were based on 1% sulfur residual oil at
New York Harbor and are therefore the same. Transportation costs for each
region, however, do vary.
The transportation costs for each region were based on an analysis of historic
New York Harbor prices and delivered residual oil at electric generating
stations in the region. Transportation costs equal the 5-year average premium
for delivered No. 6 Fuel Oil in above the New York Harbor price. This
transportation cost is held fixed over the forecast horizon. Final delivered
prices for No. 6 Fuel Oil are shown in Figure 4-4.
FIGURE 4-4
DELIVERED FO6 PRICE
(2000 $/MMBtu)
[GRAPH]
Price projections for lower sulfur oil products(13) were also calculated to
generate model inputs for regions that have more stringent environmental
regulations. The premium for lower sulfur products was derived from a comparison
of historic price data.
4.3.3 COAL
PA developed a forecast of marginal delivered coal prices (in real 2000 dollars)
for the period 2001 through 2020 on a unit-by-unit basis for electric generators
in each region. Delivered coal prices were projected in two components: (1) coal
prices at the mine and (2) transportation rates.
- -----------------------------------------
(13) Includes 0.3% residual oil, low sulfur 2-oil, and jet fuel.
4-4
Mine prices were projected with consideration of productivity increases and
supply and demand economics. Real prices are expected to decrease over the
forecast period for all of the major coal types. The rate of decrease varies
based on specific considerations such as supply and expected depletion of
reserves, market demand, and the sulfur content of the coals.
In general, prices for low sulfur coals decline the least, and prices for mid
sulfur coals decline the most. Low and mid sulfur coals currently receive a
price premium relative to high-sulfur coals based on their lower sulfur content.
Higher SO(2) allowance prices are expected to reduce demand for mid-sulfur coals
at un-scrubbed plants, which will reduce the price difference between mid and
high sulfur coals over time.
Projected transportation rates are based on available delivery options at each
plant for the coal types selected for each unit. Transportation modes include
rail, barge, truck transportation, and conveyor transportation for mine mouth
plants. Rates for different transportation modes in different regions of the
country are projected to vary at different rates over time.
Table 4-6 depicts the estimated annual decrease in coal prices by coal-type
(based on real prices).
-----------------------------------------------
TABLE 4-6
ESTIMATED ANNUAL DECREASE
IN COAL PRICES
-----------------------------------------------
REAL ESCALATION RATE
COAL PER ANNUM
---------------------- ------------------------
Eastern -0.4% to -1.0%
---------------------- ------------------------
Illinois Basin -0.4% to -1.5%
---------------------- ------------------------
Western -0.4% to -0.7%
---------------------- ------------------------
4.4 SO(2)/Nox EMISSION COSTS
4.4.1 SULFUR DIOXIDE EMISSION COSTS
PA's forecast of SO(2) allowance prices is shown in Table 4-7. The price of
SO(2) allowances starts at $165 per ton in 2001, and increases to $420 per
ton by 2006, with the largest annual increase occurring in 2002.
- -------------------------------------------
TABLE 4-7
SO(2) COST CURVES (2000 $/TON)
- ----------------------- --------------------
YEAR SO(2)
- ----------------------- --------------------
2001 $165
- ----------------------- --------------------
2002 $287
- ----------------------- --------------------
2003 $316
- ----------------------- --------------------
2004 $347
- ----------------------- --------------------
2005 $382
- ----------------------- --------------------
2006-2020 $420
- ----------------------- --------------------
The relatively low current prices for SO(2) allowances (below our expected
long-term value of allowances, on a discounted basis) reflects the
accumulation of a large bank of SO(2) allowances, which resulted from
over-compliance with Phase I of the Clean Air Act SO(2), and a number of
political and regulatory uncertainties (including the outcome of the New
Source Review litigation, the Supreme Court's ruling on EPA's proposed fine
particulate regulations, and proposed regional haze regulations) that could
reduce the value of SO(2) allowances. PA expects that the outcome of these
uncertainties will be known by 2002. Assuming that these issues are resolved
in a manner that essentially preserves the current market-based regulatory
system for SO(2) (rather than moving toward command-and-control policies),
and that additional regulations do not suppress SO(2) prices, PA would expect
SO(2) allowance prices to increase substantially from 2001 to 2002.
The SO(2) allowance price trajectories for 2001 and 2003 to 2005 reflect PA's
expectation that, since SO(2) allowances are relatively risky, they will
generally escalate at a discount rate consistent with such risky investments.
For this forecast, PA has assumed a 10% expected annual real rate of return
on holding "banked" allowances during these periods, which produces our price
trajectories for 2001 and 2003 to 2005.
4-5
The real cost of SO(2) allowances is projected to plateau at $420 per ton for
2006 and later years. This price level is determined by the marginal cost of
installing scrubbers at existing plants.(14) PA estimates that this price
level will be reached in 2006 because the "bank" of SO(2) allowances will be
almost fully depleted by 2006. (Only a small "bank" will remain, for
transactional liquidity purposes.)
4.4.2 DEVELOPMENT OF NO(x) CONTROL COSTS AND EMISSION RATES
PA forecast NO(x) allowance prices for two regions: the Ozone Transport Region
(OTR) and the South Coast Air Quality Management District (SCAQMD). See Table
4-8.
- ----------------------------------------------------
TABLE 4-8
NO(x) COST CURVES (REAL 2000 $/TON)
- --------------------------- ------------------------
YEAR NO(X)
- --------------------------- ------------------------
OTR
- --------------------------- ------------------------
2001 $1,000
- --------------------------- ------------------------
2002 $1,000
- --------------------------- ------------------------
2003-2020 $4,000
- ----------------------------------------------------
SCAQMD
- --------------------------- ------------------------
2000 $85,382
- --------------------------- ------------------------
2001 $87,278
- --------------------------- ------------------------
2002 $28,459
- --------------------------- ------------------------
2003 $26,409
- --------------------------- ------------------------
2004 $25,566
- --------------------------- ------------------------
2005 $25,031
- --------------------------- ------------------------
2006 $15,090
- --------------------------- ------------------------
2007 $13,680
- --------------------------- ------------------------
2008 $13,680
- --------------------------- ------------------------
2009 $13,680
- --------------------------- ------------------------
2010 $13,680
A. OTR
This forecast includes both an estimate of NO(x) compliance costs for units in
the Ozone Transport Region (OTR) for 2001-2002, and an estimate of the NO(x)
control costs for all of the units affected by EPA's NO(x) State Implementation
Plan (SIP) Call from 2003 forward. The NO(x) allowance price forecast begins at
the 2001 ozone season(15) price, which is approximately $1,000/ton (see
Table 4-8). The price is expected to remain at $1,000/ton in 2002, and then
rise to approximately $4,000/ton in 2003 as the tighter NO(x) regulations
proposed in the SIP call go into effect.
B. SCAQMD
SCAQMD regulates equipment in the South Coast air basin that emit nitrogen
oxide (NO(x)) and sulfur oxide (SO(x)) emissions through the Regional Clean
Air Incentives Market (RECLAIM) program established by SCAQMD. The program
mandates a cap on total emissions, provides targets emission levels for the
regulated equipment, and allows for trading of emission credits. The
relevance of this program to electricity prices is that it results in a
variable cost associated with emission of NO(x) emissions from generating
plants located in the South Coast air basin. This is the only portion of the
WSCC in which such a program is in effect.(16)
Companies in the South Coast air basin (which includes Los Angeles and Orange
counties and parts of Riverside and San Bernardino counties) emitting four or
more tons per year of either NO(x) or SO(x) must participate in the program.
Each company participating in the program receives a pre-determined number of
RECLAIM trading credits (RTCs) . Facilities that reduce emissions beyond
annual targets can sell excess credits to firms that cannot or choose not to
meet their limits.
There is a liquid market for RTCs. Cantor Fitzgerald Environmental Brokerage
Services maintains a Market Price Index(TM) of prices for various vintages of
RTCs. These prices represent the best indication of future costs for NO(x)
emissions. Table 4-8 presents selected vintage prices as of December 28,
2000. Prices were unusually high in 2000, primarily because of high demand
for fossil-fired electricity generation.
- -----------------------------
(14) This assumes a continuation of current regulations under the 1990 Clean
Air Act Amendments. As noted above, some proposals under consideration by EPA
(such as controls on fine particulates) could change these regulations.
(15) The ozone season, for purposes of assessing NOx costs, is defined as May 1
through September 30.
(16) New plants in all of California and in some other portions of the WSCC are
required to purchase emission reduction credits (ERCs) as a part of the
permitting process. These are fixed costs, so we did not model them in our
MULTISYM analysis. They can be sold when the plant is retired, which may offset,
or more than offset, the purchase price. Consequently, we also did not model
ERCs in our Capacity Market Simulation Model analysis.
4-6
PA used these prices for plants located in the South Coast air basin.(17)
4.5 HYDROELECTRIC UNITS
The hydroelectric plants are consolidated by utility and categorized as peaking
or baseload. Similar to the thermal units, the maximum capacity for each unit
was taken from the sources cited above for summer and winter capabilities.
Monthly energy patterns were developed from the 1991-1999 EIA Forms 759, which
contain monthly generation and (for pumped storage units) net inflows.
Hydroelectric capacity reflects approximately 38% of the total peak capacity for
WSCC. Hydropower is different than most other types of capacity because most of
the major hydro facilities are energy constrained. There is a limited amount of
water that can be used for generation before either running out or reaching
operational limits due to biologic, recreation, navigation, or other concerns.
Energy constraints can limit the value of hydro facilities as a capacity source.
To reflect the effect of energy constraints on peak capacity, the capacity for
hydro units was derated in developing the compensation for capacity in our
Capacity Compensation Simulation Model. The hydro units in California and the
Northwest were derated 25% and all other hydro units in the WSCC were derated
20%.
4.6 CAPACITY ADDITIONS AND RETIREMENTS
It is necessary to assess the feasibility and timing of new capacity additions
as well as the exit of uneconomic existing capacity. PA's proprietary modeling
approach serves two purposes:
o First, it identifies generating units that are not able to recover their
going-forward costs in the energy and capacity markets and are, therefore,
at risk of abandoning the markets.
o Second, it provides a rational method for ascertaining the amount, timing,
and type of capacity additions.
The transfer capabilities for the each region are shown in Figure 4-5. Capacity
additions through 2003 are based on publicly announced or planned additions. The
additions assumed in this analysis are shown in Table 4-9. These capacity
additions are a best estimate of what units will be developed during this
period. Actual additions may differ from those indicated. Cumulative capacity
additions are shown in Figure 4-6.
From 2004 through 2020, PA's approach uses a financial model to assess the
decision to add new capacity and to retire existing capacity. The approach to
plant additions is based on a set of generic plant characteristics, financing
assumptions, and economic parameters. This "add/retire" analysis is an iterative
process performed simultaneously with the development of the energy price
forecast and the projected compensation for capacity.
The methodology assesses the feasibility of annual capacity additions based on a
Discounted Cash Flow (DCF) model using net energy revenues determined in the
production-cost simulations and compensation for capacity determined from the
Capacity Compensation Simulation approach. For each increment of new capacity, a
"Go" or "No Go" decision is made based on whether the entrant would experience
sufficient returns (developed in the DCF model) to merit entry. In addition,
economic retirement decisions are made at each step in the iterative process
based on the specific financial and operating characteristics of the existing
plant.
Nuclear unit retirement assumptions are shown in Table 4-10. A nuclear units is
retired at its license expiration date unless its economic performance results
in early retirement. The only early retirement, Vermont Yankee in NEPOOL, which
retires in 2006 rather than 2012 is identified in Table 4-10.
- -----------------------------
(17) We did not model SO(x) costs because of the relatively low SO(x)
emission rates from the gas-fired plants located in the South Coast air basin.
4-7
FIGURE 4-5
TRANSFER CAPABILITY(1) (MW)
PJM, NEW YORK, AND NEPOOL
[GRAPH]
- ------------------------------------------------------------
ABBREVIATION FULL NAME
- ------------------------------------------------------------
QUE Quebec
- ------------------------------------------------------------
NoSco Nova Scotia
- ------------------------------------------------------------
ONT Ontario
- ------------------------------------------------------------
NEPOOL West New England Power Pool West
- ------------------------------------------------------------
NEPOOL Maine New England Power Pool East
- ------------------------------------------------------------
NEPOOL SE New England Power Pool Southeast
- ------------------------------------------------------------
NYPP West New York Power Pool West
- ------------------------------------------------------------
NYPP East New York Power Pool East
- ------------------------------------------------------------
NYPP In-City New York Power Pool In the City
- ------------------------------------------------------------
NYPP Long Is. New York Power Pool Long Island
- ------------------------------------------------------------
PJM West Pennsylvania, New Jersey, Maryland West
- ------------------------------------------------------------
PJM Cent. Pennsylvania, New Jersey, Maryland
Central
- ------------------------------------------------------------
PJM East Pennsylvania, New Jersey, Maryland East
- ------------------------------------------------------------
ECAR East Central Area Reliability
- ------------------------------------------------------------
SERC Southeastern Electric Reliability
Council
- ------------------------------------------------------------
MAIN
[GRAPH]
- ------------------------------------------------------------
ABBREVIATION FULL NAME
- ------------------------------------------------------------
WIUM Wisconsin Upper Michigan
- ------------------------------------------------------------
MAPus Mid-Continent Area Power Pool United
States
- ------------------------------------------------------------
CECO Commonwealth Edison Company
- ------------------------------------------------------------
AEP American Electric Power Company
- ------------------------------------------------------------
EMO Eastern Missouri
- ------------------------------------------------------------
SCIL South Central Illinois
- ------------------------------------------------------------
CIN Cinergy
- ------------------------------------------------------------
ENTR Entergy
- ------------------------------------------------------------
SPP north Southwest Power Pool North
- ------------------------------------------------------------
TEVA Tennessee Valley Authority
- ------------------------------------------------------------
SIGE Southern Illinois Gas and Electric
- ------------------------------------------------------------
(1) Capabilities represent Summer and (Winter) where applicable.
4-8
FIGURE 4-5 (CONT.)
TRANSFER CAPABILITY(1) (MW)
ECAR
[GRAPH]
- ------------------------------------------------------------
ABBREVIATION FULL NAME
- ------------------------------------------------------------
MAAC Mid-Atlantic Area Council
- ------------------------------------------------------------
MECS Michigan Electric Coordinated System
- ------------------------------------------------------------
CINERGY Cinergy
- ------------------------------------------------------------
AEP American Electric Power Company
- ------------------------------------------------------------
APS Allegheny Power System
- ------------------------------------------------------------
MAIN Mid-America Interconnected Network
- ------------------------------------------------------------
SIGE Southern Illinois Gas and Electric
- ------------------------------------------------------------
SERC Southeastern Electric Reliability
Council
- ------------------------------------------------------------
WSCC-CALIFORNIA(2)
[GRAPH]
- ------------------------------------------------------------
ABBREVIATION FULL NAME
- ------------------------------------------------------------
BC British Columbia
- ------------------------------------------------------------
ALB Alberta
- ------------------------------------------------------------
WNW West Northwest
- ------------------------------------------------------------
ENW East Northwest
- ------------------------------------------------------------
MT Montana
- ------------------------------------------------------------
NoCA Northern California
- ------------------------------------------------------------
SP Sierra Pacific
- ------------------------------------------------------------
ID Idaho
- ------------------------------------------------------------
WY Wyoming
- ------------------------------------------------------------
SoNV Southern Nevada
- ------------------------------------------------------------
UT Utah
- ------------------------------------------------------------
CO Colorado
- ------------------------------------------------------------
SoCA Southern California
- ------------------------------------------------------------
CFE Comision Federal de Electricidad
- ------------------------------------------------------------
AZ Arizona
- ------------------------------------------------------------
NM New Mexico
- ------------------------------------------------------------
(1) Capabilities represent Summer and (Winter) where applicable.
(2) Transfer capabilities shown have been adjusted for firm transmission related
to the joint ownership of generation plants located in different pricing areas.
4-9
TABLE 4-9
CAPACITY ADDITIONS, 2001-2003
- ------------------------------------------------------------
ON-
SIZE UNIT LINE
DEVELOPER (PLANT) (MW) TYPE YEAR
- ------------------------------------------------------------
PJM CAPACITY ADDITIONS
- ------------------------------------------------------------
TM Power (Chesapeake 2) 177 CT 2001
- ------------------------------------------------------------
Williams (Hazleton) 250 CC 2001
- ------------------------------------------------------------
AES (Ironwood) 705 CC 2001
- ------------------------------------------------------------
PSEG (Kearney 1-4) 164 GT 2001
- ------------------------------------------------------------
Conectiv (Hay Road) 550 CC 2002
- ------------------------------------------------------------
PSEG (Bergen 2) 546 CC 2002
- ------------------------------------------------------------
Orion (Liberty) 520 CC 2002
- ------------------------------------------------------------
PSEG (Mantua Creek) 800 CC 2002
- ------------------------------------------------------------
AES (Red Oak) 816 CC 2002
- ------------------------------------------------------------
PSEG (Linden 1) 601 CC 2003
- ------------------------------------------------------------
PSEG (Linden 2) 601 CC 2003
- ------------------------------------------------------------
MAIN CAPACITY ADDITIONS
- ------------------------------------------------------------
Mid-American (Cordova) 500 CC 2001
- ------------------------------------------------------------
Primary En. (Ind. Harbor) 50 CT 2001
- ------------------------------------------------------------
Constellation (Univ. Park) 300 CC 2001
- ------------------------------------------------------------
Wisvest/SkyGen (Calumet) 300 CC 2001
- ------------------------------------------------------------
Primary (Whiting) 525 CG 2001
- ------------------------------------------------------------
DENA (Lee County) 640 CT 2001
- ------------------------------------------------------------
Reliant (Aurora) 870 CT 2001
- ------------------------------------------------------------
LS Power (Kendall) 1,100 CC 2001
- ------------------------------------------------------------
Ameren (Petoka) 234 CT 2001
- ------------------------------------------------------------
Ameren (Grand Tower) 326 CC 2001
- ------------------------------------------------------------
SkyGen (Rock Gen) 450 CT 2001
- ------------------------------------------------------------
DENA (Audrain) 640 CT 2001
- ------------------------------------------------------------
Constellation (Holland) 650 CC 2002
- ------------------------------------------------------------
Generic 520 CC 2003
- ------------------------------------------------------------
ECAR CAPACITY ADDITIONS
- ------------------------------------------------------------
DPL (Phases 3 &4) 320 CT 2001
- ------------------------------------------------------------
PG&E Gen. (Napoleon 1) 45 CT 2001
- ------------------------------------------------------------
First Energy (West Lorain 1) 425 CT 2001
- ------------------------------------------------------------
MAGI (Zeeland 1) 300 CT 2001
- ------------------------------------------------------------
Enron (Calvert 1) 509 CT 2001
- ------------------------------------------------------------
CMS Energy (Dearborn 2) 550 CC 2001
- ------------------------------------------------------------
Columbia (Ceredo 1) 500 CT 2001
- ------------------------------------------------------------
PSEG (Waterford 1) 165 CT 2002
- ------------------------------------------------------------
PSEG (Waterford 2) 165 CT 2002
- ------------------------------------------------------------
PSEG (Waterford 3) 165 CT 2002
- ------------------------------------------------------------
Kinder Morgan (Jackson 1) 550 CC 2002
- ------------------------------------------------------------
Dynegy (Riverside 1) 500 CT 2002
- ------------------------------------------------------------
PSEG (Lawrence 1) 575 CC 2003
- ------------------------------------------------------------
PSEG (Lawrence 2) 575 CC 2003
- ------------------------------------------------------------
PSEG (Waterford 1, convert 3
CTs to 1 CC) net cap. Add. 355 CC 2003
- ------------------------------------------------------------
Constellation (Wayne Cty) 300 CT 2002
- ------------------------------------------------------------
Generic 520 CC 2003
- ------------------------------------------------------------
WSCC-CA CAPACITY ADDITIONS
- ------------------------------------------------------------
Calpine (Los Medanos) 500 CC 2001
- ------------------------------------------------------------
Calpine (Sutter) 500 CC 2001
- ------------------------------------------------------------
PG&E (Lapaloma) 1,048 CC 2001
- ------------------------------------------------------------
EME (Sunrise) 320 CC 2001
- ------------------------------------------------------------
Calpine (Delta) 880 CC 2002
- ------------------------------------------------------------
Duke (Moss Landing) 990 CC 2002
- ------------------------------------------------------------
Constellation (High Desert) 700 CC 2003
- ------------------------------------------------------------
NEW YORK CAPACITY ADDITIONS
- ------------------------------------------------------------
NYPA (CT 1) 260 CT 2001
- ------------------------------------------------------------
NYPA (CT 2) 260 CT 2001
- ------------------------------------------------------------
PG&E (Athens) 1,080 CC 2003
- ------------------------------------------------------------
Exelon (Heritage) 800 CC 2003
- ------------------------------------------------------------
Exelon (Torne Valley) 800 CC 2003
- ------------------------------------------------------------
Generic 345 CT 2003
- ------------------------------------------------------------
Generic 345 CT 2003
- ------------------------------------------------------------
Generic 345 CT 2003
- ------------------------------------------------------------
Generic 520 CC 2003
- ------------------------------------------------------------
NEPOOL CAPACITY ADDITIONS
- ------------------------------------------------------------
Power Dev Corp (Milford) 544 CC 2001
- ------------------------------------------------------------
Calpine (Westbrook) 540 CC 2001
- ------------------------------------------------------------
PG&E (Lake Road) 792 CC 2001
- ------------------------------------------------------------
ANP (Blackstone) 550 CC 2001
- ------------------------------------------------------------
PPL (Wallingford) 250 CT 2001
- ------------------------------------------------------------
ANP (Bellingham) 580 CC 2001
- ------------------------------------------------------------
Exelon (Fore River) 750 CC 2002
- ------------------------------------------------------------
FPL (Rise) 500 CC 2002
- ------------------------------------------------------------
AES (Londonderry) 720 CC 2002
- ------------------------------------------------------------
Exelon (New Boston 3) 15 GT 2002
- ------------------------------------------------------------
PDC/EP (Meriden/Berlin) 520 CC 2002
- ------------------------------------------------------------
Exelon (Mystic 8) 750 CC 2002
- ------------------------------------------------------------
Exelon (Mystic 9) 750 CC 2002
- ------------------------------------------------------------
Con Ed (Newington) 525 CT 2003
- ------------------------------------------------------------
Exelon (Medway Exp.) 450 CT 2003
- ------------------------------------------------------------
Generic 520 CC 2003
- ------------------------------------------------------------
ERCOT CAPACITY ADDITIONS
- ------------------------------------------------------------
Tenaska (Gateway) 845 CC 2001
- ------------------------------------------------------------
Reliant/Equistar (Channelview) 188 CC 2001
- ------------------------------------------------------------
Tractabel (Ennis) 350 CC 2001
- ------------------------------------------------------------
Calpine (Lost Pines) 500 CC 2001
- ------------------------------------------------------------
Panda/PSEG (Wichita Falls) 500 CC 2001
- ------------------------------------------------------------
MAGI (Bosque 3) 236 CC 2001
- ------------------------------------------------------------
ANP (Edinberg 1) 500 CC 2001
- ------------------------------------------------------------
Panda/PSEG (Guadalupe 2) 500 CC 2001
- ------------------------------------------------------------
ANP (Hays 1) 1,100 CC 2001
- ------------------------------------------------------------
CSW (Longview 1) 450 CC 2001
- ------------------------------------------------------------
Calpine (Magic Valley 1) 700 CC 2001
- ------------------------------------------------------------
Panda/PSEG (Odessa 1) 500 CC 2001
- ------------------------------------------------------------
Panda/PSEG (Odessa 2) 500 CC 2001
- ------------------------------------------------------------
Reliant/Equistar (Channelview) 563 CC 2002
- ------------------------------------------------------------
AES (Wolf Hollow) 750 CC 2002
- ------------------------------------------------------------
4-10
FIGURE 4-6
CUMULATIVE CAPACITY ADDITIONS, 2001-2020 (MW)
PJM MAIN
[GRAPH] [GRAPH]
WSCC-CA NEW YORK
[GRAPH] [GRAPH]
NEPOOL ERCOT
[GRAPH] [GRAPH]
4-11
TABLE 4-10
NUCLEAR UNIT RETIREMENTS
- -------------------------------------------------------
UNIT NAME CAPACITY (MW) YEAR(1)
- -------------------------------------------------------
PJM
- -------------------------------------------------------
Oyster Creek 1 619 2009
- -------------------------------------------------------
Peach Bottom 3 1,093 2013
- -------------------------------------------------------
Three Mile 1 786 2014
- -------------------------------------------------------
Peach Bottom 2 1,093 2014
- -------------------------------------------------------
Salem 1 1,106 2016
- -------------------------------------------------------
Salem 2 1,106 2020
- -------------------------------------------------------
Susquehanna 1 1,090 2022
- -------------------------------------------------------
Calvert Cliffs 1 835 2024
- -------------------------------------------------------
Calvert Cliffs 2 840 2024
- -------------------------------------------------------
Susquehanna 2 1,094 2024
- -------------------------------------------------------
Hope Creek 1,031 2026
- -------------------------------------------------------
Limerick 1 1,134 2024
- -------------------------------------------------------
Limerick 2 1,115 2029
- -------------------------------------------------------
MAIN
- -------------------------------------------------------
Dresden 2 772 2009
- -------------------------------------------------------
Point Beach 1 505 2010
- -------------------------------------------------------
Dresden 3 773 2011
- -------------------------------------------------------
Quad Cities 1 577 2012
- -------------------------------------------------------
Quad cities 2 577 2012
- -------------------------------------------------------
Kewaunee 494 2013
- -------------------------------------------------------
Point Beach 2 495 2013
- -------------------------------------------------------
LaSalle County 1 1,048 2022
- -------------------------------------------------------
LaSalle County 2 1,048 2023
- -------------------------------------------------------
Byron 1 1,120 2024
- -------------------------------------------------------
Callaway 1 1,143 2024
- -------------------------------------------------------
Braidwood 2 1,090 2026
- -------------------------------------------------------
Byron 2 1,120 2026
- -------------------------------------------------------
Clinton 930 2026
- -------------------------------------------------------
Braidwood 2 1090 2027
- -------------------------------------------------------
ECAR
- -------------------------------------------------------
Palisades 1 760 2007
- -------------------------------------------------------
D C Cook 1 1,000 2014
- -------------------------------------------------------
Beaver Valley 1 810 2016
- -------------------------------------------------------
D C Cook 2 1,060 2017
- -------------------------------------------------------
Davis Besse 1 873 2017
- -------------------------------------------------------
Fermi 2 1,098 2025
- -------------------------------------------------------
Perry 1 1,169 2026
- -------------------------------------------------------
Beaver Valley 2 820 2027
- -------------------------------------------------------
WSCC-CA
- -------------------------------------------------------
San Onofre 2 1,070 2022
- -------------------------------------------------------
San Onofre 3 1,080 2022
- -------------------------------------------------------
WNP 2 1,170 2023
- -------------------------------------------------------
Palo Verde 1 1,256 2025
- -------------------------------------------------------
Palo Verde 2 1,256 2025
- -------------------------------------------------------
Palo Verde 3 1,263 2025
- -------------------------------------------------------
Diablo Canyon 1 1,073 2025
- -------------------------------------------------------
Diablo Canyon 2 1,087 2025
- -------------------------------------------------------
NEW YORK
- -------------------------------------------------------
Ginna 1 499 2009
- -------------------------------------------------------
Nine Mile 1 619 2009
- -------------------------------------------------------
Indian Point 2 931 2013
- -------------------------------------------------------
J A Fitzpatrick 820 2014
- -------------------------------------------------------
Indian Point 3 970 2015
- -------------------------------------------------------
Nine Mile 2 1,142 2026
- -------------------------------------------------------
NEPOOL
- -------------------------------------------------------
Vermont Yankee(2) 500 2006
- -------------------------------------------------------
Pilgrim 664 2012
- -------------------------------------------------------
Millstone 2 871 2015
- -------------------------------------------------------
Millstone 3 1,140 2025
- -------------------------------------------------------
Seabrook 1 1,162 2026
- -------------------------------------------------------
ERCOT
- -------------------------------------------------------
South Texas 1 1,250 2027
- -------------------------------------------------------
South Texas 2 1,250 2028
- -------------------------------------------------------
Comanche Peak 1 1,150 2030
- -------------------------------------------------------
Comanche Peak 2 1,150 2033
- -------------------------------------------------------
(1) Retirements occur on December 31 of year indicated.
(2) Economic retirement. License expiration is 2012.
4-12
4.7 FINANCIAL ASSUMPTIONS
4.7.1 GENERIC PLANT CHARACTERISTICS
The starting point for the DCF calculation is the generic unit-specific
operating parameters for new combined cycle and combustion turbine units. The
generic parameters and assumptions assumed in the model are shown in Tables 4-11
and 4-12. The first
TABLE 4-11
NEW CC GENERATING CHARACTERISTICS (REAL 2000 $)
------------------------------------------------------------
CAPITAL FIXED VARIABLE
COST O&M O&M SIZE
($/KW) ($/KW-YEAR) ($/MWH) (MW)
------------------------------------------------------------
PJM $590 $11.50 $2.00 520
------------------------------------------------------------
MAIN/ECAR $560 $10.50 $2.00 520
------------------------------------------------------------
WSCC-CA $650 $10.50 $2.00 520
------------------------------------------------------------
New York $610 $11.50 $2.00 520
------------------------------------------------------------
NEPOOL $610 $11.50 $2.00 520
------------------------------------------------------------
ERCOT $540 $10.50 $2.00 520
------------------------------------------------------------
TABLE 4-12
NEW CT GENERATING CHARACTERISTICS (REAL 2000 $)
------------------------------------------------------------
CAPITAL FIXED VARIABLE SIZE
COST O&M O&M
($/KW) ($/KW-YEAR) ($/MWH) (MW)
------------------------------------------------------------
PJM $410 $6.00 $5.00 345
------------------------------------------------------------
MAIN/ECAR $380 $5.50 $5.00 345
------------------------------------------------------------
WSCC-CA $475 $5.50 $5.00 345
------------------------------------------------------------
NEW YORK $430 $6.00 $5.00 345
------------------------------------------------------------
NEPOOL $430 $6.00 $5.00 345
------------------------------------------------------------
ERCOT $370 $5.50 $5.00 345
------------------------------------------------------------
TABLE 4-13
FULL LOAD HEAT RATE IMPROVEMENT (BTU/KWH)(1)
- --------------------------------------------------------------------------------------------
2001-2003 2004-2008 2009-2013 2014-2018 2019+
- --------------------------------------------------------------------------------------------
Combined Cycle 6,700 6,566 6,435 6,306 6,180
- --------------------------------------------------------------------------------------------
Combustion Turbine 10,400 (W) 10,192 (W) 9,988 (W) 9,788 (W) 9,593 (W)
10,700 (S) 10,487 (S) 10,427 (S) 10,070 (S) 9,871 (S)
- --------------------------------------------------------------------------------------------
(1) Degradation of 2% for CC units and 3% for CT
units was assumed (not included in numbers shown).
(W) = winter, (S) = summer
year in which new generic capacity can be added to the model is 2004. Capital
costs are assumed to decrease at 1% per annum (real 2000 dollars). Table 4-13
indicates the assumed schedule and effect of technology improvement on new unit
heat rates.
4.7.2 OTHER EXPENSES
Information on fixed costs, depreciation and taxes is also developed and
incorporated within the DCF analysis to determine the economic viability of the
new unit additions. Environmental costs and overhaul expenses are not included,
due to expectations that such expenses would be minimal in early years of
operation.
o Property taxes are assumed to be 1% to 2% of the initial capital costs.
o Depreciation of the initial all-in cost of the new additions is based on a
standard 20-year Modified Accelerated Cost Recovery System (MACRS) (150 DB)
with mid-year convention.
4.7.3 ECONOMIC AND FINANCIAL ASSUMPTIONS
o Minimum internal rate of return is assumed to be 13.5%.
o Financing assumptions are assumed to be 60% debt and 40% equity for
combined cycle units, and 50% debt and 50% equity for combustion
turbine units.
o Debt interest rate is assumed to be 9.1%. Debt terms and project lives are
20 years with mortgage-style amortization for combined cycle units and 15
years for combustion turbine units.
4-13
APPENDIX A: HISTORICAL AND PROJECTED ENERGY PRICES
- --------------------------------------------------------------------------------
Figure A-1 shows historical energy prices for all regions while Table A-1 shows
the monthly electricity price forwards used in the volatility forecasts for the
PJM, WSCC-California, New York, and NEPOOL regions.
FIGURE A-1
HISTORICAL ENERGY PRICES (REAL 2000$)
PJM MAIN COMED
[GRAPH] [GRAPH]
MAIN WIUM WSCC-CALIFORNIA
[GRAPH] [GRAPH]
NY EAST NEPOOL
[GRAPH] [GRAPH]
ERCOT
[GRAPH]
A-1
TABLE A-1
MONTHLY ELECTRICITY PRICE FORWARDS FOR 2001-2003 ($/MWH)
- ----------------------------------------------------------------------------
WSCC-
CALIFORNIA
PJM (NP15) NEW YORK NEPOOL
- ----------------------------------------------------------------------------
1/1/01 51.29 94.06 56.27 57.40
- ----------------------------------------------------------------------------
2/1/01 51.29 68.61 52.59 55.13
- ----------------------------------------------------------------------------
3/1/01 38.08 67.53 54.17 53.87
- ----------------------------------------------------------------------------
4/1/01 41.29 72.89 46.84 46.28
- ----------------------------------------------------------------------------
5/1/01 43.43 75.04 47.29 46.89
- ----------------------------------------------------------------------------
6/1/01 59.86 88.00 58.93 58.93
- ----------------------------------------------------------------------------
7/1/01 99.14 144.91 90.69 90.69
- ----------------------------------------------------------------------------
8/1/01 99.14 158.51 90.69 90.69
- ----------------------------------------------------------------------------
9/1/01 36.29 128.27 55.62 55.52
- ----------------------------------------------------------------------------
10/1/01 40.46 78.83 55.62 55.52
- ----------------------------------------------------------------------------
11/1/01 40.92 59.87 55.62 55.52
- ----------------------------------------------------------------------------
12/1/01 43.17 62.33 55.62 55.52
- ----------------------------------------------------------------------------
1/1/02 42.37 48.17 48.28 48.83
- ----------------------------------------------------------------------------
2/1/02 42.00 43.70 44.34 46.87
- ----------------------------------------------------------------------------
3/1/02 32.73 43.11 43.79 44.06
- ----------------------------------------------------------------------------
4/1/02 33.79 43.83 38.15 37.94
- ----------------------------------------------------------------------------
5/1/02 33.79 43.61 39.87 39.90
- ----------------------------------------------------------------------------
6/1/02 53.43 47.66 70.00 47.15
- ----------------------------------------------------------------------------
7/1/02 84.14 67.97 70.00 72.55
- ----------------------------------------------------------------------------
8/1/02 84.14 86.41 62.75 72.55
- ----------------------------------------------------------------------------
9/1/02 29.50 90.44 46.40 46.26
- ----------------------------------------------------------------------------
10/1/02 32.58 95.39 50.61 46.26
- ----------------------------------------------------------------------------
11/1/02 35.45 75.81 43.93 46.26
- ----------------------------------------------------------------------------
12/1/02 38.51 63.14 44.01 46.26
- ----------------------------------------------------------------------------
1/1/03 37.24 56.62 42.45 42.99
- ----------------------------------------------------------------------------
2/1/03 33.02 42.34 39.44 41.63
- ----------------------------------------------------------------------------
3/1/03 28.99 36.59 37.99 37.40
- ----------------------------------------------------------------------------
4/1/03 26.02 41.25 33.95 33.88
- ----------------------------------------------------------------------------
5/1/03 28.12 35.67 36.27 36.44
- ----------------------------------------------------------------------------
6/1/03 42.57 42.52 50.00 44.37
- ----------------------------------------------------------------------------
7/1/03 60.61 52.83 50.00 43.03
- ----------------------------------------------------------------------------
8/1/03 60.61 69.10 43.65 41.94
- ----------------------------------------------------------------------------
9/1/03 28.56 82.80 43.56 43.13
- ----------------------------------------------------------------------------
10/1/03 30.33 87.19 46.04 46.97
- ----------------------------------------------------------------------------
11/1/03 31.51 83.70 40.83 40.75
- ----------------------------------------------------------------------------
12/1/03 33.68 61.82 39.80 39.67
- ----------------------------------------------------------------------------
Source: Palo Verde Forwards and PA estimations.
A-2