<PAGE>
Exhibit (c)(4)
Feasibility Assessment
of the
Proposed Astoria Energy Project
September 2000
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TABLE OF CONTENTS
1. EXECUTIVE SUMMARY
1.1 Background
1.2 Key Findings
1.3 Organization of Report
2. OVERVIEW OF THE NEW YORK WHOLESALE ELECTRIC POWER MARKET
2.1 Overview
2.2 New York Power Pool Demand and Consumption
2.3 New York Generation Capacity and Production
2.4 New York Industry Restructuring
2.5 Overview of Proposed Product Markets
2.5.1 Installed Capacity
2.5.2 Energy Markets
2.5.3 Ancillary Services Markets
2.6 Open Access Transmission Tariff
2.7 Proposed Market Monitoring Plan
2.8 Transmission Infrastructure
2.9 NYPP Market-clearing Prices to Date
3. ASTORIA ENERGY PROJECT ASSESSMENT-- KEY ELEMENTS
3.1 Article X Application
3.1.1 Project Details
3.1.2 Practicality of the Project
3.1.3 Article X Requirements
3.1.4 Status of the SCS Application
3.2 Fuel Supply Assessment
3.3 Conclusions and Recommendations on Article X Application
4. ASTORIA ENERGY CAPITAL COST ANALYSIS
4.1 Summary
4.1.1 Study of the Cost of Proposed Generation in the US
4.1.2 Astoria Energy
4.2 Comparable Asset Values found in Utility Asset Divestitures
5. DESCRIPTION OF THE PRICE FORECASTING APPROACH AND METHODOLOGY
5.1 Background
5.2 Description of Market Price Forecast Methodolog
5.2.1 Approach to Projecting Energy-Clearing Prices
5.2.2 Approach to Projecting Supplemental Revenues
6. SUMMARY OF MODELING ASSUMPTIONS
6.1 New York Demand/Energy Forecasts and Hourly Loan Profiles
6.2 Existing Resource Capabilities
6.3 Existing Generating Unit Outage Parameters
6.4 Existing Unit Heat Rates
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6.5 Fuel Price Forecast
6.5.1 Natural Gas
6.5.2 Residual and Distillate Oil
6.5.3 Coal
6.6 Fixed and Variable O&M Costs
6.7 Inflation Assumption
6.8 New Entrant Cost and Operating Assumptions
6.9 New Entry Timing/Amount Assumptions
6.10 Heat Rates for New Entrants
6.11 NYPP Transmission Region Assumptions and Modeling Methodology
7. PRICE PROJECTION RESULTS
7.1 Overview of Price Forecast Results
7.2 Pricing Applicable to the Astoria Energy Projec
7.3 Economic Feasibility of the Astoria Energy Project
APPENDICES
A. Detailed Market Price Forecast Results and Pro Forma Analysis for the
Astoria Energy Project
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1. EXECUTIVE SUMMARY
1.1 Background
Navigant Consulting, Inc. (Navigant) was retained by ValueAct Capital, Inc. to
assess the feasibility of developing the proposed Astoria Energy Project, a
1,000 MW natural gas-fired combined cycle facility to be located near New York
City. The Project, referred to hereafter as the Astoria Project, would be
located adjacent to the existing Astoria Generation Station, now owned by Orion
Power Holdings, in Queens, New York. The Astoria Project would enter commercial
operation in 2003 with the output being sold into the regional power market,
either through bilateral contract arrangements or spot sales. This report
provides an overview of the New York bulk power market; an assessment of the
Astoria Project, based on information contained in its Application X to the New
York Public Service Commission (PSC) for the construction of the facility; and a
market price forecast and related financial assessment for the project for
several likely outcomes. In addition, Navigant provides an assessment of the
proposed fuel supply plan for the project and a benchmark analysis of the
capital cost for the construction of the project.
The New York power market has undergone significant change as historically
integrated utility functions have been unbundled, and the generation and power
supply components have been deregulated and opened to competitive forces.
Moreover, the former New York Power Pool (NYPP), an institution which was
created to coordinate generation/transmission planning and to facilitate the
region-wide pooling of power supply resources to achieve production cost
savings, has been replaced by the implementation of an Independent System
Operator (ISO). The ISO serves to oversee operations of and access to the
regional transmission grid, and implement and manage the bid-based spot markets
and installed capacity (ICAP) market. These various facets of transformation
have fundamentally changed the dynamics governing the revenue streams that will
be earned by merchant power generation resources such as the Astoria Energy
Project. The focus of Navigant's analysis is to assess the feasibility of
several aspects of the project and to provide a projection of revenues that the
Project will likely earn for sales into the New York City area of the New York
Power market. This projection was prepared based on market fundamentals in the
context of the market transformation that has taken place and will continue to
evolve within New England. This report documents the methodology/approach,
underlying assumptions, and results of Navigant's analysis.
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1.2 Key Findings
Navigant's due diligence assessment of the Astoria Project was broad, covering
many areas associated with the project's development. As a result of our
analysis in these areas, the following conclusions can be made as they relate to
the New York market and the Astoria Project.
. Based on the implementation of restructuring in the New York
Power market, the state has been subdivided into 11
transmission zones, reflecting significant transmission
limitations across the system. The Astoria Project is located
in Zone J, an area that includes New York City.
. The New York Power market has been restructured to include a
spot energy market that is determined based on
locational-based marginal pricing (LBMP). As such, the spot
market transactions are settled at the market- clearing price
of numerous points on the transmission system, reflecting the
different marginal costs of supplying energy at various
locations when the transmission system is constrained. Based
on the significant transmission constraints that exist between
Zone J and other zones, the energy prices in the New York City
areas are somewhat higher than most other areas in the state,
reflecting older, more expensive, and less efficient
generation setting the clearing price.
. Reliability requirements established by the New York State
Reliability Council (NYSRC) have established locational-based
capacity requirements for the New York City (Zone J) and Long
Island (Zone K) regions. These reliability requirements create
an immediate need for new capacity within Zone J. and provide
a significant penalty ($75/kW-year) for not meeting this
requirement.
. The proposed Astoria project is projected to earn an after-tax
return of between 13% and 19%. However, this estimate is a
function of future market pricing, fuel prices,
locational-based ICAP requirements, and the amount and timing
of new entrants within Zone J. There are currently.
. There is adequate up-stream gas supply available to support
the project. However, pipeline capacity is currently
constrained, and would require a
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commitment for up-stream construction to alleviate these
constraints. Local pipeline construction to the facility is
also required. There are several options available to the
plant. Unfortunately, each will be expensive based on the
urban location of the plant.
. The Astoria project would be one of the most expensive
projects of its size in the region. However, the project is
believed to be reflective of costs for land and construction
in the New York City area. The capital cost estimate seems to
be consistent with another project on Long Island; however,
more research should be done in this area to confirm this
higher price.
. Navigant's initial review identified several areas of concern
related to environmental modeling, construction of the
facility, and construction financing. Subsequently, the PSC
has deemed the Article X application incomplete, siting
several areas of concern. Fortunately, no area found
incomplete is deemed critical. Navigant believes that the
project could correct the deficiencies within 6-12 months
time.
1.3 Organization of Report
Following the Executive Summary in this chapter, this report is organized to
provide the necessary market background and underlying assumptions associated
with out analysis, followed by Navigant's market price and revenue projection
results. Specifically, Chapter 2 provides a detailed overview of the market
structures and institutions that have recently been implemented in New York.
Chapter 3 discusses various topics of key importance to the development of the
Astoria Energy Project. Specifically, it establishes the New York City area as
the appropriate area for consideration of revenue projections, discusses the PSC
Article X application process and progress, assesses the fuel supply options
available to the Astoria Project, compares the capital costs of the project to
that of other new plants, and compares the sale prices achieved in utility
generation divestitures to the installed cost of the Astoria Energy Project.
Chapter 4 describes the approach and methodology that Navigant employed to
prepare the price projections provided herein. Included in this chapter is a
description of the production simulation model, PROPHET, which Navigant
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utilized to emulate the economic dispatch of power supply resources within New
York subject to various system and plant level operating constraints. Chapter 5
summarizes the assumptions underlying Navigant's analysis. Finally, Chapter 6
presents the price projection and pro forma results of Navigant's analysis.
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2. OVERVIEW OF THE NEW YORK WHOLESALE ELECTRIC POWER MARKET
2.1 Overview
Historically the New York Power Pool (NYPP), an association of the major
investor-owned utilities, the New York Power Authority and LIPA, was responsible
for coordinating the development and operation of its members electric
production and transmission facilities in order to obtain optimal reliability of
service and efficiency of operation from the interconnected systems of its
members. NYPP dispatched power throughout New York on a single-system basis,
optimizing economic dispatch, while meeting prescribed reliability criteria.
As part of the dynamic restructuring in the state, the NYISO recently became the
fourth ISO approved by the Federal Energy Regulatory Commission (FERC). Under
the new structure, NYPP was dissolved and many of its functions were assumed by
the NYISO. Within the New York Control Area (NYCA), the NYSRC sets the installed
capacity requirements in accordance with NERC reliability criteria. The NYISO
then administers an installed capacity market where Load Serving Entities
(LSEs)/1/ can procure installed capacity to meet their requirements either
through bilateral contracts or auctions conducted by the NYISO.
The New York market has many characteristics that distinguish it from
neighboring markets, such as New England. A list of the major characteristics of
the New York market is provided below and discussed in subsequent sections of
the analysis.
. There are a smaller number of large utilities.
. New York has a balanced generation mix.
. The dominant source of generation is oil/gas steam capacity.
__________
/1/ Initially, LSEs will be the existing vertically integrated Transmission
Providers as well as existing wholesale customers such as municipal
electric systems. Under retail access, ESCOs may be the load- serving
entities for retail customers.
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. Slight surplus of capacity in the near term given existing
generation resources.
. Merchant plant activity has been slow but is now beginning to
pick up.
. The market is being restructured at the wholesale and retail
levels.
. intra-regional transmission bottlenecks exist, creating
disparities in locational energy prices.
. A major constraint point is the Central-East interface,
. Market prices vary across these interfaces.
. NYPA/LIPA influence is significant.
. Divestiture of generation assets has occurred for most
utilities.
. Retail access is being phased-in.
. Significant gas pipeline additions from the west are proposed,
but the status remains uncertain.
. The market is not liquid at this point.
2.2 New York Power Pool Demand and Consumption The New York market
has approximately seven million retail customers with annual electricity
requirements of 156,029 GWH. The region's actual historical peak load for the
year 1999 was 30,311 MW. The projected NYCA average annual peak demand growth
rate between 2003 and 2015 is 0.75%. Electrical energy growth is projected to be
0.9% over the same period./2/ lt is interesting to note, however, that the pool
has recently under- forecast actual demand, with the 1999 actual demand more
than 1000 MW greater than expected. In its 2000 Load and Capacity Report, NYISO
indicated that the capacity resources identified in the report would satisfy
NYSRC criteria for adequate reliability for
________
/2/ NYISO 2000 Load and Capacity Data.
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the year 2000. Beyond 2000, the NYCA is showing a deficiency in the capacity
needed to meet the 18% reserve margin requirement. Approximately 4,900 MW of new
capacity with approved Article X applications was included in NYISO's reserve
calculation. In addition, there is approximately 4,270 MW of capacity in the
preapproval stages that were not included in the reserve margin calculation.
According to market design filing recently approved by FERC, distributed
generation and interruptible load that is not visible to the NYISO's Market
Information System will be allowed to participate in the installed capacity
market, providing another source of capacity to LSEs. An assessment of New
York's projected resources and requirements is presented below.
Exhibit 2-1
Need for New Capacity Resources in NYCA
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2000 2001 2002 2003 2004 2005
================================================================================
Demand (W)
Net Internal 30,200 30,460 30,790 31,070 31,300 31,510
Demand
Reserve 5,436 5,483 5,542 5,593 5,634 5,672
Requirements
Total Requirements 35,636 35,943 36,332 36,663 36,934 37,182
Supply (MW)
Total Capability* 36,118 35,793 37,973 40,692 40,298 40,298
Surplus 482 (150) 1,641 4,029 3,364 3,116
(Deficiency)
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* Including 4,940 MW of new capacity with approved Article X applications.
As indicated in Exhibit 2-1 New York will have a need for additional resources
beginning in 2002 assuming the slight deficit in 2001 can be met through
additional purchases from
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neighboring markets. NYISO forecasts an additional 2,180 MW of merchant plants
to come online in 2002 and another 2,760 MW in 2003. These projects have
received approval of their Article X applications and are expected to alleviate
what would otherwise be a severe capacity deficit. These numbers reflect NYSRC's
18% required reserve margin.
However, the situation within New York City (Zone J) and Long Island (Zone K) is
somewhat different. Locational capacity requirements have been established for
these two subregions. Of the total installed capacity required for in-City load,
a minimum of 80% must be located in-City. Of the total installed capacity
required for Long Island load, a minimum of 89.7% must be located on Long
Island. Other locational requirements may be adopted in the future. Within Zone
J, where the Astoria Energy Project is located, the peak load is 10,340 MW and
total generating capability within the zone is only 7,874 MW. Furthermore, while
there is import capability into Zone J of 5,200 MW there is also an 80%
locational capacity requirement. This means that LSEs within the zone must
procure at least 80% of their installed capacity requirement from generation
located within the zone (i.e. 8,272 MW) or pay a penalty of $75/kW. This leaves
an in-city deficit of 398 MW, but an overall surplus (including the import
capability) of 2,734 MW.
2.3 New York Generation Capacity and Production
The region's currently available summer electric generating capacity and
purchases total approximately 36,000 MW. NYCA's mix of generating resources and
the production of electricity by fuel type are illustrated in Exhibit 2-2.
Exhibit 2-2
2000 NYPP Generation Capacity by Fuel Type and Production
[Image Removed]
While, NYCA has a diverse generation mix including coal, hydro, nuclear, oil and
gas-fired units, the chart also reveals that the generation mix is dominated by
oil and gas-fired units, which account for almost 35% of the capacity in the
region. However, over the last 15 years the share of oil in the generation mix
has declined as utilities have added gas and nuclear generation and NUG
additions have been predominantly gas-fired units. In fact, natural gas is now
the dominant source of power generation in New York.
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The New York ISO has identified over 15,000 MW of proposed generation in New
York but many of the projects are in the early stages of development. Several of
these have been specifically included in Navigant's market pricing analysis,
while others that are deemed less likely to materialize or fell outside a
reasonable window of time were not specifically included. A list of the proposed
merchant projects that were specifically included in the pricing analysis is
presented in Exhibit 6-6. At this point, all of these projects can be classified
as in the development or planning stages.
One of the major factors that could influence the level of merchant activity in
New York is the age of existing utility generating units. As illustrated on
Exhibit 2-3, the vast majority of the capacity in New York is older than 25
years. Several types of projects, such as small coal units and old oil-fired
steam facilities could be quite vulnerable in a competitive market or
significant changes to environmental regulations, and could be forced into
retirement.
Exhibit 2-3
Age Distribution of NY Generating Units
[Image Removed]
The mix of generating plants In-City, however, is quite different from that of
the rest of the state. As can be seen in Exhibit 2-4, gas and oil plants make up
nearly 40% of the generating capability with another 40% coming from imports.
Exhibit 2-4
Generating Capability for In-City Area
[Image Removed]
2.4 New York Industry Restructuring
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The electric industry in New York has undergone a significant amount of
restructuring activity resulting in the unbundling of the vertically integrated
utility structure and the introduction of fully competitive wholesale and retail
markets.
The fundamental driver of New York's electric industry restructuring initiatives
is the desire to reduce costs to end-use customers. Historically, New York has
had among the highest average electric rates in the country, ranking in the top
ten for the highest average electric rates (excluding Alaska and Hawaii). New
York's 10.71 (cent)/kWh rate is more than 50% above the national average of 6.85
(cent)/kwh.
All of New York's major investor-owned utilities have filed and received
approval of their restructuring settlement agreements. Each utility's agreement
provided for retail choice, with some customers receiving retail access as early
as 1998 or as late as 2002. Therefore, a competitive retail New York electricity
market is expected to grow rapidly over the next three years.
New York's approach to electric restructuring has largely been regulatory, as
opposed to legislative. Although some restructuring bills have been introduced
in the New York Assembly, the New York PSC's Competitive Opportunities
proceeding has provided the major deregulation impetus. On August 9, 1994 the
NYPSC began its investigation of issues surrounding electric industry
restructuring and issued final principles to guide electric industry
restructuring in June 1995. Since the PSC's final order, all of New York State's
utilities have received approval of their restructuring settlement agreements.
Each New York utility has a unique and different settlement agreement.
In January 1997, the member systems of the NYPP began the power pool
restructuring process by filing with the FERC their comprehensive restructuring
proposal to implement the necessary structures and institutions to foster a
competitive wholesale electricity market. The proposal called for the
replacement of the NYPP with an ISO and other institutions designed to meet the
primary objectives of the member systems: (i) to continue to satisfy the FERC
standards for open, non-discriminatory access to the transmission system; (ii)
to preserve reliability in a competitive environment; (iii) to facilitate an
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economically efficient wholesale electricity market. While the original filing
was modified numerous times, the primary objectives of the filing have remained
unchanged.
The market structure developed in New York can be classified as a "flexible
pool" structure involving the establishment of an ISO incorporating certain
power exchange functions. The ISO's primary mission is the reliable and
efficient operation of the New York bulk power system. The ISO also provides
centralized markets for energy, capacity, and ancillary services. The
restructuring of the wholesale market involves the replacement of existing power
supply markets with day-ahead and real-time bid-based spot markets for energy
and reserves. The two-settlement system is the cornerstone and foundation of the
new deregulated wholesale electric market in New York. The restructuring also
includes the establishment of a statewide transmission tariff. As part of the
restructuring process, a NYSRC was also established to primarily address
reliability concerns that are unique to New York (e.g., many localized load
pockets). The NYSRC was responsible for establishing reliability rules that will
be carried out through procedures developed by the ISO.
In January 1999, the FERC unanimously approved, with modification, the New York
ISO Tariff and market rules for operating bid-based energy markets. Also
approved were the member system's request for market-based rate authority for
energy and ancillary services. In February of this year, the member systems
filed an application to transfer operational control of their designated
transmission facilities to the ISO. The competitive energy market in New York
became operational in November 1999.
The FERC approved the ISO proposal to operate a multi-settlement system
entailing day- ahead and realtime bid-based spot markets for energy and
reserves. All transactions are scheduled through the ISO and the ISO schedules
all transmission within and on the ISO- controlled grid. The ISO has primary
control over system security and reliability, including authority to take any
action to preserve control area operation, such as load curtailment and/or
shedding, consistent with set standards.
2.5 Overview of Proposed Product Markets
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2.5.1 Installed Capacity
As previously mentioned, the ISO has established locational capacity
requirements for all Load Serving Entities, consistent with the statewide
installed capacity requirement and the NYSRC Reliability Rules. Of the total
installed capacity required for In-City load, a minimum of 80% must be located
in-City. Of the total installed capacity required for Long Island load, a
minimum of 89.7% must be located on Long Island. An additional requirement for
total NYCA capacity is that no more than 10% of load can be met from resources
outside the state. The current requirement for installed capacity reserves is
18% of peak demand. Total pool installed capacity requirement is based on 1 day
in 10 year LOLP planning criterion. Installed capacity requirements are
established annually and are applied to all LSEs in the state, such that they
can cover their annual forecasted peak load. Provisions will be made to allow
seasonal variations in the level of installed reserves. Current plans are for
LSEs to know their ICAP requirements in advance. A deficiency penalty equal to
$75/kW-yr. is currently being imposed.
The maximum ICAP that can be purchased external to the New York control area is
3,800 MW. The maximum ICAP that can be purchased from each of the neighboring
central areas is 2,100 MW from Hydro-Quebec, 1,600 MW from Ontario Hydro, 1,450
MW from ISO-New England, and 3,150 MW from PJM.
2.5.2 Energy Markets
The NYCA features two energy-related markets. The breakdown of these markets
appears below and are based on locational marginal prices:
. Day-ahead energy market
. Real-time balancing market
The Day-ahead energy market and the Real-time balancing market constitute the
two energy related markets and form the two-settlement process. The New York
market is based on the Location-Based Marginal Price at each generator's bus.
Differences in energy clearing prices at different locations are equal to the
cost of congestion and marginal losses between locations.
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The Day-Ahead market provides for "financially firm" energy contracts between
buyers and sellers through the pool. In setting forth the roles and
responsibilities of participants in the New York market, a new term, "Direct
Customer," has been adopted to designate an entity that can interact directly
with the ISO. Any market participant, a supplier, LSE, other transmission
customer or power exchange, meeting the ISO Tariffs technical and financial
requirements for "Direct Customer" can submit schedules for bids or bilateral
transactions directly to the ISO and participate in the ISO's settlement
process. However, market participants submitting schedules or bids through a
Direct Customer settle financially with the Direct Customer, not directly with
ISO.
The operation of this market relies on hourly forecasts of LSEs' expected loads,
the generators' hourly price/quantity bids, and scheduled bilateral
transactions. By 5:00 AM of the day prior to the dispatch day, the LSEs provide
the ISO with day-ahead and 7-day forecasts. LSEs, transmission customers and
suppliers provide the ISO with bids to supply and purchase energy, capacity and
ancillary services, as well as requests for bilateral transaction schedules.
Bids to supply energy, capacity and ancillary services identify resources as
dispatchable or non-dispatchable, indicate which ancillary services are
available from the resource and specify variable energy prices. Bids may also
specify minimum generation and start-up costs; however, these are not reflected
in the LBMP. To the extent a generator does not cover its minimum generation and
start-up costs, the ISO will provide them with a supplemental payment funded
through the New York ISO transmission tariff. Bids to purchase energy in the
day-ahead market specify quantities at the point of withdrawal and the prices at
which the purchaser will voluntarily curtail the transaction. Bi-lateral
transaction schedules identify hourly quantities by point of injection and point
of withdrawal. By 11:00 AM on the day prior to Dispatch Day, the ISO closes the
day-ahead scheduling process and posts the day-ahead schedules for each hour of
dispatch in that day.
The balancing market provides for reconciliation of the difference between
energy reserved in the day-ahead market and actual energy required in the
real-time dispatch. The ISO operates the real-time balancing market on a
centralized five-minute security-constrained dispatch (SCD) process, which the
ISO uses to determine the energy requirement. Positive or negative balances in
this market are cleared based on the real-time LBMP. Buyers and sellers can
participate in the balancing market with flexible bids or they can submit
bilateral schedules for energy up to 90 minutes ahead of the settlement period.
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Loads purchase energy at the LBMP at the point of withdrawal. Initially, the
LBMP for a zone is the load-weighted average of the Generator Bus LBMPs in the
zone. Until the ISO software to compute Load Bus LBMPs, the zonal LBMPs are
based on a weighted-average of generator bus LBMPs in the zone.
2.5.3 Ancillary Services Markets
Both the ISO Tariff filed on January 31, 1997 and the revised ISO Tariff specify
in detail how the ISO procures and pays for ancillary services and how customers
are charged for such services. The ISO obtains ancillary services on an
unbundled basis, using market-based procurement where possible. Self-provision
of ancillary services is typically implemented through sales to the ISO. The
treatment puts procurement of ancillary services on a competitive basis to the
extent possible, yet ensures that the ISO controls these critical
reliability-related services. On a statewide basis, operating reserves are 1,800
MW, which is 150% of the single largest contingency (i.e., 1,200 MW based on the
loss of Bowline or the link with Hydro-Quebec at Chateauguay.
The following is a list of the ancillary services markets:
2.5.3.1 Scheduling, System Control, and Dispatch
This service is cost-based dependent on ISO startup/formation and operating
costs and provided by the ISO. In the revised tariff, the excess payments
received for marginal losses, in any, will be used as a credit to offset the
cost of Scheduling, System Control and Dispatch. Thus any excess collections for
losses will be returned to customers in proportion to their energy usage.
Generating units bidding into the LMBP market submit multi-part bids which
identify separately their startup and minimum generation costs, as well as an
incremental energy bid curve for output above minimum levels. Although the ISO
takes start-up and minimum generation bids into account in determining which
units to commit, these bids are not factored into LBMP calculations. Therefore,
it is possible that market revenues may not cover the generator's total bid cost
to produce energy, including its start-up and minimum
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generation bids. Under these circumstances, a supplemental payment is made to
compensate the generator for these costs. Supplemental payments are recovered
from all loads through the Scheduling, System Control and Dispatch Ancillary
Service.
Stormwatch is a reliability procedure for downstate New York, whereby transfer
capability to downstate New York is reduced in the event of a thunderstorm. As a
result, higher cost generation facilities in Southeastern New York and Long
Island are substituted for lower cost imports from the north. Under the ISO
tariff, the procedure is treated like any other system failure that leads to a
temporary reduction in transfer capability, thus resulting in redispatch costs
that affect LBMPs in the real-time market. If redispatch costs result in a
revenue shortfall in the real-time market, the shortfall is funded through the
Scheduling, System Control and Dispatch ancillary service. The tariff does not
permit this service to be self-provided, so all load shares in these costs.
2.5.3.2 Reactive Supply and Voltage Support Service
This service is also cost-based and provided by the ISO. Payments for this
service are generator-specific and the payment is based on the embedded cost of
the generating resource associated with its tested reactive power production
capability. The embedded cost payment is determined by a formula, which utilizes
capital investment and operating expense information filed in FERC Form is. All
in-state generators receiving installed capacity credit receive the payment;
in-state generators not receiving installed capacity credit also receive the
payment for hours they are on-line.
2.5.3.3 Regulation and Frequency Response Service
Regulation Service is the adjustment made in the output of generators in
response to a control signal sent out from the control center every six seconds
to balance the system and follow load fluctuations. This is also known as
automatic generation control (AGC) service. Generating units providing
regulation service are asked to set aside a predetermined amount of capacity so
that the unit will be able to move up or down from its initial output, as
measured in MWs, the ISO must be able to change in one minute. The price for
this ancillary service is market-based rather than cost-based. Winners for
regulation and frequency control bids receive the market clearing availability
price, which reflects market dynamics as well as the wear and tear on generating
units that provide such service. In
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addition to being compensated this availability payment, generators increasing
output will be paid the LBMP for resulting energy.
2.5.3.4 Energy Imbalance
Under the new market structure, there is no separate balancing service for
transactions. Balancing is provided through the operation of the real-time L8MP
market. Market participants electing to schedule transactions in the day-ahead
market balance at the real-time LBMP. If an LSE consumes more energy than
scheduled, it makes a balancing payment; if it consumes less energy, it sells it
back to the market at the real-time LBMP. There are no penalties associated with
either circumstance. If a generator injects less than it was scheduled to
provide day-ahead, it will be charged the real-time LBMP at its bus for the
difference. No payments are made for injections above the schedules. Generators
that are off-schedule are also subject to a regulation charge.
2.5.3.5 Operating Reserve Service
Operating Reserve Service covers three types of reserve services: Class A/Class
B Spinning Reserves, 10-Minute Non-Synchronous Reserves and 30-Minute Reserves.
These ancillary services refer to generator capacity that is available to supply
energy in the event of contingency conditions. Units that dispatch in the
balancing market, responding to the ISO's 5-minute Security Constrained Dispatch
Signal are called Class A units. An owner that chooses to bid Class A units in
the balancing market must allow the ISO to use its option to provide spinning
reserves from that unit. This implies that the ISO would ramp down the unit's
capacity factor such that the unit can increase its output when faced with a
system emergency. Generators providing operating reserve service receive an
opportunity cost payment, equal to the difference between the LBMP and the bid
price of the lost opportunity MW, to cover revenue forgone in the energy market
when the unit operates at reduced output. When output is increased in response
to an SCD signal, the generator receives the LBMP. Units that provide spinning
reserves, but that are not controlled by the ISO SCD mechanism are called class
B units. These units are not paid for lost opportunity cost, but they receive
the market-clearing availability price based on bids from all generators. This
bid reflects the supply demand balance in the spinning reserve market, as well
as the premium placed on spinning reserves versus the energy market. Owners of
generating units may also bid to provide 10-minute non-synchronous
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reserves and 30-minute reserves. The ISO calculates separate market-clearing
availability prices for these two categories of operating reserves.
2.6 Open Access Transmission Tariff
The Open Access Transmission tariff incorporates regional transmission service
designed to eliminate rate pancaking. Transmission users pay a fixed charge,
referred to as a Transmission Service Charge (TSC). The TSCs involve a "license
plate" rate structure in which loads within defined zones pay a rate that is
reflective of the embedded revenue requirements of the transmission provider in
the zone in which the load is located. Wheel through or out customers' TSCs will
be based on the revenue requirements of the providers from whose territory the
energy leaves New York. TSC is not applicable for the Transmission Provider's
use of its own system to provide service to native load customers, as well as
for services pursuant to an existing agreement that is grandfathered.
Under the open access tariff, transmission customers pay congestion and marginal
loss charges for spot transactions through the ISO. These charges are built into
the LBMP. For bilateral transactions, these charges are referred to as
Transmission Usage Charges (TUC), added as a surcharge to the TSC, the fixed
cost of transmission.
Under the revised ISO tariff, market participants may elect to receive non-firm
transmission service for a bilateral transaction. Under non-firm transmission
service, the customer submitting the bilateral schedule agrees that its
transmission service will not be scheduled if there is congestion. If a non-firm
transaction is scheduled and congestion appears later, the transmission service
may be reduced or terminated. In that case, the generator's decremental bid
would be automatically considered as a bid in the real-time market unless the
generator indicates otherwise. In contrast, customers that elect to purchase
firm transmission service commit to pay the transmission usage charge (TUC), the
cost of transmission congestion and marginal losses.
2.7 Proposed Market Monitoring Plan
The Transmission Providers market monitoring program is to be administered by
the ISO. The program is intended to assist the ISO in developing information to
identify needed
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improvements to market rules and protocols and assess the possible exercise of
market power.
The program will monitor trends and anomalies in the energy; ancillary services
and installed capacity markets. Trends will be examined for indicators such as:
peak and off- peak prices, trading volumes in the central markets versus
bilateral transactions, the amounts and types of dispatchable supply and demand.
The analysis of anomalous behavior will focus on the volatility of indicators
such as prices, bids, and unit availability, forced transmission and generation
outages. Markets will be reviewed more carefully during times when system
conditions are more susceptible to gaming or other possible exercises of market
power. Such circumstances might include periods of high demand, severe
transmission constraints, as well as sustained generation and transmission
outages. The monitoring program will identify generating units that must run in
order to maintain reliability and identify reliability constraints that may
limit competition. The program will also review Power Exchanges' submission of
bids and schedules to monitor their participation in the central market.
A major element of the program is to ensure that market-clearing prices are
transparent and publicly available. To achieve this end, working with the
adviser, the ISO compliance staff publishes daily market clearing prices by
location. These prices are an important way for the ISO to maintain the
integrity of its dispatch and market coordination functions. The ISO provides
information to the public on transmission system conditions, including
historical supply and demand. This information, along with locational prices is
assembled in a database. The ISO also retains confidential data for monitoring
purposes. These include market bids of participants, identification of units
providing marginal bids, data on unit availability and forced outages, proposed
and accepted bilateral schedules, as well as actual/forecasted hourly load at
each location.
2.8 Transmission Infrastructure
The New York Transmission System connects bulk power generators and loads
throughout the state of New York. The transmission system primarily consists of
115 kV, 138 kV, 230kV, and 345kV facilities. The backbone of the system operates
at 345kV. The transmission facilities in the northern part of the state are
generally longer in length and
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fewer in number than downstate, reflecting the substantially larger
concentration of load in and around New York City and the prevalence of low-cost
generation in upstate New York.
The map presented below identifies a number of "load pockets", or zones in NYCA
that have been identified as potentially transmission constrained areas.
Exhibit 2-5
New York Load Pockets
[Image Removed]
The NYCA is divided into the Eastern and Western regions. Frontier, Genesse,
Syracuse, Adirondack and Utica fall under the Western region and Milwood, SPR
Dunwoodie, New York City and Long Island belong to the Eastern region. The
Western region generates roughly 40% of NYCA's energy and consumes only 34% of
the total peak demand. Thus generators in the Western region serve a significant
portion of the eastern region's load via the bulk transmission system.
Internal constraints have been a big issue within New York. The Total-East
interface, which divides central and western New York from eastern and
southeastern New York, represents the primary constraint for energy transfer
from the western region to the eastern region. This interface has a capacity of
approximately 5,200 MW and congestion occurs over 75% of the time. Exhibit 2-6
illustrates the transfer limits between regions within New York.
The most notable constraint is the Central-East interface which bisects the
market between Utica and Albany. The constraints into New York City is also an
issue and is more related to contingency operating requirements than physical
transmission limitations. Constraints could lead to pricing differentials
between western and eastern New York of $4-$5/MWH or more on average. Prices in
western New York have recently been propped up by nuclear outages in Ontario,
causing export of power from New York to Ontario.
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Exhibit 2-6
New York Transmission Transfer Limits (MW)
[Image Removed]
The NYCA is directly connected to Ontario Hydro (OH), Hydro Quebec (HQ), in
Canada and to the New England Power Pool (NEPOOL), and the Pennsylvania, New
Jersey and Maryland Interconnection (PJM) in the Eastern United States. The
following table illustrates the total current transfer capabilities between New
York and other regions.
Exhibit 2-7
Inter Regional Transfer Capability/3/
================================================================================
FCTTC (MW) OH HQ PJM NEPOOL Total
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NYPP Exports 1600 1000 725 1675 5000
NYPP Imports 1825 2470 2000 1575 7870
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Although the above table suggests that a large amount of inter-regional transfer
capability exists between New York and its neighboring regions, the actual
capabilities between regions can vary significantly. A number of factors
determine the actual capability between regions such as weather, generating unit
loadings and outages and customer load levels. The interregional transmission
transfer limits are illustrated in Exhibit 2-8.
Exhibit 2-8
Regional Market Profile and Infrastructure
[Image Removed]
__________
/3/ 1998 New York Power Pool Load and Capacity Data.
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2.9 NYPP Market-clearing Prices to Date
The electric market operated by NYISO opened in November 1999. Seasonal price
patterns have shown low average prices and volatility during the spring and much
higher price volatility and averages during the high demand periods of the
winter and summer. This can be seen in Exhibit 2-9 below.
Exhibit 2-9
Historic Energy In-City Pricing (11/99-7/00)
[Image Removed]
When plotted in descending order as in the following exhibit (Exhibit 2-10) it
is apparent that the energy price over the first nine months of market operation
was above $20/MWh, or above the variable costs of a new unit roughly 85% of the
time. This means that a plant with a short run variable cost of $20/MWh could
earn a contribution towards its invested capital for nearly all of its operating
hours depending on its availability and other operational considerations. This
naturally follows from the resource mix of the in-city (Zone J) plants. Being
older oil and gas units, they are constantly on the margin cylcing to meet loads
not covered by the import capability.
Exhibit 2-10
Hourly Day Ahead In-City Prices (11/15/99-7/31-00)
[Image Removed]
Exhibit 2-11 extends the analysis of the historic pricing for Zone J by showing
that a plant with a marginal generation cost of $25/MWh could earn roughly 60%
of its gross margin in only about 12.5% of the hours of the year.
Exhibit 2-11
Revenue Concentration in Peak Hours (11/15/99-7/31/00)
[Image Removed]
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3. ASTORIA ENERGY PROJECT ASSESSMENT KEY ELEMENTS
3.1 Article X Application
As part of our assessment of the proposed project, Navigant reviewed Volume I of
the PSC Article X application submitted in June of 2000 by SCS Energy LLC for
the Astoria Energy Facility. Navigant assessed the probability of its being
found complete, thereby allowing the project to proceed into public hearings,
and to assess the practicality of the project itself. On August 18, the New York
State Board on Electric Generation Siting and the Environment (Siting Board)
notified SCS Energy that its application was incomplete, citing several of the
areas flagged by Navigant, but also citing additional concerns.
Based upon its review of Volume I of the application, Navigant believes that
some major impediments exist to it being approved as proposed. Navigant believes
a major drawback of the project is its very size. While all of the project's
components may be able to be arranged to fit on the project site, almost all of
the available space on the 23-acre site would be filled with permanent
structures. This has caused concern over how the project could actually be built
given the lack of construction laydown space on the site as well as over the
impacts at offsite laydown areas and transportation routes.
Further concerns relate to whether air emissions from the project would indeed
be below significant impact levels (SIL), as suggested in the summary of the air
emissions studies in the first volume of the application. While Navigant
Consulting has no detail of the studies performed, other projects of similar
magnitude have been found to have emissions of at least one criteria pollutant
at or above SIL. Such a finding has been the basis of a finding of
incompleteness for at least two applications, which forced the applicants to
perform multi-source emissions modeling. The requirement for such modeling would
represent a delay of six months to a year in a finding of completeness for an
application.
At this point, Navigant is skeptical of the practicality of a 1000-MW project at
the proposed site and believes that a 500-MW project may more expeditiously
alleviate concerns raised in the review of the application. Granting that it
would be practical to construct the project as proposed on the available site,
correction of the deficiencies found by the Siting Board in the application is
likely to delay a finding of completeness by six months to one year.
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3.1.1 Project Details
The Astoria Energy Project is proposed as a 1000-MW combined-cycle project that
will be principally fueled with natural gas, but that is proposed to have the
capability to use distillate oil as a backup fuel. The project developers
propose to limit the use of distillate oil to 720 hours per year.
The project would be comprised of two power blocks, with each block consisting
of two General Electric 7FA combustion turbines, two heat-recovery steam
generators, and one steam turbine. The combustion turbines would be equipped
with low-NO\\x\\ burners capable of achieving emissions of nitrogen oxides
(NO\\x\\) at levels less than 9 ppmvd, the lowest NO\\x\\ emissions level among
any heavy-duty frame combustion turbines currently available. In addition the
power blocks would be equipped with selective catalytic reduction systems (SCR),
which would further reduce emissions of nitrogen oxides to levels below 2 ppmvd,
again among the lowest levels currently achievable for combined-cycle units. In
addition to SCR for reduction in NOx emissions, the project would utilize CO
catalysts for reduction of the level of carbon-monoxide emissions from the
project.
The project would also utilize air-cooled condensers to both minimize vapor
plumes and water requirements for the project. In the one major power project
approved in New York State since passage of Article X of the Public Service Law
in 1992, the Department of Environmental Conservation (DEC) mandated the use of
air-cooled condensers to minimize the intake of raw water and the resulting
mortality of entrainable aquatic organisms.
On August 18 the Siting Board informed SCS Energy that it found the application
to be incomplete. The Siting Board will allow SCS Energy to submit additional
material when available in an effort to complete the application. However the
Board will not allow hearings to go forward or the 12-month statutory time frame
for consideration of Article X applications to begin until SCS has submitted
additional information and the Board has determined that the application is
complete. The Board is likely to take an additional 60 days once SCS has
submitted supplemental information to again review the application for
completeness.
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3.1.2 Practicality of the Project
Navigant Consulting's most immediate and major concern is over the ability to
actually construct the project as proposed. The entire project site consists of
only 23 acres. As shown on the Project Layout, Figure 3-5 of the application,
while all facilities can apparently fit on the site, there is no room for
laydown of construction materials. A project of this size should have at least 5
acres of space available for construction laydown. The application calls for
"just-in-time" deliveries and staging of construction materials at offsite
laydown areas to compensate for this lack of space. However, it does not provide
sufficient detail to give any significant level of assurance of the practicality
of these measures.
Detailed construction plans are commonly not developed during the application
phase of a project. But in the present case, development of additional detail
would be appropriate to assure that there are practical methods to actually
construct the project. While Navigant Consulting has not developed any
construction plan of its own, it believes that a 500-MW project would alleviate
many of the concerns raised by the siting board.
Even if a 1000-MW project could be built on the site, there appears to be scant
room for movement of major components onto or off of the site after construction
is complete. The scale of the project layout is of too small to allow any
reasonable assessment. But it would be appropriate to review larger-scale plans
and equipment arrangements to make a more definitive assessment of the adequacy
of maintenance space and clearances.
3.1.3 Article X Requirements
All new power plants of 80 MW or greater in capacity in New York State must be
permitted in accordance with the requirements of Article X of the New York
Public Service Law. Article X was originally intended to be a process under
which all of the permitting requirements of New York State and its political
subdivisions, including federal EPA requirements for which permitting authority
had been delegated to the State, would be dealt with in a single unified
proceeding. Under Article X, developers of new power plants must apply for what
is called a certificate of environmental compatibility and public need, with the
application being made to a regulatory body called the New York State Board of
Electric Generation Siting and the Environment, commonly called the Siting
Board. The Siting Board is made up of five statutory members: the Chairman of
the New York State Public Service Commission; the Commissioner of the NYS
Department of
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Environmental Conservation; the Commissioner of NYS Department of Health; the
Commissioner of the NYS Department of Economic Development; and the Chairman of
the NYS Energy Research and Development Authority. In addition, for each
specific application the Governor appoints two members from the general public,
one of whom must be a resident of the county in which the proposed project is
located, and one of whom must be a resident of the judicial district in which
the proposed project is located. The Chairman of the Public Service Commission
serves as the Chairman of the Siting Board, while the staff of the Department of
Public Service acts as staff to the Siting Board.
The Article X regulations delineate some requirements for the contents of an
application, but the staffs of the state agencies involved in the review of an
application exercise significant discretion in requiring applicants to carry out
the specific investigations and studies required for an application. Typically,
the requirements for studies for any particular application have resulted from
negotiations between the applicant and the staffs of the state agencies. The
agencies have tended to require increasingly extensive studies with succeeding
applications as the staffs have sought to address problems that arose in earlier
applications.
The agencies are bound by specific requirements of federal and state law,
particularly in the areas of air and water pollution. In fact, the original
vision that the Article X process would be a unified proceeding in which all
state and local permitting issues, and all federal permitting issues for which
the State had been delegated authority, would be considered was voided by the
federal Environmental Protection Agency in late 1998. At that time the EPA ruled
that the Article X process was inconsistent with EPA's delegation of federal
wastewater-discharge-permit and air-permit authority to the NYS Department of
Environmental Conservation. EPA informed the State that its original delegation
of authority was to the NYS Department of Environmental Conservation alone, and
that no other state agencies or outside individuals could possess any authority
over the granting of wastewater-discharge and air-emissions permits. This forced
New York to amend Article X of the Public Service Law in order to vest air and
wastewater permit authority solely with the Department of Environmental
Conservation. However, the amendments to the law allow evidentiary hearings on
air and wastewater issues to be conducted before the Siting Board, with the DEC
using those evidentiary hearings as part of the record for its determinations on
water and air issues.
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However, all other state and local issues remain within the province of the
Siting Board. This means that, while applicants are expected to try to comply
with all local regulations and ordinances, the Siting Board can overrule those
regulations and ordinances if it finds them overly burdensome or impractical.
The Article X process is generally initiated by informal discussions and
consultations between the applicant and the staffs of State regulatory agencies
to determine the issues that need to be dealt with in the application. There is
also an expectation that the applicant will be conducting a public- involvement
program contemporaneously with his development of concepts and designs for the
project, giving the public meaningful opportunities to voice concerns and to
participate in the development of the project. An applicant is, in turn,
expected to give due consideration in its design to concerns raised by the
public, and to mitigate adverse affects to the degree practical.
Once a reasonable concept has been developed for a project, an applicant must
submit a preliminary scoping statement to the Siting Board. This statement is in
the form of a report that lays out information and details about the project as
they are then known. This information is expected to be in sufficient detail to
allow the parties to an Article X proceeding to enter into meaningful
discussions leading to agreement on stipulations for studies to be completed by
the applicant and included in the Article X application. The stipulations for
any particular project have generally been the yardstick against which the
completeness of the submitted application is judged.
Once an application is submitted, the Siting Board has 60 days to review it for
completeness. If the Siting Board finds deficiencies it will notify the
applicant and ordinarily give the applicant the opportunity to submit additional
information to complete the application. However, the Siting Board will delay
the commencement of hearings and the 12-month time frame for a decision on an
application until the application is ultimately deemed complete.
Once the Siting Board has determined an application to be complete, it appoints
a presiding hearing examiner, who is an administrative law judge from the
Department of Public Service, and an associate hearing examiner, who is an
administrative law judge from the Department of Environmental Conservation.
Ordinarily, all evidentiary hearings are to be completed and a decision rendered
by the Siting Board on a completed application within 12 months. In some
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situations, however, the hearing schedule can be extended by an additional 6
months. At the end of this period, the Siting Board must either issue a
certificate of environmental compatibility and public need, or deny the
certificate with specific reasons for denial.
Despite an applicant's being granted a certificate by the Siting Board, the
applicant must also be separately granted wastewater discharge permits and
air-emissions permits by the Department of Environmental Conservation. The DEC
is under no statutory requirement to act in a time frame consistent with that of
the Siting Board. However, in the one case in New York that has successfully
proceeded through the Article X process, the applicant was granted wastewater
and air-emissions permits soon after being granted a certificate by the Siting
Board.
Article X certificates remain valid for commencement of construction for 12
months after they are issued. A certificate may also be transferred, with the
approval of the Siting Board, to another party that agrees to comply with the
specific requirements of the certificate.
3.1.4 Status of the SCS Application
On August 18, 2000 the New York State Board on Electric Generation Siting and
the Environment notified SCS Energy that its Article X application for the
proposed Astoria Energy LLC power plant was incomplete. The Board cited the
specific areas in which it found the application incomplete, and allowed the
applicant to submit additional information to complete the application. The
Board also included a letter from the Department of Environmental Conservation
that cited DEC's separate findings of incomplete items in the application.
The deficiencies found by the Siting Board and the DEC are listed below.
. Failure to assess the electric-system impacts of the Astoria
Project in conjunction with nine other proposed projects
currently involved in Article X review.
. Failure to provide a pre-application waiver from the US EPA
Region II office from pre-construction ambient-air monitoring
requirements.
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. Failure to meet the requirements for an Environmental Justice
(EJ) Analysis.
. Failure to discuss any potential impacts of the project on air
traffic at LaGuardia Airport. Also, failure to fully evaluate
FAA regulations and NYC local laws, and to demonstrate
acceptability of stack height to the FAA and compliance with
local zoning laws.
. Failure to demonstrate financial resources sufficient for site
restoration and decommissioning.
. Failure to consider zoning, land use, local permits,
transportation, noise, visual, dust, recreational and other
issues for off-site properties proposed as construction
support areas.
. Failure to consult with DPS Staff regarding local laws,
ordinances, regulations and rules applicable to the project.
. Failure to provide a technological basis, or to provide a
review of reasonably related precedents, as bases for waiver
requests from local laws, ordinances, regulations and rules.
. Failure to provide adequate support for waiver requests from
zoning noise requirements.
. Failure to provide specific noise design goals in terms of dB
at receptors or property lines. Also, failure to specify
specific dB levels needed to achieve the modified CNR ranking
reported in the application.
. Failure to provide noise abatement measures for the
construction phases of the project.
. Failure to provide a description of post-construction noise
evaluation studies.
. Failure to provide a discussion of construction noise,
including impulse noises such as those from pile driving.
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. Failure to discuss the appropriateness in the decommissioning
plan of leaving two oil tanks, the boiler and electric
building, and the office building upon site decommissioning.
. Failure to include the proposed Poletti Generation Station
expansion and the proposed extension of the MTA "N" Line
extension on the land use map included as part of the
application.
. Failure to consider the compatibility of the project with the
proposed "Greenway" and proposed bicycle paths within the
vicinity of the project. Also, failure to consider the
compatibility of the project with the Bower Bay Boat Club and
permanent easements of the City of New York along the eastern
edge of the site. Finally, failure to provide sufficient
detail analysis of the proposed stack height on land uses at
LaGuardia Airport.
. Failure to assess visual and noise impacts on the Bowery Bay
Boat Club.
. Failure to specify the colors of major facility components.
. Failure to provide details of project lighting.
. Failure to indicate topography or areas of screening on the
viewshed map included in the application.
. Failure to provide a typical viewshed for the urban area under
study, or to provide source information for the Landscape
Similarity Zone Map, Figure 4.5-1, or for the Viewshed Map,
Figure 4.5-2.
. Failure to provide sufficient documentation regarding
procedures to be employed to refurbish two existing oil tanks
on the project site for distillate-oil storage use, and
failure to provide testing protocols and requirements, nature
and quantities of waste material, cleanup and disposal
standards, and disposal sites.
. Failure to provide electromagnetic field data in tabular form.
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Some of the deficiencies are of a nature that should be able to be rectified in
a fairly straightforward manner, but some are of a more serious nature that will
probably require significant additional work. The most serious deficiencies as
perceived by Navigant Consulting are discussed below.
3.1.4.1 Electric Transmission Studies
Upon review of the deficiencies cited by the Board, Navigant Consulting believes
that none of the deficiencies represent fatal flaws to the project. If the
applicant were to revise all of the studies in accordance with the Siting
Board's comments, Navigant Consulting estimates that an additional three months
of time would be required.
The following deficiencies with the SCS electric transmission studies cited by
the Board, and Navigant Consulting's assessment of them, are provided below.
1. Need for "a discussion of the benefits and detriments of the proposed
facility on ancillary services and the electric transmission system,
including impacts associated with reinforcements and new construction."
2. Need to include a design study.
3. Need for a system reliability impact study, thermal analysis, voltage
analysis, stability analysis, and relay-coordination analysis incorporating
all of the following proposed projects: Sunset Energy Fleet, Millennium
Power Generating Company, East Coast Power - Linden Venture, ABB
Development Corp, KeySpan Energy Ravenswood, NYPA Poletti, NYC
Energy/SEFCO, Orion Power, and Consolidated Edison's East River Repowering.
4. Need for a submittal of a scope of work produced by Consolidated Edison or
the New York Independent System Operator.
5. Need for an evaluation of the loss of the entire Astoria Energy Project as
one of two contingencies in a double-circuit outage.
6. Need for an identification of how generators, feeders, and series reactors
are treated under the "classical" method.
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7. Need for a description of where Astoria Units 1, 2, 4, 5, and 6 and the
Astoria gas turbines will be connected when Astoria Unit 3 is switched from
Astoria East to Astoria West.
8. Need for a transient stability analysis demonstrating that the voltage
oscillations and generator rotor angle will dampen out, and the time it
will take.
Items 1, 4, 6, and 7 will require the submittal of existing documentation (e.g.,
#4), further explanation (e.g., #1, #6, #7), and a clearly labeled drawing
(e.g., #7). The time required to produce this information should be minimal, and
should not significantly delay the progress of the Article X procedure.
Item #2 requires the Siting Board staff and the applicant to come to a mutual
understanding on the meaning of a "design study." In most circumstances, a
detailed design study (also called a facilities study) would be done as part of
an interconnection agreement with the connecting transmission owner. Further, a
design study is normally performed by the transmission owner at some point after
receipt of approval for the project through the Article X process.
Item #3 conflicts with the study scope for the System Reliability Impact Study
(SRIS), approved by the NYISO on April 4, 2000. The Public Service Commission
staff has supported the SRIS procedure and has been present at meetings of the
Transmission Planning Advisory Subcommittee of the NYISO, where the scopes of
studies are discussed and approved before their submittal to the NYISO Operating
Committee. In addition, the Phase 1 and Phase 2 SRIS reports had been reviewed
and approved by the NYISO. SCS Astoria Energy had revised the study scope for
its Phase 2 study to clearly identify the development projects that were to be
included in the analyses, and resubmitted the scope to TPAS for approval. The
revised scope was just recently approved by TPAS on August 30, 2000. However, as
of August 30, Consolidated Edison had not yet approved the Phase 2 system
studies. If SCS Astoria Energy determines that it needs to revise the Phase 2
system impact studies to satisfy the Siting Board's concerns, it is estimated
that these studies will require approximately 2 to 3 months to perform and to
receive approval by NYISO and Consolidated Edison.
Items #5 and #8 could be performed within 1 week, provided it is determined that
item #3 need not be performed. If it is determined that system studies need to
be redone with the inclusion of all of
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the units specified in Item #3, items #5 and #8 may be performed simultaneously
with the new system studies.
3.1.4.2 Air-Emissions Studies
SCS Energy sought a waiver from an EPA requirement for the gathering of one year
of normally required meteorological data in the vicinity of the project. Such a
request to EPA has to be based on a demonstration that there is already
representative meteorological data available from previous studies or from
ongoing monitoring in the vicinity of the project. SCS sought to rely upon data
gathered on a continuing basis by the National Weather Service at LaGuardia
Airport in lieu of gathering its own meteorological data. Without having
reviewed the request for an exemption, Navigant Consulting believes that SCS has
a reasonable basis for its request, and that EPA is likely to grant an
exemption.
However, as of the time of the submittal of its Article X application, SCS had
not yet received a waiver of the meteorological data-gathering requirements from
EPA. Consequently, the Department of Environmental Conservation deemed the
application premature. Moreover, DEC did not rule on the adequacy of the
air-emissions studies submitted in the application because of the lack of the
waiver from EPA. SCS's application for a waiver was apparently only submitted to
EPA on June 8, 2000. If EPA grants the SCS request for a waiver, DEC will then
apparently commence its review of the SCS air-emissions studies. If EPA refuses
to grant a waiver, the SCS application would be delayed by more than one year
while SCS establishes an air-monitoring station and collects 12 months of data.
Air-emissions studies are among the most critical environmental studies for a
project such as the Astoria Energy Project. Among the positive aspects of the
project is the fact that its developers are proposing to use the lowest NOx
emitting gas turbines commercially available on the market today, in conjunction
with an 80% efficient selective-catalytic reduction system. This will result in
NO\\x\\ emission of less than 2 ppmvd on natural gas. Emissions at this level
would be among the lowest of any recent gas-fired combined-cycle project. In
addition, Astoria Energy proposes to use CO catalysts to reduce emissions of
carbon monoxide. CO emissions can be a problem with combustion-turbine based
units, which require special consideration in CO non-attainment areas such as
the New York City area.
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Volume I of the application contains a summary of the results of the
air-emissions studies performed by SCS. However, this summary does not provide
sufficient information with which to judge the adequacy of the studies. The
conclusion of the studies is that emissions of all criteria pollutants from the
Astoria Energy Facility will be below significant impact levels (SIL) specified
by EPA. If true, this means that SCS does not have to perform multi-source
emissions modeling, in which the emissions from all sources in a wide area
surrounding the proposed project would have to be modeled. While Navigant
Consulting has no specific data upon which to base an independent conclusion, it
believes that a more in-depth assessment of the air-emissions analysis is
warranted. If the project were to be required to perform multi-source emissions
modeling because deposition of one criteria pollutant at a receptor site were to
exceed a significant impact limit, completion of the application would be likely
to be delayed by a minimum of six months, and more likely one year. One
pollutant of special concern is particulate matter. In the past, only the
fraction of particulate matter that would be captured on a filter had to be
considered in air- emissions analyses. However, most recently EPA has been
concentrating on condensable particulate matter, such as sulfates, from stack
emissions. The summary information in Volume I is not clear as to whether or not
condensable particulate matter was included in the total particulate emissions
determination. If not, particulate levels could be higher than those stated in
the application, which might force the applicant into multi-source emissions
modeling.
3.1.4.3 Impacts on Air Traffic at LaGuardia Airport
The application indicates that SCS has had contact with the Federal Aviation
Administration regarding the appropriateness of the project's stack height,
given the project's proximity to LaGuardia Airport. However, there is no
indication that the FAA has firmly agreed to the stack height proposed.
Moreover, there is no discussion about the effects of stack plumes on air
traffic at LaGuardia. while the project may ultimately be in compliance with all
FAA regulations and may not present a hindrance to air traffic, the application
does not confirm the FAA's agreement that the project is compatible with
operations at the nearby airport.
3.1.4.4 Environmental Justice
The application does not satisfy the guidelines of the DEC regarding
environmental justice investigations. The Department is beginning to require
such investigations to assure that minority or low-income communities are not
disproportionately subjected to impacts of environmental hazards. The
application disposed of this issue in only two or three pages, which the DEC
found to be superficial. While a brief reconnaissance of the area surrounding
the project site by Navigant
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suggests a predominance of Caucasian middle-class residents, SCS will have to
provide a more intensive analysis in accordance with guidelines that were
apparently given to SCS by the DEC in April.
Navigant Consulting also anticipates that SCS will have to consider in its
Environmental Justice review the effects on neighborhoods near off-site
construction laydown areas and along routes from those areas to the project
site.
3.1.4.5 Demonstration of Financial Resources
The Siting Board found the applicant's demonstration of financial resources to
cover decommissioning and site restoration inadequate. The Siting Board is
unlikely to approve any project for which it has concerns over the financial
capability of the applicant to undertake the project and to ultimately
decommission the project. SCS will have to be more forthcoming and specific in
this area, and will have to confirm the credit-worthiness of the project
developers and identify financial resources available to them.
3.1.4.6 Consideration of Off-Site Properties Involved in
Construction
The application identified certain properties that might be used for off-site
construction laydown space and for offsite parking for construction workers.
However, the project developers apparently have no firm agreements for use of
any of the off-site areas mentioned. The application contains sparse information
on the impacts during construction on areas in the vicinity of these sites, or
on areas along routes from these sites to the project site. Moreover, aside from
saying that workers will be transported from off-site areas by shuttle bus,
there is no indication of the traffic that would be generated by such trips, or
of the routes that the shuttle buses would take.
Navigant Consulting believes that the applicant will have to develop much more
information about impacts during construction on all areas that will be
affected, not only on the area in the immediate vicinity of the project site.
This could be a substantial effort, particularly in light of environmental
justice concerns referred to earlier. Navigant Consulting believes that three to
six months of additional time will be required to develop appropriate additional
information.
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3.1.4.7 Waiver Requests from Local Laws and
Ordinances
The applicant has requested the Siting Board to allow the project to avoid
compliance with some of the requirements of local ordinances. However, SCS has
not demonstrated that it would be either impossible or impractical to comply
with those ordinances, which is the standard required by Article X of the Public
Service Law before the Siting Board can grant such requests. Moreover, SCS did
not consult with the Department of Public Service (DPS) Staff regarding
potential waivers of local ordinances, as required by one of the stipulations.
Navigant Consulting views this as a potentially serious oversight. The Siting
Board will probably require substantive meetings between SCS and local
government agencies to explore the practicality of the project's meeting local
requirements. The Board will not allow the applicant to merely point to other
situations in which local requirements may not have been enforced as
justification for a waiver. SCS could at this point either agree to comply with
all local ordinances, or initiate meetings with the DPS Staff and the various
agencies of local government to confirm the impracticality of compliance.
3.2 Conclusions and Recommendations on Article X Application
Upon its review of Volume I of the Article X application submitted by SCS Energy
for the Astoria Energy Facility, Navigant Consulting has the following
conclusions and recommendations.
1. The Astoria Energy project incorporates a number of environmentally
positive features that should eliminate some potentially contentious
permitting issues. The project proposes to use air-cooled condensers to
minimize water requirements and to eliminate cooling-tower vapor plumes.
The project proposes to use 9 ppmvd low-NO\\x\\ burners in conjunction with
a selective catalytic reduction system to reduce NO\\x\\ emissions below 2
ppmvd. And the project proposes to use a CO catalyst for minimization of
carbon monoxide emissions.
2. A significant effort will be required to complete the Article X application
and secure air and wastewater permits from the DEC. Navigant believes that
many of the concerns raised by the Siting Board, however, could be
mitigated or eliminated by scaling back the project size to fit more
comfortably on the 23 acre site.
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3. It is not possible to independently confirm the stated conclusions of the
air-modeling analyses with only the information contained in Volume I of
the application. However, Navigant is somewhat apprehensive with the
conclusion that deposition of all criteria pollutants from the project were
found to be below significant impact limits (SIL), thereby eliminating the
need for multi-source air-emissions modeling. At least two other projects
of similar magnitude in an area outside of New York City were required to
perform multi-source emissions modeling. If the project were to be required
to perform multi-source emissions modeling, a completed application would
be likely to be delayed by about one year.
4. SCS has not received a waiver from EPA of the requirement for collection of
one-year of meteorological data at the project site. While Navigant
believes that EPA will grant the waiver, failure of EPA to do so would
delay completion of the application for more than one year while the
applicant establishes a meteorological station and collects data.
5. SCS apparently does not have any firm confirmation from the FAA that its
project as proposed will not be a hindrance to air traffic at LaGuardia
Airport. The stack height and vapor plumes from the stack are obvious items
of concern.
6. SCS has submitted only a superficial Environmental Justice review of the
project. A rigorous EJ review is likely to take several months, and should
consider potentially negative environmental effects on predominantly
minority and low-income communities near proposed off-site construction
laydown areas and along routes from the laydown areas to the project site.
7. SCS must demonstrate sufficient credit worthiness to support site
restoration in the event the project cannot be completed, and to support
decommissioning of the project. In Navigant Consulting's opinion, it is
unlikely that the Siting Board will grant an Article X certificate to a
poorly capitalized developer.
8. While the Siting Board has the authority to exempt projects from local
ordinances and zoning requirements, it is reluctant to overrule the
authority of local government by granting such exemptions. As a minimum,
the Siting Board expects applicants to consult with local government
agencies to explore compliance options, and to make serious attempts to
comply. The Board can only grant a waiver request upon a demonstration by
an applicant that it would be impossible or impractical to comply. SCS
apparently failed to consult with PSC Staff and with local government
agencies, as required in the project stipulations. Such consultations are
likely to delay completion of the application for several months, with no
assurance that the
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Board will ultimately grant waiver requests. However, inasmuch as SCS did
not requests waiver requests on the basis of impossibility or
impracticality, it is assumed that compliance is possible and that delays
in the Article X process could be avoided if SCS elects to rescind its
requests for exemptions.
3.3 Fuel Supply Assessment
The Astoria Energy Project is located in the franchise territory of Consolidated
Edison Company of New York, Inc. (Con Ed). It can receive high-pressure gas
supply in one of two ways: by connection to Con Ed's high-pressure transmission
system or by construction of an underwater lateral connecting to the proposed
Eastchester Expansion of the Iroquois Gas Transmission System (Iroquois).
The project is within close proximity of the New York Facility System (NYF), a
high-pressure transmission system that is jointly operated by Con Ed and KeySpan
Distribution. Con Edison would construct a 0.5 mile, 20" diameter pipeline from
NYF to the plant site. They would charge a fixed-rate carrying charge to recover
the cost of the lateral, as well as a transportation charge for transportation
from the city gate to the lateral. Transportation upstream of the city gate
would be Astoria Energy's responsibility.
This alternative is relatively easy to implement but has some drawbacks. Con Ed
has flexibility in what it could charge for transportation. Historically, they
have been very difficult in their negotiations. The New York Power Authority
(NYPA) has been a Con Ed transportation customer in this area for many years and
is routinely seeking alternatives, such as underwater bypass, because of the
high rate that Con Ed charges.
A second problem with this alternative is the firmness of gas supply. Pipeline
capacity into the Northeast is severely constrained. The largest transporter
into this area is Transcontinental Gas Pipe Line Company (Transco). Transco's
line operates at near capacity for most of the year either transporting gas to
market or to its storage fields in Western Pennsylvania. Other pipelines into
the area are Texas Eastern Transmission (Tetco), Tennessee Gas Pipeline
(Tennessee) and Iroquois. These pipelines also operate at high capacity factors,
especially in the winter. There are several proposals for expansion of existing
capacity or construction of new pipelines. Two of these
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proposals have been approved by the Federal Energy Regulatory Commission (FERC).
Transportation capacity to the NYF could be increased by as much as 1.4 BOF per
day in the next few years, although, it is likely that the increased capacity
would be under contract to shippers.
All existing capacity into the area currently is under contract to the LDCs. In
the winter, capacity is extremely tight and becomes very expensive, especially
in cold winters. In addition to the difficulty of getting supplies to the city
gate, there is a complicated allocation system in effect for transportation on
the NYF. Even if upstream supply is delivered on a firm basis, transportation on
NYF could be denied since it would be considered interruptible by Con Ed. Actual
access to NYF is governed by an agreement between Con Ed and KeySpan and is
allocated between them in relation to their own peak day contracts and does not
recognize any rights of third parties. In addition, the location of the Astoria
Energy Project is in the center of NYF and the addition of such a large load
could cause pressure problems in the area.
In the summer, the Astoria Energy project would compete with older, less
efficient generating plants and should be able to outbid them for gas supply. In
the winter, those plants would burn natural gas or low sulfur residual fuel oil
and interruption in this period could be extensive in winters that are colder
than normal.
The second gas supply alternative requires construction of a 13.7 mile
underwater lateral to Iroquois' Eastchester Expansion. Although this alternative
would have a significantly higher construction cost, it presents some
significant advantages. The cost of the lateral would likely be shared by NYPA
since NYPA's Poletti plant is in close proximity to the Astoria Energy site and
NYPA could use it as an alternative to Con Ed. This alternative is free of NYF's
allocation priorities and could deliver firm gas on a year around basis.
Transportation rates on Iroquois are declining and a portion of the daily
requirement could be firmed up on Iroquois to upstream interconnects with
Tennessee and Algonquin Gas Transmission (Algonquin). The Eastchester Expansion
Lateral would also deliver gas at higher pressure than the Con Ed alternative,
thereby reducing compression costs.
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The lateral would provide access to supplies from Canada or the US but would not
have the disadvantage of having access controlled by the local utility. A direct
pipeline connection would be a distinct advantage.
The biggest drawback to the Eastchester Expansion lateral is that the project
may never be built. It has not been finalized as yet, so no filing has been made
FERC. When the project is filed, it is likely that several parties will attempt
to have it delayed or rejected altogether. The timing may be such that the Con
Ed alternative may be necessary, at least to get the project started.
Overall, the gas supply for this project is realistically achievable. Supply
should be readily available for most of the year. Fortunately, supply
availability coincides with the periods of peak electric demand and high
electric prices. Several alternatives exist to ensure supply for longer periods
and those alternatives will need to be examined and priced out.
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4. ASTORIA ENERGY CAPITAL COST ANALYSIS
Navigant Consulting has refined its study of the cost of proposed generation in
the United States. With this refinement, we are in a position to evaluate the
competitive position of the plant proposed in Queens County, New York City:
Astoria Energy.
4.1 Summary
The purpose of this section is, first, to compare the total installed cost of
Astoria Energy relative to other similar plants proposed in the US, and second,
to state our opinion as to the appropriate level of cost of the plant. We
recently completed a study of combined cycle generating plants proposed for
development in the United States. We have modified the study to focus on mature
plants in the mature stage of development with financing in place. Financed
plants disclose most of the full cost of development of generation. We compare
these costs to the total cost of Astoria Energy.
We believe a critical element of the cost of Astoria Energy is its location. New
York City intensifies the cost impact of an urban, densely populated
environment. We conclude that although high cost, Astoria Energy is comparable
to the high end of the cost of generation development experienced in Texas,
California, and New England. This conclusion is grounded by our opinion of the
increased cost of development in an extremely dense urban area, and by
comparison with another plant proposed for a comparably high cost site on Long
Island, NY.
4.1.1 Study of the Cost of Proposed Generation in the US
The objective of our recent study of proposed generation was to evaluate the
competitive position of the installed cost of individual electric generating
plants: both combined cycle and simple combustion turbine. In addition, the
study included an analysis of the cost impacts of different factors such as
different markets, in service dates, developers, sizes in MW, stage of
development, and experience of the developer. The study identified competitive
advantages and disadvantages that influence relative costs. In doing this study,
we:
. Compiled a database of proposed merchant plants.
. Searched and reviewed a number of publications and data sources to
compile this information, including trade publications and
specialized databases.
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. Identified data by electric market.
. Developed a sub-database of projects for which we had cost
estimates.
. Classified projects into categories based on perceived
reliability of cost data.
. Adjusted costs to reflect regional cost differences using the
Handy-Whitman index.
. Compared costs by category on a $/KW basis for combined
cycles and CT's.
. Compared different developers, the projected costs of
development.
. Identified and analyzed factors that could account for cost
differences.
Some of the conclusions we can draw from the data are the following:
. The data show a wide variation in cost.
. As development proceeds, estimates increase for:
. Discovery, for example, of required design changes
. Disclosure, relating to information requirements of
publicly held companies.
. Economies of scale appear in the data trends up to about
500 MW.
. The data are ambiguous about economies of scale of larger
plants. This conclusion for larger plants does not deny
economies of scale up to and perhaps beyond 1000 MW, but only
that the data do not readily exhibit such economies.
. The Handy-Whitman index may under count the high cost of
development in high cost regions. (See Exhibit 4-1 for a map
of the Handy-Whitman regions.)
. The index reports comparable costs through out the northeast
quadrant of the US, including states from West Virginia to
Maine and Ohio to Missouri. In this large region, the high
costs of urban areas like New York City, Chicago or Boston is
masked by the lower costs of less urban areas and states.
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. An index of developer experience does not predict low cost
for high experience.
. We further conclude from these 5, especially 1 and 5 that the
market is not mature and has not rung out the lesser
performers. All this suggests opportunity for the performers.
Exhibit 4-1
Handy Whitman Regions
[Image Removed]
The study did not evaluate the relative cost of generation development in dense
urban areas versus less dense suburban or rural locations. In fact, the standard
tool for adjusting for relative regional cost differences, the Handy-Whitman
Index, divides the US into 6 cost regions. The one containing New York City,
also contains states from West Virginia to Maine. In fact, the cost difference
between the Northeast and the Midwest region is barely 2%. The Midwest includes
7 states west of the Mississippi: North Dakota, South Dakota, Nebraska, Kansas,
Missouri, Iowa, and Missouri. We think the costs in rural areas of the US under
represent the costs in more urban areas. This bias is especially true for the
cost of project development and construction in New York City.
In analyzing the data, we segregate the data for Combined Cycle plants into:
. Financed, Advanced Stage Development, and Not Under
Construction. We found the data show higher costs for
financed than for not yet financed plants.
. We also concluded that only selected costs found their way
into a published cost estimate. Financed plants generally
reported costs including the following:
. Site;
. Energy Connections (but not transmission gas pipeline
extensions or transmission lines and reinforcements);
. Plant costs, including interest during construction;
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. Development costs; and
. Corporate overheads.
4.1.2 Astoria Energy
Before calculating the actual position that Astoria Energy might have in the
range of costs exhibited by proposed plants, we have to deal with the fact of
constructing a plant in New York City. One of the aspects of the City is
congestion: congestion of all kinds. For example, only 50% of the electric load
within the transmission constraint around New York City can be supplied by
sources outside the constraint. The high cost of transmission construction in a
dense urban area and the potentially even more costly burden of risk to permit
electric transmission construction are an important element of the opportunity
to supply load in the City. Transmission constraints have kept electric prices
high in New York City.
Although a plant proposed for an existing brownfield near existing electric
generation may find it easier to obtain government permits and approvals, the
costs of construction are higher due to higher labor costs, site congestion,
urban construction requirements and limitations, and the costs of transportation
congestion. When comparing plant costs across the country, we recommend reducing
the cost of plants located in New York City by 10 % or more for design and
construction congestion costs and labor costs.
Astoria Energy is proposed to cost $793.4 million for 1,090 MWs or $728 per KW.
In our study, Handy-Whitman indicates an 8% higher cost of installed plant in
the Northeast US, including lower cost rural regions of eastern states. Because
urban costs are higher, we would compound Handy- whitman cost difference with
another 10% for New York City. Therefore, in comparison with all other plants
whose costs have been adjusted to Northeast quadrant US costs, the cost of
Astoria Energy is reduced by 10% to $662 per KW. Exhibit 4-2 shows this range of
costs for Astoria in comparison with other proposed combined cycle plants in the
the different electricity markets across the US.
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Exhibit 4-2
Cost Comparison of New Plants by Region
[Image Removed]
Though not a perfect picture, Astoria falls at the top end of most of the
proposed plants in the US: just as electricity prices are at the top end in
comparison with electric prices in the US.
We note that four financed plants in New England are equal in cost or higher
than Astoria. However we also note that these four plants are substantially
smaller ranging from 150 MW to 274 MW. Our finding of economies of scale to 500
MW suggest that if larger, these plants would individually have cost less per KW
than they did.
Exhibit 4-3 provides a comparison of the cost of Astoria Energy against the more
limited set of proposed plants: those with financing. We note that Astoria is in
an earlier stage of development and that it is likely to make commitments for
major components of the plant including turbine generators at a later date than
those plants financed to date. Because of the opening competition in the
electric generation market, developers of generation have been committing to new
combustion turbine units at a record rate. The three or four manufacturers of
this equipment have already raised prices of these units substantially.
Exhibit 4-3
Cost Comparison of Plants and Financing
[Image Removed]
There is another way to evaluate the cost of Astoria Energy. We have an example
of another plant proposed for a heavily congested area near New York City: on
Long Island. PP&L Global has proposed a site for simple combustion turbine
development, 300 MW at first, more to follow. The cost of this proposal is $500
per KW.
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From our study of proposed electric generation plants in the US, we have
compared the median cost of proposed simple cycle plants with the median for
combined cycle plants, $336 and $484 per KW, respectively. Combined Cycle plants
cost about 144% of the simple cycle.
If we apply that ratio to the PP&L simple cycle proposal, adjusting it to the
combined cycle cost, we find a cost of $720 per KW. The estimated cost of
Astoria is $728 per KW ($793 million and 1090 MW).
4.2 Comparable Asset Values found in Utility Asset Divestitures
Much of the utility generation in New York has been sold to third parties as
part of the divestiture process and a portion of the purchased power contracts
have been sold or restructured. Exhibit 4-4 summarizes the divestiture activity
to date in New York and identifies the new owners of the assets. Several New
York utilities are in a position to retain some of the revenues received form
the sale of the assets, providing an incentive to maximize the sales prices.
Exhibit 4-4
Generation Divestment in New York
[Image Removed]
Sales of assets through utility divestiture have brought prices as high as
$1,000/kW in some areas and for some types of assets. This section of the report
compares the asset sales to date by region and fuel type as a way to gauge the
inherent market value of the Astoria Energy Project. While utility generation
divestiture has generally been considered to have been highly successful for the
selling utilities, there has also been a great deal of speculation to justify
the prices that have been paid. Many factors contribute to power plant valuation
including: expected prices for energy, capacity, and ancillary services; option
value inherent in the price volatility and uncertainty of start- up markets;
first-mover advantage; option value of future development on an existing
brownfield site; portfolio advantages; etc. A comparison, however, of the
divestitures across the country reveals that there are ranges of values for
certain asset types as can be seen in Exhibit 4-5 below.
Exhibit 4-5
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US Generation Divestitures by Region and Timing ($/kW)
[Image Removed]
The highest prices were paid for asset portfolios with an abundance of hydro and
coal units. Coal plants have low variable costs and will typically run whenever
they are available. Hydro plants have variable costs near zero, and if they also
have the ability to store water can target the highest prices periods thus
maximizing their margins. Plants located in metropolitan areas sold at a median
price of around $275/kW, but many of these plants are quite old and inefficient
and are only dispatched during periods of high demand.
Exhibit 4-6 shows a comparison of generation divestitures by region and
chronology. Definitive conclusions cannot be drawn from the exhibit about market
maturity affecting prices. That is, prices don't tend either up or down
depending on how early or late the divestiture occurred. There is a marked
difference, however, between sales in the Northeast and those in the West.
Average prices in the Northeast were $43 11kW versus $237/kW in Western states.
Exhibit 4-6
US Generation Divestitures by Region and Timing ($/kW)
[Image Removed]
Based on this analysis we can conclude that baseload plants in Northeast markets
are inherently more valuable than peaking or cycling plants in the Northeast,
and that at the time of the divestitures, entry into Northeastern markets was
valued more highly than entry into Western markets.
The inherent market value of the Astoria Energy Project should be above the
average for Northeast plants based on the following factors.
. It should operate as a baseload plant.
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. It should have a price advantage over other in-city
generation and be able to compete with out-of-city generation
during some periods.
. Capital expenditure requirements should be less than
neighboring plants due to age.
. There are market advantages related to in-city capacity
requirements established by the NYISO.
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5. DESCRIPTION OF THE PRICE FORECASTING APPROACH AND METHODOLOGY
5.1 Background
The approach Navigant used to develop the price projection, discussed in detail
below, is consistent with the approaches that have been used by market
participants in assessing market prices within the restructured New York power
market. Navigant has prepared market price forecasts using the same approach to
assist bidders in deriving market values -- and ultimately purchase bids -- for
numerous utility assets being divested in New York and elsewhere. Specifically,
over the past couple of years, Navigant provided such price projections to
confidential bidders in the following utility divestitures: New England Electric
System ("NEES"), Central Maine Power ("CMP"), Maine Public Service ("MPS"), New
York State Electric and Gas ("NYSEG"), Niagara Mohawk ("NiMO"), and Consolidated
Edison ("Con Ed"). In addition, Navigant has provided similar price forecasting
services, employing the same basic approach, to numerous merchant plant
developers in New York, New England, the Pennsylvania-New Jersey-Maryland
Interconnection (" PJM"), various Midwestern states, and Ontario. Through these
consulting engagements, Navigant's forecasts have withstood considerable
scrutiny from a number of sources, including senior managements, boards of
directors, and lending institutions.
5.2 Description of Market Price Forecast Methodology
The following sections present the details of our analytical approach to
projecting market prices for each of the major wholesale supply products traded
within NYPP.
5.2.1 Approach to Projecting Energy-Clearing Prices
To prepare the energy price forecast presented in this report, Navigant used a
simulation model called PROPHET. PROPHET is a multi-area, bid-based pooling
simulation model designed for projecting wholesale energy prices in a
competitive electricity market. PROPHET was specifically developed to simulate
generator bidding and dispatch in bid-based pooling energy markets, such as has
been implemented within New York. PROPHET clears the spot energy market based on
the sell "offers" specified for all generating plants within the relevant market
and projected load levels. The market-clearing price established by PROPHET
reflects detailed plant operating characteristics, random plant forced outage
rates, planned maintenance schedules, and seasonal resource characteristics. In
addition, PROPHET allows for the modeling of inter-regional transmission
limitations, and in times of constraint, calculates locational clearing prices
on both sides of the constrained interface to reflect the costs of transmission
congestion. The diagram in Exhibit 5-1 provides an overview of the energy
simulation process using PROPHET.
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Exhibit 5-1
Overview of Energy Simulation Process
[Image Removed]
Navigant used PROPHET to optimally dispatch the New York utilities' and
independent power producers' generation resources to meet projected hourly loads
within New York in a least-cost manner. The energy-clearing price in each hour
is set equal to the bid (or offer) price to supply energy of the last increment
of generation needed to meet load within the New York market. This is consistent
with the manner in which the NYISO calculates hourly energy market-clearing
prices and facilitates spot market settlements in its role as administrator of
the bid-based energy market. As discussed later in this report, Navigant assumed
that all generators bid an energy price equal to their short-run marginal cost,
consisting of fuel, variable operations and maintenance expenses, and emissions
allowance costs./4/
Translating the energy-clearing price calculation method discussed above into
fundamental economic theory, the energy-clearing price calculated for a given
hour reflects the price at the intersection of the supply and demand curves for
energy in that hour, as illustrated in Exhibit 5-2 below.
Exhibit 5-2
Illustration of Energy-clearing Price Process
[Image Removed]
In the above exhibit, the hourly clearing price P*, represents the bid price of
the unit of supply needed to meet the last increment of the total system demand
of Q*. In effect, the PROPHET
________
/4/ As discussed later, generators will bid energy in at prices above their
short-run marginal costs during high demand periods in an attempt to
maximize energy margins contributing to paying down the fixed costs of
operations. As a result, our marginal cost-based energy prices understate
somewhat the true energy prices generators would earn. We account for these
additional energy revenues through an estimate of a supplemental revenue
adder, which implicitly includes not only these "premium" energy revenues,
but also capacity and ancillary service revenues.
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model analyzes energy market supply and demand curves similar to those
illustrated above for each of the 8,760 hours of each year of our analysis, in
each case calculating the clearing price at the intersection of the supply and
demand curves. Thus, the algorithm used by the PROPHET model is consistent with
the fundamental economic theory of supply and demand equilibrium that underlies
the anticipated market behavior in the bid-based energy market in New York.
Based on the generating unit dispatch and energy-clearing price results
calculated by the PROPHET model, Navigant calculated the revenues that each
generating unit would receive from the sale of energy. The variable costs (e.g.,
fuel, etc.) that were incurred to produce the energy that was sold were netted
off from these energy revenues, resulting in a net profit margin on the sale of
energy. Importantly, in many hours, generating units will receive higher
revenues for the sale of energy than the cost incurred to produce the energy
sold. This would be the case when the energy-clearing price is higher than a
given unit's energy bid price, assuming the unit's bid price reflects its
short-run marginal production cost. This is more often the case for low-cost,
baseload resources than for relatively higher-cost peaking resources, and the
net margin on energy sales -- defined as energy revenues less energy production
costs is typically much larger for baseload resources than for peaking
resources. This resulting net margin on the sale of energy represents a
contribution towards paying down some portion of the fixed costs of unit
operations. The illustration in Exhibit 5-3 demonstrates the relationship
between a generator's marginal costs and the net energy margins it would
receive.
Exhibit 5-3
Relationship Between Generator Marginal Costs and Net Energy Margins
[Image Removed]
The graph on the left-hand side of Exhibit 5-3 presents a hypothetical energy
price duration curve assuming generators bid their short-run marginal costs into
the energy market. Given that resources would generally be dispatched in order
of increasing bid price,/5/ one can use the price duration curve to assess both
the likely number of hours a given generator would be dispatched,
________
/5/ The presence of transmission constraints or operating limitations could
cause resources to be dispatched out of economic merit order.
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as well as the net profit that generator would earn on the sale of energy. For
example, a generator with a marginal cost (i.e., energy bid price) of $20/MWh
would dispatch for just under 80% of the hours of the year, as denoted in the
exhibit. Since the generator would get paid the hourly energy-clearing price
for its energy production in each hour it operates, its total energy revenues
would be represented as the area under the price duration curve for the hours in
which it operates. In order to calculate the net profit margin on sales (i.e.,
the white area in the graph), we must net off the variable costs of production
that were incurred to produce the energy sold (i.e., the gray area of the
graph).
The graph on the right-hand side of Exhibit 5-3 provides a hypothetical
relationship between the marginal cost of a generator and the energy profit
margin it would earn. As can be seen, generators with lower marginal costs tend
to earn significantly higher energy profits than higher marginal-cost
generators. This is intuitive, as the white area in the graph on the left-hand
side of the exhibit would tend to get smaller for higher-cost, lower capacity
factor generators.
For most units, this net margin on the sale of energy (assuming marginal cost
bidding) falls significantly short of fully covering the fixed costs of
operations, even for some low marginal-cost baseload plants which earn very
sizable energy profit margins/6/. Given that most units are unable to fully
cover their fixed costs from the sale of energy at their short-run marginal
costs alone, these units must make up the remaining revenue shortfall from other
means/7/. These additional sources of revenue will likely come in a number of
distinct forms, as summarized below:
. Strategic Bidding of Energy - Although we have assumed that generators will
bid to supply energy at their short-run marginal costs in performing the
PROPHET simulation, many generators, in practice, will bid significantly
above their marginal costs in an attempt to
____________
/6/ Recent nuclear plant retirements in New England (e.g., Maine Yankee and
Millstone 1) are empirical evidence of this. Despite the fact that these
plants had among the lowest short-run marginal operating costs of any units
in NYPP, and thus would earn very high energy margins, the operators of
these plants did not believe these energy margins would be sufficient to
cover the high fixed operating costs of these facilities.
/7/ This shortfall would need to be covered in order to achieve market
equilibrium. Otherwise, operators would elect to retire plants that are not
covering their fixed costs of operations, which in turn would put upward
pressure on prices
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maximize their energy sale profits. The importance of this type of
strategic bidding is particularly evident for operators of peaking plants,
since there will be few hours in which the energy-clearing price exceeds
their operating costs (perhaps as few as 100 hours or less). As a result,
the spread between the energy-clearing price and their marginal costs must
be sufficiently large to enable them to cover their fixed operating costs.
If energy prices were simply set at short-run marginal costs, this spread
would inevitably be insufficient to allow these peaking plant operators to
fully cover their fixed costs, leading to the likely retirement of these
facilities.
This strategic bidding behavior has been witnessed in other bid-based
energy markets both in the U.S. (e.g., PJM, NEPOOL, California) and abroad
(e.g., UK, Australia, Alberta, etc.), as well as in NYPP since the
implementation of bid-based energy markets December 1, 1999. As shown
previously in Exhibit 2-10, energy prices in NYPP have been bid up to as
high as about $1000/MWh, and have been higher than $100/MWh for
approximately 3% of the hours. By comparison, Navigant estimates that the
short-run marginal costs of the more expensive peaking plants in NYPP are
generally in the $50-$100/MWh range. Thus, the energy-clearing prices to
date reflect significant departures from marginal cost bidding. While these
strategic bidding premiums are likely to occur during a relatively few
hours of the year, all plants that are operating in those hours will
receive the benefits of these higher prices. As shown in Exhibit 2-10,
these price spikes above marginal costs will likely contribute to
significant energy profits that may be used to pay down fixed costs of
operations.
. Revenues from ICAP Sales - Suppliers of retail load within NYPP will be
required to hold sufficient amounts of Installed Capacity (ICAP) or
otherwise be deemed to purchase from the spot market at market-based
clearing prices. As such, revenue from the sale of these products
represents another source of supplemental revenue over and above the
marginal cost-based energy prices that are calculated using PROPHET.
. Revenues from Ancillary Service Sales - As with ICAP, suppliers of retail
load within NYPP will be required to provide sufficient amounts of
operating reserves and (AGC). While Navigant believes that incremental
revenue opportunities from the sale of ancillary services is not likely to
be significant, any revenue earned on the sale of these products would
constitute another source of incremental value above the marginal energy
prices calculated using PROPHET.
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. Other Revenue Sources - Other sources of supplemental revenue include call
option premiums and fuel tolling agreement fees. While the markets for
these products are less uniform and visible, these arrangements could
provide an important source of incremental value.
The following section discusses the approach we used to estimate the level of
these forms of supplemental revenues, which when added to the energy prices
derived using PROPHET, constitute Navigant's estimate of the "all-in" price
projection for NYPP.
5.2.2 Approach to Projecting Supplemental Revenues
While generators will likely earn revenues from a number of sources as discussed
above, Navigant believes that the aggregate level of revenues earned is the most
important factor in achieving market equilibrium. That is, owners of existing
plants will decide to continue to operate or retire - and developers of new
plants will decide to build or not build - based on their expectations of the
total revenue they will earn from all sources. The manner in which these total
---
revenues are distributed across the various sources of value is not, in itself,
a key driver of plant retirement and entry decisions.
Therefore, Navigant's approach to forecasting supplemental revenues focused on
ensuring that the resulting all-in prices (i.e., the sum of marginal cost-based
energy prices and supplemental revenues) would be sufficient to encourage enough
generating capacity to remain in service to meet the minimum regional installed
reserve margin requirement. Navigant assumed that the total capacity requirement
is set at 118% of the projected peak demand for New York, consistent with the
approximately 18% reserve margin resulting from application of the NYISO's
installed capacity reliability criteria. In order to calculate the supplemental
revenues that would be needed to ensure enough capacity to meet the reserve
requirements at least breaks even economically, we first calculated each unit's
net shortfall in covering its "going-forward costs" after considering energy
revenues earned in the PROPHET dispatch. This shortfall for each unit represents
the amount of supplemental revenues each unit would need to avoid operating at a
loss.
For existing generating units, Navigant defines "going-forward costs" as those
annual operating and maintenance ("O&M") costs needing to be recovered such that
continued operations at an existing
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generating unit does not result in an operating loss. If these costs were not
capable of being recovered for a given generating unit, retirement of that unit
would be the most economically rational decision since the alternative would be
to operate at a loss. Previous capital investments for existing units have not
been included, since these costs are considered sunk. With respect to
prospective new generating units, Navigant defines "going-forward costs" to not
only include those costs which would need to be recovered in order to cover
annual operating expenses, but also the up-front investment costs and a
sufficient return on investment that would be required to attract a new entrant
to the market. Stated differently, Navigant defines going-forward costs for
existing units as those costs that could be avoided if the unit were retired. On
the other hand, Navigant defines going-forward costs for a prospective new unit
as those costs - including up-front investment costs - that could be avoided if
the unit were not brought on-line.
For existing generating facilities, going-forward costs included all fixed and
variable O&M costs, fuel costs, environmental emissions allowance costs, and an
estimate of property tax payments. Going-forward costs for existing plants also
included estimated future capital expenditure requirements, but did not include
previous capital investments because these costs are "sunk" and non-avoidable
even if a plant were retired. The going-forward costs of new capacity additions
included not only the basic fixed and variable O&M expenses assumed for existing
plants, but also the annual carrying costs of initial investment (including an
estimate of the return on equity which would be required to attract new
development).
Based on the calculated going-forward cost shortfalls for each unit, a supply
curve for capacity was constructed by stacking generating units in order of
decreasing profitability (i.e., increasing going- forward cost shortfalls). This
was done to determine the lowest-priced means of ensuring that sufficient
capacity at least breaks even economically to meet the regional reserve
requirement. Exhibit 5-4 illustrates the manner in which the sorted supply stack
for capacity and the assumed installed capacity requirements were used to derive
the supplemental revenue adder to be added to our marginal cost-based energy
prices determined using PROPHET to arrive at an all-in price. Specifically, the
bars reflect the magnitude of various units' (labeled A through I) net shortfall
in covering their going-forward costs, and as such, also reflect the amount of
supplemental revenues each unit needs to at least break even./8/
_________________
/8/ A positive bar reflects that the unit was actually able to more than cover
its full going-forward costs solely from the sale of energy, such that any
capacity revenues earned would fully contribute to net profits.
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<PAGE>
Exhibit 5-4
Illustration of Process for Determining Supplemental Revenue Adder
[Image Removed]
As indicated in the above graphic, generating unit H is the last unit required
to meet the market's total capacity requirement. Therefore, we would set the
supplemental revenue adder at unit H's going-forward cost shortfall. Based on
this supplemental adder, unit H would exactly break even on covering its
going-forward costs. Importantly, we assume that all units would receive this
payment, consistent with market-clearing principles. Units A through G would see
a positive net profit, since their net revenue shortfalls were less than that of
unit H. On the other hand, unit I would fall short in covering its full
going-forward costs, since its net shortfall was greater than the shortfall of
the marginal capacity unit, unit H. Given that unit I would suffer a net loss,
it would be a prime candidate for retirement if this situation prevailed over a
period of time because the operator of that unit would be better off ceasing
operations of the unit than continuing to operate for a loss. This is the basic
rationale Navigant employed in the analysis to prompt economic retirements of
existing units.
Based on the approach described above, Navigant assumed that the supplemental
revenue adder in the long run would be established by the costs of new entrants
to the market. More specifically, Navigant assumed that the supplemental adder
would be capped at a level that, when combined with energy clearing prices,
would not exceed the all-in price required to attract a new entrant. This
assumption is premised on the view that if the supplemental revenues paid to
essential generators are too high, new entrants would be attracted and their
entry would result in a reduction in prices back to equilibrium levels.
_______________________
profits.
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6. SUMMARY OF MODELING ASSUMPTIONS
Navigant's analysis was based on the use of the most recent, reliable, and
objective information, including regional demand and energy forecasts, actual
utility hourly load profiles, fuel price forecasts, generating plant ratings,
and other pertinent generating unit operating parameters. This chapter provides
a summary of those modeling assumptions, as well as the sources and basis for
those assumptions.
6.1 New York Demand/Energy Forecasts and Hourly Load Profiles
The PROPHET model requires the specification of hourly load profiles for each
year of the analysis. In order to derive hourly load profiles for each year of
the forecast, Navigant utilized hourly load information for 1997 which was filed
by NYPP in the FERC Form No. 714/9/. This historical hourly load profile was
scaled appropriately for each year of the analysis to reflect the expected
growth in peak demand and energy. To accomplish this, Navigant used the annual
peak demand and energy forecasts for New York as reported in the 2000 NY/SO Load
and Capacity Data report. The Load an Capacity Data forecast is developed by
staff at the NYISO using econometric forecasting models, and reflects
substantial input from NYPP members regarding key factors affecting load and
energy growth in their respective service territories. The year-by-year peak
demand and energy assumptions for New York used in the PROPHET model are
summarized below in Exhibit 6-1.
_________
/9/ While the 1998 and 1999 load shapes were also available, Navigant felt that
the 1997 load shape provided a better representation of a "typical" year.
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Navigant Consulting, Inc. Page 6-1
<PAGE>
Exhibit 6-1
New York Peak Demand and Energy Forecast
Assumptions
Year of Projected Summer Peak Projected Annual Energy
Analysis Demand (MW) Requirements (GWh)
2003 31,070 161,880
2004 31,300 163,570
2005 31,510 164,770
2006 31,740 166,240
2007 31,990 167,740
2008 32,250 169,320
2009 32,480 170,680
2010 32,720 172,280
2011 32,970 173,890
2012 33,200 175,450
2013 33,470 176,860
2014 33,730 178,370
2015 33,970 179,980
6.2 Existing Resource Capabilities
Navigant relied on the 2000 Load and Capacity Data Report as the primary source
for all generating unit capacity ratings. PROPHET was specified with both the
summer and winter generating plant capability ratings reported in the Load and
Capacity Data Report, thus reflecting the fact that many facilities have lower
ratings during the summer peak period.
6.3 Existing Generating Unit Outage Parameters
The maintenance schedule for units was based on a representative three-year
schedule for 1998 through 2000 developed by NYPP, which was repeated in a
cyclical fashion throughout the forecast period. The forced outage rate
assumptions for each of the generating units in New York were based on values
provided in the Summary of the NEPOOL Generation Task Force Long-Range Study
Assumptions ("GTF Assumptions") prepared by the NEPOOL Generation Task Force and
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Navigant Consulting, Inc. Page 6-2
<PAGE>
NEPLAN staff. The GTF Assumptions provide planning forced outage rate
assumptions for generic types of generating units which are applicable for New
York based generating technology.
6.4 Existing Unit Heat Rates
For existing plant heat rates, Navigant relied on a number of sources of
information, including heat rate information filed with NYPP, heat rate
information provided in the GTF Assumptions, actual heat rates calculated using
data filed by New York utilities in their FERC Form 1 filings, and Navigant's
own judgement.
6.5 Fuel Price Forecast
The year-by-year fuel price forecast assumptions that Navigant used in its
analysis are summarized below in Exhibit 6-2. These prices are intended to
reflect prices delivered to the generator, and as such, are inclusive of any
transportation charges that would be incurred./10/ The prices shown in Exhibit
6-2 for interruptible gas also accounts for the cost of fuel oil when an
interruptible gas plant has been interrupted and is required to operate on
distillate fuel oil.
Exhibit 6-2
Fuel Price Forecast Assumptions ($/MMBtu in nominal dollars)
[Image Removed]
Navigant combined these fuel forecasts with the assumed heat rates for each
generating unit to convert the $/mmBtu fuel prices to a $/MWh basis. This $/MWh
marginal fuel cost was used as the primary component of each generating unit's
bid price for the sale of energy in PROPHET. In addition to this marginal fuel
price, we also included estimated variable O&M costs in each unit's energy bid
price. Furthermore, we included within each unit's energy bid prices the costs
of the SO\\2\\ and NOx allowances that would be required by the units, given
their respective SO\\2\\ and NOx
__________
/10/ Transportation charges will vary from plant to plant, depending on which
pipeline is used, the transportation services that have been contracted,
and the specific receipt points used for the contract. For example, two
projects purchasing gas at two different receipt points on a particular
pipeline would likely pay similar prices for the gas, but pay different
charges for the transportation, which are considered fixed costs and are
appropriately not reflected in the plant's dispatch costs.
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emission rates in generating electricity./11/ The escalation rates underlying
the above fuel price projections are summarized in Exhibit 6-3 below.
Exhibit 6-3
Summary of Nominal Fuel price Escalation Rates
Nominal Escalation Rates: 2003-2015
-------------------------------------------------
Inflation: 2.50%
Delivered Gas: 2.22%
Resid Oil: 2.20%
Distillate: 2.20%
Coal 1.60%
A more detailed discussion of the basis for Navigant's price projection and
escalation assumptions for each fuel type follows.
6.5.1 Natural Gas
In developing its gas price forecast assumptions, Navigant relied on the Gas
Research Institute (GRI) 2000 Baseline Projection report. The GRI model
incorporates various macroeconomic drivers into its complex modeling effort to
achieve an internally consistent energy supply and demand outlook across all
energy sources and end-use demand sectors. Development of the GRI Baseline
Projection is an ongoing process that seeks to incorporate technological
advances and penetration of gas into end-use sectors. Since the forecast
reflects prices at the spot market (Henry Hub), Navigant included a
transportation differential to reflect deliveries into the Northeast. These
estimates reflect recent history for delivery costs.
Navigant believes its gas price projection represents a reasonable estimate of
delivered prices to the Northeast, taking into consideration the profound
impacts the pipeline expansions and the significant increase in demand by power
generators will have on delivered gas prices. With respect to longer-term gas
price escalation (see Exhibit 6-3), we assumed that gas prices escalate more
slowly than the general inflation rate of 2.5% (i.e., 0.28% real decline in
prices). It is important to
________
/11/ We assumed allowance costs of $200/ton and $1,000/ton for SO2 and NOx,
respectively, and held these ft throughout the forecast.
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note that the gas prices presented in Exhibit 6-2 were used for all New York
gas-fired generating units.
6.5.2 Residual and Distillate Oil
Like natural gas, Navigant relied upon GRI price forecast for oil. Exhibit 6-2
provides a graphical depiction of the GRI forecast. With respect to long-term
escalation, Navigant assumes that residual oil will escalate at 2.2% per year
(i.e., -0.3% real escalation) while distillate oil was assumed to escalate at
2.5% per year (i.e., 0% real escalation). While residual oil and natural gas
have historically been viewed as substitutes and thus tended to increase in
price with one another, we have assumed that residual oil will escalate at a
lower rate than gas for two primary reasons. First, residual oil will
increasingly be disfavored for environmental reasons and gas will become a
premium fuel due to its clean burning properties, thus likely leading to gas
prices increasing at a greater rate than residual oil prices. Second, most of
the dual-fueled oil/gas steam units which burn residual oil in New York are
relatively inefficient, and these units will likely get displaced by newer more
efficient gas-fired combined-cycle plants within New York. This would lead to a
drop in demand for residual oil for power generation, and thus likely soften
prices for residual oil as compared to gas. We have assumed that distillate oil
will escalate at the same rate as natural gas, both due to its relatively better
environmental properties than residual oil as well as the fact that most new
combined-cycle facilities will use distillate oil as a backup fuel.
6.5.3 Coal
The longer-term coal price escalation underlying Navigant's forecast is 1.6% per
year (i.e., -0.9% real escalation), which is consistent with the escalation
rates underlying the GRI. This drop in coal prices in real terms is consistent
with recent trends and, in Navigant's view, would be required in order for coal
to remain competitive given the increasing environmental costs associated with
burning coal.
6.6 Fixed and Variable O&M Costs
Fixed and variable O&M costs for utility generating units were calculated based
on an average of actual operating cost information filed by the New York
utilities in their FERC Form No.1 filings over the 1992-1996 period. This period
was selected due to its availability at the time the production costs model's
was being developed. However, since this time, Navigant has benchmarked its data
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for accuracy. The various FERC Form 1 O&M expense accounts were allocated
between fixed and variable expenses as shown in Exhibit 6-4 below.
Exhibit 6-4
Assumed Allocation of O&M Expenses
Between Fixed and Variable
----------------------------------------------------------------------
Op Super & Engin. Fixed
----------------------------------------------------------------------
Fuel Fuel
----------------------------------------------------------------------
Coolants and Water/ Water for Power Variable
----------------------------------------------------------------------
Steam/ Hydraulic Expenses 50/50 Variable/Fixed
----------------------------------------------------------------------
Steam from Other Sources Variable
----------------------------------------------------------------------
Steam Trans. (Cr.) Fixed
----------------------------------------------------------------------
Electric Expenses Fixed
----------------------------------------------------------------------
Misc. Steam (Nuclear/Hydraulic) Expenses Fixed
----------------------------------------------------------------------
Rents Fixed
----------------------------------------------------------------------
Maint., Super & Engin, Fixed
----------------------------------------------------------------------
Maint. of Structures Fixed
----------------------------------------------------------------------
Maint. of Plant/ or Res, & Waterways Fixed
----------------------------------------------------------------------
Maint. of Electric Plant Fixed
----------------------------------------------------------------------
Maint, Misc. Steam (Nuclear/ Hydraulic )Plant Fixed
----------------------------------------------------------------------
6.7 Inflation Assumption
We assumed an annual inflation rate of 2.5%, which is consistent with sources
Navigant reviewed, including data reported by the Bureau of Economic Analysis
and the Bureau of Labor Statistics. In addition, Navigant reviewed the
Congressional Budget Office's Economic & Budget Outlook for the Fiscal Years
2000-2009. In this report, the Congressional Budget Office projects Consumer
Price Index ("CPI") growth of 2.6% per year. Our inflation assumption was used
to escalate the fixed and variable O&M expenses for each generating unit from
one year to the next, and, therefore, has an underlying influence on the
escalation embedded into our wholesale market price forecast.
6.8 New Entrant Cost and Operating Assumptions
Navigant's assumptions regarding the unit specifications, costs, and other
pertinent assumptions with respect to combined-cycle gas turbine ("CCGT") and
simple-cycle gas turbine ("SCGT") new entrants are set forth in Exhibit 6-5.
Specifically, Exhibit 6-5 provides cost and operational information for CCGT and
SOGT facilities and the financing and economic assumptions which we applied to
our analysis of both CCGTs and SCGTs. These assumptions were derived based on
Navigant's market insights and experience with respect to the costs and
characteristics of new entrant generation. These assumptions are supported by a
wide array of other timely and authoritative sources, including quotes from
equipment vendors and publicly available information regarding the cost and
operational characteristics of the proposed new generating facilities in the
Northeast.
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Exhibit 6-5
New Entrant cost and Operational Assumptions
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
Parameter CCGT SCGT Notes
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Plant Rating (MW) - Winter 504 176 Assume 20 MW of SCGT capacity added for each CCGT capacity addition
as proxy for CCGT dud firing capacity
- Spring 494 169
- Summer 473 165
- Fall 492 176
----------------------------------------------------------------------------------------------------------------------------------
Plant Construction Cost -
Through 2005 ($/kW) 550 315 Reflects tightness in CC equipment mkt.
----------------------------------------------------------------------------------------------------------------------------------
Plant Construction Cost -
Post.2005 ($/kW) 510 315 Reflects CC equipment supply catching up WI demand
----------------------------------------------------------------------------------------------------------------------------------
Percent Annual Growth in
Capital Costs 1.88% 1.88% Reflects 75% of the inflation value
----------------------------------------------------------------------------------------------------------------------------------
Fixed Operating and Maintenance
Expenses ($/kW-Yr) 9.00 5.25
----------------------------------------------------------------------------------------------------------------------------------
Variable Operating and
Maintenance Expenses ($/MWh) 2.50 2.63
----------------------------------------------------------------------------------------------------------------------------------
Percent Annual Growth in 2.50% 2 50% Reflects 100% of the inflation value
Operating Costs
----------------------------------------------------------------------------------------------------------------------------------
Net Plant Heat Rate (Btu/kWh - Study assumes CCGT/SCGT reductions of 200/320 mmBtu/GWh in 2008.
HHV) for incremental plants See below 10900 Heat rate represents degraded heat rate to account for partial load
entering commercial operation operation and efficiency deterioration between major maintenance
during the study period. overhauls
1998 6958
1999 7219
2000 6860
2001 6825
2002 6760
2003 6700
2004 and thereafter 6700
----------------------------------------------------------------------------------------------------------------------------------
Gas Arrangements Firm Interruptible
----------------------------------------------------------------------------------------------------------------------------------
Debt Leverage 65% 65%
----------------------------------------------------------------------------------------------------------------------------------
Cost of Debt 8% 8%
----------------------------------------------------------------------------------------------------------------------------------
Term of Debt (Years) 15 15
----------------------------------------------------------------------------------------------------------------------------------
Return on Equity 15% 15%
----------------------------------------------------------------------------------------------------------------------------------
Book Life (Years) 15 15
----------------------------------------------------------------------------------------------------------------------------------
Tax Life (Years) 20 15
----------------------------------------------------------------------------------------------------------------------------------
Property Tax Rate 2% 2%
----------------------------------------------------------------------------------------------------------------------------------
Inflation Rate 2.5% 2.5%
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Note: All Costs are in 1999 Dollars
In addition to the above, Navigant's modeling assumptions assume increased
capital costs for projects developed in New York City and on Long Island. Our
assumptions include $625/kW for In-City and $600/kW for Long Island, reflecting
much higher construction costs
Of particular note in the above new entrant assumptions is the assumed drop in
CCGT installed capital costs after 2005. This assumed drop is intended to
reflect the fact that current CCGT prices are somewhat inflated as a result of a
significant backlog in orders for such equipment with all the major equipment
manufacturers. Current estimates are that new equipment orders cannot be met any
earlier than 2002. This equipment shortage, combined with a frenzy of developers
vying to be "first to market", has caused prices for CCGT equipment to exceed
equilibrium levels. Navigant
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believes that by 2005 the supply-demand imbalance will have been reversed, and
CCGT equipment prices will drop to equilibrium levels. It should be noted that
the heat rates for the CCGTs, as provided in Exhibit 6-5, reflects the average
heat rate for all of the plants entering commercial operation during that year.
6.9 New Entry Timing/Amount Assumptions
Based on the status of proposed merchant plant developments in New York and our
opinion regarding which of the proposed merchant plants are most likely to go
forward, we fixed a certain level of entry of new gas-fired capacity through the
year 2006. The specific assumptions regarding which of the proposed merchant
plants would go forward are presented on Exhibit 6-6. Beyond the fixed entry,
additional new entrants were added based on economics and need.
The new entrant plants listed in Exhibit 6-6 represent the most viable of the
proposed merchant plants, as these plants constitute those plants which are in
operation, under construction, or have reached significant milestones in their
development process (e.g., siting approval, air permit approval, financing,
etc.). In general, the plants included have a high probability of materializing.
6.10 Heat Rates for New Entrants
There are several projects in the region that are either under construction or
under development and have been included as new entrants in the market price
analysis. It should be noted that the heat rates for the CCGTs, as provided in
Exhibit 6-6, reflects the average heat rate for all of the plants entering
commercial operation during that year.
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Exhibit 6-6
New Entrants Fixed Into the Market Price Analysis
Plant Additions
Nominal Estimated
Project Capacity COD
=============================================================
Cogen Tech Expansion 300 2001
Athens Generating Plant 1,080 2003
Astonia Energy 1,090 2003
Heritage Station 800 2004
Bethlehem Energy Center 750 2005
Bowline Unit 3 750 2005
East River Repowering 360 2005
Ravenswood Cogeneration Project 250 2006
Torne Valley Station (1) 860 2006
Poletti Expansion 500 2006
Brookhaven 580 2006
Plant Retirements
Nominal Estimated
Project Capacity COD
=============================================================
Waterside (2) 160 2005
Albany 1-4 (Bethlehem) (3) 381 2005
1. ANP Ramapo also proposed in same area.
2. Retired when East River Repowering enters CO.
3. Retired when Bethlehem Energy Center enters CO.
6.11 NYPP Transmission Region Assumptions and Modeling Methodology The
NYISO has identified 11 sub-regions within New York that it uses for planning
and operational purposes. While it monitors thousands of locational bus prices
for energy and congestion, load weighted average prices are calculated within
these 11 zones for withdrawals of energy from the system. The map of New York
shown earlier in Exhibit 2-5 illustrates these sub-zones identified by the NYISO
and the transmission interfaces demarcating them.
While the New York ISO has identified Zones A-K for planning and operational
purposes, Navigant's analysis has shown that significant prices differences
exist primarily between only four
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aggregated regions. To reflect the locational marginal pricing and congestion
management framework that has been proposed by NYPP, Navigant sub-divided the
New York region into the following four sub-zones for transmission congestion
analysis:
. ConEd (Zone J)
. Long Island (Zone K)
. NY-West (Zones A-E)
. Southeast New York (SENY, Zone F-I)
In addition, Navigant has modeled the New England market at the same level of
detail and integrated with New York. Exhibit 6-8 provides a graphical
representation of these transmission zones and the megawatt transfer
capabilities assumed between each zone for both New York and New England.
Exhibit 6-8
Inter-Zonal Transmission Transfer Assumptions (MW)/12/
[Imaged Removed]
Navigant mapped these transmission interfaces into the PROPHET model based on a
review of detailed transmission system and load information submitted in various
filings by NYPP to the FERC. A summary of the steps which Navigant employed to
segment the NYPP region into the four zones is provided below:
. Directional transfer limits between the four transmission zones were
based on the thermal/stability transfer limits presented in the FERC
Form 715. Specifically, Navigant used the thermal constraint basis
reported in the Form 715. In cases where a range of transfer limits are
presented, Navigant used the midpoint of that range for its assumption.
. Loads were mapped to the transmission zones in the following manner:
. Navigant used 1997 hourly load shape data for each New York
utility as filed in the FERC Form 714. Navigant advocates
using 1997 load shape data as a more representative "typical
year" than 1998, 1999, or another year's data.
. In cases where a utility's service area falls entirely within
one of the four transmission zones identified above, the
entire utility load profile was mapped to that zone.
. In cases where a utility's service area spans two or more of
the transmission zones, Navigant utilized bus-level load
information contained in transmission power flow cases filed
by NYPP in the FERC Form 715. Navigant aggregated the
bus-level load data contained in the power flow cases by
transmission zone. Based on the
_________
/12/ In directions where no limit is specified, there is essentially no
binding limit in that direction.
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relative aggregate bus-level loads in each zone, Navigant
calculated allocation factors by which to allocate utility
aggregate hourly load shapes across the multiple zones in
which that utility serves load.
. In some cases, utility holding companies report hourly load
profiles in aggregate for their operating companies. In such
cases, Navigant used monthly energy data for each operating
company to derive allocation factors by which to allocate the
aggregate company load profiles to each of the operating
companies by month.
. Existing resources were mapped to each transmission zone based on their
geographic location
. Imports into New York were mapped to zones as follows:
. Navigant explicitly modeled the interconnections between New
York and New England. Navigant's modeling of New England was
at the same resolution as New York (i.e., individual
generating units, with some less important units aggregated
together). Moreover, Navigant's modeling of New York
appropriately reflects the internal constraints within it
which impact the ability for economic energy to flow into New
England from New York.
. Other interconnections (PJM, Quebec, New Brunswick) were
represented as injections of energy within the appropriate
zone, based on the terminus of the interconnection within New
York. New entrants were mapped to the transmission regions in
the following manner:
. Based on the status of current merchant proposals, Navigant
fixed a certain amount of entry in the early years of the
study (as indicated in Exhibit 6-6).
. Generic new entry was mapped to the transmission zones such
that zones with highest energy prices were targeted first.
This reflects the fact that developers will target plants in
areas that offer the promise of greatest revenues. However,
Navigant imparted judgement as to the potential for/pace of
entry in any single zone given siting climate, constraint
issues, etc.
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7. PRICE PROJECTION RESULTS
This chapter of the report presents the results of Navigant's market price
projections and related assessment of the economic feasibility of the Astoria
Energy Project based on the assumptions and approach outlined in the previous
chapters. First, this chapter presents a high-level overview of the forecast
results. Next, we provide a general discussion of the economic feasibility of
the Astoria Energy Project. Included as part of this section of the report is a
pro forma assessment of the economic feasibility related to the Astoria Energy
Project for each of the scenarios analyzed. Finally, we provide NYPP price
forecast results reflective of the capacity and energy payments associated with
sales by the Astoria Energy Project into the New York power market.
7.1 Overview of Price Forecast Results
Exhibit 7-1 summarizes the forecast results for the period from 2003 through
2015./13/ Specifically, the graph presents the average energy-only and all-in
price results for the Con Ed zone of NYPP, which is the relevant region for the
Project. The energy-only prices plotted in Exhibit 7-1 reflect likely
energy-clearing prices assuming that market participants bid energy in at their
short-run marginal costs for all hours (average price of energy for all hours in
the year). As such, these prices do not include capacity or ancillary service
revenues. Moreover, the energy-only prices do not include "premium" energy
revenues that generators would earn in periods of tight supply and demand when
participants may bid above their short-run marginal costs./14/ The "all-in line"
on the graph combines the marginal-cost energy prices with Navigant's estimate
of these other sources of supplemental revenue (capacity, ancillary service, and
energy premiums) to arrive at an "all-in" price projection. This all-in price
represents the composite wholesale market revenue stream that a generator would
earn.
Energy-only prices are presented in Exhibit 7-1 for two specific time periods:
(1) an average over all 8,760 hours of the year (referred to as "all-hours");
and (2) an average of the 876 highest hourly energy-clearing prices for the year
(referred to as "Top-10%"). The all-hours energy price reflects the average
energy revenue that a baseload generator operating at a 100% capacity factor
would earn, while the top-10% energy price reflects the average energy revenue
that a peaking resource operating at a 10% capacity factor would receive./15/
___________
/13/ Navigant did not explicitly model each year in this period. Rather,
Navigant prepared capacity and energy price forecasts for each year from
2003 through 2010, and then 2012 and 2015
/14/ While we have assumed all generators bid their short-run marginal costs,
experience to date indicates that participants will bid significantly above
short-run marginal costs in select hours when available supplies tighten
up.
/15/ In actuality, this represents the upper bound on the average energy revenue
that a peaking unit operating at a 10% capacity factor would receive, since
it implicitly assumes that the hours that the unit is operating are
coincident with the 876 highest-priced hours of the year. In practice
however, unexpected forced outages and the inability to predict the precise
timing of price spikes would likely result in that unit not capturing some
of the highest-priced hours, thus resulting in a slightly lower average
energy price than the top-i 0% price presented in Exhibit 7-1.
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Exhibit 7-1
Summary of Price Forecast Results
Summary Comparison of All-in and Energy Only Prices
[Image Removed]
A review of Exhibit 7-1 provides some key observations, as noted below:
. The overall pricing trend follows the trends in the gas forecast noted
earlier. This is due to gas-fired generation being on the margin (i.e.
setting the market clearing price) for a significant number of hours.
. There is a drop in prices between the years 2005 and 2009 reflecting both
the contribution of additional gas pipeline capacity and an overbuild of
electric generating capacity. By 2009, load growth catches up the earlier
growth of supply and again prices begin to climb. These increases in
capacity supply result in a discounting of capacity values below the full
level needed to allow new entrants to realize their target returns for the
front years of the analysis. This capacity discounting derives from the
fact that we have assumed more new entry will come on line than is needed
to meet ICAP requirements over the 2005-2009 period, creating a short-term
capacity overbuild situation of almost 1000 MW in 2006. However, with load
growth and some small retirements, the short-term surplus is eliminated
resulting in a significant upward shift in pricing.
. Between 2009 and 2012, energy prices climb steadily and then level off due
to a leveling off of gas prices.
The price results discussed above reflect all-in prices over all 8,760 hours of
the year. In addition, the numerical price forecast results underlying the
graph in Exhibit 7-1 are presented in tabular format in Appendix A to this
report.
7.2 Pricing Applicable to the Astoria Energy Project
Exhibit 7-1 provides the energy price projection results applicable to the
Astoria Energy Project for the years 2003 through 2015, as well as supplemental
revenues that would likely be available to the Project./16/ The all-in price
figures in Exhibit 7-1 reflect the likely composite revenue stream that the
Astoria Energy Project could earn for its sale of energy, capacity, and
ancillary service into NYPP, as calculated in accordance with the approach
outlined in this report. In addition, our analysis suggests that the majority
of the total annual supplemental revenue is likely to occur during the summer
months. This is due to the fact that NYPP loads are highest in the summer,
________________
/16/ As discussed previously, these supplemental revenues not only reflect ICAP
revenue potential, but also serve as a catch-all for other forms of
revenues that generators would be able to earn over and above the energy
prices we have calculated based on marginal cost bidding behavior. Most
notably, these additional forms of revenue include energy price premiums
earned during periods in which participants bid to supply energy at prices
above their short-run marginal costs (i.e., as has been experienced
recently when prices were bid up as high as $1,000/MWh)
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causing most of the strategic bidding energy premiums and capacity value to
occur in the summer months.
7.3 Economic Feasibility of the Astoria Energy Project
As described above, the production cost assessment provides a forecast of the
dispatch and operation of the plant within the NYPP environment, and, as a
result, is able to provide a projection of the total revenue for the project
from selling energy into the markets. This revenue projection can be used to
measure the financial feasibility of the Astoria Energy Project in a pro forma
model. Navigant has prepared a pro forma analysis, measuring the profitability
of the project using assumptions with regard to capital costs, debt and equity
costs, and taxes. For this analysis, we relied on SCS's generic proforma model
that includes specific costs related to project's operation and maintenance
(O&M) and other variable costs specific to the proposed project. Results of the
analysis conclude that the project earns internal rates of return (IRR) between
11.4 and 13 percent using SCS Energy's proforma and Navigant's fuel costs and
energy and capacity revenues for the project. Details can be found in the in
the proformas in Appendix A.
Return On High Capacity Payment Case
12.99% Cash on Cash
31.51% Pre-Tax Leveraged
19.16% After-Tax Leveraged
Return On Low Capacity Payment Case
11.40% Cash on Cash
21.32% Pre-Tax Leveraged
13.09% After-Tax Leveraged
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APPENDIX A
Detailed Price Forecast Results
Exhibits A provides a detailed summary of the pricing results./17/ In reading
the price forecast summaries in these exhibits, the top block of prices are
energy-only prices based on the PROPHET model simulations assuming marginal cost
bidding of energy. The bottom block of prices are all-in prices reflecting the
composite of the energy-only prices and the supplemental revenue adder. As
discussed in detail in the body of this report, the supplemental revenue adder
captures the incremental value associated with strategic energy bidding premiums
and capacity/ancillary service revenues. The all-in prices capture the
composite revenue that generating units are likely to receive from all value
components in the unbundled wholesale power market.
The "all-hours" energy prices are the average of the hourly prices determined
using the PROPHET model over all 8,760 hours in the year, whereas the prices at
the various percentages reflect the cumulative average of the highest energy
prices for those respective percentiles of hours in the year. For example, the
prices on the 10% line reflect the average of the 876 (i.e., 10% times 8760)
highest-priced hours. The energy-only prices in Exhibit A can be used to
approximate the average marginal cost-based energy price a unit would receive
based on its capacity factor. For example, a peaking facility in NYPP that
operates at a 10% capacity factor in 2003 would realize an average energy price
of approximately $36.88/MWh. A baseload generator could expect to be
compensated for its output at approximately the all-hours energy price, which in
2003 is projected to be $31.22/MWh.
To arrive at the all-in price figures presented in Exhibit A, the supplemental
revenue adder was translated to a $/MWh basis by "spreading" the annual price
(in $IkW-yr.) over the appropriate number of hours. For example, for the all-in
price at the 10% level the $/kW-year value was converted to $/MWh as follows:
$/MWh = ($/kW-year)*[1 year/(8760 hours *10%)](1000 kW/MW).
_____________________
/17/ The prices presented in these exhibits reflect energy pricing for the Con
Ed transmission zone, which is most relevant for the Project since it will
be located in that zone.
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IN-CITY ENERGY PRICES AND CAPACITY PAYMENTS
09-Aug-00
<TABLE>
<CAPTION>
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Supplemental
Adders
($/KW-Yr) 49.67 51.67 52.28 65.23 66.64 67.84 66.41 67.35 65.44 65.53 65.21 66.88 68.56
--------------------------------------------------------------------------------------------------------------------
All Hours
Energy
($/MWh) 31.22 32.81 35.95 33.09 32.38 31.74 31.69 36.10 39.09 42.08 41.91 41.74 41.57
--------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10% 36.88 38.49 41.46 40.14 39.68 38.91 38.85 43.65 47.36 51.06 50.85 50.64 50.43
20% 35.56 37.50 40.53 39.74 39.05 38.21 38.11 43.12 46.72 50.31 50.12 49.94 49.75
30% 35.09 37.12 40.15 39.48 38.68 37.74 37.56 42.65 45.89 49.13 49.19 49.26 49.33
40% 34.69 36.70 39.94 38.61 38.00 37.32 37.18 43.31 45.25 48.20 48.39 48.57 48.76
50% 34.34 36.39 39.77 37.24 36.62 36.00 36.04 41.17 44.11 47.05 47.07 47.10 47.13
60% 34.07 36.13 39.61 36.12 35.49 34.88 34.90 39.89 42.87 45.86 45.81 45.77 45.72
70% 33.61 35.31 38.63 35.19 34.53 33.90 33.89 38.69 41.67 44.65 44.57 44.50 44.42
80% 32.73 34.39 37.64 34.37 33.64 33.03 33.02 37.67 40.67 43.67 43.53 43.39 43.25
90% 31.93 33.53 36.75 33.68 32.95 32.32 32.28 36.81 39.80 42.79 42.64 42.48 42.32
--------------------------------------------------------------------------------------------------------------------
<CAPTION>
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
All Hours
All-in Price
($/MWh) 36.89 38.71 41.92 40.54 39.99 39.48 39.27 43.79 46.56 49.33 49.35 49.37 49.40
--------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10% 93.59 97.48 101.14 114.60 115.75 116.35 114.66 120.54 122.06 123.58 125.29 126.99 128.70
20% 63.92 67.00 70.37 76.97 77.08 76.93 76.01 81.57 84.07 86.57 87.34 88.11 88.88
30% 53.99 56.78 60.05 64.30 64.04 63.55 62.83 68.27 70.79 73.30 74.01 74.71 75.42
40% 48.86 51.44 54.86 57.23 57.02 56.68 56.14 61.53 63.93 66.33 67.00 67.66 68.33
50% 45.68 48.18 51.71 52.14 51.83 51.49 51.20 56.55 59.05 61.55 61.96 62.37 62.79
60% 43.52 45.96 49.56 48.53 48.17 47.79 47.53 52.70 55.32 57.95 58.22 58.49 58.77
70% 41.71 43.74 47.15 45.83 45.39 44.97 44.72 49.68 52.34 55.01 58.21 55.40 55.60
80% 39.82 41.76 45.10 43.68 43.15 42.71 42.50 47.28 50.01 52.74 52.84 52.93 53.03
90% 38.23 40.09 43.38 41.96 41.41 40.92 40.71 45.35 48.10 50.85 50.91 50.96 51.02
--------------------------------------------------------------------------------------------------------------------
</TABLE>
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