New York State Capacity Market Review
prepared for
American Public Power Association
National Rural Electric Cooperative Association
New York Association of Public Power
prepared by
Laurence D. Kirsch
Mathew J. Morey
Christensen Associates Energy Consulting LLC
September 19, 2012
Christensen Associates Energy Consulting, LLC
800 University Bay Drive, Suite 400
Madison, WI 53705-2299
Voice 608.231.2266 Fax 608.231.2108
TABLE OF CONTENTS
Executive Summary..........................................................................................................................ii
I. Introduction .............................................................................................................................. 1
II. Background ............................................................................................................................... 3
A. Institutional Framework for Assuring Resource Adequacy .......................................... 3
B. Evolution of Institutional Responsibility for Resource Adequacy ................................ 5
III. New York Generation Investment History ................................................................................ 6
A. Generation Investment, 2000 to 2012 ......................................................................... 7
B. Generation Investment, 2000 to 2005 ....................................................................... 10
C. Generation Investment, 2006 to 2012 ....................................................................... 14
D. Planned Generation Additions .................................................................................... 16
E. Fuel Diversity............................................................................................................... 21
F. Geographic Dispersion: “Where It’s Needed Most” ................................................... 23
G. Reliability..................................................................................................................... 24
IV. Drivers of Generation Investment in New York ...................................................................... 27
A. Non-Market Standards ............................................................................................... 27
1. Obligations to Serve ........................................................................................ 27
2. Reliability Standards ....................................................................................... 27
3. Renewable Portfolio Standards ...................................................................... 28
4. Environmental Regulations ............................................................................. 30
B. Market Incentives ....................................................................................................... 30
1. Short-Term Markets........................................................................................ 31
2. Long-Term Markets......................................................................................... 33
3. Short-Term vs. Long-Term Markets ................................................................ 33
4. Capacity Markets ............................................................................................ 34
V. Conclusions ............................................................................................................................. 35
Attachment A. New York Generation Brought In-Service, 2000–2012 ....................................... 36
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EXECUTIVE SUMMARY
New York State’s electricity sector restructuring of the late 1990s included divestiture by
the State’s electric utilities of their generating assets, establishment of the New York
Independent System Operator (NYISO), and creation of competitive retail markets. Under
these new circumstances, New York State has engaged the question of how best to ensure
that investment in new generating capacity is sufficient to: 1) maintain reliability as demand
grows and as older, uneconomic generating units are retired and 2) support workably
competitive retail and wholesale electricity markets. The debate has focused on the value of
replacing the existing voluntary short-term forward capacity market with a mandatory longterm forward capacity market that would be similar to those in PJM and ISO-New England.1
Generation investment in New York is driven by both non-market standards and by market
incentives. The non-market standards, many of which are set by non-NYISO institutions,
include obligations to serve, reliability standards, renewable portfolio standards, and
environmental regulations. Market incentives are provided by the revenues that can be
gained or the costs that can be avoided: a) in NYISO-administered short-term markets for
energy, ancillary services, and capacity; b) through long-term bilateral transactions; and c)
through self-supply or ownership of generation. Thus, the NYISO-administered markets are
only one part of the overall framework for providing generation capacity and assuring
reliability.
The history behind each of the generating units placed in service in New York since 1999
indicates the following:

A mixture of bilateral PPAs, merchant plant investments, utility-owned supply, and
renewable resources, including those encouraged by federal tax incentives and the
New York State Energy Research and Development Authority (NYSERDA) has
provided adequate generation resources to satisfy growing electricity demand,
provide reliable electric power service, and meet environmental public policy goals.

The voluntary centralized capacity market administered by NYISO has provided a
workable complement to the bilateral market, utility-owned supply, and NYSERDAand federal tax-supported renewable resources.

The historical evidence of capacity investments over the past twelve years and the
proposed capacity investments over the next four years indicate that New York
State’s present capacity market structure has provided sufficient generation capacity
and promises to continue to do so for the foreseeable future.
1
The New York State capacity market in this paper refers to utility-owned supply, bilateral contracts between
utilities and merchant plant developers, merchant plants that rely on the New York ISO’s capacity and its other
centrally administered markets for revenues, and renewable resources that may enter bilateral contracts or
operate as pure merchant plants, but are also funded in part by New York State and federal incentives, such as
the federal Production Tax Credit.
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Consequently, there is no need to fix what is not broken. The existing capacity market
structure has provided generation capacity where it is most highly valued, using diverse
fuels and meeting a variety of renewable resources and environmental policy goals. This
success has been achieved without resorting to a mandatory forward market such as those
used by PJM and ISO-New England. The current design does not require replacement by a
mandatory forward centralized capacity market.
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New York State Capacity Market Review
I. INTRODUCTION
Beginning in the mid-1990s, New York State’s electricity industry underwent dramatic changes
in the institutional structure of its retail and wholesale markets. Precipitated by the New York
Public Service Commission’s (NYPSC) restructuring order of 1996,2 these changes included
divestiture by the State’s electric utilities of their generating assets, establishment of the New
York Independent System Operator (NYISO) as successor to the New York Power Pool, and
creation of competitive retail markets.3 As a consequence, New York State has engaged in a
long-standing debate about how best to ensure that investment in new generating capacity is
sufficient to: 1) maintain reliability as demand grows and as older, uneconomic generating units
are retired and 2) support workably competitive retail and wholesale electricity markets.
The resource adequacy debate in New York State, which parallels the debate held in other
regions of the country where restructuring of retail and wholesale markets has taken place,
centers on the question of what changes, if any, need to be made to institutional and market
arrangements to induce investments in new generating capacity to ensure resource adequacy.
On the institutional side of the question, suggestions in the mid-2000s that the State once again
play a larger role in resource planning,4 a function it had performed through the New York State
Energy Office prior to restructuring, were implemented in 2009 in the form of the State Energy
Planning Board.5 As it stands now, long-term resource planning is a combination of planning
efforts by the State’s public power utilities with obligations to serve, the NYISO, which manages
the Comprehensive System Planning Process (CSPP), and as part of that conducts the Reliability
Needs Assessment (RNA).6
2
New York Public Service Commission, Competitive Opportunities Regarding Electric Service, No. 94-E-0952,
March 6, 1996.
3
The NYPSC’s stated objective was to “identify regulatory and ratemaking practices that will assist in the transition
to a more competitive electric industry designed to increase efficiency in the provision of electricity while
maintaining safety, environmental, affordability, and service quality goals.” Id. p. 4.
4
Committee on Energy, The Association Of The Bar Of The City Of New York, Electric Regulation In The State Of
New York, February 9, 2007, pp. 25-26, (“Committee on Energy Report”).
5
In 2009, the New York legislature passed Article 6 of the New York State Energy Law (Section 6-108) that
statutorily established the State Energy Planning Board (Board) and requires the Board complete a State Energy
Plan on or before March 15, 2013.
6
As NYISO states: “The Reliability Needs Assessment (RNA) is developed … as its first step in the Comprehensive
System Planning Process (CSPP)…. The RNA is performed to evaluate electric system reliability, for both
transmission security and resource adequacy, over a ten-year study period. If the RNA identifies any violation of
Reliability Criteria for Bulk Power Transmission Facilities (BPTF) the NYISO will report a Reliability Need, quantified
by an amount of compensatory megawatts (MW) and/or megavars (MVAr). In addition, after approval of the RNA,
the NYISO will request market-based and alternative regulated proposals from interested parties to address the
identified Reliability Needs, and designate one or more Responsible Transmission Owners to develop a Regulated
Backstop Solution to address each identified need.”
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On the market side of the question, the debate has focused on the value of replacing the
existing voluntary short-term forward capacity market with a mandatory long-term forward
capacity market that would be similar to those administered by PJM and ISO New England.7
Proponents of this approach believe that investment in merchant plants has been limited by
investors’ reluctance to finance new plants without long-term power purchase agreements
(PPAs) with load-serving entities (LSEs).8 On this view, the introduction of a mandatory longterm forward capacity market would help to bridge the gap between a short-term spot capacity
market and the long-term bilateral capacity market.
The debate’s intensity has varied over time according to the results of the most recent
projections of resource adequacy. Such projections have varied significantly over time going
from critical impending shortages to long-term sufficiency. For example, the NYISO’s initial RNA
in December 2005 suggested that the State’s transmission and generation resources would be
adequate only through 2007.9 The NYISO quickly revised this estimate the very next year in its
Comprehensive Reliability Plan, which projected a reliability need emerging by 2011.10 In
contrast, Con Edison, in a November 2005 assessment, projected a system reliability need by
2012.11 The NYISO’s most recent assessment projects a reliability-related resource adequacy
need no sooner than 2020.12
The inevitable cyclicality associated with generation investment engenders a “boom-bust”
outcome in reliability needs assessment studies that, on the one hand, leads to calls for
institutional and market reforms to incent generation investment, and, on the other hand,
suggests that the existing processes and structures have delivered new generation resources
when and where they were needed. Consequently, the question arises as to just how well New
York State’s existing capacity market structure has performed over the past decade in providing
needed new capacity.
To shed light on the success of the existing structure, this report examines the types and
quantities of investment in generation capacity in New York State since 1999, with a focus on
the motivations for that investment. In particular, it examines the relative extent to which the
market for bilateral contracts and the role of self-owned generation, as supplemented by the
7
The New York State capacity market in this paper refers to utility-owned supply, bilateral contracts between
utilities and merchant plant developers, merchant plants that rely on the New York ISO’s capacity and its other
centrally administered markets for revenues, and renewable resources that may enter bilateral contracts or
operate as pure merchant plants, but are also funded in part by New York State and federal incentives, such as the
federal Production Tax Credit.
8
Committee on Energy Report, p. 12.
9
New York ISO, Comprehensive Reliability Planning Process Draft Reliability Needs Assessment, November 22,
2005.
10
New York ISO, The Comprehensive Reliability Plan for 2005: A Long-term Reliability Assessment of New York’s
Power System, August 22, 2006.
11
Consolidated Edison Company of New York, System Reliability Assurance Study, December 30, 2005.
12
New York ISO, 2012 Reliability Needs Assessment, Draft of August 28, 2012.
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NYISO’s voluntary installed capacity (ICAP) market, have worked together to meet New York’s
resource adequacy requirements over the period 2000 to 2012.
To review the history behind each of the generating units placed in service during this period,
we looked at generators’ applications for certificates of environmental compliance, and at
various other public records.13 Our main findings are as follows:

Over past decades and up to the present, a mixture of bilateral PPAs, merchant plant
investments, utility-owned supply, and renewable resources encouraged by the New
York State Energy Research and Development Authority (NYSERDA) and by federal tax
incentives has provided adequate generation resources to satisfy growing electricity
demand, provide reliable electric power service, and meet environmental public policy
goals.

The voluntary centralized capacity market administered by NYISO has provided a
workable complement to the bilateral market, utility-owned supply, and publicly
supported renewable resources.

The historical evidence of capacity investments over the past twelve years and the
proposed capacity investments over the next four years indicate that New York State’s
present capacity market structure, combined with self-builds, long-term contracts, and
NYSERDA support and federal tax incentives for renewables, has provided sufficient
generation capacity and promises to continue to do so for the foreseeable future.
Consequently, there is no need to fix what is not broken.
The report is organized as follows. Section II provides institutional background on the
framework and the evolution of the responsibility for assuring resource adequacy in New York
State. Section III summarizes New York’s generation investment history over the period 2000 to
2012 as well as planned investment from 2012 to 2016. Section IV provides discussion of the
various factors driving investment in generation in general and in New York in particular.
Section V offers conclusions.
II. BACKGROUND
This section discusses the various institutions that are responsible for determining New York’s
ICAP requirements, the rules established by those institutions, and the history by which those
rules were established.
A. Institutional Framework for Assuring Resource Adequacy
“Resource adequacy” is the ability of an electric system’s generation resources to reliably meet
the aggregate electrical demand, energy, and reserve requirements of customers at all times,
taking into account scheduled and reasonably expected unscheduled outages of system
13
Other public records include news releases about generation development as well as various reports by NYISO,
NYSERDA, New York Power Authority (NYPA), Long Island Power Authority (LIPA), and NYPSC.
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facilities. In the context of this report, “resource adequacy” does not refer to the adequacy of
transmission resources, though the term does encompass consideration of whether the
services provided by generation resources are deliverable to customers given the configuration
of the transmission system.
The institutions that are responsible for assuring resource adequacy in New York State include
the New York State Reliability Council (NYSRC), the Northeast Power Coordinating Council
(NPCC), the North American Electric Reliability Corporation (NERC), NYISO, the NYPSC, and the
Federal Energy Regulatory Commission (FERC). These institutions and the rules and
requirements they establish create significant regulatory and legal forces to ensure resource
adequacy in New York State. Many of these rules and requirements pre-date the establishment
of the NYISO and exist outside of the NYISO’s ICAP market structure. Furthermore, as the
NYSRC manual explains, the NYISO’s reliability role is to facilitate the attainment of those
resource standards established by other institutions:
The New York Independent System Operator… is required to comply with all of
the Reliability Rules. To the extent that Market Participant action is necessary to
implement a Reliability Rule, a requirement for such action is included in the
NYISO procedures, which are binding on all Market Participants.14
Resource adequacy requirements in New York State are driven by the reliability rules
established in accordance with the NYSRC rules and with agreements between the NYSRC and
NYISO. These requirements incorporate the following rules and standards:

NERC Standards;

NPCC Criteria, Guidelines and Procedures;

New York-specific reliability rules; and

local reliability rules.
NPCC criteria may be more specific or stringent than NERC standards and policies, recognizing
regional characteristics or reliability needs. In turn, New York-specific reliability rules may be
more specific or stringent than NERC Standards and NPCC Criteria, recognizing New York
control area (NYCA) system characteristics or reliability needs. Local reliability rules can be even
more stringent than the general New York-specific reliability rules and apply to certain NYCA
zones, recognizing unique local area characteristics or reliability needs.
The specific NYRSC reliability rules governing resource adequacy and affecting generation
investment include:

the Installed Capacity Requirement (ICR), which refers to physical generation capacity;

the Installed Reserve Margin (IRM) requirement, which refers to the relationship
between physical generation capacity and annual peak loads; and
14
NYSRC, Reliability Rules For Planning And Operating the New York State Power System, Version 31, May 11,
2012, p. 4 (Reliability Rules).
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
the Minimum Operating Reserve requirement, which refers to the amount by which the
generation capacity that is available to produce power at a particular time exceeds load
at that time.
The NYSRC is responsible for establishing the annual statewide ICR to ensure adequate resource
capacity. Factors to be considered in the calculation of the ICR include the characteristics of the
loads, uncertainty in the load forecast, outages and deratings of generating units, the effects of
interconnections to other control areas, and transfer capabilities within the NYCA. The annual
statewide ICR is established by implementing reliability rules for providing the corresponding
statewide IRM requirement. The IRM requirement relates to ICR through the following
equation:
ICR = (1+ IRM Requirement) x forecasted NYCA Peak Load
where the IRM Requirement is expressed as a percentage of peak load. To meet the annual
statewide ICR established by the NYSRC, the NYISO establishes locational ICAP requirements
that recognize internal and external transmission constraints. The NYCA IRM is defined by an
acceptable Loss of Load Expectation of one day in ten years.15
With respect to operating reserves, the NYSRC rule is more specific than the NERC standard in
that it specifies scheduled outage requirements and requires procedures for maintaining
minimum operating reserve levels. The NYSRC rule is also more specific than the corresponding
NERC and NPCC rules in specifying minimum 10-minute and 30-minute reserve requirements
and the permissible mix between synchronized and non-synchronized reserves.
Under these rules, LSEs must demonstrate that they meet capacity requirements including the
IRM.16 In addition, LSEs must comply with all reliability rules or face penalties assessed by the
NYISO.17
In summary, resource adequacy in New York is ensured by Reliability Rules that are created by
institutions other than the NYISO.
B. Evolution of Institutional Responsibility for Resource Adequacy
In the wake of the wide-scale Northeast blackout of 1965, New York’s electric utilities
established a state-wide, wholesale power coordinating institution, the New York Power Pool
(NYPP). The NYPP operated for over thirty years until it was superseded by NYISO, playing a
central role in helping the electric utilities in New York State to operate their systems
cooperatively for the purpose of assuring reliable, economic electric service for electricity
customers in the state. The revenue to support the cost of operating the NYPP was collected
through consumers’ electric rates.
15
Refer to NYSRC, Reliability Rules, p. 13.
16
New York ISO, Installed Capacity Manual, March 2012, Chapter 3.
17
New York ISO, New York ISO Agreement, Article 16: Penalties for Non-Performance, December 6, 2011, p. 80.
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New York created NYPP as a “tight power pool” responsible for grid management and economic
dispatch of the power plants in the state. To serve their own requirements, individual utilities
owned and entered into contractual arrangements for generating resources and transmission
systems, and they coordinated (or “pooled”) their operations for their mutual benefit and the
benefit of their customers.
NYPP managed many of the reliability functions that would typically be performed by a control
area operator.18 In addition, it provided economic benefits by performing certain functions—
committing and dispatching generation—to minimize the variable cost of producing power for
the combined system by arranging efficient trades among the utilities. For this wholesale power
production function, NYPP provided what amounts to a centrally administered market for
arranging short-term trades among the utilities, whereby the trades were priced (albeit
inefficiently) on the basis of a “split-savings” rule.19
In 1999, NYISO was authorized by FERC to be the successor to NYPP. NYISO performs the
functions that were performed by NYPP, though it performs many of those functions
differently. For example, NYISO uses different dispatch models than did NYPP and
simultaneously optimizes the provision of energy and operating reserve service. In addition,
NYISO performs functions that NYPP did not perform. For example, NYISO operates centralized
markets for energy and operating reserves, and sets the prices for these services on a nodal
basis for generators and a zonal basis for loads.20
III. NEW YORK GENERATION INVESTMENT HISTORY
This section presents a history of the investment in new generation in New York State over the
past twelve years, since the NYISO commenced operations in November 1999 and examines the
proposed investment over the coming four years.
18
These functions typically are as follows: real-time balancing of electric system supply and demand, maintaining
voltages, monitoring contingencies, managing operating reserves, and committing and dispatching generation.
19
Although the dispatch was efficient, the inefficient pricing eventually led, in the early 1990s, to a breakdown of
NYPP’s unified dispatch. This occurred because NYPP participants were allowed to trade power with entities
outside of New York at market prices. In the wake of the passage of the Energy Policy Act of 1992, electricity
markets opened up so that NYPP participants could find better market-based power prices outside of New York
than the split-savings prices that they could obtain within NYPP. The creation of NYISO was partly motivated by the
need for a better pricing system within New York.
20
Because generators are very price-sensitive, a small change in price can induce a generator to change its output
from minimum to maximum, or vice versa. Therefore, it is important that generators get accurate nodal prices.
Because loads are much less price-sensitive and most loads do not see wholesale prices at all, efficiency is barely
compromised by charging loads less accurate zonal prices. Charging loads on a zonal basis is also consistent with
the traditional and still prevalent notion that it would be unfair to charge high locational prices to those customers
who happened to have the misfortune of being located at a high-price node.
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A. Generation Investment, 2000 to 2012
Table 1 summarizes the generation capacity placed in service in New York over the period
January 2000 through April 2012, by year and zone. It shows that just over half of the
investment during these dozen years occurred in the three years 2004–2006. It also shows that
just over half of the investments occurred by 2005, and that just under half of the investments
occurred after 2005.
Table 1 also indicates that, over the twelve-year period, 82% of generation investment in New
York State was located in Zone F (Albany area, also called Capital Zone), Zone J (New York City),
and Zone K (Long Island). The bottom of the table, however, shows a remarkable difference
between the two subperiods: whereas 97% of investment was in Zones F, J, and K during the
2000–2005 period, only 68% of investment was in those zones after 2005.
Table 2 presents information for the same period by generation technology and zone. It shows
that nearly all of the generation investments were in combined cycle (65%), combustion turbine
(15%), and wind (16%) technologies. Table 3 shows the investments by technology broken
down between the periods through 2005 and after 2005. This table indicates that the
investment in combustion turbines in the years through 2005, which was motivated almost
entirely by reliability concerns, shifted entirely toward wind power in the years after 2005,
which was motivated by a combination of federal tax policies favorable to wind resources, the
New York State renewable portfolio standard and state-based encouragement through
NYSERDA.
According to NYISO’s Power Trends report issued in 2011:
Since 2000, more than 8,600 megawatts of new generation have been built by
private power producers and public authorities. Among the new power plants
were numerous merchant projects, shifting the risk of building new power
supplies from rate-paying consumers to investors.
Over 80 percent of the new generation has been sited in New York City, on Long
Island and in the Hudson Valley, the regions of New York State where demand is
greatest… Much of the new generation developed in upstate regions is powered
by wind; consequently, it was sited where wind resources are most available.
Increased generation in upstate regions also resulted from upgrades in existing
nuclear and hydropower plants. Almost all of the conventional new generation
has been added near the load centers where power is needed the most.21
The NYISO’s own Power Trends report thus tells a story of the success of what the State has
managed to accomplish through a capacity market consisting of utility self-supply, long-term
bilateral contracts between load serving entities and merchant plants, merchant plants that rely
on the NYISO’s centralized markets for revenue, and State environmental policies supported by
the State (NYSERDA) and federal tax policies.
21
NYISO, Power Trends 2011: Energizing New York’s Legacy of Leadership, undated, p. 12.
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Table 1
New York State Generation Capacity Investment by Zone and Year,
January 2000–April 2012 (MW)22
Year
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
Total
2000-2005
2006-2012
22
A
B
Zone23
D
E
12
C
15
211
18
517
392
456
2,925
3,180
1,401
Total
18
813
581
120
1,694
1,447
1,458
161
760
502
713
817
15
9,100
53
158
7
11
84
433
392
14
442
2,218
707
1,304
1,876
995
407
4,674
4,426
7
6
47
F
78
J
K
680
50
532
114
121
178
2
6
6
26
101
6
5
10
3
257
113
9
51
392
231
125
5
5
2
74
1,323
895
5
250
374
1,216
9
693
375
660
32
NYISO 2012 Gold Book, pp. 30-49, and CA Energy Consulting analysis.
23
NYISO Zones are: A – West, B – Genesee, C – Central, D – North, E – Mohawk Valley, F – Capital, G – Hudson
Valley, H – Millwood, I – Dunwoodie, J – New York City, K – Long Island.
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Table 2
New York State Generation Capacity Investment by Generation Technology and Zone,
January 2000–April 2012 (MW)24
Zone
Technology
Combined Cycle
Cogeneration
Energy Storage
Combustion Turbine
Conventional Hydro
Internal Combustion
Photo Voltaic
Steam Turbine
Wind Turbine
Total
A
CC
CG
ES
GT
HY
IC
PV
ST
WT
B
C
D
E
F
2,886
J
2,500
K
553
500
817
3
47
28
11
8
48
2
15
20
6
2
8
11
8
32
180
136
211
7
18
445
517
386
392
442
456
2,925
3,180
1,401
Total
5,939
3
28
1,412
15
77
32
180
1,414
9,100
Table 3
New York State Generation Capacity Investment by Generation Technology and Period
(MW)25
Unit Type
Combined Cycle
Cogeneration
Energy Storage
Combustion Turbine
Conventional Hydro
Internal Combustion
Photo Voltaic
Steam Turbine
Wind Turbine
Total
CC
CG
ES
GT
HY
IC
PV
ST
WT
2000–2005 2006–2012
3,018
2,921
3
28
1,412
4
11
12
65
32
180
48
1,366
4,674
4,426
24
Source: NYISO 2012 Gold Book, pp. 30–49, and CA Energy Consulting analysis.
25
Id.
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Total
5,939
3
28
1,412
15
77
32
180
1,414
9,100
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B. Generation Investment, 2000 to 2005
As Figure 1 shows, of the 4,674 MW of generation capacity placed in service between 2000 and
2005, about 41% was either utility-owned capacity or under long-term PPAs with utilities.
Another 58% of the capacity was placed in service as merchant plants relying on the NYISO’s
centralized markets for revenues. About 1% received public support but also could be classified
under merchant plant.
Figure 1
Capacity Addition Shares by Transaction Type, January 2000–December 2005, MW26
Public Support
1%
Utility/Bilateral
41%
Merchant
58%
Utility/Bilateral
Merchant
Public Support
Given the time that must elapse between planning and initially operating a generator, most (if
not all) of the generation investment during this period was planned for and initiated under the
NYPP and prior to the creation of the NYISO. For example, consider the histories of two
particular merchant plants, both located in Zone F, that together accounted for nearly 39% of
26
NYISO Gold Book and CA Energy Consulting analysis. Transaction types are: “Public Support” = long-term
contract sponsored by NYSERDA along with federal tax incentives; “Merchant” = capacity developed by
independent power producer relying on NYISO’s markets for revenues; “Utility/Bilateral” = utility-owned capacity
or bilateral long-term PPA between utility and merchant plant developer.
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the capacity installed during the period 2000–2005. The first plant, the Athens Generating
Station (owned by Athens Generating Company LLC, a subsidiary of U.S. Generating Company
(USGen)), began commercial operation in 2004 and consists of three combined cycle units
totaling 1,080 MW. The second plant, the Bethlehem Energy Center (PSEG Energy Resource &
Trade LLC), began commercial operation in 2005 and consists of a 750 MW combined cycle unit.
Both of these plants had their planning origins in the NYPP era.
USGen filed a pre-application for siting of the plant with the New York State Board on Electric
Generation Siting and the Environment (Siting Board) in September 1997, well before the NYISO
came into being. It was granted a permit by the Siting Board on June 15, 2000, barely six
months after the launch of the NYISO.27 At the time, USGen conducted a benefit-cost study of
the plant for Greene County where the plant would be located. The study provides the
motivations for the development of the plant as it states:
As a non-utility generator of electric power, USGen would be selling electricity
on the open market with prices subject to competitive pressures now being
unleashed through a complex deregulation of the power industry in New York
State.28
The statement reveals that USGen was clearly motivated by the prospect of selling power in the
wholesale and retail markets that had been restructured in New York, but the statement does
not mention the prospect of selling capacity in a short-term capacity market. Certainly, it was
not motivated by the prospect of selling capacity into NYISO’s centralized capacity market, as
neither NYISO nor a centralized capacity market existed at that time.
The Bethlehem Energy Center (BEC) story is more complicated but also has its origins in the preNYISO period. In November 1998, before the NYISO took over, Niagara Mohawk Power
Corporation (NIMO) filed an application with the Siting Board for a Certificate of Environmental
Compatibility and Public Need (Certificate) to construct and operate a 750 MW combined-cycle
electric generation station on a 186-acre site where the 400 MW Albany Steam Station was
already located. In May 2000, NIMO sold 84 acres and the Albany Steam Station to PSEG Power
LLC. Subsequently, on July 2, 2001, PSEG Power New York Inc. supplemented the November
1998 application and thus resumed the process to redevelop the site with a combustion
turbine. In February 2002, the Siting Board determined that the PSEG application complied with
27
State of New York, Board on Electric Generation Siting and the Environment, Case 97-F-1563, Application by
Athens Generating Company, L.P. for a Certificate of Environmental Compatibility and Public Need to Construct
and Operate a 1,080 Megawatt Natural Gas-fired Combined Cycle Combustion Turbine Generating Facility, in the
Town of Athens, Greene County, Opinion And Order Granting Certificate Of Environmental Compatibility And Public
Need, June 15, 2000.
28
Center for Governmental Research Inc., Athens Generating Project: An Assessment Of The Project’s Value To The
Community and the Owner, prepared for Athens, NY Community, funded by Central Hudson Gas & Electric
Corporation, June 1998, p. i.
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the requirements of Public Service Law.29 Completion of the plant was delayed, however,
because PSEG Power experienced financial difficulties; so the plant did not achieve commercial
status until 2005. In 2006, the NYISO’s capacity market was reasonably well developed and
PSEG had this to say in describing the attractiveness of the BEC location in New York:
Perhaps the most attractive characteristic of BEC’s site is its location. It is not
only within NYISO’s footprint (the robust New York City market is just 150 miles
downriver) but also near a small load pocket that includes Albany. Significantly,
that load pocket requires considerable reactive support during the summer,
when everyone uses their air conditioners, and winter, when they run their
electric heaters. Providing that support by selling ancillary services to NYISO was
an opportunity that made completing BEC even more attractive to PSEG, which
— like any utility — is always on the lookout for sources of revenue other than
capacity payments. The old plant’s switchyard connections allow the plant to
pump reactive power directly into Albany.30
The plant’s attractiveness centers on its location, which highlights how critical the plant is for
providing reliability service (reactive support and other ancillary services) to the grid. It is likely
that the retirement of the original Albany Steam Station meant that some plant had to be built
to replace it in order to maintain grid reliability. This aspect was also emphasized by remarks of
the then-chairman of the New York Public Service Commission:
The Bethlehem Energy Center exemplifies how we can meet our growing
demand for energy in an efficient and environmentally responsible manner, and I
want to thank PSEG for making this investment in New York… Investments in
new generating capacity are critical to maintaining the high reliability of the
state’s power grid, particularly during these summer months when the use of
electricity spikes.31
Even though both the Athens and the Bethlehem plants are run as merchant plants today and
depend on the short-term ICAP market for a portion of their revenues, their origins lie in the
period before the NYISO began operations and well before the current ICAP market came into
being.
Between 2001 and 2005, LIPA entered into PPAs for 719 MW of capacity for reasons other than
the prospect of making money in or avoiding payments to NYISO’s capacity market. Very
29
New York State Board On Electric Generation Siting And The Environment, C 97-F-2162 - Application by PSEG
Power New York, Inc. for a Certificate of Environmental Compatibility and Public Need to Construct and Operate a
750 Megawatt Natural Gas-Fired Combined Cycle, Combustion Turbine Generating Facility in the Town of
Bethlehem, Albany County. Opinion And Order Granting A Certificate Of Environmental Compatibility And Public
Need Subject To Conditions, February 28, 2002.
30
John Javetski, Bethlehem Energy Center, Glenmont, New York, August 15, 2006,
powermag.com/print/issues/cover_stories/Bethlehem-Energy-Center-Glenmont-New-York_457.html
31
PSEG Power Completes 750-MW Bethlehem Energy Center,
http://www.energyvortex.com/pages/headlinedetails.cfm?id=1941.
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simply, LIPA needed the capacity to satisfy its obligation to serve load as well as satisfy
reliability requirements. As LIPA stated, it “has moved aggressively to facilitate the upgrading
and addition of generation on Long Island as one of the solutions to meet growing customer
demand.”32 Table 4 shows that LIPA’s load obligation (i.e., it had to meet the locational ICAP
requirement) led it to support the building of a dozen generators in New York.
Table 4
Long Island Power Authority, Generation Capacity Additions, 2001–200533
InService
Date
2002
2002
2002
2002
2002
2002
2003
2003
2004
2004
2005
2005
Total
Developer
Calpine
FPL Energy
National Grid
National Grid
PPL Global
PPL Global
FPL Energy
Hawkeye
Equus
Village of Freeport
Calpine
Pinelawn
Facility Name
Bethpage
Baywater
Glenwood Landing
Port Jefferson
Brentwood
Shoreham
Jamaica Bay
Greenport
Freeport
Freeport
Bethpage
West Babylon
Summer
Rating
(MW)
48
50
80
79
78
76
52
52
48
4934
76
78
719
In 2001, NYPA placed in service ten gas-fired combustion turbine units in New York City and one
unit in Long Island (Brentwood) for a combined total of 550 MW.35 None of this capacity was
brought into service through incentives provided by the NYISO’s capacity market. According to
NYPA it:
…had launched a crash program in late August 2000 to install these PowerNow!
plants in response to warnings from officials in the public and private sectors
32
Long Island Power Authority, Electric Resource Plan 2010 – 2020, February 2010, Appendix C, Energy Primer,
p. 10.
33
Long Island Power Authority, Electric Resource Plan 2010 – 2020, February 2010, Appendix C, Energy Primer,
Exhibit 2-5, p. 9, supplemented by review of the NYISO 2012 Gold Book, Table III-2.
34
Strictly speaking, the Village of Freeport built the Freeport facility to serve its own load, and sold 10 MW to LIPA
under a PPA.
35
As listed in 2012 Gold Book.
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that the New York City metropolitan area could face power shortages in the
summer of 2001. Similar warnings were repeated throughout the 10 months it
took to obtain, site, design and install the units—a process that normally would
require more than two years.36
NYPA’s investment in generation in the early 2000s was motivated to meet its load obligations
and satisfy reliability requirements in New York City, rather than by the prospect of revenues
earned in the NYISO’s administered markets.
In summary, of the 4,674 MW of generation capacity placed into service between 2000 and
2005, about 41% was either utility-owned supply or under long-term bilateral contract, 58%
was merchant plant, and about 1% was renewable power, some of which was receiving public
support from and under long-term contracts with NYSERDA. The 41% was built to meet load
obligations in conformance with reliability requirements, not in reliance on the NYISO
centralized markets. Most of the 58% was initiated to satisfy increasing load demands and to
sell into the broadest set of markets then available, including the residual, short-term capacity
market. Thus, the majority of the capacity placed in service in this period was built for reasons
having little or nothing to do with a possible future mandatory forward capacity market.
C. Generation Investment, 2006 to 2012
As Table 3 shows, 4,426 MW of generation capacity was placed in service over the 2006 to 2012
time period. Figure 2 shows the percentage shares of capacity additions by technology type.
Natural gas-fired combined cycle and co-generation units, at 66% of the total, continue to
prevail because of their relatively low capital costs, their operational efficiency, and low natural
gas prices. Wind turbines make up the majority of the remaining capacity additions (1,414
MW), driven by a combination of RPS, federal renewable resource tax incentives such as the
production tax credit, and with a significant portion of that wind generation (1,003 MW, 73%)
also encouraged by NYSERDA under long-term contracts.
36
http://www.nypa.gov/facilities/powernow.htm
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Figure 2
Capacity Addition Shares by Technology Type, January 2006–April 201237
IC
PV
1.47% 0.71%
ES
HY
CG
0.63% 0.24% 0.07%
WT
30.87%
CC
66.00%
CC
WT
IC
PV
ES
HY
CG
Figure 3 summarizes the shares by transaction type over the period. The renewable resources
that have been supported by the federal tax incentives and by NYSERDA (labeled “Public
Support”) under long-term (mostly 10-year) contracts constitute 25% of the total capacity
additions listed in the NYISO’s 2012 Gold Book.38 About 44% of the capacity placed in service
during this period was supported by a long-term PPA between a utility (i.e., an LSE) and a
merchant plant developer, labeled “Utility/Bilateral.”39 The 31% of capacity additions labeled
“Merchant” have been placed in service by independent power producers that depend entirely
on the NYISO’s centrally administered markets for revenues.
37
NYISO 2012 Gold Book, pp. 30-49, and CA Energy Consulting analysis. CC = combined cycle, WT = wind turbine, IC
= internal combustion, PV = photo voltaic, ES = energy storage, HY = hydro, CG = cogeneration.
38
NYSERDA, 2011 RPS Performance Report, Appendix A – Renewable Portfolio Standard, Main Tier Contracts as of
December 31, 2011, pp. A-1–A-2.
39
During this period, there were no capacity additions that were directly owned by utilities.
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Figure 3
Capacity Addition Shares by Transaction Type, January 2006–April 2012, MW40
Public Support
25%
Utility/Bilateral
44%
Merchant
31%
Utility/Bilateral
Merchant
Public Support
Consequently, a combination of bilateral market long-term PPAs, merchant plants, and publicly
funded renewables (including support through federal tax credits) have been responsible for
securing the generation resources necessary to ensure safe, reliable, efficient, and
environmentally conscious capacity for New York State during this period. The voluntary NYISO
residual ICAP market has been a useful supplement to these main means by which New York
obtains generation capacity.
D. Planned Generation Additions
The New York State market continues to stimulate investment in economic generation capacity
in diverse locations, particularly where it is valued most highly. The NYISO’s 2012 Gold Book lists
40
NYISO Gold Book and CA Energy Consulting analysis. Transaction types are: “Public Support” = long-term
contract sponsored by NYSERDA along with federal tax incentives; “Merchant” = capacity developed by
independent power producer relying on NYISO’s centralized markets for revenues; “Utility/Bilateral” = utilityowned capacity or bilateral long-term PPA between utility and merchant plant developer.
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4,266 MW of proposed generation additions by class year and unit type for the period from
April 2012 through June 2016.41
Figure 4 summarizes the shares by unit type. A significant share (30%) of the proposed
generation investment consists of wind farms in upper and western New York. In keeping with
their strong economic advantages, combined cycle units constitute the largest share (57%) of
the proposed capacity additions.
Figure 4
Proposed Capacity Addition Shares by Technology Type, 2012–201642
Hydro
0%
Solid
Waste
1%
Landfill Gas
0%
Dual Fuel
12%
Wind Turbines
30%
Combined Cycle
57%
Wind Turbines
Combined Cycle
Dual Fuel
Hydro
Solid Waste
Landfill Gas
Figure 5 summarizes proposed capacity additions by transaction type (Utility/Bilateral,
Merchant, Public Support, and Uncertain). The market category labeled “Uncertain” in Figure 5
accounts for several wind farms whose disposition depends on a number of key factors,
41
The period is defined in terms of the expected in-service date of the proposed plant.
42
NYISO 2012 Gold Book, p. 59 and CA Energy Consulting analysis. Proposed re-ratings, amounting to a total
increment of 214 MW, have not been included in this chart. CC = combined cycle, WT = wind turbine, IC = internal
combustion, PV = photo voltaic, ES = energy storage, HY = hydro, GT = combustion turbine, CG = cogeneration, ST =
steam turbine (fossil).
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including securing investors and long-term bilateral PPAs, as well as overcoming local
community resistance to their further expansion. These projects are currently on hold, and
therefore categorized as “Uncertain.”
Figure 5
Proposed Generation Additions by Transaction Shares, 2012–201643
Uncertain
4%
Public support
12%
Merchant
16%
Utility/Bilateral
68%
Utility/Bilateral
Merchant
Public support
Uncertain
Developers of two planned combined cycle projects, Cricket Valley Energy Center’s (CVE) 1000
MW44 project and CPV Valley Energy Center’s (CPV Valley) 650 MW45 project, have both
indicated the significance of obtaining long-term PPAs in order that they may secure financing
43
NYISO, 2012 Gold Book, p. 59; and CA Energy Consulting analysis. Transaction types are: “Public Support” = longterm contract sponsored by NYSERDA; “Merchant” = capacity developed by independent power producer relying
on NYISO’s centralized markets for revenues; “Utility/Bilateral” = utility owned capacity or bilateral long-term PPA
between utility and merchant plant developer, “Uncertain” = capacity additions whose transactional relationship
could not be determined from information that CA Energy Consulting was able to obtain.
44
Listed at 1,136 MW nameplate capacity in the 2012 Gold Book.
45
Listed at 691.6 MW nameplate capacity in the 2012 Gold Book.
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for project completion. In response to requests for information from the New York Energy
Highway Task Force, Cricket Valley had this to say about long-term contracts:
Obtaining a long-term Power Purchase Agreement (PPA), or equivalent
contractual off-take agreement, from an “investment-grade” counterparty will
be an essential element for the CVE Project to be financed and constructed. A
PPA will ensure a stable cash flow to the project, which will reduce risk and
provide the most attractive economic benefits. CVE believes that the State of
New York can facilitate such an agreement, and in turn accomplish the goals of
the Energy Highways Initiative, through the creation of a state-sponsored
Request for Proposals (RFP).46
In order to minimize the Project’s exposure to market risk and provide stable
pricing, CVE intends to negotiate long-term off-take agreements for the entire
output of the Facility. Ongoing discussions with potential long-term
counterparties indicate that future revenue streams for installed capacity (ICAP)
in New York are somewhat speculative and, therefore, there is a great deal of
uncertainty over the future of this important revenue source. Obtaining a longterm PPA from an investment-grade counterparty (e.g., State or publicly-owned
electric utilities or other investment grade counterparties) will be an essential
element to reduce pricing and uncertainty for the Project, its equity investors,
and debt providers.47
CPV Valley echoed CVE’s statements in its own response to a request for information from the
New York Energy Highway Task Force:
CPV Valley’s finance plan addresses the Project’s three distinct periods of
activity: development, construction, and operations. During development, CPV
Valley’s sponsors will contribute the required equity to fund 100% of the capital
needs of the Project. Raising debt financing for the CPV Valley Energy Center is
predicated on a solution beyond that currently offered in the NYISO market. CPV
Valley is flexible and willing to work with the state of New York in developing a
structure that provides the greatest value to the New York ratepayers. However,
in order to effectively raise the private capital to start construction of the CPV
Valley Energy Center, CPV Valley would require some form of surety of future
revenues in the form of a long-term contract.48
46
Cricket Valley Energy, LLC, Response of Cricket Valley Energy to Request for Information from the New York
Energy Highway Task Force, May 12, 2012, p. 3, (Cricket Valley Response).
47
Id., p. 12.
48
CPV Valley Energy Center, LLC, Response of CPV Valley Energy to Request for Information from the New York
Energy Highway Task Force, undated, p. 8.
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NRG Energy, developer of the four-unit, 1,000 MW49 Astoria Repowering Project, also
emphasized the value of long-term contracts to ensure financing when it stated:
The following table summarizes the key financing terms which NRG believes,
based on its recent experience successfully obtaining project financing and its
ongoing consultations with leading financial institutions, could be available to
the project, assuming commencement of financing negotiations in 2012
following execution of a long-term, financeable contract and other material
project contracts.50
Combined cycle projects are not alone in looking to the bilateral market to secure financing.
Wind project developers have also signaled the importance of long-term contracts to enable
completion of renewable resource projects. For example, BP Wind Energy, developer of the 285
MW Cape Vincent Wind Farm, states:
Wind projects can benefit greatly from the certainty provided by a long term
power purchase agreement. This helps with securing a future revenue stream
that can then be used to help with financing the project. Given the purchasing
power of the public authorities in New York, we look forward to seeing a
stronger willingness by such entities to enter into 20 year power purchase
agreements.51
BP Wind Energy’s preferred source of project revenue is to enter into a longterm power purchase agreement with a credit worthy counterparty; however,
other sources of revenue which will allow the Project to be financed will also be
considered (e.g. a combination of a long-term renewable energy credit (REC)
contract from NYSERDA and an energy hedge).52
A significant proportion of the proposed combined cycle units are replacing older, less efficient
units; so the net addition to capacity will be less than the 4,266 MW. Nonetheless, the evidence
from the proposed capacity additions strongly reinforces the historical record that New York
State’s capacity market, as presently configured, is working to reliably meet load growth and
fulfill environmental public policy goals.
49
The 2012 Gold Book lists only three units at a total of 580 MW nameplate capacity. The fourth unit is not listed
in the Gold Book because long-term contracts have not been secured.
50
NRG Inc., Response of NRG Inc. to Request for Information from New York Energy Highway, May 30, 2012, p. 15.
The table referred to has been omitted.
51
BP Wind Energy NA Inc., Response of BP Wind Energy to Request for Information from New York Energy Highway,
May 30, 2012, p. 5.
52
Id., p. 7.
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E. Fuel Diversity
Table 2 and Figure 6 show the diversity of generation that has been installed over the past
twelve years. Combined cycle units have provided the lion’s share of new generation capacity
because of their relatively low cost, an advantage that has become greater as natural gas prices
have dropped dramatically. Wind power has ranked a distant second, spurred by New York’s
RPS, support from NYSERDA and federal tax incentives. Gas-fired combustion turbines have
ranked a close third. Other technologies have made only a very small contribution.
Figure 6
New York State Capacity Additions by Technology Shares, January 2000–April 201253
CG
0.04%
HY
0.16%
ES
PV
0.35% 0.31%
ST
1.98%
GT
15.51%
IC
0.85%
WT
15.54%
CC
65.27%
CC
WT
IC
PV
ES
HY
GT
CG
ST
In spite of the preponderance of gas-fired generation additions over the past twelve years, New
York has diverse fuel sources. The NYISO remarked on the achieved fuel diversity in its Power
Trends 2011 report:
53
NYISO Gold Book and CA Energy Consulting analysis. CC = combined cycle, WT = wind turbine, IC = internal
combustion, PV = photo voltaic, ES = energy storage, HY = hydro, GT = combustion turbine, CG = cogeneration, ST =
steam turbine (fossil).
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From a statewide perspective, the mix of fuels used to generate electricity in
New York State is relatively diverse and balanced among hydropower, nuclear,
coal, natural gas, and oil. However, fossil-fueled generation predominates in the
high-demand downstate regions of New York due to stringent environmental
requirements in that region. New York State has adopted energy policies aimed
to promote the growth of power supplies from clean and renewable resources.
Progress is being made toward expanding “green power,” such as wind and solar
energy, and increasing energy efficiency and demand-side resources.54
The combination of utility-owned supply, bilateral contracts, NYSERDA grants and federal tax
incentives for renewables, and the NYISO’s voluntary ICAP market have worked to deliver
diversity where it has been most economical. For example, substantial amounts of wind
capacity were developed following 2004 and, as illustrated by Figure 7, most of it in the western
and upstate portions of New York where wind conditions are the most favorable.
54
NYISO, Power Trends 2011: Energizing New York’s Legacy of Leadership, undated, p. 6.
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Figure 7
New York State Wind Power Projects—May 201255
F. Geographic Dispersion: “Where It’s Needed Most”
There is evidence that the combination of the bilateral market, owned-supply, and the
voluntary NYISO ICAP market has successfully delivered resource adequacy where it is needed
most. Figure 8 shows the geographic dispersion of capacity investment over the period January
2000 to April 2012 by zone. The zones that have perennially been in greatest need of capacity
are the densely populated zones J and K (New York City and Long Island); and these have been
two of the three zones that have received the most capacity investment.
55
New York State Department of Environmental Conservation, http://www.dec.ny.gov/energy/40966.html. There
are some relatively small differences between the nameplate capacities of some wind projects listed in the 2012
Gold Book and those same projects shown in the map. The 2012 Gold Book lists a total of 1,414 MW installed
nameplate capacity compared to the 1,407 MW shown in the figure. The figure is used here to illustrate the
distribution of wind projects throughout the state, not as a data source.
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Figure 8
New York State Installed Capacity Investment by Zone, January 2000–April 201256
The concentration of generation in Zone F may be explained by the fact that it is below the
Central East transmission constraint dividing upstate and downstate and has convenient access
to natural gas pipelines and transmission lines.
G. Reliability
A combination of utility-owned capacity, bilateral contracts, NYSERDA-stimulated renewables,
and merchant plant development has delivered resources adequate for keeping pace with both
peak demand and reserve margin requirements. This success is evident in the 2010 Reliability
Needs Assessment (RNA), which is part of NYISO’s Comprehensive System Planning Process.57
56
NYISO Zone Map and CA Energy Consulting analysis. The value 3,180 MW applies to capacity additions in Zone J
only. The 2012 Gold Book shows no capacity additions in Zones G, H, and I during the period 2000 to 2012.
57
NYISO, 2010 Reliability Needs Assessment, Final Report, September 2010, p. 56 ff.
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The RNA includes a scenario analyses that found that reliability violations could occur only
under limited circumstances:

if the Indian Point plant was retired at the end of its license expiration date;

if government initiatives to improve air quality result in retirements that are greater
than specific expectations; or

if the economic recovery through 2019 is stronger than expected.
Despite the challenges noted in its scenario analyses, NYISO concluded that there are no unmet
“Reliability Needs” forecast at this time, assuming that transmission and generation facilities
stay in service from 2011-2020. NYISO listed two primary factors that have favorable
implications for reliability over this intermediate term:

Generation additions are forthcoming with two new proposed generating plants totaling
1,060 MW of new capacity in Zone J alone; and

Electricity demand growth will be moderated by the continuing impacts of the 20082009 financial crisis, Statewide Energy Efficiency Programs, and increased registration of
Special Case Resources that reduce power usage.
NYISO has therefore stated it will not issue a request for additional reliability solutions and will
continue to evaluate the progress of the market-based solutions.58 NYISO will thus continue to
monitor whether the resource adequacy and security needs for the New York power grid are
continuing to be met.
NYISO’s Power Trends 2011 paints a positive picture for reliability from the perspective of
resource adequacy. NYISO stated:
The immediate outlook for New York’s electric system is positive. As a result of
developments that have contributed to a more reliable system over the past
decade, as well as planned additions in the near future, the adequacy of power
resources is not an imminent concern. 59
In summing up the resource adequacy assessment, NYISO states:
The NYISO’s latest assessment of the electric system’s reliability needs reports
that New York has sufficient resources (generation, transmission and demand
response) to reliably serve load through 2020. In 2011, resources are anticipated
to exceed peak demand by more than 10,000 megawatts, and exceed reserve
requirements by more than 5,000 megawatts.60
58
Id., p. 9.
59
NYISO, Power Trends 2011, undated, p. 6.
60
Id., p. 15.
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Figure 9, taken from Power Trends 2011, shows the adequacy of generation resources to
serve New York State load for the summer 2011. In-state resources alone were found to
be sufficient to serve forecast peak load plus the installed reserve margin.
Figure 9
New York State Resource Capability: Summer 201161
According to the NYISO, the existing and planned resources (including demand response and
Special Case Resources) are expected to be adequate to serve peak load and satisfy reliability
criteria into the next decade:
The total resource capability in the NYCA for 2012 is 43,686 MW, an increase of
1,528 MW due to the net impact of additions, retirements and changes in unit
ratings… This includes existing NYCA capacity and resources (including demand
response), all resource changes, and known long-term purchases and sales with
neighboring Control Areas. It is greater than 116% of the 2012 projected peak
load of 33,295 MW. The total resource capability is also greater than 116% of
projected peak loads for all succeeding years through 2022.62
61
Id., p. 16.
62
NYISO 2012 Gold Book, p. 7.
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IV. DRIVERS OF GENERATION INVESTMENT IN NEW YORK
Generation investment in New York is driven by both non-market standards and by market
incentives.
A. Non-Market Standards
Generators and LSEs must respond to non-market standards, all of which affect market prices
and market incentives. These include obligations to serve, reliability standards, renewable
portfolio standards, and environmental regulations.
1. Obligations to Serve
Utility franchise arrangements traditionally require that utilities serve all customers who desire
electric power service in their franchise territories. This includes the 51 municipal and
cooperative distribution utilities in New York State. With industry restructuring, New York’s
investor-owned utilities have a continuing obligation to serve as providers-of-last-resort for
those customers who do not choose or cannot choose alternative suppliers. The NYPSC
specifically requires regulated franchise utilities to serve as providers-of-last-resort for
residential and small commercial and industrial customers.63 The practices of the utilities in
meeting that obligation (as LSEs) vary according to the composition of their supply portfolio
(e.g., the shares occupied by legacy contracts, spot market purchases, and supply obtained
through competitive procurement auctions). Obligations to serve growing electricity demand
and the ongoing procurement practices of the utilities create demand for additional generation
capacity.
2. Reliability Standards
To meet the reliability standards of NYSRC, NPCC, and NERC, it is generally (but not always)
necessary to build generation capacity. This serves as a motive for LSEs to secure sufficient
capacity to meet reserve and planning reserve requirements, thereby creating demand for new
generation. The examples of NYPA and LIPA to build generation in zones J and K in response to
the locational ICAP requirements were discussed above.
Another example was ConEd’s repowering of the East River generating station shows how
reliability standards drive investment in generation, regardless of NYISO’s ICAP market. In 2000,
well before NYISO’s centralized ICAP market was put in place, ConEd announced plans for
replacing the steam production capacity of the company’s 100-year old Waterside generating
station with new capacity at its East River station. Subsequently, the Waterside station was
closed in 2005 and sold along with other nearby ConEd properties. The focus of the repowering
plan was to replace the Waterside station and enhance and improve ConEd’s ability to reliably
and economically supply steam by installing a state-of-the-art steam generation facility in an
unused portion of the East River generating station. The cogeneration technology thus installed
63
New York PSC, Opinion No. 96-12, Case 94-E-0952, May 20, 1996.
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enabled ConEd to generate electricity in addition to the plan’s primary purpose of providing
steam. This project added 360 MW to installed capacity in the NYCA in 2005 that had little or
nothing to do with NYISO’s ICAP market.
3. Renewable Portfolio Standards
New York, through regulations adopted by the NYPSC and quite independent of the NYISO’s
capacity market, first enacted its renewable portfolio standard (RPS) in 2004, with the goal of
increasing the amount of renewable electricity used by consumers to 25% by 2013.64 In 2010,
following a comprehensive mid-course review, the Commission issued an Order that expanded
the RPS target from 25% to 30% and extended the terminal year of the program from 2013 to
2015.65
As part of the September 24, 2004 Order creating the RPS, the NYPSC designated NYSERDA as
the central procurement administrator for the RPS Program. In doing so, the NYPSC noted an
expectation that voluntary renewable purchases by retail customers would contribute at least
1% toward the 25% goal, thus leaving baseline resources, State Agencies’ purchases, and
NYSERDA procurements to realize the remaining 24%. In the same Order, the NYPSC directed
the major investor-owned utilities to collect funds from ratepayers to be administered by
NYSERDA for the purpose of supporting NYSERDA’s implementation responsibilities. Thus,
NYSERDA has been responsible for the majority of the program’s goal. Specifically, NYSERDA is
responsible for achieving targets for larger utility-scale resources and smaller behind-the-meter
resources, with the remainder to be provided by voluntary renewable purchases, purchases
made by state agencies, and purchases made by the LIPA.
In addition to actions taken by the State to encourage investment in renewable resources, steps
were taken at the Federal level to do the same. The Energy Policy Act of 1992 enacted the
renewable electricity production tax credit (PTC), which reduced corporate income tax liability
for electricity produced by renewable resources, including a 1.5 cents tax credit for each kWh of
electricity produced by wind power. The PTC initially expired in July 1999 but has been
expanded and extended several times through many different laws.66 It will expire at the end of
2012 and currently credits 2.2 cents per kWh for electricity produced by wind power. The PTC
has been a major incentive for wind power development, and has helped to spur independent
wind energy power producers across the country, including New York State.
The 2004 NYPSC Order and the ensuing activity administered by NYSERDA, funded by electricity
customers throughout New York State, along with the stimulus from the federal PTC, have
64
State Of New York Public Service Commission, Order Regarding Retail Renewable Portfolio Standard, CASE 03-E0188, September 24, 2004.
65
State Of New York Public Service Commission, Order Authorizing Customer-Sited Tier Program Through 2015 And
Resolving Geographic Balance And Other Issues Pertaining To The RPS Program, CASE 03-E-0188, April 2, 2010.
66
The PTC has been extended through passage of the Job Creation and Worker Assistance Act of 2002 (P.L. 10747), the American Jobs Creation Act of 2004 (P.L. 108-357), the Energy Policy Act of 2005 (P.L. 109-58), and
the American Recovery and Reinvestment Act of 2009 (P.L. 111-5).
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contributed substantially to the subsequent wind development boom in New York. Figure 10
shows that wind power investments took off after the RPS program began. This has led to
installation of 1,414 MW67 of wind-powered capacity in various parts of New York State, largely
spurred by the funding support from NYSERDA and the PTC. Thus, approximately 15% of the
total installed capacity placed in service from 2000 to 2012 has been largely the result of the
RPS and the efforts of the NYPSC, NYSERDA, and the federal PTC. This wind power investment
has had little to do with incentives provided by the NYISO’s capacity market.
Figure 10
New York State Wind Power Capacity Additions (MW)68
Since 2004, the New York RPS and NYSERDA have also encouraged the development of small
quantities of non-wind renewable resources as summarized in Table 3 and Table 5. These other
renewables, all of which are traded under long-term PPAs, account for another 1% of the
installed capacity brought into service since 2000.
67
NYSERDA’s 2011 RPS Performance Report indicates that, through the end of 2011, there were 1,326 MW of wind
powered capacity added in New York that is currently in operation. The difference may be due to the wind farms
that came into service prior to 2004. The source of the 1,414 MW value is NYISO’s 2012 Gold Book.
68
Source, New York State Energy Research and Development Authority, The New York State Renewable Portfolio
Standard Performance Report, Through December 31, 2011, undated, p. 10. Figure 4 skips from 2001 to 2006
because there was no wind capacity installed in the years 2002 through 2005.
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Table 5
Non-Wind Renewable Resources Promoted by the RPS and NYSERDA since 2004
Resource
Type
Biogas
Biomass
Hydro
Total
Total Installed
Capacity (MW)
56
31
27
114
Contract
Length (Years)
10
10
1069
4. Environmental Regulations
Environmental regulations tend to act as barriers to generation investment.
From the early 1990s until 2002, New York had a streamlined process, codified in Article X of
the Public Service Law, for granting permits to power plants 80 MW and over. The law provided
a one-stop permitting process that helped developers secure approvals in approximately 12
months and incorporated what would have otherwise been local permitting issues. Article X
expired at the end of 2002 and annual efforts to pass similar legislation have failed. Today,
permits for large new generation facilities must be obtained through the State Environmental
Quality Review Act process, which is more complicated and lengthy than the one that existed
under Article X. The requirement for local permits often results in delays and additional
expense, and may be used to block locally unpopular projects. This additional uncertainty can
make New York State a riskier, and therefore less attractive, option for potential investors.
In addition, regulations promulgated by the U.S. Environmental Protection Agency (EPA)
increase the difficulty and cost associated with building new generation and with repowering
existing generation. For example, the EPA’s Cross-State Air Pollution Rule (CSAPR) requires
twenty-seven states to reduce power plant emissions of sulfur dioxide and nitrogen oxide
emissions. New York is one of the states directly affected by this rule. How this rule will
ultimately impact resource additions is unclear at this point because CSAPR’s requirements
have been vacated by the U.S. Court of Appeals for the D.C. Circuit.70
B. Market Incentives
Investors build generation partly in response to the market prices they can receive for
generation services. These prices reflect the foregoing non-market standards.
69
One contract has a length of three years.
70
EME Homer City Generation v. Environmental Protection Agency, et al., D.C. Cir. No. 11-1302, decided August 21,
2012.
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1. Short-Term Markets
The NYISO administers short-term markets for energy, ancillary services, and capacity.
The energy market consists of a day-ahead market and a real-time market. The day-ahead
market is a forward market in which hourly locational marginal prices (LMPs) are calculated for
the next operating day based on generation offers, demand bids, and scheduled bilateral
transactions. The real-time market is a spot market in which current LMPs are calculated at
five-minute intervals based on actual grid operating conditions.
The ancillary services markets include those for operating reserves and regulation. By selecting
units with the lowest total production costs to provide energy, operating reserves, and
regulation, the NYISO minimizes the cost of serving load. Operating reserves and regulation are
typically provided by generators, though the NYISO has opened these markets to include loads
(i.e., demand-side providers).
The NYISO currently conducts three types of ICAP auctions: forward strip auctions, in which
capacity is transacted in six-month blocks for the upcoming capability period; monthly forward
auctions in which capacity is transacted for the remaining months of the capability period; and
monthly spot auctions. Auction participants include any entities seeking to purchase Unforced
Capacity (including all entities that have Unforced Capacity shortfalls), qualified ICAP suppliers,
and any entity that owns excess Unforced Capacity. The two forward markets are voluntary, but
all requirements must be satisfied at the conclusion of the spot market immediately prior to
each month. LSEs that have purchased more than their obligation prior to the spot auction may
sell the excess into the spot auction.
As a report prepared in 2009 for the NYISO stated:
At present, the New York capacity market does not appear to have fundamental
design flaws that require total redesign of the market. FERC has not found the
NYISO market to be unjust and unreasonable as it did for the capacity markets
that preceded the implementation of forward capacity markets in PJM and ISONE.
The NYISO’s Independent Market Advisor has likewise not identified
fundamental design flaws, although he has recommended creating a new
Southeast New York capacity zone and some other adjustments. The
Independent Market Advisor’s largest concern, about market power in New York
City has already been addressed through a proceeding and a series of FERC
Orders, first in March 2008.71
The NYISO’s various markets, like those of the other Regional Transmission Organizations, are
all short-term (or relatively short) forward markets. The introduction of these short-term
markets beginning in the late 1990s introduces risks for investors in merchant generating plants
71
The Brattle Group, Cost-Benefit Analysis of Replacing the NYISO’s Existing ICAP Market with a Forward Capacity
Market, June 15, 2009, prepared for the New York Independent System Operator, p. 10, footnotes omitted.
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that are distinctly different from risks associated with the traditional electric utility industry
involving regulated utilities.
Given the long-term nature of electricity investments, investment decisions in baseload
generating capacity are being made on the basis of long-term market fundamentals rather than
looking at short-term behavior of the spot or forward electricity markets. Investors take
account of differences in risk levels in assessing the likely profitability of different types of
power sector investments.
The current market preference for gas-fired generation for baseload generation can be
explained mainly by the perceived lower cost of gas-fired generation. The characteristics of the
combined cycle gas turbine (CCGT)—its low capital cost and its operational flexibility—add to its
attractiveness. The proliferation of CCGTs means that gas markets take on greater importance
for power generation development, exposing investors to increased fuel price risk. The
restructuring of electricity and natural gas markets has led to a system where, in the absence of
long-term hedging possibilities, it is difficult to manage price risks, which must be assessed by
probabilistic approaches.
For the more traditional role played by combined cycle gas turbines as peaking plants, price
risks are especially acute, because those plants depend upon prices in a low number of highpriced hours in each year. This raises the question as to whether competitive power markets
can bring forward adequate peaking capacity.
The current economic downturn has held down electricity prices and caused investors to look
for strong companies with stable revenue flows and customer bases. Restructured electric
markets have affected the way power plants are financed. Early enthusiasm about the benefits
of the merchant power plant model has waned thanks to recent years of adverse investment
experience. Due to substantial losses by companies with merchant plant investments, rising
capital costs of new generators, and decreasing liquidity of electricity forward markets, it is
currently difficult to obtain bank financing for new merchant power plants.
The risks associated with the merchant plant model have persuaded many investors to find
mechanisms to hedge these risks. Long-term purchase power contracts between producers and
retailers or directly with consumers have emerged as one of the more important ways that
investors can hedge the risks of competitive power markets. For the merchant generator, the
shift from reliance on the short-term competitive power market to hedging market risk through
long-term contracts is evident in a statement made by Lee Davis, NRG’s Regional PresidentNortheast, in an interview with Reuters in late 2011. Mr. Davis stated that NRG would be willing
to invest in a new generating unit to replace the Indian Point Energy Center (in New York) under
one condition:
‘All we need is a (power purchase) contract in hand with a creditworthy
counterparty,’ Davis said and NRG can get the financing needed to build the
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project…. ‘NYPA is obviously the one that stands out as the most likely … we
expect NYPA to continue to write contracts for new units’ Davis said.72
2. Long-Term Markets
The NYISO’s centralized markets are but one path to providing energy and ancillary services and
securing capacity investment that provides reliable service at the lowest reasonable cost.
Another path, which is commonly used in New York and across the country, is comprised of
long-term bilateral transactions, including PPAs and hedging instruments among LSEs, suppliers,
energy service companies, and financial institutions. A third path is self-supply. Long-term
bilateral agreements and LSE-owned resources are not “out-of-market” paths to achieve service
reliability but are instead the primary means by which customers and system operators have
assured reliability for over a century, and by which they continue to assure reliability today.
Indeed, the NYISO’s ICAP markets are a less desirable path for achieving and maintaining
reliability and controlling costs because of their short-term and volatile nature.
3. Short-Term vs. Long-Term Markets
A wholesale power market will produce spot energy market and spot capacity market price
fluctuations that reflect moments of scarcity and surplus over a seasonal or business cycle. In
addition, unpredictable changes in system configuration in real time produce price volatility, on
top of the expected cyclical price swings. The most visible manifestations of price volatility are
daily and hourly price fluctuations that could easily double or halve prices within an hour.73
In a competitive commodity market in which consumers have an option to face spot market
prices, this kind of price volatility creates uncertainty for buyers and sellers about future spot
prices that, in turn, creates risks that spot prices will be above or below expected values. For
end users who face volatile spot market prices, the risks can be significant. The utilities and
other LSEs with obligations to serve face similar market risks when regulated retail electricity
rates are fixed. Hence, commercial end users and utilities naturally seek protection from price
volatility that makes long-term planning more costly and finances risky. Generators will seek to
protect themselves against the possibility that energy spot prices and capacity market spot
prices might not be sufficient to cover production costs and capital costs. Therefore, buyers and
sellers can obtain protection by entering into bilateral forward contracts for delivery of power
and capacity at fixed (or indexed) prices.
When buyers, such as NYPA or LIPA and municipalities and electric cooperatives, have an
obligation to ensure sufficient capacity will be available to handle contingencies, they face
uncertainty about whether a contingency will occur, and if it does, what price they would pay if
72
Reuters, Interview: NRG looks to replace power from Indian Point, available at
http://www.ubs.wallst.com/ubs/mkt_story.asp?docKey=1329-S1E78M0HK-1&first=0 , October 8, 2011 (Reuters
Article).
73
Price volatility can be exacerbated in tight supply situations when generators know that small exercises of
market power can raise prices without triggering mitigation by market monitors.
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they purchased from the energy spot market and from the monthly ICAP auction market. Thus,
LSEs will hedge at least a portion of the price risk by either owning supply (vertical integration)
or by entering bilateral contracts for energy and capacity.
4. Capacity Markets
The capacity market in New York State is a mixture of self-supply, bilateral contracts (i.e., PPAs),
and the NYISO’s voluntary centralized ICAP market. The self-supply and bilateral contract
options tend to offer long-term commitments for capacity to satisfy reserve requirements.
These options also offer capacity price stability (i.e., predictability) that can facilitate utility
planning and budgeting.
In contrast, the NYISO’s ICAP market is a voluntary short-term market, except for the
mandatory one-month-ahead market. From the LSE’s perspective, NYISO’s ICAP market
functions as a backstop at times when the utility cannot satisfy its reserve requirements
through self-supply and PPAs. The ICAP market standardizes the capacity product and provides
greater liquidity and transparency than can be found generally in a bilateral market. While
adding complexity in market design, these features are particularly beneficial in market
environments with many small LSEs, retail competition, and migrating customer loads, as is the
case in New York.
It is informative that the FERC has recently issued an order regarding the implementation of a
capacity market for MISO. This order reaffirms a previous order from 2008 that approved the
use of a voluntary capacity market auction mechanism to complement the bilateral and utilityowned capacity market segments.74 The FERC’s reasons for approving a voluntary capacity
market auction include:

Consistent rejection of a “one-size-fits-all” approach due to significant differences
among RTO regions;75

The voluntary nature of the centralized auction “allows LSEs and their regulators to
maintain significant flexibility when developing resource plans based on their specific
region;”76
 MISO’s lack of justification for a mandatory forward capacity auction;77 and

The auction’s opt-out provision “enables LSEs to manage how they will fulfill their
capacity requirement” and “maintains the voluntary framework of the currently
effective resource adequacy plan.”78
74
Midwest Independent System Operator, Inc., 139 FERC ¶ 61,199 (2012).
75
Id., P 37.
76
Id., P 39.
77
Id., P 40.
78
Id., P 41.
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V. CONCLUSIONS
The record of the past twelve years shows that the capacity market structure in New York State
has worked successfully to provide adequate generation resources through a combination of
utility-owned supply, long-term PPAs between utilities and merchant plants, merchant plant
development that relies on the NYISO’s centralized markets, and publicly funded renewable
resource projects motivated by New York’s RPS and encouraged by NYSERDA and the federal
production tax credit. This market structure has provided generation capacity where it is
needed most, using diverse fuels and meeting a variety of renewable resources and
environmental policy goals. This success has been achieved without resorting to a mandatory
forward market such as those used by ISO New England and PJM. The current design does not
require replacement by a mandatory forward centralized ICAP market.
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ATTACHMENT A.
NEW YORK GENERATION BROUGHT IN-SERVICE, 2000–2012
Table 6 provides a listing of the generation built in New York during the past dozen years. The
table covers new generation through April 2012, and does not include any generation placed in
service since that time. Capacities are nameplate ratings, not net summer or winter ratings.
Table 6
New York Generation Brought In-Service, 2000–201279
Owner, Operator, and/or
Billing Organization
Station Unit
Zone
In Service
Year
Name Plate
Rating
Unit
Type
Transaction
Type
Madison Windpower, LLC
Madison Wind Power
E
2000-09-01
11.6
WT
Public Support
Western New York Wind Corp.
Western NY Wind Power
B
2000-10-01
6.6
WT
Public Support
Standard Binghamton LLC
Binghamton Cogen (Ret. 2/15/12)
C
2001-03-01
47.7
GT
Merchant
Astoria Generating Company L.P.
Astoria 2 (Ret. - 4/11/12)
J
2001-05-01
180.0
ST
Merchant
Model City Energy LLC
Model City Energy
A
2001-06-01
5.6
IC
Utility/Bilateral
New York Power Authority
Brentwood
K
2001-08-01
50.0
GT
Utility/Bilateral
New York Power Authority
Gowanus 5
J
2001-08-01
50.0
GT
Utility/Bilateral
New York Power Authority
Gowanus 6
J
2001-08-01
50.0
GT
Utility/Bilateral
New York Power Authority
Harlem River 1
J
2001-08-01
50.0
GT
Utility/Bilateral
New York Power Authority
Harlem River 2
J
2001-08-01
50.0
GT
Utility/Bilateral
New York Power Authority
Hellgate 1
J
2001-08-01
50.0
GT
Utility/Bilateral
New York Power Authority
Hellgate 2
J
2001-08-01
50.0
GT
Utility/Bilateral
New York Power Authority
Kent
J
2001-08-01
50.0
GT
Utility/Bilateral
New York Power Authority
Pouch
J
2001-08-01
50.0
GT
Utility/Bilateral
New York Power Authority
Vernon Blvd 2
J
2001-08-01
50.0
GT
Utility/Bilateral
New York Power Authority
Vernon Blvd 3
J
2001-08-01
50.0
GT
Utility/Bilateral
Fenner Wind Power
Fenner Wind Power
C
2001-12-01
30.0
WT
Public Support
Jamestown Board of Public Utilities
Jamestown 7
A
2002-01-01
47.3
GT
Utility/Bilateral
Long Island Power Authority
Glenwood GT 04
K
2002-06-01
53.0
GT
Utility/Bilateral
Long Island Power Authority
Glenwood GT 05
K
2002-06-01
53.0
GT
Utility/Bilateral
Calpine Energy Service LP
Bethpage GT4
K
2002-07-01
60.0
GT
Utility/Bilateral
Erie Blvd. Hydro - Oswegatchie
Lower Newton Falls 1
E
2002-07-01
0.5
HY
Utility/Bilateral
Erie Blvd. Hydro - Oswegatchie
Upper Newton Falls 2
E
2002-07-01
0.5
HY
Utility/Bilateral
Erie Blvd. Hydro - Oswegatchie
Upper Newton Falls 3
E
2002-07-01
0.5
HY
Utility/Bilateral
Erie Blvd. Hydro - Oswegatchie
Upper Newton Falls 4
E
2002-07-01
0.5
HY
Utility/Bilateral
79
NYISO, 2012 Load & Capacity Data: “Gold Book,” Table II-2: Existing Generating Facilities, pp. 30–48. 2012 Gold
Book covers new generation through April 2012. Any generation placed in service after April 2012 does not appear
on this list.
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Owner, Operator, and/or
Billing Organization
Station Unit
Zone
In Service
Year
Name Plate
Rating
Unit
Type
Transaction
Type
Long Island Power Authority
Far Rockaway GT1
K
2002-07-01
60.0
GT
Utility/Bilateral
Long Island Power Authority
Port Jefferson GT 02
K
2002-07-01
53.0
GT
Utility/Bilateral
Long Island Power Authority
Port Jefferson GT 03
K
2002-07-01
53.0
GT
Utility/Bilateral
Long Island Power Authority
Pilgrim GT1
K
2002-08-01
50.0
GT
Utility/Bilateral
Long Island Power Authority
Pilgrim GT2
K
2002-08-01
50.0
GT
Utility/Bilateral
Long Island Power Authority
Shoreham GT3
K
2002-08-01
50.0
GT
Utility/Bilateral
Long Island Power Authority
Shoreham GT4
K
2002-08-01
50.0
GT
Utility/Bilateral
Long Island Power Authority
Far Rockaway GT2
K
2003-07-02
60.0
GT
Utility/Bilateral
Long Island Power Authority
Greenport GT1
K
2003-07-02
54.0
GT
Utility/Bilateral
Seneca Energy II, LLC
Ontario LFGE
C
2003-12-01
6.4
IC
Utility/Bilateral
Freeport Electric
Freeport CT 2
K
2004-03-01
60.5
GT
Utility/Bilateral
Athens Generating Company, LP
Athens 1
F
2004-05-01
441.0
CC
Merchant
Athens Generating Company, LP
Athens 2
F
2004-05-01
441.0
CC
Merchant
Athens Generating Company, LP
Athens 3
F
2004-05-01
441.0
CC
Merchant
TC Ravenswood, LLC
Ravenswood CC 04
J
2004-05-01
250.0
CC
Merchant
Long Island Power Authority
Freeport CT 1
K
2004-06-01
60.0
GT
Utility/Bilateral
Niagara Mohawk Power Corp.
Mechanicville
F
2005-03-01
2.0
HY
Utility/Bilateral
Consolidated Edison Co. of NY, Inc.
East River 1
J
2005-04-01
185.0
CC
Utility/Bilateral
Consolidated Edison Co. of NY, Inc.
East River 2
J
2005-04-05
189.0
CC
Utility/Bilateral
Long Island Power Authority
Bethpage 3
K
2005-05-01
96.0
CC
Utility/Bilateral
Long Island Power Authority
Pinelawn Power 1
K
2005-06-01
82.0
CC
Utility/Bilateral
PSEG Energy Resource & Trade, LLC
Bethlehem Energy Center
1
F
2005-07-01
893.1
CC
Merchant
Flat Rock Windpower, LLC
Maple Ridge Wind 1
E
2006-01-01
231.0
WT
Public Support
New York Power Authority
Astoria CC 1
J
2006-01-01
288.0
CC
Utility/Bilateral
New York Power Authority
Astoria CC 2
J
2006-01-01
288.0
CC
Utility/Bilateral
Modern Innovative Energy, LLC
Modern LF
A
2006-02-01
6.4
IC
Merchant
Innovative Energy Systems, Inc.
Colonie LFGTE
F
2006-03-01
4.8
IC
Merchant
Astoria Energy, LLC
Astoria East Energy - CC1
J
2006-04-01
320.0
CC
Astoria Energy, LLC
Astoria East Energy - CC2
J
2006-04-01
320.0
CC
Erie Blvd. Hydro - Seneca Oswego
Oswego Falls W 6
C
2007-01-01
0.5
HY
Public Support
Erie Blvd. Hydro - Seneca Oswego
Oswego Falls W 7
C
2007-01-01
0.5
HY
Public Support
Commerce Energy, Inc.
Steel Wind
A
2007-01-23
20.0
WT
Public Support
Mill Seat
B
2007-07-20
6.4
IC
Merchant
Chaffee
A
2007-08-09
6.4
IC
Merchant
Constellation Energy Commodities
Group, Inc.
Constellation Energy Commodities
Group, Inc.
50%
Utility/Bilateral
50%
Utility/Bilateral
Shell Energy North America (US), L.P.
Munnsville Wind Power
E
2007-08-20
34.5
WT
Merchant
New York State Elec. & Gas Corp.
Broome LFGE
C
2007-09-01
2.1
IC
Merchant
Flat Rock Windpower II, LLC
Maple Ridge Wind 2
E
2007-12-01
90.8
WT
Merchant
Constellation Energy Commodities
Group, Inc.
High Acres 2
C
2008-02-28
6.4
IC
Merchant
Christensen Associates Energy Consulting, LLC
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Owner, Operator, and/or
Billing Organization
Station Unit
Zone
In Service
Year
Name Plate
Rating
Unit
Type
Transaction
Type
Noble Bliss Windpark, LLC
Bliss Wind Power
A
2008-03-20
100.5
WT
Public Support
Noble Ellenburg Windpark, LLC
Ellenburg Wind Power
D
2008-03-31
81.0
WT
Public Support
Noble Clinton Windpark 1, LLC
Clinton Wind Power
D
2008-04-09
100.5
WT
Public Support
Niagara Mohawk Power Corp.
Allied Frozen Storage
A
2008-05-01
0.1
IC
Utility/Bilateral
Innovative Energy Systems, Inc.
DANC LFGE
E
2008-09-08
4.8
IC
Merchant
Innovative Energy Systems, Inc.
Hyland LFGE
B
2008-09-08
4.8
IC
Merchant
Noble Altona Windpark, LLC
Altona Wind Power
D
2008-09-23
97.5
WT
Public Support
Innovative Energy Systems, Inc.
Clinton LFGE
D
2008-10-01
6.4
IC
Merchant
Noble Chateaugay Windpark, LLC
Chateaugay Wind Power
D
2008-10-07
106.5
WT
Public Support
Canandaigua Power Partners, LLC
Canandaigua Wind Power
C
2008-12-05
125.0
WT
Merchant
Noble Wethersfield Windpark, LLC
Wethersfield Wind Power
C
2008-12-11
126.0
WT
Public Support
Sheldon Energy LLC
High Sheldon Wind Farm
C
2009-02-01
112.5
WT
Public Support
Erie Blvd. Hydro - Upper Hudson
Sherman Island 6
F
2009-02-02
1.0
HY
Public Support
Delaware County
Delaware LFGE
E
2009-02-11
2.0
IC
Merchant
Erie Blvd. Hydro - Upper Hudson
Sherman Island 1
F
2009-03-01
8.0
HY
Public Support
Long Island Power Authority
Caithness_CC_1
K
2009-08-01
375.0
CC
Utility/Bilateral
E
2009-11-01
1.1
CG
Utility/Bilateral
E
2009-11-01
2.2
CG
Utility/Bilateral
Niagara Mohawk Power Corp.
Niagara Mohawk Power Corp.
Burrstone Energy Center,
LLC
Burrstone Energy Center,
LLC
Niagara Mohawk Power Corp.
Edison Hydro Electric
F
2009-11-01
0.0
HY
Not Included
Niagara Mohawk Power Corp.
Finch Paper LLC - Glens
Falls
F
2009-11-01
0.0
HY
Not Included
Niagara Mohawk Power Corp.
Moutainaire Massage Spa
F
2009-11-01
0.0
HY
Not Included
Niagara Mohawk Power Corp.
Oakvale Construction
D
2009-11-01
0.0
HY
Not Included
Niagara Mohawk Power Corp.
Tri-City JATC
F
2009-11-01
0.0
IC
Not Included
Niagara Mohawk Power Corp.
United States Gypsum
A
2009-11-01
0.0
CG
Not Included
Niagara Mohawk Power Corp.
Wave Hydro LLC
C
2010-02-07
0.8
HY
Merchant
Innovative Energy Systems, Inc.
Chautauqua LFGE
A
2010-02-12
9.6
IC
Merchant
Constellation Energy Commodities
Group, Inc.
Madison County LF
E
2010-03-01
1.6
IC
Merchant
Innovative Energy Systems, Inc.
Fulton LFGE
F
2010-06-04
3.2
IC
Merchant
Empire Generating Co, LLC
EMPIRE_CC_1
F
2010-09-02
335.0
CC
Merchant
Empire Generating Co, LLC
EMPIRE_CC_2
F
2010-09-02
335.0
CC
Merchant
Stephentown Regulation Services LLC
Beacon LESR
F
2010-11-29
20.0
ES
Merchant
AES ES Westover LLC
Westover LESR
C
2010-12-13
8.0
ES
Merchant
Hardscrabble Wind Power LLC
Hardscrabble Wind
E
2011-02-01
74.0
WT
Public Support
Astoria Energy II, LLC
Astoria Energy 2 - CC3
J
2011-07-01
330.0
CC
Utility/Bilateral
Astoria Energy II, LLC
Astoria Energy 2 - CC4
J
2011-07-01
330.0
CC
Utility/Bilateral
K
2011-11-01
31.5
PV
Utility/Bilateral
Long Island Power Authority
Howard Wind LLC
Howard Wind
C
2011-12-01
51.3
WT
Public Support
First Wind Energy, LLC
Erie Wind
A
2012-02-01
15.0
WT
Merchant
Christensen Associates Energy Consulting, LLC
38
9/19/12