Capacity Watch Excerpt

Transcription

CAPACITY WATCH
Authors: Paul Flemming, Scott Niemann and José Rotger
April 2015
EXECUTIVE SUMMARY
T
his issue of Capacity Watch™ discusses several important ca 2015. In PJM, the Capacity Performance (CP) docket before FERC con
letter. FERC has also granted PJM a tariff waiver to allow the 2018/19
BRA to be delayed until after the Commission has reached a decision
about the CP rules. ESAI presents an outlook for the upcoming BRA,
both with and without the CP rules in place. For New York, ESAI asseses the ICAP market outlook in light of an increased forecast for growth
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land, ESAI recaps the Ninth Forward Capacity Auction (for 2018/19)
and discusses late updates on peak load forecasts and implementation of
capacity zones for the 2019/20 capacity auction.
In this Issue
Opportunities in Lower
Load Growth Environment?
New England
PJM
2
New York
7
California
24
Appendix
45
62
71
ESAI
401 Edgewater Place
Suite 640
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Note: No parts of the Capacity WatchTM may be duplicated, transmitted or stored without ESAI’s written permission. The estimates,
forecasts and analyses in this report are our judgment and are subject to change without notice. No warranty is made or implied.
OPPORTUNITIES IN LOWER LOAD GROWTH ENVIRONMENT?
Capacity WatchTM
2
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cantly as a result of lower economic activity. Forecasts for the return of ‘latent’
growth did not materialize, particularly in PJM where growth rates were forecast
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still dropping their load forecasts for the coming Base Residual Auctions, with the
most recent change being a 4 GW drop in RTO peak load for the 2018/19 BRA. As
noted in our January Capacity Watch, the PJM peak load compound annual growth
rate (CAGR) was unchanged at 1.0 percent.
In contrast to PJM, both energy and peak load growth rates in New England
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500 MW in 2017 and beyond. Only about 100 MW of this 500 MW drop is due
to a change in the outlook for underlying growth. The additional difference comes
from behind-the-meter PV solar and Passive Demand Response (PDR, or energy
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to 450 MW in 2024.
Figure 1: New England Peak Load Reduction (2015 Preliminary
F’cast)
0
(MW)
-100
-200
-300
-400
-500
-600
2015
2016
2017
2018
2019
2020
2021
2022
2023
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the New York ‘Reforming the Energy Vision’ or REV program and the Clean En
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peak load outlooks from the recently released NYISO Gold Book load forecast.
The 2015 peak load outlook includes a reduction in the 2015 prompt year forecast of 500 MW. A combination of the front year load growth drop and tepid load
growth through 2019 results in load reductions in 2020 of 1,500 MW.
April 2015
©
2015, ESAI Power LLC, Reproduction Prohibited
Capacity WatchTM
3
Figure 2: New York Peak Load Reduction (2015 Gold Book)
37,000
36,500
(MW)
36,000
35,500
35,000
34,500
34,000
33,500
33,000
2014 Gold Book
32,500
2015 Gold Book
32,000
31,500
With lower load growth, the need for new capacity in each of the three Northeast pools becomes less urgent. Although New England and PJM are already build
;
were the only driver for new capacity additions. However, there will still be room
for new capacity to enter the market due to a number of factors that should combine to create opportunity for new builds even in a low load growth environment:
1. Plants At Risk of Retirement
There are several factors that put older plants at risk of retirement, even
though capacity price signals are generally strong enough to incentivize
many older plants to remain in the markets.
Performance and Fuel Assurance
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penalty structures proposed in PJM and going forward in New England, penalties for non-performance can exceed capacity payments.
As these rules are implemented and actual penalties are assessed,
more retirements are likely.
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April 2015
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Nuclear plants are at risk, particularly in New York and PJM where
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tinued operations at the older and smaller nuclear plants such as Ginna
in New York, especially when very low gas prices are yielding low
7x24 energy prices.
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vestments will have reduced revenues in a low gas price environment,
©
CapacityENGLAND
Watch
NEW
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7
SUMMARY
The 2018/19 Forward Capacity Auction (FCA9) cleared at $9.551/kW-month
for the Rest of Pool, Connecticut, and NEMA/Boston zones, with imports over
two external interfaces (New York and New Brunswick) receiving lower prices
as a result of excess supply over those interfaces. ISO-NE triggered the inad
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the price for new resources in SEMA-RI at the FCA starting price ($17.728/kWmonth) and for existing resources at $11.08/kW-month.
Separately, ISO-NE proposed a new zonal structure for FCA10 collapsing
NEMA/Boston and SEMA-RI into a single import-constrained zone (Southeast
New England) and merging Vermont, New Hampshire and Maine into a new
Northern New England export-constrained zone.
2018/19 CLEARS AT $9.55/KW-MO.; SEMA-RI SEPARATES
ISO-NE held its ninth Forward Capacity Auction (FCA9) on February 2, procuring capacity for the June 2018 through May 2019 capacity commitment period.
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Pool (system-wide) zone; however, import-constrained zones were cleared against

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The system-wide clearing price was $9.551 per kW-month, for a cleared
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connection capability credits). However, two external interfaces had more excess
supply that needed to exit the descending clock auction, resulting in the auction
continuing and setting a lower clearing price. The New York interface cleared at
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(the dynamic de-list bid threshold), meaning that capacity imports cleared over
these interfaces would be paid these lower prices.
FCA9 featured three import-constrained zones – Connecticut, NEMA/Boston and SEMA-RI – and no export-constrained zones (Maine was collapsed into
Rest-of-Pool). Both Connecticut and NEMA/Boston did not separate from Restof-Pool and cleared at the $9.55 price. However, the sum of existing and new
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>:!$% sets the price for new resources in SEMA-RI at the FCA starting price ($17.728)
and for existing resources at the higher of Net CONE ($11.08) or the Rest-of-Pool
clearing price – in other words, $11.08 per kW-month.
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Rest-of-Pool demand curve to the left, thus resulting in the lower $9.55 clearing
April 2015
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of-Pool demand curve would have returned a price of $10.61 per kW-month. If
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Table 1 - 2018/19 FCA Cleared Resources by Capacity Zone
(Summer MW Cleared)
CT
NEMA/
Boston
SEMA-RI
Rest of
Pool
Total
EXISTING CAPACITY
Generation (incl. intermittent)
Demand
Imports
Subtotal Existing Capacity
8,415
486
–
8,901
3,301
531
–
3,832
6,413
475
–
6,888
11,253
945
89
12,286
29,382
2,436
89
31,907
NEW CAPACITY
Demand
Imports
Subtotal New Capacity
837
64
–
900
1
95
–
95
214
139
–
353
9
69
1,360
1,438
1,060
367
1,360
2,787
TOTAL RESOURCES CLEARED
9,802
3,927
7,241
13,724
34,695
LOCAL SOURCING REQUIREMENT /
NET ICR
7,331
3,572
7,479
n/a
34,189
2,471
33.7%
355
9.9%
(238)
-3.2%
n/a
n/a
506
1.5%
CAPACITY EXCESS/(SHORTFALL)
New Capacity Cleared
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imports which under the FCM rules are eligible to be treated as “new” resources
every year, despite some of them having cleared past auctions. Excluding imports,
the amount of new resources cleared in FCA9 is 1,427 MW, comprised of 1,060
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the new generation and import resources cleared in FCA9.
Figure 1 - New Capacity Cleared in 2018/19 FCA (By Type, MW)
Imports
1,360
49%
Generation
1,060
38%
Demand
367
13%
April 2015
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Table 2 - New Generation Resources Cleared in 2018/19 FCA
(Summer MW)
Resource
CPV Towantic
LS Power Wallingford 6 & 7 (peakers)
Bridgeport Energy (uprate)
Exelon Medway Peaker
Tiverton Power (uprate)
Solar PV
Other (landfill gas, hydro)
Location
Summer MW
Connecticut
Connecticut
Connecticut
SEMA-RI
SEMA-RI
various
Rest of Pool
725
90
22
195
11
16
1
Total
1,060
Table 3 - Imports Cleared in 2018-19 FCA
Project Name
Origin
Capacity
Zone
Summer MW
Cleared
NYPA Preference Power (CT,MA,RI)
NYPA Preference Power (VT)
via Highgate tie
NYISO
NYISO
Québec
Rest of Pool
Rest of Pool
Rest of Pool
69
14
6
89
via New York AC ties
via Phase II tie
via Highgate tie
Roseton Unit 1 (NY)
Rennselaer Cogen (NY)
Massena Energy (CCGT)
Broome County (NY) landfill gas unit
Control-area backed
Biomass in Maine Public Service via New Brunswick ties
Biomass in Maine Public Service via New Brunswick ties
Québec
Québec
Québec
NYISO
NYISO
NYISO
NYISO
New Brunswick
MPS/New Brunswick
New Brunswick
Rest of Pool
Rest of Pool
Rest of Pool
Rest of Pool
Rest of Pool
Rest of Pool
Rest of Pool
Rest of Pool
Maine
Maine
300
166
46
512
77
80
2
114
31
32
Sponsor
Existing Capacity
NYPA
NYPA
Vermont Joint Owners/HQ
Subtotal Existing
New Capaciy
Hydro-Québec
Hydro-Québec
Hydro-Québec
Castleton Commodities Inc.
Castleton Commodities Inc.
Alliance Energy / Power City Partners
Broome Energy
New Brunswick Power
ReEnergy Fort Fairfield
ReEnergy Ashland
Subtotal New
1,360
Total Imports Cleared
1,449
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solar PV resources, the following new generating units cleared FCA9:
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Competitive Power Ventures (CPV) Towantic CCGT in Connecticut (725
MW);
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Exelon’s West Medway (MA) peaking units (190 MW total).
While information regarding which resource stopped the descending clock
auction is not publicly available, our expectation is that one of the above generating resources set the $9.55 clearing price for the auction. Notably, several
April 2015
©
Capacity WatchTM
10
proposed generating units did not clear the auction, including PSEG’s Bridgeport

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Boston, and the Pioneer Valley CCGT project in western Massachusetts. While
some reports indicated that NRG had proposed a CCGT project for its Canal gen
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Separately, ISO-NE indicated that the 16 MW of cleared solar PV resources
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amount from the last FCA, capped at a maximum of 600 MW).
As for imports, FCA9 cleared slightly more imports than last year’s FCA8
(2017/18), which cleared one of the lowest amounts of imports of all FCM auc"
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imports via the New York AC ties, as illustrated in Table 4 and Figure 2. As indicated earlier, additional imports from New York and New Brunswick in excess
of interface import limits resulted in the descending clock auction continuing for
those external interfaces, which ended in lower prices for imports at both of these
interfaces.
Table 4 - Imports Cleared in 2018/19 FCA by Interface
External Interface
Existing
New
Total
FCA9
New York AC ties
New Brunswick ties
Phase II
Highgate
Total
83
0
0
6
89
971
177
166
46
1,360
1,054
177
166
52
1,449
Total
FCA8
678
202
246
111
1,237
Increase/
(Decrease)
376
-25
-80
-59
212
Figure 2 - Cleared Imports in FCM Auctions
MW
2,500
2,000
1,900
1,993
2,011
1,924
1,830
1,449
1,500
1,237
1,000
500
2012/13
2013/14
Via Phase II
April 2015
2014/15
Via NY AC ties
2015/16
2016/17
Via NB ties
2017/18
2018/19
Via Highgate
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Capacity WatchTM
11
Implementation of a system-wide sloped demand curve for FCA9 included
provisions to continue the descending clock auctions at the external interfaces
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import capability available (see Table 5). Note that the interface limits in Table 5
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External Interface
Qualified
Interface
Limit **
Cleared
Cleared vs.
Qualified
Unused
Import Limit
New York AC ties
New Brunswick ties
Phase II
Highgate
2,203
390
166
52
1,054
177
447
52
1,054
177
166
52
-1,149
-213
-281
0
0
0
281
0
Total
2,811
1,730
1,449
-1,643
281
** After deducting tie benefits, which have priority over capacity imports
Finally, the amount of cleared demand resources in FCA9 was fairly similar to
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prices for FCA9, demand resources have yet to rebound to the levels seen in past
auctions.
Figure 3 - Demand Resources Cleared in ISO-NE Forward Capacity
Auctions
MW
4,000
263
3,000
314
515
355
309
367
245
2,000
3,205
2,558
2,746
2012/13
2013/14
3,315
2,503
2,686
2016/17
2017/18
2,436
1,000
2014/15
Existing
April 2015
2015/16
2018/19
New
©
Capacity WatchTM
12
Cleared De-List Bids
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MW); however, only 65 de-list bids remained (5,708 MW) in the auction. Twenty
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generator (approximately 4 MW) converted their static de-list bid into a full non
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de-list bids were converted into partial NPRs. As shown on Table 6, a total of 194
MW of static de-list bids cleared FCA9. There was one administrative export de;
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de-list bids were submitted. Notably, ISO-NE did not reject any de-list bids for
reliability reasons. A summary of the major generation resources that de-listed
from FCA9 is presented in Table 7.
Table 6 - 2018/19 FCA Cleared De-Lists by Capacity Zone
(Summer MW Cleared)
STATIC DE-LISTS
Demand
Imports
Total Static De-Lists
CT
NEMA/
Boston
SEMA-RI
Rest of
Pool
Total
17.1
–
–
17.1
–
1.6
–
1.6
–
–
–
–
75.1
–
–
75.1
92.2
1.6
–
93.8
100.0
100.0
175.1
193.8
ADMINISTRATIVE DE-LISTS
Generation (J. Cockwell - export)
TOTAL DE-LISTS
17.1
1.6
–
Table 7 - De-Lists Cleared in 2018/19 FCA (Summer MW)
Resource
Bridgeport Harbor 4 (jet peaker)
Covanta West Enfield (wood/waste)
Covanta Jonesboro (wood/waste)
Penobscot Energy Recovery (waste)
Stony Brook units ambient air de-rates
J. Cockwell (export to LIPA)
RTEG demand resources
Total
Location
Summer MW
Connecticut
Rest of Pool (Maine)
Rest of Pool (WCMA)
Rest of Pool (WCMA)
NEMA/Boston
17
20
20
21
13
100
2
194
We do not know the prices submitted by these resources in their cleared static
de-list bids, but they were all above the system-wide $9.55 clearing price. ISO$%
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resources as inconsistent with the IMM’s determination of going forward costs. Of

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April 2015
©
Capacity WatchTM
13
de-list bids and remained in the auction as price taking resources down to the dy!;
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As for dynamic de-list bids, the only submitted (and cleared) dynamic de-list
bids were for imports from New Brunswick, as the descending clock auction for
that external interface was the only auction that reached the threshold for submitting dynamic de-list bids. As indicated earlier, dynamic de-list bids stopped the
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kW-month.
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unit in western Massachusetts.
FCA9 Zonal Results: Inadequate Supply Rule Sets Price in SEMA-RI
As indicated earlier, FCA9 was held with four capacity zones, with Connecticut, NEMA/Boston, and SEMA-RI as import-constrained zones subject to an
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Notably, FCA9 had no export-constrained zones subject to a Maximum Capacity
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zone. Also, the import constrained zones
Both Connecticut and NEMA/Boston cleared capacity well above their re=6
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the Rest-of-Pool zone. As shown in Table 1 above, existing plus new cleared re
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the amount of existing resources entered into FCA9 included the Footprint Power
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retired Salem Harbor station in Salem, MA. First clearing the 2016/17 (FCA7)
auction but with its capacity supply obligation deferred to 2017/18, the Footprint
project is under construction and expected to enter service by June 2017.
In contrast to the rest of the region, the SEMA-RI zone fell short of the loca
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new resources received the FCA starting price of $17.728/kW-month and existing
resources will be paid the higher of Net CONE or the Rest-of-Pool clearing price.
The Net CONE value used to set the FCA9 demand curve was $11.08/kW-month,
April 2015
©
PJM
Capacity WatchTM
24

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(BRA) to secure capacity resources for the 2018/19 Delivery Year, to be conducted
in Summer of 2015. At the heart of the regulatory uncertainty is PJM’s proposal
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waiver that allows the RTO to postpone the auction. The delay is intended to allow
enough time for CP to be implemented, if approved by the commission.
Approval of CP is not the only source of uncertainty facing the PJM RPM
capacity market. The details of CP rules themselves are a source of uncertainty, as
; D gies for offering resources into the BRA. In addition, regardless of the rules that
will ultimately be in place for the BRA, a fairly broad range of market outcomes
is possible based purely on supply and demand fundamentals: what level of new
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be offered and at what prices? What level of external resources will participate?
In this issue of Capacity WatchTM, ESAI discusses potential scenarios for the
next BRA and provides a base case outlook, both with and without the CP rules in
place. We also provide additional discussion of some details of the CP rules and
the implications for the market outcome.
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: '*@ #%6D ditional information to facilitate a decision by the Commission. Many were expecting an order from the Commission on April 1, 2015, the date by which PJM
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focused on the offer cap for CP resources, the monthly stop loss provision, the
potential to phase-in penalties over time (like ISO-NE), the potential to reduce the
number of incremental auctions, and the mechanisms and procedures in place for
the performance assessments of external resources. Although it is impossible to
predict where the Commission will ultimately stand on the overall CP package,
general support for the rules, with reservations among some commissioners on a
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cating that he believed the Commission had the information necessary to make a
determination by April 1 and should have acted on the proposal in order to provide clarity to market participants in advance of the upcoming BRA, but that the
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appears to be driven more by timing of a decision and the importance of working
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the CP framework in general. However, until an order is issued, risk that the pro
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April 2015
©
Capacity WatchTM
25
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sought further explanation of the offer cap, regarding its applicability when new
resources are not needed, the level of comparability with ISO-NE’s offer cap under
its pay-for-performance rules, historical information about the Balancing Ratio
(BR), the predictability of the number of Performance Assessment Hours across
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Market Monitor’s (IMM’s) comments and proposal that the offer cap be lowered to
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cap, rather than all resources being capped at Net CONE for CP offers, the offer
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formance (A) times Net CONE:
Default Offer Cap = Net CONE x B + Max{0, (ACR - A x Net CONE)}
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as performance improves due to the incentives created by CP.
The offer cap, which PJM and IMM assert represent the competitive offer
level, was derived by taking the difference in expected net revenues for an energy
only resource and one that has a CP obligation. The fact that the cap is mathemati;$D:$%
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and not any direct linkage to long-run costs or expected prices. Recall that the
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number of Performance Assessment Hours (H). So, the Offer Cap could also be
written as:
Default Offer Cap = PRR x H x B + Max{0, [(ACR – (A x PRR x H)]}
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;$D:$%propriate when new capacity is not needed. PJM’s response appropriately noted
that the expected opportunity cost of providing CP is based on expected penalties
and bonus payments. Because those rates are based on Net CONE, the linkage
to Net CONE is appropriate regardless of whether or not new capacity is needed.
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April 2015
©
Capacity WatchTM
26
cap approved by the Commission for ISO-NE under its Pay-for-Performance rules.
PJM also explained that although alternative caps could also be reasonable, spe$D
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the preferred approach. The preference for the proposed cap is due to both the
conceptual tie to expected competitive offer levels and administrative simplicity.
As a practical matter, the change in the offer cap from Net CONE to Net Cone
x B is unlikely to have any impact on the outcome of the next BRA. As discussed
in more detail below, ESAI’s forecast of the BRA clearing price under CP is below both Net CONE and Net CONE x B, so resource bids at that level will not
clear with either cap. In the longer term, the impact should also be minimal, since
capacity suppliers will still have the ability to bid at higher levels if they can be
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The change in the offer cap was the only revision to PJM’s original proposal
;
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a willingness to adopt two other changes, should the Commission determine they
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has argued that an annual stop-loss is appropriate, but a monthly limit mutes incentives and is unnecessary. PJM did not withdraw the monthly penalty limit from the
proposal, but said it would not oppose removing it. The other point on which PJM
acknowledged a change might be appropriate is related to incremental auctions
(IAs). The commission asked PJM if it would be appropriate to implement PJM’s
proposal, raised in another docket, to reduce the number of IAs from three to one
as part of the CP rules. PJM reiterated its support for that change and expressed it
would be open to implementing it through either a condition from the Commission
as part of a CP order, or through a determination under the original docket where
it was proposed.
The Commission also asked PJM if a phase-in of the CP penalties, as was
approved for ISO-NE, would be appropriate for PJM. This change is the only
potential revision to CP that PJM argued should not be included. PJM noted that a
transition is already built in to its proposal, and delaying the full incentives needed
to improve performance would work against the objectives of the CP rules.
Finally, PJM provided additional data about historical Compliance Hours and
the average Balancing Ratio during those hours. Those data show that the balancing ratio during compliance hours has averaged approximately 85 percent. However, PJM also noted that the average balancing ratio was lower than it is expected
to be going forward do to a high concentration of Compliance Hours during the
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tex. With the incentives created by CP, better performance is expected in winter
periods going forward and Compliance Hours are expected to be more concentrated in the higher demand peak summer periods, for which the balancing ratio
4
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April 2015
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Capacity WatchTM
27
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FERC will have up to 60 days to response with an order approving or denying
the rule changes. This timeline made it virtually impossible to get the CP rules
approved and implemented for the 2018/19 BRA. PJM continues to express a
strong desire to get CP implemented for the 2018/19 Delivery Year and to that end
it asked the Commission to grant a one-time waiver of the PJM Tariff that would
allow the 2018/19 BRA to be delayed long enough to allow the CP rules to be
implemented, should FERC approve PJM’s proposal. On April 24, the Commission approved the Waiver.
7
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tion. Most generation owners favor CP and therefore supported delaying the BRA
in order to allow the CP rules to be put in place. Opposition to the delay has come
from two groups. First, developers of new capacity expressed concern that a delay
would cause problems in the construction timeline for new resources and could in
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or additional costs to accelerate the construction timeline after the BRA. Second,
load interests that have generally opposed the CP rules have protested the delay of
the auction on the grounds that it will cause too much regulatory uncertainty for no
or very limited gain. Both of these opposing groups asserted that a delay is unnecessary, and that CP resources could still be procured for the Delivery Year though
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acknowledged by PJM, the Commission granted the waiver on the basis that a
timely implementation of CP outweighs the concerns raised by the interveners.
The auction delay may have implications not only for the timing of the BRA,
but potentially for the outcome as well. As will be discussed more in the BRA outlook section below, one of the key factors in determining the price in the next auction will be the level of participation by new capacity resources. Several new generation projects remain in active development for PJM and several are far enough
along in the process that they could be offered into the upcoming BRA, potentially
;"7}
cient to support additional new entry depends largely on whether or not CP is in
place. The fact that forecasted peak load is lower for the upcoming BRA than it
was for the 2017/18 BRA means there is very little room for new capacity to clear
Z6]
;
retirements). The CP rules create a potential opening for new supply by adding
demand (through elimination of the Short-Term Resource Procurement Target, or
767Q
D
;
of penalties.
The fact that multiple developers of new capacity protested any delay in the
BRA indicates two things. First, there may be several projects in line to bid into
April 2015
©
Capacity WatchTM
28
the BRA for 2018/19 that are aggressively trying to move forward and are expecting to clear in the BRA, a potentially bearish factor for the BRA clearing price.
However, the fact that some of these projects may be unwilling or unable to take on
a capacity supply obligation for 2018/19 if the auction is delayed could be a bullish
factor for the auction, regardless of whether or not CP is approved. Some projects
already on a tight timeline for the 2018/19 Delivery Year may now need to delay
participation until the 2019/20 BRA.
FERC Rejects DR Stop-Gap Rules
]
DUgency plan with FERC to allow participation by DR resources in the upcoming
BRA in the event that the legal decision to vacate FERC Order 745 is upheld.
j
:
XH@&6
;
retail markets and therefore under state jurisdiction rather than FERC jurisdiction,
potentially excluding DR from participating as supply in the wholesale markets
(including capacity). PJM’s proposal would have allowed DR to affect the RPM
market through a reduction in demand. In other words, the DR would not be bid
;
\66 ; amount of DR available at various price points. FERC rejected the proposal as
premature. However, the Commission did not express an objection to the concept.
Uj""
D
hear the appeal of the decision of Order 745, DR could be excluded from the next
Z6]
"
Where Do We Go from Here?
The exact path to implementation of CP, or continuation of existing rules for
the next BRA remains far from certain, but there will be several fronts to watch
}
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days of PJM’s April 10 Response. Action by the Commission could be approval
D
;
and protests in the record. Alternatively, the Commission could set the matter for

"
&=
;
of CP, with potential changes as discussed above. In that case, it is very likely CP
could be implemented for the 2018/19 BRA. The aspects of the proposal that are
;
[;D
;;
caps, the number of compliance hours included in the PRR calculation (including potential updates between auctions), the format and timing of the transitional
D
#}6
6
CP.
The timing of the BRA will be linked to the timing of FERC action on the
"
};
]gust 2015. If a FERC order is issued in advance of the mid-June deadline, earlier
implementation of the BRA is possible. An order before mid-May is probably
unlikely, so the BRA is unlikely to occur before late June or July.
April 2015
©
Capacity WatchTM
29
>#%6DD}
draft manuals with more details about the CP rules. Of particular importance is the
potential for using capacity within a given portfolio to cover an underperformance
;
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#%6D
capacity in a portfolio could be used as replacement capacity for underperforming
"7#%6D
}
this type of replacement. However, PJM has indicated it is working on language
for the manuals with will allow use of replacement resources, and that the replacements could be designated after-the-fact, provided they had been available and
performing during a Compliance Event. This provision is important because it
would allow performance by uncommitted resources to offset underperformance
on a MW for MW basis, rather than a dollar-for-dollar basis. If the bonus payment
rate for over-performance is below the PRR, which could occur due to excuses
for underperformance, MW netting provides a much more effective hedge against
penalties within a portfolio.
Market Impacts of CP
The details of the proposed CP rules were discussed in detail in the January
2015 issue of Capacity Watch™. The key aspects of the rules are the following:
April 2015
`
D
;[
;
assessed penalties for under-performance or receive payments for overperformance. Bonus payments are available to CP resources as well as
resources that do not have a CP commitment.
`
=};
and dispatch/scheduling (unlike the ISO-NE rules, which allow no exceptions, even for RTO-approved maintenance outages).
`
A transitional period will be implemented with multiple products (Base
DQ ; D 2020/21 Delivery Year.
`
;
;
emergency conditions (20-50 hours per year expected).
`
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D3;
-
PRR is based on Net CONE, spread over hours of expected emergency
*
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-
Performance is assessed relative to the prorated share of hourly load
¡
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Z6}pected to average 85 percent to 95 percent over all compliance events.
-
Bonus payments for over-performance are funded entirely by penalties for underperformance
©
NEW YORK
Capacity WatchTM
45
SUMMARY
In addition to the New York capacity market forecasts, ESAI presents summaries of a number of developments with impacts on the capacity markets including:
`
NYISO presented its preliminary load forecast in advance of the 2015
Z
"&
tributed generation (solar), peak load outlooks are lower
`
$<>:
to a February 26 FERC order directing NYISO to add a Competitive Entry
Exemption to its buyer-side mitigation rules
`
An evaluation of a forward capacity market concluded that a transition
from the current spot market construct to a forward market is not advisable
at this time
`
The Fuel Assurance program continues to be developed including options
for the inclusion of Performance Incentives
Preliminary Load Forecast - Peak Loads Decline
As outlined in the January issue of Capacity Watch$<>:>D]
market peak load forecast for the 2015/16 Capability Year which sets the ICAP
$<>:
capability period auctions. Table 1 shows the previously issued 2015 peak load
'*HZ
"]$<
D=
Island and G-J localities show growth from the 2014 summer peak load forecast,
each of these areas show declines from last year’s Gold Book forecast for 2015.
$<D]
*"

cast and about a 500 MW drop in peak load relative to the 2015 peak load forecast
issued in the 2014 Gold Book.
Table 1: NYISO Peak Load Forecast for ICAP Market (MW)
Growth from
Change
2014 Gold
2014 Peak
Relative to
2014 Peak
Book Forecast
2015 Peak
Load Forecast
Gold Book
Load Forecast for 2015 Peak Load Forecast
(%)
Forecast (MW)
New York City
11,783
12,050
11,929
1.2%
Long Island
5,496
5,543
5,539
0.8%
-121
-4
G-J Locality
16,291
16,557
16,340
0.3%
-217
NYCA
33,666
34,066
33,567
-0.3%
-499
At the March 20 meeting of the Electric System Planning Group (ESPWG),
NYISO presented its preliminary load forecasts for peak load and energy. Tables
'!H#
![
by NYISO. Each of the load regions is showing both near term and longer term
April 2015
©
Capacity WatchTM
46
;
;
meter distributed generation (largely solar). The new estimates are based on state
programs such as REV (Reforming the Energy Vision) and CEF (Clean Energy
Fund). The preliminary outlooks presented emerged mostly unchanged in the 2015
Gold Book recently released in April.
For NYCA, the 2015 peak load drops by 499 MW but 2016 drops by a further
44 MW, dropping the 2016 load by 899 MW compared to the 2014 Gold Book.
The 2016 to 2018 growth rate drops from 1.0 percent in the 2014 Gold Book to 0.2
percent in the preliminary outlook. The longer term growth rate from 2019 to 2024
drops slightly from 0.7 percent to 0.5 percent.
The New York City peak load outlooks are also lower, but the declines are not
as severe as seen in NYCA. The 2016 to 2018 growth rate drops from 1.4 percent
in the 2014 Gold Book to 0.9 percent in the preliminary outlook. The longer term
growth rate from 2019 to 2024 drops slightly from 0.8 percent to 0.65 percent.
7=>
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next issue of Capacity Watch.
April 2015
©
Capacity WatchTM
47
Table 2 - NYCA Preliminary Peak Load Outlook
z|
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
Figure 1 - NYCA (ROS) Peak Load Forecast
37,000
2014 Gold
Book
2015 NYISO
Preliminary
Delta
34,066
34,412
34,766
35,111
35,454
35,656
35,890
36,127
36,369
36,580
33,567
33,523
33,668
33,760
33,980
34,161
34,316
34,486
34,675
34,867
-499
-889
-1,098
-1,351
-1,474
-1,495
-1,574
-1,641
-1,694
-1,713
36,500
36,000
35,500
35,000
34,500
34,000
33,500
33,000
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
2014 Gold Book
Table 3 - Zone J (NYC) Preliminary Peak Load
z|
2014 Gold
Book
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
12,050
12,215
12,385
12,570
12,700
12,790
12,900
12,990
13,100
13,185
2015 NYISO
Preliminary (Est)
11,929
12,025
12,148
12,251
12,342
12,398
12,478
12,562
12,652
12,744
Figure 2 - Zone J Peak Load Forecast
13,500
Delta
-121
-190
-237
-319
-358
-392
-422
-428
-448
-441
13,250
2015 NYISO
Preliminary (Est.)
Zone J Peak Load
13,000
12,750
12,500
12,250
12,000
11,750
11,500
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
2014 Gold Book
Table 4 - Zone K (LI) Preliminary Peak Load
z|
2014 Gold
Book
2015 NYISO Preliminary
2015 NYISO Preliminary (Est)
Figure 3 - Zone K Peak Load Forecast
6,000
Delta
Zone K Peak Load
5,800
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
April 2015
5,543
5,588
5,629
5,668
5,708
5,748
5,789
5,831
5,879
5,923
5,539
5,517
5,510
5,499
5,516
5,526
5,580
5,642
5,707
5,772
-4
-71
-119
-169
-192
-222
-209
-189
-172
-151
5,600
5,400
5,200
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
2014 Gold Book
©
2015 NYISO Preliminary (Est)
Capacity WatchTM
48
J]J`!?"=!Jj
The NYISO has been discussing the potential for a Competitive Entry Exemption for much of the past two years. Moving things forward late last year was
&;
H'*H#%6D;
D%
NYSEG, Central Hudson, RGE) seeking to modify the tariff to add a competitive
entry exemption to the buyer-side mitigation rules. In its February 26 order (Dock%=@!'Q#%6D
$<>:
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}
to the buyer-side mitigation rules. NYISO later asked for and received an exten
;]
"
New York’s buyer-side mitigation rules seek to prevent buyer-side market
power in which a load serving entity could contract with and support a non-eco

"
The mitigation rules apply to the Zone J and G-J capacity zones. While the buyerside mitigation rules are designed to prevent price suppression from PPA-supported capacity, the current rules apply the mitigation tests to all capacity, including
purely merchant capacity that has no PPA contracts or other subsidy. This means
that a new entrant, including a purely merchant new entrant, must pass either part
or a two tier mitigation test or be forced to offer at the lower of the default offer

X@ D:$%Q ! CONE. FERC’s order does not address the underlying methodology of the exemption test, but rather whether a merchant new entrant should be subjected to the
}
"
NYISO itself was strongly supportive of implementing the competitive entry
exemption sought by the Complainants. NYISO argued that capacity market miti
}
capacity supported by subsidies. Further they argued, that competitive entrants
should not be prohibited from taking risks based on their own projections, even if
their entry does result in lower capacity prices. As a new merchant entrant does not
;
;
;
on their own risk metrics. As FERC notes in its order, the purpose of buyer-side
mitigation is to protect the market against abuse of market power, “not to protect a
merchant resource from making a poor investment decision with its own capital”.
On this basis, FERC had previously approved a competitive entry exemption for
PJM’s mitigation rule known as MOPR (Minimum Offer Price Rule).
Comments from the market monitor were also supportive of the exemption.
The market monitor noted that without such an exemption, buyer-side mitigation
rules may prevent entry of new competitive generation. This can arise when the
new entrant has a view of future market conditions that are inconsistent with the
assumptions that are used in the NYISO mitigation exemption test. TDI commented that its Champlain Hudson Project was such an example of an economic project
that had been mitigated by the NYISO inappropriately, even though it is purely
merchant with no out-of-market contracts or state subsidies.
April 2015
©
Capacity WatchTM
49
Having found that the competitive entry exemption should be included in the
NYISO buyer-side mitigation rules, FERC ordered NYISO to implement tariff
;D
&;
"$<>:
#%6D
;
]
"7 entry exemption are:
`
7
$<>:
!
contractual relationships”, meaning subsidies or out-of-market contracts.
`
7
must be updated at the time of market entry.
`
>
!
on or before its commercial on-line date, the competitive entry exemption
; " = }
!
"
`
If the generator is found to have been granted an exemption based on false
or misleading information, the exemption may be revoked.
`
If a generator exemption is revoked, or not granted, then the generator is
;[$D:$%

;!

"
!"+
NYISO is developing a generator performance incentive initiative known as
the Fuel Assurance program. This program would be in parallel with other initiatives such as Comprehensive Shortage and Scarcity Pricing and Gas-Electric
Coordination that are in place to enhance incentives for increased generator availability during hours when system conditions are tight. NYISO is developing a
performance incentive program that would apply to ICAP suppliers in order to
increase real-time reliability, particularly on days when there are higher risks of
reduced availability due to high demand or fuel supply uncertainties.
The New York performance incentives are still in development but are shaping up differently than similar rules in PJM and New England due to differences
$<
;$<

capable units. The incentives would be available on Critical Operating Days and
is intended to boost performance by committed units on those days through payments for over-performance or penalties for under-performance.
A unit would be included in the Performance Incentive if the unit is:
April 2015
`
An ICAP supplier, and
`
The unit is scheduled in the Day Ahead market for energy or reserve (or
committed as a supplemental resource), and
©
Capacity WatchTM
`
50
$;D
:
&
If a Critical Operating day is declared, the generator’s availability is compared
to a baseline. Over-performance gains eligibility for a payment and under-performance results in a charge to the generator. As in New England and PJM, the New
York program would fund payments to over-performers with revenues collected
from under-performers with distributions to over-performers prorated if collections are short of payments. There are not expected to be any additional direct
charges to load, however, changes in generator behaviors could result in higher
costs to the system as generators price in risk factors etc.
If there are 5 or more Critical Operating days, then the generator could potentially lose its full monthly capacity payment. Otherwise, with fewer Critical Operating days the maximum loss is prorated by the number of days relative to the 5
day limit such that one day of forced outage would not result in a loss of more than
20 percent of the monthly ICAP revenue. In other words, if there are only 2 Critical Operating days, then the maximum loss would be based on a “Scaling Factor”
of 2/5, resulting in a maximum loss of 40 percent of the total capacity payment.
While still in discussion in the ICAP and Market Issues Working Groups, two
directions have emerged as potential mechanisms for the Performance Incentives
calculations:
1. Performance relative to a baseline EFORd
a. The unit would compare its baseline EFORd to an EFORd calculated
during the critical operating days of that month
b. >
}
outage for one full day, then its PI EFORd would be 4/5 or 80 percent
c. If the unit’s long term EFORd was 90 percent, then the unit would be
under-performing and subject to a penalty
d. If the unit’s long term EFORd was 70 percent, then the unit would be
over-performing and would be eligible for a credit payment
2. j
:
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a. A unit would be penalized if operating under the Day Ahead schedule
;jD]Q
b. ]
!
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commitment
c. The unit’s output would be averaged over the critical operating days.
It would not be assessed on individual days
In addition to developing these Performance Incentive mechanisms, NYISO is
also evaluating as part of the Fuel Assurance initiative, new mechanisms to allow
April 2015
©
CALIFORNIA
Capacity WatchTM
62
D
electric utility industry. Issues include the continued assessment of what kind of
resources should be used to replace the 2,200 MW San Onofre Nuclear Plant, the
appropriate role of energy storage in a system increasingly reliant on non-dispatchable renewable resources, dealing with increasing levels of behind the meter solar
;
;
generation. California’s major energy consumers are getting into it as well, with
]
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and other emissions; and,
`
an increasing focus on distribution level resource planning.
SCE’s Local Capacity Procurement – BUGs in the process
The most controversial component of SCE’s local capacity procurement appears to be the 70 MW of demand response from NRG, which would rely on
!;
ZjQ"
DjD
&"H!'!*'HQ}

aversion to the use of technologies, such as fossil-fueled back-up generation” to
;">DjD
>:j
Zj
demand response. It remains to be seen whether the aforementioned “aversion”
;Zj
"
Carlsbad Proposal
A Proposed Decision1 was issued on March 6 that would deny SDG&E authority to enter into a PPA with Carlsbad without prejudice. The application could
;
;&©%=D66#:
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3
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preferred resources exceed 200 MW but not the entire need. The RFO short list is
!"7&D
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percent of which may be from preferred resources or energy storage, in SDG&E’s
=D6
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the CAISO, an alternative proposed decision2 was issued on April 6 that would approve the PPA provided that it is reduced from 600 to 500 MW and that the residual
100 MW must consist of preferred resources and or storage.
1
33"""3;&3%3***3H+3¨'@43H+'@4+"&#
33"""3;&3%3***3@*3¨X43@*X4*@H"&#
2
April 2015
©
Capacity WatchTM
63
Redondo Beach Re-Power Project
Z]]%
]
D
(AFC) of the proposed 496 MW replacement of its Redondo Beach power plant
while it developed a proposal to convert the site to a mixed-use commercial/residential development. The AFC was suspended until April 1, 2015, pending voter
"7;]%
that termination of the suspension be lifted. The AFC is now back in play (though
AES does not have any off-take agreement for the facility.
Preferred Resource Pilot
D%
!
traditional resource solutions to mitigate load growth in Orange County. Based on
feedback from potential offerors regarding problems with Fast Track interconnection applications, SCE has postponed the offer submittal deadline from April 1 to
June 22, 2015. A technical webinar will be held on April 14.
SCE Renewable Procurement
:
DjD;
SCE renewable PPAs totaling almost 1,600 MW. They are summarized in Table 1.
Table 1 – SCE RPS PPA Resolutions
Res
Seller
MW/GWh/yr
COD
Location
Term
E-4703
Nichols (PV)
20/51.51
Dec-15
Vestal Sub
20
E-4703
Tropico
14/36.05
Dec-15
Vestal Sub
20
E-4707
Panoche Vly
247/666
Jan-19
Paicines
20
E-4705
Tribal Solar
328/830
Dec-19
Fort Mojave
20
E-4712
Geysers
225/1,972
Jun-17
Geysers
10
E-4704
Mt. Signal II
154/402
Jun-20
Calexico
20
E-4704
Mt. Signal V
252/660
Feb-19
Calexico
20
E-4704
Copper Mtn
94/256
Jan-20
Boulder City, NV
20
E-4713
Tranquility
206/555
Dec-19
Fresno County
15
E-4713
Borden
51.3/125
Jun-20
Madera County
20
']*]
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solutions that would make the additional capacity available would be both environmentally challenging and very costly, the CAISO evaluated other potential
solutions. It found that by tweaking an operating procedure and revising import
allocations, that total import capacity from Imperial County to the CAISO could
support 1,700 to 1,800 MW of RA capacity.
April 2015
©
Capacity WatchTM
64
San Francisco Peninsula
The CAISO’s Transmission Planning Process has also been considering potential solutions to minimize possible recovery time to restore power to the San
Francisco peninsula in the event of a major seismic event. After analyzing this
; ;; D]>: [

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"7
;
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;
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7
seismic O&M upgrades currently being implemented by PG&E are as effective as
any major transmission project.
Coolwater Lugo Transmission
Continuing the trend of reevaluating the need for major new transmission proj D]>: D
!= project, which was originally approved to provide full capacity deliverability to
the 250 MW Mojave Solar Project. While NRG’s announcement in October that
; @ U D

[;$6
three years to determine whether or not to repower the plant, the ISO determined
that “due to the election by several generating facilities in the area (other than
D
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ity available to provide full capacity deliverability to Mojave Solar and that “the
D
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!=DD$"
New Renewable Procurement Rulemaking
The CAISO issued a new rulemaking R.15-02-0203 to succeed R.11-05-005.
It will provide a forum to lay the groundwork for possible further development of
the RPS program and includes a preliminary scope:
1. D 6"!*@!**@ ; completed.
2. Monitor, review and improve existing elements of RPS program and identify new elements that could be developed.
" >
;
course of proceeding.
4. Consider expansion and further development of RPS program
33"""3DjD
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April 2015
©
APPENDIX
Capacity WatchTM
71
ESAI evaluates individual projects through development and construction and projects the probability of completion
with start-up dates under its Project Evaluation Program (PEP). The projects are then compiled to provide a forecast of new
capacity for each year in each of the three Northeast Control Areas. A spreadsheet provides details of each project and is
;
"7
;
%]>;"];;
spreadsheet is provided below.
ESAI continually updates the PEP as new information becomes available that would affect the timing or probability of
completion of a project. ESAI incorporates a wide array of source information to develop an assessment of the likelihood of
a project moving forward to completion including:
`
Industry Network of Contacts
`
Government Agency Contacts
`
Financial Community Contacts
`
Filings with Transmission Authorities
`
Filings with Siting Commissions
`
Environmental Permits and Filings
`
Municipal Planning, Zoning & Inspector Contacts
`
Other; Media & Corporate Relations
These sources, combined with ESAI’s in-house expertise, allow ESAI to provide its clients with detailed and accurate
information. ESAI closely follows changes in permitting and siting status and makes adjustments whenever necessary.
%]>
!%
"7
vide a recap of the updates as well as the summarized projections for each Control Area.
ESAI
PROJECT EVALUATION PROGRAM
Online
PJM Projects
Linden Uprate
Warren County Power Station
West Deptford
Fourmile Ridge Wind Project
Willow Island Hydro
Meldahl (Captain Anthony Meldahl)
Newark Energy Center
Garrison Energy Center (Phase 1)
Nelson Phase 1
Brunswick County Power Station
Perryman 6
April 2015
Developer
PSEG Power
Dominion
LS Power
Exelon
American Municipal Power
AMP/City of Hamilton
Hess / EIF
Calpine Corp
Invenergy
Dominion
Exelon
Retirement
Pricing
Zone
PSEG
DOM
AE
APS
APS
DEOK
PSEG
DPL
COMED
DOM
BGE
Fuel Type
Nat Gas
Nat gas
Nat Gas
Wind
Hydro
Hydro
Nat gas
Nat Gas
Nat gas
Nat Gas
Nat Gas
Withdrawn
Capacity
(MW)
63
1329
738
40
35
105
735
309
584
1358
120
©
Peaker
(1)
1
1
Probability of
Completion
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
Estimated
In-Service
Date
May
Dec
Dec
Jan
Sep
Dec
Jun
Jun
Jun
Jun
Jun
Year
2014
2014
2014
2015
2015
2015
2015
2015
2015
2016
2015
Capacity WatchTM
73
PJM - Construction Timetable
WINTER
2015
2016
2017
2018
SUMMER
WINTER SUMMER
CC/Other
Peaker
CC/Other
Peaker
Total
Total
2,205
4,915
6,161
1,413
194
11
0
0
2,041
4,428
5,546
1,277
174
10
0
0
2,399
4,926
6,161
1,413
2,215
4,438
5,546
1,277
14,693
205
13,293
184
14,898
13,477
NYCA - Construction Timetable
WINTER
2015
2016
2017
2018
SUMMER
WINTER SUMMER
CC/Other
Peaker
CC/Other
Peaker
Total
Total
658
93
672
986
0
26
0
0
281
92
614
899
0
24
0
0
658
119
672
986
281
115
614
899
2,409
26
1,885
24
2,435
1,909
NEPOOL - Construction Timetable
WINTER
2015
2016
2017
2018
April 2015
SUMMER
WINTER SUMMER
CC/Other
Peaker
CC/Other
Peaker
Total
Total
296
390
925
1,012
0
0
0
317
294
390
866
926
0
0
0
285
296
390
925
1,329
294
390
866
1,212
2,623
317
2,477
285
2,940
2,762
©
Capacity WatchTM
ESAI
75
Online
PJM Projects
Linden Uprate
Warren County Power Station
West Deptford
Fourmile Ridge Wind Project
Willow Island Hydro
Meldahl (Captain Anthony Meldahl)
Newark Energy Center
Nelson Phase 1
Brunswick County Power Station
Perryman 6
Clayville (Vineland)
Moxie Liberty Plant
Moxie Patriot Plant
Woodbridge Energy Center (CPV Shore)
Pilot Hill (K4 Wind Farm)
CPV Saint Charles Energy Center
Wildcat Point Generation Facility
Stonewall Energy Project
Northwest Ohio Wind
Oregon Clean Energy Project
New Covert (Moving from MISO)
Peach Bottom Uprate Unit 2
York 2 Energy Center
Hummel Station (Sunbury)
Lackawanna Energy Center
Bergen Uprate
B.L. England CC
Beech Ridge Expansion
Keys
Roundtop Energy Project
Peach Bottom Uprate Unit 3
Florey Knob IC
Carroll County Energy Center
Good Spring NGCC1
Rolling Hills Generating Station
Hickory Run Energy Station
West Deptford Expansion
Buckeye Wind Project
Hardin Wind I and II (Scioto Ridge)
Fowler Ridge Wind Farm (Phase 4)
April 2015
Developer
PSEG Power
Dominion
LS Power
Exelon
American Municipal Power
AMP/City of Hamilton
Hess / EIF
Calpine Corp
Invenergy
Dominion
Exelon
Vineland Municipal Electric
Panda Power Funds
Panda Power Funds
CPV/ArcLight/Toyota Tsusho
EDF
CPV/Marubeni/Toyota Tsusho
Old Dominion Electric Coop.
Green Energy Partners
Starwood Energy
EIF
Tenaska
PSEG/Exelon
Calpine Corp
Panda / Sunbury
Invenergy
PSEG Power
RC Cape May Holdings
Invenergy
Genesis Power
IMG Midstream
PSEG/Exelon
Florey Knob Energy LLC
Advanced Power
EmberClear / Tyr
Tenaska
LS Power
Calpine Corp
LS Power
EverPower Renewables
Invenergy
Pattern Energy
Retirement
Pricing
Zone
PSEG
DOM
AE
APS
APS
DEOK
PSEG
DPL
COMED
DOM
BGE
AECO
PENELEC
PPL
JCPL
COMED
PEPCO
DPL
DOM
AEP
ATSI
AEP
PPL
PECO
PPL
PPL
PSEG
AECO
APS
PEPCO
PENELEC
PPL
PENELEC
AEP
PPL
AEP
ATSI
DPL
AE
DAY
AEP
AEP
Fuel Type
Nat Gas
Nat gas
Nat Gas
Wind
Hydro
Hydro
Nat gas
Nat Gas
Nat gas
Nat Gas
Nat Gas
Nat gas
Nat gas
Nat Gas
Nat gas
Wind
Nat Gas
Nat Gas
Nat Gas
Wind
Nat Gas
Nat gas
Nuclear
Nat Gas
Nat Gas
Nat Gas
Nat Gas
Nat Gas
Wind
Nat Gas
Nat Gas
Nuclear
Nat Gas
Nat Gas
Nat Gas
Nat Gas
Nat Gas
Nat Gas
Nat Gas
Wind
Wind
Wind
Withdrawn
Capacity
(MW)
63
1329
738
40
35
105
735
309
584
1358
120
63
760
760
700
175
661
1000
778
100
800
1030
142
760
1059
1500
31
570
53.5
775
21.1
142
22
672
330
560
900
309
74
135
300
150
©
Peaker
(1)
1
1
1
1
1
Probability of
Completion
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
90%
75%
60%
60%
60%
50%
50%
50%
50%
50%
50%
50%
50%
30%
30%
30%
25%
20%
20%
20%
15%
Estimated
In-Service
Date
May
Dec
Dec
Jan
Sep
Dec
Jun
Jun
Jun
Jun
Jun
Jun
Mar
Jun
Jun
Mar
Jun
Jun
Jun
Dec
May
Jun
Fall
Jun
Jun
Jun
Jun
Dec
Jun
Dec
Fall
Jun
May
Jun
Jun
Jun
Dec
Dec
Dec
Year
2014
2014
2014
2015
2015
2015
2015
2015
2015
2016
2015
2015
2016
2016
2016
2015
2017
2017
2017
2015
2017
2016
2015
2017
2017
2017
2015
2016
2016
2017
2015
2016
2016
2017
2017
2018
2018
2017
2017
2018
2019
2016
Capacity WatchTM
ESAI
79
Online
NYCA Projects
Danskammer Repowering (Units 1 and 2)
Ravenswood 3-4
Marsh Hill Wind
Standard Binghamton Cogen
Danskammer Repowering (Units 3 and 4)
Astoria 20 Reactivation
Cohoes Falls Uprate (School Street)
Cody Road Wind Farm
Bowline Unit 2 Reactivation
Black Oak Wind
Dunkirk Repowering (Units 2-4)
Bethlehem Energy Center Uprate
Arkwright Summit
Jericho Rise Wind
Delta Hydroelectric Project
Taylor Biomass
Cricket Valley Energy Center
CPV Valley
Astoria Repowering Project
Luyster Creek Energy Project
South Pier Improvement Project
Astoria Unit 40 Restoration Project
Bowline 3 Generation Project
Caithness II
Bowline 2 Restoration
Cannonsville
North Bergen Liberty Energy Center
Monticello Hills Wind
Cassadaga Wind
Castleton (Roseton)
Cayuga Repowering
Copenhagen Wind Farm
Linden Venture
Galloo Island Wind Farm (Hounsfield)
Roaring Brook Wind Farm
NISA Floating Power Plant
Baron Winds
Brookfield Wind Energy
Call Hill Wind
Island Park Energy Center 1 (E.F. Barrett)
Island Park Energy Center 2 (E.F. Barrett)
Franklin Wind
April 2015
Developer
Mercuria
TC Ravenswood
Invenergy
Binghampton BOP
Mercuria
Astoria Gen/USPowerGen
Brookfield
Green Power Energy Holdings
NRG
Black Oak Wind Farm, LLC
NRG
PSEG Power
EDP Renewables
EDP Renewables
City of Watervliet
Taylor Biomass Energy
Advanced Power Systems
CPV
NRG Energy
Tenaska
Astoria Generating Co.
Astoria Gen/USPowerGen
GenOn
Caithness Long Island II LLC
GenOn
NYC DEP
Cavallo Energy LLC
Ridgeline Energy
Cassadaga Wind LLC
Castleton Commodities Int LLC
NRG
OwnEnergy Inc.
Cogen Tech Linden Venture LP
Upstate NY Power Corp.
Iberdrola Renewables
NYC Energy LLC
Baron Winds LLC
NextEra Energy Resources
NextEra Energy Resources
National Grid
National Grid
Franklin Wind Farm LLC
Retirement
Zone
G
J
C
C
G
J
F
C
G
C
A
F
A
D
E
F
G
G
J
J
J
J
G
K
G
E
J
E
A
F
A
W
J
E
E
J
C
E
B
K
K
E
Fuel Type
Natural Gas/Oil
Nat Gas
Wind
Nat gas
Natural Gas/Oil
Nat gas
Hydro
Wind
Nat gas
Wind
Nat gas
Nat Gas
Wind
Wind
Hydro
Biomass
Nat gas
Nat gas
Nat gas
Nat gas
Nat Gas
Nat gas/Oil
Nat gas
Nat gas
Nat gas
Hydro
Nat Gas
Wind
Wind
Nat gas
Nat gas
Wind
Nat Gas
Wind
Wind
Nat gas
Wind
Wind
Wind
Nat gas
Nat gas
Wind
Withdrawn
Capacity
(MW)
120
42.9
16.2
47.7
315
180
10
10
387
11.9
435
58
78
79.9
8
24
1000
650
420
401
88
387
775
752
567
14
940
19.8
126
600
300
79.9
208
244.8
78
79.9
300
100.3
102
243.1
238.3
50.4
©
Peaker Probability Estimated In(1) of Completion Service Date
100%
Sep
1
100%
Oct
100%
Dec
100%
Dec
100%
Dec
100%
Dec
100%
90%
Jul
90%
Jun
75%
Dec
65%
Oct
50%
Jun
50%
50%
50%
40%
Feb
30%
Jun
30%
May
30%
Jun
30%
Jun
1
30%
Jun
30%
30%
Jun
20%
May
15%
15%
Dec
10%
10%
Dec
10%
5%
Mar
5%
Jan
5%
5%
Jun
5%
5%
5%
Nov
5%
Dec
5%
Dec
5%
Dec
1
5%
5%
5%
Year
2014
2014
2014
2014
2014
2014
2017
2015
2015
2015
2015
2018
2017
2016
2017
2017
2018
2018
2018
2017
2016
2017
2017
2018
2017
2018
2018
2016
2016
2018
2017
2017
2016
2017
2016
2015
2016
2017
2017
2019
2017
2016
Capacity WatchTM
ESAI
81
Online
Retirement
Probability
of
Capacity Peaker Completion ESAI Estimated
(%)
In-Service Date
(MW)
(1)
Year
CT
RI
ME
3.71
75
217.987
22
82.39
1.5
3.2
147.6
32
195
90
720
674
15.85
6.68
1.4
22
184.8
51
250
92.5
152.5
185
200
192.5
105.5
20
30
40
NH
ME
NH
SEMA
SEMA
WMA
MA
VT
CT
SEMA
ME
SEMA
NEMA
ME
ME
NH
ME
8.55
22.8
35
340
100
4.8
422
30
42
350
6.8
468
208
38.2
9
3.5
90
NEPOOL Projects
Developer
Fuel Type
Zone
Forbes Street Solar
Berlin Station (Burgess)
MA Solar SREC 1, 2014
Northfield Mountain Uprate, Unit 4
WED Coventry One
Orbit Energy HSAD Biogas
Oakfield Wind
Saddleback Ridge Wind
Medway Peaking
Wallingford Peaker Expansion
Towantic Energy Center
Salem CC
MATEP
Berlin Station (Burgess) Expansion
Southbridge Landfill Gas
Northfield Mountain Uprate, Unit 1
Bingham Wind (Blue Sky West)
Hancock Wind
Number Nine Wind Farm
Fusion Solar
Deepwater Wind
Passadumkeag Mountain
CME/OCI Solar Power
Cate Street Capital
RI
NH
Quantum Utility Generation
Solar
Biomass
Solar
Pumped Stg
Solar
Wind
Biogas
Wind
Wind
Nat gas
Nat gas
Nat gas
Nat gas
Oil
Biomass
Landfill Gas
Pumped Stg
Wind
Wind
Wind
Solar
Solar
Solar
Solar
Solar
Solar
Solar
Wind
Wind
Jerico Power LLC
Patriot Renewables
Essential Power
GenOn
Exelon
MMWEC
Pioneer Valley Energy Center
Iberdrola Renewables
NRG
Brockton Clean Energy
Brookfield
Cape Wind Associates
Exelon
Exergy Development Group
Pisgah Mountain LLC
Jerico Power LLC
Apex Clean Energy
Wind
Wind
Nat gas
Nat gas
Nat gas
Wind
Nat gas
Wind
Biomass
Nat gas
Hydro
Wind
Nat gas
Wind
Wind
Wind
Wind
Jericho Mountain Wind Project
Canton Mountain Wind
Newington Power Expansion
Canal CCGT
Edgar Peaking
Berkshire Wind Uprate
Pioneer Valley Energy Center
Deerfield Wind Project
Montville Unit 5 Repowering
Brockton Power
Wyman Uprate (Units 1 and 3)
Cape Wind
Mystic Expansion
Passamaquoddy Wind
Clifton Wind - Pisgah Mountain
Jericho Mountain Expansion
Downeast Wind
April 2015
FirstLight Power
Wind Energy Dev LLC
Orbit Energy Rhode Island
First Wind
Patriot Renewables
Exelon
LS Power
CPV
Footprint Power
Mayflower
Cate Street Capital
Casella Waste
FirstLight Power
First Wind
First Wind
EDP
HelioSage Energy
Deepwater Wind
Withdrawn
WMA
RI
RI
ME
ME
SEMA
CT
CT
NEMA
NEMA
NH
WMA
WMA
ME
ME
ME
1
1
0.2
1
1
©
100%
100%
100%
100%
100%
100%
100%
100%
100%
90%
90%
90%
85%
80%
80%
80%
75%
75%
75%
75%
70%
70%
70%
70%
70%
70%
60%
60%
60%
Jan
Jun
Jun
Jun
Dec
Sep
Sep
Dec
Dec
May
May
Jun
Mar
Jun
Jun
Jun
Jun
Jan
Dec
Dec
Dec
Dec
Dec
Dec
Dec
Dec
Dec
Sep
Dec
2014
2014
2014
2014
2014
2015
2015
2015
2015
2018
2018
2018
2017
2017
2017
2017
2016
2017
2016
2016
2015
2016
2017
2018
2019
2020
2016
2016
2015
50%
50%
50%
50%
50%
30%
30%
25%
10%
10%
10%
5%
5%
5%
5%
5%
5%
Sep
Oct
May
May
May
Jan
Mar
Dec
2015
2016
2015
2018
2018
2017
2019
2018
2017
2018
2015
2017
2018
2017
2017
2015
2018
Jun
May
Dec
Sep
Oct