PSEG LIPA Resource Study

8/11/2019 PSEG LIPA Resource Study

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Objective and Key Assumptions

Resource Planning: History, NYSRC/NYISO, and LIPA

Planning Results

Findings and Conclusions

Recommendations

Next Steps

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Objective

Recommend which resource planning methodology should form the basis forLIPAs resource needs assessment.

Key Assumptions

No unit in LIPAs current resource base, with minimal exceptions, facesimminent mandatory retirement for operational, environmental, economic orsafety reasons.

No proposed project was singled out for examination.

Results of planning model runs were assumed accurate.

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In NYS: Market restructuring in NYS in the late 1990s and early 2000s was unsettled; market rules,

operating procedures, and planning processes, for example, were far from finalized.

Capacity markets at that time were not fully functional or liquid, particularly on LI (and remain so

today). Demand curve concept not introduced until mid- 2000s. Locational capacity requirements (LCRs) were a new concept and the calculation of LCRs was

rudimentary. For example, LCR calculations at that time (i.e., early to mid 2000s) did not allow for,among others:

Zonal load forecast uncertainty

Ambient temperature deratings of generating units

Tie-line forced outages

Dynamic transmission constraints

Unified IRM/LCR calculations

Multiple load shape considerations

4

LIPAs current resource planning approach reflect antecedents in NYS market restructuring,

LIPA operations, and a management preference for high confidence that sufficient on- island generation would always be available, irrespective of the NYSRC/NYISO criterion.


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On Long Island:

Confidence that the NYISO LCR targets adequately represented on-island resource needs was low inthe early 2000s.

The early 2000s saw on-island capacity resources barely equal on-island demand. Long Island had limited and poor performing inter-ties. Reliability on Long Island had high exposure to a single, major operating event. Lacking effective capacity markets, LIPA felt compelled to install simple cycle gas turbine units on an

emergency basis to meet anticipated demand, thereby spurring LIPA senior management to direct that LIPA plan conservatively for future resource

needs.

Consequently, over time LIPA developed planning methods that it believed reflected itssomewhat unique environment.

The Locational Capacity Requirement (LCR) is a Zone K (Long Island) requirement (i.e., not aLIPA-only requirement).

o LIPA load on Long Island is about 95% of the total Zone K load. LIPA also plans for municipal utilitieson Long Island (Freeport, Greenport and Rockville Center and NYPA load).

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6

1. NYSRC Reliability Rules, Version 33, April 10, 2004, pg. 13-14.

The New York State Reliability Council (NYSRC) Reliability rule A-R1 1 determines and sets the InstalledReserve Margin (IRM) requirement for the New York Control Area (NYCA).

Compliance with the IRM is evaluated probabilistically such that the loss of load expectation (LOLE) ofdisconnecting firm load due to resource deficiencies shall be, on average, no more than 0.1 day per year or 1day in 10 years .

The 0.1 day/year criterion is an industry standard and is used by other RTOs (e.g., PJM, ISO-NE, MISO). The design criterion makes due allowance for demand uncertainty, scheduled outages and deratings, forced

outages and deratings, assistance over interconnections with neighboring control areas , NYS TransmissionSystem transfer capability , and capacity and/or load relief from available operating procedures . (Emphasis inoriginal.)

The criterion incorporate guidelines and procedures of the Northeast Power Coordinating Council (NPCC) andthe standards of the North American Electric Reliability Corporation (NERC).

Reliability Rule A-R2 1 requires LSEs to procure sufficient resource capacity to meet the statewide IRM,and this capacity obligation is distributed so as to meet locational ICAP requirements.

NYSRC evaluates compliance for NYCA and individual zones with the the design LOLE probabilistically viaGEs MARS (Multi -Area Reliability Simulation) Model under security constrained conditions, i.e., allocationof generation and transmission resources to serve the system load with high reliability.

Importantly, both NYSRC rules and IRM studies are subject to a vigorous internal vetting process by allNYISO members/participants and results are adopted by both FERC and the NYS PSC.

However, NYS reliability planning has evolved significantly and now represents a highlysophisticated, comprehensive approach based on an industry standard design criterion.


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The NYSRC and NYISO use what is termed the Unified Method to relate IRM and LCR values.

Any point on the curve meets the LOLE design criterion of 0.1 day/year (i.e., 1 day in 10 years). Depending on which direction movement on the curve occurs, resource dependency shifts between

LIPA/Con Edison and the rest-of-state. The TAN 45 methodology is used to select a point on the curve that represents the location where there

is an approximately equal change in IRM and LCR independent of direction of movement (i.e., where thedotted red line touches the blue curved line).

2: Source: NYSRC Policy 5-7, Appendix B, PSEG Long IslandInstalled Reserve Margin (IRM) %

@ TAN 45

L

o

C

yR

reme

LC

% Minimum Flow EquivalentMaximum Possible LCR at Lowestpossible IRM

IRM-LCR CurveDynamics 2

Unified Method withTan 45 Anchor Point

Maximum Flow EquivalentMaximum Possible IRM at lowest possible LCR


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LIPA must plan to meet two NYSRC/NYISO planning criteria an Installed Reserve Margin

(IRM), and a zonal, or locational, capacity requirement.

* The LCR is expected to decline by approximately 3.0% in 2015 with the Danskammer generating units anticipated return to s ervice.

3. Source: LIPA Board of Trustees Briefing, February 25, 2010, pg.8; PSEG Long Island.

Proportional Share of a Statewide InstalledReserve Margin (IRM) Requirement 3

Determines how much total capacity on andoff island - LIPA must have.

Set annually for the upcoming planning yearby the NYSRC.

Calculated using GE MARS, a probabilistic,security (i.e., transmission) constrained model.

Statewide, there must be at least enoughcapacity to meet the combined projected loadof all utilities, plus the IRM.

Currently, the IRM is 17% for the period fromMay 1, 2014 to April 30, 2015.

The IRM requirement is allocated to each loadserving entity in proportion of its peak load toNYCA total peak load.

Zone K Locational Capacity Reserve (LCR)Requirement 3

Due to transmission constraints, Zone K(Suffolk, Nassau and Far Rockaway) must beable to serve the specified percentage of its

load from resources qualified as on-islandresources.

The LCR is set annually for the upcomingplanning year by the NYISO. It is calculated bydividing required on-island designatedresources (MWs) by forecasted peak load (MWs).

The LCR is calculated using the same modeland methodologies used to determine the IRM.

LIPAs LCR for the planning year May 2014 toApril 2015 is 107%*. That is, LIPA must haveon-island resources equivalent to 107% of theNYISO approved peak load for Long Island.


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Probabilistic (LIPA) - 80th percentile confidence level : Needs assessment projections reflectthe 80th percentile results (i.e., conservative results) from LIPAs internally developedprobabilistic model based on customized probability distributions of key variables (e.g., loadforecast, energy efficiency program targets, unit rating variability).

Probabilistic (NYISO) *: Results reflect the use of the NYISO-approved inputs** and target LCR,

coupled with existing resource supply to determine resource need.

OPCAP-C: An alternative planning criteria that takes into account specific operationalconditions and contingencies. It does not account or allow for LCR, LOLE or IRM requirements.

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LIPAs preferred methodology for making reliability and resource decisions is to use the Probabilistic(LIPA) model.

OPCAP-C was used for a few years but was superseded by the development of the Probabilistic(LIPA) model around 2005.

The Probabilistic (NYISO) methodology provides the basis for Probabilistic (LIPA) resourceplanning with LIPA choosing to plan to the 80% percentile confidence level.

LIPA can use, or has used, different methodologies to determine anticipated resource needs.

* IRM and LCR targets are developed through application of the Probabilistic (NYISO) methodology.** In 2014 the NYISO decided to use its own peak load forecast for Zone K, which is very similar to LIPAs forecast for Zone K f or the first five years, but then

grows more slowly.


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LIPAs probabilistic model uses the NYISO probabilistic model as its base case

4. 2012 NYISO Reliability Needs Assessment, pg. 35, 39.

LIPA uses an internally developed probabilistically-based model for resource planning. The model, similar to NYISOs, contains sufficient functionality to produce results adequate for the

purposes of long-term planning; results, however, are driven by the value of assumptions used.

The model contains over several hundred individual variables, each with probabilistic distributions.

The model assumptions are not the same, in all cases, as the information/assumptions that LIPAprovides to the NYISO for IRM and LCR purposes (e.g., load forecast, SCRs, planned effects of theEfficiency Long Island (ELI), EFORds).

Under NYSRC Reliability Rules AR-1 and AR-2 LIPA must plan to meet the LCR requirement asdetermined by the NYISO for the upcoming planning year.

Meeting or exceeding the LCR target achieves, by definition, a lower LOLE than the NYCA designstandard because the NYCA LOLE is, essentially, a sum of zonal events (i.e., each zone has acalculated LOLE that is less than the NYCA LOLE.) LIPAs current or as - is LOLE is 0.001 day/per

year, or 1 day/1000 years .)

The NYISO/NYSRC estimates of resource needs for each zone are based on projected reliability andsecurity needs and targets. LIPA is not projected to exceed an LOLE of 0.1 day/year until 2022 butmay need to add capacity in 2020 to ensure that NYCA satisfies the design criterion. 4


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The relationships of the various planning methodologies to each other and to the

NYISO/NYSRC is reasonably direct, as shown in the simplified illustration.

LIPA Load Fcast

NYISO LoadForecast

NYISO ApprovedLoad Forecast

LIPA ResourcePortfolio NYISOProbabilities

TransmissionTopology

NYCA LOLEDesign Criterion

GE MARS Model

Other inputs e.g.,Tie-line support,

other TO data

InstalledReserve Margin

(IRM)LIPA LCR

Prob. (NYISO) Prob. (LIPA) OPCAP-C

Planning Models/Approaches

LI centric Not influenced by

LOLE, IRM or LCR. Focus is on major LI

contingencies. Results in needs

assessment close to

Probabilistic (NYISO).

Uses modified LIPA peakload forecast submitted toNYISO.

Modifies other variables,e.g., EFORds

Needs assessment moreconservative than design

criterion requirement.

Uses LIPA peak loadforecast submitted toNYISO.

Needs assessmentconsistent with designcriterion.

Unified Method/Tan 45


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The Probabilistic (NYISO) and Probabilistic (LIPA) approaches to determining base case LIPA

resource needs are similar in some respects but also have fundamental differences.Probabilistic (NYISO) Probabilistic (LIPA)

Inputs

Probability distributions of key variables (more expansivethan LIPAs)

E.g., load forecast and growth, resource level andperformance (e.g., EFORds), load shapes, external(other RTOs) support, load relief from operatingprocedures, etc.

Developed by NYISO/NYSRC in conjunction withmarket participants

Known additions/retirementsSensitivity analyses performed on key uncertaintiesConsiders Special Case Resources (SCR)

Starts with LCR/IRM (from NYISO) as inputAdditional probability distributions of certain keyvariables are added on top of ISO Probabilisticassumptions

E.g., load forecast and growth, resource level andperformance (e.g., EFORds), etc.

Developed by LIPA

Known additions/retirementsExcludes Special Case Resources (SCR)

Engine/Approach

GE MARSDeveloped by GEIndustry standardSecurity (i.e., transmission) constrained capability

TAN 45 Unified MethodDevelops LCR/IRM relationship

Market ManagerInternally developedExcel based, At- Risk add -onNot security constrained

Design Criterion LOLE of 0.1 day/year Meet LCR target at a high targeted (80%) confidence level

Outputs Annual LCR and IRM Long Term Resource Needs Assessment

Long-term probability based distribution of needsassessments

Confidence level tables of needs assessments High confidence level indicates a process that

satisfies a high level of worst case contingencies

Needs Assessment

Surplus/deficit = [Resources - (LCR x base case loadforecast)]Equivalent to ~30th to 40th percentile results from LIPAsProbabilistic model output.

LIPA uses 80th percentile confidence level results: i.e.,High confidence

Accounts for 80% of all possible resource needsoutcomes produced by the model, equates to ~1/250yr. LOLE.


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Irrespective of methodology, resource needs are determined by a simple equation:

Resource Need +/-) = Resource Supply LCR x Peak Load Forecast)

The major driver of the difference in resource needs results obtained using the probabilisticmodels of NYISO and LIPA is that LIPA allows for inclusion of additional uncertainty over and abovethe uncertainty already embedded in NYISO calculations.

This uncertainty primarily manifests itself in the fact that the peak load forecast used in LIPAs

probabilistic model is not the same as the peak load forecast submitted to the NYISO for reviewand approval.

LIPA adjusts the peak load forecast that it submits to the NYISO by discounting the effectiveness ofits energy efficiency programs, including ELI, thereby increasing forecasted peak load. (LIPA hadpreviously discounted the effectiveness of ELI prior to submittal to the NYISO but discontinued thepractice of discounting in 2014 due to the programs experience. However, the Probabilistic (LIPA)model continues that discounting practice.)

LIPA also does not include Special Case Resources (SCRs) as a resource in its models, while theNYISO does.

LIPA also adjusts the resource supply by applying model-specific distributions of unit parameters,such as unit ratings; adjustments that, to some degree, have already been accounted for in the theGE MARS model and reflected in the the NYISOs Resource Needs Assessment (RNA) target .

LIPA uses, as previously noted, the 80th percentile confidence level of model results.


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Variations in actual peak loads vs. projected peak loads have been substantive (above and belowprojections) and largely have been weather driven...but LCR calculations allow for variations in weather normalized peak load.

LIPAs peak load forecasts trend very closely with weather normalized peak loads indicating a highdegree of forecast accuracy. (Statistically, the median absolute percent error (Median APE) is verylow, 0.5%., or less than 30 MW)

5,000

5,100

5,200

5,300

5,400

5,500

5,600

5,700

5,800

5,900

6,000

2007 2008 2009 2010 2011 2012 2013

Z

KP

Lo

-MW

Historic Peak Loads

Weather Adjusted

Projected

Actual Load

Source: PSEG Long Island Transmission and Distribution Planning, NYISO Load and Capacity Data (Gold Book), 2006 2013


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There are long-term differences in projected peak load forecasts developed by LIPA and

submitted to NYISO for approval and those used in the Probabilistic (LIPA) resourceplanning model.*

5. Long Island Resource Needs Assessment, May 2014 Update, June 19, 2014.

* In 2014 the NYISO decided to use its own peak load forecast for Zone K, which is very similar to LIPAs forecast for Zone K for the first fiveyears, but then grows more slowly.

NYISO

LIPA Submitted

Probabalistic (LIPA)

OPCAP-C

5,000

5,200

5,400

5,600

5,800

6,000

6,200

6,400

6,600

6,800

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Z

KL

F

e

-MW

Load Forecasts 5

NYISO Approved


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Actual supply margin above target LCRs can be expected, to some degree, since resourceadditions/removals can be lumpy and the LCR target is represents a minimum resource threshold.

Consistently high differences, however, reflect a trend that results from LIPAs determination to embedmore conservatism in its needs assessments.

90

95

100

105

110

115

120

125

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

LC

%

Zone K Location Capacity Requirements (LCR)

ForecastedHistorical

NYISO Target

Actual Supply Margin

Probabilistic (LIPA) - Danskammer In

Probabilistic (LIPA) - Danskammer Out

Probabilistic (NYISO) - Danskammer In

Probabilistic (NYISO) - Danskammer Out

Since 2006 LIPAs actual supply margins* have been consistently above target LCRs,

sometimes significantly so, and are projected to remain above target in the future.**

* Available on-island resources divided by forecasted peak load.** Forecasted Probabilistic (LIPA) LCRs = [Projected Probabilistic (LIPA) resource levels] divided by [LIPA load forecast]

Source: Long Island Resource Needs Assessment, May 2014 Update, June 19, 2014.


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LIPA LCRs have varied over time for a number of reasons, some of which are under LIPAs

control, such as election of Unforced Delivery Rights (UDRs) over transmission tie lines.

PlanningYear LCR (%)

Delta*(%) Drivers**

2008 - 2009 94 (5) Addition of Neptune HVDC line (-), increased availability of generating

units and cable interfaces (-).

2009 2010 97.5 3.5 Increase in generating unit EFORs (+), less assistance from PJM (+), lower

MWs from EOP (+), higher peak load forecast (+)

2010 2011 104.5 7.0 Increase in generating unit EFORs (+), poorer performance from SCRs (+),

less assistance available on HVDC lines (i.e., election of UDRs associatedwith Marcus hook) (+)

2011 - 2012 101.5 (3) Decrease in EFORs (-), increased transfer capability from M29 project (-),

greater amount of assistance from New England (-)

2012 - 2013 99 (2.5) Anticipated better performance from SCRs (-), a 1.2% drop in LI load

forecast uncertainty (-)

2013 - 2014 105 6

Addition of HTP (-), lower LI load forecast uncertainty (-), changed EFORdcalculation methodology (-); adopt fixed SCR values (+), increased LI unitEFORds (+), increased EFORs on subterranean cable (+), lower assistancefrom nearby control areas (+), Danskammer retirement (+)***

2014 - 2015 107 2 Adoption of new load shape model (-), reduced SCR response (+),

increased EFORd LI generating fleet (+), less assistance from ISO-NE (+)

* Change from previous year.** Sign convention: lowers LCR, (-); increases LCR, (+).*** If Danskammer is reactivated in 2015, as expected, LIPAs LCR will decrease about 3%.


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The IRM/LCR process has matured and, consequently, the risk of a large change in annual values due to changesin methodology, database errors and other calculation anomalies has been greatly diminished.

A decline in LCR does not present a problem.

Due to the lumpiness of capacity additions LIPA will always be projected to be above the minimumrequirements; it is reasonable to anticipate that some degree of excess capacity will be available.

Many large LCR swings are due to LIPA-controlled decisions (election of UDRs, LIPA policy decisions)

System changes such as units retirements require ISO studies and will only be allowed to the extent reliability

criteria is satisfied. RMR contracts may be required to offset reliability impacts.LIPA Resource Planning does not consider SCRs, which equate to ~80 MW of added buffer beyond LIPAProbabilistic model results. Also, the possibility of entering into additional UDRs over the Cross Sound Cablerepresents an additional potential margin of ~92MW. A further additional ~55 MW of energy output beyond unitCapacity Resource Interconnection Service (CRIS) Rights ratings is available in an emergency and potentiallycould be converted to firm capacity with appropriate studies.

While never planning to be deficient, there are options, and an unforeseen large Increase in LCR can bemanaged.

As a stop gap measure, LIPA can work with the NYISO to purchase additional IRM to make up for an LCR shortfall thishas been done before. Due to market structure, LIPA is somewhat financially indifferent as it is both the LSE andresource supplier. (LIPA will get back 95 of every dollar of the deficiency penalty because it has approximately 95% ofthe load in Zone K.)

Emergency Generators: This has been done before by LIPA - 96 MW in 2004-2007 of Cummins Diesel EmergencyGeneration.

PSEG PM verified that interconnecting infrastructure is virtually entirely intact at Shoreham and Holtsville.

Roughly $10-20 M cost for 100 MW.


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Curtail Company use

Public Appeals

Voltage reduction

Curtail Con Edison wheel

Emergency support (NYISO)

Emergency support (ISO-NE)

NYISO Special Case Resources (SCRs) in LICA (day-ahead)

Load shed

Along with an ability to manage LCR volatility, LIPA has a variety of measures to manage

operational volatility. These measures include the following:

While there is always the possibility, by design, of the loss of load due to a resource shortfall, theprobability of such a shortfall is low and is subject to mitigation through numerous potential actions.


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LIPAs probabilistic approach to resource planning has resulted in greater than needed

capacity reserves vis a vis the reliability design criterion of 0.1 days/year which can, to someextent, provide support to the rest of NYCA.

Both NYCAs and LIPAs as - is conditions reflect high levels of capacity reserves,

hence low LOLEs relative to the design criterion of 0.1 day/yr, or 1 day/10 years. The NYISO Criterion LOLE reflects what NYCA designs to and what LIPA would

achieve if it closely met the LCR projection.

The 80th percentile planning criteria indicates what LIPAs LOLE would be if thatmethodology were followed and, because of the relationship between LCR and IRM,the projected impact it would have on the design criterion for the rest of NYCA (i.e.,lowering it from 0.1 to 0.06)

Note: As is represents a snap - shot of current system conditions. Small percentage increases or decreases inreserves relative to total supply may significantly impact reliability criterion results (i.e., day/years).


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Source: NYISO 2012 Reliability Needs Assessment, Pg. 35.

Resource additions in NYS, possibly in Zone K, would likely be required by 2020 to ensure thatNYCA as whole stayed below the LOLE design criterion of 0.10. (An updated RNA, due in fall2014, could show an advanced resource need in Zone K).

Note: Refer to Map of NYCA Load Zones provided in Appendix. A 0 represents an LOLE of less than 0.001. AnLOLE value of 0.00 represents a rounded value such as 0.001 through 0.004.

The base case of the most recent NYISO Reliability Needs Assessment (2012 RNA) shows

that LIPA (i.e., Area K) is not projected to exceed the NYCA design LOLE of 0.10 days/yearuntil 2022 under base case conditions.


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Probabilistic (NYISO) and OPCAP-C approaches result in similar short and long-term

needs assessments*; Probabilistic (LIPA) needs assessments are significantly greater thaneither the NYISO or OPCAP-C approaches, in both the short and long term.

* The current probabilistic NYISO resource need date for Zone K of 2020 is advanced relative to the 2013 RNA.Source: Long Island Resource Needs Assessment, May 2014 Update, June 19, 2014.

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Probabilistic (NYISO) 148 241 211 135 69 (9) (99) (231) (330) (436) (546)

Probabalistic (LIPA) 118 9 (160) (256) (341) (439) (551) (718) (832) (979) (1,100)

OPCAP-C 281 218 193 124 65 (5) (86) (171) (261) (357) (457)

(1,200)

(1,000)

(800)

(600)

(400)

(200)

0

200

400

L

sa

R

o

cS

pu

N

-MW

Long Island Resource Assessment - with Danskammer


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Following deregulation the NYISO and FERC established a demand curve to incentivize newgeneration to locate in NYS and LI/NYC localities.

Prices based on level of surplus/deficit resources relative to LCR.

As zone approaches capacity deficiency, capacity prices increase to support new unitdevelopment.

If an area is substantially overbuilt relative to requirements, capacity prices collapse.

LIPA probabilistic criteria has led to excess supply margins* (up to ~1000 MW beyond NYISOrequirement).

Low capacity prices on LI are a disincentive to new generation development.

Requires LIPA to support new capacity suppliers with long term PPAs to incent capacitydevelopment.

LIPA ratepayers assume risks traditionally borne by merchant suppliers in deregulated power

supply market.Con Edison has not signed a PPA for new capacity since the early 2000s. Over 3000 MW ofnew capacity has been developed in Zone J without Con Edison ratepayer commitments.

The resulting high percentage of long-term bilateral capacity contracts impedes viability ofLIPA retail choice programs by removing liquidity from the LI capacity market and ESCOsability to make money.

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* See Appendix for illustrative rate impact analysis.


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LIPA has not experienced resource shortfalls or reliability issues during the use of its probabilisticmodel

however, the model , by design, projects a need for higher levels of on-island resources thanwould be required using only the NYISO-developed criterion or the OPCAP-C approach.

The current LCR calculation methodology (i.e., Unified Method/TAN 45) represents a much moresophisticated approach than was employed in the early 2000s and is approved by both FERC andthe NYS PSC.

Actual achieved LI resource levels (2005 - 2013), on average, have been significantly higher (over500 MWs) than NYISO-approved LCR levels.

In addition, projected target resource levels using the Probabilistic (LIPA) methodology are expected tocontinue to be significantly higher than target LCRs using LIPAs base case load forecast.

Low market capacity prices on Long Island are a disincentive to merchant generation development.

LCRs, while subject to some volatility, are considered manageable and are not anticipated tochange substantially from current levels absent significant system changes.

LIPAs base peak load forecast, a key input into resource need calculations, closely tracks weathernormalized peak loads.


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The LOLE for all NYCA zones must be, by definition, below the NYCA target of 0.1 days/year, therebyimplying a greater level of resource adequacy in each zone than NYCA overall.

Zone K (Long Island) is not projected to exceed the design LOLE until 2022, or have a resource need until2020, under the NYISOs 2012 Resource Needs Assessment base case.

Planning should always be based on the need to meet NYSRC/NYISO requirements, but not meetingthe LCR target does not necessarily mean that reliability is compromised.

LIPA is the only utility in New York state that explicitly uses a more conservative planning criteria thanthat mandated by the NYISO/NYSRC .

Using the NYISO design criterion will bring LIPA in alignment with other NY state utilities and willreduce the implicit dependence that the rest of NYCA and interconnected regions enjoy by havingLIPA effectively design to a criterion well below 0.1 days/year.

A planning approach based on the NYSRC-approved LOLE and NYISO-developed LCR delays theprojected need for new capacity resources approximately 3 years (from 2016 to 2019) in comparisonwith the Probabilistic (LIPA) approach.

Inclusion in the planning process of the effects of Special Case Resources (SCRs), Utility 2.0 projectedimpacts, and the election of available Unforced Deliverability Rights (UDRs) would push out the need datean additional 2 3 years, to 2022.

There is essentially no LI merchant development activity in the generating sector and, effectively, nocompetitive wholesale power market. (Largely driven by capacity oversupply and full reliance onPPAs).


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LIPAs current planning approach (i.e., Probabilistic (LIPA)): allows for greater uncertainty than what is embedded in the NYSRC/NYISO methodology.

indicates greater resource needs than are identified using the NYCA designated design criterion.

reflects antecedent events in the early 2000s (i.e., relative geographic isolation and substantialuncertainty in supply adequacy, which supported a degree of conservatism) that is no longerapplicable, or at least not as relevant under current circumstances.

The NYSRC/NYISO planning approach is based on industry standards, conservative assumptions,

and forms a sound basis for LIPA long-term planning.

Adoption of the NYSRC/NYISO planning criterion is consistent will all other NYS utilities;therefore, based on historical performance, adoption is unlikely to lead to reliability impacts.

The use of the Probabilistic (LIPA) approach for resource planning compared with theProbabilistic (NYISO) approach will require hundreds of additional MWs of generation and, bydefinition, lead to near-term rate impacts.

A delay of 12- 18 months of LIPAs current resource plan presents no demonstrable risk to LongIsland reliability.

Increases in load or decreases in supply would be addressed by measures to preserve reliability andmeet NYISO requirements.

Power Market opportunities at both the wholesale and retail level will be identified through theIntegrated Resource Planning Process.


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PSEG Long Island should adopt the NYISO planning criterion for resource needs assessment.

The NYISO planning process has matured and become highly sophisticated over the last decade.

NYISOs probability analysis is sufficiently robust.

NYISO adopts conservative values for many key variables, such as availability of external (to NYCA) assistance.

The design criterion is consistent with that u sed by other NYS utilities, reflects the standards and guidelines of NERC and NPCC, and is approved byboth FERC and the NYS PSC.

Re-task Phase 2 of this process to perform a full Integrated Resource Plan (IRP), expected to be concluded byend of 2015.

Public outreach and input to be solicited.

Delay commitments on all current RFPs excepting those with existing, binding agreements and/or immediateneeds:

2010 Generation and Transmission RFP (Caithness selected), 2013 GS&DR RFP in progress, 280 MW RFP (Renewable)-in progress

Suspend payments on Iroquois pipeline but continue OSC/AG approval process.

Suspend any significant expenditures for Article 7 process for Caithness, Barrett Peaking Units and Barrett Steam Repowering,maintain optionality at minimal expense.

All RFPs listed above, should continue to be reviewed and short listed as appropriate.

Specifically address issues on the the eastern end of the island with Utility 2.0 or Block 1 of GS&DR RFP.

PSEG Long Island condition assessments of National Grid generating units is pending. However, review of performance data anddiscussions with NG staff do not indicate any signi ficant near-term performance related or environmentally mandated changes to thecurrent generating unit portfolio. [See Appendix 6 for related data].

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Short-Term

Develop IRP plan and schedule.

Perform detailed condition assessment of capacity resources.

Validate use of existing RFPs and/or initiate new RFPs, if appropriate.

Further consideration of transmission solutions on par with on-islandgeneration options.

Consideration of Utility 2.0 and UDRs.

Longer TermReview contracts for energy pricing improvements.

Conduct study for opening a fully competitive capacity market for Zone K.

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Interviews, Data Review and Analysis

Rate Impact

Map of NYCA Load Zones

Footnotes

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Multiple Interviews with LIPA Staff

Multiple Interviews with PSEG Long Island Staff

Interview with NYISO Vice President of Planning

Interview with National Grid Staff

Documents reviewed and analyzed included, among others: LIPA Electric Resource Plan 2010-2020

LIPA Strategic Plan, supporting documentation and presentations

NYISO Load and Capacity Data (Gold Book) various

NYSRC New York Control Area Capacity Requirement, May 2014 April 2015 (December 2013)

NYSRC Policy 5-7, Procedure for Establishing New York Control Area Installed CapacityRequirements, April 2013

PSEG Long Island IC Resource Needs Assessment May 2014 Update Final

NYISO Reliability Needs Assessment, 2012 NYSRC Reliability Rules, April 2014

NYISO Reliability Planning Process Manual, June 2014

NYISO Installed Capacity Manual, May 2014

NYISO Load Forecasting Manual, September 2014

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2005-2013 Average LIPA capacity excess over NYISO LCR was 528 MW

Probabilistic (LIPA) methodology results in approximately 400 MW in excess ofNYISO LCR (2018)

LI net capacity cost ~ $285/KW-Year (2018)*

NYISO Rest of State capacity price forecast: $65/KW-Year (2018)

Cost of 400 MW oversupply is approximately $88M/year, or an approximate 2%rate impact.

($285/kw-yr. $65/kw-yr.) x 400 MWs = $88million/year

LIPA revenue requirements = ~$4 billion/yr. (2018 estimate)

Rate Impact = (~$88 million/~$4 billion) = 2.2 percent

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A high level estimate of the rate impact of LIPAs projected excess supply, over and above

that required to meet the LCR requirement, results in a measureable impact on rates.

Derived from RPCC Benchmark file and Caithness II study for energy offset.


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A - WESTB - GENESEC - CENTRLD - NORTHE - MHK VLF - CAPITLG - HUD VLH - MILLWDI - DUNWODJ - N.Y.C.K - LONGIL


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1. NYSRC Reliability Rules, Version 33, April 10, 2004, Pg. 13-14

2. NYSRC Policy 5-7, Section 3.1 and Appendix B

3. LIPA Board of Trustees Briefing, February 25, 2010; PSEG Long Island update,pg. 8

4. NYISO 2012 Reliability Needs Assessment, pg. 35, 39

5. Long Island Resource Needs Assessment, May 2014 Update

6. National Grid Generating Units, June 27, 2014. Pg. 11-12, 17-19, 27.

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