1

Review of Cayuga Repowering Options

Prepared by:

David J. Lawrence

Pinewood Power Solutions LLS

Ricardo J. Galarza

PSM Consulting, Inc.

June 25, 2013

Introduction

The New York State Public Service Commission (“Commission”), as part of Dockets 12-E-0400, Petition of

Cayuga Operating Company, LLC to Mothball Generating Units 1 and 2, and 12-E-0577, Proceeding on

Motion of the Commission to Examine Repowering Alternatives to Utility Transmission Reinforcements,

is currently engaged in reviewing and deciding upon solutions to reliability issues associated with the

intended mothballing of the Cayuga power facility. Pinewood Power Solutions LLC (PPS) has been

retained by the Sierra Club, a Party in the aforementioned Commission proceedings, to review the

materials submitted in both dockets and to provide technical recommendations on the proposed

repowering alternatives. PSM Consulting, Inc. (PSM) has been retained as a subcontractor by PPS to

perform power flow analyses as needed to further understand the technical issues surrounding the

repowering alternatives. This report is issued jointly by PPS and PSM (“the Consultants”) and provides a

high-level summary of the Consultant’s findings, offered to further the understanding and resolution of

reliability issues surrounding the retirement of the Cayuga facility. The curricula vitae of the principals

associated with PPS and PSM are included in Attachments F and G of this report.

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Reliability Issues Associated with the Mothballing of the Cayuga Generating Facility

In its report on repowering alternatives,1 New York State Electric and Gas (NYSEG) identifies several

potential adverse reliability impacts associated with the loss of the Cayuga generating facility:

A thermal overload of the 336 ACSR conductor in the Elbridge to State Street 115 kV Line #972

under all facilities in-service system conditions at a local area load level of 135 MW, which is

approximately 73% of the projected 2012 summer peak load (221 hours, 2011).

Loss of The Quaker Road to Sleight Road 115 kV line #980 will cause the conductor in the #972

line to exceed its summer Long Term Emergency ("LTE") rating at a local area load level of 120

MW, which is approximately 65%o of the projected 2012 summer peak load (505 hours, 2011).

Loss of the Clinton Corners to State Street 115 kV line #971 will cause the conductor in the #972

line to exceed its summer LTE rating at a local area load level of 138 MW, which is

approximately 75% of the 2012 projected summer peak load (170 hours, 2011).

NYSEG’s Proposed Transmission Solutions are Appropriate to Relieve the Identified Reliability Issues

To eliminate the identified overloads, NYSEG proposes the following transmission solutions:2

Constructing a new 14.5 mile, 115 kV line from National Grid's Elbridge Substation to NYSEG's

State Street Substation

Rebuilding the existing 14.5 mile, 115 kV line from National Grid's Elbridge Substation to

NYSEG's State Street Substation

NYSEG has indicated that completion of the above-noted transmission projects is anticipated to occur by

mid-2017.

As will be evident from the powerflow analyses discussed below and included in Attachment B, for the

simulated contingencies, the only facility that is subject to overload is the State St-Elbridge #972

transmission line. Once the generation at Cayuga is removed, the transmission topology in the general

vicinity of Auburn is essentially radial, with generation from remote generating units feeding a series of

loads that ultimately terminate in the Cayuga/Auburn area. The overloads identified under normal and

contingency conditions are symptomatic of a weak link (relative to other transmission facilities) in the

series transmission topology. As part of NYSEG’s analysis, no low voltage problems were identified

associated with the removal of the Cayuga facility, indicating that excessive var consumption is not an

issue. Regardless of the status of the Cayuga facility, the State St-Elbridge #972 line will continue to be

the weakest portion of the transmission system in the Auburn area and is subject to overload in the

1 Report on Cayuga Repowering Analysis (Public version), May 17, 2013 pp.5-6. Available at:

http://documents.dps.ny.gov/public/MatterManagement/CaseMaster.aspx?Mattercaseno=12-E-0577 2 Ibid., pp. 6-8.

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future. As standard utility planning procedure, upgrading the transmission facility is appropriate, as is

the decision to build a parallel transmission line. The solution proposed by NYSEG will significantly

increase the thermal capability of that portion of the transmission system feeding the Auburn area, and

should be chosen as the best long-term solution to the identified reliability problems.

An Alternative to Keeping Both Cayuga Units On-Line is Proposed

While we recommend that, in the longer term, a transmission solution is the correct one for the

reliability issues noted, there will still be a need for an interim solution for the period beginning in mid-

January 2014 until the transmission projects are completed, estimated to be mid-2017.3 We do not

believe that keeping both Cayuga units in service through an RSS contract until mid-2017 is the only

solution, nor is it the most cost-effective solution for consumers. In the following sections, we will lay

out first from a technical standpoint the opportunities afforded by reasonable levels of demand

response, then the cost per kilowatt-month rationale for such a solution, together with only one Cayuga

unit, and why that solution is preferable to keeping both Cayuga units in service.

Demand Response Potential Based Upon NYSEG’s Load-Duration Curve for the Auburn Area

To determine the level of demand response that could be effectively used to address the reliability

problems noted in the NYSEG repowering report, we constructed the load-duration curve for the

Auburn load area from data provided by NYSEG. The local Auburn load can be approximated by

summing up (with the proper power flow direction) the loads on the following buses:

Using peak load forecasts for the Auburn area, we determined a load-duration curve based upon 4

actual data for the identified buses, for the period July 1-September 1, scaled to the 2017 summer peak

load of MW (see Attachment A). We used 2017 as the target date, given that the second phase of

the NYSEG transmission solutions are anticipated to be completed by mid-2017. Based upon past

experience with the New York Independent System Operator (NYISO) demand response programs, use

of demand response for hours or less over the summer period provides the greatest opportunity for

participants to respond, with minimal fatigue (reduced ability to provide load reduction due to repeated

requests over time). Based upon the Auburn load-duration curve, load drops from MW in the peak

hour to approximately MW in the hour, indicating a realistic demand response potential of 25

3 Id., 7.

4

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MW. Essentially, if 25 MW of load can be reduced through a demand response program, and these

loads would normally be consuming during the top hours of load in the Auburn area, the forecasted

peak load would not exceed MW. The slope of the load-duration curve beyond this point flattens

out, so that if one were to consider demand response over hours instead of hours, only an

additional MW would be useful. This report does not assess whether customers totaling 25 MW

would be willing to participate in a demand response program, only the degree to which load reduction

is feasible (from the standpoint of customer fatigue) and provides a reliability benefit to the system.

Program design is a primary factor in determining whether customers will be willing to participate in a

load reduction program.

Reliability Analysis Including the Impact of Demand Response

We modeled the impact of demand response using the 2019 summer peak load powerflow case

provided to us by NYSEG. NYSEG did not provide a corresponding powerflow case for the 2017 summer

peak period, which would correspond to the point in time when the NYSEG transmission solutions are

projected to be in service. The 2019 case represents loading conditions that are somewhat greater than

would be expected in 2017, hence the results can be considered conservative for the 2017 period (i.e.,

overloads associated with contingencies identified in the 2019 case would likely be less severe under

2017 loading conditions).

To model the impact of demand response, we reduced the load on the Auburn area buses proportionate

to their 2019 loading5 such that the total load reduction in the Auburn area would be 25 MW, consistent

with the potential demand response contribution derived from load-duration curve data. Table 1 below

summarizes the various cases run and the various overloads observed.

Table 1 – Powerflow Results Illustrating the Impact of Demand Response in the Auburn Area

Case Cayuga Status Demand Response

Auburn Area Load MW

Contingency Overload

1 Both OFF No Base case State St-Elbridge#972

2 Both OFF Yes 1 Base case --

3 Both OFF Yes 1 Loss of SLEIGH-S121#B2 State St-Elbridge#972

4 Both OFF Yes 1 Loss of CLTNCORN-STATE State St-Elbridge#972

5 Cayuga 2 @ MW No Base case --

6 Cayuga 2 @ MW No Loss of CLTNCORN-STATE --

5 There is a discrepancy in the NYSEG data provided to us between the projected 2019 Auburn area peak load

provided based on a regression forecast MW) and that used in the 2019 summer peak load powerflow case MW). We have elected to use the loads in the powerflow case for our analysis.

5

7 Cayuga 2 @ MW No Loss of SLEIGH-S121#B2 State St-Elbridge#972

8 Cayuga 2 @ MW Yes 1 Loss of SLEIGH-S121#B2 State St-Elbridge#972

9 Cayuga 2 @ MW Yes Loss of SLEIGH-S121#B2 State St-Elbridge#972

10 Cayuga 2 @ MW Yes Loss of SLEIGH-S121#B2 --

11 Cayuga 2 @ MW Yes 1 Loss of SLEIGH-S121#B2 --

1 Load of MW represents the original loading minus the amount of MW provided by DR

Case 1 replicates the analysis performed by NYSEG, illustrating that a base case overload on the State St-

Elbridge #972 line would exist at forecast peak load conditions. Cases 2 through 4 indicate that, with

both Cayuga units out of service during the interim period, overloads will occur even with the use of 25

MW of demand response. Cases 5 through 7 show that, with only one unit on at Cayuga operating at

MW, overloads on the State St-Elbridge #972 line would still exist for the loss of Sleigh-S121#B2.

Case 8 indicates that, with one Cayuga unit dispatched at MW and 25 MW of demand response

available, there is still a slight (7 MVA) overload of the State St-Elbridge #972 line for the loss of Sleigh-

S121#B2. Cases 9 and 10 show that, with a 10 MW increase in demand response (to 35 MW), a dispatch

of MW can be maintained on Cayuga unit 2 without overloads under normal or contingency

conditions. Case 11 redispatches Cayuga unit 2 up to its maximum (per the power flow database) of

MW, while maintaining 25 MW of demand response; no overload conditions were observed.

To investigate the possibility that corrective actions such as redispatching other generators on the

system might improve normal and contingency overload situations, the sensitivity of the flow on the

State St- Elbridge #972 line to the change in generation of every available system generator was

computed. Not enough generation was found either within or outside of the area of study to eliminate

the overload under contingency situations.

In summary, as shown in power modeling Case 11 discussed above, overloads on the State St – Elbridge

#972 line are eliminated in the 2019 Summer peak case (under system loading conditions forecast to be

greater than those expected in mid-2017 when the transmission solutions are planned to be in service)

using one of the two Cayuga units and 25 MW of demand response from loads in the Auburn area.

The Per-Kilowatt Cost of a Demand Response Program is Competitive with the 2013 RSS Agreement

As shown above, the combination of targeted demand response with one unit operating at Cayuga has

been identified as a technically viable solution to the Auburn area overload issues for the interim period

of 2014 through summer 2017 until the proposed transmission solutions are in place. We have

investigated whether such a demand response program could be developed cost-effectively as an

alternative to keeping both Cayuga units operating under an RSS Agreement as is currently in place for

the period Jan. 16, 2013 through Jan. 15, 2014. As a comparison, we looked to the publicly-filed annual

demand response reports made to the Commission by Con Edison, available under Docket No. 09-E-

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0115.6 The purpose of this analysis is not to estimate the cost of a specific demand response program

targeted at the Auburn area or to suggest a program with the same cost and payment structure as found

in Con Edison’s Commercial System Relief and Distribution Load Relief programs, but to illustrate that

demand response is competitive with the current RSS structure.

In Dec. 2012, the Commission issued its Order approving the terms for the RSS Agreement between

Cayuga and NYSEG.7 The terms of the agreement are summarized here:

RSS would be procured from the Cayuga Facility (312.7 MW total) for one year beginning

January 16, 2013, and ending January 15, 2014. During this period, NYSEG would identify and

consider alternative reliability solutions.

NYSEG would continue to procure RSS from the Cayuga Facility beyond this period, if necessary,

dependent upon the implementation of NYSEG’s planned system reinforcements or alternative

reliability solutions.

NYSEG would pay Cayuga a monthly fixed-price charge of $2,431,388/month for RSS, totaling

$29,176,656 over 12 months. In addition, NYSEG would fund certain capital expenditures up to

$4,325,000. NYSEG would also pay Cayuga one- half of the reasonable expense it incurred, up

to $150,000, for the cost of service (COS) study for the Cayuga Facility that was filed in this

proceeding on November 9, 2012. NYSEG would also reimburse Cayuga for cumulative

incremental forced outage repair costs that exceed $450,000.

Any ICAP revenues received by Cayuga would be credited against NYSEG’s monthly payment to

Cayuga. Cayuga would retain any combined energy and ancillary service revenues, net of

variable production costs, up to $7 million annually, while NYSEG would share equally in any

such revenues in excess of $7 million annually.

If Cayuga operates the facility beyond January 15, 2014, Cayuga would reimburse NYSEG for one

half of the capital expenditures that were paid by NYSEG, at the rate of 20% per year for each of

the next five years of operation. In each such year, up to $432,500 in Cayuga’s EBITDA would be

paid back to NYSEG.

Attachment C evaluates the anticipated cost (in dollars per kilowatt month) of the current RSS contract

between Cayuga and NYSEG. Expressing costs in terms of Cayuga plant capacity permits a

straightforward comparison of RSS costs with publicly-available costs to administer demand response

programs in New York.

6 Consolidated Edison Company Of New York, Inc. Evaluation Of Program Performance And Cost Effectiveness Of

Demand Response Programs, Dec. 14, 2012, available at http://documents.dps.ny.gov/public/MatterManagement/CaseMaster.aspx?MatterCaseNo=09-e-0115&submit=Search+by+Case+Number 7 Order Deciding Reliability Issues And Addressing Cost Allocation And Recovery, Dec. 17, 2012. NYSDPS Docket No.

12-E-0400. Available at: http://documents.dps.ny.gov/public/MatterManagement/CaseMaster.aspx?Mattercaseno=12-E-0400

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The analysis assumes that NYSEG will fund the full $4.325MM associated with capital expenditures,

along with $75K for the COS study. NYISO capacity market revenue estimates are based upon spot

market auction prices for Rest of State (ROS) from January through June 2013, with average summer

and winter estimates used for the remainder of 2013. Energy market revenue is based upon total 2012

energy production, along with estimates of NYISO Zone C LBMPs (day-ahead market), western NY coal

prices and unit heat rates. As noted below, calendar year 2012 GWh production was well above that

needed to support reliability in the Auburn area. A provision of the RSS states that NYSEG will be

entitled to one-half of the energy and ancillary services revenue, net of variable costs, above $7MM. In

estimating the variable costs associated with the operation of Cayuga, only the primary cost component,

the price of coal, is factored in; other variable cost elements such as routine maintenance and

consumables used in environmental control technologies, reduce the likelihood that the $7MM net

energy revenue benchmark will be met.

The analysis shows that the cost of the current RSS contract is estimated to be $5.15/kW-month. With

the assumptions made, Cayuga’s net energy revenue will be below $7MM, resulting in no credit

adjustment to NYSEG. While the analysis contains a number of simplifying assumptions, it is reasonable

to consider how variations in key parameters, not including the impact of additional variable operating

costs, would cause the net energy revenue to exceed $7MM, triggering an additional credit to NYSEG.

The degree to which changes in key assumptions will begin to raise net energy revenue above $7MM,

thereby lowering the estimated RSS contract cost below $5.15/kw-month, are given below:

An increase of 230 GWh in total plant production.

An increase in day-ahead market LBMP from $40 to $45.

Improved plant heat rate from 10,100 Btu/kWh to 8,400 Btu/kWh

Reduction in coal prices from $2.96/MMBtu to $2.46/MMBtu.

It is noted that, using the 2012 Cayuga historical energy production, the plant would be operating an

average of 1,492 hours per year. If Cayuga is needed only for reliability, this figure should be compared

to the expected duration of the worst case reliability condition identified through contingency analyses.

In the Reliability Need section of NYSEG’s report on repowering,8 it is noted that ”loss of the Quaker

Road to Sleight Road 115 kV line #980 will cause the conductor in the #972 line to exceed its summer

Long Term Emergency ("LTE") rating at a local area load level of 120 MW, which is approximately 65% of

the projected 2012 summer peak load. Exposure to this condition historically has been limited to the

months of June through September for a total of 505 hours in 2011.” Our analysis assumes Cayuga GWh

production at historical 2012 levels, which translates into operation for significantly greater than 505

hours needed for reliability. Any increase in total plant production beyond the 505 hours cited in

8 Report on Cayuga Repowering Analysis (Public version), May 17, 2013, p.5.

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NYSEG’s report would not be expected to contribute to Auburn area reliability. It is noteworthy that

NYSEG’s repowering solicitation for Cayuga indicates need for a minimum of 600 hours per year.9

Attachment D provides information on recent costs reported on by Con Edison, Inc. associated with the

demand response programs implemented in the Con Edison territory.10 Specifically, 12-month costs for

Con Edison’s Distribution Load Relief Program (DLRP) and Commercial System Relief Program (CSRP) are

detailed in the filing. DLRP is a contingency program that is activated by Con Edison in system critical

situations; CSRP is activated when the day-ahead forecast is 96% or greater of the forecasted summer

system peak load. In both programs, customers are paid a reservation payment and an energy payment

for verified load reduction.

For DLRP, the total program costs for 2012 were $ 3,972,579, of which approximately two-thirds was

paid directly as customer incentives. Other cost components included program administration (both

Con Edison and third-party vendors), program equipment (not including metering), measurement and

verification, and marketing costs. A total of 129 MW of verified load reduction was achieved during the

system-wide test event on 6/22/2012, which results in a cost/kW-month of $5.13. For Con Edison’s

CSRP program, 2012 program costs were $2,531,737, with 60.75 MW of average mandatory plus

voluntary response, resulting in a cost/kW-month of $6.95.

Con Edison’s evaluation did not include costs of hourly interval meters needed to verify load reduction

performance. These costs are covered under Con Edison’s Mandatory Hourly Pricing and Reactive

Power Programs. We have not included metering costs in this analysis for the same reason; NYSEG

currently offers an hourly pricing program to business customers with 300 kW or greater demand.11 A

subset of these customers would be likely candidates for a demand response program targeted at the

Auburn area.

As can be seen from the above analysis, the per-kW-month cost of administering a demand response

program ($5.13 to $6.95 per kw-month from the examples provided) are competitive with that of the

current RSS agreement between Cayuga and NYSEG ($5.15 per kw-month). In total dollars, based upon

the total MW needed to solve the reliability issues identified in the Auburn area, a demand response

solution would be far cheaper (see Attachment E). Under the assumption that only one unit at Cayuga is

needed for reliability purposes, for a 6-month summer demand response program (covering the period

of reliability need) targeted at 25 MW, projected costs (excluding metering and using the average of the

Con Edison program costs in Attachment D) would be approximately $10.5 MM/year.12 . There is also a

reasonable argument for limiting a single-unit RSS agreement to the six months covering the summer

9 Cayuga Repowering Solicitation, February 19, 2013, p. 5, available at

http://documents.dps.ny.gov/public/MatterManagement/CaseMaster.aspx?Mattercaseno=12-E-0577 10

Consolidated Edison Company Of New York, Inc. Evaluation Of Program Performance And Cost Effectiveness Of Demand Response Programs, NYSDPS Docket No. 09-E-0115, December 14, 2012. 11

http://www.nyseg.com/YourBusiness/HourlyPricing.html 12

This analysis assumes that the per-kW-month cost of an RSS for only one unit at Cayuga is the same as that for both units; the RSS cost for a single unit may be higher than fifty percent of the two-unit cost.

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peak period. We did not have a comparable winter peak powerflow case to analyze, so we have kept

the duration of any RSS agreements involving Cayuga at the full twelve months. Cayuga and NYSEG’s

RSS contract will be almost twice as expensive, costing upwards of $19 MM/year, including payments

for annual capital expenses.

Conclusions

Our analysis indicates that NYSEG’s proposed transmission solution is the appropriate long-term

solution to the reliability issues identified with the mothballing of the Cayuga generating facility. Since

NYSEG has indicated that the transmission upgrades/additions associated with this solution are not

anticipated to be in place before mid-2017, an interim solution covering the period from mid-January

2014 (when the current one-year RSS agreement between Cayuga and NYSEG expires) to mid-2017 is

needed. Rather than continuing with an RSS solution requiring operation of both Cayuga units, we

recommend that a demand response program that provides 25 MW of load reduction over the summer

months be instituted, along with continued operation of only one Cayuga unit. Based on our analysis,

this alternative is more cost-effective than the current RSS solution. Consideration should be given to

whether or not any RSS agreement with the Cayuga facility should cover all 12 months, or if it can be

limited to a 6-month summer period, given the nature of the reliability needs identified.

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Attachment A (Confidential) – Projected Load-Duration Curve, Auburn

Area, 2017 Summer

(Pincwoo./f1'oWI'r So{utions LLe

11

Attachment B (Confidential) – Powerflow Simulation Results

12

(Pincwoo./f1'oWI'r So{utions LLe

13

14

15

16

17

18

(Pincwoo./f1'oWI'r So{utions LLe

•

19

20

21

(Pincwoo./f1'oWI'r So{utions LLe

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Attachment C – Anticipated $/kW-month Cost of Current RSS Contract

Between Cayuga and NYSEG

Cayuga kW: 312,700

Annual Per Month Per kW/mo

2013 monthly payment: 2,431,388$ 7.78$ per RSS

Annual capital expense allowed: 4,325,000$ per RSS

360,417$ 1.15$

One-half COS study cost: 75,000$ 0 02$ per RSS

Credit for capacity market pmts:

Assumed EFORd: 0.0891 summer 2013 NYCA EFORd

Summer 2013 revenue/kW: 35.49$ actual + estimated

Jan-Apr, Nov-Dec revenue/kW: 14.58$ actual + estimated

Total annual ICAP revenue/kW: 50.07$

Annual ICAP revenue: 14,261,860$ 3 80$ credit to NYSEG

Energy Market credit to NYSEG:

Unit 1 est MWh: 239,800 2012 total, from 2013 NYISO Gold Book

Unit 2 est MWh: 226,900 2012 total, from 2013 NYISO Gold Book

Average plant run hours: 1,492 based on plant GWh at full capacity

avg. LBMP ($/MWh): 40$ estimated from NYISO monthly market operations report, Zone C

Energy Market revenue: 18,668,000$ 18,668,000$

less cost of production:

coal price ($/MMBtu): 2 96$ US EIA March 2013 coal prices, NY

heat rate (Btu/kWh): 10,100 assumed average coal-fired plant heat rate

cost/MWh: 30$

total fuel cost: 13,952,463$ 13,952,463$

net earnings: 4,715,537$ 4,715,537$

retention limit: 7,000,000$ 7,000,000$ per RSS

credit to NYSEG for energy: -$ -$ -$ credit to NYSEG

TOTAL $/kW-mo cost of RSS: 5.15$

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Attachment D – Con Edison 2012 Demand Response Program Costs

~ (Pincwoo./f1'{)wI'r Solutions LLe

Con Edison DR Program Cost Evaluat ion

DlRP 2012

Total program costs: $ 3,972,579

kw reduction ach ieved: 129,000

# of program-mont hs: 6

Cost/kW-mo: $ 5.13

CSRP 2012

Total program cost s: $ 2,531, 737

kw reduction ach ieved: 60, 750

# of program-months: 6

c ost/kW-mo: $ 6.95

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Attachment E – Annual Cost of Demand Response Solution vs. RSS

Agreement

Comparison of Total Annual Cost, RSS vs. Demand Response Alternative

RSS Cost ($/kw 5.15$

kW: 312,700

# months: 12

RSS Annual Cost ($/yr): 19,314,796$

DR Cost ($/kW- 6.04$

kW: 25,000

# months: 6

DR Annual Cost ($/yr): 905,873$

1/2 RSS Cost ($/yr): 9,657,398$

Cost, DR+1 Cayuga unit ($/yr) 10,563,271$

(Pincwoo./f1'oWI'r So{utions LLe

, , ,

+ , + + , + + , + + , + + , .. .. t

+ + , + , .. ,

1

Attachment F – Qualifications of Pinewood Power Solutions

LLC

2

Pinewood Power Solutions LLC, a New York State Limited Liability Corporation, was founded in

November 2012 by David J. Lawrence, with the purpose of providing consulting services related to

wholesale electricity markets, particularly focused on demand response programs, capacity market

initiatives, and renewable resource market participation. Currently, Pinewood Power Solutions LLC is

engaged in the following projects:

Serving as consultant to a Demand Response provider in the New York Independent System

Operator’s (NYISO) wholesale demand response programs.

Developing a suite of graduate-level courses on deregulated electricity markets for an upstate

NY graduate school.

Prior to founding Pinewood Power Solutions LLC, Mr. Lawrence retired from the NYISO as Manager of

Capacity Market Products; his complete resume follows.

Nov. 2005 – Manager, Capacity Market Products – New York Independent System Dec 2011 Operator, Rensselaer, New York Responsible for design, development and deployment of NYISO’s demand response and

Installed Capacity (ICAP) market products. Major initiatives include:

Leading NYISO governance process discussions on ICAP demand curve reset (2007, 2010).

Developing and implementing capacity market mitigation measures for New York City.

Developing criteria for establishing new capacity market localities.

Establishing capacity market participation rules for solar generation facilities. Represented NYISO on numerous environmental initiatives, including the Northeast Regional Greenhouse Gas Initiative (RGGI) and New York’s Renewable Portfolio Standard (RPS). Worked collaboratively with NY State Energy Research & Development Authority, NY Dept. of Public Service and NY Dept. of Environmental Conservation on design of a NY generator attributes tracking system and various environmental rulemakings. Received NYISO Core Values Awards in 2007 and 2008.

Nov. 2001- Product Development Manager, Market Services Dept. – New York Nov. 2005 Independent System Operator, Albany, New York Managed demand response programs, Installed Capacity (ICAP) market design,

environmental initiatives and coordination of inter-regional Independent System Operator activities. Designed and implemented internal issues management process. Presented numerous technical outreach talks to NYISO stakeholder groups, US and Canadian organizations. On behalf of the NYISO, accepted from the Peak Load Management Alliance the 2002 and 2004 awards for best ISO Demand Response Program in the U.S.

Apr. 2000- Senior Engineer, Planning Dept. – New York Independent System Nov. 2001 Operator, Albany, New York

Spearheaded development of NYISO reliability-based and economic demand response programs with NYISO stakeholders. Prepared monthly transmission congestion reports; developed initial process for system reliability impact studies.

3

Mar. 1995- Director, Instrumentation and Energy Management Dept., Power Apr. 2000 Technologies, Inc., Schenectady, New York

P/L responsibility for PTI’s monitoring and control products and associated services. Devised marketing and sales strategies; led new product development; negotiated contracts on a worldwide scale. Department expanded in 1997 to include power plant performance analysis software development and services personnel. In 1999, assumed responsibility for all of PTI’s professional training courses. Elected to the PTI Board of Directors, 2 terms.

1994- Product Manager, Industrial Load Shedding System, Power 1995 Technologies, Inc.

Managed all marketing, sales, product development, and client support associated with PTI’s industrial load shedding system.

1990- Product Manager, Dynamic System Monitor, Power Technologies, Inc. 1994 In coordination with equipment manufacturing and marketing partner, managed product

development and client technical support for PTI’s Dynamic System Monitor phasor measurement system. Also developed algorithms for DSP-based voltage, frequency, and power sensors.

1984- Senior Engineer, Power Technologies, Inc. 1990 Responsible for contractual, technical, and financial aspects of project management, including supervision of project staff. Projects included:

Project Engineer for Electric Power Research Institute RP2542-1, Characteristics of Lightning Surges on Distribution Systems,

developed and presented PTI Short Course on Disturbance Monitoring and Analysis,

developed three-phase analysis and transmission line fault location software for use with digital transient recorders, and

served as instructor for Power System Reliability and Transmission System Reliability courses.

1976- Analytical Engineer, Power Technologies, Inc. 1984 Developed software, performed studies, and prepared reports for a number of utility-

related projects, including:

design and development of a short-term hydro-scheduling computer program, along with on-line control software, for a Spanish utility,

development of a fault data analysis software package for a distribution fault current study sponsored by the Electric Power Research Institute,

several bulk power system and substation reliability studies, and

development of a microprocessor-based high impedance fault detection algorithm.

Education 1975- Graduate School of Engineering, Rensselaer Polytechnic 1976 Institute, Troy, New York

Master of Engineering Degree in Electric Power Engineering, May 1976

4

1971- Rensselaer Polytechnic Institute, Troy, New York 1975 Bachelor of Science Degree in Electric Power Engineering, with a minor concentration in

Technical Writing.

Professional Certification Certified as an Intern Engineer in New York State, October, 1975.

Professional Societies Member, Institute of Electrical and Electronics Engineers. Past Chairman, Power Engineering Society, Schenectady Chapter. Past Chairman, Institute of Electrical and Electronics Engineers, Schenectady Section. Past Member of Power System Relay Committee Working Groups H5, Common Data Format for Exchange of Transient Data, and I11, Digital Fault Recorder Data Standards.

Honors and Awards Nominated for the Eta Kappa Nu Outstanding Young Electrical Engineer Award, 1985. Technical Papers by David J. Lawrence: 1. "On-Line Economic Control of the Iberduero Hydro Thermal Systems," Seventh Power Systems Computation Conference,

Lausanne, Switzerland, July 12-17, 1981, (co-authors: J.A. Garrido, J.L. San Pedro, R.L. Zabalza, R.E. Kilmer, E.J. Lessans, T.A.

Mikolinnas, and R.J. Ringlee).

2. "Characteristics of Fault Currents on Distribution Systems," IEEE Transactions on Power Apparatus and Systems, Vol. PAS-103,

No. 1, Jan. 1984, p. 1-6, (co-author: J.J. Burke).

3. "Computation of Upper and Lower Bounds on Reliability Indices for Bulk Power Systems," IEEE Transactions on Power

Apparatus and Systems, Vol. PAS-103, No. 8, Aug., 1984, p. 2318-2325, (co-authors: K.A. Clements, B.P. Lam, and N.D. Reppen).

4. "Transmission System Reliability Assessment by Contingency Enumeration," Eighth Power Systems Computation Conference,

Helsinki, Finland, August, 1984, (co-authors: B.P. Lam, N.D. Reppen, and N.J. Balu).

5. "Generating Unit Performance Modeling and Measurement Uncertainty," ASME Paper No. 84 - JPGC-PTC-7, presented at the

1984 Joint Power Generation Conf., Toronto, Ontario, Oct. 1984, (co-authors: B.P. Lam, R.J. Ringlee, and S.E. Williams).

6. "A Microprocessor-Based Technique for Detection of High Impedance Faults," IEEE Transactions on Power Apparatus and

Systems, Vol. PWRD-1, No. 3, July 1986, pp. 252-258, (co-authors: S.J. Balser and K.A. Clements).

7. "Current Developments in Transmission Reliability Assessment," presented at the Pennsylvania Electric Association System

Planning Committee Meeting, Pittsburgh, PA, May 13-14, 1986, (co-author: N.D. Reppen).

8. "Transmission Line Fault Location Using Digital Fault Recorders," IEEE Paper 86 T&D 545-8, IEEE Transactions on Power

Delivery, April 1988, pp. 496-502, (co-author: D. Waser).

9. "Analysis of Digital Transient Recorder Event Waveforms," presented at the 1986 Utility Fault and Disturbance Analysis Conf.,

Denver, CO, October 29-30, 1986.

10. "Incremental Heat Rate Sensitivity Analysis," Proceedings: 1986 Power Plant Performance Monitoring and System Dispatch

Conference, EPRI Publication CS/EL-5251-SR, July 1987.

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11. "Further Experience with Transmission Line Fault Location Techniques," paper presented at the 40th Annual Conference for

Protective Relay Engineers, Texas A&M University, April 13-15, 1987.

12. "Distribution Feeder Operational Analysis Using Digital Transient Recorders," presented at the 1987 Utility Fault and

Disturbance Analysis Conference, Denver, CO, October 1-2, 1987, (co-authors: M.D. Taylor, J.A. D'Angelo, F. Frank, and P. Barker).

13. "Analysis of Lightning Waveforms as Recorded on Typical Distribution Feeders," presented at the Fourth Annual Fault and

Disturbance Analysis Conference, New Orleans, LA, September 26-27, 1989 (co-authors: P.P. Barker and D. Parrish).

14. "Breathing Life Into Digital Fault Recorder Data," presented at the 57th Annual International Conference of Doble Clients,

Boston, MA, April 2-6, 1990.

15. "Development of an Advanced Transmission Line Fault Location System, Part I: Input Transducer Analysis and Requirements,"

IEEE Transactions, Paper No. 90 SM 474-7PWRD, presented at the IEEE/PES Summer Meeting, Minneapolis, MN, July 15-19, 1990,

(co-authors: L. Cabeza and L.T. Hochberg).

16. "Development of an Advanced Transmission Line Fault Location System, Part II: Algorithm Development and Simulation," IEEE

Transactions, Paper No. 90 SM 475-4PWRD, presented at the IEEE/PES Summer Meeting, Minneapolis, MN, July 15-19, 1990, (co-

authors: L. Cabeza and L.T. Hochberg).

17. "Long-Term Disturbance Analysis - Some Case Studies," paper presented at the Sixth Annual Conference for Fault and

Disturbance Analysis, Texas A&M University, April 17-19, 1991, (co-author: S.J. Balser).

18. “Defining the Benefits of Phasor Measurement Systems,” presented at the IEEE/PES 1993 Winter Power Meeting, Panel

Session on Applications and Experience in Power System Monitoring with Phasor Measurements, Columbus, OH, February 2, 1993,

(co-author: G.R. Jensen).

19. “Using Digital Signal Processors to Measure Power System Quantities,” presented at the 8th Annual Conference for Fault and

Disturbance Analysis, Texas A&M University, College Station, TX, April 14-16, 1993, (co-author: R.C. Gough).

20. “Application of an Electrical Load Shedding System to a Large Refinery,” presented at the 42nd Annual IAS Petroleum &

Chemical Industry Technical Conference, Denver, CO, September 11-13, 1995, (co-author: J.S. Czuba).

21. "An Add-On Power System Stabiliser,” presented at the IEE Colloquium on Generator Excitation Systems and Stability, London, UK, February 6, 1996, (Digest No. 1996/023, pp. 7/1-4),(co-author: C.A. Lynch).

22. “2001 Performance of New York ISO Demand Response Programs”, panel session presentation at the 2002 IEEE Power

Engineering Society Winter Power Meeting, New York, NY, January 27-31, 2002.

23. “The Status of Demand Response in New York”, panel session presentation at the 2003 IEEE Power Engineering Society

General Meeting, Toronto, CA, July 13-17, 2003, (co-author B.F. Neenan).

24. “Market Design with Consideration for Intermittent Wind Resources”, presented at the 2006 IEEE Power Engineering Society

General Meeting, Montreal, CA, (co-author R.W. deMello).

25. “How Capacity Markets Address Resource Adequacy”, presented at the 2009 IEEE Power Engineering Society General Meeting,

Calgary, CA, July 2009 (co-author Henry Chao).

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Attachment G – Qualifications of PSM Consulting, Inc.

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Located in Guilderland, New York, PSM Consulting, Inc. is a minority-owned, New York State

Corporation, founded in 2003, with expertise in power systems engineering and electricity markets. We

also provide Environmental Engineering Services with a focus on the power industry.

Our staff performed numerous power system analysis and studies across many regions in the US and

abroad. PSM Consulting, Inc. has experience in projects of various sizes and levels of complexity.

Our experience related to this Project is illustrated in the following selected projects:

Transient Stability Studies to determine the feasibility of the largest transmission project of the

country: The TransWest Express Project (TWE) which will deliver 3,000 MW of wind power from

Wyoming to the southwest (Nevada).

Feasibility Studies for the Interconnection of renewable energy generation including wind

power, energy storage devices, and power production using Landfill gas.

Power flow analysis to analyze the potential mothballing of generating plants in New York and

New England.

Transient Stability analysis of the AES Energy Storage (+/- 20 MW) Westover Small Generating

Frequency Regulation Facility.

Full System Reliability Impact Study (SRIS) for wind farms (Evaluated the interconnection of

more than 2,000 MW to the electrical grid).

Resume: Ricardo J. Galarza, Ph.D.

President, PSM Consulting, Inc.

Experience with PSM Consulting: 9 years (Founding President)

Experience with other firms: 13

Education

Ph. D., Electric Power Engineering, Rensselaer Polytechnic Institute, 1996.

M. S., Electric Power Engineering, Rensselaer Polytechnic Institute, 1992.

B. S., Electrical Engineering, Northeastern National University, Argentina, 1985.

Graduate-Level Course (Equivalent to M.S.): Energy Economics and Planning, Institute for the

Study of Energy Economics, Comahue National University, Argentina, 1987.

3

Experience Summary

Dr. Galarza has worked in the electric power industry for over 20 years in various positions, gaining

extensive experience in power system engineering and the electricity markets.

After obtaining his B.S. degree, he worked for an electric utility in various capacities. In 1987, he

became Project Manager in two studies supported by the European Community. The first involved

energy and transmission planning (for the northeastern part of Argentina) and the second

concerned the utilization of alternative generation sources for small isolated systems. In 1991, he

joined the graduate engineering program at Rensselaer Polytechnic Institute. His dissertation title

was: “Power System Dynamic Equivalencing: Advanced Analysis and Improvements”.

Dr. Galarza joined Power Technologies, Inc. (PTI) in late 1996 as a Senior Consultant, Transmission

Planning, in the System Planning and Operations Department. At PTI, Dr. Galarza led and performed

numerous consulting studies in the areas of transmission planning (across many regions in the US

and abroad), software development, generator interconnection studies, modeling of electrical

apparatus for steady state and dynamic analysis. Dr. Galarza was also involved in development of

training material for using steady-state techniques and dynamic modeling in power system analysis,

use of appropriate software for system planning and grid reliability, and power system

fundamentals. He was the course instructor for many courses offered by PTI.

In 2001, he joined the Market Monitoring and Performance Unit of the NYISO where as a Senior

Analyst he was involved in a variety of projects as the only transmission system specialist. He

designed a market simulator software that included the transmission system model, conducted

numerous market analysis studies, participated in the implementation of most of the changes

introduced to the NY market, performed analysis of market design as it relates to grid operation,

monitored the Transmission Congestion Contract (TCC) market, and developed a congestion cost

allocation method that allow for better understanding of the impact of the transmission system on

prices, hence allowing for system-wide congestion savings.

Dr. Galarza founded PSM Consulting, Inc. in September of 2003. As an independent consultant at

PSM Consulting, Inc. he was involved in numerous transmission planning project such as: analysis of

alternatives of interconnections for new substations in Connecticut and voltage control issues in the

same area, feasibility and system impact reliability for the interconnection of renewable energy

generation including wind power and and power production using Landfill gas, addition of new

technology to the grid such as energy storage and frequency regulating devices. As a Project

manager, he supervised PSM Consulting, Inc. staff for evaluating more than 2,000 MW to the

electrical grid. Dr. Galarza also assisted clients to Committees and participated actively on the

Transmission Planning Advisory Committee of the NYISO. He also worked as a technical auditor for

the NYISO, reviewing and supervising technical work performed by other companies. He is the

current technical advisor on Transmission Planning for the New England Committee on Electricity

(NESCOE).

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As a consultant, Dr. Galarza continued assisting the NYISO on the implementation of numerous

market changes and new market products into the market operation software. Dr. Galarza also

provided technical support for Standard Market Design Implementation for the Market Monitoring

Unit, New York ISO.

Relevant Publications

Ricardo J. Galarza and Heidi Knach: “Integrating Wind Power into the New York Grid and Electricity

Market”, in Proc. Of the 2009 IEEE-PES/IAS Conference on Sustainable Alternative Energy (SAE),

Valencia, Spain.

Ricardo J. Galarza, Ibrahim Mqasqas, and James C. David: “Elements of Design in Local Market Power

Screens,” in Proc. of the 2006 IEEE PES Power Systems Conference & Exposition.

Ricardo J. Galarza: “Market Monitoring and SMD Implementation: the New York Experience and

Beyond,” in Proc. 2004 IEEE PES Power Systems Conference & Exposition, Oct. 2004.

Ricardo J. Galarza, R. DeMello: “The Use of Conduct and Impact Tests in the Mitigation of Market

Power,” in Proc. 2004 IEEE PES Power Systems Conference & Exposition, Oct. 2004.

Ricardo J. Galarza, et. al.: “Building a Market Simulator Tool for Market Monitoring and Performance

Evaluation”, IEEE Power and Energy Magazine, 2004.

Ricardo J. Galarza, "Aggregation of Exciter Models for Constructing Power System Dynamic

Equivalents," IEEE Transactions on Power Systems, Vol. 13, No. 3, pp. 782-788, August 1998, (co-

authors: J. H. Chow, W.W. Price, A. Hargrave, and P. Hirsch).

W. W. Price, G. E. Boukarim, J. H. Chow, R. J. Galarza, A. W. Hargrave, B. J. Hurysz, and R. Tapia,

Improved Dynamic Equivalencing Software, Final Report, EPRI Project RP2447-02, 1996.

J. J. Sanchez-Gasca, J. H. Chow, and R. J. Galarza, “Reduction of Linearized Power Systems for the

Study of Interarea Oscillations,” Proceedings 4th IEEE Conference on Control Applications, pp. 624-

630, September 1995.

R. J. Galarza, “Transformer Model Reduction Using Time and Frequency Domain Sensitivity

Techniques,” IEEE Trans. on Power Delivery, vol. 10, no. 2, pp. 1052-1059, April 1995, (co-authors: J.

H. Chow, and R. C. Degeneff).

J. H. Chow, R. J. Galarza, P. Accari, and W.W. Price, “Inertial and Slow Coherency Aggregation

Algorithms for Power System Reduction,” IEEE Trans. on Power Systems, vol. 10, no. 2, pp. 680-685,

May 1995.