CONFIDENTIAL

IN THE UNITED STATES DISTRICT COURT

DISTRICT OF PUERTO RICO

In re:

THE FINANCIAL OVERSIGHT AND 

MANAGEMENT BOARD FOR PUERTO 

RICO,

as representative of

THE COMMONWEALTH OF PUERTO RICO, 

et al.

Debtors.

PROMESA TITLE III

Case No. 17-BK-3283-LTS

(Jointly Administered)

In re:

THE FINANCIAL OVERSIGHT AND 

MANAGEMENT BOARD FOR PUERTO 

RICO,

as representative of

THE PUERTO RICO ELECTRIC POWER 

AUTHORITY,

Debtor.

Case No. 17-BK-4780-LTS

This Court Filing Relates Only to 

PREPA and Shall be Filed Only in Case 

No. 17-BK-4780-LTS and Main Docket 

17-BK-3283-LTS

EXPERT REPORT OF SUSAN TIERNEY, PHD

APRIL 28, 2023

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TABLE OF CONTENTS

I. Qualifications..........................................................................................................................1

II. Assignment .............................................................................................................................2

III. Summary Of Findings And Conclusions................................................................................4

IV. Background.............................................................................................................................8

A. Load And Expense Forecasting By Electric Utilities....................................................8

B. The FOMB’s Legacy Charge Model Uses A Modified Version Of 

PREPA’s Existing Base Case Load Forecast...............................................................10

C. PREPA’s Gross Load Forecast Predicts Declining Load ............................................12

V. PREPA’s Net Load Forecast Significantly Understates Future Electricity 

Demand.................................................................................................................................14

A. Dr. Edwards’s Macroeconomic Projections Imply A Substantially 

Higher Gross Load Forecast For PREPA ....................................................................15

B. PREPA’s Base Case Net Load Forecast Significantly Understates 

Future Electricity Demand By Making Unrealistic, Unsupportable 

Adjustments To Gross Load ........................................................................................17

1. PREPA’s Base Case Forecast Of Reduced Net Load From 

Energy Efficiency Is Unreliable And Unreasonable................................. 19

2. PREPA’s Base Case Forecast Of Reduced Net Load From 

Distributed Generation Is Unsupported .................................................... 26

3. PREPA’s Base Case Forecast Of Additional Net Load 

From Electric Vehicles Is Arbitrarily Truncated And 

Understated ............................................................................................... 35

C. A More Realistic PREPA Net Load Projection Would Be Much 

Higher Than That Projected by PREPA ......................................................................39

VI. PREPA Has A Track Record of Underestimating Net Load................................................41

VII. Electricity Demand Is Not As Responsive To Changes In Electricity Prices 

As FOMB Assumes..............................................................................................................42

A. Background On Price Elasticity In Electricity.............................................................43

B. FOMB’s Price Elasticity Assumptions Are Unsupported And 

Contradicted By The Academic Literature ..................................................................45

1. FOMB’s Posited Elasticity Effect Is Estimated From A 

Series Of Unexplained Assumptions And Adjustments........................... 45

2. The Board’s Long-Term Elasticity Estimates Are Not 

Supported By The Cited Authority........................................................... 48

3. The Board’s Long-Term Elasticity Estimates Are 

Substantially Higher Than The Academic Consensus 

Reflected By Surveys Of Hundreds Of Studies........................................ 50

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C. FOMB’s Own Gross Load Forecast Assumes Zero Elasticity ....................................51

VIII. The FOMB Artificially Inflates PREPA’s Likely Future Capital 

Expenditures To Derive Its Legacy Charge..........................................................................53

A. PREPA’s Legacy Charge Derivation Uses A Capital Cost Forecast 

That Is Outdated And Too High Compared To LUMA’s Latest 

Forecasts ......................................................................................................................54

B. PREPA’s Legacy Charge Derivation Assumes Additional Capital 

Costs That Are Unreasonable and Inconsistent With PREPA’s Own 

Fiscal Plan....................................................................................................................57

IX. PREPA’s Assumptions About the Commonwealth’s And Other 

Governmental Entities’ Non-Payment Of Past Electricity Bills Is 

Inconsistent With Sound Utility Practice..............................................................................63

A. The Commonwealth And Other Governmental Entities Owe Large 

Amounts To PREPA....................................................................................................63

B. The FOMB’s Revenue Envelope Should Assume That Government 

Entities Will Pay Their Unpaid Electricity Bills..........................................................65

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I. QUALIFICATIONS

1. I am Susan Tierney. I am a Senior Advisor at Analysis Group, Inc., an economics 

consulting firm headquartered in Boston, Massachusetts.

2. I spent much of my career working in Massachusetts state government on matters 

related to the electric industry—first as the electric-industry economist for the state’s energy 

office; then as an analyst and ultimately the Executive Director of the state’s Energy Facilities 

Siting Council (the agency that reviews electric utilities’ long-term demand forecasts, supply 

plans, and facility proposals); then as Commissioner of the Department of Public Utilities (the 

regulatory agency with ratemaking oversight and approval for utilities in the state); and then as 

Secretary of Environmental Affairs (the cabinet officer for environmental regulation and 

programs). At the U.S. Department of Energy, I served as Assistant Secretary of Policy with 

responsibility for a range of matters related to the nation’s electric, gas, oil, coal, and other 

industries.

3. For more than two decades, I have consulted to companies, government entities, 

grid operators, non-profit organizations, large electricity consumers, and others, on energy and 

environmental economics, policy, ratemaking, and regulation, and served as an expert witness in 

litigation on the same topics. Throughout my consulting practice, as in my government service, I 

have had experience with electric utility ratemaking, demand forecasting, and supply planning.

Among the many pro bono activities I have undertaken since leaving government are the 

following: chairing the Department of Energy’s Electricity Advisory Committee; chairing the 

External Advisory Board of the National Renewable Energy Laboratory (“NREL”); and serving 

as a member of several committees of the National Academies of Sciences, Engineering and 

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Medicine (including the committees on the Future of Electric Power in the U.S., the Role of Net 

Metering in the United States, Enhancing the Resilience of the Nation’s Electric System, and 

Decarbonizing the U.S. Energy System).

4. I have a Ph.D. and Master’s degree in regional planning from Cornell University. 

A copy of my curriculum vitae is attached to this report as Appendix A.

5. Analysis Group is being compensated for my time in this matter at a rate of $920 

per hour. In carrying out my assignment, I have directed and supervised employees of Analysis 

Group, though the views and conclusions in this report are mine. My compensation is not 

contingent on the content of my opinions or on the outcome of this matter.

6. In preparing this expert report, I, along with Analysis Group staff working under 

my direction, have reviewed various documents and data sources. I attach a list of documents 

and sources which I have considered as Appendix B to this Report.

II. ASSIGNMENT

7. I have prepared and submit this Report pursuant to Analysis Group’s retention by

the Ad Hoc Group of PREPA Bondholders,1 Syncora Guarantee, Inc., Assured Guaranty Corp., 

and Assured Guaranty Municipal Corp. (collectively, “Bondholders”), in connection with their 

objections to confirmation of a plan of adjustment (the “Plan of Adjustment” or “Plan”) filed by 

1 The Ad Hoc Group of PREPA Bondholders includes BlackRock Financial Management, Inc., Franklin Advisers, 

Inc., GoldenTree Asset Management LP, Invesco Advisers, Inc., Nuveen Asset Management, LLC, Taconic Capital 

Advisors L.P., and Whitebox Advisors LLC.

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representatives of the Financial Oversight and Management Board (“FOMB” or “Oversight 

Board”) on behalf of the Puerto Rico Electric Power Authority (“PREPA”).2

8. I have been asked to:

• Assess the reasonableness of key elements of PREPA’s projection of its customers’ 

future demand for electricity—its “load forecast”—which is a significant input into the model by 

which the FOMB derives its proposed Legacy Charge. I also analyzed how PREPA’s existing 

projection of future gross load would change by adopting Dr. Sebastian Edwards’s 

macroeconomic projections.

3 I also analyzed the predictions and assumptions—about the 

adoption of energy efficiency, distributed generation (including rooftop solar panels), and 

electric vehicles—by which PREPA modifies its gross load forecast to arrive at the net load 

forecast the FOMB used for its Legacy Charge model.

• Assess the FOMB’s assertions related to the future price elasticity of electricity demand.

• Assess the FOMB’s projection of PREPA’s future capital costs, including costs assumed 

by the FOMB’s Legacy Charge model that are additional to the capital costs already included 

and approved in the 2022 PREPA Fiscal Plan.

4

2 Disclosure Statement for Modified Second Amended Title III Plan of Adjustment of the Puerto Rico Electric 

Power Authority, In re: The Financial Oversight and Management Board for Puerto Rico, as representative of the 

Commonwealth of Puerto Rico, et al., Debtors, PROMESA Title III No. 17-BK-3283-LTS, and In re: The Financial 

Oversight and Management Board for Puerto Rico, as representative of Puerto Rico Electric Power Authority, 

Debtor, PROMESA Title III No. 17-BK-4780-LTS (Jointly Administered), United States District Court for the 

District of Puerto Rico, San Juan, Puerto Rico, dated March 1, 2023 (hereafter “Disclosure Statement”). Disclosure 

Statement Exhibit A: Modified Second Amended Title III Plan of Adjustment of the Puerto Rico Electric Power 

Authority (hereafter "Plan of Adjustment").

3 Expert Report of Sebastian Edwards, April 28, 2023 (hereafter “Edwards Report”).

4 PREPA, “2022 Certified Fiscal Plan for the Puerto Rico Electric Power Authority,” FOMB_PREPA 00000699 -

FOMB_PREPA 00000882 (hereafter “2022 PREPA Fiscal Plan”).

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• Assess the type and extent of unpaid historical bills and of Contributions in Lieu of Taxes 

(“CILT”) from PREPA to governmental and municipal entities that are paid for by other PREPA 

customers.

III. SUMMARY OF FINDINGS AND CONCLUSIONS

9. It is my opinion that the “Base Case” net load forecast of PREPA’s future 

electricity demand—as reported in the 2022 PREPA Fiscal Plan and that the FOMB uses to

calculate its proposed Legacy Charge—greatly underestimates PREPA’s future sales of 

electricity. It predicts that PREPA’s electricity sales will decline by more than half over the next 

decade. The FOMB reaches this conclusion as the result of several unfounded and unreasonable

assumptions, which render that forecast unreliable.

10. The FOMB’s net load forecast begins with a gross load forecast that is also taken 

from PREPA’s 2022 Fiscal Plan. I note that Dr. Edwards concludes that the gross national 

product (GNP) and population projections taken from the Commonwealth’s 2022 Fiscal Plan

(which are used by PREPA to arrive at their gross load forecast) are understated. As a result, 

PREPA and the FOMB substantially understate the likely gross load over the coming decades. 

That distorts the starting point for the net load modifiers that I assess.

11. Those load modifiers are derived from a Base Case net load forecast that reflects a 

series of adjustments made to the gross load forecast. The 2022 PREPA Fiscal Plan also presents 

an “Alternative Forecast” of gross and net load that is substantially more realistic than the Base 

Case—but which is ignored in FOMB’s Legacy Charge analysis. Unlike the Base Case, the 

Alternative Forecast is based on actual experience and constraints in achieving certain energy 

policy goals. While PREPA’s Alternative Forecast is flawed as well, it nevertheless provides a 

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more defensible and appropriate starting point for projecting load for purposes of deriving a

reasonable Legacy Charge.

12. In its Base Case, the FOMB makes a series of adjustments to its gross load 

forecast, to reach its Base Case net load forecast, which I understand is used to calculate the 

Legacy Charge. First, and most important, the FOMB assumes that Puerto Rico will achieve a 

30% reduction in demand for electricity by 2037 relative to 2019, based upon the rapid and 

widespread adoption of energy efficiency measures. The sole basis for this assumption is a 2019 

legislative enactment which stated that 30% figure as a target. But all available evidence 

demonstrates that target is unattainable. The proposition that Puerto Rico can achieve this goal of 

energy efficiency is inconsistent with (i) a competing and much lower forecast by LUMA of the 

potential adoption of energy-efficiency measures in Puerto Rico; (ii) Puerto Rico’s low ranking 

compared to other U.S. jurisdictions for government-backed energy efficiency policies, programs 

and initiatives; and (iii) the FOMB’s own Alternative Forecast, which is based upon actual data

and undermines its aggressive Base Case assumption.

13. Second, FOMB further adjusts its gross electricity demand forecast downward on 

the assumption that Puerto Rico residents will rapidly adopt “distributed generation” 

technologies—principally rooftop solar panels—which will reduce demand on and purchases 

from the grid. Yet, the FOMB’s base-case projection lacks supporting evidence. In fact, that 

projection fails to take account of the up-front cost of adopting solar energy (which is prohibitive 

to many residents on the island), as well as operational barriers, and a lack of adequate 

infrastructure to accommodate such a rapid adoption of solar power. And again, the FOMB’s

projection ignores its own bottom-up Alternative Forecast analysis, as well as the predicted 

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adoption rates of other states that are better positioned for the rapid adoption of solar energy 

systems.

14. Third, the adoption of electric-powered vehicles will increase demand for 

electricity, and therefore requires an upward adjustment to the gross load forecast. But the 

FOMB assumes that the growth in load due to electric vehicles in Puerto Rico will abruptly and

completely halt in 15 years, with no further growth thereafter. The FOMB provides no basis for 

that assumption, which is contrary to the FOMB’s own Alternative Forecast, industry and 

governmental forecasts, and common sense. In my opinion, each of these assumptions by which 

FOMB arrives at its net load forecast are unsupported, unreasonable and unreliable.

15. The FOMB’s Legacy Charge Derivation5 further modifies downward the already

too-low Base Case net load forecast to account for an “elasticity effect,” demand reductions that 

FOMB believes would result from any future rate increases not contemplated by the 2022 Fiscal 

Plan. This “elasticity effect” in the FOMB’s Legacy Charge Derivation is significant—for 

example, the Oversight Board assumes a 1.7% drop in residential energy consumption for every 

1% increase in price. According to the FOMB, that assumed reduction in demand “in turn will 

require increases to rates to ensure revenues are sufficient to pay all of PREPA’s fixed costs.”6

16. I find the FOMB’s estimated long-term elasticity effect to be unsupported by the 

two academic papers on which it relies (one of which, notably, is a working paper). The FOMB’s

long-term elasticity estimates are also inconsistent with—and substantially higher than—the 

estimated elasticities reflected by an academic consensus demonstrated in surveys of hundreds of 

studies of the elasticity of electricity demand. The result is that the FOMB substantially 

5 Disclosure Statement Exhibit P: Legacy Charge Derivation (hereafter “Legacy Charge Derivation”).

6 Legacy Charge Derivation, p. 6.

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overstates the extent to which increases in rates would suppress demand, which causes the 

FOMB to overstate the amount of potential new revenues that should be reserved to cover a 

supposed shortfall in funds to pay fixed costs instead of being available to fund creditor 

recoveries.

17. I also assess yet another adjustment made by the FOMB’s Legacy Charge 

Derivation that has the effect of reducing the amount of potential new revenues the FOMB says 

are available to fund creditor recoveries—this time focused on estimated future capital 

expenditures. The FOMB proposes to reserve $2.425 billion in potential new revenues (and to 

not make those potential new revenues available for creditor recoveries), to provide for future 

capital expenditures over and above what is already projected and budgeted for in PREPA’s 

2022 Fiscal Plan. That is, whereas PREPA’s 2022 Fiscal Plan forecasts annual capital 

expenditures based on projections and capital-expense planning, the Legacy Charge Derivation 

sets an unexplained higher target for such expenditures that is inconsistent with that Fiscal Plan, 

and then asserts that the difference must be taken out of any potential new revenues that 

otherwise would be available for creditor recoveries. This unexplained departure from PREPA’s

2022 Fiscal Plan—which is already over-generous in terms of capital-expense forecasting—is 

inconsistent with standard utility planning and methodologically unsound.

18. Finally, I assess the FOMB’s assumptions about the non-payment of balances

owed to PREPA by governmental customers. In particular, I explain that sound utility planning 

and practice would require assuming that these governmental customers will pay their overdue 

balances. In fact, many of the entities in arrears are now under the FOMB’s direct supervision. 

Payment of these unpaid governmental balances, as I explain, could make hundreds of millions 

of additional dollars available for creditor recoveries in the near term.

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19. I understand that as part of her expert report, Dr. Maureen Chakraborty uses my 

findings on future electricity demand, price elasticity, and additional capital expense as inputs

into her analysis of PREPA’s ability to pay its creditors.7

IV. BACKGROUND

A. Load And Expense Forecasting By Electric Utilities

20. Public utilities, including PREPA, collect revenues from customers through sales 

of utility service at regulated prices (“rates”) that may vary by customer type and usage patterns.8

Rates are constructed to ensure “revenue sufficiency,” which is achieved when the applicable 

rates multiplied by the volume of electrical demand (also known as the “load,” which is in effect 

equivalent to the volume of sales) produces revenues sufficient to cover the utility’s total costs.

9

In aiming for revenue sufficiency, therefore, utilities forecast both electrical demand and service 

costs.

21. Forecasting demand is necessary because electric utilities provide electricity 

service to customers “on demand,” and thus need to anticipate the volume of electricity that 

customers will use in the future. A utility’s forecast of its future electricity demand affects its 

7 Expert Report of Maureen M. Chakraborty, PhD, April 28, 2023 (hereafter “Chakraborty Report”).

8 “Cost Allocation is the process by which a utility's costs are attributed to different customers. The fundamental 

objective is to ensure that the revenue burden is being equitably shared amongst each customer class.” See National 

Association of Regulatory Utility Commissioners, “Primer on rate design for cost-reflective tariffs,” January 2021,

available at https://pubs.naruc.org/pub.cfm?id=7BFEF211-155D-0A36-31AA-F629ECB940DC.

9 National Association of Regulatory Utility Commissioners, “Primer on rate design for cost-reflective tariffs,” 

January 2021, pp. 8, 10, https://pubs.naruc.org/pub.cfm?id=7BFEF211-155D-0A36-31AA-F629ECB940DC.

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short-term to long-term operational requirements, infrastructure planning, financial planning, 

ratemaking, and other core business functions.10

22. Given the lead times for many types of capital investments and other substantial 

financial commitments, it is normal practice for a utility to make long-term load forecasts. As a 

general matter, the further out into the future the forecast period goes, the more complex and 

uncertain the forecast will be. Over periods extending decades into the future, electricity demand 

will be affected by many things, including population shifts, the impacts of climate change, and a 

host of other technological, economic, behavioral, and physical factors.

23. Utilities also develop detailed capital-cost forecasts in the regular course of 

business. Electric systems are capital-intensive and making investments to maintain or replace 

system facilities and infrastructure is a normal part of the utility business. Capital costs (and the 

service of the debt that finances them) must also be recovered through electricity rates, making a 

utility’s assumptions about its future capital needs a key input into its revenue-requirement and

rate forecasts. 

24. In my experience, it is critical that utilities engage in sound and unbiased demandforecasting methods, using the best available data, and avoiding the adoption of aggressive and 

aspirational assumptions that do not comport with such information. Similarly, capital-cost 

forecasts must present realistic estimates of money needed for infrastructure maintenance, repair, 

and replacement, so that a utility collects enough to keep its system in good order while not 

overcharging customers.

10 “Short-term” and “long-term” (and even “mid-range”) time periods tend to have different meanings in different 

utility contexts. For the purposes of this discussion, I use “short-term” to describe a period of one year or less, “midrange” to describe a period from over one year up to five years, and “long-term” to describe a period of over five 

years.

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B. The FOMB’s Legacy Charge Model Uses A Modified Version Of PREPA’s 

Existing Base Case Load Forecast

25. It is my understanding that the FOMB’s Plan of Adjustment for PREPA proposes 

a new Legacy Charge for PREPA customers to finance “New Bonds” that would be provided to 

PREPA’s existing creditors as partial recovery of what PREPA owes them.11 It is also my 

understanding that the amount of that Legacy Charge is derived from a model that is based on, 

among other things, PREPA’s existing 2022 Fiscal Plan gross load forecast of the volume of

electricity that PREPA would sell to customers from fiscal year 2023 through fiscal year 2051.12

That gross load forecast is then adjusted by certain load modifiers to reflect customers’ projected 

adoption of (i) energy efficiency measures and (ii) distributed generation technologies such as 

rooftop solar panels (both of which would result in a net reduction in load), and (iii) electric 

vehicles (which would result in a net increase in load) to create PREPA’s Base Case net load 

forecast for that forecast period.13

26. I also understand that the FOMB’s Legacy Charge Derivation (Plan Exhibit P) 

further modifies PREPA’s Base Case net load forecast to account for an assumed future price 

elasticity of demand—that is, a reduction of future demand that would be caused by customers’ 

responses to the price increase reflected in the Legacy Charge. Figure 1 shows how the FOMB

generated the modified net load forecast that it uses to derive its Legacy Charge proposal. Again, 

11 Disclosure Statement, p. 5.

12 PREPA’s load forecasts are prepared for PREPA’s fiscal years, which start on July 1 of the previous calendar 

year. For example, FY 2023 started on July 1, 2022 and will last until June 30, 2023.

13 PREPA’s “Base Case” is defined as “a load scenario that is based on assumptions for key gross load drivers (GNP 

and population projections consistent with Commonwealth Certified Fiscal Plan) and for key net load drivers related 

to energy efficiency (EE), distributed generation (DG) adoption and electric vehicle (EV) uptake. The net load 

driver assumptions in the Base Case are based on Act 17 compliance (EE achieving 30% target by FY 2040) and 

basic assumptions of future growth based on historical growth (DG and EV).” 2022 PREPA Fiscal Plan, p. 151;

“PREPA 2022 Fiscal Plan Model.xlsx,” FOMB_PREPA 00003018 (hereafter “2022 PREPA Fiscal Plan Model”).

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PREPA’s Base Case net load forecast is based on adjustments made to PREPA’s gross load 

forecast.

Figure 1: Components of PREPA’s Net Load Forecast as Used in the Derivation of 

FOMB’s Proposed Legacy Charge

Sources:

[1] Siemens, “Puerto Rico Integrated Resource Plan 2018-2019,” June 19, 2019, Section 3-1, available at 

https://energia.pr.gov/wp-content/uploads/sites/7/2019/06/IRP2019-Main-Report-REV2-06182019-

wERRATA.pdf.

[2] 2022 PREPA Fiscal Plan, pp. 151-152.

27. As a general matter, the FOMB’s modified net load forecast has the following 

significance: A higher forecast of future load would mean more electricity sales on which to 

assess a Legacy Charge, resulting in greater revenues from that Legacy Charge that PREPA 

could use to support payments on additional New Bonds as creditor recoveries. A higher forecast 

of future load would also allow PREPA to recover its projected fixed costs through lower nonLegacy-Charge base rates, as the same amount of fixed costs could be spread over more demand. 

By contrast, a lower forecast of future load would mean lower revenues collected by PREPA 

from a Legacy Charge, and a need for higher base rates to cover fixed costs.

28. Notably, PREPA has a higher forecast of future load than the Base Case the 

FOMB chose to use in its Legacy Charge model. PREPA’s 2022 Fiscal Plan includes an 

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“Alternative Forecast” of net load that is more realistic and reliable than the Base Case. The 

Fiscal Plan itself states that the Alternative Forecast is premised on a pace for the future adoption 

of energy efficiency measures, distributed generation, and electric vehicles that captures the 

current situation in Puerto Rico, is not constrained by targets in legislation, and incorporates the

latest cost data.

14 PREPA’s Base Case load forecast, by contrast, assumes as a given that

statutory energy-efficiency targets will be met, that installation of distributed generation 

technologies (like rooftop solar panels) will outpace what is predicted to happen in even the most 

aggressive and well-funded U.S. jurisdictions, and that there will be zero additional electrical 

demand from electric vehicles after 2038. PREPA’s Alternative Forecast predicts a significantly 

higher future net load than the Base Case forecast and is the more realistic and only plausible one 

of the two net load forecasts. The Plan of Adjustment provides no explanation for its use of the 

Base Case load forecast, rather than the Alternative Forecast, in its Legacy Charge model.

C. PREPA’s Gross Load Forecast Predicts Declining Load

29. PREPA’s gross load forecast is the starting point for the annual net load forecasts 

the FOMB relies on in its Legacy Charge Derivation (see Figure 1 above). PREPA forecasts that 

its gross load (before any of the adjustments that result in its forecasted net load) will steadily 

decline over the next three decades.

30. PREPA’s annual gross load forecast, for any given fiscal year, is the sum of its 

monthly gross load forecasts for the residential, commercial, industrial, agricultural, public 

lighting, and “other” customer categories.15 Those monthly gross load forecasts are principally 

14 2022 PREPA Fiscal Plan, p. 151.

15 2022 PREPA Fiscal Plan Model; Responses And Objections Of LUMA Energy, LLC And LUMA Servco, LLC 

To The Bondholders’ Document Requests, In re: The Financial Oversight and Management Board for Puerto Rico, 

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constructed based on separate regression models for the residential, commercial, and industrial 

sectors.16

31. The regression models in the 2022 PREPA Fiscal Plan use different sets of 

monthly macroeconomic and weather-related historical data as independent variables, including 

Puerto Rico’s real GNP, population, manufacturing employment levels,17 and temperature 

measures.18 To forecast PREPA’s gross loads for fiscal years 2023-2051, the regression models 

rely on forecasts of those explanatory variables (that is, forecasted GNP, forecasted population, 

etc.).19

as a representative of the Commonwealth of Puerto Rico, et al., Debtors, PROMESA Title III No. 17-BK-3283-

LTS, and In re: The Financial Oversight and Management Board for Puerto Rico, as a representative of Puerto 

Rico Electric Power Authority, Debtor, PROMESA Title III No. 17-BK-4780-LTS (Jointly Administered), United 

States District Court for the District of Puerto Rico, San Juan, Puerto Rico, April 12, 2023; LUMA Energy, “Load 

Forecast FY 2023,” June 21, 2022, available at https://energia.pr.gov/wp-content/uploads/sites/7/2022/06/LoadForecast-FY-2023_Values-3.xlsx.

16 Regression analysis is a statistical tool for analyzing historical data and determining the extent to which various 

combinations of explanatory (or “independent”) variables predict values for the outcome (or “dependent”) variable, 

in this case monthly electrical demand by sector. PREPA’s regression models were originally developed by 

Siemens as part of PREPA’s 2019 Integrated Resource Plan (hereafter “2019 IRP”). Siemens, “Puerto Rico 

Integrated Resource Plan 2018-2019,” June 19, 2019, Section 3-1, available at https://energia.pr.gov/wpcontent/uploads/sites/7/2019/06/IRP2019-Main-Report-REV2-06182019-wERRATA.pdf. The 2022 PREPA Fiscal 

Plan forecasts future load from the agricultural, public lighting, and “other” sectors as constant daily values, without 

any regression model.

17 The manufacturing employment series used by PREPA in the gross load forecast was not provided. Therefore, for 

modified load forecasts, I use the results of PREPA’s industrial sector gross load forecast to calculate the implied 

manufacturing employment series used in PREPA’s forecast.

18 PREPA’s regression model uses explanatory variables of a) for residential sector: Cooling degree days (CDD), 

real GNP, population, and month dummies; b) for commercial sector: CDD, population, and month dummies; c) for 

industrial sector: CDD, real GNP, manufacturing employment, and month dummies. CDD is a measure of how hot 

the temperature was during a period of days. Month dummies, also known as indicator variables, have a value of 1 if 

the observation is in the month represented by the variable and 0 otherwise. LUMA Energy, “Load Forecast FY 

2023,” June 21, 2022, available at https://energia.pr.gov/wp-content/uploads/sites/7/2022/06/Load-Forecast-FY2023_Values-3.xlsx; 2019 IRP.

19 I provide the annual GNP and population projections underlying the 2022 PREPA Fiscal Plan’s gross load 

forecast as Appendix C. Annual GNP and population projections are from the Commonwealth 2022 Certified Fiscal 

Plan.

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Figure 2, which is based on PREPA’s 2022 Fiscal Plan model, shows PREPA’s gross 

load forecast by customer type for each fiscal year from FY 2023 through FY 2051.20 PREPA

forecasts an 8.4% total decline in gross load over that period.21

Figure 2: PREPA Gross Load Forecast by Customer Type, Fiscal Years 2023-2051 

Source:

[1] 2022 PREPA Fiscal Plan Model.

V. PREPA’S NET LOAD FORECAST SIGNIFICANTLY UNDERSTATES FUTURE 

ELECTRICITY DEMAND

32. In this section, I show that PREPA’s Base Case net load forecast, which the 

FOMB uses in its Legacy Charge model, substantially understates future electricity demand. I 

begin by discussing the implications of an adjusted gross load forecast, based on Dr. Sebastian 

20 Demand by government agencies is included as part of “Commercial” demand.

21 PREPA predicts a decline in gross load from 16,870 GWh in FY 2023 to 15,458 GWh in FY 2051. See “Revenue 

Envelope and Legacy Charge_protected.xlsx” (hereafter “Revenue Envelope and Legacy Charge Model”).

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Edwards’s macroeconomic projections. I then demonstrate that the adjustments related to energy 

efficiency, distributed generation, and electric vehicles that PREPA makes to its gross load 

forecast to arrive at its Base Case net load forecast are unsupportable. 

A. Dr. Edwards’s Macroeconomic Projections Imply A Substantially Higher 

Gross Load Forecast For PREPA

33. As noted above, key inputs in PREPA’s gross load regressions include projections 

of Puerto Rico’s growth in real GNP and population. In his expert report, Dr. Sebastian Edwards 

considers the GNP projections, and prepares two modified projections that have higher GNP 

relative to the ones underlying the Plan of Adjustment.

22 I understand that one of Dr. Edwards’s 

scenarios is produced using his own economic-growth model for Puerto Rico in combination 

with population data from the World Bank and that the other scenario is based on

macroeconomic projections from the 2022 Commonwealth Fiscal Plan.

23

34. Figure 3 shows two adjusted gross load forecasts for FY 2023-2051, premised on 

incorporating each of Dr. Edwards’s two scenarios of macroeconomic projections into PREPA’s 

regression models: (a) Macro Scenario 1, which replaces the GNP projections used in PREPA’s 

existing gross load forecast with Dr. Edwards’s projections using a Solow Growth Model for 

GNP and World Bank population forecasts; and (b) Macro Scenario 2, which replaces the GNP 

projections used in PREPA’s gross load forecast with the baseline GNP forecast from the 2022 

Commonwealth Fiscal Plan Economic Outlook Model (including a COVID-19 income 

adjustment), as discussed in Dr. Edwards’s report.

24 Figure 3 also compares those two 

22 Edwards Report, Sections IV.F and V.B.3.

23 Edwards Report, Sections IV.F and V.B.3.

24 Edwards Report, Sections IV.F and V.B.3. and Appendix C.

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Edwards-adjusted gross load forecasts to PREPA’s existing gross load forecast (which, again, 

forms the basis for the modified net load forecast on which the FOMB’s Legacy Charge 

Derivation relies).

Figure 3: Forecasts of PREPA Gross Loads With Alternative Macroeconomic Inputs, 

Fiscal Years 2023-2051 

Sources:

[1] 2022 PREPA Fiscal Plan Model.

[2] Edwards Report, Appendix C.

35. I calculate that, using Dr. Edwards’s modified projections as new inputs into 

PREPA’s regression models (while keeping the rest of those models constant) produces gross 

load forecasts for fiscal years 2023-2051 that are between 2.3% to 7.3% higher, in aggregate

across all 29 fiscal years, than PREPA’s existing gross load forecast. The gross load forecast 

under Macro Scenario 1 is approximately the same at the beginning of the forecast period and 

13.4% higher at the end of the forecast period. The gross load forecast under Macro Scenario 2 is 

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4.1% higher at the beginning of the forecast period and 2.1% higher at the end of the forecast 

period.

B. PREPA’s Base Case Net Load Forecast Significantly Understates Future 

Electricity Demand By Making Unrealistic, Unsupportable Adjustments To 

Gross Load

36. FOMB’s Disclosure Statement filed March 1, 2023 and the Legacy Charge 

Derivation state that FOMB relied upon PREPA’s Base Case net load forecasts for fiscal years 

2023-2051 as a key input for its Legacy Charge model.25 That Base Case net load forecast starts 

with PREPA’s gross load forecast (discussed above in Section V.A) and adjusts it using “load 

modifiers” reflecting PREPA’s projections of: (i) future load reductions resulting from 

customers’ implementation of energy efficiency measures (“EE”);

26 (ii) future load reductions 

resulting from customers’ adoption of distributed generation technologies, primarily rooftop 

solar panels (“DG”);

27 and (iii) future load additions from customers’ adoption of electric 

vehicles (“EVs”).28

37. Figure 4 illustrates the combined net effect of these three load adjustments on 

PREPA’s gross load forecast. The resulting Base Case net load forecast estimates that energy 

efficiency and distributed generation, even after accounting for electric vehicles, will cause 

electricity demand in Puerto Rico to drop by more than half over the next three decades.

25 Disclosure Statement; Revenue Envelope and Legacy Charge Model.

26 2022 PREPA Fiscal Plan, pp. 147-148.

27 2022 PREPA Fiscal Plan, p. 149.

28 2022 PREPA Fiscal Plan, p. 150.

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deeply flawed and unreliable. Their combined effect is to significantly underestimate the volume 

of PREPA’s future electricity sales.

1. PREPA’s Base Case Forecast Of Reduced Net Load From Energy 

Efficiency Is Unreliable And Unreasonable

40. The most significant of the three “load modifiers” that PREPA uses to generate its 

Base Case net load forecast is the one that predicts a sharp decline in load from customers’ rapid 

adoption of energy efficient technologies. That load modifier takes as its premise that PREPA 

will achieve a statutory goal of a 30% load reduction by 2040 relative to 2019 levels by 

implementing robust energy efficiency programs. As I describe below, that is an unreliable way 

to forecast load reductions from energy efficiency, and in this instance, it leads to an 

unsupportable and unrealistic result. Indeed, PREPA’s own “Alternative Forecast” of energy 

efficiency adoption, which it based on a bottom-up analysis of actual data instead of assumption 

of statutory targets, results in a substantially smaller load reduction—and thus a higher net load 

forecast—than the base case the FOMB uses to determine its proposed Legacy Charge.

41. In 2014, Puerto Rico enacted the Energy Transformation and RELIEF Act, which 

directed PREPA, as now overseen by the Puerto Rico Energy Board (“PREB”), to achieve a 30% 

load reduction through energy efficiency programs by 2040.30 In 2019, Puerto Rico enacted the 

Puerto Rico Energy Public Policy Act, also known as “Act 17,” which reconfirmed that energy

efficiency goal.

31

30 See Office of Management and Budget, Puerto Rico Energy Transformation and RELIEF Act, Act No. 57 of May 

27, 2014, as amended, Section 6.29B — Energy Efficiency (codified as 22 L.P.R.A. § 1054bb-2), available at 

https://bvirtualogp.pr.gov/ogp/Bvirtual/leyesreferencia/PDF/2-ingles/57-2014.pdf.

31 Office of Management and Budget, Puerto Rico Energy Public Policy Act, Act. No. 17 of April 11, 2019 

(hereafter “Puerto Rico Energy Public Policy Act” or “Act 17”), available at 

https://bvirtualogp.pr.gov/ogp/Bvirtual/leyesreferencia/PDF/2-ingles/17-2019.pdf. In 2022, PREB issued regulations 

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42. As PREPA explains in its 2022 Fiscal Plan, its Base Case load modifier forecast 

for energy efficiency just takes as a given, rather than supports with evidence, that PREPA will 

meet that 30% load reduction target—and will do so right on time. It calls these “Act 17 

compliant projections.”32 In my opinion, that is an unreliable way for an electric utility to engage 

in load forecasting for business purposes. Rather than building out a forecast based on reasonable 

projections from the best available data, PREPA and FOMB instead start with the conclusion—

achievement of a 30% load reduction by 2040—and then “forecast” a line for getting from here 

to there.

43. Figure 5 shows this base case prediction for PREPA’s achievement of Act 17-

compliant load reductions from energy efficiency during the FY 2023 – FY 2051 forecast period.

clarifying that the baseline for this 30% reduction goal was FY 2019 electricity sales. PREB, Regulation for Energy 

Efficiency, Article 3, Energy Efficiency Savings Targets, March 25, 2022, available at https://energia.pr.gov/wpcontent/uploads/sites/7/2022/04/Reglamento-9367-Regulation-for-Energy-Efficiency.pdf.

32 2022 PREPA Fiscal Plan, p. 148.

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Figure 5: 2022 PREPA Fiscal Plan Base Case Energy Efficiency Forecast: 

Cumulative Energy Efficiency Savings Goals By Program

Fiscal Years 2023-2051

Source:

[1] 2022 PREPA Fiscal Plan Model.

44. A notable feature of this forecast—and indicative of its ends-driven approach—is 

the “elbow” at fiscal year 2040. The Base Case projects rapid increases in annual load reductions 

from energy efficiency through 2040—in time for the 30% reduction target stated in Act 17 to be 

achieved—but then predicts no further load reductions from energy efficiency for eleven years

thereafter. In other words, the forecast assumes that large, annual load reductions will occur per 

the schedule stated in Act 17, after which no more load reduction will be provided by increasing

energy efficiency. 

45. None of this is based upon evidence of what energy-efficiency gains can and will 

actually be achieved in Puerto Rico. To the contrary, the scenario reflected in the Base Case is 

implausible. Achieving PREPA’s energy efficiency forecast would require the widespread, rapid 

adoption of energy-efficient technologies (e.g., lighting, air conditioning, appliances) by multiple 

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types of customers (residential, commercial, industrial, etc.). In my experience, this would

necessitate large-scale private investments and government subsidies and programs that do not 

currently exist in Puerto Rico. In fact, as PREPA acknowledges in the 2022 PREPA Fiscal Plan, 

“To date, there is [...] no implementation or financing plan in place that would be typical for 

energy efficiency programs with targets of this scale, and it is unclear how energy efficiency 

measure[s] will be implemented or how much impact on load such measures will have.”33 PREB 

also acknowledged last year that there “have never been extensive utility-run energy efficiency 

programs in Puerto Rico.”34

46. LUMA, as PREPA’s transmission-and-distribution system operator, is developing 

a series of “Transition Period” energy efficiency programs and incentives in an attempt to 

overcome existing barriers to consumers’ adoption of energy efficiency.35 LUMA foresees a 

two-year transition period, in fiscal years 2023 and 2024, during which LUMA predicts that its 

initial energy-efficiency programs will generate some limited load reductions. But these 

cumulative reductions amount to only 17 GWh in FY 2023 and 41 GWh in FY 2024. Those 

projected reductions are two-thirds lower (69% and 65%, respectively) than the energyefficiency load reductions that PREPA’s Base Case assumes for FY 2023 and FY 2024.36 And 

PREB concedes that the “size and scope of Puerto Rico’s energy efficiency programs will be 

33 2022 PREPA Fiscal Plan, p. 74.

34 PREB, “Request for Proposals: Energy Efficiency Baseline and Potential Studies,” April 27, 2022 (hereafter 

“PREB Request for Proposals”), p. 5, available at 

https://static1.squarespace.com/static/61ea784947109b1572ec37ec/t/627cca4e2ddcae3086a1faf5/1652345423614/N

EPR+EE+Study+RFP+revised.pdf.

35 See LUMA Energy, “Transition Period Program Plan for Energy Efficiency and Demand Response,” June 21, 

2022 (hereafter “LUMA Transition Period Program Plan”), available at https://energia.pr.gov/wpcontent/uploads/sites/7/2022/06/Motion-Submitting-Proposed-EE-DR-Transition-Period-Plan-NEPR-MI-2021-

0006.pdf.

36 See Table 1. 69% and 65% are given by the ratio of 2022 LUMA Transition Period Plan predictions to the 2022 

Fiscal Plan predictions for 2023 and 2024, respectively.

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limited by practical considerations of program launch and scale-up during the next five years.”37

PREPA’s Base Case projection of energy-efficiency gains is also implausible in light of the fact 

that Puerto Rico has less-well-developed energy efficiency programs backed by government 

funding than exist in other U.S jurisdictions. In 2018, the American Council for an Energy 

Efficient Economy (“ACEEE”) assigned a 15% score out of 100% to Puerto Rico’s energy

efficiency programs and initiatives, which ranks it near the bottom of other U.S. states.

38

47. It is therefore not surprising to me that PREPA has repeatedly failed to meet its 

inflated forecasts for energy efficiency. PREPA’s 2020 Fiscal Plan estimated 303 GWh of 

cumulative savings from energy efficiency by FY 2022. Just one year later, PREPA’s 2021 

Fiscal Plan had cut that FY 2022 estimate to zero. Likewise, PREPA’s 2020 Fiscal Plan 

estimated 607 GWh in cumulative savings by FY 2023—an amount that was cut in half to 303 

GWh in the 2021 Fiscal Plan, and then down to 55 GWh in the 2022 Fiscal Plan.39 PREPA thus 

has repeatedly demonstrated it is not capable of accomplishing the load reduction from energy 

efficiency that is predicted by its Base Case forecast. In fact, the 2019, 2020, 2021, and 2022 

Fiscal Plans each show that PREPA has made virtually no progress on the Act 17 target on 

which the Base Case forecast relies. Table 1 shows the forecasts of energy efficiency in 

PREPA’s Fiscal Plans from 2020 through 2022, along with estimates from LUMA’s latest 

Transition Period Program Plan.

37 PREB Request for Proposals, p. 9.

38 ACEEE, “Puerto Rico,” July 20, 2018, available at https://database.aceee.org/territory/puerto-rico; ACEEE, “2018 

State Energy Efficiency Scorecard,” October 4, 2018, available at https://www.aceee.org/research-report/u1808.

39 See Table 1.

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Table 1: Fiscal Plan Estimates of Cumulative Savings from Energy Efficiency 

Programs: PREPA Fiscal Plans for FY 2020, FY 2021, and FY 2022 and LUMA Transition 

Period Program Plan

Forecast Source

Cumulative Savings Relative 

to 2019 Estimated to be 

Achieved by:

2020 PREPA 

Fiscal Plan 

2021 PREPA 

Fiscal Plan

2022 PREPA 

Fiscal Plan 

2022 LUMA 

Transition 

Period Plan

FY 2022 303 GWh 0 GWh – –

FY 2023 607 GWh 303 GWh 55 GWh 17 GWh

FY 2024 911 GWh 607 GWh 118 GWh 41 GWh

FY 2025 1,216 GWh 911 GWh 911 GWh –

Sources:

[1] “FOMB - June 2020 PREPA CFP Model_vS.03.xlsx,” FOMB_PREPA 00024556 (hereafter “2020 PREPA 

Fiscal Plan Model”).

[2] “FOMB - May 2021 FP Model_Data_Room_vF2.xlsx,” FOMB_PREPA 00020362 (hereafter “2021 PREPA 

Fiscal Plan Model”).

[3] 2022 PREPA Fiscal Plan Model.

[4] LUMA Transition Period Program Plan, p. 10.

48. Last year, PREPA effectively conceded that its Base Case forecast of load 

reduction from energy efficiency is unreliable. PREPA’s 2022 Fiscal Plan states that because its 

Act 17 compliance projections “are based on optimistic assumptions regarding participation rates 

and savings potential, the observed impact of such measures might be lower.”40 In fact, 

PREPA’s 2022 Fiscal Plan states clearly that “assumptions in the Base Case do not fully capture 

the actual constraints and realities in Puerto Rico or the state of current programs and plans in 

place to support these assumptions.”41

49. The 2022 PREPA Fiscal Plan therefore presents an “Alternative Forecast” 

projection of load reductions from energy efficiency (and other load modifiers) that, unlike the 

Base Case, this Alternative Forecast is based upon a ground-up analysis of data and trends. The 

Alternative Forecast shows lower load reductions (and thus higher net load) for every year after 

2024, as shown in Figure 6. In particular, it shows load reductions from energy efficiency that 

40 2022 PREPA Fiscal Plan, p. 148.

41 2022 PREPA Fiscal Plan, p. 151.

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Alternative Forecast assumes 100% customer adoption, each replacement cycle, of all modeled 

energy efficient non-lighting technologies (such as household appliances).43 And PREPA 

acknowledges that this models a best-case scenario of “maximum technical reduction in load due 

to EE” from such adoption.44 But even with that and other flaws, it is my opinion that PREPA’s 

Alternative Forecast, unlike the Base Case forecast, at least comports in broad strokes with basic 

principles of forecasting future outcomes based on the best available data.

2. PREPA’s Base Case Forecast Of Reduced Net Load From Distributed 

Generation Is Unsupported

51. PREPA’s Base Case net load forecast is further altered unreliably by its 

unsupported assumption that Puerto Rico will make unprecedented gains in customers’ 

installation of distributed generation facilities, which would reduce demand for electricity from 

the grid. PREPA assumes that this distributed generation will largely occur through the adoption

of rooftop solar panels by residential, commercial, and industrial customers, and growth in the 

use of combined heat and power (“CHP”) technologies by industrial customers. PREPA reports 

that its Base Case forecast for the use of distributed generation is based on the methodology used 

in PREPA’s 2019 Integrated Resource Plan.

45 That Base Case forecast starts with actual 

43 “PREPA 2022 FP Alternative Forecast.xlsx”, FOMB_PREPA 00003022 (hereafter “2022 PREPA Fiscal Plan 

Alternative Forecast Model”), tab “EE Inputs.”

44 2022 PREPA Fiscal Plan Alternative Forecast Model, tab “EE Inputs.”

45 The 2022 PREPA Fiscal Plan notes that “[d]eployment of distributed generation (i.e., rooftop solar and combined 

heat and power generation) is expected to grow and is projected based on the same methodology used for the IRP 

[2019 Integrated Resource Plan].” The 2019 IRP estimate of growth in customer-sited generation was based on 

historical trends as of 2018, which were then carried forward into future years. The 2022 PREPA Fiscal Plan also 

assumes growth in CHP in the industrial sector and notes “[t]he assumptions for CHP are based on customer survey 

and data gathering used in the IRP and updated by PREPA Planning and T&D personnel.” See 2022 PREPA Fiscal 

Plan, p. 149; Siemens, “Puerto Rico Integrated Resource Plan 2018-2019 Appendix 4: Demand Side Resources,” pp. 

3-19, available at https://aeepr.com/espr/QuienesSomos/Ley57/Plan%20Integrado%20de%20Recursos/IRP2019%20-%20Ex%201.04%20-

%20%20Appendix%204%20-%20Demand%20Side%20Resources.pdf.

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distributed generation output of 864 GWh in FY 2022, and predicts that output will increase 

nearly fivefold, to 4,298 GWh, by FY 2051.46

52. Those assumptions far outstrip any reliable forecast of what is reasonable to 

expect in view of the constraints on such adoption and the actual experience of other 

jurisdictions, including jurisdictions with more favorable economic environments for catalyzing 

such alternative energy progress. 

53. PREPA also has prepared an Alternative Forecast of distributed generation. But 

as with PREPA’s Alternative Forecast of energy efficiency gains, PREPA’s Alternative Forecast 

is ignored by the Plan of Adjustment in favor of the Base Case forecast. Unlike the Base Case 

forecast, the Alternative Forecast relies upon specific forecasts of distributed solar generation 

adoption by residential, commercial, and industrial customers which appear to be developed 

from estimates of distributed generation system costs and the incremental economic benefits to 

adopters from electricity bill savings.47

54. The Alternative Forecast also assumes that, consistent with Puerto Rico law, 

PREPA and PREB will soon consider reforms to the “net metering” program that determines the 

amount of any monetary credit customers receive for distributed-generated electricity they sell 

back to the grid.48 PREPA’s Alternative Forecast assumes that Puerto Rico’s post-2024 net 

46 2022 PREPA Fiscal Plan Model.

47 The Alternative Forecast uses NREL 2020 Annual Technology Baseline (ATB) estimates of installation and 

O&M costs for rooftop solar over time, assuming that Puerto Rico will face a 16% higher DG installation cost 

compared to the US mainland due to various logistical constraints. The Alternative Forecast does not re-estimate the 

forecast of CHP in the industrial sector. See 2022 PREPA Fiscal Plan, p. 153.

48 Currently, under the net metering program, customers with small distributed generation installations are 

compensated at 100% of the retail electricity rate for excess generation produced by the equipment and not used by 

the customer. DSIRE, “Puerto Rico – Net Metering,” October 12, 2021, available at 

https://programs.dsireusa.org/system/program/detail/2846/puerto-rico-net-metering.

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metering policy will avoid overpaying new net metering customers for power generated by 

rooftop solar panels and other distributed generation.49

55. Figure 7 shows PREPA’s Base Case and Alternative Forecasts for distributed 

generation (including CHP). Generally speaking, the Base Case forecast predicts faster adoption 

in the earlier years of the FY2023-2051 period, whereas the Alternative Forecast starts out 

slower but ultimately ends up with higher levels of load reductions.

Figure 7: 2022 PREPA Fiscal Plan Base Case and Alternative Distributed Generation 

and CHP Forecasts, Fiscal Years 2023-2051

Notes:

[1] Both PREPA forecasts include the load reduction from industrial Combined Heat and Power (“CHP”). 

The forecast for CHP is identical between the Base Case and Alternative forecasts.

[2] For the Alternative Forecast, I extrapolate 2051 load reduction values using the Alternative Forecast 

growth rates between 2049 and 2050 by forecast subcomponent.

Sources:

[1] 2022 PREPA Fiscal Plan Model.

[2] 2022 PREPA Fiscal Plan Alternative Forecast Model.

49 2022 PREPA Fiscal Plan, p. 154.

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56. In my opinion, the ground-up methodology used by the Alternative Forecast, and 

its more reasonable assumptions about future net metering policies, is the only one that is 

consistent with estimation methodology typically employed by other large public electricity 

utilities. But both forecasts, in my view and based on my experience, are unreasonably optimistic 

about the pace at which customers can be expected to adopt distributed generation.

57. In both the Base Case and Alternative Forecast, most of the predicted distributed 

generation capacity would come in the form of new rooftop solar generation, and most of that is 

expected to be installed by residential customers.50 But there are a number of substantial barriers 

to Puerto Rico households’ installation and use of solar generation systems that would need to be 

overcome, and whose impacts are understated in PREPA’s forecasts.

58. First, residential distributed solar systems are expensive. The Solar Foundation 

observes that the “upfront capital expenditure to purchase and install solar panels, inverters, 

balance of system equipment, racking systems, and storage is too steep an entry point for most 

individuals and families” in Puerto Rico.51 Based on cost and average system size assumptions 

made by PREPA’s Alternative Forecast, the average cost of a new residential photovoltaic 

(“PV”) system in fiscal year 2023 would be at least $13,702.52 That would be a substantial 

burden for most households in Puerto Rico. Moreover, the up-front cost for solar installations in 

50 See 2022 PREPA Fiscal Plan Model; 2022 PREPA Fiscal Plan Alternative Forecast Model.

51 The Solar Foundation, “Finance Report: An Assessment of Opportunities and Barriers to Solar Finance in Puerto 

Rico,” April 2021, p. 13, available at https://irecusa.org/wp-content/uploads/2021/07/FinanceReport-Completed_5-

13.pdf.

52 $13,702 is $2,635 per kW “Installed Cost post-ITC” multiplied by the assumed “running average PV system size” 

of 5.2 kW (the average of 4.8kW from the 2022 PREPA Fiscal Plan Alternative Forecast Model “High Adoption” 

tab and 5.6kW from the “Low Adoption” tab). The “post-ITC” cost assumes that the household customer is eligible 

for a 22% federal investment tax credit. PREPA’s projected “Installed Cost” without the ITC credit is $3,378/kW, 

which implies a total system cost of $17,566. See 2022 PREPA Fiscal Plan Alternative Forecast Model, tabs “Low 

Adoption”, “High Adoption”, “Model – Low”, “Model – High.”

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U.S. states is partially defrayed by a federal investment tax credit (“ITC”) for distributed solar 

(which as of 2023, provides a credit of 30% of solar equipment and installation costs).53 But U.S. 

federal income tax does not apply to Puerto Rico income, and so most households do not have a 

federal tax liability to offset with this non-refundable tax credit.54 Solar financing to residential 

customers could offset some up-front costs to households, but those options remain limited 

because, among other things, “[s]olar financing is not advertised nor marketed aggressively by 

any of the coops, traditional banks, or federal credit unions in Puerto Rico” and PREB has raised 

legal issues with power purchase and lease financing agreements.55

59. Second, there are operational barriers to distributed solar installations. The 

Alternative Forecast assumes that 85% of all residential customers have access to rooftops 

suitable for solar panel adoption, based on a NREL study.56 But the Alternative Forecast 

confuses technical potential (which analyzes the suitability of technology adoption based on 

things like having a large enough surface with an unobstructed line of sight to the sun for a 

sufficient portion of the day) with economic and logistical feasibility or viability. In short, the 

percentage of suitable rooftops is not the same as the percentage of eligible customers who can 

53 Solar Energy Technologies Office, “Homeowner’s Guide to the Federal Tax Credit for Solar Photovoltaics,” 

March 2023, available at https://www.energy.gov/eere/solar/homeowners-guide-federal-tax-credit-solarphotovoltaics. 

54 IRS, “Topic No. 901, Is a Person with Income from Puerto Rico Required to File a U.S. Income Tax Return?” 

April 7, 2023, available at https://www.irs.gov/taxtopics/tc901. According to the Energy Department the federal tax 

credit for solar PV “is a nonrefundable tax credit, which means you will not get a tax refund for the amount of the 

tax credit that exceeds your tax liability.” Solar Energy Technologies Office, “Homeowner’s Guide to the Federal 

Tax Credit for Solar Photovoltaics,” March 2023, available at https://www.energy.gov/eere/solar/homeownersguide-federal-tax-credit-solar-photovoltaics. 

55 The Solar Foundation, “Finance Report: An Assessment of Opportunities and Barriers to Solar Finance in Puerto 

Rico,” April 2021, p. 14, available at https://irecusa.org/wp-content/uploads/2021/07/FinanceReport-Completed_5-

13.pdf. 

56 2022 PREPA Fiscal Plan Alternative Forecast Model, tab “NREL”; NREL, “Puerto Rico Low-to-Moderate 

Income Rooftop PV and Solar Savings Potential,” December 17, 2020, available at

https://www.nrel.gov/docs/fy21osti/78756.pdf.

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feasibly (and legally) install solar panels on those roofs. For example, in 2021, over 30% of 

Puerto Rico’s households were renters who cannot unilaterally decide to install rooftop solar 

panels on their landlords’ roofs.57 Moreover, residents of multi-story apartment complexes or 

condos may live in buildings with suitable roofs but would face multiple constraints to installing 

rooftop solar panels on those buildings. Accordingly, significantly fewer than 85% of all 

residential customers would realistically be able to adopt distributed solar, even leaving aside the 

economic barriers.

60. Finally, the kind of substantial, increased deployment of distributed generation 

modeled by PREPA’s forecasts would likely require PREPA to make significant investments in 

its grid infrastructure to accommodate the injection of such decentralized power supply on a 

reliable basis.58 The effects of distributed generation on local grids can be location-specific, 

sometimes imposing substantial costs and operational challenges for the system, such as voltage 

control, power quality, advanced communications, power electronics, and management of energy 

imbalances across different distribution circuits.59 PREPA does not yet have deep experience 

integrating high-penetration levels of distributed generation into its system, and its net load 

57 The owner-occupied housing unit rate is 68.0%. US Census, “QuickFacts Puerto Rico,” available at 

https://www.census.gov/quickfacts/fact/table/PR/HSG445221.

58 See, for example, National Academies of Sciences, Engineering and Medicine, The Future of Electric Power in 

the U.S., The National Academies Press, 2021, available at https://doi.org/10.17226/25968. (As a member of the 

NASEM Committee on the Future of Electric Power, I am a co-author of this report.) See also Tierney, Susan, “The 

Value of ‘DER’ to ‘D’: The Role of Distributed Energy Resources in Supporting Local Electric Distribution System 

Reliability,” Analysis Group, March 31, 2016, available at 

https://www.analysisgroup.com/globalassets/content/news_and_events/news/value_of_der_to-_d.pdf.

59 See Razavi, Seyed-Ehsan, et al. “Impact of Distributed Generation on Protection and Voltage Regulation on 

Distribution Systems: A Review,” Renewable and Sustainable Energy Reviews, Vol. 105, May 2019, available at 

https://www.sciencedirect.com/science/article/abs/pii/S1364032119300668.

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forecasts underestimate that practical limitation on the reasonable pace of future rooftop solar 

adoption.60

61. The result of making these aggressive and unsupported assumptions about 

residential solar adoption is that PREPA’s Base Case and Alternative Forecast both assume 

much greater growth of distributed generation than is reasonable to expect in Puerto Rico, or 

even in states with much more experience and governmental funding to support distributed 

generation adoption. Figure 8 compares PREPA’s Base Case and Alternative Forecast of 

distributed solar generation to NREL’s mid-case scenario forecasts for U.S. states with the 

highest levels of predicted load reduction from distributed solar generation between 2020 and 

2050.61 Each of these states have higher median household incomes than Puerto Rico.62 

Although my experience leads me to expect that Puerto Rico’s pace of solar adoption should be 

slower than these states, PREPA’s forecasts predict that Puerto Rico pace of adoption will, by 

2037, surpass even these leading states—and, indeed, all states in the contiguous U.S. That is 

unrealistic and unsupported. 

60 NREL observes a “[l]ack of knowledge, understanding, and experience” as an issue for the integration of 

distributed energy resource integration in Puerto Rico. Narang, David, et al., “Considerations for Distributed Energy 

Resource Integration in Puerto Rico,” NREL, February 2021, p. vii, available at 

https://www.nrel.gov/docs/fy21osti/77127.pdf. 

61 NREL, “Mid-Case Scenario,” State and Local Planning for Energy, available at https://maps nrel.gov/slope/dataviewer?layer=standard-scenarios mid-re-cost&res=state&year=2020&filters=%5B%5D. The Mid-Case scenarios for 

other states are based on (i) electricity demand growth and natural gas prices from the Annual Energy Outlook 2020 

Reference scenario, (ii) Mid-case technology, battery storage, and finance (20-year capital recovery period) cost 

projections from the 2020 Annual Technology Baseline, (iii) reference retirements (i.e., the model retires plants 

when they reach a specified lifetime or if their revenues are not sufficient to cover their costs), and (iv) current law 

(i.e., state, regional, and federal energy policies as of May 31, 2020). NREL does not predict power system 

evolution in Hawaii or Alaska.

62 US Census, 2017-2021 American Community Survey 5-year Estimates, available at 

https://data.census.gov/table?q=median+household+income+california&g=040XX00US04,06,12,15,25,34,50,72&ti

d=ACSST5Y2021.S1903. 

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Figure 8: Distributed Solar Generation Forecast from 2022 PREPA Fiscal Plan 

Compared to NREL Mid-Case Forecasts for Other U.S. States

Notes:

[1] Distributed solar generation data are provided by NREL every 2 years starting in 2018.

[2] The PREPA forecasts of distributed generation exclude CHP for the industrial sector. 

[3] Distributed generation data from the Alternative Forecast is replaced with historical data from the 2022 

Fiscal Plan for the years before 2023. 

[4] For the Alternative Forecast, I extrapolate 2051 load reduction values using the Alternative Forecast 

growth rates between 2049 and 2050 by forecast subcomponent.

Sources: 

[1] NREL, “Net Electricity and Natural Gas Consumption,” State and Local Planning for Energy, 2019, 

https://maps nrel.gov/slope.

[2] NREL Data Viewer, “Mid-Case Scenario,” State and Local Planning for Energy, 2020, 

https://maps nrel.gov/slope.

[3] 2022 PREPA Fiscal Plan Model. 

[4] 2022 PREPA Fiscal Plan Alternative Forecast Model. 

62. For example, PREPA surprisingly—and implausibly—forecasts that Puerto 

Rico’s distributed solar adoption will outpace California, a historical leader in distributed solar 

adoption. But there are important differences between the two: California has substantially 

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higher median income than households in Puerto Rico,63 and unlike Puerto Rico, California has 

state-mandated policies supporting consumer adoption of rooftop solar. California began its 

California Solar Initiative back in 2007, which included significant funding for low-income 

households to install solar equipment through the Single Family Affordable Solar Homes 

program.64 One of California’s major electric utilities testified that “since 2008, the CPUC 

[California Public Utilities Commission] has adopted $2 billion in funding for [solar] programs

with approximately $1.3 billion remaining to be spent through 2038.”65 Puerto Rico would need 

to make an extraordinary and unprecedented investment in support for distributed solar 

generation to cause the kind of huge gains in adoption rates over the next decade that would even 

approach California’s level of progress, much less to surpass it.

63. While both are flawed, the Alternative Forecast of adoption of distributed

generation, as compared to the Base Case forecast, provides an estimation methodology more 

consistent with typical forecasting practice. But both forecasts significantly overstate the likely 

pace of adoption of distributed generation, and therefore understate likely net load in the future.

63 In 2021, the Census reported that median household income was $84,097 in California. By contrast, in 2021 

median household income was only $21,967 in Puerto Rico. US Census, 2017-2021 American Community Survey 5-

year Estimates, available at 

https://data.census.gov/table?q=median+household+income+california&g=040XX00US04,06,12,15,25,34,50,72&ti

d=ACSST5Y2021.S1903.

64 California Public Utilities Commission, “About the California Solar Initiative,” available at

https://www.cpuc.ca.gov/-/media/cpuc-website/about-cpuc/documents/transparency-andreporting/fact_sheets/csifactsheet_v4.pdf.

65 Three quarters of the funding is from the proceeds California receives as revenues in the sale of GHG emission 

allowances in its cap-and-trade-program. Joint Opening Testimony of Southern California Edison Company, Pacific 

Gas and Electric Company and San Diego Gas & Electric Company before the California Public Utilities 

Commission, R.20-08-020 Order Instituting Rulemaking to Revisit Net Energy Metering Tariffs Pursuant to 

Decision 16-01-044, and to Address Other Issues Related to Net Metering, June 18, 2021, p. 166.

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3. PREPA’s Base Case Forecast Of Additional Net Load From Electric 

Vehicles Is Arbitrarily Truncated And Understated 

64. The Base Case further understates net load by arbitrarily assuming that load 

growth resulting from increased adoption of electric vehicles will abruptly halt in 15 years. The 

increased use of electric vehicles tends to increase the future loads on electric utility systems, 

including PREPA, as the penetration of electric vehicles increases over time. To state the 

obvious, electric vehicles are recharged by plugging them into an electricity source, instead of by 

refilling a gas tank. The 2022 PREPA Fiscal Plan observes that “a significant uptake in EV sales 

will have an impact on electricity demand, both on average and peak load and has the potential 

to offset the effect of EE and DG.”66 PREPA’s load forecasts thus acknowledge that increasing 

use of electric vehicles in Puerto Rico increases electricity demand, all else being equal. 

PREPA’s Base Case forecast assumes load growth in the residential and commercial sectors 

from the increasing automobile-market penetration of electric vehicles.67 The Base Case states a 

forecast of EV demand, and resulting load addition, that is assertedly founded on “basic 

assumptions of future growth based on historical growth,” but the Fiscal Plan provides no 

evidence for its assumptions.

65. As shown in Figure 9, PREPA’s Base Case assumes unexplained year-to-year 

incremental additions to electricity load from charging EV batteries. PREPA forecasts those 

incremental additions to grow from 2022 through 2038, with roughly a doubling of electricity 

consumption by EVs every five years from 2020 through 2038. Then, starting in 2038, the 

forecast abruptly switches to predicting no further increases in EV-related load. In other words, 

66 2022 PREPA Fiscal Plan, pp. 150-151.

67 The 2022 PREPA Fiscal Plan Base Case forecast assumes zero growth in EV load from the industrial or any other 

sectors.

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PREPA’s Base Case net load forecast appears to assume that however many EVs are on the 

streets of Puerto Rico in 2038, the PREPA system will have the same total electric usage by EVs

in 2051. This growth-to-no-growth pattern is inexplicable and unsupportable; it is not reasonable 

to assume that there will be no change in EV consumption from 2038 through 2051.

Figure 9: Electric Vehicle Forecast from 2022 PREPA Fiscal Plan Base Case

Source:

[1] 2022 PREPA Fiscal Plan Model.

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66. Once again, PREPA’s Alternative Forecast provides a more reasonable approach

than the Base Case EV load forecast. PREPA states that the Alternative Forecast is based on a 

ground-up projection of the total number of electric vehicles in Puerto Rico over time and takes 

into account things like an electric vehicle’s cost of ownership and Puerto Rico’s gasoline prices 

versus electricity rates. This alternative approach estimates that “33% of cars in Puerto Rico [will 

be] EVs by 2050,” and estimates the corresponding additional electrical demand from these 

vehicles.

68 I note that, like the Alternative Forecast projection presented for energy efficiency 

and distributed generation, the Alternative Forecast for the adoption of electric vehicles forecasts 

greater consumption of electricity as compared to the Base Case. That is, what all three 

alternative load modifier forecasts have in common is that (i) they all project greater demand for 

electricity than in their respective Base Case forecasts and (ii) none of them are considered in the 

Plan of Adjustment.

67. Figure 10 compares the Base Case forecast and Alternative Forecast of EV 

demand.

68 2022 PREPA Fiscal Plan Alternative Forecast.

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even that forecast may well understate the likely amount of load increase resulting from EV 

adoption, given IHS Markit projections that 41% of cars in the U.S. will be electric by 2050.69

C. A More Realistic PREPA Net Load Projection Would Be Much Higher Than 

That Projected by PREPA

70. The FOMB’s assumptions about gross load, energy efficiency, distributed 

generation, and electric vehicles together lead to a substantial downward bias in anticipated 

levels of electricity sales in the future. In Figure 11 below, I show revised net load forecasts (not 

including the FOMB’s elasticity effect which will be discussed separately in Section VII) using 

two sets of revised forecast components:

1) Forecasts for gross load are recalculated using revised macroeconomic model inputs for 

Puerto Rico’s real GNP and population from Dr. Edwards (which I discussed earlier in 

Section VI.A).

2) Forecasts for the energy efficiency, distributed generation, and electric vehicle load modifiers 

from the Base Case are replaced with PREPA’s Alternative Forecast projections from the 

2022 PREPA Fiscal Plan (which I discussed earlier in Section VI.B).

71. These revised net load forecasts show substantially higher loads compared to the 

Base Case net load forecast underlying the Legacy Charge Derivation. The revised net load 

forecast using PREPA’s Alternative Forecast and Edwards’s Solow growth model (the green line 

69 Plumer B, Popovich N, and Migliozzi B, “Electric Cars Are Coming. How Long until They Rule the Road?” New 

York Times, March 2021, available at https://www.nytimes.com/interactive/2021/03/10/climate/electric-vehiclefleet-turnover.html.

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in Figure 11) is 2,028 GWh (15%) higher than FOMB’s net load forecast in 2030, and the 

revised net load forecast is 3,965 GWh (49%) higher in 2050.70

Figure 11: Revised PREPA Net Load Forecasts with PREPA Alternative Forecast Load 

Modifiers and Revised Macroeconomic Inputs, Fiscal Years 2023-2051

Sources:

[1] 2022 PREPA Fiscal Plan Model.

[2] Revenue Envelope and Legacy Charge Model.

[3] Edwards Report, Appendix C.

70 See Figure 11 Backup. I provide the revised net load forecasts for each customer type and fiscal year in

Appendix D. For each revised net load forecast, I also recalculate the implied PREPA base rates for each customer 

type and fiscal year. I describe my base rate recalculation methodology and results in Appendix E.

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VI. PREPA HAS A TRACK RECORD OF UNDERESTIMATING NET LOAD

72. The clearest evidence that PREPA’s net load forecasts incorporate a downward 

bias is their historical results. Each of PREPA’s Fiscal Plans from 2017 through 2022 includes a 

projection of net load for the immediately upcoming fiscal years. In each of these years’ forecast 

of future sales where there is now actual historical data to compare to PREPA’s prior net load 

forecasts, the actual data exceed the prediction—sometimes substantially.

73. The dotted line in Figure 12 (which tracks the historical portion of the red, 2022 

Fiscal Plan line) shows PREPA’s actual sales of electricity through fiscal year 2022. This is 

compared to other lines depicting the corresponding load forecast in PREPA’s prior fiscal plans. 

For example, the 2017 PREPA Fiscal Plan projected that net load in fiscal year 2021 would be 

only 14,476 GWh, but the actual load that fiscal year was 16,280 GWh. That 11% 

underestimation of net load just four years earlier is a substantial forecasting error. The 2018-

2020 PREPA Fiscal Plans included updated forecasts of net load in fiscal year 2021, each of 

which was also too low by amounts ranging from 3% to 14%71.

71 The 3% and 14% amounts are equal to the forecasted net sales for fiscal year 2021 from the 2020 PREPA Fiscal 

Plan and the 2018 PREPA Fiscal Plan, respectively, divided by actual observed net sales for fiscal year 2021.

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according to FOMB, would result in lower-than-expected load as compared to the load forecast

that otherwise results from the factors I have described above. FOMB argues that this demand 

reduction would then lead to less revenue collected to cover PREPA’s fixed costs. FOMB states

that it needs to reserve a portion of PREPA’s available “Revenue Envelope”72 to make up for 

that assumed shortfall, thus reducing its ability to repay creditors.73

76. For the reasons I discuss below, FOMB’s estimation of that elasticity effect is 

unreasonable, inconsistent with the academic literature on elasticity, and unsupported by 

PREPA’s own prior load-forecasting assumptions. 

A. Background On Price Elasticity In Electricity

77. Price elasticity refers to the degree to which consumer demand changes in 

response to a change in price.74 Mathematically, the elasticity of demand measures the 

percentage change in the quantity demanded for a product or service due to a one percent change 

in the price of that product or service.75 A price elasticity of −0.6, for example, means that the 

quantity demanded decreases 0.6% in response to a 1.0% price increase.

78. In electricity markets, there are a number of ways in which higher rates might 

affect electricity demand: (i) customers might make behavioral changes (e.g., turning off lights, 

72 As described in Dr. Maureen Chakraborty’s Expert Report, the “Revenue Envelope” is the maximum additional 

revenue that could be generated by the Legacy Charge that is affordable to PREPA customers. Chakraborty Report, 

Sections II and III.

73 “An important consideration for the Oversight Board in designing the Legacy Charge was the impact that 

increasing PREPA’s rates would have on PREPA’s sales. As a general matter, the higher PREPA’s rates are, the 

more PREPA’s rates incentivize customers to choose alternatives.” Legacy Charge Derivation, p. 3.

74 Besanko, David and Ronald Braeutigam, Microeconomics, John Wiley & Sons, 6th Ed., 2020 (hereafter “Besanko

and Braeutigam (2020)”), p. 44, available at

https://faculty ksu.edu.sa/sites/default/files/David%20Besanko%2C%20Ronald%20Braeutigam%20-

%20Microeconomics-Wiley%20%282020%29.pdf.

75 Besanko and Braeutigam (2020), pp. 44-45.

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waiting longer before turning on the air conditioning) resulting in lower power consumption; 

(ii) customers might invest in and install technologies (more efficient appliances, rooftop solar 

panels, etc.) that reduce electricity purchases from the grid; or (iii) customers might leave the 

grid entirely (going “off-grid” by taking full responsibility for their own electricity supply, 

moving away, etc.).

79. Elasticity effects in the use of electricity differ by customer type. For example, 

companies that engage in electricity-intensive activities may be more sensitive to electricity 

prices in their consumption decisions and be more motivated to find alternatives that reduce 

electricity purchases from the grid if the expense of that electricity grows and is expected to 

remain higher in the future.76 By contrast, other customers might use electricity only for 

necessary basic functions (e.g., lighting, refrigeration, etc.), or may run a business in which 

electricity costs are only a small fraction of total expenses, and thus be far less sensitive to 

electricity prices in their consumption decisions.

80. Elasticity effects in use of electricity also may differ by time horizon, because 

consumers’ ability to adjust their electricity consumption in response to price changes varies 

over time. Generally speaking, consumers have fewer opportunities to adjust to electricity price 

changes in the near term than in the long term. For example, a residential customer facing higher 

electricity rates may be able to replace household appliances with more energy-efficient models 

76 “To see why a business might care about the price elasticity of demand, let’s consider how an increase in price 

might affect a business’s total revenue, that is, the selling price times the quantity of product it sells, or PQ. You 

might think that when the price rises, so will the total revenue, but a higher price will generally reduce the quantity 

demanded. Thus, the “benefit” of the higher price is offset by the “cost” due to the reduction in quantity, and 

businesses must generally consider this trade-off when they think about raising a price. If the demand is elastic (the 

quantity demanded is relatively sensitive to price), the quantity reduction will outweigh the benefit of the higher 

price, and total revenue will fall. If the demand is inelastic (the quantity demanded is relatively insensitive to price), 

the quantity reduction will not be too severe, and total revenue will go up. Thus, knowledge of the price elasticity of 

demand can help a business predict the revenue impact of a price increase.” Besanko and Braeutigam (2020), p. 49.

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over a few years but is less likely to do so immediately after seeing the first increase in her utility

bill.

B. FOMB’s Price Elasticity Assumptions Are Unsupported And Contradicted

By The Academic Literature

1. FOMB’s Posited Elasticity Effect Is Estimated From A Series Of 

Unexplained Assumptions And Adjustments 

81. FOMB’s Legacy Charge Derivation assumes the same short-run elasticity of 0.2 

for each of PREPA’s rate classes.

77 In the short run, therefore, FOMB assumes that a 1% price 

increase will cause a 0.2% decrease in sales for each class of customers. Over the long run, 

however, FOMB assumes different elasticity rates for different customer groups.

82. Table 2, in its first and third columns, shows FOMB’s short- and long-term 

elasticity estimates for each customer class as used in the FOMB’s Legacy Charge Derivation.

The middle column of the table lists the “Long Run Elasticity Factors” the FOMB uses. For 

example, as the table shows, PREPA’s general residential customers, in rate class GRS 112, are 

estimated to have a long-run elasticity of -1.7 (i.e., a 1.7% decline in demand for every 1% 

increase in price). Commercial customers, in rate class GSS 211, are estimated to have less 

elastic demand (i.e., demand that is less responsive to price changes), with a long-run elasticity 

of -0.68.

77 PREPA’s “rate classes” are its classifications of customer types that are typically charged different prices and may 

face different pricing structures. PREPA’s rate classes and pricing per rate class are described in detail in PREPA's 

tariff book. PREPA, “Tariff Book - Electric Service Rates and Riders,” May 28, 2019, available at 

https://aeepr.com/es-pr/QuienesSomos/Ley57/Facturaci%C3%B3n/Tariff%20Book%20-

%20Electric%20Service%20Rates%20and%20Riders%20Revised%20by%20Order%2005172019%20Approved%2

0by%20Order%2005282019.pdf; Revenue Envelope and Legacy Charge Model.

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Table 2: Elasticity Assumptions by PREPA Rate Class Used in Legacy Charge Derivation 

Source:

[1] Revenue Envelope and Legacy Charge Model. 

83. The FOMB derives these estimates of each customer class’s long-run elasticity 

from two academic papers: Burke and Abayasekara (2018),78 published in The Energy Journal, 

and Buchsbaum (2022),79 an unpublished, non-peer reviewed working paper. Burke and 

78 Burke, Paul J. and Ashani Abayasekara, “The Price Elasticity of Electricity Demand in the United States: A 

Three-Dimensional Analysis,” The Energy Journal, Vol. 39, 2018 (hereafter “Burke and Abayasekara (2018)”),

FOMB_PREPA 00020208 - FOMB_PREPA 00020243, available at https://doi.org/10.5547/01956574.39.2.pbur. 

79 Buchsbaum, Jesse, “Long-Run Price Elasticities and Mechanisms: Empirical Evidence from Residential 

Electricity Consumers,” Energy Institute Working Paper 331, 2022 (hereafter “Buchsbaum (2022)”),

FOMB_PREPA 00022518 - FOMB_PREPA 00022589, available at https://haas.berkeley.edu/wpcontent/uploads/WP331.pdf. 

Short Run 

Elasticity

Long Run 

Elasticity 

Factors

Long 

Run 

Elasticity

Residential

RH3, LRS, RFR -0.2 100% -1.7

GRS 111 -0.2 100% -1.7

GRS 112 (LC Subsidy eligible) -0.2 100% -1.7

GRS 112 (General) -0.2 --- -1.7

Commercial

GSS 211 -0.2 40% -0.68

GSP 212 -0.2 70% -1.19

GST 213 -0.2 100% -1.7

Government

GSS 211 -0.2 40% -0.68

GSP 212 -0.2 70% -1.19

GST 213 -0.2 100% -1.7

Municipalities

GSS 211 -0.2 40% -0.68

GSP 212 -0.2 70% -1.19

GST 213 -0.2 100% -1.7

Industrial

GSS 311 -0.2 50% -0.85

GSP 312 -0.2 50% -0.85

GST 313 -0.2 75% -1.275

TOU-T 363 -0.2 75% -1.275

LIS 333 -0.2 75% -1.275

TOU-T 963 -0.2 75% -1.275

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Abayasekara (2018) use U.S. state-level data for the lower 48 states, from 2003-2015, to estimate 

long-term elasticities for different customer classes: residential (-1.0), commercial (-0.3 to -0.6), 

industrial (-1.2), and general (-0.9).

80 Buchsbaum (2022) uses data on residential PG&E 

customers in Northern and Central California, from 2008-2020, to estimate those customers’

long-run price elasticity at -2.4.81

84. The FOMB uses the Burke and Abayasekara (2018) values to set baseline 

estimates of each customer class’s long-run elasticity.82 The FOMB asserts, however, that those 

baseline estimates do not reflect any effect on customers’ price elasticity of their potential 

adoption of solar PV systems in response to higher electricity rates.83 By contrast, the FOMB 

asserts that the Buchsbaum (2022) estimate of PG&E residential customers’ long-run elasticity 

does account for the potential adoption of solar PV systems.84 FOMB thus takes the difference 

between the two estimates of residential elasticity (-1.4) and calls it an “Incremental Solar PV 

effect.”85 FOMB then adds half of that amount (or -0.7) to the Burke and Abayasekara (2018) 

baseline estimate of residential customers’ long-run elasticity (-1.0), resulting in FOMB’s final 

estimate of their long-run elasticity of -1.7.

86 By this measurement, approximately 40% of 

residential customers’ long-run elasticity would be attributable solely to the option to install solar 

panels.

80 Burke and Abayasekara (2018).

81 Buchsbaum (2022), pp. 3, 10.

82 “LT Elasticity workbook.xlsx,” FOMB_PREPA 00022590.

83 “LT Elasticity workbook.xlsx,” FOMB_PREPA 00022590.

84 “LT Elasticity workbook.xlsx,” FOMB_PREPA 00022590.

85 -1.4 is the difference between the Buchsbaum (2022) estimate of residential elasticity of -2.4 minus the Burke and 

Abayasekara (2018) estimate of -1.0. “LT Elasticity workbook.xlsx,” FOMB_PREPA 00022590.

86 “LT Elasticity workbook.xlsx,” FOMB_PREPA 00022590.

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85. Further complicating this unusual elasticity calculation, the FOMB then estimates

long-run elasticity for other customer classes by applying different percentages of the 

“Incremental Solar PV Effect” to the Burke and Abayasekara (2018) estimates of elasticity for 

the commercial and industrial customer classes.87 The FOMB then calculates rounded “Long 

Run Elasticity Factors” by customer classes as a specified percentage of general residential 

customers’ long-term elasticity.

88 Those “Long Run Elasticity Factors,” and each customer 

class’s final, long-run elasticity estimate are listed in Table 2.

86. The FOMB does not provide any supporting documents related to its assumption 

of the same short-term elasticity of -0.2 across all customer classes. The two papers FOMB uses

for its long-term elasticity estimates calculate different short-term elasticity estimates. Burke and 

Abayasekara (2018) calculate short-term elasticity of “around -0.1 or less for all sectors”89 and 

Buchsbaum estimates short-term elasticity of -0.36.90

2. The Board’s Long-Term Elasticity Estimates Are Not Supported By 

The Cited Authority

87. The FOMB’s analysis is not supported by the academic papers it relies on, and its

methodological approach results in flawed and unreliable long-run elasticity estimates.

88. First, the FOMB misinterprets the Burke and Abayasekara (2018) results when it 

contends that their estimates exclude solar PV effects (if any). In fact, Burke and Abayasekara 

(2018) estimates the demand reduction from higher electricity prices attributable to all causes, 

87 The percentage of the “Incremental Solar PV Effect” applied ranges from 5% to 100% depending on the 

commercial or industrial rate class. “LT Elasticity workbook.xlsx,” FOMB_PREPA 00022590.

88 Revenue Envelope and Legacy Charge Model.

89 Burke and Abayasekara (2018), p. 123.

90 Buchsbaum (2022), p. 1.

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necessarily including any such reduction relating to solar PV adoption. The data underlying 

Burke and Abayasekara (2018) extend through 2015, and so cover a period during which solar 

installations increased and were available to many customers. There is thus no basis for the 

FOMB’s adjustment of the Burke and Abayasekara (2018) elasticity estimates upward to 

incorporate any additional elasticity effect corresponding to solar PV system adoption.

89. Moreover, the FOMB is mistaken that the Buchsbaum (2022) estimate of higher 

long-run elasticity for PG&E residential customers is premised on those customers’ ability to 

adopt solar PV systems. First, Buchsbaum himself states that, “[n]otably, I do not find that 

consumers are responsive to long-run prices in their adoption of rooftop solar or utility energy 

efficiency programs,”91 and that his results “effectively rule out solar and energy efficiency 

programs as mechanisms driving the observed long-run elasticities.”92 Put another way, while 

FOMB relies on this working paper to assert that there is a substantial, incremental elasticity 

effect caused solely by the availability of rooftop solar panels, the author of the paper himself

expressly concludes otherwise. Buchsbaum (2022), like Burke and Abayasekara (2018), 

observes that his data already takes into account any elasticity effect of solar PV adoption, and 

Buchsbaum expressly concludes that solar PV adoption has no “incremental effect” on elasticity.

90. Second, Buchsbaum explains that his working paper’s results were generated in 

part by using atypical data and methodology—it “leverage[s] a novel source of cross-sectional 

price variation.”93 Neither the findings in Buchsbaum (2022) nor the methodology used to 

91 Buchsbaum (2022), p. 4.

92 Buchsbaum (2022), p. 36.

93 Buchsbaum (2022), p. 43. 

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generate them, have been peer-reviewed—or even published. Thus, even properly characterized, 

Buchsbaum (2002)’s results have not been demonstrated to be reliable.

91. Third and finally, Buchsbaum (2022) explains that the elasticities calculated for 

PG&E residential customers “are specific to the geography and climate in this northern and 

central California sample.”94 To state what should be obvious, the geography and climate of 

northern and central California are dissimilar to that of Puerto Rico.

92. For these reasons, the FOMB erred in relying on the Buchsbaum (2022) working 

paper in its analysis of any elasticity effect of increasing the rates paid by PREPA customers, and 

by assuming any “Incremental Solar PV Effect” based on a working paper that expressly rejects 

any such “incremental effect.”

3. The Board’s Long-Term Elasticity Estimates Are Substantially 

Higher Than The Academic Consensus Reflected By Surveys Of 

Hundreds Of Studies

93. By selecting the Burke and Abayasekara (2018) findings as “baseline estimates” 

of long-term price elasticity, and then adding to those baseline estimates an “Incremental Solar 

PV Effect” derived from the Buchsbaum (2022) working paper, the FOMB generates estimates 

of long-term elasticities that are significantly higher than the consensus in the academic 

literature. The effect of doing so is to overstate the amount of demand reduction that new rate

increases would cause, and thereby to understate the amount of PREPA’s available Revenue 

Envelope that could be devoted to debt service.

94. Zhu et. al. (2018) surveyed 196 other studies of the price elasticity of electricity 

demand for the residential sector globally. This paper found that the mean estimate of long-term 

94 Buchsbaum (2022), pp. 4-5.

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residential elasticity was -0.577, which is roughly one-third as large as the Board’s estimate.95

Likewise, Labandeira et. al. (2017) surveyed 232 estimates of the price elasticity of electricity 

demand from around the world and found a mean estimate of long-term elasticity of -0.481 for 

the residential sector—just over one-quarter of the FOMB’s estimate.96

95. The FOMB’s long-term elasticity estimates are out of line with these and other 

results demonstrating the consensus of the academic literature, and consequently produce an 

inflated, upward-biased elasticity effect.

97 The Buchsbaum (2022) estimate of elasticity for 

PG&E residential customers in northern and central California, in particular, is well above 

common elasticity estimates found in the literature. The FOMB’s elasticity estimates are 

similarly greatly overstated as a result of FOMB’s method that makes incremental additions to 

the estimates provided by Burke and Abayasekara (2018).

C. FOMB’s Own Gross Load Forecast Assumes Zero Elasticity

96. As part of my analysis, I reviewed PREPA’s 2022 Fiscal Plan, and the underlying 

regression models developed in connection with PREPA’s 2019 IRP, to see what level of price 

elasticity of electricity demand PREPA has been assuming as part of its own forecasting of gross 

load. The answer is zero: the gross load forecast presented in PREPA’s 2022 Fiscal Plan is based 

on regression models that assume no short-term elasticity for any of the forecasted customer 

95 Zhu, Xing, Lanlan Li, Kaile Zhou, Xiaoling Zhang, and Shanlin Yang, “A Meta-Analysis on the Price Elasticity 

and Income Elasticity of Residential Electricity Demand,” Journal of Cleaner Production, Vol. 201, November 10, 

2018, pp. 169-177, available at https://www.sciencedirect.com/science/article/abs/pii/S0959652618323588.

96 Labandeira, Xavier, José M. Labeaga, and Xiral López-Otero, “A Meta-Analysis on the Price Elasticity of Energy 

Demand,” Energy Policy, Vol. 102, March 2017, pp. 549-568, available at 

https://www.sciencedirect.com/science/article/abs/pii/S0301421517300022. Labandeira et. al. also found mean 

estimated elasticities of -0.664 for the commercial sector, and -0.510 for the industrial sector.

97 Both the Zhu et al. (2018) and Labandeira et al. (2017) studies also find different estimates of short-term 

elasticity compared to the -0.2 that the FOMB assumes. I provide a summary of the long- and short-term elasticities 

discussed in this section as Appendix F.

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types. Even the two load modifiers applied to reduce PREPA’s net load forecast—energy 

efficiency and distributed generation—are applied without building in a sensitivity to changes in 

price.

97. PREPA’s own 2019 IRP states that “customer rates were considered” as a 

potential explanatory (independent) variable in the analysis, “but they were found not to have a 

strong historic correlation to demand and explanatory power.”98 In other words, PREPA itself 

concluded that price changes are not a significant factor that meaningfully explains the amount 

of electricity that PREPA’s customers will need and demand. 

98. The 2019 IRP further explains that residential and commercial electricity demand 

in Puerto Rico is essentially inelastic—that is, that is has an elasticity near 0.0. “The residential 

sector,” PREPA’s 2019 IRP explains, “is traditionally a sector with low response to changes in 

retail rates and to some exten[t] the commercial customers.”99 The 2019 IRP also stated that 

Puerto Rico’s industry mix is likewise not particularly sensitive to changes in electricity prices: 

“The manufacturing sector in Puerto Rico, mostly comprised of pharmaceutical, textiles, 

petrochemicals, and electronics, appears to be less responsive to changes in customer rates 

compared to other manufacturing industries such as steel or aluminum, which are highly 

sensitive (high elasticity).”100 It is not surprising that firms that are sensitive to electricity prices 

do not locate on an island that has relatively high electricity prices. The 2019 IRP’s gross load 

98 2019 IRP, Section 3.1.3.

99 2019 IRP, Section 3.1.3.

100 2019 IRP, Section 3.1.3.

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regressions – which are the bases for the gross load forecasts underlying the forecasts used in the 

Plan of Adjustment – do not include any short-term elasticity adjustments.101

99. In sum, the preceding discussion shows that the FOMB’s methodology for 

arriving at its elasticity effect estimates is convoluted, involves unexplained assumptions, and 

relies inappropriately on two papers (one unpublished) to produce elasticity effects that are 

outside—and well above—the consensus of the academic literature. The resulting figures

significantly overstate the potential effect of future rate increases on the level of PREPA’s sales 

to its customers.

VIII. THE FOMB ARTIFICIALLY INFLATES PREPA’S LIKELY FUTURE CAPITAL 

EXPENDITURES TO DERIVE ITS LEGACY CHARGE

100. PREPA’s assumptions about its future capital costs are a key input into its 

revenue requirement—i.e., the amount of revenues the utility states that it will need to collect

from customers to cover its costs—and rate forecasts. In standard utility ratemaking, all else 

being equal, unreasonably high statements of capital costs would increase a utility’s overall 

revenue requirements and thus the level of rates that it believes it will need to charge to

customers. In the context of this proceeding, unreasonably high projections of future capital costs

would put downward pressure on the amount of potential available revenues available to be 

collected from customers by a Legacy Charge to fund creditor recoveries. 

101 Furthermore, the PREPA’s methodology of applying energy-efficiency and distributed-generation load modifiers 

to achieve a base case net load forecast that is substantially lower than its gross load forecast already assumes that 

some customers will adopt energy efficiency and rooftop solar generation in part to reduce their electricity purchases 

from the grid. In so doing, that net load forecast already implicitly assumes a form of long-term demand elasticity 

among PREPA’s customers. By nevertheless adding, as part of its Legacy Charge Derivation model, an additional

elasticity effect over and above these net load forecast assumptions the FOMB is effectively double-counting overall 

elasticity effects.

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101. The FOMB overstates future capital expenditures in two separate respects, each of 

which affects the amount of the Legacy Charge that FOMB derives. First, the capital 

expenditures assumed in the 2022 PREPA Fiscal Plan are overly inflated due to outdated data 

and would be $1.94 billion (undiscounted value) lower over FY 2023-2051 if updated.

102

Second, and independently, I find no reliable support for the FOMB’s assumption, in its Legacy 

Charge Derivation, that PREPA will face unspecified capital expenditures totaling $2.425 billion 

(undiscounted value) over and above what is already assumed by its 2022 PREPA Fiscal Plan—

which was certified by the Board.103 The FOMB’s contention that these additional billions of 

dollars of capital expenditures, which were not anticipated by it or PREPA less than a year ago, 

are now critically necessary in order for PREPA to “remain a viable operating entity” is

surprising, unexplained, and wholly inconsistent with standard utility practice.

104

102. Therefore, I find that the total capital expenditures that are inputs to FOMB’s 

Legacy Charge Derivation are inflated by $4.37 billion over FY 2023-2051.105

A. PREPA’s Legacy Charge Derivation Uses A Capital Cost Forecast That Is 

Outdated And Too High Compared To LUMA’s Latest Forecasts

103. The 2022 PREPA Fiscal Plan’s projections of PREPA-funded capital 

expenditures—i.e., capital investments that are intended to be put into rates charged to customers 

and recovered from them—are based on April 2022 forecasts by LUMA for the three fiscal years 

102 See Figure 13 Backup.

103 See Figure 13 Backup.

104 Legacy Charge Derivation, p. 7.

105 $4.37 billion is the sum of $1.94 billion assumed in the 2022 PREPA Fiscal Plan and $2.425 billion assumed by 

the FOMB in the Legacy Charge Derivation.

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of 2023, 2024, and 2025.106 For each subsequent year through 2051, the 2022 PREPA Fiscal 

Plan assumes that the costs associated with the PREPA-funded capital expenditures will be the 

same as the forecast in fiscal year 2025, grown at the rate of inflation.107

104. However, LUMA has subsequently updated its forecast for PREPA-funded capital 

expenditures and provides new forecasts for each fiscal year between 2023 and 2032. The 

updated LUMA forecasts of such PREPA-funded capital expenditures beyond fiscal year 2025 

are markedly lower than PREPA’s assumptions in the 2022 PREPA Fiscal Plan and are

consistent with LUMA’s multi-phase proposed recovery and transformation roadmap.108 The 

PREPA Fiscal Plan notes that LUMA plans an initial surge of capital expenditures to restore 

“high-risk infrastructure and processes to a safe and functioning state,” but this phase is not 

expected to continue indefinitely.109 LUMA’s revised outlook undermines PREPA’s Fiscal Plan 

assumptions about customer-funded capital costs for the years beyond 2025.

105. Figure 13 compares the PREPA-funded capital expenditure forecasts as shown in 

the 2022 PREPA Fiscal Plan with the updated LUMA forecasts. For the period between FY 2023 

and 2032, the 2022 PREPA Fiscal Plan assumes $359 million more in PREPA-funded capital 

expenditures than in the updated LUMA projection.

110 If one were to assume that the amount of 

PREPA-funded capital expenditures in fiscal year 2032 were maintained until fiscal year 2051 

and grown at the rate of inflation (which is the same growth approach used in the 2022 PREPA 

106 2022 PREPA Fiscal Plan, Exhibit 35; 2022 PREPA Fiscal Plan Model.

107 2022 PREPA Fiscal Plan Model.

108 2022 PREPA Fiscal Plan, p. 99 and Exhibit 36; “Estimated Non-Federally Funded CAPEX FY2023-2032.xlsx,”

FOMB_PREPA 00020150.

109 2022 PREPA Fiscal Plan, p. 99 and Exhibit 36.

110 See Figure 13 Backup.

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Fiscal Plan after FY2025), then the 2022 PREPA Fiscal Plan would overstate PREPA-funded 

capital expenditures by a total of $1.94 billion (undiscounted value) relative to the amount 

indicated in the updated LUMA projection.

Figure 13: Differences in PREPA-Funded Capital Expenditure Forecasts Between 2022 

PREPA Fiscal Plan and Updated LUMA Projections

Sources:

[1] “Estimated Non-Federally Funded CAPEX FY2023-2032.xlsx”, FOMB_PREPA 00020150.

[2] 2022 PREPA Fiscal Plan Model.

106. This overstated forecast of capital expenditures from the 2022 PREPA Fiscal Plan 

is an input to its Legacy Charge Derivation, which relies on the capital expenditure forecasts in 

the 2022 Fiscal Plan even though they have been reduced by LUMA in its more recent 

projections. All else being equal, the FOMB’s reliance on outdated data would lead to an 

understated value for the Legacy Charge that can be supported in customer rates.

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B. PREPA’s Legacy Charge Derivation Assumes Additional Capital Costs That 

Are Unreasonable and Inconsistent With PREPA’s Own Fiscal Plan

107. PREPA included (and, as discussed above, overstates) sizable capital 

expenditures in its 2022 Fiscal Plan, certified by the FOMB to be adequate to meet PREPA’s 

needs. The FOMB nevertheless asserts, as part of its Legacy Charge Derivation, that the

projection of future capital expenditures in PREPA’s 2022 Fiscal Plan does not include “capital 

expenditures (and matches to federal funding) PREPA will likely need to make to remain a 

viable operating entity.”111 The Legacy Charge Derivation thus assumes, with little support or 

explanation, that PREPA will require an estimated $2.425 billion in additional revenues 

(undiscounted) to fund capital expenditures through 2051 beyond the capital costs already 

accounted for in the certified 2022 PREPA Fiscal Plan.112 As a result, according to the FOMB, a 

portion of PREPA’s Revenue Envelope of potential new revenues must be reserved for capital 

expenditure and so is not available for creditor recoveries.

113

108. Figure 14 shows these additional annual capital expenditures assumed in the 

Legacy Charge Derivation. The FOMB assumes (a) an additional $50 million a year for each 

fiscal year between 2024 and 2033, and (b) an increasing annual expenditure thereafter, starting

at $91.7 million in 2034 and rising to $124.5 million in 2051114.

111 Legacy Charge Derivation, p.7.

112 Legacy Charge Derivation, p.7.

113 Legacy Charge Derivation, p.7.

114 See Figure 14 Backup.

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Figure 14: Incremental Capital Expenditures Assumed in the Legacy Charge Derivation 

That are Beyond 2022 PREPA Fiscal Plan’s Capital Investment Forecast

Source:

[1] “20221115 Risk model.xlsx”, FOMB_PREPA 00022385.

109. These additional, incremental capital expenditures are unreasonable and 

unreliable for at least three reasons: First, FOMB has not explained why these additional capital 

expenditures, if they are truly necessary to keep PREPA a “viable operating entity,” were not 

contemplated or provided for under the 2022 Fiscal Plan certified in June 2022. In that Fiscal 

Plan, PREPA and the FOMB forecast future expenses at a level sufficient for PREB to 

“determine rates [...] such that they provide PREPA with the revenue – or funds – that it requires 

to pay for all of the projected expenses needed to provide adequate service to its customers and 

pay its obligations.”115 The FOMB does not explain why PREPA neglected to include $2.425 

115 2022 PREPA Fiscal Plan, p. 159.

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billion in mission-critical capital expenditures—or why they have become evident only as part of 

its analysis of how much of PREPA’s potential future revenues can be used to fund creditor 

recoveries under the Plan.

110. Second, the FOMB’s Legacy Charge Derivation unreasonably assumes $50 

million in additional annual capital costs from fiscal years 2024 through 2033 (or $500 million 

total, in nominal terms).116 Figure 15 shows this additional capital expenditure:

Figure 15: “CapEx Impact FEMA” Expenditures Assumed in Legacy Charge Derivation, 

FY2023-2033

Note:

[1] The 2022 PREPA Fiscal Plan Model includes an error in its calculation of “Identified Federally Funded Capital 

Expenditures” by double counting expenditures allocated to “Hydro, Dams & Irrigation”. This figure corrects for the 

calculation error.

Sources:

[1] 2022 PREPA Fiscal Plan Model.

[2] Revenue Envelope and Legacy Charge Model.

116 See Figure 14, 15, and 16 Backup.

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111. The FOMB describes this annual $50 million as reflecting “Capex Impact 

FEMA.”117 But PREPA’s 2022 PREPA Fiscal Plan already includes projections of PREPA’s 

cost-share obligations on FEMA and other federally funded capital expenditures, and excluded 

them from PREPA’s revenue requirement estimate because they were assumed to be funded by 

the federal government rather than by customers.118 In particular, PREPA assumed that the 

Department of Housing and Urban Development (“HUD”) would fund PREPA’s FEMA costshare obligations.119 However, FOMB assumes now—without evidence—that there is an annual 

net outlay by PREPA of $50 million related to “Capex Impact FEMA” that means that PREPA 

cannot otherwise devote such revenues to pay creditors.

120 This assumption is at odds with 

current government statements; on April 27, 2023, Puerto Rico’s Secretary of State and AAFAF 

Executive Director Omar Marrero stated that “Right now, the way we see it is our capital 

investment needs are covered for the next 10 years. And this is across all infrastructure sectors 

including energy, water, education, public buildings and municipalities.”121

112. Third, the FOMB’s Legacy Charge Derivation unreasonably assumes—contrary 

to PREPA’s 2022 Fiscal Plan—that PREPA’s transmission and distribution system will require 

117 Revenue Envelope and Legacy Charge Model.

118 During fiscal years 2023-2033, the 2022 PREPA Fiscal Plan includes specific estimates of “Identified Federally 

Funded Capital Expenditures” which total $4.34 billion, and include assumed spending on PREPA’s generation, 

transmission, distribution, hydroelectric dams, and irrigation. The $4.34 billion of “Identified” capital expenditures 

are only a small fraction of the $14 billion in total obligated expenditures described in the 2022 PREPA Fiscal Plan, 

as there are also obligated Federal Emergency Management Agency (“FEMA”) funds which have not been assigned 

to specific identified projects.

119 2022 PREPA Fiscal Plan, p. 86.

120 In a letter between FOMB and LUMA counsel, LUMA asserts that “if [HUD cost-share funds] are not available, 

PREPA must identify other funds or adjust rates to cover the local cost-share required to access FEMA funds” and 

that PREPA’s projections do not include “missing cost-share funding [which] amounts to approximately $0.5 

billion.” Letter from Covington and DLA Piper to Proskauer, FOMB_PREPA 00023701.

121 Reorg, “With Federal Funds Expected to Cover CapEx Needs for Next Decade, Commonwealth Takes Measured 

Path Toward Investment-Grade Credit Ratings,” April 27, 2023.

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annual capital spending of $250 million per year (in 2022 dollars) between fiscal years 2034 and 

2051. The FOMB’s Legacy Charge Derivation adjusts that sum for inflation, and labels it 

PREPA’s “expected” capital spending target.

122 That target is $296 million in FY2034, $328M

in FY2040, and so on.123

113. The FOMB then subtracts from those newly assumed capital-spending targets the 

amounts of such capital spending that are actually contemplated by the certified 2022 Fiscal 

Plan, with the result being sums of additional capital spending, in FY2034-FY2051, that are not 

contemplated in the 2022 Fiscal Plan but that, according to the FOMB, require the reserve of any 

new revenues ahead of creditor recoveries. It labels these additional capital expenses as the 

“Capex Impact Non-FEMA” in its Legacy Charge model. Figure 16 shows that additional 

capital expense assumed by the FOMB’s Legacy Charge Derivation, which increases annually 

from $91.7 in FY2034 to $124.5 million in FY2051—roughly a 45% annual increase over the 

capital spending forecast for the same years under the 2022 Fiscal Plan.

124

122 Revenue Envelope and Legacy Charge Model.

123 Revenue Envelope and Legacy Charge Model.

124 See Figure 16 Backup.

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Figure 16: “Capex Impact Non-FEMA” Assumed in Legacy Charge Derivation,

FY 2034-2051

Sources:

[1] 2022 PREPA Fiscal Plan Model.

[2] Revenue Envelope and Legacy Charge Model.

114. FOMB has not explained why $250 million (in 2022 dollars) is a reasonable

expected amount of additional capital expenditures on PREPA’s transmission and distribution 

program from FY2034 through FY2051, or why that target is more reasonable than the lower 

capital expenditure estimates for those years in PREPA’s approved 2022 Fiscal Plan. FOMB’s 

assumption of additional capital expenditures in fiscal years 2034-2051 is unfounded.

115. In conclusion, there is no sound basis on which the FOMB’s Legacy Charge 

Derivation reserves future additional revenue capacity for $2.425 billion in previously 

unanticipated, incremental capital expenditures. The basis for that sum is completely 

unexplained and disconnected from any identifiable project or need. It appears merely to state a 

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large “cushion” for possible future needs for which, until the FOMB developed its Legacy 

Charge Derivation, PREPA had not been forecasting or reserving. If unexpected capital needs 

not identified in the normal course of long-term planning are eventually identified, standard 

practice would be to obtain financing for such projects at that time, for example through a new 

bond offering.

IX. PREPA’S ASSUMPTIONS ABOUT THE COMMONWEALTH’S AND OTHER 

GOVERNMENTAL ENTITIES’ NON-PAYMENT OF PAST ELECTRICITY 

BILLS IS INCONSISTENT WITH SOUND UTILITY PRACTICE 

A. The Commonwealth And Other Governmental Entities Owe Large Amounts 

To PREPA

116. PREPA invoices Commonwealth government and municipal customers for 

electricity provided to them, and those accounts have historically been unpaid or underpaid. 

These past-due governmental accounts are responsible for large amounts of PREPA’s customer 

accounts receivable.

117. As of March 31, 2022, based on the latest data provided by PREPA, 

Commonwealth government and municipal entities owed $2.23 billion in accrued accounts 

receivable to PREPA. This quantity includes unpaid bills accumulated by these entities that

averaged $20.6 million per month during the period of April 2021 through March 2022 alone. 

Excluding accounts associated with PREPA’s CILT (Contributions in Lieu of Taxes) 

arrangements, territorial government and municipal entities owed PREPA $719 million as of 

March 2022. This amount grew by an average of $13.5 million in additional unpaid bills per 

month between April 2021 and March 2022, dollar amounts that need to be recovered in rates 

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charged to other customers.125 The Commonwealth and public corporations alone owed $265 

million to PREPA as of March 2022.126 Table 3 summarizes PREPA accounts receivable from 

governmental and municipal entities. 

Table 3: Summary Statistics for PREPA Accounts Receivable from Commonwealth 

Government and Municipal Entities, April 2021 – March 2022 

Note:

[1] Monthly unpaid bills are calculated as the monthly billed amount less the amount paid by the entity to PREPA 

each month.

Source:

[1] “Government Accounts Receivable March 2022.xlsx”, FOMB_PREPA 00001467. 

118. I understand that, under reforms made after the 2016 enactment of PROMESA, a 

variety of Puerto Rico governmental institutions now fall under the FOMB’s oversight, including 

the Puerto Rico Aqueduct and Sewer Authority (“PRASA”), the University of Puerto Rico 

(“UPR”), and the various Commonwealth agencies and instrumentalities. The FOMB has direct 

oversight over the finances of these entities, yet many of them also owe large unpaid balances to 

PREPA. Some of these entities (like PRASA) completed debt-restructuring processes under 

PROMESA yet continue to owe large amounts of money to PREPA.127

119. In total, entities under the FOMB’s oversight accounted for $140 million in 

PREPA accounts receivable as of March 31, 2022. That includes $5.7 million in unpaid bills to 

125 See Table 3. 

126 See Table 3. 

127 For example, PRASA signed a loan modification agreement in 2019 under PROMESA’s Section 207 to lower its 

debt service payments under U.S. government loans. Financial Oversight & Management Board of Puerto Rico, 

“Puerto Rico’s Debt Restructuring Process,” available at https://oversightboard.pr.gov/debt/.

Number of 

Accounts

Aggregate Ending Balance 

as of March 2022

Aggregate Monthly 

Bills

Aggregate Monthly 

Unpaid Bills[1]

All Accounts 457 $ 2,231,589,373 $ 55,011,138 $ 20,648,185

Excluding CILT 377 $ 718,925,799 $ 47,820,204 $ 13,503,014

Excluding CILT and Public Lighting 299 $ 327,200,096 $ 38,590,359 $ 4,279,369

Excluding All Municipal Accounts 223 $ 284,096,603 $ 37,288,457 $ 4,131,315

Only Commonwealth and Public Corporations 141 $ 265,513,150 $ 33,296,191 $ 3,439,959

 

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PREPA per month during the period of April 2021 to March 2022 alone. PRASA by itself 

accounts for $101 million of this amount.128 Commonwealth agencies together account for 

another $37 million in accounts receivable, and other entities supervised by the FOMB account 

for about $2.5 million in unpaid balances as of March 31, 2022. Table 4 summarizes PREPA 

accounts receivable from governmental and municipal entities under the FOMB’s oversight. 

Table 4: Summary Statistics for PREPA Accounts Receivable from Commonwealth

Government and Municipal Entities Under the Oversight of the FOMB,

April 2021 – March 2022

Note:

[1] Monthly unpaid bills are calculated as the monthly billed amount less the amount paid by the entity to PREPA 

each month.

Source:

[1] “Government Accounts Receivable March 2022.xlsx”, FOMB_PREPA 00001467. 

B. The FOMB’s Revenue Envelope Should Assume That Government Entities 

Will Pay Their Unpaid Electricity Bills

120. PREPA’s Plan of Adjustment assumes its continued inability to collect in full on 

unpaid bills owed by Commonwealth and other governmental entities. Assuming continued 

under-collection on unpaid electricity bills has the effect of reducing the Revenue Envelope 

available for debt service, and in the context of this proceeding asks PREPA’s existing creditors 

128 See Table 4. Recently, PREPA and PRASA reached an agreement for certain payments by PRASA to PREPA in 

order to reduce PRASA’s outstanding balance with PREPA. PREPA Governing Board, Resolution 5027, “Approval 

of a Memorandum of Understanding Between the Puerto Rico Electric Power Authority and Puerto Rico Aqueduct 

and Sewer Authority,” February 24, 2023, available at https://aeepr.com/es-pr/jpportal/Resoluciones

/Resolution%205027%20-%20Approval%20of%20a%20Memorandum%20of%20Understanding%

20between%20PREPA%20and%20PRASA.pdf. 

Entity

Account 

Code

Ending Balance as 

of March 2022

Average 

Monthly Bill

Average Monthly 

Unpaid Bill

Puerto Rico Aqueduct and Sewer Authority CORP 100,828,310 $ $ 12,219,194 $ 2,239,347

Commonwealth of Puerto Rico AEST $ 37,196,996 $ 12,390,692 $ 3,637,597

University of Puerto Rico (UPR) CORP 2,479,984 $ $ 2,141,176 $ (145,684)

Municipal Revenue Collection Center (CRIM) AEST $ 224,626 $ 72,994 $ 11,475

Public Corporation for the Supervision and Insurance of Cooperatives (COSSEC) CORP $ 1,842 $ 34 $ (23)

Puerto Rico Government Developing Bank CORP $ (9) $ - $ -

Puerto Rico Highway and Transportation Authority (HTA) CORP $ (228,661) $ 222,210 $ (1,112,442)

Total: $ 140,731,748 $ 26,824,090 $ 5,742,712

 

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to pay for governmental customers’ past electricity use in the form of lower recoveries. 

Moreover, the Plan’s proponent—the FOMB—has supervisory authority over some of these 

delinquent entities and could require them to plan for, budget, and in fact make payments.

121. When pressed, some governmental entities have demonstrated their ability to 

make payments on unpaid balances owed to other service providers. For example, PRASA’s 

2022 Fiscal Plan describes an effort where it “worked jointly with the Government to reconcile 

balances of accounts receivable” owed to PRASA.129 As a result, “PRASA’s cumulative 

collections rate for government accounts from FY2018 to FY2022 averaged just over 100%, with 

total recovered amounts of $155 million over that time period.”130 

122. It is unreasonable and inconsistent with sound utility planning and practice for 

PREPA and the FOMB to assume that PREPA will have to recover these past-due amounts from 

other customers rather than from the governmental customers that owe the money to PREPA. It 

is unreasonable to assume that these new revenues would not be included in the amounts 

available to pay PREPA’s existing customers as part of PREPA’s revenue requirement.

129 PRASA, “Puerto Rico Aqueduct and Sewer Authority 2022 Fiscal Plan,” pp. 2-34, available at

https://drive.google.com/file/d/1m3p6XwENAyNuELOb2ugncn9aGfK7n4mS/view.

130 PRASA, “Puerto Rico Aqueduct and Sewer Authority 2022 Fiscal Plan,” pp. 2-34, available at

https://drive.google.com/file/d/1m3p6XwENAyNuELOb2ugncn9aGfK7n4mS/view.

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Signed on the 28th day of April, 2023. 

__________________________________________

Susan Tierney

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APPENDIX A

SUSAN F. TIERNEY, Ph.D.

Analysis Group

Office: 617 425 8114 1900 16th Street 

Mobile: 617 901 6921 Suite 1100 

susan.tierney@analysisgroup.com Denver, CO, 80202

Dr. Tierney, a Senior Advisor at Analysis Group, is an expert on energy economics, regulation, and policy, 

particularly in the electric and gas industries. She has consulted to businesses, federal and state governments, 

tribes, environmental groups, energy consumers, foundations, and other organizations on energy markets, 

economic and environmental regulation and strategy, and energy projects. Her expert witness and consulting 

services have involved wholesale and retail market analysis and design, contract disputes, resource planning and 

procurements, regional transmission organizations, the siting of electric and gas infrastructure projects, electric 

system reliability, utility ratemaking, carbon-emission-reduction policy, and other environmental policy and 

regulation. She has served as an expert in civil litigation cases and regulatory proceedings before state and federal 

agencies.

Previously, she served as the Assistant Secretary for Policy at the U.S. Department of Energy. She was the 

Secretary of Environmental Affairs in Massachusetts, where she was responsible for environmental regulation and 

natural resource protection. She was Commissioner at the Massachusetts Department of Public Utilities, 

Chairman of the Board of the Massachusetts Water Resources Authority, and Executive Director of the 

Massachusetts Energy Facilities Siting Council. 

Dr. Tierney has authored numerous articles and spoken frequently at industry conferences. She serves on a 

number of boards and advisory committees, including chairing the Board of Resources for the Future. She is a 

trustee of the Barr Foundation and of the Alfred P. Sloan Foundation, a director of World Resources Institute, the 

Coalition for Green Capital, and the Climate Leadership Initiative, and an Advisor to the Trustees of the Oak 

Foundation. She is a member of the advisory councils at the New York University’s Institute for Policy Integrity, 

and the New York Independent System Operator (NYISO). She is a member of the National Academies of 

Sciences, Engineering and Medicine’s Committee on Accelerating Decarbonization in the United States, the 

Committee on Net Metering, and Climate Communications Initiative. She was a member of the NAS’s 

Committee on The Future of Electric Power in the U.S., and on Enhancing the Resilience of the Nation’s Electric 

Power Transmission and Distribution System. She chairs the External Advisory Council of the National 

Renewable Energy Laboratory (NREL) and previously chaired the Department of Energy’s Electricity Advisory 

Committee. She was co-lead author of the energy chapter of the National Climate Assessment. She was Chair of 

Board of Directors of ClimateWorks Foundation, a member of the Board of the Energy Foundation, a member of 

the Columbia University’s Center for Global Energy Policy Advisory Council, and a Visiting Fellow in Policy 

Practice at the University of Chicago’s Energy Policy Institute, and served on the U.S. Secretary of Energy 

Advisory Board. 

She taught at the Department of Urban Studies and Planning at MIT and at the University of California at Irvine, 

and has lectured at Harvard University, Yale University, New York University, Tufts University, Northwestern 

University, University of Chicago, and University of Michigan. She received NARUC’s Mary Kilmarx Award in 

2015, and in 2020 was designated as a National Associate of the National Research Council of the Academies of 

Sciences, Engineering and Medicine. She earned her Ph.D. and M.A. in regional planning at Cornell University 

and her B.A. at Scripps College.

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EDUCATION

1980 Ph.D., regional planning, Cornell University

1976 Masters of Regional Planning, Cornell University

1973 B.A., art history, Scripps College

Studied political science at L’Institut d'Etudes Politiques, Paris, France

PROFESSIONAL EXPERIENCE

2003–Present Analysis Group, Inc., Boston, MA and Denver, CO

Senior Advisor (April 2014–Present) 

Managing Principal (July 2003–March 2014)

1999–2003 Lexecon, Inc., Cambridge, MA (formerly The Economics Resource Group, Inc.)

Senior Vice President

1995–1999 Economics Resource Group, Inc., Cambridge, MA

Principal and Managing Consultant

1993–1995 U.S. Department of Energy, Washington, D.C.

Assistant Secretary for Policy

1991–1993 Commonwealth of Massachusetts, Executive Office of Environmental Affairs, Boston

Secretary of Environmental Affairs

1988–1991 Commonwealth of Massachusetts, Department of Public Utilities, Boston, MA

Commissioner

1984–1988 Commonwealth of Massachusetts, Energy Facilities Siting Council, Boston, MA

Executive Director

1983–1984 Commonwealth of Massachusetts, Executive Office of Energy Resources, Boston, MA

Senior Economist

1982–1983 Commonwealth of Massachusetts, Energy Facilities Siting Council, Boston, MA

Policy Analyst

1982 National Academy of Sciences, Washington, D.C.

Researcher

1978–1982 University of California at Irvine, Irvine, CA

Assistant Professor

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SELECTED CONSULTING EXPERIENCE

 Various Confidential Engagements 

Including power sales agreements, fuel contracts, investment strategy, project development, and other electric and 

gas industry matters. 

 Commonwealth Edison Company

Expert witness in support of ComEd’s proposed grid modernization plan and multi-year rate case (2022-present).

 Major Electric Utility 

Analyzed the economic and policy implications of wholesale electricity market congestion (2022).

 Zuni Tribal Council

Advisor on transmission line right-of-way compensation issues (2020-2022).

 RISE Light & Power/Outerbridge New Jersey LLC

Co-author of report on the public benefits of the client’s onshore transmission proposals to support the delivery of 

offshore wind into New Jersey (2021).

 Pacific Gas & Electric Company, Southern California Edison, San Diego Gas & Electric Company

Witness ion policy issues related to reforms of the companies’ net energy metering tariff (2021-2022).

 Group of U.S. and European Foundations Funding on Climate Mitigation Issues

Work with China clean energy expert to analyze gaps in philanthropic funding on GHG mitigation in China (2021-

present).

 Coalition of CEOs of Investor-Owned Electric Utilities and Environmental Organizations 

Project manager to support roundtable discussions on reducing greenhouse gas emissions in the U.S. power sector 

(2020-2022). 

 CMS Energy 

Witness in support of CMS Energy’s appeal before the Michigan Tax Tribunal (2020-2022). 

 Coalition for Green Capital 

Co-authored a white paper on a new national green bank (2020-2021). 

 Pacific Gas and Electric Company

Conducted benchmarking study on investor-owned utilities’ provision of wholesale distribution service and 

submitted testimony in PG&E’s rate case filing on its wholesale distribution tariff (2020-present). 

 Santee Cooper

Prepared affidavit on states’ electric industry structure (2020).

 Major Electric and Gas Utility 

Analyzed the impacts (e.g., on cost, GHG emissions, gas and electric system costs) associated with alternative 

strategies for shifting end-use consumers’ non-electric energy uses to electricity (2019-2020).

 La Plata Electric Association 

Prepared testimony before the Colorado Public Utilities Commission regarding the complaints by La Plata Electric 

and United Power of the exit fee to be charged by Tri-State Generation and Transmission Association for La 

Plata’s and United’s potential withdrawal from the Tri-State system (2020).

 Natural Resources Defense Council 

Prepared a white paper on comments filed in the Federal Energy Regulatory Commission docket on whether to 

modify its Policy Statement related to certification of new gas pipelines (2019).

 Delta-Montrose Electric Association 

Provided testimony before the Colorado Public Utilities Commission regarding the complaint by Delta-Montrose 

of the exit fee being charged by Tri-State Generation and Transmission Association for Delta Montrose to 

withdraw from participation in the Tri-State system. (2019)

 Transource 

Provided testimony before the Maryland Public Service Commission regarding regulatory standards for reviewing 

transmission proposals that emanate from the regional transmission-planning process administered by a Regional 

Transmission Organizations. (2019)

 New York ISO (NYISO)

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Prepared a white paper on the impacts on New York of the introduction of a carbon pricing mechanism into 

NYISO wholesale markets (2019).

 Salt River Project

Wrote white paper on utility ratemaking processes and principles (2019).

 Attorney General of New York State, on behalf of a coalition of state Attorneys General 

Preliminary assessment of the U.S. Environmental Protection Agency’s proposed Affordable Clean Energy (ACE) 

rule with changes in the New Source Review program (2018-2019).

 Xcel Energy (Northern States Power - Minnesota) 

Facilitated stakeholder meetings and outreach related to NSPM’s integrated resource plan (2018-2019). 

 Commonwealth Edison (ComEd) 

Provided expert testimony before the Illinois Commerce Commission on regulatory policy issues related to 

proposed pilot projects involved battery energy storage systems (2018).

 Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison Company 

Prepared white paper on a future structure for California’s resource-adequacy and wholesale market structure in a 

low-carbon power system (2018).

 Analysis Group, Inc. 

Prepared a white paper about the rebound effect in estimating the impacts of changes in federal fuel economy and 

greenhouse-gas-emissions standards (2017-2018).

 Merck Family Foundation

Analyzed the economic impacts of the Regional Greenhouse Gas Initiative’s third compliance period (2015-2017) 

(2018).

 Commonwealth Edison (ComEd)

Provided expert testimony before the Illinois Commerce Commission on regulatory policy issues related to a 

proposed microgrid pilot project (2017).

 Natural Resources Defense Council 

Prepared a white paper on changes in the natural gas industry since 1999 when the Federal Energy Regulatory 

Commission issued its Policy Statement related to certification of new gas pipelines (2017).

 New York State Research and Development Administration 

Provided support to NYSERDA and the New York Department of Public Service on issues relevant to the New 

York “REV” proceeding (2017-2019).

 Hewlett Foundation 

Supported strategy development for the Foundation’s Environment Program (2017). 

 Advanced Energy Economy Foundation and American Wind Energy Association 

Co-authored a white paper on wholesale power markets and system reliability and resilience (2017).

 Entergy Vermont Yankee

Provided expert testimony before the Vermont Public Service Board on the public benefits of the proposed sale of 

Vermont Yankee to NorthStar (2016–2018).

 Dominion Energy

Analyzed the implications for carbon emissions and consumer costs of a hypothetical shutdown of the Millstone 

Nuclear Station in Connecticut, and proposed testimony in support of Dominion filings before state agencies 

related to Millstone and a potential long-term power sales agreement for zero-carbon supply (2017–2019).

 Protect the Granite State

Analyzed the economic implications of the proposed Northern Pass Transmission project for New Hampshire and 

New England (2017).

 Environmental Defense Fund

Authored a white paper on challenges facing the U.S. coal industry in the 21st Century (2016).

 Merck Family Fund

Co-authored a white paper on potential design issues relating to trading of carbon-emission credits between RGGI 

states and other states under the U.S. EPA’s Clean Power Plan (2016).

 Consolidated Edison and Southern California Edison

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Authored a white paper on the role of distributed energy resources in distribution utility planning and operations 

(2016).

 Hawaii Gas Company

Provided expert testimony before the Hawaii Public Utilities Commission on issues related to the proposed merger 

of the Hawaii Electric Companies and NextEra (2015–2016).

 The Energy Foundation and Merck Family Fund

Co-authored report on the economic impacts of the Regional Greenhouse Gas Initiative’s (RGGI’s) second three 

years of implementation during 2012–2014. (2015).

 State of Delaware

Provided expert testimony before the Delaware Superior Court on issues related to the impact of the

RGGI program on electricity customers and the economy in Delaware (2015–2016).

 NEXUS Gas Transmission

Co-authored a report on the market for natural gas in the state of Ohio (2015).

 Electric Power Supply Association

Co-authored a report for EPSA on the design of State Plans to align with organized wholesale markets in response 

to the U.S. Environmental Protection Agency’s Proposed Clean Power Plan (2015). 

 Baltimore Gas and Electric, Pepco Holdings Inc. and PHI’s affiliates Pepco, Delmarva Power, and Atlantic 

City Electric

Provided expert testimony before the Federal Energy Regulatory Commission on the need for and risks associated 

with transmission investment (2015).

 Exelon Generating Company LLC

Analyzed alternative generation technologies and the consistency of Exelon’s proposal to construct a natural-gas 

fired peaking unit with Massachusetts energy and environmental policies (2015).

 The Energy Foundation

Co-authored reports on reliability issues related to the U.S. Environmental Protection Agency’s proposed Clean 

Power Plan. (2014–2015).

 New England Power Generators Association

Analyzed the impact of legislative proposals in Massachusetts to direct electric utilities to enter into long-term 

power supply agreements with Canadian hydropower companies. (2014, 2015).

 Spectra Energy

Provided expert report in Maine regulatory proceeding related to the potential for the State of Maine to enter into a 

contract to support natural gas pipeline infrastructure in New England (2014).

 The Energy Foundation and Merck Family Fund 

Co-authored report on the consumer impacts of the U.S. EPA’s proposed Clean Power Plan. (2014).

 Exelon Corporation and Pepco Holdings, Inc.

Analyzed customer and state economic benefits of the proposed merger (2014–2015).

 Major electric utility

Conducted independent review of the company’s internal customer and shareholder analyses of long-term resource 

options (2014).

 Major merchant generating company

Conducted valuation of assets (2014).

 Entergy Wholesale Commodities

Provided strategic advice on wholesale and retail market issues in the Northeast power markets (2013–2016).

 Hualapai Tribe

Provided strategic advice regarding energy resource development and valuation of electric transmission rights of 

way (2014–2018).

 Barr Foundation

Prepared a report on the impacts of the Massachusetts Green Communities Act of 2008 on the Massachusetts

economy. (2013–2014).

 Five California Utilities (LADWP, PG&E, SCE, SDG&E, SMUD)

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Served on the four-person expert independent advisory panel for the third-party study of integration of renewable 

energy into California’s Electric System. Contributed to report titled “Investigating a Higher Renewables Portfolio 

Standard in California” (2013–2014).

 State of Colorado

Prepared expert report on behalf of the three public utility commissioners in Colorado, in support of the complaint 

against them on implementing Colorado’s renewable energy standard under alleged violations of the interstate 

commerce clause (2013–2014).

 Energy Foundation

Wrote white paper on the implications for electric system reliability of the Environmental Protection Agency’s 

implementation of its authority under Section 111(d) of the Clean Air Act, to regulate greenhouse gas emissions 

from existing power plants (2013–2014).

 Major engineering, construction and project management company

Prepared an expert report on electric market conditions in a dispute surrounding cancellation of a major power 

plant (2012–2017).

 Ambri (battery company)

Analyzed energy system issues related to integration of renewables on a military base (2013–2014).

 Advanced Energy Economy Institute

Facilitated workshop for state utility commissioners in Midwest states, on advanced energy technologies and 

related regulatory issues (2013).

 Environmental Defense Fund – North Carolina

Testified on energy efficiency program design issues (2013).

 Advanced Energy Economy Institute (with the New England Clean Energy Council and the New England 

Conference of Regulatory Utility Commissioners)

Supported workshop on advanced energy technologies and related regulatory issues (2013)

 Lawrence Berkeley National Laboratory Energy Program

Provided regulatory policy support at the NJ Board of Public Utilities on smart grid workshop (2013).

 Advanced Energy Economy Ohio

Provided testimony before the Ohio Senate Public Utilities Committee in support of the Ohio Energy Efficiency 

Resource Standard (2013).

 Pepco Holdings Inc., and its operating affiliates, Potomac Electric Power Company, Delmarva Power & 

Light Company, and Atlantic City Electric Company

Provided testimony in support of appropriate incentives for investment in electric transmission (2013)

 Baltimore Gas and Electric Company

Provided testimony in support of appropriate incentives for investment in electric transmission (2013).

 Advanced Energy Economy Institute

Survey of CEOs of advanced energy companies doing business in California, with regard to the state’s energy and 

environmental policies (2012–2013).

 NSTAR and Cape Wind

Provided testimony in support of the long-term power contract of NSTAR and Cape Wind (2012).

 Energy Foundation

Conducted strategic planning for the China Sustainable Energy Program (2012).

 Pacific Gas & Electric Company

Provided testimony on ratemaking issues for PG&E’s proposed pipeline safety enhancement plan (2012).

 COMPETE Coalition

Provided testimony on energy efficiency as part of the performance of state and wholesale electric markets in New 

Jersey (2011).

 Compressed Air Energy Storage Company

Confidential engagement to analyze regional wholesale markets for baseload and renewable energy power 

generation (2011).

 Merck Family Foundation

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Analyzed the economic impacts of the funds collected through the auction of allowances under the Regional 

Greenhouse Gas Initiative (2011).

 American Clean Skies Foundation Corporation

Analyzed the reliability and air emission issues associated with potential retirement of the Potomac River 

Generating Station (2011).

 Colorado Public Utilities Commission

Analyzed the Colorado solar photovoltaic incentive program (2011).

 Exelon Corporation and Constellation Energy (Baltimore Gas & Electric)

Analyzed the economic impacts on the Maryland economy associated with the proposed clean- energy 

commitments tied to the proposed merger of Exelon and Constellation Energy (2011–2012).

 New England Power Generators Association

Analyzed competition issues in the proposed merger of Northeast Utilities and NSTAR (2011).

 Dominion Generation

Analyzed the proposed state tax on output from in-state power generation (2011).

 Exelon Corporation and Clean Energy Group

Analyzed electric industry issues involved in responding to the U.S. EPA’s air regulations (2010-2015).

 Major electric distribution company and independent power producer

Analyzed (modeled) the net benefits of retiring several generating units and replacing them with a long-term 

contract to provide power from a gas-fired power plant (2010).

 Major electric utility company

Analyzed changing fuel-market conditions affecting the value of gas-fired power generation in the context of 

litigation (2010).

 Commonwealth Edison Company

Analyzed the ratemaking issues for an electric distribution utility with respect to energy efficiency program effects 

in Illinois (2010–2011).

 National Grid – Massachusetts electric distribution companies

Analyzed the market for the long-term contract for power from the Cape Wind project (2010).

 Spectra Energy (with the Interstate Natural Gas Association of America)

Analyzed the markets for natural gas, and analysis of the implications of the U.S. EPA’s Advanced Notice of 

Proposed Rulemaking on PCBs (2010–2011).

 Renewable energy company

Analyzed transmission access, planning, cost allocation and siting conditions in US regions (2010-2011).

 Indian tribe in Midwest

Analyzed the value of an oil pipeline right-of-way (2010).

 Dominion Generation

Analyzed the proposed legislation in Connecticut to establish a windfall profits tax on all generating assets located 

in the state (2010).

 Transmission consortium

Analyzed cost-allocation models for an interstate transmission project involving transmission utilities and 

merchant transmission companies (2009–2010).

 Massachusetts renewable energy trust

Analyzed transmission-related approaches to the development of offshore renewable energy (2009).

 Major electric utility

Developed business models and approaches for deploying energy efficiency within the context of the American 

Climate and Energy Security Act framework (2009).

 Major industrial electricity consumer

Assisted in analyzing the implications of the American Climate and Energy Security Act for the company, in light 

of impacts on energy prices and trade considerations (2009).

 National Grid

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Assisted in developing a revenue decoupling mechanism for retail distribution service, and testifying in electric 

and natural gas distribution rate cases in Massachusetts, Rhode Island, New York, and New Hampshire (2009–

2011).

 Sandia Pueblo

Assisted in valuing a transmission corridor on tribal reservation land (2008–2011).

 Major electric and gas company

Provided analytic and strategic support for company’s development of a business plan for energy efficiency and 

other energy-related investments on the customer side of the meter (2008).

 AEP Transmission

Prepared a white paper on the design and cost allocation framework for a high-voltage transmission system 

designed to support renewable and other resources (2008).

 Reliant

Prepared study assessing competition in the wholesale and retail electricity markets in ERCOT (2008).

 Major environmental organization

Analytic and strategic support for utility ratemaking policies for advancing energy efficiency in many states 

(2008–2012).

 New York Independent System Operator

Supported strategic planning and assessment for the Board of Directors (2008–2010).

 Commonwealth Edison Company

Provided testimony on ratemaking policy issues relating to regulatory lag (2008).

 Energy Association of Pennsylvania (EGA)

Analyzed of proposed legislation to cap retail electricity rates in Pennsylvania after the expiration of rate caps 

(2008).

 National Association of Regulatory Utility Commissioners (NARUC)

Prepared study on best practices relating to state regulatory agency policies and utility practices on competitive 

procurement of resources to serve retail electricity customers (2007).

 KeySpan/Boston Gas

Analyzed of the implications of utility ratemaking for valuation of utility assets for property taxation purposes 

(2008).

 Electric company

Analyzed of state’s retail and wholesale power market structure (2008).

 Electric company

Prepared expert report on electric industry structure in the 1990s and 2000s (2007–2008).

 Major electric company

Provided analytic support for company’s development of strategic plan for company-wide GHG-reduction 

commitments (2008).

 Sierra Pacific Power Company

Provided testimony on policy issues relating to the use of historic, future, and hybrid test years in state utility rate 

cases (2007–2008).

 Harvard University

Provided strategic assistance relating to regulatory issues affecting the planning and design of

Harvard’s “green campus” development in Allston Landing (2007–2008).

 Public Service Gas & Electric Company of New Jersey (PSEG)

Provided assistance in facilitating the development of a policy to address “leakage” of CO2 emissions associated 

with the adoption of the RGGI cap-and-trade program (2007).

 Electric Power Supply Association

Prepared white paper on economic, environmental, and regulatory trends in the electric industry (2007).

 Sempra Energy Company – San Diego Gas & Electric Company and SoCalGas Company

Provided testimony on policy issues relating to the provision of financial incentives to electric and gas utilities for 

the successful provision of energy efficiency programs (2007).

 PECO Energy Company

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Provided advice and testimony on various economic and policy issues relating to electric industry restructuring 

policy (2007). 

Provided testimony on issues relating to the market for alternative energy credits and the proposal of PECO to 

voluntarily solicit, procure, and bank alternative energy credits (2007).

 Commonwealth Edison Company

Provided testimony on issues relating to the relationship of auctions for wholesale supply for basic service 

customers and alternative proposals for utility resource procurement (2007).

 ISO New England

Assisted in scenario planning for transmission and other alternatives (2006–2007).

 PJM

Preparing report on market monitoring functions performed under various federal regulatory agencies with 

responsibility to oversee electricity and energy markets (i.e., the Federal Energy Regulatory Commission and the 

Commodities Futures Trading Commission) (2006–2007).

 Major Industrial and Power Plant Company

Assisted company in analyzing market and negotiating the price and other terms and conditions for long-term gas 

supply and in valuing a power plant asset (2006–2007).

 State of North Carolina

Provided expert witness services on electric utility economics and regulatory issues, on behalf of the Attorney 

General in a nuisance lawsuit to require the Tennessee Valley Authority to put in place air pollution control 

equipment on coal-fired power plants in TVA’s system. (2006–2008)

 Major Regional Transmission Organization

Performed analysis of market conditions and trends, and benchmarking market rules and reliability performance 

with other comparable organizations (2006–2007).

 Special LNG Committee, Commonwealth of Massachusetts

Prepared pro-bono report on the need for natural gas and liquefied natural gas in the Northeast (2006).

 Ute Indian Tribe of the Uintah and Ouray Reservation

Prepared a report on economic and policy issues relating to use of tribal lands for energy rights-of- way, as called 

for in Section 1813 of the Energy Policy Act of 2005 (2006).

 New York ISO

Prepared white paper on fuel diversity issues in the New York market (2008). 

Prepared white papers on long-term contracting issues in states with restructured electric industries, and on the 

economic foundations for single-clearing-price markets versus pay-as-bid markets (2007).

Performed economic benefit/cost study of wholesale competition into the region’s wholesale electric market 

(2006–2007).

 Commonwealth Edison Company

Provided testimony on appropriate ratemaking principles for recovery of pension-related costs in proceeding to set 

rates to go into effect following the transition period (2006).

 Commonwealth Edison Company

Provided testimony on economic principles associated with single-price auction design versus pay- as-bid auction 

design (2006).

 Exelon Corporation

Provided analysis of designs of mandatory carbon control policies (2005–2007).

 Sonosky, Chambers, Sachse, Endreson & Perry, LLP, on behalf of various Indian Tribes

Provided analysis in support of comments filed with the Departments of Interior and Energy on energy rights of 

way on tribal land (as called for in Section 1813 of the Energy Policy Act of 2005) (2005–2006).

Provided analysis in support of various tribal negotiations with energy companies with respect to valuation of 

energy rights of way on tribal reservation lands (2007).

 Electric utility company

Performed independent evaluator services in procurement for power resources (2005–2006).

 Power Generation Company

Provided analysis of product market development in MidWest and Eastern RTOs (2005).

 New England Energy Alliance

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Prepared a white paper on energy infrastructure needs in the New England states (2005).

 Committee on Regional Electric Power Cooperation (of the Western Interstate Energy Board) 

Provided research on market monitoring for Western wholesale electric markets (2005–2007).

 Southern California Edison Company

Provided Independent Evaluator services for a competitive procurement of new long-term generation resources and 

renewable resources (2005).

 LNG / Interstate Gas Pipeline project – Duke Energy/Excelerate project

Prepared regional market study for the project proposed for Massachusetts (2004–2005).

 Electric Generating Company

In a contract dispute, provided expert witness services relating to whether changes in a region’s wholesale power 

market rules nullified a power sales agreement (2004–2006).

 Louisville Gas & Electric and Kentucky Utilities

For two vertically integrated electric companies, provided expert witness services in a state investigation of which 

regional transmission approach satisfies state policy objectives (2004).

 Independent Generating Company

For a power company owned by commercial lenders in a Northeast power market, provided consulting services to 

monitor state regulatory policies and actions affecting power plants (2004).

 Major Electric and Gas Company

Performed confidential study of the benefits, costs and current conditions in certain wholesale and retail electric 

power markets (2004–2005).

 Regional Transmission Organization

For a confidential project, analyzed market monitoring and mitigation approaches (2004–2005).

 Major Commercial Bank

For a confidential project, advise with regard to electric industry restructuring and profitability of large energy 

marketer and trading organization (2004–2005).

 Consumer Energy Council of America

For a group of electric industry market participants, regulators, and interest groups, prepared white papers on the 

need for transmission enhancements in U.S. power markets (2004).

 Retail electric company

Provided confidential analysis of business models and regulation approaches for providing retail electric service in 

the state (2004).

 Independent system operator

Provided confidential analysis and research on aligning retail and wholesale market policies (2004).

 California State attorney general

Provided expert witness services with regard to state resource adequacy & planning practices (2004).

 Pacific Gas & Electric Company

Provided expert witness services relating to the public benefits of the settlement between PG&E and the California 

Public Utility Commission, to enable PG&E to emerge from bankruptcy (2003).

 Independent power company

Provided consulting advice on economics of compliance strategies for air and water permits (2003).

 Major public utility company

Advised on the pricing and other terms for a long-term purchase power agreement (2003).

 Duke Power

Provided expert advisory services relating to ratemaking and other regulatory practices (2003).

 Exelon Generation

Provided strategic advice and analytic services relating to market conditions in New England (2003).

 Entergy Services Inc.

Provided services as the independent monitor of Entergy's Fall 2002, Spring 2003 and Fall 2003

Requests for Proposals for Supply-Side Resources (2002–2005).

 Power generation company in New England

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Provided expert testimony in contract dispute regarding allocation of uplift costs in an agreement concerning the 

supply of wholesale power for standard offer service (2002).

 Connecticut Light and Power Company

Provided expert testimony in contract dispute regarding allocation of congestion costs in an agreement concerning 

the supply of wholesale power for standard offer service (2002–2003).

 Ocean State Power

Provided arbitration services in a dispute regarding a gas purchase contract between Ocean State

Power and ProGas Ltd. (2002–2003).

 Regional independent system operator

Provided strategic advice on regional market trends and strategy (2002).

 PJM Interconnection

Provided advice to the appointed mediator as part of the Alternative Dispute Resolution process, in a dispute 

involving PJM and a market participant (2002).

 Duke Energy Corporation

Provided analysis on strategic issues in gas and electric regulatory policy for Duke Energy’s corporate office, 

including with regard to code of conduct issues and wholesale competition (2001–2002).

 Pacific Gas and Electric Corporation

Provided expert witness testimony in proceedings of the FERC on public benefits of the proposed restructuring of 

PG&E assets as part of its emergence from bankruptcy (2001–2002).

 Massachusetts Renewables Trust

Provided assistance in support of the Trust’s renewables and power quality program (2001–2002).

 Major electric holding company

Prepared an analysis of the regulatory policies for reviewing merger applications in states where potential merger 

candidates are located (2001).

 Western Massachusetts Electric Company

Provided expert testimony in contract disputes regarding allocation of congestion costs in agreements concerning 

the supply of wholesale power for standard offer service (2001–2002).

 Energy Foundation

Researched and wrote a white paper on California's process for permitting new power plants (2001).

 Cross-Sound Cable Company

Provided expert testimony regarding public benefits of proposal to construct merchant transmission facility across 

Long Island Sound (2001–2002).

 Major independent power company

Served as expert witness in litigation surrounding power plant development project (2001–2004).

 MASSPOWER Inc.

Served as Mediator in a contract dispute involving pricing of power purchases (2001).

 NRG Energy and Dynegy

Provided expert witness support in regulatory proceeding to review these companies’ acquisition of power plants 

being divested by Sierra Pacific and Nevada Power (2001).

 Occidental Chemical Corporation

Served as expert witness on vertical market power in electric utility’s transmission practices (2000).

 PP&L Global

Provided economic and environmental analysis and expert witness support for proposal to build the

Kings Park Energy power plant in Long Island, New York (2000).

 Calpine Corporation

Provided economic and environmental analysis and expert witness support for the Wawayanda power project in 

Rockland County, NY and for the Towantic power plant in Oxford, Connecticut (2001).

 American National Power, Calpine, El Paso, NRG Energy, Sithe, Southern Energy

Provided support for the development of a proposal for an RTO for New England (2000–2001)

 Duke Energy/Maritimes and Northeast Pipeline

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Provided expert reports on the market and environmental impacts of new natural gas infrastructure and supply in 

New England (2000–2003).

 Arkansas Electric Distribution Cooperatives and Arkansas Electric Cooperative Corporation

Served as expert witness on economic and public policy issues associated with wholesale and retail competition in 

Arkansas (2000–2001).

 TransÉnergie U.S.

Served as expert witness on public benefits of a proposed merchant transmission facility (2000–2001).

 Conectiv

Provided strategic wholesale market analysis and support for procurement of supplies for distribution utility 

company’s provision of Basic Generation Services to retail customers (2000).

 SCS Energy Corp. – Astoria Energy

Served as expert witness for proposal to build new power plant in New York City (2000–2001).

 HEFA Power Options

Provided strategic advice regarding wholesale power market for retail buyers’ group (2000–2003).

 Major real estate development company

Provided analysis of electric and gas infrastructure for large mixed-use development (2000–2001).

 Investment company

Provided strategic advice to investment company with regard to potential investment in major electric generating 

equipment manufacturing company (2000)/

 Major independent power company

Provided economic and environmental support for company’s application to construct a merchant power plant in 

Florida (2000).

 Major railroad company

Provided expert witness support on economic and regulatory policy issues for railroad in state regulatory 

proceeding on a proposed utility merger (2000).

 Coalition of Wireless Telecommunications Carriers

Prepared an expert report on economic benefits of wireless telecommunications (2000).

 Major brownfield property developer

Provided valuation of property as a site for new electric generating facility (2000).

 Fitchburg Gas and Electric Company

Provided litigation support for a gas and electric company on rate design policy (2000)/

 Consortium of electric companies

Provided economic analysis, contract review, and litigation support for a consortium of electric companies with 

power purchase agreements with PURPA projects (1999).

 FirstEnergy Corp.

Provided expert witness support regarding generation asset valuation and the impacts of a new electric industry 

restructuring law on the company (1999–2000).

 Ozone Attainment Coalition

Provided strategic analysis and advice on electric system reliability issues relating to electric companies' 

implementation of 2003 NOx requirements issued by the U.S. EPA (1999).

 Municipal electric department

Provided expert witness services and analysis of the economics and need for a new natural gas pipeline proposed to 

serve an existing electric power plant in Massachusetts (1998–2001).

 Seneca Nation

Provided expert analysis and strategic advice regarding the value of transmission rights of way, in a dispute with 

an electric utility company (1998–2000).

 Major cable company

Provided strategic advice in a series of regulatory and court cases involving inter-affiliate transactions of electric 

utility company entering into competitive telecommunications and cable markets (1998).

 Major electric utility company

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Provided expert witness support regarding structural changes in the electric industry, in litigation pertaining to the 

company's restructuring plans (1998–1999).

 Sithe Energies, Inc.

Provided strategic advice and regulatory support on a variety of issues (market analysis, transmission and ISO 

issues, federal and state market rules, legislation, siting, environmental strategy) relating to the company’s 

participation in the New England, New York, and PJM markets (1997–2003).

Provided transition assistance to the company in its acquisition and integration of approximately

2,000 MW of existing fossil fuel generation from Boston Edison Company (1997–1998).

Provided transition assistance to the company in its acquisition and integration of approximately

4,100 MW of existing fossil and hydroelectric generation capacity from GPU Genco (1998–1999).

Provided support for the company’s participation in electricity product markets under development in New 

England, New York and PJM (1997–2002).

Provided strategic project development advice and expert witness support for the company’s applications to 

construct three natural gas merchant power plants (totaling 2865 megawatts) in Everett, Weymouth, and Medway, 

Massachusetts. (1998–2001)

Provided strategic guidance and regulatory support regarding design of air quality improvement plan for existing 

fossil units at Mystic Station. (1998–2001)

Provided strategic guidance regarding company’s natural gas-fired merchant power plant development projects in 

Ontario, Canada (2000–2001).

 Natural Resources Canada

Prepared a white paper on the implications for electric system reliability in Canada that are associated with 

restructuring the electric industry in the United States (1999).

 Cummins Engine Company, Inc.

Provided strategic analysis on implications of national energy and environmental policies for the Company's longterm business opportunities (1999).

 Electric utility company

Provided advice and regulatory support with regard to the economics and prudency of an existing long-term power 

purchase agreement (1998).

 National Association of Regulatory Utility Commissioners (NARUC)

Assisted the Executive Director and NARUC leadership in updating its strategic plan and in preparing a business 

plan for its implementation (1998).

 State energy office

Assisted in analyzing options for supporting renewable resource development in the state and in designing a 

market-based strategy to implement a new renewables portfolio standard (1997–1998).

 U.S. Generating Company (PG&E Generating Company)

Provided analysis of and testimony on the economic, reliability, and environmental benefits to the host state and 

region of a new merchant power generation facility: the 360-megawatt Millennium project in Massachusetts 

(1996–1997).

Provided analysis of and testimony on the economic, reliability, and environmental benefits of a new merchant 

power generation facility: the 792-megawatt Lake Road Generating Project in Connecticut (1997–1998).

 Pennsylvania Power & Light Company

Provided strategic guidance, economic and policy analysis, and regulatory support for electric utility company as it 

developed and proposed its plan for restructuring its company for retail competition. Provided expert witness 

testimony on rate design policy issues (1996–1998).

 Major diversified electric equipment company

Provided strategic advice and analysis on market opportunities and risk in various regions of the U.S. electric 

industry, under numerous restructuring scenarios (1996–1997).

 Major nationwide electricity consumer

Conducted analysis of buying options and strategies for acquisition of electricity services in states with customer 

choice in retail generation markets (1997).

 National Council on Competition in the Electric Industry

Prepared a Briefing Paper on Regional Issues in Electric Industry Restructuring, for the NCCEI – a joint project of 

the National Association of Regulatory Utility Commissioners, the National Conference of State Legislatures, the 

U.S. DOE and the U.S. EPA (1997).

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 Major western coal company

Analysis of western states’ electric industry restructuring policies and market prices for power in various states 

within the Western Systems Coordinating Council area (1996–1997).

 Major gas pipeline company

Provided analysis of market structures and prices for generation and delivery services in electric service territories 

where the gas pipeline would locate facilities that use electricity (1997).

 Major electric supply company

Provided analysis of regional electricity market conditions to support the company’s analysis of the value of 

various utility assets that were being divested as part of corporate restructuring (1997).

 Massachusetts Division of Energy Resources

Analyzed Boston Gas Company’s proposal for unbundling its retail service, its proposal for performance-based 

rates, and its plan for departing the merchant function (1996–1998).

 Massachusetts Division of Energy Resources

Assisted the state’s energy office in developing policies for establishing a statewide fund to support renewable 

resource development as part of the state’s electric industry restructuring plan (1997).

 Massachusetts Water Resources Authority Advisory Board

Analyzed opportunities for use of the Authority’s energy-using and -producing assets, to position itself beneficially 

as a participant in a restructured retail electricity market in New England (1996–1997).

 Coalition of marketers and independent power producers

Analyzed state regulatory proposals for restructuring the electric industry (1996–1997).

 Major independent power producer

Analyzed market opportunities and risks for merchant plant development in a U.S. region (1996).

 Major independent power producer

Analyzed the expected market price of power in two regions of the U.S. electricity markets (1996).

 Group of municipal electric companies in New York State

Served as expert witness on cost allocation issues in litigation on wholesale power contracts (1996).

TESTIMONY IN LAST FOUR YEARS

 Many confidential expert reports, testimonies, declarations, affidavits, and depositions. 

 On behalf of Commonwealth Edison Company

Before the Illinois Commerce Commission, Order Requiring Commonwealth Edison Company to file an Initial 

Multi-Year Integrated Grid Plan and Initiating Proceeding to Determine Whether the Plan is Reasonable and 

Complies with the Public Utilities Act and Verified Petition for Approval of a Multi-Year Rate Plan under 

Decision 16-108.18 of the Public Utilities Act, Consolidated Dockets No. 22-0486 and 23-0055, 2021, Direct 

Testimony, January 17, 2023.

 On her own behalf 

Before the Federal Energy Regulatory Commission, Technical Conference on Greenhouse Gas Mitigation: Natural 

Gas Act Sections 3 and 7 Authorizations,” Docket No. PL21-3-000, November 19, 2021.

 Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric 

Company

Before the California Public Utilities Commission, Order Instituting Rulemaking to Revisit Net Energy Metering 

Tariffs Pursuant to Decision 16-01-044, and to Address Other Issues Related to Net Metering, Docket No. R.20-

08-020, Opening Testimony (June 18, 2021), Rebuttal Testimony, July 16, 2021, cross-examination at hearing 

(July 26-27, 2021).

 On behalf of CMS Energy 

Before the Michigan Tax Tribunal, CMS Energy Corporation v. Michigan Department of Treasury, Docket No. 

19-003783, affidavit, supplemental affidavit and cross-examination at deposition (2021).

 On her own behalf

Before the House Committee on Energy and Commerce Committee Subcommittee on Energy Subcommittee 

Hearing on “The CLEAN Future Act and Electric Transmission: Delivering Clean Power to the People,” June 29, 

2021.

 On her own behalf

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Before the Federal Energy Regulatory Commission, Workshop on the Office of Public Participation, April 16, 

2021.

 On her own behalf 

Before the House Committee on Science, Space and Technology, hearing on “Lessons learned from the Texas 

blackouts: Research needs for a secure and resilient grid,” March 18, 2021. 

 On her own behalf 

Before the Federal Energy Regulatory Commission, Technical Conference on Carbon Pricing in Organized 

Wholesale Electricity Markets, Docket No. AD20-14-000, September 30, 2020.

 Pacific Gas and Electric Company

Before the Federal Energy Regulatory Commission, in the Matter of Pacific Gas and Electric Company’s 

Wholesale Distribution Tariff Rate Case, Docket ER20-2878-000, Testimony, September 15, 2020.

 Santee Cooper

Before the Court of Common Pleas for the Ninth Judicial Circuit of South Carolina, City of Goose Creek v. South 

Carolina Public Service Authority, Civil Action No. 2020-CP-08-00821, Affidavit, August 24, 2020.

 Amicus Curiae Brief of Susan Tierney in Support of Petitioners the Environmental Defense Fund in Support 

of Reversal of the Challenged Orders of the Federal Energy Regulatory Commission

Before the U.S. Court of Appeals for the District of Columbia Circuit, in the case of Environmental Defense Fund 

v. Federal Energy Regulatory Commission, Case Nos. 20-1016 and 20-1017, Petition for Review of Orders of the 

Federal Energy Regulatory Commission, July 1, 2020. 

 On her own behalf

Before the House Energy Subcommittee of the House Energy and Commerce Committee, at hearing on the Natural 

Gas Act, February 5, 2020. 

 La Plata Electric Association

Before the Colorado Public Utilities Commission, in the matter of La Plata’s and United Power’s complaints that 

the Tri-State Generation and Transmission Association’s exit fee is unjust, unreasonable and discriminatory, 

Proceeding Nos. 19F-0620E and 19F-0621E, Testimony, January 10, 2020; Cross-Examination at Deposition, 

January 31, 2020; Rebuttal Testimony, March 10, 2020; Cross-Examination at hearings, May 18, 2020.

 Delta Montrose Electric Association

Before the Colorado Public Utilities Commission, in the matter of Delta-Montrose’s complaint that the Tri-State 

Generation and Transmission Association’s exit fee is unjust, unreasonable and discriminatory, Proceeding No. 

18F-0866E, Rebuttal Testimony, June 28, 2019.

 Transource Maryland LLC

Before the Maryland Public Service Commission, in the matter of Transource’s request for a certificate of public 

convenience and necessity to construct new high-voltage transmission facilities in Maryland, Case No. 9471, 

rebuttal testimony, May 8, 2019, and testimony under cross-examination at hearing before the Maryland PSC, June

24, 2019.

 On her own behalf

Before the Senate Energy and Natural Resources Committee, at hearing on the electric industry in a changing 

climate, oral and written testimony, March 5, 2019.

PUBLICATIONS, REPORTS, ARTICLES

Tierney, Susan, Joseph Cavicchi, and Paul Hibbard, “The Outerbridge New Jersey Renewable Energy Connector 

Transmission Proposal to Support Delivery of Offshore Wind: Project Benefits Report,” September 14, 2021.

The National Academies of Sciences Committee on the Future of the U.S. Electric System (with Susan Tierney as 

Committee member and co-author), https://www.nap.edu/catalog/25968/the-future-of-electric-power-in-the-unitedstates, February 2021.

The National Academies of Sciences Committee on Accelerating Decarbonization of the U.S. Energy System (with 

Susan Tierney as Committee member and co-author), “Accelerating Decarbonization of the U.S. Energy System,” 

February 2, 2021, https://www nap.edu/resource/25932/interactive/. 

Tierney, Susan, and Paul Hibbard, “Accelerating Job Growth and an Equitable Low-Carbon Energy Transition: The 

Role of the Clean Energy Accelerator,” January 2021, 

https://www.analysisgroup.com/globalassets/insights/publishing/2021-ag-white-paper-on-cgc-accelerator-full-paper.pdf. 

Tierney, Susan, “Wholesale Power Market Design in a Future Low-Carbon Electric System: A proposal for 

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consideration,” WRI/RFF Future of Power Initiative, November 28, 2020, https://files.wri.org/s3fs-public/tierney-whitepaper-on-wholesale-market-design-12-15-2020-final-to-wri-rff.pdf?KmZ4_HCRyF4ZtCCmu3EFjbpx4R9Xxpa0.

Tierney, Susan, and Lori Bird, “Setting the Record Straight About Renewable Energy,” World Resources Institute, blog, 

May 12, 2020, https://www.wri.org/blog/2020/05/setting-record-straight-about-renewable-energy.

Tierney, Susan, “Powering Through – and Beyond – The Crisis,” Utility Dive, May 4, 2020, 

https://www.utilitydive.com/news/powering-through-and-beyond-the-crisis/577221/. 

Tierney, Susan, “Time to move away from old precedents in FERC pipeline reviews,” Utility Dive, November 19, 2019, 

https://www.utilitydive.com/news/time-to-move-away-from-old-precedents-in-ferc-pipeline-reviews/567512/. 

Tierney, Susan, “Certification of New Interstate Natural Gas Pipeline Facilities: Revising the 1999 Policy Statement for 

the 21st Century,” White paper prepared with funding from the Sustainable FERC Project at the Natural Resources 

Defense Council, November 2019.

Tierney, Susan and Paul Hibbard, “Clean Energy in New York State: The Role and Economic Impacts of a Carbon Price 

in NYISO’s Wholesale Electricity Markets,” October 2019.

Tierney, Susan, “Rushing to Close NJ’s Nuclear Power Plants Could Be a Costly Mistake,” NJ.Com, April 9, 2019.

Tierney, Susan. “Public Utility Ratemaking: Context for SRP’s 2019 Public Pricing Process,” February 17, 2019.

Tierney, Susan, et al., “The California Wildfires: Implementing SB 901’s Customer Harm Threshold,” December 2018. 

Duffy, Philip, et al. (including Susan Tierney), “Strengthened scientific support for the Endangerment Finding for 

atmospheric greenhouse gases,” Science, December 13, 2018.

Tierney, Susan, “Initial Observations: On the Operational and Investment Incentives of Different Owners of Coal-Fired 

Power Plants in Light of EPA’s Proposed ‘Affordable Clean Energy’ Rule With Proposed Changes in the New Source 

Review Program,” October 30, 2018.

Tierney, Susan, “Resource Adequacy and Wholesale Market Structure for a Future Low-Carbon Power System in 

California,” July 10, 2018. 

Hibbard, Paul, and Susan Tierney, Pavel Darling, and Sarah Cullinan, “An expanding carbon cap-and-trade regime? A 

decade of experience with RGGI charts a path forward,” The Electricity Journal, June 2018.

Tierney, Susan, and Paul Hibbard, “Vehicle Fuel-Economy and Air-Pollution Standards: A Literature Review of the 

Rebound Effect,” June 28, 2018. 

Tierney, Susan, and Karen Palmer, “Federal Interventions in Wholesale Power Markets: Examining the Implications for 

Market Performance and National Security,” blog post on Resources for the Future website, May 9, 2018.

http://www.rff.org/blog/2018/federal-interventions-wholesale-power-markets-examining-implications-marketperformance.

Tierney, Susan and Karen Palmer, “Grid Resilience, Generation Portfolios, and National Security,” blog post on 

Resources for the Future website, May 8, 2018. http://www.rff.org/blog/2018/grid-resilience-generation-portfolios-andnational-security.

Hibbard, Paul, Andrea Okie, Susan Tierney, and Pavel Darling, “The Economic Impacts of the Regional Greenhouse 

Gas Initiative on Nine Northeast and Mid-Atlantic States: Review of RGGI’s Third Three- Year Compliance Period 

(2015–2017),” April 2017.

Tierney, Susan, “About that national conversation on resilience of the electric grid: The urgent need for guidance and 

action,” Utility DIVE, December 13, 2017.

Tierney, Susan, “Natural Gas Pipeline Certification: Policy Considerations for a Changing Industry,” November 6, 2017.

Tierney, Susan, “Rick Perry went looking for a reason to bail out coal and came back empty,” The Hill, September 7, 

2017.

Tierney, Susan, “The Big Drumroll Ends with a Thud: DOE’s Study on the U.S. Power Grid,” August 24, 2017, 

Insights: WRI Blog, August 24, 2017.

Hibbard, Paul, Susan Tierney and Katie Franklin, “Markets, Reliability and the Evolving U.S. Power System,” June 

2017.

Tierney, Susan and Pavel Darling, “The Proposed Northern Pass Transmission Project: Assessing its impacts on New 

Hampshire,” February 2017.

Tierney, Susan, and Craig Aubuchon, “Millstone Power Station: Providing support for achieving Connecticut’s clean 

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energy goals,” December 2016. 

Tierney, Susan, “Is Nuclear Power Vital to Hitting CO2 Emissions Targets? Yes, Renewables Can’t Fill the Gap Yet,” 

Wall Street Journal, November 11, 2016.

Tierney, Susan, “The U.S. Coal Industry: Challenging Transitions in the 21st Century,” September 26, 2016.

Rabago, Karl, and Susan Tierney, “Does the Clean Power Plan Go Too Far? No.” National Law Journal, September 26, 

2016.

Tierney, Susan, Paul Hibbard, and Ellery Berk, “Considerations Related to Trading for the RGGI States Under the 

EPA’s Clean Power Plan,” July 12, 2016.

Tierney, Susan, “Proposed Senate Bill No. 1965: An Act Relative to Energy Sector Compliance with the Global 

Warming Solutions Act: Potential costs and other implications for Massachusetts consumers and the state’s and region’s 

electric system,” September, 2015.

Tierney, Susan, “Usher in a New Era of Affordable Power,” U.S.News.com (Debate Club: webpost), August 5, 2015.

http://www.usnews.com/debate-club/is-obamas-clean-power-plan-a-good-idea/usher-in- a-new-era-of-affordable-power.

Tierney, Susan, “Don't let nuke plants go too fast,” The Hill (Opinions: webpost), July 15, 2015, 

http://thehill.com/opinion/op-ed/247858-dont-let-nuke-plants-go-too-fast.

Hibbard, Paul, Andrea Okie, Susan Tierney, and Pavel Darling, “The Economic Impacts of the Regional Greenhouse 

Gas Initiative on Nine Northeast and Mid-Atlantic States: Review of RGGI’s Second Three- Year Compliance Period 

(2012–2014),” July 2015.

Tierney, Susan, Paul Hibbard and Craig Aubuchon, “Electric System Reliability and EPA’s Clean Power Plan: The Case 

of MISO,” June 8, 2015.

Tierney, Susan, Craig Aubuchon, and Pavel Darling, “Ohio Natural Gas Market Study: Prepared for the NEXUS Gas 

Transmission Project,” Appendix 1C4 to the NEXUS Project’s Resource Report 1 – General Project Description, PreFiling Draft, submitted to the Federal Energy Regulatory Commission, June 2015.

Tierney, Susan, and Paul Hibbard, “Carbon Control and Competitive Wholesale Electricity Markets: Compliance Paths 

for Efficient Market Outcomes,” May 2015.

Tierney Susan, “Déjà vu: Pushback to U.S. Clean Power Plan Reminiscent of 2011 Mercury Rule,” Insights: WRI Blog, 

May 14, 2015.

Tierney, Susan, Eric Svenson, Brian Parsons, letter and report to Chairman Norman Bay, Federal Energy Regulatory 

Commission, re: Ensuring Electric Grid Reliability Under the Clean Power Plan: Addressing Key Themes from the 

FERC Technical Conferences, Docket No AD15-4, April 17, 2015.

Tierney, Susan, “The Role of “DER” to “D””: The role of distributed energy resources in local electric distribution 

system reliability,” March 31, 2015.

Tierney, Susan, Paul Hibbard and Craig Aubuchon, “Electric System Reliability and EPA’s Clean Power Plan: The Case 

of PJM,” March 16, 2015.

Tierney, Susan, Paul Hibbard and Craig Aubuchon, “Electric System Reliability and EPA’s Clean Power Plan: Tools 

and Practices,” February 2015.

Hibbard, Paul, Andrea Okie and Susan Tierney, “EPA’s Clean Power Plan: States’ Tools for Reducing Costs and 

Increasing Benefits to Consumers,” July 14, 2014.

Lubber, Mindy and Susan Tierney, “Carbon producers can meet EPA’s limits as they have in the past,” McClatchyTribune News Service (printed in the Miami Herald) July 10, 2014.

Tierney, Susan, “Greenhouse Gas Emission Reductions From Existing Power Plants Under Section 111(d) of the Clean 

Air Act: Options to Ensure Electric System Reliability,” May 8, 2014.

Tierney, Susan, “The Proposed ‘Clean Energy Resources’ Bill: Potential costs and other implications for Massachusetts 

consumers and the state’s and region’s electric system,” April 1, 2014.

Tierney, Susan, “State shouldn’t pursue hydropower from Quebec,” The Boston Globe Opinion (The Podium (online)), 

March 25, 2014.

Hibbard, Paul, Steven Carpenter, Pavel Darling, Andrea Okie, Maggie Reilly, Susan Tierney, “Project Vigilance: 

Functional Feasibility Study for the Installation of Ambri Energy Storage Batteries at Joint Base Cape Cod,” March 7, 

2014.

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Hibbard, Paul, Susan Tierney, and Pavel Darling, “The Impacts of the Green Communities Act on the Massachusetts 

Economy: A Review of the First Six Years of the Act’s Implementation,” March 4, 2014.

Arvizu, Dan, Severin Borenstein, Susan Tierney, and Stephen Wright, “Report of the Independent Advisory Panel 

Regarding the Five California Utilities’ Study of Integration of Renewable Energy into California’s Electric System: 

‘Investigating a Higher Renewables Portfolio Standard in California’,” January 2014.

Tierney, Susan, with Steve Carpenter, “Planning for Offshore Energy Development: How Marine Spatial Planning 

Could Improve the Leasing/Permitting Processes for Offshore Wind and Offshore Oil/Natural Gas Development,” paper 

prepared for the Fund for Ocean Economic Research,” June 2013.

Tierney, Susan, “Framing the Issues: Growing Tensions at the Interface of the Natural Gas and Electricity Markets (or, 

If You Want People to Think Outside of the Box, Don't Put Them in One),” paper prepared for MIT Energy Initiative 

(MITEI) Symposium: “Growing Concerns, Possible Solutions: The Interdependency of Natural Gas and Electricity 

Systems,” April 16, 2013.

Hibbard, Paul, Andrea Okie, Susan Tierney, “California’s Advanced Energy Economy: Advanced Energy Business 

Leaders’ Perspectives and Recommendations on California’s Energy Policies,” February 2012.

Alliance Commission on National Energy Efficiency Policy (Susan Tierney, member), “Energy 2030: Doubling U.S. 

Energy Productivity by 2030,” February 2013.

Bipartisan Policy Center Energy Project (Susan Tierney, member), “America’s Energy Resurgence: Sustaining Success, 

Confronting Challenges,” February 2013.

Tierney, Susan, Co-lead Convening Author, Energy Supply and Use Chapter, Draft National Climate Assessment, 

January 2013.

Tierney, Susan, “The Positive Outlook for Cleaner Air and Reliable Electric Service,” June 11, 2012. 

Tierney, Susan, “America’s Bright Future: Cleaner Air and Affordable, Reliable Electricity,” April 23, 2012.

Tierney, Susan, Foreword to CERES Report, “Practicing Risk-Aware Electricity Regulation: What Every State 

Regulator Needs to Know (How State Regulatory Policies Can Recognize and Address the Risk in Electric Utility 

Resource Selection,” authored by Ron Binz, with Richard Sedano, Denise Furey, Dan Mullen, April 2012.

Tierney, Susan, “Time to retire coal-fired plants,” Politico, March 20, 2012.

Tierney, Susan, “Why Coal Plants Retire: Power Market Fundamentals as of 2012,” February 16, 2012. Hibbard, Paul J., 

and Susan F. Tierney, “Carbon Control and the Economy: Economic Impacts of RGGI’s First Three Years.” Electricity 

Journal, December 2011.

Deutch, John, Steven Holditch, Fred Krupp, Kathleen McGinty, Mark Zoback, Susan Tierney, and Daniel Yergin, “The 

Secretary of Energy Advisory Board Shale Gas Production Subcommittee Second Ninety- Day Report” (on steps to 

address the environmental and safety performance of shale gas extraction) November 18, 2011.

Hibbard, Paul J., Susan F. Tierney, Andrea M. Okie, Pavel G. Darling, “The Economic Impacts of the Regional 

Greenhouse Gas Initiative on Ten Northeast and Mid-Atlantic States: Review of the Use of RGGI Auction Proceeds 

from the First Three-Year Compliance Period,” November 15, 2011.

Deutch, John, Steven Holditch, Fred Krupp, Kathleen McGinty, Mark Zoback, Susan Tierney, and Daniel Yergin, “The 

Secretary of Energy Advisory Board Shale Gas Production Subcommittee Ninety-Day Report” (addressing the 

environmental and safety performance of shale gas extraction) August 11, 2011.

Hibbard, Paul J., Pavel Darling, and Susan Tierney, “Potomac River Generating Station: Update on Reliability and 

Environmental Considerations,” prepared for the American Clean Skies Foundation, July 19, 2011.

Bradley, Michael J., Susan F. Tierney, Christopher E. Van Atten, Amlan Saha, and Carrie Jenks, “Ensuring a Clean, 

Modern Electric Generating Fleet while Maintaining Electric System Reliability: Summer Update 2011,” prepared for 

the Clean Energy Group, June 2011.

Tierney, Susan, and Charles Cicchetti, The Results in Context: A Peer Review of EEI’s “Potential Impacts of 

Environmental Regulation on the U.S. Generation Fleet,” May 2011.

Tierney, Susan, “Policies for a Secure Energy Future: Issues in Supply and Demand,” paper prepared for the Aspen 

Institute Congressional Program, February 22–27, 2011.

Tierney, Susan, “Guest Commentary: EPA Air Pollution Rules are Good for the Nation,” CarbonMarket North America, 

February 11, 2011.

Tierney, Susan, “Electric Reliability under New EPA Power Plant Regulations: A Field Guide,” January 18, 2011.

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Tierney, Susan, and Robert Earle, “The Costs of Compliance to EPA’s Advance Notice of Proposed Rulemaking on the 

PCB Use Authorization for Interstate Natural Gas Pipelines,” prepared on behalf of the Interstate Natural Gas 

Association of America (“INGAA”), September 10, 2010.

Bradley, Michael J., Susan F. Tierney, Christopher E. Van Atten, Paul J. Hibbard, Amlan Saha, and Carrie Jenks, 

“Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability,” prepared for the 

Clean Energy Group, August 2010.

Tierney, Susan, “The New York Independent System Operator: A Ten-Year Review,” prepared for the NYISO, April 

12, 2010.

Tierney, Susan, “The Prospects for Natural Gas, Coal, and Nuclear Power in America’s Energy Future,” paper prepared 

for the Aspen Institute’s Congressional Program on Energy Security and Climate Change: Policy Challenges for the 

Congress, Lisbon, Portugal, April 7, 2010.

Tierney, Susan, with Andrea Okie and Stephen Carpenter, “Strategic Options for Investment in Transmission in Support 

of Offshore Wind Development in Massachusetts: Summary Report with Expanded Technical Information” Report 

prepared for the Massachusetts Renewable Energy Trust, January 2010.

Tierney, Susan, with Andrea Okie and Stephen Carpenter, “Strategic Options for Investment in Transmission in Support 

of Offshore Wind Development in Massachusetts: Summary Report,” Report prepared for the Massachusetts Renewable 

Energy Trust, December 2009.

Tierney, Susan, “Allocating Investment Risk in Today’s Uncertain Electric Industry: A Guide to Competition and 

Regulatory Policy During ‘Interesting Times,’” A paper prepared for the Electric Power Supply Association, September 

2009.

Tierney, Susan, “An Assessment of the McCullough Research Memo on Profitability Results of Selected Power Plants 

in New York State,” A paper prepared for the New York ISO, September 2009

Tierney, Susan, “An Evaluation of the McCullough Research Report on New York’s Wholesale Power Market,” A 

report prepared for the New York ISO, March 25, 2009.

Tierney, Susan, Andrea Okie, Rana Mukerji, Michael Swider, Robert Safuto, Arvind Jaggi, “Fuel Diversity in the New 

York Electricity Market,” A New York ISO White Paper, October 2008

Tierney, Susan, “ERCOT Texas’s Competitive Power Experience: A View from the Outside Looking In,” October, 

2008.

Tierney, Susan, “A 21st Century “Interstate Electric Highway System” – Connecting Consumers and Domestic Clean 

Power Supplies,” October 31, 2008.

Barmack, Matthew, Edward Kahn, Susan Tierney, Charles Goldman, “Econometric models of power prices: An 

approach to market monitoring in the Western US,” Journal of Utilities Policy, 2008, 307-320.

Tierney, Susan, and Todd Schatzki, “Competitive Procurement of Retail Electricity Supply: Recent Trends in State 

Policies and Utility Practices,” prepared for the National Association of Regulatory Utility Commissioners (NARUC), 

July 2008.

Tierney, Susan, et al., “Pay-as-Bid vs. Uniform Pricing: Discriminatory auctions promote strategic bidding and market 

manipulation,” Public Utilities Fortnightly (March 2008).

Tierney, Susan, “Statement on Pennsylvania House Bill No. 54 – Why Extending Electricity Rate Caps Ultimately 

Would Not Protect Consumers From Rising Electricity Prices,” February 2008.

Tierney, Susan, “Pennsylvania’s Electric Power Future: Trends and Guiding Principles,” January 2008, Prepared for the 

Energy Association of Pennsylvania.

Tierney, Susan, “Decoding Developments in Today’s Electric Industry — Ten Points in the Prism,” October 2007, 

Prepared for the Electric Power Supply Association.

Baldick, Ross, Ashley Brown, James Bushnell, Susan Tierney, and Terry Winter, “A National Perspective on Allocating 

the Costs of New Transmission Investment: Practice and Principles,” A White Paper Prepared by The Blue Ribbon 

Panel on Cost Allocation for WIRES, the Working group for Investment in Reliable and Economic electric Systems, 

September 2007.

Tierney, Susan, “Adaptation and the Energy Sector,” National Summit on Coping with Climate Change, University of 

Michigan, Ann Arbor, May 8–10, 2007.

Tierney, Susan, and Edward Kahn, “A Cost-Benefit Analysis of the New York Independent System Operator: The Initial 

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Years,” March 2007.

Tierney, Susan, and Paul Hibbard, “Market Monitoring at U.S. RTOs: A Structural Review,” March 2007 (Appendix 17 

of PJM 2007 Strategic Report, April 2, 2007).

“A Cost-Benefit Assessment of Wholesale Electricity Restructuring and Competition in New England,” Coauthored

with Dr. Matthew Barmack and Dr. Edward Kahn, Journal of Regulatory Economics, 2007, vol. 31, Issue 2, pages 151–

184.

Tierney, Susan, “Recollections of a State Regulator,” NRRI 30th Anniversary, Journal of Applied Regulation, Volume 

4, December 2006.

Barmack, Matthew, Edward Kahn, Susan Tierney, and Charles Goldman, “A Regional Approach to Market Monitoring 

in the West,” Prepared the Western Interstate Energy Board Committee on Regional Electric Power Cooperation and

Office of Electricity Delivery and Energy Reliability, Department of Energy, LBNL-61313, October 2006.

“Electric Reliability,” letter to the Editor, Issues in Science and Technology, Fall 2006, Forum.

Report to the Massachusetts Special Commission Relative to Liquefied Natural Gas Facility Siting and Use, June 2006.

“Energy Policy Act Section 1813 Comments: Report of the Ute Indian Tribe of the Uintah and Ouray Reservation for 

Submission to the U.S. Departments of Energy and Interior,” Coauthored with Paul J. Hibbard, In Cooperation With The 

Ute Indian Tribe of the Uintah and Ouray Reservation, May 15, 2006.

“In support of a Sound plan,” Op Ed Coauthored with John DeVillars, Boston Globe, April 23, 2006.

“Let’s Talk About the Weather: Interview with Susan Tierney on climate change risks that corporate boards should 

know about and address,” Corporate Board Member Magazine, January/February 2006.

“New England Energy Infrastructure – Adequacy Assessment and Policy Review,” White Paper prepared for the New 

England Energy Alliance; Coauthored with Paul J. Hibbard November 2005.

"New energy bill doesn’t do enough.” Op Ed, Boston Globe, July 29, 2005.

“The Benefits of New LNG Infrastructure in Massachusetts and New England: The Northeast Gateway Project,” 

Prepared for Northeast Gateway Energy Bridge, L.L.C., and Algonquin Gas Transmission, LLC, White Paper 

Coauthored with Paul. J. Hibbard, June 2005.

“Principles for Market Monitoring and Mitigation in PJM: A Review of Economic Principles, Legal and Regulatory 

Structures, and Practices of Other Regions, with Recommendations,” White Paper prepared for PJM Interconnection, 

January 3, 2005.

“Keeping the Power Flowing: Ensuring a Strong Transmission System to Support Consumer Needs For CostEffectiveness, Security and Reliability – A Report of the Transmission Infrastructure Forum of the Consumer Energy 

Council of America,” Coauthored the report with CECA staff for this CECA Transmission Infrastructure Forum, 

January 2005.

Signatory to “Ending the Energy Stalemate: A Bipartisan Strategy to Meet America’s Energy Challenges, Summary of 

Recommendations,” National Commission on Energy Policy, December 2004.

“Comments of Susan F. Tierney and Paul. J. Hibbard on their own behalf,” before the Federal Energy Regulatory 

Commission, in the Matters of Solicitation Processes for Public Utilities (Docket No. PL04-6-000) and Acquisition and 

Disposition of Merchant Generation Assets by Public Utilities (Docket No. PL04-9-000), on the role of independent 

monitors in public utility resource solicitations, July 1, 2004.

“Energy and Environmental Policy in the United States: Synergies and Challenges in the Electric Industry” (with Paul J. 

Hibbard), prepared for Le Centre Français sur les Etats-Unis (The French Center on the United States), July 2003; 

presentation in Paris, October 2003.

“Supplemental Report on the Benefits of New Gas Infrastructure in New England: The Everett Extension Project” (with 

Charles Augustine), prepared for Algonquin Gas Transmission Company, February 5, 2003.

“The Political Economy of Long-Term Generation Adequacy: Why an ICAP Mechanism Is Needed as Part of Standard 

Market Design” (with Janet Gail Besser and John Farr), The Electricity Journal, August/September 2002.

“Siting Power Plants in the New Electric Industry Structure: Lessons California and Best Practices for Other States” 

(with Paul J. Hibbard), The Electricity Journal, June 2002.

"Maritimes Phase III & Algonquin Hubline: ‘Coastal Dependency'” CZM Consistency Review, May 2002. 

“Siting Power Plants: Recent Experience in California and Best Practices in Other States” (with Paul J. Hibbard), 

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prepared for The Hewlett Foundation and The Energy Foundation, February 2002.

“Economic and Environmental Benefits of the Kings Park Energy Project: System Production Modeling Report” (with 

Joseph Cavicchi), prepared for PPL Global, January 25, 2002.

“The Benefits of New Gas Infrastructure in New England: The Maritimes & Northeast Phase IV Pipeline Project” (with 

Charles Augustine), prepared for Maritimes & Northeast Pipeline, LLC, January 2002.

“Activating Ontario’s Capacity Market: Design and Implementation Issues” (with Janet Gail Besser and John Farr), 

prepared for Sithe Energies, Inc., October 24, 2001.

White paper on “Ensuring Sufficient Capacity Reserves in Today's Energy Markets” (with Janet Gail Besser and John 

Farr), prepared for submission as part of comments filed by Sithe Power Marketing LLC, Sithe New England Holdings, 

FPL Energy LLC, in FERC Docket No. EX01-1-000, October 17, 2001.

“The Rationale and Need for Capacity Obligations and a Capacity Market in a Restructured Ontario Electricity Industry” 

(with Janet Gail Besser & John Farr), prepared for Sithe, September 27, 2001.

“Economic and Environmental Benefits of the Wawayanda Energy Center: System Production Modeling Report” (with 

Joseph Cavicchi), prepared for Wawayanda Energy Center, LLC, August 24, 2001.

“A Better CO2 Rule,” op-ed, The New York Times, May 16, 2001.

“Air Pollution Reductions Resulting from the Kings Park Energy Project” (with Joseph Cavicchi), prepared for PPL 

Global, January 24, 2001.

“Report on “Economic Benefits of Wireless Telecommunications,” prepared on behalf of the N.H. Coalition of Wireless 

Carriers for the New Hampshire HB 733 Study Committee, November 13, 2000.

Expert Report: “Public Benefits of the Proposed Cross Sound Cable Project Prepared for TransÉnergie U.S. Ltd.,” July 

2000.

“The Benefits of New Gas Infrastructure in Massachusetts and New England: The Maritimes & Northeast Phase III 

Pipeline and the Algonquin Gas Transmission Company HubLine Projects” (with Wayne Oliver of Navigant 

Consulting), prepared for Maritimes & Northeast Pipeline, LLC and Algonquin Gas Transmission Company, October 

2000.

“Production Modeling for the Astoria Project: Report on Results” (with John G. Farr), report for SCS Energy Corp., 

June 14, 2000.

“Observations from Across the Border: Implications for Canadian Reliability of Recent Changes in U.S. Electricity 

Markets and Policy,” white paper for Natural Resources Canada, 1999.

“Research Support for the Power Industry” (with M. Granger Morgan), Issues in Science and Technology, Fall 1998.

“Maintaining Reliability in a Competitive U.S. Electricity Industry,” Final Report of the Task Force on Electric System 

Reliability, U.S. Department of Energy, September 29, 1998.

“Regional Issues in Restructuring the Electric Industry,” The Electricity Industry Briefing Papers, The National Council 

on Competition and the Electric Industry, April 1998.

“Fueling the Future: America’s Automotive Alternatives” (with Philip Sharp), The American Assembly, Columbia 

University, Arden House, NY, September, 1995.

“Needed: Broad Perspective, Fresh Ideas,” guest editorial, The Electricity Journal, November 1994. Foreword in J. 

Raab, Using Consensus Building to Improve Utility Regulation, American Council for an Energy-Efficient Economy, 

Washington, D.C., 1994.

“Massachusetts’ Pre-Approval Approach to Prudence in Massachusetts,” Electricity Journal, December 1990.

“Using Existing Tools to Pry Open Transmission—A New England Proposal,” Electricity Journal, April 1990.

“Sustainable Energy Strategy: Clean and Secure Energy for a Competitive Economy” (directed), National Energy Policy 

Plan, July 1995.

“The Domestic Natural Gas and Oil Initiative: First Annual Progress Report” (directed), U.S. Department of Energy, 

February 1995.

General Guidelines for Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy Policy Act of 

1992 (directed), U.S. Department of Energy, October 1994.

“Fueling a Competitive Economy: Strategic Plan for the U.S. Department of Energy” (directed), 1994.

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“The Domestic Natural Gas and Oil Initiative: Energy Leadership in the World Economy” (directed), U.S. Department 

of Energy, December 1993.

“Siting Needs: Issues and Options,” U.S. Department of Energy, June 1993.

“The Nuclear Waste Controversy,” in D. Nelkin, Controversy: The Politics of Technical Decisions, Sage, 1977; 1984 

(second edition). 

Kenneth Kraemer, Siegfried Dickhoven, John Leslie King, Susan Fallows Tierney, Datawars, Columbia University 

Press, 1987.

“The Evolution of the Nuclear Debate: Role of Public Participation,” Annual Review of Energy, 1978.

RECENT SPEECHES AND PRESENTATIONS

“Net Zero America,” National Association of Regulatory Utility Commissioners, November 7, 2021.

“Transmission’s Critical Role in Decarbonizing New England,” New England Electricity Restructuring Roundtable, 

September 24, 2021.

“Wholesale Electricity Markets,” National Governors Association, September 23, 2021.

Expert Panel on “Greenhouse Gases - Where are they from, why do they matter, and can they be reduced?” 

America in One Room: Climate and Energy - Deliberative Polling Event (Stanford University), September 2021.

“Improving Electricity Transmission Siting Opportunities to Meet America’s Consumer, Economic, Clean Energy and 

Climate Goals,” Progressive Policy Institute, September 14, 2021. 

“Energy Transitions: Agency of Change, Changing Agents,” UT Energy Week, 2021, University of Texas Energy 

Institute, April 2021.

Briefings on the National Academies’ study on The Future of Electric Power, February-March 2021.

Briefings on the National Academies’ study on Decarbonizing the U.S. Energy System, February-March 2021.

“Wholesale Electricity Markets: Resource Adequacy,” Future Power Markets Forum, Johns Hopkins and Columbia 

University Center for Global Energy Policy, February 5, 2021.

“Wholesale Power Market Design in a Future Low-Carbon Electric System,” WRI-RFF Workshop, December 16, 2020, 

https://www.rff.org/events/workshops/market-design-for-the-clean-energy-transition-advancing-long-term-approaches/.

“Introduction to the Theory and Practice of Regulation: The Coming Utility Transition,” NRRI Regulatory Training 

Initiative,” November 9, 2020, https://www.youtube.com/watch?v=OqVv1KEK5ko. 

“Opportunities for Governors to Leverage or Align Electricity Markets to Meet State Energy Goals,” National 

Governors Association, October 29, 2020, https://www.nga.org/center/meetings/strategies-meet-clean-energy-goals/ . 

“New York’s Path to a Carbon Free Future,” City and State New York, September 17, 2020, 

https://www.cityandstateny.com/events/nys-path-carbon-free-future. 

“Energy Stimulus: Investing in the Power Grid of the Future,” Irving Institute, Dartmouth College, July 14, 2020.

“The Future of Natural Gas in New England’s Electric System? Who knows; It’s complicated,” New England 

Electricity Roundtable, June 12, 2020. http://www raabassociates.org/main/roundtable.asp?sel=155. 

“The NYISO’s Carbon Pricing Proposal: Value Proposition to New York,” Energy Policy Roundtable in the PJM 

Footprint, panel on carbon pricing, April 28, 2020. http://pjm.raabassociates.org/main/roundtable.asp?sel=159. 

“Decarbonizing the Electric Power Sector,” Center for Strategic and International Studies, March 30, 2020. (podcast) 

https://www.csis.org/events/audio-event-decarbonizing-electric-power-sector. 

“Making Sense of FERC’s MOPR Order,” Resources for the Future Workshop, January 22, 2020.

“CEO Roundtable: The New England Investment Thesis,” moderator of panel at the New England Power Generator 

Association’s Summit, Boston, December 2, 2019.

“Government Policies Promoting Low Carbon Transitions,” moderator of panel at the U.S. Association of Energy 

Economists, Denver, November 5, 2019.

“A Transformation of Power: The U.S. Electric Grid Undergoes Change,” Energy Journalism Initiative, Center for 

Global Energy Policy, Columbia University, New York City, June 12, 2019. 

“Trends and Issues in the Electric Industry – and Potential Implications for State AGs,” New York University State 

Energy & Environmental Impact Center, Washington, DC, May 29, 2019. 

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“Electric System Planning: Mapping Opportunities for Participation by State Air Offices,” National Association of 

Clean Air Agencies, Webinar, April 4, 2019.

“Emerging Energy and Environmental Technologies: Possibilities, Policy Implications, and Potential Consequences,” 

Resources for the Future/Alfred P. Sloan Foundation Conference on Energy Research Insights for Decision making, 

Washington, DC, November 29, 2018.

“The Energy 202 Live: Powering a Cleaner and Brighter Future,” Washington Post Live, November 28, 2018.

“Energy Policy: Research and analysis in an era of disruptive change,” Keynote Address, Energy Policy Research 

Conference, Boise State University Energy Policy Institute, Boise, Idaho, September 6, 2018. 

“Transitions to a Low-Carbon Electric Supply,” EEI CEO meeting, Colorado Springs, September 5, 2018. 

“Potential Solutions & Discussions, NERC (North American Electric Reliability Corporation), Technical Workshop on 

Gas Infrastructure Risk and Associated Recommendations, Atlanta, July 10, 2018. 

“Economic Approaches to Understanding and Addressing Resilience in the Bulk Power System,” Resources for the 

Future and R Street Institute Workshop, Washington, D.C., May 30, 2018; webinar, June 18, 2018.

“The Future of Nuclear Power,” The Council of State Governments/Eastern Regional Conference, Northeastern 

Legislative Climate and Energy Summit, Andlinger Center for Energy and the Environment, Princeton University, May 

11, 2018. 

“The Energy 202 Live: Energy Investment for Today and Tomorrow,” Washington Post Live, May 10, 2018.

“State Policies and Proposals to Support Existing Nuclear Power Plants,” Center for Climate and Energy Solutions, 

Washington, DC, May 9, 2018.

“The Energy 202 Live: Energy Investment for Today and Tomorrow,” Washington Post Live, May 10, 2018. 

“The Fracking Debate: The Pros, Cons, and Lessons Learned from the U.S. Energy Boom,” Energy Policy Institute of 

Chicago, University of Chicago, April 11, 2018. 

“Power Sector Transformation: Natural Gas/Electricity Panel,” Annual Meeting of the Joint Institute for Strategic 

Energy Analysis, National Renewable Energy Laboratory, April 5, 2018. 

“The Evolution of Utility and Regulatory Reform in the U.S.,” 2018 e21 Forum #1: Toward a 21st C. Electric System in 

Minnesota, March 20, 2018.

“The Natural Gas/Electricity Nexus,” Keystone Energy Board meeting, Keystone CO, February 9, 2018.

“Critical Aspects of Transitioning to Competitive Energy Markets from a Wholesale and Retail Perspective & 

Renewable Energy Procurement in Restructured Markets,” Committee on Energy Choice, State of Nevada, Las Vegas, 

November 7, 2017.

“Firm With Trump Cabinet Ties Scores $300M Puerto Rico Power Contract,” On Point radio show on restoration of 

Puerto Rico’s electric grid, WBUR/NPR, October 25, 2017.

“Beyond Baseload? Electricity Markets and Reliability,” Keystone Energy Board meeting, Washington, D.C., October 

24, 2017.

“The Future of Baseload in the West,” Committee on Regional Electric Power Cooperation (CREPC), Reno, October 17, 

2017. 

“Regulatory Paths Forward for a Clean Grid,” Harvard Law School, Cambridge, October 13, 2017.

“This Thing about Coal and Nukes,” Grid Geeks Podcast, October 6, 2017.

“What Do Americans Think about the Direction of Energy and Climate Policy?” EPIC, University of Chicago, October 

4, 2017.

“Preparing for the Future: Challenges and Opportunities of Modernizing the Grid,” NextGrid Illinois conference, 

Chicago, September 28, 2017.

“Designing America’s Energy Future,” National Renewable Energy Laboratory’s 40th Anniversary meeting on energy 

innovation, Golden, CO, September 20, 2017. 

“The Future of Power Markets in a Low Marginal Cost World: Electricity Sector Overview,” Resources for the Future, 

September 14, 2017. 

“The National Academy of Sciences Report on Electric System Resiliency: Natural Gas and Electric System 

Interdependencies,” NAESB, September 7, 2017.

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“Valuing Distributed Energy Resources,” Aspen Energy Policy Forum, July 2017.

“The Road from Paris: A Conversation with the Former Secretary of Energy Ernie Moniz,” Aspen Ideas Festival, July 

2017. 

“How Policy Choices Today Will Impact the Future of Electric Power,” Edison Electric Institute, Annual Meeting, 

Boston, MA, June 12, 2016.

“Big Think Presentations on the Future of Retail Electricity Service,” California Public Utilities Commission and 

California Energy Commission, Joint En Banc on Changing Nature of Consumer and Retail Choice in California, 

Sacramento, CA, May 19, 2017.

“Energy Resources: The Right Mix – or Mix It Up? Is What We Need Compatible With The Region’s Energy Goals?” 

Northeast Energy and Commerce Association, Mystic, CT, May 10, 2017. 

“Comments at the FERC Technical Conference on Certain Matters Relating to State Policy Initiatives Affecting 

Wholesale Energy and Capacity Markets Operated by Eastern Regional Transmission Organizations (RTOs) and 

Independent System Operators (ISOs),” Washington, D.C, May 2, 2017.

“Utility of the Future: Valuing Distributed Energy Resources,” Electric Power Research Institute (Research Advisory 

Committee), Tempe, AZ, March 7, 2017. 

“Navigating the Energy and Environmental Policy Landscape,” Nicholas School for the Environment, Duke University, 

Washington, D.C, February 15, 2017.

“What is Next for the EPA’s Carbon Regulations for Existing Power Plants?” NARUC Electricity Committee and the 

Energy Resources and the Environment Committee, Washington, D.C., February 14, 2017.

“Carbon: A risk or an opportunity?” NARUC Energy Resources and the Environment Committee, Washington, D.C., 

February 14, 2017.

“Managing the Energy Transition: Exploring Pathways to Deep Decarbonization,” Bipartisan Policy Center, 

Washington, D.C., December 8, 2016.

“The Clean Power Plan and Beyond: What to Expect in 2017...” NYU School of Law – Institute for Policy Integrity, 

New York, NY, November 15, 2016.

“Location, Location, Location, and the Value of Distributed Energy Resources,” NARUC Annual Meeting, La Quinta, 

CA, November 14, 2016.

“Value of ‘DER’ to ‘D’: The role of distributed energy resources in local electric distribution system reliability,” 

Presentation to NARUC Committee on Electricity, November 14, 2016, La Quinta, California. 

“State Electric Industry Policies and Organized Wholesale Electricity Markets,” Presentation to the NYISO 

Environmental Advisory Council, Albany, NY, November 4, 2016.

“Existing nuclear units and potential policy solutions: Approaches in other states beyond Illinois,” Chicago, IL, October 

18, 2016.

“Existing Nuclear Units – and New York’s Clean Energy Standard,” presentation to the NARUC Energy Resources and 

the Environment Committee – Monthly Conference Call, September 16, 2016.

“Understanding the Evolving Trends in the Eastern Interconnect: Implications for Environmental Policies & 

Investments,” Duke Nicholas Institute for Environmental Policy Solutions/Great Plains Institute/Bipartisan Policy 

Center, I, Atlanta, September 13, 2016.

“What does the U.S. need to do to meet its climate goals? Why Nuclear? How Much and How Fast?” Aspen Institute 

Forum on the Future of Nuclear Energy, Aspen, August 10, 2016.

Testimony of Susan F. Tierney, Ph.D. Before the Democratic Platform Committee, U.S. Progress on Clean Energy 

Policy, Phoenix, June 17, 2016.

“Value of “DER” to “D”: The Role of Distributed Energy Resources in Local Electric Distribution System Reliability,”

presentation to the MidAtlantic Conference of Regulatory Utility Commissioners (MACRUC), Williamsburg, VA, June 

21, 2016.

“How does New Jersey Achieve a Low-Carbon Future?” New Jersey Spotlight conference, Trenton, NJ, June 3, 2016.

"Potential federal and state actions that could help address financial risks facing many existing nuclear power plants,” 

U.S. Department of Energy’s Summit on Improving the Economics of America’s Nuclear Power Plants, Washington, 

D.C., May 19, 2016.

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“New England’s Electricity ‘Restructuring:’ Successes, disappointments, and what’s next,” 150th meeting of the New 

England Electricity Restructuring Roundtable, Boston, MA, May 18, 2016.

“Clearing the Way: Pioneering New York’s Clean Energy Standard,” Albany, NY, May 11, 2016. 

“Electricity markets in transition,” Annual Energy Summit of Columbia University’s Center for Global Energy Policy, 

New York, NY, April 27, 2016.

“Value of “DER” to “D”: The Role of Distributed Energy Resources in Local Electric Distribution System Reliability,” 

California Public Utility Commission’s “Thought Leaders Forum,” April 21, 2016.

“Transforming Power Systems: Challenges and Solutions,” Annual meeting of the Joint Institute for Strategic Energy 

Analysis, NREL, Golden, CO, March 31, 2016.

“Background and Context: Eras of Electric Utility Industry (in 5 Minutes!),” New Orleans City Council/ Entergy New 

Orleans Electricity Symposium, March 22, 2016.

“Affordability, Cost Containment, and Economic Development: Complying with the Clean Power Plan,” 3-N meeting 

(NARUC, NASEO, NACAA) on How State Agencies Are Working Together, Washington D.C., February 11, 2016.

“Evaluating Clean Power Plan Pathways in a Dynamic Electricity Sector,” Conference on Navigating the EPA’s Clean 

Power Plan: Charting a Course for the Southeast, sponsored by Duke University Nicholas Institute for the Environment, 

Orlando, January 28, 2016.

NASEO/DOE/EIA, “2015 – 2016 Winter Energy Outlook Conference,” National Press Club, Washington, D.C., 

October 6, 2015.

“Outlook for Energy,” Clinton Foundation Global Initiative, New York, NY, September 28, 2015.

“Reactions to the Clean Power Plan,” NARUC Electricity Committee, Arlington, VA, August 14, 2015.

“Trends in national climate policy,” Institute for Sustainable Cities, June 18, 2015.

“EPA’s Clean Power Plan and its potential effects on system reliability,” Mid-American Regulatory Commissioners 

(MARC) Conference, Milwaukee, June 8, 2015.

“Proposed Reliability Mechanisms for the Clean Power Plan,” Bipartisan Policy Center Workshop, National Press Club, 

Washington D.C., May 9, 2015.

“EPA’s Proposed Clean Power Plan: Testing the tires, looking under the hood... How far does it take us toward a clean, 

modern electric system?” Cornell University, Ithaca, NY, November 2014.

“Readying States for New Greenhouse Gas Rules in the Electricity Sector,” National Governors Association –

Workshop for Governors’ Energy Advisors, Washington, D.C., September 22, 2014,

“Natural Gas and Renewable Energy Synergies: Challenges and Opportunities,” North American Energy Standards 

Board (NAESB), Board Meeting, Houston, September 10, 2014.

“America's Electricity Evolution: New Policies, Regulations, and Technologies Converging to Change the Future of 

Power Production and Use,” 2014 NASEO Annual Meeting, Savannah, September 2014.

“Implications for Energy, Economy, and Environment Under the Proposal,” Environmental Council of the States 

(ECOS), Washington D.C., July 31, 2014.

“Regional Options and Strategic Choices,” NARUC Workshop on Regional Compliance Options for Sec. 111d, 

Washington D.C., July 28, 2014.

“111d in Big D: Compliance Options, Regional Approaches, and Where We Go from Here,” NARUC, Dallas, July 16, 

2014.

“The National Climate Assessment: What Risks Lie Ahead for the Energy Sector?” NARUC, Dallas, July 14, 2014.

“The EPA’s new Clean Power Plan proposal: Some suggestions for state action now,” National Association of Clean Air 

Agencies, Washington, D.C., July 13, 2014.

“Changing electric industry dynamics: The role of regulation,” Aspen Institute Energy Policy Forum: Electricity 

Structure and Regulation, July 7, 2014.

“Natural Gas and Renewable Energy Synergies: Challenges and Opportunities,” Synergies of Natural Gas and 

Renewable Energy: 360 Degrees of Opportunity, Center for the New Energy Economy (CNEE), Joint Institute for 

Strategic Energy Analysis (JISEA), Gas Technology Institute (GTI), Bloomberg New Energy Finance, New York, NY,

July 1, 2014.

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“EPA’s Clean Power Plan,” Bipartisan Policy Center, June 18, 2014.

“GHG Emission Reductions From Existing Power Plants Under Section 111(d) of the Clean Air Act: Options to Ensure 

Electric System Reliability,” Electricity Advisory Committee, U.S. Department of Energy, May 8, 2014.

“Climate Solutions: The role of existing nuclear power,” Center for Climate and Energy Solutions, Washington, D.C., 

April 28, 2014.

“Electric Power Systems: The Outlook for Electric Transmission: Where You Stand Depends Upon Where You Sit,” 

Harvard Law School, March 20, 2014.

“Section 111(d) of the Clean Air Act: Drivers of Power Sector CO2 Reductions,” Bipartisan Policy Center Workshop on 

GHG Regulation of Existing Power Plants under the Clean Air Act: Policy Design and Impacts, Washington, D.C., 

December 6, 2013.

“The World of Abundant Natural Gas in the U.S.: Looking Ahead for Power-Sector Implications,” presentation to the 

Keystone Energy Board, Washington, D.C., October 30, 2013.

“Energy: From the Last to the Next 150 years,” keynote address to the Energy Forum of Boston College’s

Sesquicentennial Celebration, October 25, 2013.

“Capacity Markets in the Northeast: A Preview of Comments at the FERC Technical Conference on Centralized 

Capacity Markets in RTOs/ISOs,” presentation to the Independent Power Producers of New York, Saratoga Springs, 

New York, September 10, 2013.

“Opportunities and Risks of Shale Gas Development,” presentation to the Governors’ Policy Forum on Shale Energy 

Development, National Governors Association, Denver, September 9, 2013.

“The National Climate Assessment (Draft): Chapter on Energy Supply and Use,” presentation to the National 

Association of Regulatory Utility Commissioners, Denver, July 23, 2013.

“Climate Change Preparedness in New Jersey: Utilities – Leading Practices and Trends Nationally,” presentation to the 

New Jersey Climate Adaptation Alliance, Rutgers University, May 21, 2013.

“Is New England Over-Reliant on Natural Gas?” presentation to the 20th Annual Energy Conference of the Northeast 

Energy and Commerce Association, Groton CT, May 21, 2013.

“Jevons’ Boomerang: Is the rebound effect real? If so, is the effect negative or positive?” presentation to the EE Global 

Conference, Washington, D.C., May 20, 2013.

“Framing the Issues: Growing Tensions at the Interface of the Natural Gas and Electric Industries,” presentation to the 

MIT Energy Initiative (MITEI) Symposium on “Growing Concerns, Possible Solutions: Gas/Electric Interdependence,” 

April 16, 2013.

“Unconventional Natural Gas: The Fracking Debate,” Northeast Gas Assn, Providence RI, March 15, 2013.

“Unconventional Natural Gas: Trends, Opportunities, and Challenges with America’s New Energy Resource, Center for 

the American West series on “FrackingSENSE: What We Know, What We Don’t Know, and What We Hope to Learn 

about Natural Gas Development,” Boulder, Colorado, March 5, 2013.

“Global Energy Security: Upcoming challenges and opportunities (from a U.S. vantage point),” Tufts University Energy 

Conference – Powering Global Energy Security, Medford, Massachusetts, March 3, 2013.

“Old Made New – Conventional Resource Innovation in the 21st Century,” MIT Energy Conference, Boston, March 2, 

2013.

“The Evolving Energy Landscape: Standing at the Crossroads in 2013,” Keynote Address, Kellogg School of 

Management Energy Conference, Northwestern University, Chicago, February 13, 2013.

“The Starting Point: Interconnection/Grid Planning in the Face of Diversity, Technical Complexity, Uncertainties, 

Challenges, Opportunities,” NARUC/DOE, Washington D.C., February 6, 2013.

“Electric Power Systems: The Outlook for Electric Transmission: Where You Stand Depends Upon Where You Sit,” 

Yale University School of Forestry/Management, February 5, 2013.

“Electric Power Systems: The Outlook for Electric Transmission: Where You Stand Depends Upon Where You Sit,” 

New York University Law School, February 4, 2013.

“The Future of Energy,” DOE Energy All Stars, Department of Energy, January 19, 2013.

“The Economic Impacts of RGGI’s First Three Years,” Columbia University Law School – Center for Climate Change 

Law, Conference on the Future of the Regional Greenhouse Gas Initiative, New York, City, October 22, 2012.

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“Reality Check on Energy Conditions,” New Hampshire Energy Summit, Concord, NH, October 22, 2012. 

Natural gas and renewables: Curious bedfellows,” Renewable Energy Law & Policy Summit, University of Denver 

Sturm College of Law, October 19, 2012.

“Smart Grid and Air Emissions,” Gridweek, Washington D.C., October 4, 2012.

“C3E Women in Clean Energy Symposium,” Keynote Address, Boston, September 28, 2012.

“Natural Gas: Risks and Opportunities – Shale Gas, Hydraulic Fracturing, and Other Facts,” EPA Region 1 seminar, 

Boston, MA, September 27, 2012.

“Finding the Sensible Middle: Policies and Institutional Roles in Unconventional Gas Development,” Unconventional 

Gas Research Forum, Board on Energy and Environmental Systems, National Academy of Sciences, Washington D.C., 

September 11, 2012.

“Unlocking the Potential of Regional Collaboration,” California ISO Stakeholders Symposium, Sacramento, September 

6, 2012.

“The Context for Compliance with EPA Air Regulations: Power Market Conditions,” EPA/DOE/NETL/ EPRI/AWMA 

Power Plant Air Pollution Control Mega-Symposium, Baltimore, August 20, 2012.

“Finding the Sensible Middle: Unconventional Gas Development,” 24th Annual Natural Gas Strategy Conference & 

Executive Forum, August 15, 2012.

Intelligence Squared U.S. debate: “No fracking way: The natural gas boom has done more harm than good,” against the 

proposition (with team mate, Joe Nocera (New York Times)), Aspen, Colorado, July 1, 2012.

“What, Me, Worry? The New Outlook for Natural Gas in New England - How Will Natural Gas Impact

New England's Electricity Markets and Reliability,” New England Restructuring Roundtable – June 15, 2012.

“China’s Energy Challenges and Policy Responses: Observations from a U.S. Vantage Point,” Connecticut College 

Vietnam Program, June 15, 2012.

“Economic Impacts of RGGI: Following the Dollars,” presentation to the RGGI Board, June 2012.

“The Energy Scene: Update on a Few Key Issues,” presentation to the Ozone Transport Commission, April 23, 2012.

“Shale Gas: Analyzing Risks and Opportunities,” Society for Risk Assessment, Boston University, April 9, 2012.

“Sustainable Energy Highway,” New York State Energy Highway Summit, April 4, 2012.

“Electric and Natural Gas Markets – Interactions, Opportunities, Challenges (with a focus on Texas),” Gulf Coast Power 

Association Spring Meeting, April 3, 2012.

“Natural Gas: Risks and Opportunities – Shale Gas, Hydraulic Fracturing, and Other Facts,” Tufts University – Fletcher 

School, March 29, 2012.

“Fracking and Shale Gas, Part I: Impacts on Energy Markets and Massachusetts,” Boston Bar Association, March 6, 

2012.

Electric Power Systems: “The Outlook for Electric Transmission: Where You Stand Depends Upon Where You Sit,” 

Harvard Law School, February 16, 2012.

“Natural Gas: Policy Recommendations of the NPC, SEAB, and BPC,” Energy, Utility and Environment Conference 

2012, January 30, 2012.

“Economic Impacts of RGGI: Following the Dollars,” Energy, Utility and Environment Conference 2012, January 30, 

2012.

“Electric Power Systems: “The Outlook for Electric Transmission: Where You Stand Depends Upon Where You Sit,” 

Yale University School of Forestry and Environmental Studies, January 24, 2012.

“U.S. Renewable Energy Policy: Overview, with comparisons to European approaches,” presentation to the Wharton 

School, January 3, 2012.

“The Truth about Fracking,” presentation to the New York Energy Forum, December 19, 2011.

“The Clean Energy Economy,” presentation to the Environmental Lawyers, Environmental League of Massachusetts,” 

November 30, 2011.

“Outlook for the Electric Generating Fleet: Effects of the Upcoming EPA Regulations,” presentation to the Harvard 

Kennedy School Energy Policy Series, November 28, 2011.

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“The National Petroleum Council’s “Prudent Development: Realizing the Potential of North America’s Abundant 

Natural Gas and Oil Resources,” NARUC Annual Meeting, St. Louis, November 15, 2011.

“The Future of U.S. Energy Policy: What happens when we assume no changes in the near term...?” Wharton Energy 

Conference – Energy Frontiers: A Global Perspective, Philadelphia, October 28, 2011.

“Natural Gas: Risks and Opportunities (*with an emphasis on shale gas developments),” Harvard University Center for 

the Environment – Future of Energy Series, Cambridge, October 26, 2011.

“An Expanded Toolkit – Environmental Regulations, Natural Gas, and Modernizing the U.S. Generating Fleet,” Great 

Lakes Symposium on Smart Grid and the New Energy Economy, Chicago, October 19, 2011.

“Pricing in a Western Energy Imbalance Market: Market Clearing Price versus Pay-As-Bid Pricing.” Western Interstate 

Energy Board – Webinar on the Energy Imbalance Market,” October 18, 2011.

“Federal and State Legislative and Regulatory Outlook: Connecting the Dots: Options for Upcoming Electric 

Resources,” Emerging Issues Policy Forum, Amelia Island, October 9, 2011.

“Environmental Challenges Associated with Meeting Future Energy Needs: The role of shale gas?” National 

Association of Clean Air Agencies, Cleveland, October 4, 2011.

“Facing tough realities: Upcoming Energy and Environmental Issues – With a Focus on Electricity and Natural Gas,” 

National Association of Clean Air Agencies, Cleveland, October 4, 2011.

“Assessing Natural Gas' New Promises and Controversies: Strategies to Improve the Safety & Environmental 

Performance of Shale Gas Extraction,” Wisconsin Public Utilities Institute, University of Wisconsin at Madison, 

October 3, 2011.

“The Outlook for Natural Gas: Role of Shale Gas,” EnergySMART Conference, Boston, September 27, 2011.

“The Outlook for Natural Gas: What does shale gas look like?” NECA Fuels Conference, Marlboro, MA, September 27, 

2011.

“Facing tough realities: Upcoming Energy and Environmental Issues – With a Focus on Electricity and Natural Gas,” 

Environmental Council of the States, Indianapolis, September 25, 2011.

“Electric Reliability Under EPA’s New Air Regulations: What We Know, and What We Can Do About What We Don’t 

Yet Know,” National Association of State Energy Offices, September 12, 2011.

“The Future of Electricity Generation in the U.S. – A Modest Set of Observations,” 19th Annual MIT- NESCAUM 

Endicott House Symposium, August 18, 2011.

“Unconventional Approaches: Part of the Electric Industry’s Response to Upcoming EPA Regulations,” panel on

Infrastructure Reliability and Adequacy at the Aspen Energy Policy Forum, Aspen, July 5, 2011.

“What we know, what we might know, and what we know we don’t know yet,” joint meeting of the NARUC, NASEO, 

and NACAA states, Baltimore, June 23, 2011.

“Facing tough realities: Energy and environmental issues in 2011 and beyond,” joint meeting of the NARUC, NASEO, 

and NACAA states, Baltimore, June 23, 2011.

“China’s Energy Challenges and Policy Responses: Observations from a U.S. Vantage Point,” Connecticut College 

Vietnam Program, June 16, 2011.

“Strategies for Addressing Change at FERC and the RTOs: A new lens on responding to near-term changes,” 

FERC/RTO Training Session, Institute Policy Integrity, New York, NY, July 15, 2011.

“’May you live in interesting times...’: The Regulators’ Tool-Kit in an Era of Uncertainty,” Western Conference of 

Public Service Commissioner, Denver, June 14, 2011.

“Dirty to Clean? The Future of Electric Power in America,” CERES Conference 2011, Oakland, CA, May 12, 2011.

“EPA Regulations, Power Generation Capacity & Reliability,” MIT Center for Energy & Environmental Policy 

Research Workshop, Cambridge, MA, May 5, 2011.

“The Electric Industry’s Response to EPA’s Upcoming Regulations: Options for Owners and Others,” Energy Bar 

Association, Panel on Environmental Regulations, Washington, D.C., May 4, 2011.

“Framing the Issues: Energy & the Environment,” keynote address, Health Effects Institute, Boston, May 2, 2011.

“Federal Air Pollution Regulations Affecting Fossil Power Plants: Current issues, implications, strategies,” Annual 

Conference on Tribal Energy in the Southwest, Law Seminars International, Phoenix, April 29, 2011.

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“China and U.S. Energy and Environmental Policy Challenges: Learning from Each Other, In It Together,” presentation 

to China Energy & Environment Conference, Harvard University, April 9, 2011.

“EPA’s MACT, Water Cooling Intake and Transport Rules: What now for power generation?” presentation to SNL 

Energy Webinar, April 12, 2011.

“Policies for a Secure Energy Future: Issues in Supply and Demand,” Aspen Institute Congressional Program (meeting 

on Energy Security: Policy Considerations in the New Congress), Puerto Rico, February 22–27, 2011.

“EPA’s Regulations Affecting Coal Plants: Using a 21st Century Toolkit (or, upgrading to the “Champ” from the 

“Classic”),” DOE/NARUC National Electricity Forum, Washington, D.C., February 16, 2011.

“Responding to EPA’s Regulations Affecting Coal Plants: Using a 21st Century Toolkit (or, upgrading to the “Champ” 

from the “Classic”),” NARUC Winter Meeting, Washington, D.C., February 14, 2011.

“Local, State and Regional Coordination and Solutions: Non-conventional capacity and energy resources,” Bipartisan 

Policy Center’s Workshop on Power Sector Environmental Regulations, Washington, D.C., January 19, 2011.

“Renewable Energy in New England,” New Hampshire Business and Industry Conference, Concord, New Hampshire, 

December 7, 2010.

“Framing the Issues: Energy and the Environment,” National Academy of Public Administration, Washington, D.C., 

November 18, 2010.

“Toolkit for Ensuring Reliable, Economic Responses to EPA’s Proposed Air Regulations,” NARUC Meeting, Atlanta, 

Georgia, November 17, 2010.

“Challenges for Recovering Costs During a Push for Cleaner Generation and More Efficient Energy Use,” Law 

Seminars International conference (Utility Rate Cases), Boston, November 9, 2010.

“Public Policy for Advanced Energy Technology,” New York Advanced Energy Technology Conference, New York, 

NY, November 8, 2010.

“Energy Future: Bridging the Gap,” Wharton Energy meeting, Philadelphia, October 28, 2010.

“Upcoming Power Sector Environmental Regulations: Framing the issues about potential reliability/ cost impacts,” 

National Commission on Energy Policy Workshop on Power Sector Environmental Regulations, Washington, D.C., 

October 22, 2010.

“Vulnerability of the Gulf Coast Energy Infrastructure,” America’s Energy Coast Policy Forum on The Future of the 

U.S. Gulf Coast Energy Infrastructure in the Face of Changing Climate, New Orleans, October 20, 2010.

“Today’s Energy Landscape: Scanning the terrain – with tips for a safe journey,” presentation to the annual meeting of 

the National Association of State Energy Officials, September 30, 2010.

“2020: What can we expect? Where we are now, and how it influences where we’ll be a decade from now,” Law 

Seminars International conference, “Energy in the Northeast,” September 29, 2010.

“Today’s Energy Landscape: Exploring economic, environmental and technological trends,” annual meeting of the 

Independent Power Producers of New York, September 22, 2010.

“Transforming America's Energy Systems: Challenges and opportunities along the nation's coastal and marine 

environments,” Annual Lecture at the Metcalf Institute, University of Rhode Island, June 8, 2010.

“New England at the Crossroads: The Intersection between Regulatory Policy and Future Energy Supply,” presentation 

to the Northeast Energy and Commerce Association, 17th New England Energy Conference, Green Thumb on the Scale: 

Impact on Future Energy Choices, June 8, 2010.

“Is Competition Dead?” Annual Meeting of the New England Conference of Public Utility Commissioners, May 17, 

2010.

“Why it is so Darn Hard to Adopt Advanced Energy Technologies, But So Worth the Effort,” presentation to the Tufts 

University Energy Conference, “The Evolution of Energy,” April 17, 2010.

“The Prospects for Natural Gas, Coal, and Nuclear Power in America’s Energy Future,” discussions with members of 

Congress at the Aspen Institute’s Congressional Program on Energy Security and Climate Change: Policy Challenges 

for the Congress, April 6–10, 2010.

“Why is Modernizing Our Energy Technologies So Darn Hard, But Worth the Effort?” presentation to the MIT Energy 

Initiative Lecture Series, February 2, 2010.

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SERVICE ON BOARDS OF DIRECTORS (PUBLIC COMPANIES, PRIVATE COMPANIES, NONGOVERNMENTAL ORGANIZATIONS)

Chair, Resources for the Future Board of Directors (2018–Present); Member of the Board (2014-Present)

Trustee, Barr Foundation (2016–Present)

Trustee, Alfred P. Sloan Foundation (2022-present)

Advisor, Oak Foundation Board of Trustees (2022-present)

Member, Climate Leadership Initiative, Board of Directors (2022-present), Advisory Board (2019-2022)

Chair, ClimateWorks Foundation Board of Directors (2013–2022)

Member and Vice-Chair, World Resources Institute Board of Directors (2009–Present)

Chair, Energy Foundation Board of Directors (2000– 2011); Vice-Chair (1999–2000); Director (1997–2011); Director 

(2013–2022)

Member, Clean Energy and Sustainability Accelerator (2022-present)

Member, Coalition for Green Capital, Board of Directors (2021-present) 

Member, Keystone Center Energy Board (2016–present) 

Member, Keystone Center Board of Trustees (2016–2019) 

Member, Alliance to Save Energy Board of Directors (2011–2018)

Member, EnerNOC, Inc. Board of Directors (February 2010–May 2013)

Member, Evergreen Solar, Inc. Board of Directors, 2008–2011)

Member, Ze-gen Inc. Board of Directors, 2009–2011)

Member, Renegy Holdings Board of Directors, 2007–2009)

Member, Clean Air Task Force Board of Directors, 2008–2013)

Member, Catalytica Energy Systems Inc. Board of Directors (2001–2007)

Member, Climate Policy Center Board of Directors (2001–2007)

Member, NorthEast States Center for a Clean Air Future, Board of Directors (1998–2010)

Chair, Clean Air–Cool Planet / Climate Policy Center Board of Directors (2004–2009); Director (1999–2014) Member, 

ACORE (American Council on Renewable Energy) Board of Directors (2006–2007)

Member, Electric Power Research Institute (EPRI) Board of Directors (1998–2003, 2005–2006)

Chair, Electricity Innovations Institute, Board of Directors, (2002–2004); Director (2001–2002)

Director, The Randers Group (subsidiary of Thermo TERRATEK) Board of Directors (1997–2000)

Director, Thermo ECOTEK Corporation Board of Directors (1996–1999)

OTHER PROFESSIONAL ACTIVITIES

Member, Committee on Accelerating Decarbonization in the United States: Technology, Policy and Social Dimensions, 

National Academies of Sciences, Engineering & Medicine (2020-present) 

Member, Climate Crossroads Planning Committee, National Academies of Sciences, Engineering & Medicine (2022-

present)

Member, Committee on Net Metering, National Academies of Sciences, Engineering & Medicine (2021-present)

Member, Committee on the Modernization of the Electric Grid, National Academies of Sciences, Engineering & 

Medicine, Climate Communications Initiative (2019-2021)

Member, Advisory Committee of the National Academy of Sciences, Engineering & Medicine, Climate 

Communications Initiative (2018-present)

Chair, External Advisory Council, National Renewables Energy Laboratory (2009–present) 

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Member, Columbia University, Center for Global Energy Policy (2014–2018, 2020-Present)

Member, Institute for Policy Integrity, New York University School of Law (2017-Present)

Member, New York Independent System Operator, Environmental/Advisory Council (2004–Present) 

Member, Technical Review Panels at National Renewable Energy Laboratory: Member, Energy Systems Integration 

TRP (2021-present); Chair, Computational Sciences and Energy Analysis TRP (2018-2021); Chair, Energy Analysis 

TRP (2009-2018).

Visiting Fellow in Policy Practice at the Energy Policy Institute at the University of Chicago (2017–2018)

Chair and Member, Electricity Advisory Committee (Department of Energy) (2015–2017)

Member, National Academy of Sciences Committee on Enhancing the Resiliency of the Nation’s Electric Power 

Transmission and Distribution System (2015–2017)

Chair, Aspen Institute Energy Policy Forum (2015)

Member, Innovation Review Panel, “51st State” Initiative of the Solar Electric Power Association (2015)

Chair, External Review Panel for the Clean Energy Ministerial (2015)

Chair, Aspen Institute Energy Policy Forum (2014)

Participant in studies of the Colorado State University’s Center for Clean Energy Economy (“Powering

Forward: Presidential and Executive Agency Actions to Drive Clean Energy in America”) (January 2014)

Co-Lead Convening Author, Energy Supply and Use Chapter, National Climate Assessment (2012–2014)

Member, Committee on Risk Management and Government Issues in Shale Gas Development, of the National Academy 

of Sciences, Board on Environmental Change and Society (of the Division of Behavioral and Social Sciences and 

Education) (2013–2014)

Co-chair, Bipartisan Policy Center’s Cyber-security and the Electric Grid project (2013–2014)

Co-chair, National American Energy Standards Board (NAESB) Gas-Electric Harmonization Committee

(2012, 2014)

Alliance Commission on National Energy Efficiency Policy (2012–2013): Report “Energy 2030: Doubling

Energy Productivity by 2030” (February 2013)

Bipartisan Policy Center – Energy Project (2011–Present): Report (“America’s Energy Resurgence: Sustaining Success, 

Confronting Challenges” (February 2013)

U.S. Secretary of Energy Advisory Board (July 2010–May 2013). Member of the Natural Gas Subcommittee examining

shale gas development. (2011–2013)

Chair, Policy Subgroup of the National Petroleum Council’s study on North American Gas and Oil

Resource Development (2010–2011)

Visiting Professor, Department of Urban Studies & Planning, Massachusetts Institute of Technology

(Spring 2010)

Massachusetts Clean Energy Grand Prize Judge (2010)

World Resources Institute: Chair of Presidential Search Committee (2011)

Co-Lead, Department of Energy Agency Review Team, Obama/Biden Presidential Transition Team, Washington D.C., 

while on full-time leave for four months from Analysis Group (2008–2009)

Chair, Massachusetts Ocean Advisory Commission (2008–2010)

Member, Blue Ribbon Commission on Cost-Allocation Issues for Transmission Investment, WIRES (2007) Member, 

National Academy of Sciences Committee on Enhancing the Robustness and Resilience of

Electrical Transmission and Distribution in the United States to Terrorist Attack (2005–2008)

Member, National Commission on Energy Policy, Member (2002–2011); Co-chair (2009–2011) Member, Advisory 

Committee, Carnegie Mellon Electricity Industry Center (2001–2009)

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Member, Policy Advisory Committee, China Sustainable Energy Project–A Joint Project of The Packard

Foundation and The Energy Foundation (1999–2014)

Co-Chair, Energy/Environment Working Group, Governor Deval Patrick Transition Team (2006–2007) Presenter, 

Economic Issues, National LNG Forums, U.S. Department of Energy, Boston Massachusetts

Astoria, Oregon (2006)

Chair of the Technical Review Panel, Critical Infrastructure Protection Decision Support Systems (CIP- DSS), Argonne, 

Los Alamos and Sandia National Laboratories (2006)

Advisory Council member, New England Energy Alliance (2005–2006)

Chair of the Laboratory Direction’s Division Review Panel for the Environmental Energy Technologies

Division, Lawrence Berkeley National Laboratory (2005)

Chair, Ocean Management Task Force, Commonwealth of Massachusetts (2003–2004) Co-Chair, RTO Futures: 

Regional Power Working Group (2001–2002)

Member, Florida Energy 2020 Study Commission, Environmental Technical Advisory Committee (2001) Technical 

Advisor, Mid-Atlantic Area Council/PJM, Dispute Resolution Procedure (1998–2008)

Member, “ISO-New England” (Independent System Operator) Advisory Committee (1998–2003)

Member, United States Department of Energy, Electricity Reliability Task Force (1996–1998) Member, Harvard 

Electricity Policy Group (1993–2005)

HONORS AND AWARDS

Lifetime National Associate of the National Research Council of the National Academies of Sciences, Engineering and 

Medicine (January 2020)

Mary Kilmarx Award for lifetime work on good government, clean energy and the environment, presented by NARUC’s 

Committee on Energy Resources and the Environment (November 2015)

Lifetime Achievement Award, U.S. Department of Energy/MIT/Clean Energy Ministerial C3E (CleanEnergy Education 

& Empowerment) Initiative (2014)

Champions Award, Charles River Watershed Association (2013)

Leadership Award, New England Women in Energy and the Environment (2013) Clean Energy Hall of Fame, New 

England Clean Energy Council (2012)

DOE Women in Clean Energy Initiative, C3 Ambassador (2012)

Climate Champion Award, Clean Air – Cool Planet (2009)

Distinguished Alumna Award, Scripps College, Claremont, CA (1998)

Award for Individual Leadership in Public Service, The Energy Daily (1995)

Special Recognition Award, Outstanding Contribution to the Industry, Assn of Energy Engineers (1994)

Leadership Award, National Association of State Energy Officials (1994)

Commencement Speaker and Honorary Doctorate of Laws, Regis College, Weston, MA (1992)

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APPENDIX B

Materials Considered

Legal Documents

Disclosure Statement for Modified Second Amended Title III Plan of Adjustment of the Puerto 

Rico Electric Power Authority, In re: The Financial Oversight and Management Board 

for Puerto Rico, as a representative of the Commonwealth of Puerto Rico, et al., 

Debtors, PROMESA Title III No. 17-BK-3283-LTS, and In re: The Financial 

Oversight and Management Board for Puerto Rico, as a representative of Puerto Rico 

Electric Power Authority, Debtor, PROMESA Title III No. 17-BK-4780-LTS (Jointly 

Administered), United States District Court for the District of Puerto Rico, San Juan, 

Puerto Rico, March 1, 2023.

Responses And Objections Of LUMA Energy, LLC And LUMA Servco, LLC To The 

Bondholders’ Document Requests, In re: The Financial Oversight and Management 

Board for Puerto Rico, as a representative of the Commonwealth of Puerto Rico, et al., 

Debtors, PROMESA Title III No. 17-BK-3283-LTS, and In re: The Financial 

Oversight and Management Board for Puerto Rico, as a representative of Puerto Rico 

Electric Power Authority, Debtor, PROMESA Title III No. 17-BK-4780-LTS (Jointly 

Administered), United States District Court for the District of Puerto Rico, San Juan, 

Puerto Rico, April 12, 2023.

Expert Reports

Expert Report of Maureen M. Chakraborty, PhD, April 28, 2023, and associated Exhibits.

Expert Report of Sebastian Edwards, April 28, 2023, and associated Exhibits.

Bates Stamped Documents

Buchsbaum, Jesse, “Long-Run Price Elasticities and Mechanisms: Empirical Evidence from 

Residential Electricity Consumers,” Energy Institute Working Paper 331, 2022, 

FOMB_PREPA 00022518 - FOMB_PREPA 00022589, available at 

https://haas.berkeley.edu/wp-content/uploads/WP331.pdf.

Burke, Paul J. and Ashani Abayasekara, “The Price Elasticity of Electricity Demand in the 

United States: A Three-Dimensional Analysis,” The Energy Journal, Vol. 39, 2018, 

available at https://doi.org/10.5547/01956574.39.2.pbur. FOMB_PREPA 00020208 -

FOMB_PREPA 00020243.

“Estimated Non-Federally Funded CAPEX FY2023-2032.xlsx,” FOMB_PREPA 00020150.

“FOMB - June 2020 PREPA CFP Model_vS.03.xlsx,” FOMB_PREPA 00024556.

“FOMB - May 2021 FP Model_Data_Room_vF2.xlsx,” FOMB_PREPA 00020362.

“Government Accounts Receivable March 2022.xlsx,” FOMB_PREPA 00001467.

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“January 2022 Fiscal Plan Model Certified (Dataroom).xlsx,” FOMB_PREPA 00020359.

Letter from Covington and DLA Piper to Proskauer, FOMB_PREPA 00023701.

“LT Elasticity workbook.xlsx,” FOMB_PREPA 00022590.

PREPA, “2022 Certified Fiscal Plan for the Puerto Rico Electric Power Authority,” 

FOMB_PREPA 00000699 - FOMB_PREPA 00000882. 

“PREPA 2022 Fiscal Plan Model.xlsx,” FOMB_PREPA 00003018.

“PREPA 2022 FP Alternative Forecast.xlsx,” FOMB_PREPA 00003022.

“20221115 Risk model.xlsx”, FOMB_PREPA 00022385.

Siemens, “Puerto Rico Integrated Resource Plan 2018-2019,” FOMB_PREPA 00024202 - 

FOMB_PREPA 00024531 

Data

LUMA Energy, “Load Forecast FY 2023,” June 21, 2022, available at 

https://energia.pr.gov/wp-content/uploads/sites/7/2022/06/Load-Forecast-FY2023_Values-3.xlsx. 

LUMA Energy, “Proyecciones x clase (May 5 2021 updated).xlsx,” available at 

https://energia.pr.gov/wp-content/uploads/sites/7/2021/06/Proyecciones-x-clase-May5-2021-updatedvalues.xlsx.

NREL, “Net Electricity and Natural Gas Consumption,” State and Local Planning for Energy, 

2019, https://maps.nrel.gov/slope. 

NREL Data Viewer, “Mid-Case Scenario,” State and Local Planning for Energy, 2020, 

https://maps.nrel.gov/slope. 

NREL, “Mid-Case Scenario,” State and Local Planning for Energy, available at 

https://maps.nrel.gov/slope/data-viewer?layer=standard-scenarios.mid-recost&res=state&year=2020&filters=%5B%5D.

“Revenue Envelope and Legacy Charge_protected.xlsx.”

U.S. Census Bureau, 2017-2021 American Community Survey 5-year Estimates, available at 

https://data.census.gov/table?q=median+household+income+california&g=040XX00U

S04,06,12,15,25,34,50,72&tid=ACSST1Y2021.S1903. 

Publicly Available Documents

ACEEE, “2018 State Energy Efficiency Scorecard,” October 4, 2018, available at 

https://www.aceee.org/research-report/u1808. 

ACEEE, “Puerto Rico,” July 20, 2018, available at https://database.aceee.org/territory/puertorico.

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Besanko, David and Ronald Braeutigam, Microeconomics, John Wiley & Sons, 6th Ed., 2020, 

available at 

https://faculty.ksu.edu.sa/sites/default/files/David%20Besanko%2C%20Ronald%20Bra

eutigam%20-%20Microeconomics-Wiley%20%282020%29.pdf. 

California Public Utilities Commission, “About the California Solar Initiative,” available at 

https://www.cpuc.ca.gov/-/media/cpuc-website/about-cpuc/documents/transparencyand-reporting/fact_sheets/csifactsheet_v4.pdf.

California Public Utilities Commission, Decision Revising Net Energy Metering Tariff and 

Subtariffs, Docket No. 20-08-020, Order Instituting Rulemaking to Revisit Net Energy 

Metering Tariffs Pursuant to Decision 16-01-044, and to Address Other Issues Related 

to Net Energy Metering, December 15, 2022, p. 209, available at 

https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K043/500043682.PDF.

DSIRE, “Distributed Generation Tariffs,” March 3, 2023, available at 

https://programs.dsireusa.org/system/program/detail/596.

DSIRE, “Puerto Rico – Net Metering,” October 12, 2021, available at 

https://programs.dsireusa.org/system/program/detail/2846/puerto-rico-net-metering.

Financial Oversight & Management Board of Puerto Rico, “Puerto Rico’s Debt Restructuring 

Process,” available at https://oversightboard.pr.gov/debt/.

IRS, “Topic No. 901, Is a Person with Income from Puerto Rico Required to File a U.S. 

Income Tax Return?,” April 7, 2023, available at https://www.irs.gov/taxtopics/tc901

Labandeira, Xavier, José M. Labeaga, and Xiral López-Otero, “A Meta-Analysis on the Price 

Elasticity of Energy Demand,” Energy Policy, Vol. 102, March 2017, available at 

https://www.sciencedirect.com/science/article/abs/pii/S0301421517300022.

LUMA Energy, “Transition Period Program Plan for Energy Efficiency and Demand 

Response,” June 21, 2022, available at https://energia.pr.gov/wpcontent/uploads/sites/7/2022/06/Motion-Submitting-Proposed-EE-DR-TransitionPeriod-Plan-NEPR-MI-2021-0006.pdf.

Narang, David, et al., “Considerations for Distributed Energy Resource Integration in Puerto 

Rico,” NREL, February 2021, available at 

https://www.nrel.gov/docs/fy21osti/77127.pdf.

National Academies of Sciences, Engineering and Medicine, The Future of Electric Power in 

the U.S., The National Academies Press, 2021, available at 

https://doi.org/10.17226/25968. 

NREL, “Puerto Rico Low-to-Moderate Income Rooftop PV and Solar Savings Potential,” 

December 17, 2020, available at https://www.nrel.gov/docs/fy21osti/78756.pdf

Office of Management and Budget, Puerto Rico Energy Public Policy Act, Act. No. 17 of 

April 11, 2019, available at 

https://bvirtualogp.pr.gov/ogp/Bvirtual/leyesreferencia/PDF/2-ingles/17-2019.pdf. 

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Office of Management and Budget, Puerto Rico Energy Public Policy Act, Act. No. 17 of 

April 11, 2019, available at 

https://bvirtualogp.pr.gov/ogp/Bvirtual/leyesreferencia/PDF/2-ingles/17-2019.pdf. 

Office of Management and Budget, Puerto Rico Energy Transformation and RELIEF Act, Act 

No. 57 of May 27, 2014, as amended, Section 6.29B — Energy Efficiency (codified as 

22 L.P.R.A. § 1054bb-2), available at 

https://bvirtualogp.pr.gov/ogp/Bvirtual/leyesreferencia/PDF/2-ingles/57-2014.pdf. 

Office of Management and Budget, Puerto Rico Net Metering Act, Act. No. 114 of August 16, 

2007, as amended, available at 

https://bvirtualogp.pr.gov/ogp/Bvirtual/leyesreferencia/PDF/2-ingles/114-2007.pdf.

Plumer B, Popovich N, and Migliozzi B, “Electric Cars Are Coming. How Long until They 

Rule the Road?,” New York Times, March 2021, available at 

https://www.nytimes.com/interactive/2021/03/10/climate/electric-vehicle-fleetturnover.html.

PRASA, “Puerto Rico Aqueduct and Sewer Authority 2022 Fiscal Plan,” available at 

https://drive.google.com/file/d/1m3p6XwENAyNuELOb2ugncn9aGfK7n4mS/view.

PREB, “Request for Proposals: Energy Efficiency Baseline and Potential Studies,” April 27, 

2022, available at 

https://static1.squarespace.com/static/61ea784947109b1572ec37ec/t/627cca4e2ddcae3

086a1faf5/1652345423614/NEPR+EE+Study+RFP+revised.pdf.

PREB, Regulation for Energy Efficiency, Article 3, Energy Efficiency Savings Targets, March 

25, 2022, available at https://energia.pr.gov/wpcontent/uploads/sites/7/2022/04/Reglamento-9367-Regulation-for-EnergyEfficiency.pdf.

PREPA Governing Board, Resolution 5027, “Approval of a Memorandum of Understanding 

Between the Puerto Rico Electric Power Authority and Puerto Rico Aqueduct and 

Sewer Authority,” February 24, 2023, available at https://aeepr.com/espr/jpportal/Resoluciones/Resolution%205027%20-

%20Approval%20of%20a%20Memorandum%20of%20Understanding% 

20between%20PREPA%20and%20PRASA.pdf.

PREPA, “Tariff Book - Electric Service Rates and Riders,” May 28, 2019, available at 

https://aeepr.com/espr/QuienesSomos/Ley57/Facturaci%C3%B3n/Tariff%20Book%20-

%20Electric%20Service%20Rates%20and%20Riders%20Revised%20by%20Order%2

005172019%20Approved%20by%20Order%2005282019.pdf.

PREPA, “2019 FOMB - Fiscal Plan for PREPA, as Certified by FOMB on June 27 2019,” 

June 27, 2019, available at https://aeepr.com/es-pr/Documents/Exhibit%201%20-

%202019%20Fiscal_Plan_for_PREPA_Certified_FOMB%20on_June_27_2019.pdf.

National Association of Regulatory Utility Commissioners, “Primer on rate design for costreflective tariffs,” January 2021, available at 

https://pubs.naruc.org/pub.cfm?id=7BFEF211-155D-0A36-31AA-F629ECB940DC.

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Razavi, Seyed-Ehsan, et al. “Impact of Distributed Generation on Protection and Voltage 

Regulation on Distribution Systems: A Review,” Renewable and Sustainable Energy 

Reviews, Vol. 105, May 2019, available at 

https://www.sciencedirect.com/science/article/abs/pii/S1364032119300668.

Reorg, “With Federal Funds Expected to Cover CapEx Needs for Next Decade, 

Commonwealth Takes Measured Path Toward Investment-Grade Credit Ratings,” 

April 27, 2023.

Siemens, “Puerto Rico Integrated Resource Plan 2018-2019,” June 19, 2019, Section 3-1, 

available at https://energia.pr.gov/wp-content/uploads/sites/7/2019/06/IRP2019-MainReport-REV2-06182019-wERRATA.pdf.

Siemens, “Puerto Rico Integrated Resource Plan 2018-2019 Appendix 4: Demand Side 

Resources,” available at https://aeepr.com/espr/QuienesSomos/Ley57/Plan%20Integrado%20de%20Recursos/IRP2019%20-

%20Ex%201.04%20-%20%20Appendix%204%20-

%20Demand%20Side%20Resources.pdf.

Solar Energy Technologies Office, “Homeowner’s Guide to the Federal Tax Credit for Solar 

Photovoltaics,” March 2023, available at 

https://www.energy.gov/eere/solar/homeowners-guide-federal-tax-credit-solarphotovoltaics. 

The Solar Foundation, “Finance Report: An Assessment of Opportunities and Barriers to Solar 

Finance in Puerto Rico,” April 2021, available at https://irecusa.org/wpcontent/uploads/2021/07/FinanceReport-Completed_5-13.pdf.

Tierney, Susan, “The Value of ‘DER’ to ‘D’: The Role of Distributed Energy Resources in 

Supporting Local Electric Distribution System Reliability,” Analysis Group, March 31, 

2016, available at 

https://www.analysisgroup.com/globalassets/content/news_and_events/news/value_of_

der_to-_d.pdf.

US Census, “QuickFacts Puerto Rico,” available at 

https://www.census.gov/quickfacts/fact/table/PR/HSG445221.

Zhu, Xing, Lanlan Li, Kaile Zhou, Xiaoling Zhang, and Shanlin Yang, “A Meta-Analysis on 

the Price Elasticity and Income Elasticity of Residential Electricity Demand,” Journal 

of Cleaner Production, Vol. 201, November 10, 2018, available at 

https://www.sciencedirect.com/science/article/abs/pii/S0959652618323588. 

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Fiscal Year

Real GNP

(Millions $)

Population 

(Millions)

2021 5,761 3.323

2022 5,913 3.279

2023 5,968 3.241

2024 5,927 3.208

2025 5,928 3.177

2026 5,947 3.152

2027 6,005 3.137

2028 6,033 3.122

2029 6,028 3.104

2030 6,008 3.081

2031 5,998 3.055

2032 5,954 3.027

2033 5,912 3.000

2034 5,864 2.973

2035 5,815 2.946

2036 5,731 2.916

2037 5,672 2.884

2038 5,625 2.851

2039 5,587 2.818

2040 5,557 2.786

2041 5,558 2.755

2042 5,501 2.724

2043 5,477 2.694

2044 5,455 2.665

2045 5,434 2.637

2046 5,415 2.612

2047 5,402 2.587

2048 5,387 2.564

2049 5,372 2.542

2050 5,361 2.520

2051 5,351 2.520

Notes:

Sources:

Table C-1: GNP and Population Forecasts Underlying 2022 PREPA Fiscal Plan

[1] The PREPA Gross Load Forecast uses the population series from the Commonwealth 2022

Certified Fiscal Plan on a one year lag.

[2] The PREPA Gross Load Forecast uses the Real GNP projection without Income Adjustments

from the Commonwealth 2022 Certified Fiscal Plan.

Appendix C: Macroeconomic Forecasts Underlying 2022 PREPA Fiscal Plan

[1] "January 2022 Fiscal Plan Model Certified (Dataroom).xlsx," FOMB_PREPA 00020359.

[2] LUMA Energy, “Load Forecast FY 2023,” June 21, 2022, available at

https://energia.pr.gov/wp-content/uploads/sites/7/2022/06/Load-ForecastFY-2023_Values-3.xlsx

C-1

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Fiscal Year

Residential 

(GWh)

Commercial 

(GWh)

Industrial 

(GWh)

Public Lighting 

(GWh)

Agricultural 

(GWh)

Others 

(GWh)

Total 

(GWh)

2023 6,977 7,347 1,884 275 27 38 16,547

2024 6,793 7,151 1,825 276 27 38 16,109

2025 6,694 7,025 1,799 240 27 38 15,823

2026 6,614 6,899 1,838 206 27 38 15,621

2027 6,560 6,756 1,828 172 27 38 15,380

2028 6,506 6,616 1,790 138 27 38 15,114

2029 6,432 6,470 1,688 137 27 38 14,792

2030 6,335 6,317 1,591 137 27 38 14,445

2031 6,220 6,150 1,589 137 27 38 14,160

2032 6,093 5,980 1,576 138 27 38 13,852

2033 5,960 5,885 1,548 137 27 38 13,595

2034 5,848 5,809 1,397 137 27 38 13,257

2035 5,764 5,735 1,338 137 27 38 13,039

2036 5,671 5,660 1,273 138 27 38 12,807

2037 5,571 5,581 1,211 137 27 38 12,565

2038 5,484 5,521 1,172 138 27 38 12,379

2039 5,395 5,451 1,145 137 27 38 12,193

2040 5,303 5,377 1,117 137 27 38 11,999

2041 5,218 5,295 1,119 137 27 38 11,834

2042 5,131 5,216 1,077 138 27 38 11,627

2043 5,036 5,131 1,033 137 27 38 11,402

2044 4,948 5,044 1,007 137 27 38 11,201

2045 4,855 4,951 983 137 27 38 10,990

2046 4,772 4,865 961 138 27 38 10,800

2047 4,687 4,774 945 137 27 38 10,609

2048 4,604 4,684 930 137 27 38 10,420

2049 4,514 4,586 915 137 27 38 10,217

2050 4,431 4,492 903 138 27 38 10,029

2051 4,432 4,264 941 138 27 38 9,840

Sources:

[1] 2022 PREPA Fiscal Plan Model.

[2] 2022 PREPA Fiscal Plan Alternative Forecast Model.

Table D-1: Annual Net Load Under PREPA Alternative Forecast

Appendix D: Modified Net Load Forecasts

D-1

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Fiscal Year

Residential 

(GWh)

Commercial 

(GWh)

Industrial 

(GWh)

Public Lighting 

(GWh)

Agricultural 

(GWh)

Others 

(GWh)

Total 

(GWh)

2023 6,940 7,324 1,883 275 27 38 16,487

2024 6,822 7,161 1,850 276 27 38 16,173

2025 6,796 7,064 1,874 240 27 38 16,039

2026 6,776 6,964 1,948 206 27 38 15,958

2027 6,774 6,842 1,978 172 27 38 15,830

2028 6,770 6,714 1,993 138 27 38 15,680

2029 6,741 6,577 1,954 137 27 38 15,474

2030 6,686 6,430 1,915 137 27 38 15,233

2031 6,601 6,268 1,956 137 27 38 15,026

2032 6,499 6,102 1,979 138 27 38 14,782

2033 6,388 6,009 1,984 137 27 38 14,582

2034 6,293 5,935 1,863 137 27 38 14,293

2035 6,228 5,861 1,839 137 27 38 14,130

2036 6,158 5,786 1,818 138 27 38 13,965

2037 6,085 5,709 1,800 137 27 38 13,795

2038 6,024 5,651 1,801 138 27 38 13,679

2039 5,963 5,586 1,816 137 27 38 13,566

2040 5,900 5,516 1,828 137 27 38 13,446

2041 5,844 5,438 1,875 137 27 38 13,359

2042 5,782 5,363 1,870 138 27 38 13,217

2043 5,709 5,280 1,859 137 27 38 13,050

2044 5,644 5,196 1,868 137 27 38 12,910

2045 5,571 5,104 1,877 137 27 38 12,753

2046 5,505 5,018 1,886 138 27 38 12,612

2047 5,436 4,927 1,904 137 27 38 12,469

2048 5,369 4,834 1,926 137 27 38 12,330

2049 5,294 4,733 1,949 137 27 38 12,177

2050 5,226 4,635 1,976 138 27 38 12,039

2051 5,140 4,517 2,050 138 27 38 11,910

Sources:

[1] Expert Report of Dr. Sebastian Edwards, Appendix C.

[2] 2022 PREPA Fiscal Plan Model.

[3] 2022 PREPA Fiscal Plan Alternative Forecast Model.

[4] 2019 IRP.

Table D-2: Annual Net Load Under PREPA Alternative Forecast and Macro Scenario 1: World Bank 

Population and Edwards GNP

D-2

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Fiscal Year

Residential 

(GWh)

Commercial 

(GWh)

Industrial 

(GWh)

Public Lighting 

(GWh)

Agricultural 

(GWh)

Others 

(GWh)

Total 

(GWh)

2023 7,216 7,347 2,336 275 27 38 17,237

2024 7,007 7,151 2,230 276 27 38 16,729

2025 6,872 7,025 2,134 240 27 38 16,336

2026 6,760 6,899 2,113 206 27 38 16,043

2027 6,688 6,756 2,071 172 27 38 15,751

2028 6,630 6,616 2,024 138 27 38 15,473

2029 6,556 6,470 1,922 137 27 38 15,149

2030 6,458 6,317 1,824 137 27 38 14,801

2031 6,343 6,150 1,820 137 27 38 14,515

2032 6,215 5,980 1,807 138 27 38 14,205

2033 6,082 5,885 1,778 137 27 38 13,947

2034 5,969 5,809 1,626 137 27 38 13,607

2035 5,885 5,735 1,566 137 27 38 13,388

2036 5,791 5,660 1,500 138 27 38 13,153

2037 5,690 5,581 1,436 137 27 38 12,909

2038 5,603 5,521 1,396 138 27 38 12,721

2039 5,512 5,451 1,367 137 27 38 12,533

2040 5,420 5,377 1,337 137 27 38 12,336

2041 5,334 5,295 1,339 137 27 38 12,170

2042 5,246 5,216 1,294 138 27 38 11,959

2043 5,150 5,131 1,247 137 27 38 11,730

2044 5,061 5,044 1,219 137 27 38 11,526

2045 4,966 4,951 1,193 137 27 38 11,312

2046 4,882 4,865 1,169 138 27 38 11,119

2047 4,797 4,774 1,152 137 27 38 10,925

2048 4,713 4,684 1,136 137 27 38 10,734

2049 4,622 4,586 1,119 137 27 38 10,528

2050 4,538 4,492 1,105 138 27 38 10,338

2051 4,440 4,379 1,142 138 27 38 10,163

Sources:

[1] Expert Report of Dr. Sebastian Edwards, Appendix C.

[2] 2022 PREPA Fiscal Plan Model.

[3] 2022 PREPA Fiscal Plan Alternative Forecast Model.

[4] 2019 IRP.

Table D-3: Annual Net Load Under PREPA Alternative Forecast and Macro Scenario 2: 2022 

Commonwealth Fiscal Plan Population and GNP Including COVID-19 Income Adjustment

D-3

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Appendix E: Adjustments to PREPA Base Rates Under Revised Net Load Forecasts

PREPA’s non-Legacy-Charge revenue requirement comprises both fixed and variable costs, and 

is collected through “base rates” charged to its customers. If PREPA’s load forecasts are revised, then its 

fixed costs must be spread over a different set of loads, and its base rates must also change. This 

Appendix describes my methodology for adjusting PREPA’s base rates under revised net load forecasts.

In the 2022 PREPA Fiscal Plan and the FOMB’s Revenue Envelope and Legacy Charge Model, 

PREPA’s non-Legacy Charge revenue requirement is assumed to be collected through base rates in the 

categories of “Basic Revenue,” “Fuel & Purchased Power,” “CILT,” Subsidies”, and “ERS Pension.”1

FOMB assumes that the costs collected through the “Basic Revenues” and “ERS Pension” rates are 100% 

fixed, the costs collected through the “Fuel & Purchased Power” rate are 10% fixed and 90% variable, 

and the costs collected through the “CILT” and “Subsidies” rates are 97.5% fixed and 2.5% variable.2

With revised net load forecasts, the base rates for the residential, commercial, and industrial classes

used in calculating the Revenue Envelope must be adjusted to account for the revised net loads of each 

customer class, so that revenues collected from the base rates cover both the fixed costs (unchanged under 

a revised load forecast) and revised variable costs (which change proportionally with the revised load 

forecast).

3 The adjustment calculation proceeds in the following steps in each fiscal year:

1. The ratios of the revised net load forecasts to the original 2022 PREPA Fiscal Plan net load 

forecasts are calculated for each customer class (see rows 29-31).4

2. The revenue generated from each customer class’s “Basic Revenue” rates is assumed to cover 

100% fixed costs which stay constant even as the net load forecast changes. Therefore, the 

adjusted “Basic Revenue” rates are calculated by dividing by these ratios for each customer class 

1 Revenue Envelope and Legacy Charge Model, tab “Revenue Recovery Rates.” 2 Revenue Envelope and Legacy Charge Model, tab “Revenues Available.” 3 See rows 10-12 of “Base Rate Adjustment.xlsx,” tabs “Alternative Model,” “+Macro 1 WB Pop Edwards GNP,” 

and “+Macro 2 CW FP Pop and GNP”. 4 See tabs “Alternative Model,” “+Macro 1 WB Pop Edwards GNP,” and “+Macro 2 CW FP Pop and GNP” of 

“Base Rate Adjustment.xlsx”.

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Exhibit Exhibit A - Expert Report of S. Tierney Page 112 of 117
CONFIDENTIAL

E-2

(see rows 34-36).

5 For example, if the new residential net load is 1% higher than the residential 

net load in the Fiscal Plan net load forecast, then the “Basic Revenue” rate for the residential class 

is adjusted by dividing by 1.01. This adjustment ensures that “Basic Revenue” rates for each 

customer class continues to cover the same level of fixed costs even under the revised load 

forecasts.

3. For other volumetric rates used in calculating the revenue envelope (Fuel & Purchased Power, 

CILT, Subsidies, and ERS Pension Charge, rows 5-8), the board assumes a percentage of the 

revenues generated by each are fixed (the percentages assumed fixed are listed in column D).

6

For these categories, the rate is adjusted by splitting it into a fixed component and a variable 

component.

a. The fixed components are adjusted in exactly the same way as the “Basic Revenue” rates 

for customer classes described in Step 2, but using the ratio of the revised total net load 

forecasts to the original 2022 PREPA Fiscal Plan total net load forecasts (see row 32).

7

b. The variable component of each rate, on the other hand, is first assumed to increase 

proportionally to the ratio of modified total net load to the Fiscal Plan total net load, but 

is also assumed to be spread out over more units of consumption, and therefore 

multiplied by the ratio of the Fiscal Plan net load to the modified net load. These two 

effects cancel each other out, and there is no net adjustment to the variable component of 

each rate.

c. The adjusted rates are then calculated by recombining the fixed and variable components 

(see rows 38-41).8

5 See tabs “Alternative Model,” “+Macro 1 WB Pop Edwards GNP,” and “+Macro 2 CW FP Pop and GNP” of 

“Base Rate Adjustment.xlsx”. 6 See tabs “Alternative Model,” “+Macro 1 WB Pop Edwards GNP,” and “+Macro 2 CW FP Pop and GNP” of 

“Base Rate Adjustment.xlsx”. 7 See tabs “Alternative Model,” “+Macro 1 WB Pop Edwards GNP,” and “+Macro 2 CW FP Pop and GNP” of 

“Base Rate Adjustment.xlsx”. 8 See tabs “Alternative Model,” “+Macro 1 WB Pop Edwards GNP,” and “+Macro 2 CW FP Pop and GNP” of 

“Base Rate Adjustment.xlsx”.

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Exhibit Exhibit A - Expert Report of S. Tierney Page 113 of 117
CONFIDENTIAL

Fiscal Year

Residential Base Rate 

($/kWh)

Commercial Base Rate 

($/kWh)

Industrial Base Rate 

($/kWh)

ERS Pension Charge 

($/kWh)

Fuel & Purchased Power 

($/kWh)

CILT

($/kWh)

Subsidies

($/kWh)

2024 $0.0602 $0.0813 $0.0472 $0.0241 $0.1225 $0.0071 $0.0156

2025 $0.0585 $0.0784 $0.0467 $0.0211 $0.1253 $0.0054 $0.0120

2026 $0.0580 $0.0782 $0.0446 $0.0212 $0.1333 $0.0056 $0.0115

2027 $0.0574 $0.0782 $0.0441 $0.0213 $0.1453 $0.0059 $0.0111

2028 $0.0568 $0.0782 $0.0437 $0.0214 $0.1437 $0.0063 $0.0110

2029 $0.0564 $0.0784 $0.0449 $0.0215 $0.1454 $0.0065 $0.0112

2030 $0.0561 $0.0787 $0.0475 $0.0216 $0.1477 $0.0067 $0.0114

2031 $0.0560 $0.0793 $0.0477 $0.0163 $0.1506 $0.0070 $0.0116

2032 $0.0560 $0.0800 $0.0478 $0.0147 $0.1540 $0.0071 $0.0119

2033 $0.0560 $0.0796 $0.0455 $0.0144 $0.1589 $0.0074 $0.0120

2034 $0.0558 $0.0791 $0.0491 $0.0142 $0.1626 $0.0078 $0.0124

2035 $0.0553 $0.0786 $0.0504 $0.0139 $0.1666 $0.0081 $0.0126

2036 $0.0549 $0.0781 $0.0513 $0.0136 $0.1710 $0.0085 $0.0128

2037 $0.0545 $0.0778 $0.0522 $0.0133 $0.1759 $0.0086 $0.0130

2038 $0.0546 $0.0772 $0.0527 $0.0128 $0.1804 $0.0090 $0.0132

2039 $0.0542 $0.0760 $0.0527 $0.0124 $0.1877 $0.0093 $0.0134

2040 $0.0537 $0.0748 $0.0531 $0.0120 $0.1950 $0.0098 $0.0137

2041 $0.0537 $0.0757 $0.0526 $0.0115 $0.2077 $0.0103 $0.0139

2042 $0.0536 $0.0765 $0.0532 $0.0111 $0.2079 $0.0107 $0.0143

2043 $0.0535 $0.0775 $0.0539 $0.0107 $0.1860 $0.0110 $0.0145

2044 $0.0534 $0.0785 $0.0543 $0.0103 $0.2076 $0.0110 $0.0145

2045 $0.0534 $0.0797 $0.0547 $0.0099 $0.2177 $0.0111 $0.0146

2046 $0.0534 $0.0808 $0.0550 $0.0094 $0.2253 $0.0111 $0.0146

2047 $0.0534 $0.0821 $0.0553 $0.0089 $0.2349 $0.0111 $0.0146

2048 $0.0533 $0.0834 $0.0554 $0.0085 $0.2432 $0.0111 $0.0146

2049 $0.0535 $0.0849 $0.0557 $0.0080 $0.2502 $0.0112 $0.0147

2050 $0.0045 $0.0864 $0.0558 $0.0075 $0.2590 $0.0112 $0.0148

2051 $0.0045 $0.0891 $0.0548 $0.0070 $0.2679 $0.0113 $0.0148

Sources:

[1] Revenue Envelope and Legacy Charge Model.

[2] 2022 PREPA Fiscal Plan Model.

[3] 2022 PREPA Fiscal Plan Alternative Forecast Model.

Table E-1: PREPA Base Rates under PREPA Alternative Forecast

E-3

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Exhibit Exhibit A - Expert Report of S. Tierney Page 114 of 117
CONFIDENTIAL

Fiscal Year

Residential Base Rate 

($/kWh)

Commercial Base Rate 

($/kWh)

Industrial Base Rate 

($/kWh)

ERS Pension Charge 

($/kWh)

Fuel & Purchased Power 

($/kWh)

CILT

($/kWh)

Subsidies

($/kWh)

2024 $0.0599 $0.0812 $0.0465 $0.0240 $0.1224 $0.0071 $0.0156

2025 $0.0577 $0.0780 $0.0448 $0.0209 $0.1251 $0.0054 $0.0118

2026 $0.0566 $0.0775 $0.0421 $0.0208 $0.1330 $0.0054 $0.0113

2027 $0.0556 $0.0772 $0.0407 $0.0207 $0.1449 $0.0057 $0.0108

2028 $0.0546 $0.0771 $0.0393 $0.0206 $0.1433 $0.0061 $0.0106

2029 $0.0538 $0.0771 $0.0388 $0.0205 $0.1448 $0.0062 $0.0107

2030 $0.0532 $0.0774 $0.0395 $0.0205 $0.1470 $0.0064 $0.0109

2031 $0.0528 $0.0778 $0.0388 $0.0154 $0.1498 $0.0066 $0.0110

2032 $0.0525 $0.0784 $0.0381 $0.0138 $0.1532 $0.0067 $0.0111

2033 $0.0522 $0.0780 $0.0355 $0.0135 $0.1580 $0.0069 $0.0112

2034 $0.0518 $0.0774 $0.0368 $0.0132 $0.1616 $0.0072 $0.0115

2035 $0.0512 $0.0769 $0.0366 $0.0129 $0.1655 $0.0075 $0.0116

2036 $0.0505 $0.0764 $0.0359 $0.0125 $0.1697 $0.0078 $0.0117

2037 $0.0499 $0.0760 $0.0351 $0.0121 $0.1745 $0.0079 $0.0119

2038 $0.0497 $0.0754 $0.0343 $0.0116 $0.1789 $0.0081 $0.0120

2039 $0.0490 $0.0741 $0.0333 $0.0112 $0.1861 $0.0084 $0.0121

2040 $0.0483 $0.0729 $0.0325 $0.0107 $0.1933 $0.0088 $0.0122

2041 $0.0479 $0.0737 $0.0314 $0.0102 $0.2058 $0.0092 $0.0124

2042 $0.0475 $0.0744 $0.0306 $0.0098 $0.2059 $0.0095 $0.0127

2043 $0.0472 $0.0753 $0.0300 $0.0094 $0.1841 $0.0097 $0.0128

2044 $0.0468 $0.0762 $0.0293 $0.0089 $0.2054 $0.0096 $0.0127

2045 $0.0466 $0.0773 $0.0286 $0.0085 $0.2152 $0.0096 $0.0126

2046 $0.0463 $0.0783 $0.0280 $0.0081 $0.2227 $0.0095 $0.0125

2047 $0.0460 $0.0795 $0.0274 $0.0076 $0.2320 $0.0095 $0.0125

2048 $0.0457 $0.0808 $0.0268 $0.0071 $0.2401 $0.0094 $0.0124

2049 $0.0456 $0.0823 $0.0261 $0.0067 $0.2469 $0.0094 $0.0124

2050 $0.0038 $0.0838 $0.0255 $0.0062 $0.2555 $0.0094 $0.0124

2051 $0.0038 $0.0841 $0.0251 $0.0058 $0.2640 $0.0094 $0.0123

Sources:

[1] Revenue Envelope and Legacy Charge Model.

[2] 2022 PREPA Fiscal Plan Model.

[3] 2022 PREPA Fiscal Plan Alternative Forecast Model.

[4] Expert Report of Susan Tierney, PhD, April 28, 2023, Appendix D.

Table E-2: PREPA Residential/Commercial/Industrial Base Rates under PREPA Alternative Forecast and Macro Scenario 1: World Bank Population and Edwards GNP

E-4

Case:17-03283-LTS Doc#:24392-1 Filed:06/01/23 Entered:06/01/23 21:01:55 Desc:

Exhibit Exhibit A - Expert Report of S. Tierney Page 115 of 117
CONFIDENTIAL

Fiscal Year

Residential Base Rate 

($/kWh)

Commercial Base Rate 

($/kWh)

Industrial Base Rate 

($/kWh)

ERS Pension Charge 

($/kWh)

Fuel & Purchased Power 

($/kWh)

CILT

($/kWh)

Subsidies

($/kWh)

2024 $0.0583 $0.0813 $0.0386 $0.0232 $0.1220 $0.0068 $0.0151

2025 $0.0570 $0.0784 $0.0393 $0.0205 $0.1249 $0.0053 $0.0116

2026 $0.0567 $0.0782 $0.0388 $0.0207 $0.1330 $0.0054 $0.0112

2027 $0.0563 $0.0782 $0.0389 $0.0208 $0.1450 $0.0057 $0.0109

2028 $0.0558 $0.0782 $0.0387 $0.0209 $0.1434 $0.0061 $0.0107

2029 $0.0554 $0.0784 $0.0394 $0.0210 $0.1451 $0.0063 $0.0109

2030 $0.0550 $0.0787 $0.0414 $0.0211 $0.1473 $0.0066 $0.0112

2031 $0.0550 $0.0793 $0.0417 $0.0159 $0.1503 $0.0068 $0.0114

2032 $0.0549 $0.0800 $0.0417 $0.0143 $0.1537 $0.0069 $0.0116

2033 $0.0548 $0.0796 $0.0396 $0.0141 $0.1586 $0.0072 $0.0117

2034 $0.0546 $0.0791 $0.0422 $0.0139 $0.1623 $0.0076 $0.0121

2035 $0.0542 $0.0786 $0.0430 $0.0136 $0.1663 $0.0079 $0.0122

2036 $0.0537 $0.0781 $0.0435 $0.0133 $0.1706 $0.0083 $0.0124

2037 $0.0534 $0.0778 $0.0440 $0.0129 $0.1755 $0.0084 $0.0127

2038 $0.0535 $0.0772 $0.0443 $0.0125 $0.1800 $0.0087 $0.0128

2039 $0.0530 $0.0760 $0.0442 $0.0121 $0.1872 $0.0091 $0.0131

2040 $0.0526 $0.0748 $0.0444 $0.0117 $0.1946 $0.0096 $0.0133

2041 $0.0525 $0.0757 $0.0440 $0.0112 $0.2073 $0.0101 $0.0135

2042 $0.0524 $0.0765 $0.0443 $0.0108 $0.2074 $0.0105 $0.0139

2043 $0.0523 $0.0775 $0.0447 $0.0104 $0.1856 $0.0107 $0.0141

2044 $0.0522 $0.0785 $0.0449 $0.0100 $0.2072 $0.0107 $0.0141

2045 $0.0523 $0.0797 $0.0451 $0.0096 $0.2172 $0.0108 $0.0142

2046 $0.0522 $0.0808 $0.0452 $0.0091 $0.2248 $0.0108 $0.0142

2047 $0.0522 $0.0821 $0.0453 $0.0087 $0.2343 $0.0108 $0.0142

2048 $0.0521 $0.0834 $0.0454 $0.0082 $0.2426 $0.0108 $0.0142

2049 $0.0523 $0.0849 $0.0455 $0.0077 $0.2496 $0.0108 $0.0143

2050 $0.0044 $0.0864 $0.0456 $0.0073 $0.2584 $0.0109 $0.0143

2051 $0.0045 $0.0868 $0.0451 $0.0068 $0.2672 $0.0109 $0.0144

Sources:

[1] Revenue Envelope and Legacy Charge Model.

[2] 2022 PREPA Fiscal Plan Model.

[3] 2022 PREPA Fiscal Plan Alternative Forecast Model.

[4] Expert Report of Susan Tierney, PhD, April 28, 2023, Appendix D.

Table E-3: PREPA Residential/Commercial/Industrial Base Rates under PREPA Alternative Forecast and Macro Scenario 2: 2022 Commonwealth Fiscal Plan Population and GNP Including COVID-19 

Income Adjustment

E-5

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Exhibit Exhibit A - Expert Report of S. Tierney Page 116 of 117
CONFIDENTIAL

F-1

Appendix F: Elasticity Estimates Used by the FOMB and in Academic Literature

Notes:

[1] "Lower 48" indicates all U.S. states excluding Alaska and Hawaii. 

[2] Burke and Abayasekara (2018) long-term estimates are rounded from non-IV cross-state estimates, and 

are used in FOMB's long-term elasticity estimates.

[3] Labandeira et al (2017) estimates are calculated as the sum of the intercept and the coefficient on each 

sector in tables A3 and A4 of their paper.

[4] Zhu et al (2018) estimates report the mean for short-term and long-term elasticities.

Sources:

[1] “Revenue Envelope and Legacy Charge_protected.xlsx”

[2] Burke, Paul J. and Ashani Abayasekara, “The Price Elasticity of Electricity Demand in the United States: 

A Three-Dimensional Analysis,” The Energy Journal, Vol. 39, 2018, available at 

https://doi.org/10.5547/01956574.39.2.pbur. FOMB_PREPA 00020208 - FOMB_PREPA 00020243. 

[3] Buchsbaum, Jesse, “Long-Run Price Elasticities and Mechanisms: Empirical Evidence from Residential 

Electricity Consumers,” Energy Institute Working Paper 331, 2022, FOMB_PREPA 00022518 -

FOMB_PREPA 00022589, available at https://haas.berkeley.edu/wp-content/uploads/WP331.pdf. 

[4] Labandeira, Xavier, José M. Labeaga, and Xiral López-Otero, “A Meta-Analysis on the Price Elasticity of 

Energy Demand,” Energy Policy, Vol. 102, March 2017, available at 

https://www.sciencedirect.com/science/article/abs/pii/S0301421517300022.

[5] Zhu, Xing, Lanlan Li, Kaile Zhou, Xiaoling Zhang, and Shanlin Yang, “A Meta-Analysis on the Price 

Elasticity and Income Elasticity of Residential Electricity Demand,” Journal of Cleaner Production, Vol. 201, 

November 10, 2018, available at https://www.sciencedirect.com/science/article/abs/pii/S0959652618323588.

Short-Run Elasticities

Source

FOMB Legacy 

Charge 

Derivation

Burke 

Abayasekara 

(2018)

Buchsbaum 

(2022)

Zhu et al. 

(2018)

Labandeira et 

al. (2017)

Geography Puerto Rico Lower 48 California Global Global

Residential -0.36 -0.228 -0.191

Commercial – – -0.212

Industrial – – -0.149

# Elasticity Estimates

(If Applicable) 175 306

Long-Run Elasticities

Source

FOMB Legacy 

Charge 

Derivation

Burke 

Abayasekara 

(2018)

Buchsbaum 

(2022)

Zhu et al. 

(2018)

Labandeira et 

al. (2017)

Geography Puerto Rico Lower 48 California Global Global

Residential -1.7 -1.0 -2.4 -0.577 -0.481

Commercial -0.68 to -1.7 -0.3 to -0.6 – – -0.664

Industrial -0.85 to -1.275 -1.2 – – -0.510

# Elasticity Estimates

(If Applicable) 196 232

-0.2 -0.1

Case:17-03283-LTS Doc#:24392-1 Filed:06/01/23 Entered:06/01/23 21:01:55 Desc:

Exhibit Exhibit A - Expert Report of S. Tierney Page 117 of 117