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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Application of NEVADA POWER COMPANY d/b/a NV Energy and SIERRA PACIFIC POWER COMPANY d/b/a NV Energy, seeking approval to add 1,001 MW of renewable power purchase agreements and 100 MW of energy storage Docket No. 18-06___ capacity, among other items, as part of their joint 2019-2038 integrated resource plan, for the three year Action Plan period 2019-2021, and the Energy Supply Plan period 2019-2021
VOLUME 2 OF 18
TESTIMONY
DESCRIPTION PAGE NUMBER
Application and Exhibits 2
TESTIMONY
Shawn M. Elicegui 82
Terry A. Baxter 113
Joseph R. Brignola 125
Michael Cole 132
Kevin C. Geraghty 143
David Harrison 161
APPLICATION
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
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Application of NEVADA POWER COMPANY ) d/b/a NV Energy and SIERRA PACIFIC POWER COMPANY d/b/a NV Energy, seeking approval to add 1,001 MW of renewable power purchase agreements and 100 MW of energy storage capacity, among other items, as part of their joint 2019-2038 integrated resource plan, for the three year Action Plan period 2019-2021,
) ) ) ) ) )
Docket No. 18-06_____
and the Energy Supply Plan period 2019-2021 /
APPLICATION TO APPROVE TRIENNIAL INTEGRATED RESOURCE PLAN, THREE YEAR ACTION PLAN AND ENERGY SUPPLY PLAN
Nevada Power Company, d/b/a NV Energy (“Nevada Power”) and Sierra Pacific
Power Company d/b/a NV Energy (“Sierra” and together with Nevada Power, the
“Companies”), make this Application, pursuant to Nevada Revised Statute (“NRS”) §
704.741 et seq., and Nevada Administrative Code (“NAC”) § 704.9005 et seq. This
application seeks approval by the Public Utilities Commission of Nevada (“Commission”) of
the Companies’ 2019-2038 first ever joint triennial integrated resource plan (“2018 Joint
IRP”), the plan of action for the three year period 2019-2021 (“Action Plan”), including their
energy supply plan for the three year period 2019-20201 (“2018 ESP”). A triennial IRP must
be processed within 210 days of filing pursuant to NRS § 704.751(1)(b), as amended by
Senate Bill 146 (2017 Legislature), or it is deemed approved as filed. Thus, the “deemed
approved” date for the IRP is December 28, 2018. A triennial ESP must be processed within
135 days of filing pursuant to NRS § 704.751(1)(a). Thus, the “deemed approved” date for
the 2018 ESP is Friday, October 15, 2018.
I. SUMMARY AND INTRODUCTION
The Companies make this 2018 Joint IRP at a time of tremendous uncertainty. Despite
the uncertainty, the 2018 Joint IRP sets forth a real and achievable plan to reliably deliver
more clean energy and service to our customers at low prices. The 2018 Joint IRP
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demonstrates how NV Energy will navigate the substantial risks and uncertainties inherent in
today’s energy business. At the same time, the filing demonstrates sound decision-making
that is good for customers, our communities, our environment, and the state of Nevada.
Customers – residential, commercial and industrial – have been clear that they want
Nevada Power and Sierra to serve them with more renewable energy without impacting the
costs they pay. The Companies are listening and this Joint 2018 IRP delivers. This 2018 Joint
IRP demonstrates just how the Companies intend to maintain the pace of economic growth in
both northern and southern Nevada, rely more on renewable energy, and keep our rates low.
The overarching goal of this 2018 Joint IRP is to meet growth and shrink our exposure to
natural gas prices by delivering more low-cost renewable energy to our customers,
accelerating our transition to a cleaner energy future with near-term investments by our PPA
counterparties to support new Nevada-based renewable energy resources, shoring up our
transmission infrastructure, and increasing our investment in energy efficiency programs.
After analyzing several energy supply portfolios based on price impact, societal cost,
economic development and reliability metrics, the Companies selected the Low Carbon Case
as their Preferred Plan. The Low Carbon Case recommends the addition of six new solar
generating resources, three battery storage systems, and transmission network upgrades
during the Action Plan period. The Low Carbon Case represents an unprecedented, concrete
plan for creating more than $2.175 billion of investment opportunities in progressive, clean
energy resources located in Clark, Humboldt and Washoe counties. The Low Carbon Case
also advances the retirement of the last of the Companies’ coal fleet, located in northern
Nevada, in a responsible and prudent manner. The Low Carbon Case represents a low-cost,
least-risk, and flexible blueprint for meeting customer energy needs. Nevada Power and Sierra
therefore ask that the Commission accept the Low Carbon Case as the Preferred Plan, and
authorize them to take all necessary steps during the Action Plan period to implement the Low
Carbon Case, if voters do not approve Question 3 in November.
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II. THE APPLICANTS
Nevada Power and Sierra are Nevada corporations and wholly-owned subsidiaries of
NV Energy, Inc. Nevada Power and Sierra are public utilities as defined in NRS § 704.020,
and are subject to the jurisdiction of the Commission. Nevada Power is engaged in providing
electric service to the public in portions of Clark and Nye counties, Nevada pursuant to a
certificate of public convenience and necessity issued by this Commission. Sierra provides
electric service to the public in portions of fourteen northern Nevada counties, including the
communities of Carson City, Minden, Gardnerville, Reno, Sparks, and Elko. Sierra owns and
operates a certificated local distribution company engaged in the retail sale of natural gas to
customers in the Reno-Sparks metropolitan area.
Sierra’s primary business office is located at 6100 Neil Road in Reno, Nevada and
Nevada Power’s primary business office is located at 6226 West Sahara Avenue in Las Vegas,
Nevada. All correspondence related to this Application should be transmitted to the
Companies’ counsel and to the Manager of Regulatory Services, as set forth below:
Elizabeth Elliot LoreLei Reid Deputy General Counsel Manager, Regulatory Services 6100 Neil Road 6100 Neil Road Reno, NV 89511 Reno, NV 89511 775-834-5694 775-834-5823 [email protected] [email protected]
III. APPLICATION EXHIBITS
Included with this Application and incorporated herein by reference are the following
exhibits:
• Application Exhibit A is the three-year Action Plan for the period January 1,
2019 through December 31, 2021. This exhibit is required by NAC § 704.9489.
• Application Exhibit B is a roadmap of applicable statutes and regulations and the
location of the required information in the filing. This exhibit is not described in
or mandated by the Commission’s IRP regulations or prior IRP orders, but is
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provided to assist those performing an evaluation of the technical aspects of the
filing.
• Application Exhibit C, is a proposed notice of the Application as required by
NAC § 703.162.
In addition, as required by NAC § 704.9215, the 2018 Joint IRP contains a small, stand-alone
Summary Volume. Section I of that document contains a short, executive summary of the
2018 Joint IRP. The remainder of the Summary Volume addresses each of the items required
by NAC § 704.925, is written in plain English, and includes easily interpretable tables, graphs
and maps. An additional copy of the Action Plan is attached to the Summary Volume for easy
reference.
IV. SUPPORTING MATERIAL
Section 704.9321 of the NAC provides that a utility’s resource plan must be based on
substantially accurate data, adequately demonstrated and defended, and adequately
documented and defended. As is set forth below, included in this 2018 Joint IRP and
incorporated herein by reference, the reader will find all material required to adequately
demonstrate and defend the substantially accurate data supporting the analysis and the
requests for affirmative relief set forth herein. A summary of this information, which includes
narrative, technical appendices,1 and supporting prepared direct testimony,2 is set forth by
general topic below.
A. Consistency of Resource Plan with Companies’ Strategic Objectives.
Included the Action Plan, the Summary Volume and Supply Side narrative are discussions of
1 NAC § 704.922 requires that a utility’s resource plan include technical appendices that contain sufficient detail to enable a technically proficient reader to understand how the resource plan and its forecasts were prepared and to evaluate the validity of the assumptions and the accuracy of the data used, including, without limitation, a list of the major assumptions used, a description of the forecasting methods employed and a description of the software utilized. 2 NAC § 704.9321(4) requires that all testimony offered in support of a utility’s resource plan be filed with the resource plan.
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the consistency between the 2018 Joint IRP, especially the Preferred Plan, and the
Companies’ strategic objectives. These discussions, as well as recommendations for an
alternative plan should Question 3 succeed in the November 2018 elect, are supported by the
prepared direct testimony of Shawn M. Elicegui, Senior Vice President of Business Planning,
Regulative and Legislative Strategy.
B. Load, Fuel and Purchased Power Forecasts. The first narrative in the 2018
Joint IRP filing addresses load forecasts, includes a comprehensive discussion of market
fundamentals that impact long-term fuel and purchased power pricing, and describes and
supports the long-term price forecasts for fuel and purchased power that underlie the analysis
in the 2018 Joint IRP.
1. Load Forecasting. The narrative addressing the load forecast is supported by
the prepared direct testimony of Mr. Terry A. Baxter, Manager of Load Forecasting, as well
as the following technical appendices:
• LF-1 - 2019-2048 Load Forecast (Confidential)
• LF-2 - Population Forecasts: Long-Term Projections for Clark County, Nevada
2016-2050, May, 2017
• LF-3 - State Demographer 2017 Population Forecasts
• LF-4 - Nevada State Demographer Intercensal Population Estimates
• LF-5 - Population of Nevada’s Counties and Incorporated Cities 2000-2017
• LF-6 - Las Vegas Convention and Visitors Year to Date October executive
summary for 2017
• LF-7 - ADM Report on Energy Intensity Development
2. Fuel and Purchased Power Forecasting. The narrative addressing the fuel
and purchased power forecasts is supported by the prepared direct testimony of Mr. Marc D.
Reyes, Director of Resource Planning and Analysis, and Mr. Joseph R. Brignola, Manager,
Coal Operations and Procurement, as well as the following technical appendices:
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• FPP-1 - CPP Cases (Redacted)
C. Demand-Side Resources. The second narrative in the 2018 Joint IRP
addresses the Companies’ demand-side management (“DSM”) and planning processes, the
performance of the Companies’ 2017 DSM programs, as well and their current and proposed
portfolio of demand-side resources and programs. The narrative addressing demand-side
resources is supported by the following technical appendices.3
• DSM-1 - Portfolio Pro Model
• DSM-2 - Lost Revenue Annual Multiplier
• DSM-3 - DSM Collaborative
• DSM-4 - M&V Process
• DSM-5 - M&V Energy Education - NPC
• DSM-6 - M&V Energy Education –SPPC
• DSM-7 - M&V Energy Reports – NPC
• DSM-8 - M&V Energy Reports - SPPC
• DSM-9 - M&V Energy Assessments – NPC
• DSM-10 - M&V Energy Assessments – SPPC
• DSM-11 - M&V Direct Install-NPC
• DSM-12 - M&V Residential Air Conditioning – NPC
• DSM-13 - M&V Demand Response – Residential - NPC
• DSM-14 - M&V Demand Response – Residential - SPPC
• DSM-15 - M&V Schools – NPC
• DSM-16 - M&V Schools – SPPC
• DSM-17 - M&V Commercial Energy Services – NPC
• DSM-18 - M&V Commercial Energy Services – SPPC
3 In addition, consistent with the Companies’ commitment in prior DSM plan proceedings, a set of electronic workpapers supporting the analysis and selection of the programs and measures discussed in the narrative have been developed. The electronic workpapers are not a part of the filing, but have been provided to the Commission’s Regulatory Operations Staff (“Staff”) and the Bureau of Consumer Protection (“BCP”).
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• DSM-19 - M&V Demand Response - Commercial – NPC
• DSM-20 - M&V Demand Response - Commercial – SPPC
• DSM-21 - Market Potential Study
• DSM-22 - Net to Gross Ratios
The demand-side resources narrative and the technical appendices supporting the
narrative, are sponsored by the prepared direct testimony of the following demand-side
planning, implementation and evaluation experts:
Ms. Anita L. Hart, Director, Demand Side Management, sponsors all portions of the
DSM plan not sponsored or supported by witnesses Mr. Robert Oliver and Ms. Ingrid
Rohmund as well as DSM Technical Appendices DSM-1 through DSM-4, and DSM-22. Mr.
Robert Oliver, Director/Project Manager for ADM Associates, Inc., sponsors the
measurement and verification reports contained in Technical Appendix Items DSM-5 through
DSM-20. Ms. Ingrid Rohmund, Senior Vice President for Applied Energy Group, Inc.,
sponsors the DSM Market Potential Study contained in Technical Appendix DSM-21.
D. Supply-Side Resources. The third narrative in the 2018 Joint IRP filing
addresses the Companies’ Supply-Side Plan (including the generation, renewable energy, the
transmission and distribution plans). Each element of the Supply-Side Plan is addressed in
turn below:
1. Conventional Generation, Power Purchase Agreements and Fuel Supply. These
portions of the Supply-Side Plan are found in Sections 2.A. (Generation), 2.B (Long-Term
Purchased Power Agreements (“PPAs”)), and 2.C (Fuel Supply) of the Supply-Side narrative,
and are supported by the following technical appendices:
• GEN-1 - Unit Characteristics Table (Confidential)
• GEN-2 - New Generation Unit Performance Data (Confidential)
• GEN-3 - 2017 Plant Emission Rates (Confidential)
• GEN-4(a) - Clark Peaker Unit 4 Life Span Analysis Plan (“LSAP”)
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• GEN-4(b) - Clark Mountain 4 LSAP
• GEN-4(c) - Fort Churchill 1 LSAP
• GEN-4(d) - Harry Allen 3 LSAP
• GEN-5(e) - Sun Peak 3-5 LSAP
The Conventional Generation, PPA and Fuel Supply sections of the Supply-Side Plan
narrative, as well as the technical appendices supporting these narrative sections, are
sponsored by the prepared direct testimony of the following supply-side resource planning
and implementation experts.
Mr. Kevin Geraghty, Senior Vice President, Operations, sponsors the Supply-Side
Plan narrative sections for Generation and discusses the Companies’ requests for changes to
the retirement dates for several generating units. Mr. Geraghty also supports the conditional
early retirement of North Valmy Unit 1 (from December 31, 2025 to December 31, 2021) and
the request to create a regulatory asset if North Valmy Unit 1 is retired on December 31, 2021.
Ms. Patricia Rodriguez, Manager, Gas Transportation Planning, supports the Current
Physical Gas Supply, Physical Gas Procurement, and Current Oil Supply discussions in the
Fuel Supply section of the Supply-Side plan.
2. Current Renewable Portfolio, Compliance with Renewable Portfolio Plan and
New Renewable Resources. These portions of the Supply-Side Plan are found in Section 2.D.
(Renewable Energy Plan) of the Supply-Side Plan narrative. This section of the narrative is
supported by the following technical appendices:
• REN-1 - 2018 Renewable RFP, Top Projects PPA 12x24 Supply Tables
• REN-2 - 2018 IRP Generic Placeholder 12x24 Supply Table
• REN-3 - 2018 IRP Generic Placeholder Pricing (Confidential)
• REN-4 - 2018 IRP All Renewable and market Cases
• REN-5 - 2018 Renewable RFP Protocol with Attachments
• REN-6-DFS(a) - Long-Term Renewable PPA for Dodge Flat Solar, LLC
(Redacted)
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• REN-6-DFS(b) - Dodge Flat Solar Renewable Portfolio Standard (“RPS”
Regulation Roadmap
• REN-6-FSR(a) - Long-Term Renewable PPA for Fish Springs Ranch Solar, LLC
(Redacted)
• REN-6-FSR(b) - Fish Springs Ranch RPS Regulation Roadmap
• REN-6-BMS(a) - Long-Term Renewable PPA for Battle Mountain Solar SP, LLC
• REN-6-BMS(b) - Battle Mountain Solar RPS Regulation Roadmap
• REN-6-ESM(a) - Long-Term Renewable PPA for 325MK 8ME, LLC
• REN-6-ESM(b) - 8minutenergy RPS Regulation Roadmap
• REN-6-CMS5(a) - Long-Term Renewable PPA for Copper Mountain Solar 5,
LLC
• REN-6-CMS5(b) - Copper Mountain Solar 5 RPS Regulation Roadmap
• REN-6-TS5(a) - Long-Term Renewable PPA for Techren Solar V LLC
• REN-6-TS5(b) - Techren Solar V RPS Regulation Roadmap
• REN-7 - RFP Initial Short List Scoring Report (Confidential)
• REN-8 - Final Due Diligence and Selection Reports (Confidential)
• REN-9 - 2018 Renewable RFP Report of the IE or Independent Evaluator
(Confidential)
The Renewable Energy Plan section of the Supply-Side narrative and the technical
appendices supporting this narrative section are sponsored by the prepared direct testimony
of Mr. David Ulozas, Senior Vice President, Renewable Energy and Origination. Mr. Ulozas
supports both near-term outlook and long-term planning to meet Nevada’s RPS. He also
sponsors and supports the processes followed and results of the 2018 Renewable RFP,
including the request for approval of six PPAs for 1,001 MW of new renewable resources, as
well as 100 MW of co-located battery storage capacity.
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3. Transmission Plan. This portion of the Supply-Side Plan is found in Section 2.E
(Transmission Plan) of the Supply-Side Plan. The following technical appendices support this
section of the narrative:
• TRAN-1 - Timing of New Transmission Sources for Northern Nevada
(Confidential)
• TRAN-2 - Dodge Flat Solar Large Generator Interconnection Agreement
(“LGIA”)
• TRAN-3 - Fish Springs Ranch Solar Facilities Solar
• TRAN-4 - Battle Mountain Solar LGIA
• TRAN-5 - Eagle Shadow Mountain Solar Farm System Impact Study
• TRAN-6 - Copper Mountain Solar 5 Facilities Study
• TRAN-7 - Techren Solar 5 LGIA
• TRAN-8 - Arden to McDonald 230 kV Line Upgrade
• TRAN-9 - Renewable Energy Zone Transmission Plan
The Transmission Plan narrative, as well as the technical appendices supporting the
narrative, are sponsored by the prepared direct testimony of Mr. Sachin Verma, Director,
Transmission System Planning.
4. Distribution Plan. This portion of the Supply Side Plan is found in Section 2.F of
the Supply Side Plan narrative and is sponsored by the prepared direct testimony of Mr.
Joseph Sinobio, Manager, Major Projects – Delivery.
E. Economic Analysis. The Economic Analysis narrative follows the Supply-
Side narrative and discusses the methodologies and analytical tools used to perform the
integrated economic analysis that underlies the Companies’ selection of the Preferred Plan
and Alternative Plan. This section also describes the calculation of environmental
externalities for the Preferred and Alternative Plans. The economic analysis narrative is
supported by the following technical appendices:
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• ECON-1 - Notice of Public Meeting and Overview of the 2018 IRP
• ECON-2 - Description of Production Modeling Software
• ECON-3 - Average Generation Costs (Confidential)
• ECON-4 - Energy Mix for All Cases
• ECON-5 - Marginal Energy Costs (Confidential)
• ECON-6 - Loads and Resources Tables
• ECON-7 - Capital Projects (all cases and sensitivities) (Confidential)
• ECON-8 - PWRR (Production + Capital Costs)
• ECON-9 - Operating Reserves Calculation
• ECON-10 - PROMOD Area Diagram
• ECON-11 - Solar PV Capacity Study
• ECON-12 - NERA Report
The Economic Analysis narrative, as well as the technical appendices supporting the
narrative, are sponsored in the prepared direct testimony of Mr. Marc D. Reyes, introduced
above, as well as Dr. David Harrison, Jr., economist and Senior Vice President at NERA
Economic Consulting. Dr. Harrison sponsors the discussion and analysis of environmental
externalities contained in the Economic Analysis discussion, as well as Technical Appendix
item ECON-12. All other material in the Economic Analysis discussion is sponsored by Mr.
Reyes.
F. Financial Plan. The 2018 Joint IRP narrative closes with a discussion of the
Financial Plan, and follows the Economic Analysis narrative. This section of the narrative
discusses the methodologies and analytical tools used to evaluate the impact of the Preferred
Plan and Alternative plans on the Companies’ financial metrics. Mr. Michael Cole,
Treasurer, sponsors the financial narrative of the IRP.
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G. Energy Supply Plan. The 2018 Joint IRP includes an Energy Supply Plan.
Because the IRP statute requires that an ESP be processed in 135 days, while the full IRP is
to be processed in 210 days, the Companies have segregated the ESP narrative, testimony and
technical appendices into stand-alone volumes filed as part of the 2018 Joint IRP. Together
the 2018 ESP narrative, prepared direct testimony and technical appendices provide the
Companies’ recommended power procurement plans, fuel procurement plans, and risk
management strategies based on current market conditions during the 2018 ESP period. The
2018 ESP narrative is supported by the following technical appendices and prepared direct
testimony.
1. Policy including Prudence Determinations and Compliance with Prior
Commission Directives. Mr. Marc D. Reyes, introduced above, is the overall policy witness
for the 2018 ESP and sponsors Sections 2.B (Capacity Requirements), 2.C (Energy
Requirements), 3.A (Power Fundamentals), 3.B (Natural Gas Fundamentals), 3.D.1 (Natural
Gas Price Forecast), 3.D.2 (Power Price Forecast), 4 (Power Procurement Plan), 5.C
(Recommend Gas Hedging Plan), 8 (Determination of Prudence), 9 (Commission Directives)
of the ESP narrative and Technical Appendix Items ECON-1, FPP-1 and GAS-1.
2. Load Forecasting. Terry Baxter, introduced above, sponsors the 2018 ESP
load forecast ESP. The Technical Appendix items LF-1 through LF-7 are identical as between
the ESP and IRP, and thus are included only once, with the 2016 Joint IRP.
3. Fuel and Purchased Power Forecasting. Mr. Reyes and Mr. Joseph R.
Brignola, both introduced above, sponsor the market fundamentals narrative accompanying
the ESP, as well as the following Technical Appendix:
• FPP-1 - Fuel and Purchased Power Price Forecasts (Confidential)4
4. Power Procurement Plan. Mr. Reyes, and Mr. David Ulozas, both of whom
have been introduced above, as well as Ms. Elena P. Mello, Manager, Revenue Requirements
4 The fuel and purchased power price forecast for the ESP period from 2019 through 2021 is identical to the IRP forecast contained in IRP Technical Appendix FPP-1
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& FERC, and Mr. Vernon Taylor, Director, Market Analytics, sponsor portions of the
power procurement plan, as well as the following Technical Appendices:
• POWER-1 - Forward Power Sales Procedures Manual (Confidential)
• GAS-1 - Gas Hedge Strategies Simulation
• GAS-2 - Summary of Actual and Forecasted BTERs and DEAAs
5. Fuel Procurement Plan. Mr. Reyes and Ms. Patricia Rodriguez, both of
whom have been introduced above, sponsor the fuel procurement plan. In addition, Ms.
Rodriguez sponsors the following Technical Appendix:
• GAS-3 - Gas Hedging Workshop Presentations (Confidential)
6. Economic Analysis. Mr. Reyes, introduced above, sponsors Economic
Analysis discussion in the ESP and the following Technical Appendix item:
• ECON-1 - PROMOD Results (Confidential)
7. Risk Management Strategy. Mr. Cole, introduced above, sponsors the
narrative addressing the Companies’ risk management strategies, policies and processes, as
well as the following Technical Appendices:
• RM-1 - Risk Management and Control Policy
• RM-2 - Energy Risk Management and Control Policy
• RM-3 - Credit Risk Management and Control Policy
V. CONFIDENTIALITY
Certain information set forth in the narratives and Technical Appendices is
commercially confidential and/or trade secret information subject to protection pursuant to
NRS § 703.190. Specifically, the confidential information in this filing, along with the basis
for the assertion of confidentiality, is set forth below.
Load Forecasts. The Companies have prepared comprehensive load forecasts for the
2018 Joint IRP and the 2018 ESP. Certain information in the narratives and Technical
Appendix item LF-1 in both the 2018 Joint IRP and 2018 ESP are confidential because they
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contain usage of discrete and specific customers. This information cannot be made public
without the consent of the customers identified and qualifies for confidential treatment under
NRS § 703.190.
Fuel and Purchased Power Price Forecasts. The Companies have prepared price
forecasts for natural gas, coal and purchased power for the 2018 Joint IRP and the 2018 ESP.
The following figures in the market fundamentals narrative in the 2018 Joint IRP are
confidential and have been redacted in the public version of the filing.
• Figure PF-2 - Annual Average Gas Price Forecast
• Figure PF-3 - Average Market Implied Heat Rate Forecast - Southern Nevada
• Figure PF-4 - Average Market Implied Heat Rate Forecast - Northern Nevada
• Figure PF-5 - Average Annual Price Forecast - Mead
• Figure PF-6 - Average Annual Price Forecast - Northern Nevada
• Figure PF-7 - Average Annual Price Forecast - Southern California
• Figure PF-8 - Base, High and Low Gas Price Forecast - Malin
• Figure PF-9 - Base, High and Low Gas Price Forecast - Mead
• Figure PF-10 - Base, High, Low Power Price Forecast - Northern Nevada
• Figure PF-11 - WoodMac Long-term Outlook Reserve Margins for Desert
Southwest, Northwest Power Pool, and Mead
• Figure PF-12 - Projected Coal Prices
In addition, in the 2018 Joint IRP, Technical Appendix item FPP-1 provides additional
confidential fuel price information.
In the 2018 ESP narrative, Figure ESP-33 sets forth the coal price forecast and
Technical Appendix FPP-1 contains confidential fuel price information.
Fuel and purchased price forecasts qualify for confidential treatment under NRS §
703.190. They derive independent economic value from not being generally known and
disclose the Companies’ views and expectations of the relevant markets. This information is
not known outside the Companies and its distribution is limited within the Companies.
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Releasing this highly sensitive information would disadvantage the Companies by limiting
their ability to foster competition among prospective suppliers, compromising the
Companies’ negotiating position and reducing its bargaining leverage. Publication of this
information would unfairly advantage competing coal buyers and impair the Companies’
ability to achieve the most favorable pricing and terms and conditions from suppliers on
behalf of its customers.
Gas Premiums. Portions of the Companies’ Physical Gas Procurement plan in the
2018 ESP contain the premiums that the Companies may be willing to pay for physical gas
supplies. Similarly, portions of Technical Appendix item GAS-3 Gas Hedging Workshops
contain the same premiums for physical gas supplies. This confidential information is
commercially sensitive and/or trade secret information that derives independent economic
value from not being generally known. Disclosure of this confidential information to any third
party would adversely affect The Companies’ ability to obtain favorable terms from its gas
suppliers.
Operational Data. A comprehensive IRP analysis necessarily relies on confidential
information regarding the performance characteristics of the Companies’ generating fleet. In
the 2018 Joint IRP, the following Technical Appendix items are provided in redacted form in
the public version of the filing.
• GEN-1 - Unit Characteristics Table
• GEN-2 - New Generation Unit Performance Data
• GEN-3 - 2017 Plant Emission Rates
• ECON-3 - Average Generation Costs
• ECON-5 - Hourly Marginal Costs
• ECON-7 - Capital Projects
Similar information is included in POWER-1 and ECON-1 in the 2018 ESP.
Generation unit characteristics and similar operational data qualify for confidential
treatment under NRS § 703.190. The information in these Technical Appendices derive
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independent economic value from not being generally known. This information discloses the
Companies’ views and expectations of the relevant markets and its future procurement
opportunities. This information is not known outside the Companies and its distribution is
limited within the Companies. Releasing this highly sensitive information would
disadvantage the Companies by limiting their ability to foster competition among prospective
energy suppliers and buyers; compromising the Companies negotiating positions and
reducing their bargaining leverage. Publication of this information would unfairly advantage
competing market participants and impair the Companies’ ability to achieve the most
favorable pricing and terms and conditions from suppliers on behalf of its customers.
Transmission Infrastructure. In the 2018 Joint IRP, the Companies have prepared
a comprehensive transmission plan to address system requirements to address Sierra’s load
growth. Technical Appendix TRAN-1 contains customer specific load information that is
included in the study and qualifies as for confidential treatment under NRS § 703.190.
Forecasted Financial Data. A comprehensive IRP analysis necessarily relies on
confidential information regarding the impact of the Preferred Plan on the Companies’
financial performance. That information is discussed in the narrative of the Financial Plan.
The following figures in the Financial Plan narrative are confidential and have been redacted
in the public version of the filing.
• Figure FP-3 - Nevada Power Summary of External Debt Financing
• Figure FP-4 - Sierra Summary of External Debt Financing
• Figure FP-11 - Nevada Power Funds from Operations to Total Debt
• Figure FP-12 - Nevada Power EBITDA Interest Coverage
• Figure FP-13 - Nevada Power Total Debt to Total Capital
• Figure FP-14 - Nevada Power Cash from Operations to CAPEX
• Figure FP-15 - Sierra Funds from Operations to Total Debt
• Figure FP-16 - Sierra EBITDA Interest Coverage
• Figure FP-17 - Sierra Total Debt to Total Capital
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• Figure FP-18 - Sierra Cash from Operations to CAPEX
The financial analysis accompanying the 2018 Joint IRP qualifies for confidential
treatment under NRS § 703.190. It derives independent economic value from not being
generally known and discloses the Companies’ views and expectations of the relevant
markets. This information is not known outside the Companies and its distribution is limited
within the Companies. Moreover, the financial analysis contains non-public financial data.
Renewable Projects. A comprehensive IRP analysis necessarily relies on
confidential information regarding renewable projects and pricing. That information is
discussed in the following Technical Appendix items:
• REN-3 - 2018 IRP Generic Placeholder Pricing
• REN-6-DFS(a) - Long-Term Renewable PPA for Dodge Flat Solar, LLC;5
• REN-6-FSR(a) - Long-Term Renewable PPA for Fish Springs Ranch Solar, LLC;
• REN-7 - RFP Initial Short List Scoring Report
• REN-8 - Final Due Diligence and Selection Reports
• REN-9 - 2018 Renewable RFP Report of the IE or Independent Evaluator
REN-3 contains the Companies’ internal views, expectations and analysis of the
renewable energy market and costs. Confidential Technical Appendix Items REN-7 and
REN-8 contains the initial short list of bidders, along with the pricing and scoring results for
each of the bids submitted under the 2018 Renewable RFP. Exhibits 21 in the PPAs for the
Dodge Flat and Fish Springs projects (REN-6-DFS(a) REN-6-FSR(a)) set forth the site plans
for these two projects, which the developer has requested remain confidential in order to
protect its own commercially confidential and trade secret information. REN-8 contains the
due diligence reports from subject matter experts. All of these appendices are confidential
because they derive independent value to the Companies and would hinder the Companies
abilities from negotiating the best economic terms for its customers if the information was
publically disclosed.
5 Only Exhibit 21 to the two NextEra PPAs, REN-6-DFS(a) and REN-6-FSR(a) are confidential.
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Pursuant to NAC § 703.5274(1), one unredacted copy of the confidential information
will be filed with the Commission’s Secretary in a separate envelope stamped “confidential.”
Redacted versions of confidential information will be submitted for processing and posting
onto the Commission’s public website.
Pursuant to NAC § 703.5274(2), the Companies hereby request that the above-
described information not be disclosed to the public. The Companies request that this
information remain confidential for a period of five years.
Confidential treatment of the above-described information will not impair the ability
the Staff or the BCP to fully investigate the Companies’ proposals. Pursuant to NAC §
703.527 and § 703.5274, Staff and BCP have already have executed a protective agreement
for this case and will be immediately provided unredacted copies of the filing.
VI. REQUEST FOR DEVIATION FROM REGULATION
NAC § 704.0097 provides that the Commission may allow deviation from any
provision of NAC Section 704 if:
(1) Good cause for the deviation appears;
(2) The person requesting the deviation provides a specific reference to each provision
of the chapter from which the deviation is requested; and
(3) The Commission finds that the deviation is in the public interest and is not contrary
to statute.
NAC § 704.9492 requires that in its triennial IRP filing, the utility must propose a
methodology and calculate and file its long-term avoided costs (“LTAC”) and preliminary
LTAC rates that reflect the utility’s Preferred Plan. These calculations are set forth in Section
3.I in the Supply Side Plan narrative, and form the basis of a preliminary administratively
determined LTAC and LTAC rates.
Under NAC § 704.9496, the Commission must specifically address in its IRP order
the utility’s proposed estimated rates for LTAC, including the methodology and limits to be
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used going forward. Next, the regulation requires that within 60 days of the final
determination in the utility’s IRP, the utility must recalculate and refile LTAC that reflect the
plan of action ultimately adopted by the Commission. NAC § 704.9496(2). Unless otherwise
ordered by the Commission in its final determination regarding the utility’s IRP, the
recalculated rates reflecting LTAC also will reflect the same terms and be in the same format
as the estimated rates originally filed by the utility in its IRP. NAC §704.9496(3).
The process contemplates that the recalculated administratively determined estimate
of LTAC and LTAC rates, along with the limits proposed by the utility, may be disputed.
NAC § 704.9496(4) provides that “if required,” within 90 days of the filing of the recalculated
estimated LTAC and LTAC rates, the Commission will hold a hearing to approve the
administratively determined LTAC rates and the limits of capacity or energy or both that
should be made available to be filled by QFs at the utility’s LTAC. The Commission has 45
days after the hearing on the administratively determined estimate of LTAC and LTAC rates
to issue an order on the matter.
Within 30 days of the issuance of the subsequent order, the utility must solicit
proposals to provide the utility capacity or energy or both, consistent with the Commission-
approved methodology for estimating long-term avoided costs. NAC § 704.9496(5). Within
90 days of issuing this solicitation, the utility must file a report with the Commission
summarizing the results of the solicitation. NAC § 704.9496(6).
Finally, NAC § 704.9496(7) provides that the utility’s LTAC rate for each block of
capacity authorized to be filled by QFs is the lower of the administratively determined
estimate of the utility’s LTAC and LTAC rate, or the competitive rate solicited.
The Companies’ request to deviate from the requirements of NAC § 704.9496 and to
instead establish the Companies’ LTAC rates in a single step, using the current pricing from
the highest cost 50 MW bid selected in the recent 2018 Renewable RFP (the Techren V
project) to cap the Companies’ administratively determined long-term avoided cost. This
long-term avoided cost rate would be made available for up to 50 MW (nameplate, AC) of
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renewable resource for contracts up to 25 years, provided that, if Ballot Question 3 is
successful in November 2018, the contract term would not extend beyond 2023. The
Companies’ request to deviate is in the public interest because it produces regulatory
efficiency and eliminates undue costs and of issuing a new RFP.
VII. PRAYER
WHEREFORE, the Companies requests that the Commission:
(1) Accept the Action Plan as it is set forth in Exhibit A to this Application which
includes the following items:
a) Regarding the 2018 Joint IRP, approval of the long-term base load forecast
presented in the Load Forecast and Market Fundamentals volume of this filing
as being the most accurate information upon which to base long-term planning
decisions through the Action Plan period;
b) Regarding the 2018 ESP, approval of the three-year base load forecast
presented in the 2018 ESP as being the most accurate information upon which
to base near-term planning decisions through the Action Plan period;
c) Regarding the 2018 Joint IRP, approval of the base long-term fuel and
purchased power price forecasts presented in FPP-1 as presenting the best and
most accurate information upon which to base long-term planning decisions
through the Action Plan period;
d) Regarding the 2018 ESP, approval of the base three-year fuel and purchased
power price forecasts presented in the 2018 ESP as presenting the best and
most accurate information upon which to base near-term planning decisions
through the Action Plan period;
e) Approval of the Companies’ Preferred Plan, which does not include the
acquisition or construction by the Companies of new generation resources;
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f) Assuming that Ballot Question 3 is not successful in the November 2018
election, approval of the early (December 31, 2021) retirement of North
Valmy Unit 1, conditioned on the following:
i. The PPAs for the output of the three new northern Nevada renewable
energy projects and stationary storage projects included in Low Carbon
Case must be approved by the Commission and then must demonstrate
sufficient development progress to ensure commercial operation
before June 2022; and
ii. NV Energy must have adequate capacity to serve customer load, which
will be determined using, at a minimum,6 the following metrics:
• “Loss of Load Probability.” For any given hour, an increase
in the LOLP by more than 100 percent would trigger the
reevaluation of the North Valmy Unit 1 retirement, and
• “Expected Unserved Energy.” Any megawatt-hour increase
in expected unserved energy under the North Valmy Unit 1
retirement scenario would trigger a reevaluation of the
retirement, and
• “Loss of Load Expectation.” This metric does not exceed the
one day in 10 year criterion;
iii. Conditions in the western energy markets must be such that NV Energy
has sufficient access to economic energy and capacity to mitigate the
cost pressure and reduction in flexibility associated with having power
available from North Valmy Unit 1. This condition will be measured
through production cost modeling; an increase in the Base Tariff
6 Because real –time system reliability is paramount, additional analysis similar to that developed by the CAISO may be used by NV Energy to assess real-time reliability risk.
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Energy Rates by more than $0.00250 per kilowatt-hour versus the non-
retirement scenario will trigger reevaluation of the decision; and
iv. Transmission area load of 2,800 MW will trigger a re-evaluation and,
possibly, delay of the retirement of North Valmy Unit 1; and
v. Approval of the request, made consistent with the tracking and
accounting systems put in place at the Companies’ other retired
generating facilities, the costs of decommissioning the North Valmy
Generating Station, including those incurred to isolate and make safe
North Valmy Unit 1, will be tracked and placed into a regulatory asset,
and a carrying charge equal to Sierra’s currently approved cost of
capital would be applied. Upon completion of decommissioning, the
balance in the regulatory asset will be placed into rate base. Sierra will
apply in a future proceeding to collect the balance over an appropriate
amortization period; and
vi. Approval of the request, also made consistent with the tracking
accounting treatment authorized in prior dockets, upon its retirement,
the undepreciated book value of North Valmy Unit 1 will be placed
into a regulatory asset where it would not earn a carrying charge.
Instead, until it is included in Sierra’s revenue requirement, Sierra will
amortize the regulatory asset balance using the depreciation rate for
North Valmy Unit 1 at the time of its retirement. When the balance in
the regulatory asset is included in revenue requirement, it will be
placed into rate base. Sierra will apply in a future proceeding to collect
the balance over an appropriate amortization period;
g) Assuming that Ballot Question 3 is not successful in the November 2018
election, approval of 1,001 MW of renewable PPAs, which will be provided
from six new solar PV projects, three of which located in Sierra’s service
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territory, and three of which are located in Nevada Power’s service territory.
Battery storage capacity is being co-located at the three projects located in
Sierra’s service territory. Each PPA is described briefly below:
i. Sierra’s PPA with NextEra’s Dodge Flat Solar, LLC for 200 MW
(nameplate, AC) of solar PV generation, with an additional 50 MW of
capacity from a co-located Battery Storage system. The expected
Commercial Operation Date is December 1, 2021;
ii. Sierra’s PPA with NextEra’s Fish Springs Ranch Solar, LLC for 100
MW (nameplate, AC) solar PV generation, with an additional 25 MW
of capacity from a co-located Battery Storage system. The expected
Commercial Operation Date is December 1, 2021;
iii. Sierra’s PPA with CCR’s Battle Mountain Solar SP, LLC for 101 MW
(nameplate, AC) solar PV generation, with an associated 25 MW of
capacity from a co-located Battery Storage system. The expected
Commercial Operation Date is June 1, 2021;
iv. Nevada Power’s PPA with 8minutenergy’s 325MK 8ME, LLC for 300
MW (nameplate, AC) of solar PV generation from the Eagle Shadow
Mountain Solar Farm, with an expected Commercial Operation Date
of December 31, 2021;
v. Nevada Power’s PPA with Sempra’s Copper Mountain Solar 5, LLC
for 250 MW (nameplate, AC) of solar PV generation, with an expected
Commercial Operation Date of December 31, 2021;
vi. Nevada Power’s PPA with 174 Power Global’s Techren Solar V, LLC
for 50 MW (nameplate, AC) of solar PV generation, with an expected
Commercial Operation Date of December 31, 2020;
h) Assuming that Ballot Question 3 is successful in the November 2018 election,
approval of the lowest cost PPA among the six listed above, Nevada Power’s
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PPA with 8minutenergy’s 325MK 8ME, LLC, as well as the assignment of
the PPA to Sierra;
i) Assuming that Ballot Question 3 is not successful in the November 2018
election, the Companies seek approval to construct the network upgrades
necessary to interconnect the six renewable energy projects identified above
to the Companies’ transmission system. Network upgrades will be necessary
to complete the interconnection of the following four projects:
• Dodge Flat Solar $12.565 million, and
• Fish Springs Ranch $2.38 million, and
• Eagle Shadow Mountain Solar Farm $550,000, and
• Copper Mountain 5 $7.44 million;
j) Approval to reconductor a 1.45 mile segment of Arden to McDonald 230 kV
transmission line. This upgrade project is necessary to mitigate a potential
NERC TPL-001-4 violation identified as a result of the previously approved
McDonald 230/138 kV Substation Upgrade project, and is budgeted to cost of
$720,000;
k) Approval to continue the Companies’ involvement and membership in
WestConnect. The Action Plan budget to continue membership is $225,000
annually in 2019, 2020, and 2021 for a total of $675,000;
l) Regarding the 2018 Joint IRP, approval of the DSM Plans as part of the
Companies’ Action Plan. The Companies are requesting specific acceptance of
the budgets and energy savings for the DSM Plans for the 2019-2021 Action
Plan period: Nevada Power $49.8 million, $50.2 million, and $50.6 million in
2019, 2020, and 2021 respectively; Sierra $14.8 million, $15.5 million, and
16.1 million in 2019, 2020, and 2021 respectively; and NV Energy combined
$64.6 million, $65.7 million, and 66.7 million in 2019, 2020, and 2021
respectively;
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m) The Companies also request that the Commission review and approve the M&V
reports for program year 2017 provided in Technical Appendix DSM-5 through
DSM-20 for the DSM programs delivered in the 2017 program year;
n) Regarding the 2018 ESP, acceptance and approval of the power procurement
plan and an affirmative finding, consistent with NAC § 704.9494(3), that the
power procurement strategy is prudent;
o) Regarding the 2018 ESP, acceptance and approval of the physical gas
procurement plan and an affirmative finding, consistent with NAC §
704.9494(3), that the physical gas procurement strategy is prudent;
p) Regarding the 2018 ESP, acceptance and approval of its gas transportation
plan, and an affirmative finding, consistent with NAC § 704.9494(3), that the
gas transportation strategy is prudent;
q) Regarding the 2018 ESP, acceptance and approval of its gas hedging plan, and
an affirmative finding, consistent with NAC § 704.9494(3), that the gas
hedging plan is prudent;
r) Regarding the 2018 ESP, acceptance and approval of the coal procurement
plan, and an affirmative finding consistent with NAC § 704.9494(3) that its
coal procurement strategy is prudent;
s) Regarding the 2018 ESP, acceptance an approval of the risk management
strategy, and an affirmative finding consistent with NAC § 704.9494(3) that
its risk management strategy is prudent;
t) Regarding the 2018 ESP, an affirmative finding that Nevada Power has
satisfied the Commission directive from the Commission’s Order approving
the modified stipulation in Docket No. 13-08024, requiring the Company to
continue conducting quarterly gas hedging workshops with Staff and BCP to
review the implementation of the elements of the ESP Update and the
approved hedging strategy;
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u) Regarding the 2018 ESP, pursuant to NAC § 704.9494, the Companies request
that the Commission determine that the elements of the ESP are prudent by
making the following findings:
i. That the ESP balances the objectives of minimizing the cost of supply,
minimizing retail price volatility and maximizing the reliability of supply
over the term of the plan; and
ii. That the ESP optimizes the value of the overall supply portfolio of the
utility for the benefit of its bundled retail customers; and
iii. That the ESP does not contain any feature or mechanism that would impair
the restoration of the creditworthiness of the utility or would lead to a
deterioration of the creditworthiness of the utility;
(2) Approval the Companies’ request to deviate from the requirements of NAC §
704.9496 and to instead establish the Companies’ long-term avoided cost rates in a single
step, using the pricing from the highest cost 50 MW bid selected in the recent 2018 Renewable
RFP (the Techren V project) to cap the Companies’ administratively determined long-term
avoided cost. This long-term avoided cost rate would be made available for up to 50 MW
(nameplate, AC) of renewable resource for contracts up to 25 years, provided that, if Ballot
Question 3 is successful in November 2018, the contract term would not extent beyond 2023;
(3) Grant the Companies’ request to maintain the confidentiality of the
information as provided above;
(4) Grant any other requests as are specifically set forth in the testimony and
exhibits filed herewith, both those that are directly addressed and those that are not directly
addressed in this Application; and
(5) Grant such additional other relief as the Commission may deem appropriate
and necessary.
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Dated this 1st day of June, 2018.
Respectfully submitted,
NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY
/s/Elizabeth Elliot Elizabeth Elliot Deputy General Counsel Nevada Power Company Sierra Pacific Power Company 6100 Neil Road Reno, NV 89511 775-834-5694 [email protected]
/s/Tim Clausen Tim Clausen Senior Attorney Nevada Power Company Sierra Pacific Power Company 6100 Neil Road Reno, NV 89511 775-834-5678 [email protected]
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EXHIBIT A
ACTION PLAN
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2018 Joint IRP Application Exhibit A
ACTION PLAN Nevada Power Company d/b/a NV Energy
Sierra Pacific Power Company d/b/a NV Energy
2018 Joint Integrated Resource Plan Docket No. 18-06_____
Action Plan Period January 1, 2019 to December 31, 2021
SECTION I INTRODUCTION — NAC § 704.9489(1)(a)
Nevada Power Company (“Nevada Power”) and Sierra Pacific Power Company (“Sierra” and together with Nevada Power the “Companies” or “NV Energy”) are filing this first joint integrated resource plan (“2018 Joint IRP”). Senate Bill 146 from the 2017 Legislature required the Companies to file a joint plan for both utilities on or before June 1, 2018. The 2018 Joint IRP is guided by the Companies’ six core principles: customer service, employee commitment, environmental respect, regulatory integrity, operational excellence, and financial strength. In addition, the 2018 Joint IRP furthers the Companies’ strategic plan to double their use of renewable energy while maintaining, and not increasing, their bundled retail rates. In determining their Preferred Plan and preparing its Action Plan, the Companies developed four long-term expansion cases for meeting customers’ demands,1 and tested them to determine how each performed across the range of potential load, purchased power price, fuel price and carbon cost scenarios. Assuming that Question 3 is not successful in the November 2018 election, the Companies have selected as their Preferred Plan the Low Carbon Case, the centerpiece of which is:
1) The expansion of the Companies’ demand side management (“DSM”) programs to deliver statewide energy savings of at least 1.1 percent of the weather normalized retail sales over the Action Plan period.
2) The addition of 1,001 MW of renewable energy sourced from six new solar photovoltaic (“PV”) purchased power agreements (“PPAs”) and three new co-located battery storage projects; and
3) The early retirement of the North Valmy Unit 1, by December 31, 2021, provided that certain specified conditions are met.
A complete list of all Action Plan items follows in Section II.
A fifth case was constructed for the purposes of short-term planning. This case was only evaluated over five years and is the Companies’ preferred plan in the event voters approve Question 3 in November 2018.
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1
Residential, commercial and industrial customers have been clear that they want Nevada Power and Sierra to serve them with more renewable energy without impacting the costs they pay. Nevada Power and Sierra have listened, as is demonstrated by their strategic plan to double their renewable energy resources by 2023, without increasing bundled rates. This 2018 Joint IRP demonstrates just how the Companies intend to meet the pace of economic growth in both northern and southern Nevada, rely more on renewable energy, and keep rates low. The overarching goal of this 2018 Joint IRP is to meet growth and shrink customers’ exposure to natural gas prices by delivering more low-cost renewable energy to customers. If approved, the 2018 Joint IRP will further accelerate Nevada’s transition to a cleaner energy future, using new long-term commitments with committed and capable renewable companies to add over a gigawatt of new Nevada-based renewable energy resources, shoring up the Companies’ transmission infrastructure, and increasing investment in energy efficiency programs.
SECTION II ACTION PLAN ITEMS — NAC § 704.9489(1)(b)
LOAD FORECAST – IRP & ESP
• Approval of the long-term base load forecast presented in the Load Forecast and Market Fundamentals volume of this filing as being the most accurate information upon which to base long-term planning decisions through the Action Plan period.
• Approval of the three-year base load forecast presented in the 2018 Energy Supply Plan (“2018 ESP”) as being the most accurate information upon which to base near-term planning decisions through the Action Plan period.
FUEL AND PURCHASED POWER PRICE FORECASTS – IRP & ESP
• Approval of the base long-term fuel and purchased power forecasts presented in FPP-1 as presenting the best and most accurate information upon which to base long-term planning decisions through the Action Plan period.
• Approval of the base three-year fuel and purchased power forecast presented in the 2018 ESP as presenting the best and most accurate information upon which to base near-term planning decisions through the Action Plan period.
GENERATION – IRP
• Approval of the Companies’ Preferred Plan, which does not include the acquisition or construction by the Companies of new generation resources.
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• Assuming that Ballot Question 3 is not successful in the November 2018 election, approval of the early (December 31, 2021) retirement of Valmy Unit 1, conditioned on the following:
1. The PPAs for the output of the three new northern Nevada renewable energy projects and stationary storage projects included in Low Carbon Case must be approved by the Commission and then must demonstrate sufficient development progress to ensure commercial operation before June 2022.
2. NV Energy must have adequate capacity to serve customer load, which will be determined using, at a minimum,2 the following metrics:
a. “Loss of Load Probability.” For any given hour, an increase in the LOLP by more than 100% would trigger the reevaluation of the North Valmy Unit 1 retirement.
b. “Expected Unserved Energy.” Any megawatt-hour increase in expected unserved energy under the North Valmy Unit 1 retirement scenario would trigger a reevaluation of the retirement.
c. “Loss of Load Expectation.” This metric does not exceed the one day in 10 year criterion.
3. Conditions in the western energy markets must be such that NV Energy has sufficient access to economic energy and capacity to mitigate the cost pressure and reduction in flexibility associated with having power available from North Valmy Unit 1. While the present worth revenue requirement difference between the Low Carbon and Renewable Cases is relatively small, the Companies will monitor the production cost impact of any North Valmy Unit 1 retirement on retail rates and reevaluate the retirement decision if the retirement of North Valmy Unit 1 increases Base Tariff Energy Rates by more than $0.00250 per kilowatt-hour versus the non-retirement scenario.
4. Transmission area load of 2,800 MW will trigger a re-evaluation and, possibly, delay of the retirement of North Valmy Unit 1.
5. Approval of the request, made consistent with the tracking and accounting systems put in place at the Companies’ other retired generating facilities, the costs of decommissioning the North Valmy Generating Station, including those incurred to isolate and make safe North Valmy Unit 1, will be tracked and placed into a regulatory asset, and a carrying charge equal to Sierra’s currently approved cost of capital would be applied. Upon completion of decommissioning, the balance in the regulatory asset will be placed into rate base. Sierra will apply in a future proceeding to collect the balance over an appropriate amortization period.
Because real–time system reliability is paramount, additional analysis similar to that developed by the CAISO may be used by NV Energy to assess real-time reliability risk.
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2
6. Approval of the request, also made consistent with the tracking accounting treatment authorized in prior dockets, upon its retirement, the undepreciated book value of North Valmy Unit 1 will be placed into a regulatory asset where it would not earn a carrying charge. Instead, until it is included in Sierra’s revenue requirement, Sierra will amortize the regulatory asset balance using the depreciation rate for North Valmy Unit 1 at the time of its retirement. When the balance in the regulatory asset is included in revenue requirement, it will be placed into rate base. Sierra will apply in a future proceeding to collect the balance over an appropriate amortization period.
• Approval of the changes in the retirement dates of company-owned generating facilities as recommended in analysis completed pursuant to the Life Span Analysis Process;
• Approval the Companies’ request to deviate from the requirements of NAC § 704.9496 and to instead establish the Companies’ long-term avoided cost rates in a single step, using the pricing from the highest cost 50 MW bid selected in the recent 2018 Renewable RFP (the Techren Solar V project, described below) to cap the Companies’ administratively determined long-term avoided cost. This long-term avoided cost rate would be made available for up to 50 MW (nameplate, AC) of renewable resource for contracts up to 25 years, provided that, if Ballot Question 3 is successful in November 2018, the contract term would not extent beyond 2023.
RENEWABLES – IRP
• Assuming that Ballot Question 3 is not successful in the November 2018 election, approval of 1,001 MW of renewable PPAs, which will be provided from six new solar PV projects, three of which located in Sierra’s service territory, and three of which are located in Nevada Power’s service territory. As is described below, battery storage capacity is being co-located at the three projects located in Sierra’s service territory. Each PPA is described briefly below:
1. Sierra’s PPA with NextEra’s Dodge Flat Solar, LLC for 200 MW (nameplate, AC) of solar PV generation, with an additional 50 MW of capacity from a co-located battery storage system. The expected Commercial Operation Date (“COD”) is December 1, 2021.
2. Sierra’s PPA with NextEra’s Fish Springs Ranch Solar, LLC for 100 MW (nameplate, AC) solar PV generation, with an additional 25 MW of capacity from a co-located battery storage system. The expected COD is December 1, 2021.
3. Sierra’s PPA with Cypress Creek Renewables’ Battle Mountain Solar SP, LLC for 101 MW (nameplate, AC) solar PV generation, with an associated 25 MW of capacity from a co-located battery storage system. The expected COD is June 1, 2021.
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4. Nevada Power’s PPA with 8minutenergy’s 325MK 8ME, LLC for 300 MW (nameplate, AC) of solar PV generation from the Eagle Shadow Mountain Solar Farm, with an expected COD of December 31, 2021.
5. Nevada Power’s PPA with Sempra’s Copper Mountain Solar 5, LLC for 250 MW (nameplate, AC) of solar PV generation, with an expected COD of December 31, 2021.
6. Nevada Power’s PPA with 174 Power Global’s Techren Solar V, LLC for 50 MW (nameplate, AC) of solar PV generation, with an expected COD of December 31, 2020.
• Assuming that Ballot Question 3 is successful in the November 2018 election, approval of the lowest cost PPA among the six listed above, which is Nevada Power’s PPA with 8minutenergy’s 325MK 8ME, LLC, as well as the assignment of the PPA to Sierra. With this PPA, Sierra will be able to maintain compliance with Nevada’s Renewable Portfolio Standard (“RPS”) beyond December 31, 2021.
TRANSMISSION — IRP
• Assuming that Ballot Question 3 is not successful in the November 2018 election, approval to construct the facilities necessary to interconnect the six renewable energy projects identified above to the Companies’ transmission system. Network upgrades will be necessary to complete the interconnection of four of the six projects. The costs of these network upgrades, which while secured by the project developers but which will eventually be reflected in cost of service are:
• Dodge Flat Solar $12.565 million,
• Fish Springs Ranch $2.38 million,
• Eagle Shadow Mountain Solar Farm $550,000, and
• Copper Mountain 5 $7.44 million.
• Assuming that Ballot Question 3 is successful in the November 2018 election, approval to construct the facilities necessary to interconnect the lowest cost of the six renewable energy projects identified above, the 8minutenergy Eagle Shadow Mountain Solar Farm, to the Companies’ transmission system. Network upgrades costing $550,000 will be expended to complete this project.
• Approval to reconductor a 1.45 mile segment of Arden to McDonald 230 kV transmission line. This upgrade project is necessary to mitigate a potential North American Reliability Corporation TPL-001-4 violation identified as a result of the previously approved McDonald 230/138 kV Substation upgrade project, and is budgeted to cost of $720,000.
• Approval to continue the Companies’ involvement and membership in WestConnect. The Action Plan budget to continue membership is $225,000 annually in 2019, 2020, and 2021 for a total of $675,000.
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DEMAND SIDE PROGRAMS — IRP
• The Companies request approval of the DSM Plans as part of the Companies’ Action Plan. The Companies are requesting specific acceptance of the budgets and energy savings for the DSM Plans for the 2019-2021 Action Plan period: Nevada Power $49.8 million, $50.2 million, and $50.6 million in 2019, 2020, and 2021 respectively; Sierra $14.8 million, $15.5 million, and 16.1 million in 2019, 2020, and 2021 respectively; and NV Energy combined $64.6 million, $65.7 million, and 66.7 million in 2019, 2020, and 2021 respectively.
• The Companies also requests that the Commission review and approve the Measurement and Verification reports for program year 2017 provided in Technical Appendix DSM-5 through DSM-20 for the DSM programs delivered in the 2017 program year.
2018 JOINT ENERGY SUPPLY PLAN — ESP
• Power Procurement Plan. The Companies request approval of their joint Power Procurement Plan, which contains the following elements:
1. The Companies will close their respective 2019 summer open positions and a portion of the 2020 summer open positions with firm products prior to summer 2019. Thereafter, implement a four-season laddering strategy to close the remaining 2020 and 2021 open power positions with physical power and/or capacity acquired through a competitive bidding process. Any proposed purchases of greater than three years in duration will be submitted to the Commission for approval in accordance with NAC §§ 704.9113 and 704.9512.
2. The Companies will monitor the portfolio seasonally, monthly, weekly, daily, and hourly, and when economic, seek to make short-term and forward sales of resources not expected to be needed to serve native load. This practice will be continued over the 2018 ESP period.
3. The Companies anticipate meeting its RPS credit obligations throughout the 2018 ESP planning period, with Nevada Power continuing to repay its outstanding credit obligation to the joint pool for the benefit of Sierra.
• Fuel Procurement Plan. The Companies request approval of their joint Fuel Procurement Plan, which contains a (1) a physical gas procurement plan, (2) a gas transportation plan, (3) a gas hedging plan and (4) a coal procurement plan.
1. Physical Gas Supply. The Companies will continue to employ a four-season laddering strategy for physical gas purchases, through which 25 percent of projected monthly gas requirements per season are procured, subject to the availability of conforming bids and the willingness of suppliers to accept reasonable commercial terms. The
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Companies will continue to solicit physical gas supplies sourced from geographically diverse gas supply basins.
2. Gas Transportation. The Companies are seeking approval to maintain their current natural gas transportation portfolios. At Sierra, 26 transportation and storage contracts expire in 2019 and 2020. Sierra will rely on rights of first refusal and annual evergreen rights under its contracts and pipeline tariffs to keep existing gas transport capacity rights in place.
3. Gas Hedging Plan. The Companies are proposing to continue the current approved hedging strategy and acquire no natural gas hedging products during the 2018 ESP period. The Companies will continue to monitor the natural gas market fundamentals and recommend changes to the hedging strategy in a future ESP update or ESP amendment as necessary.
4. Coal Procurement Plan. Valmy’s coal requirements will be filled via spot market solicitations through RFPs transmitted to a list of qualified suppliers. In order to minimize the total cost of Valmy’s coal supply, the Companies will not issue an RFP for a long-term coal supply contract.
• Risk Management Strategy. The Companies have established a strategy that identifies risks inherent in procuring and obtaining a supply portfolio and establishes the means by which the utility plans to address and balance or hedge the identified risks related to cost, price volatility and reliability.
• Prudence Findings. The 2018 ESP regulations require the Commission to make four findings regarding the Companies’ 2018 ESP. The Companies request that consistent with regulation, the Commission make the following three findings regarding their 2018 ESP:
o Finding One: This ESP balances the objectives of minimizing the cost of supply, minimizing retail price volatility and maximizing the reliability of supply over the term of the plan.
o Finding Two: This ESP optimizes the value of the overall supply portfolio of the utility for the benefit of its bundled retail customers.
o Finding Three: This ESP does not contain any feature or mechanism that would impair the restoration of the creditworthiness of the utility or would lead to a deterioration of the creditworthiness of the utility.
o Finding Four: consistent with NAC § 704.9494(3), the Companies’ power procurement plan, fuel procurement plan and risk management strategies are prudent.
• Quarterly Hedging Workshops. An affirmative finding that the Companies have satisfied the Commission directive from the Commission’s Order approving the modified stipulation in Docket No. 13-08024, requiring the Companies to continue conducting
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quarterly gas hedging workshops with the Regulatory Operations Staff and the Bureau of Consumer Protection to review the implementation of the elements of the ESP update and the approved hedging strategy.3
SECTION III FORECASTING DATA -— NAC § 704.9489(1)(c)
The Companies will continue to pursue improvements to its forecast models including economic and price projections for all customer classes, end-use saturations and efficiency trends.
SECTION IV TIMETABLE AND BUDGET FOR PROGRAMS — NAC § 704.9489(1)(d), (3), (4)
The figure below shows the Action Plan timetable and budget by Action Plan year. Further details regarding the project schedules and milestones for capital projects is set forth in the Supply-Side Plan. Further details regarding the Demand Side Management Plan budget can be found in the Demand Side volume.
See, Order, Application of Sierra Company d/b/a NV Energy for Approval of its Energy Supply Plan Update for 2014-2015, ¶ 6, Docket No. 13-08024 (iss. November 19, 2013).
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3
ACTION PLAN BUDGET (Millions excluding AFUDC)
Action Plan Items 2019 2020 2021 3-Year Total Nevada Power Demand Side Outreach & Program Development $ 4.40 $ 4.50 $ 4.50 $ 13.40 Home Services $ 26.80 $ 26.90 $ 26.70 $ 80.40 Business Services $ 18.60 $ 18.80 $ 19.40 $ 56.80 Total Demand Side $ 49.80 $ 50.20 $ 50.60 $ 150.60
Transmission Copper Mtn 5* $ - $ - $ - $ 7.44 Eagle Shadow Mtn* $ - $ - $ - $ 0.55 Arden to McDonald $ 0.72 $ - $ - $ 0.72 WestConnect $ 0.15 $ 0.15 $ 0.15 $ 0.45 Total Transmission $ 0.87 $ 0.15 $ 0.15 $ 9.16
Nevada Power Total $ 50.67 $ 50.35 $ 50.75 $ 159.76
Sierra Demand Side Outreach & Program Development $ 2.15 $ 2.55 $ 2.65 $ 7.35 Home Services $ 5.75 $ 5.65 $ 5.75 $ 17.15 Business Services $ 6.90 $ 7.30 $ 7.70 $ 21.90 Total Demand Side $ 14.80 $ 15.50 $ 16.10 $ 46.40
Transmission Dodge Flat Interconnection $ 0.90 $ 8.50 $ 3.17 $ 12.57 Fish Springs Interconnection* $ - $ - $ - $ 2.38 WestConnect $ 0.07 $ 0.07 $ 0.07 $ 0.22 Total Transmission $ 0.97 $ 8.57 $ 3.24 $ 15.17
Sierra Total $ 15.77 $ 24.07 $ 19.34 $ 59.19
Combined NV Energy Demand Side Outreach & Program Development $ 6.55 $ 7.05 $ 7.15 $ 20.75 Home Services $ 32.55 $ 32.55 $ 32.45 $ 97.55 Business Services $ 25.50 $ 26.10 $ 27.10 $ 78.70 Total Demand Side $ 64.60 $ 65.70 $ 66.70 $ 197.00
Total Transmission $ 1.85 $ 8.73 $ 3.39 $ 24.33
NV Energy Total $ 66.45 $ 74.43 $ 70.09 $ 221.33 * Note: Annual cash flow not available.
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SECTION V CHANGES IN METHODOLOGY — NAC § 704.9489(1)(e)
While some modeling techniques have been improved, especially in the areas of load forecasting and demand-side management planning, the Companies are not proposing any changes in basic planning methodologies.
SECTION VI ACQUISITION OF NEW MODELING INSTRUMENTS — NAC § 704.9489(l)(f)
NV Energy is evaluating upgrades to its production cost modeling software. As the complexity of the electric system increases with the integration of renewable resources, distributed generation resources, and other technologies, production cost modeling needs to evolve. A discussion of the attributes that NV Energy is investigating is included in the testimony of Shawn M. Elicegui
SECTION VII DEMAND SIDE PLAN PROGRAMS — NAC § 704.9489(1)(g)
A description of continued planning efforts and the plan to carry out and continue selected conservation and DSM measures is set forth in Section II above. The Companies have not attempted to claim or calculate imputed debt associated with energy efficiency contracts in the Preferred Plan.
SECTION VIII ACQUISITION OF RESOURCES — NAC § 704.9489(1)(h)
The Companies do not plan to construct incremental generating resources during the Action Plan period.
SECTION IX RENEWABLE ENERGY ZONE TRANSMISSION ACTION PLAN — NAC 704.9489(5)
In response to the requirements provided for in NAC § 704.9489(5), regarding the development of transmission facilities to serve renewable energy zones within the State of Nevada, the Companies have prepared a Conceptual Renewable Energy Zone Transmission Plan (“REZTP” or “Plan”).
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The REZTP is a conceptual plan for transmission facilities that shows possible transmission access to areas of Nevada that have been designated as renewable energy zones. The REZTP does not request any funds construction nor does it request Commission approval of any facilities associated with the REZTP.
The Companies did not produce new studies for the REZTP for this 2018 Joint IRP. There has been no interest by any parties outside the Companies to pursue any studies with respect to this plan. Upon a new identification of renewable energy zones by the Commission, or new interest by outside parties, the Companies will revisit the REZTP and update accordingly. Additional details on the REZTP are provided in the Technical Appendix Item TRAN-9.
SECTION X ASSET RETIREMENT PLAN — NAC 704.9489(6)
Nevada Power and Sierra hold ownership interests in three generation assets that meet the criteria of NAC 704.9489(6), specifically:
• Brunswick Diesel Plant - Sierra: The Brunswick Diesel Plant is a 6 MW Emergency “Black Start Only” plant, comprised of three reciprocating diesel fired engines located on approximately 10 acres in Carson City, Nevada. This Plant is operational; however, since it is black start only, it cannot be used to serve customer load and so does not provide system capacity.
• Mohave Generating Station – Nevada Power: The Mohave site is located in Laughlin, Nevada and is the previous site of a 1,500 MW coal-fired generating plant. The site is co-owned by Southern California Edison (56 percent), Salt River Project (20 percent), Nevada Power (14 percent) and Los Angeles Department of Water and Power (10 percent). Mohave ceased operations in January 1, 2006 and has been decommissioned. In 2015, the co-owners agreed to proceed with selling the majority of the property through a public sale process. The property was listed by a nationwide commercial real estate firm in October 2016. No sales transactions have been executed at this time.
• Reid Gardner Generating Station – Nevada Power: The last unit at the Reid Gardner Generating Station ceased operations in March 2017 and the plant is in a state of Post-Operational Reserve. The units are currently being dismantled. Dismantling and demolishing will be completed over the next 18 months and site remediation will follow. The Commission approved plan remains as presented in Docket 15-05004. A final disposition plan for the site will be developed as the site remediation scope becomes better known.
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EXHIBIT B
ROADMAP
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Exhibit B
The following is a list of the Integrated Resource Planning regulations and the document location where each regulation has been addressed.
Code Sub-Section Description IRP Location
NAC 704.9215 NAC 704.9215 Summary of Resource Plan (NRS 704.741(1), 704.741(2)(a), 704.741(2)(b), 704.741(3)(a), 704.741(3)(b))
NAC 704.9215 1
1. Requires that “a utility's resource plan be accompanied by a summary that is suitable for distribution to the public. The summary must contain easily interpretable tables, graphs and maps and must not contain any complex explanations or highly technical language. The summary must be approximately 30 pages in length.”
Summary Volume
NAC 704.9215 2 2. The summary must include:
NAC 704.9215 2a
The summary must include: (a) “a brief introduction, addressed to the public, describing the utility, its facilities and the purpose of the resource plan, and the relationship between the resource plan and the strategic plan of the utility for the duration of the period covered by the resource plan. "
Summary Volume, Section I. (Introduction)
NAC 704.9215 2b
The summary must include: (b) “forecast of low growth, the forecast of high growth and the forecast of base growth of the peak demand for electric energy and of the annual electrical consumption, for the next 20 years, commencing with the year following the year in which the resource plan is filed, both with and without the impacts of programs for conservation and demand management and an explanation of the economic and demographic assumptions associated with each forecast.
Summary Volume, Section II. (Forecast of Growth)
NAC 704.9215 2c
The summary must include: (c) “a summary of the demand side plan listing each program and its effectiveness in terms of costs and showing the 20-year forecast of the reduction of demand and the contribution of each program to this forecast.
Summary Volume - Section III (Demand Side Plan Summary)
NAC 704.9215 2d
The summary must include: (d) “a summary of the preferred plan showing each planned addition to the system for the next 20 years, commencing with the year following the year in which the resource plan is filed, with its anticipated capacity, cost and date of beginning service. ”
Summary Volume - Section IV. (Summary of the Preferred Plan)
NAC 704.9215 2e
The summary must include: (e) “a summary of renewable energy showing how the utility intends to comply with the portfolio standard and listing each existing contract for renewable energy and each existing contract for the purchase of renewable energy credits and the term and anticipated cost of each such contract."
Summary Volume - Section IV. (Summary of the Preferred Plan);
Summary Volume - Section V. (Renewable Energy Plan)
NAC 704.9215 2f (f) A summary of:
NAC 704.9215 2f1 (1) The energy supply plan for the next 3 years setting out the anticipated cost , price volatility and reliability risks of the energy supply plan;
Summary Volume - Section VI
NAC 704.9215 2f2 (2) The risk management strategy Summary Volume - Section VI (Risk
Management Strategy)
NAC 704.9215 2f3 (3) The fuel procurement plan Summary Volume - Section VI (Gas
Procurement Plan, Coal Procurement Plan)
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Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9215 2f4 (4) The purchased power procurement plan. Summary Volume - Section VI (Power
Procurement Plan)
NAC 704.9215 2g (g) “a summary of the activities, acquisitions and costs included in the action plan of the utility .”
Summary Volume, Section VII. (Summary of the Activities, Acquisitions, and Costs
Included in the Action Plan of the Utility); Figure S-12 (Action Plan Budget)
NAC 704.9215 2h
(h) “an integrated evaluation of the components of the resource plan which relates the preferred plan to the objectives of the strategic plan of the utility, and any other information useful in presenting to the public a comprehensive summary of the utility and its expected development.”
Summary Volume
NAC 704.922 NAC 704.922 Technical appendix to resource plan
NAC 704.922 1
1.“a utility's resource plan must include a technical appendix. The appendix must contain sufficient detail to enable a technically proficient reader to understand how the resource plan and its forecasts were prepared and to evaluate the validity of the assumptions and the accuracy of the data used, including, without limitation, a list of the major assumptions used, a description of the forecasting methods employed and a description of the software utilized.
The 2018 IRP includes a technical appendix with sufficient detail to enable a technically proficient individual to understand how the resource plan and its forecasts were prepared and to evaluate the validity of the assumptions and accuracy of the data used.
NAC 704.922 2
2. “the appendix must contain sufficient information to enable a technically proficient reader to reproduce the results from the computations shown, including, without limitation:
NAC 704.922 2a (a) Citations to the sources of all significant information used in the resource plan;
Technical Appendix Items: LF-1 through LF-7;
FPP-1; DSM-1 through DSM-22;
GEN-1 through GEN-4(a)-(e); TRAN-1 through TRAN-10; ECON-1 through ECON-12;
REN-1 through REN-9
NAC 704.922 2b (b) Descriptions of all data inputs to the models used in developing the resource plan accompanied by an explanation of any modifications made to the data;
Technical Appendix Items: LF-1 through LF-7;
FPP-1; DSM-1 through DSM-22;
GEN-1 through GEN-4(a)-(e); TRAN-1 through TRAN-10; ECON-1 through ECON-12;
REN-1 through REN-9
NAC 704.922 2c (c) Characteristics of the generation operation of the utility, including the:
NAC 704.922 2c1 (1) Rates of forced outages; Technical Appendix Item GEN-1 (Unit
Characteristics Table)
NAC 704.922 2c2 (2) Rates of scheduled outages; Technical Appendix Item GEN-1 (Unit
Characteristics Table)
NAC 704.922 2c3 (3) Heat rates; Technical Appendix Item GEN-1 (Unit
Characteristics Table)
NAC 704.922 2c4 (4) Rates at which pollutants are emitted; Technical Appendix Item GEN-3 (Plant
Emission Rates)
NAC 704.922 2c5 (5) Controls required to mitigate pollution at planned facilities and estimates of the costs of those controls; and
Not Applicable
NAC 704.922 2c6 (6) Projections for the availability and price of fuels. Technical Appendix Items: FPP-1
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Exhibit B
Code Sub-Section Description IRP Location
NAC 704.922 2d
(d) Output characteristics or profiles of renewable resources for each type of renewable resource that is being considered as a resource option or that is currently owned or under contract with the utility;
Technical Appendix REN-1 (Generic Placeholder 12x24 Supply Tables);
Technical Appendix REN-2 (Generic Placeholder Pricing)
NAC 704.922 2e (e) A summary of the impact of intermittent energy resources on the electric system of the utility;
Technical Appendix ECON-11 (Solar PV Capacity Study B&V)
NAC 704.922 2f (f) The final results derived from the models;
Technical Appendix Items: LF-1 2018 IRP Load Forecast
FPP-1 Fuel and Purchased Power Price Forecasts
ECON-7 Capital Projects ECON-8 PWRR
REN-2 Generic Placeholder 12x24 Supply Table
REN-3 Generic Placeholder Pricing REN-4 All Renewable and Market Case
NAC 704.922 2g (g) Documentation of all models and formulas used consistent with any proprietary requirements imposed upon the utility by outside suppliers of the models;
Technical Appendix Items: LF-1 2018 IRP Load Forecast DSM-1 Portfolio Pro Model
DSM-21 Market Potential Study ECON-2 Description of PROMOD
Modeling Software ECON-11 Solar PV Capacity Study B&V ECON-12 NERA NV Energy 2018 Report
NAC 704.922 2h
(h) Such other information as is necessary to enable an informed reader to examine the resource plan and verify the adequacy and accuracy of the data, assumptions and methods used in developing the
The Technical Appendix includes additional information that the Company believes will be useful in examining the resource plan.
NAC 704.9225 NAC 704.9225 Forecasts of peak demand and annual energy consumption: General requirements (NRS 703.025, 704210, 704.741)
NAC 704.9225 1
1. “a utility's resource plan must contain a series of forecasts of the peak demand and annual energy consumption that represent the range of future load which its system may be required to serve. The range of future peak demand and energy consumption must be based upon and consistent with the upper and lower limits of expected economic and demographic change in the utility's service territory in the next 20 years, commencing with the year following the year in which the resource plan is filed, as follows:
NAC 704.9225 1a (a) A forecast of high growth; Appendix LF-1, Section VI, Tables LF-70
through LF-77
NAC 704.9225 1b (b) A forecast of base growth; and
Appendix LF-1, Section IV.A, Table LF-38 and Table LF-40 for sales and Section V.B
Tables LF-53 through LF-56 for peak demand, system energy, company use and
losses
NAC 704.9225 1c (c) A forecast of low growth." Appendix LF-1, Section VI, Tables LF-70
through LF-77
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Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9225 2
2. “in each of the forecasts described in subsection 1, the utility shall account for customer response to changes in the prices of electric energy and substitute energy sources and to the impacts of existing and proposed programs undertaken by the utility or required by governmental regulation to alter current energy use patterns."
Technical Appendix LF-1, Section II.B.Tables LF-16 and LF-17 for electricity prices; Section II.C, Tables LF-18 thru LF-27 and discussion for DSM; Section III for
discussion of how governmental energy efficiency regulations are treated; Section
IV.B, discussion and Tables LF-44 through LF-46 for the sales impacts of company
energy efficiency programs and for electric vehicles; Section V.C., LF-61 thru LF-66
and discussion for peak demand impacts of the company energy efficiency programs.
NAC 704.9225 3 3. “to the extent data is available, peak demand must be forecasted before accounting for the effects of cogeneration."
Technical Appendix LF-1, Section V.D.
NAC 704.9225 4
4. requires that the “utility shall maintain internal consistency among its forecasts. The forecast of peak demand must be consistent with the forecast of energy consumption and must be based on data which is normalized for weather pursuant to NAC 704.9245."
Technical Appendix LF-1, Section III discusses the weather normalization for the sales forecast, and Section V.A for the peak
demand and hourly load forecast. The consistency between sales and peak demand is ensured by using the class end-use sales forecast to develop peak factors used in the monthly peak model to develop estimated cooling, heating and other impacts at the
time of the monthly peaks.
NAC 704.923 NAC 704.923 Periods to be covered by resource plan (NRS 703.025, 704.210, 704.741)
NAC 704.923 1
1. “for historical data, the 10-year period preceding the year in which the resource plan is filed. If estimated data are used, the utility shall identify such data and describe the procedure by which the estimates were made.”
Technical Appendix LF-1, Table LF-1 through Table LF-3 contains historical data
as recorded. For the Nevada Power, an adjustment was made for the recently
departed DOS load to sales and peaks. See Section II.B and Section V.B, footnote 16. Weather Normalized values are based on
model coefficients and are discussed elsewhere.
NAC 704.923 2 2. “for the forecasts of peak demand and energy consumption, the 20-year period beginning with the year in which the resource plan is filed."
Technical Appendix LF-1, Tables LF-38 and LF-40 for sales and Tables LF-53
through LF-56 for Peak and system energy.
NAC 704.9235 NAC 704.9235 Formats for information included in resource plan (NRS 703.025, 704.210, 704.741)
NAC 704.9235 1
1. requires that “a utility shall, in consultation with the staff and subject to the approval of the Commission, develop suitable formats to be used for all information required in the resource plan of the utility.”
This filing is consistent with past filings, in terms of formatting in accordance with
Commission regulations. The Companies provide executable copies of non-
confidential filing documents to Staff and BCP upon request.
NAC 704.9235 2 2. requires “graphical and tabular information must be accompanied by explanatory narratives.”
All graphical and tabular information is accompanied by explanatory narratives.
NAC 704.9235 3 3. requires “a resource plan may include text which is not specifically related to those formats but is of importance to the resource plan.”
This Companies' Joint IRP filing includes text which is of importance to the proposed
plan.
4 Page 46 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9245
NAC 704.9245 Normalizing Forecast Values of Peak Demand and Energy Consumption to Account for Normal Weather Conditions requires “all forecast values of peak demand and energy consumption must be normalized to account for normal weather conditions within the service territory of the utility.”
Technical Appendix LF-1, Section III.A for sales, V. A. for peak demand. HDD and CDD are embedded in the heating and
cooling variables used in the sales and peaks regression models.
NAC 704.925
NAC 704.925 Resource plan: Inclusion, contents and evaluation of forecasts of energy consumption and peak demand; consideration of certain impacts; identification of change in methodology of forecasting.
NAC 704.925 1
1. Requires that “a utility's resource plan must include forecasts of energy consumption and the peak demand for summer and winter for the system, disaggregated by rate schedule, for the 20-year period beginning with the year following the year in which the resource plan is filed. The utility may combine rate schedules if necessary to protect the confidentiality of individual customers.”
Technical Appendix LF-1, Tables LF-41 and LF-42 for sales and Tables LF-59 and
LF-60 for Peak demand.
NAC 704.925 2
2. Requires that “the utility shall identify components of residential and commercial energy and demand for which initiatives for conservation and demand management are applicable. The utility shall include in its forecast an assessment of the impacts of such initiatives on the identified components and on overall levels of energy consumption and demand by residential and commercial customers.”
Section II.C, Tables LF-18 thru LF-27 and discussion for DSM; Section III for
discussion of how governmental energy efficiency regulations are treated; Section
IV.B, discussion and Tables LF-44 through LF-46 for the sales impacts of company
energy efficiency programs and for electric vehicles; Section V.C., LF-61 thru LF-66
and discussion for peak demand impacts of the company energy efficiency programs
including demand response
NAC 704.925 3 Requires that “the utility's forecast must include:
NAC 704.925 3a (a) Estimated annual losses of energy on the system for the 20-year period of the resource plan; and
Technical Appendix LF-1, Table LF-53 and LF-54
NAC 704.925 3b (b) Estimated annual energy to be used by the utility for the 20-year period of the resource plan.”
Technical Appendix LF-1, Table LF-53 and LF-54
NAC 704.925 4 4. Requires “the utility shall consider the impact of applicable new technologies and the impact of applicable new governmental programs or
Technical Appendix LF-1, Section II.C, and Section III
NAC 704.925 5
5. requires “the utility shall consider the impact of distributed generation and customers who acquire energy pursuant to NRS 704.787 or chapter 704B of NRS.”
Technical Appendix LF-1, Sections IV.B Table LF-44 and LF-45 for sales reductions;
Section V.B and C, Figure LF-41, Tables LF-61-62 contain the solar distributed
generation forecasted peak demand reductions; Section IX, Tables 80 and 81
show the MWh and installed MW. Section II.B discusses the methodology for
accounting for 704B customers. Section V.D discusses current 704B customers and
current DG impacts at the time of peak.
5 Page 47 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.925 6 6. requires “the utility shall provide a reasonable estimate of the demand from interruptible loads and the total demand of each type of interruptible load.”
Technical Appendix LF-1 Section V.A and Figure LF-51 and Table LF-52 contain a
discussion of how the avoided DR capacity is calculated. Section V.C. Tables LF-61, LF-62 show avoided capacity by class and
LF-63 shows the total installed DR and avoided capacity by year. Tables LF-64 and
LF-65 show the DR in the calculation of gross and net peaks
NAC 704.925 7
7. requires “the utility shall identify all standby loads and the total demand of each type of standby load and include an analysis of the likelihood and effect of incurring such demands at the time of the system peak of the utility.”
Technical Appendix LF-1 Sections V.D and V.E discuss the current standby and distributed generation load and the
likelihood they will be on peak
NAC 704.925 8
8. requires “all forecast values for the entire system of the utility must be reported. The utility shall separately estimate the contribution to peak demand and energy consumption for the components of the system located within the State of Nevada and for the components of the system located outside the State of Nevada.”
Technical Appendix LF-1 Section V. Tables LF-55 and LF-56 contains a breakout of the Nevada and California energy, summer and winter peaks. As there is no California retail load, there are no retail sales and customer
forecast for that load.
NAC 704.925 9
9. requires that “a resource plan must contain a graphical representation of projected load duration curves for the year following the year in which the resource plan was filed and every fifth year thereafter for the remainder of the period covered by the resource plan.”
Technical Appendix LF-1 Section V. Figures LF-57 and LF-58.
NAC 704.925 10 10. requires that “to verify and complete the final forecasts, the utility may evaluate the forecasts with the results of alternative forecasting methods.”
No alternative models were evaluated.
NAC 704.925 11
11. requires that “any change in the methodology of forecasting used by the utility from that used in the utility's previous resource plan must be identified in the current resource plan of the utility.”
No methodology changes for this IRP
NAC 704.9281 NAC 704.9281 Resource plan: Contents of data relating to peak demand and energy consumption. (NRS 703.025, 704.210, 704.741)
NAC 704.9281 1 1. requires that “the historical data relating to peak demand and energy consumption submitted in a utility's resource plan must contain:
NAC 704.9281 1a
(a) The recorded and coincident peak demand, normalized for weather, in the summer and winter for the total system for the 10-year period immediately preceding the year in which the resource plan is filed;
Technical Appendix LF-1, Section I.A, Table LF-2 through Table LF-3 report the
peaks. Section I.C,Tables LF-5 through LF-9 and associated discussion for peak
weather normalization.
NAC 704.9281 1b
(b) The recorded and annual sales of energy consumption, normalized for weather, for the total system for each year of the 10-year period immediately preceding the year in which the resource plan is filed;
Technical Appendix LF-1, Table LF-1 report the consumption. Section I.B.
discusses the sales weather normalization procedure.
NAC 704.9282 1c (c) The estimated losses of energy for the system for each year of the 10-year period immediately preceding the year in which the resource plan is filed; and
Technical Appendix LF-1, Table LF-1
NAC 704.9283 1d
(d) The estimated or actual amount of electric energy used by the utility in the operation of its business for each year of the 10-year period immediately preceding the year in which the resource plan is filed.
Technical Appendix LF-1, Table LF-1
6 Page 48 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9284 2
2. requires that “the data on energy consumption and peak demands must include data on all consumption and demands of ultimate customers that reflect firm, contractual commitments.”
Technical Appendix LF-1, section II.B discusses adjustments to Nevada Power for
704B customers. Section IV. Discuses shows reductions for sales due to Demand Response. Section V.A discusses how the
demand response reduces the peak demand and hourly loads
NAC 704.9321
NAC 704.9321 Reliability of assumptions, forecasts, conclusions and information; adjustments to forecasts; maps of covered areas; supportive testimony.
NAC 704.9321 1
1. Requires that “to the extent consistent with cost-effective procedures generally accepted by the industry, all assumptions, forecasts, conclusions and information used by a utility in its resource plan must
NAC 704.9321 1a (a) Based on substantially accurate data; The assumptions, forecasts, conclusions and
information used in this filing meet these requirements.
NAC 704.9321 1b (b) Adequately demonstrated and defended; and The assumptions, forecasts, conclusions and
information used in this filing meet these requirements.
NAC 704.9321 1c (c) Adequately documented and justified.” The assumptions, forecasts, conclusions and
information used in this filing meet these requirements.
NAC 704.9321 2
2. requires that “adjustments to forecasts obtained from external or published sources that are made on the basis of factors specifically relating to the utility must be explained.”
Load Forecast and Market Fundamentals Volume, Section 3.H
NAC 704.9321 3
3. requires that “each utility shall provide a suitable map or maps to show all areas covered by the resource plan. Each such map must show at least:
NAC 704.9321 3a (a) The service territory covered by the resource plan; Summary Volume, Figure S-1 (NV Energy
Service Territories)
NAC 704.9321 3b (b) The locations of the utility's facilities for generation of electric energy;
Supply Plan Narrative, Section 2.A.1 (Existing Generation)
NAC 704.9321 3c
(c) The location of renewable resources, independent power producers and distributed generation that are located within the service territory of the utility and are under contract with the utility;
Supply Plan Narrative, Section 2.D
NAC 704.9321 3d (d) The interconnections with other utilities and independent power producers; and
Transmission Plan Narrative; Section 3
NAC 704.9321 3e (e) The utility's facilities for transmission of electric energy.”
Transmission Plan Narrative; Section 2
NAC 704.9321 4 4. requires that “all testimony offered in support of the resource plan must be filed with the resource plan.”
All of the testimony offered in support of the 2018 Joint IRP is filed with the 2018
Joint IRP Plan.
NAC 704.934
NAC 704.934 Preparation, contents and submission of demand side plan; annual filing of analyses regarding conservation and demand management programs. (NRS 703.025, 704.210, 704.741)
NAC 704.934 1 1. requires that “as part of its resource plan, a utility shall submit a demand side plan.”
See DSM Narrative and Technical Appendix Items DSM-1 - DSM-22
NAC 704.934 2 2. requires that “the demand side plan must include:
NAC 704.934 2a (a) An identification of end-uses for programs for conservation and demand management.
See DSM Narrative
7 Page 49 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.934 2b
(b) An assessment of savings attributable to technically feasible programs for conservation and demand management, as determined by the utility. The programs must be ranked in a list according to the level of savings in energy or reduction in demand, or
See DSM Narrative Section 4
NAC 704.934 2c
(c) An assessment of technically feasible programs to determine which will produce benefits in peak demand or energy consumption. The utility shall estimate the cost of each such program. The methods used for the assessment must be stated in detail, specifically listing the data and assumptions considered in the assessment.
See DSM Narrative Section 4
NAC 704.934 3
3. requires that “in creating its demand side plan, a utility shall consider the impact of applicable new technologies on current and future demand side options. The consideration of new technologies must include, without limitation, consideration of the potential impact of advances in digital technology and computer information systems.”
See DSM Narrative Section 4
NAC 704.934 4 4. requires that “the demand side plan must provide a list of the programs for which the utility is requesting the approval of the Commission. The list must include:
NAC 704.934 4a
(a) An estimate of the reduction in the peak demand and energy consumption that would result from each proposed program, in kilowatt-hours and kilowatts saved. The programs must be listed according to their expected savings and their contribution to a reduction in peak demand and energy consumption based upon realistic estimates of the penetration of the market and the average life of the programs.
See DSM Narrative
NAC 704.934 4b
(b) An assessment of the costs of each proposed program and the savings produced by the program. If the program can be relied upon to reduce peak demand on a firm basis, the assessment must include the savings in the costs of transmission and distribution.
See DSM Narrative
NAC 704.934 4c (c) An assessment of the impact on the utility's load shapes of each proposed and existing program for conservation and demand management.
See DSM Narrative
NAC 704.934 4d (d) If a program is an educational program, the projected expenses of the utility for the educational program.
See DSM Narrative
NAC 704.934 5
5. requires that “the utility shall include with its demand side plan a report on the status of all programs for conservation and demand management that have been approved by the Commission. The report must include tables for each such program showing, for each year, the planned and achieved reduction in kilowatt-hours, the reduction in kilowatts and the cost of the program.
See DSM Narrative Section 4
NAC 704.934 6
6. requires that “on or before August 15 of each year following the filing of its resource plan, the utility shall file with the Commission a copy of the complete analysis the utility used in determining for the upcoming year which conservation and demand management programs are to be continued and which programs are to be cancelled. The Commission will process this analysis in the same manner as an amendment filed pursuant to NAC 704.9503.”
See DSM Narrative Section 4
8 Page 50 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.934 7
The utility shall include with its demand side plan a report on the status of all programs for energy efficiency and conservation that have been approved by the Commission. The report must include tables for each such program showing, for each year, the planned and achieved reduction in kilowatt-hours, the reduction in kilowatts and the cost of the program
See DSM Section 2
NAC 704.9355 NAC 704.9355 Analyses of options for supply (NRS 703.025, 704.210, 704.741)
NAC 704.9355 1
1. requires that “a utility shall develop a set of analyses of its options for supply to be considered for meeting the expected future demand on its system. These analyses must include an examination of the environmental impact of each option, taking into account the best available technologies and the environmental benefit of renewable resources. The options to be analyzed must include:
NAC 704.9355 1a
(a) Construction of new generation facilities or upgrades to existing generation facilities, including retrofitting existing facilities with more efficient systems or converting to other fuels;
Supply Plan Narrative, Section 2.A.1, 2.A.2, 2.A.4
NAC 704.9355 1b (b) Construction of new transmission facilities or upgrades to existing transmission facilities;
Transmission Plan Narrative; Section 10
NAC 704.9355 1c (c) Purchase of long-term transmission rights on transmission facilities owned by other persons;
Transmission Plan Narrative; Section 10
NAC 704.9355 1d
(d) Improvements in the efficiency of operations and scheduling, including, without limitation, improvements that are attributable to the proposed implementation of new digital and computer information system technologies; and
Supply Plan Narrative, Section 2.A.1, 2.A.2, 2.A.4
NAC 704.9355 1e (e) Transactions with other utilities, independent producers and utility customers for:
NAC 704.9355 1e1 (1) Pooling of power; Not Applicable NAC 704.9355 1e2 (2) Purchases of power; or Not Applicable NAC 704.9355 1e3 (3) Exchanges of power. Not Applicable
NAC 704.9355 2
2. states that “as used in this section, “environmental benefit of renewable resources” means the present worth over a 20-year period of the benefits associated with the generation and maintenance of renewable resources for supply of capacity or energy, or supply of both capacity and energy, that results in a reduction of harm to the environment.”
Not Applicable
NAC 704.9357 NAC 704.9357 Analysis of net economic benefits to State. (NRS 703.025, 704.210, 704.741)
NAC 704.9357 1
1. requires that “an analysis of the changes that result in net economic benefits to Nevada from electricity-producing or electricity-saving resources must be conducted by the utility in selecting a resource option. The net economic benefit to the State must be quantified to reflect both the positive and negative changes and must include the net economic impact of renewable resources. The projected present worth of societal cost of a competing resource plan must be within 10 percent of the lowest societal costs plan before proceeding with an analysis of the economic benefits to Nevada.
Supply Plan Narrative, Section 3.H (Environmental Externalities and Economic
Net Benefits to the State); Technical Appendix ECON-12 (NERA
Report)
9 Page 51 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9357 2
2. requires that “the economic benefits analysis must be achieved by calculating the portion of the present worth of future requirements for revenue that is expended within the State, including the following for both the construction and operation phases of any
Supply Plan Narrative, Section 3.H (Environmental Externalities and Economic
Net Benefits to the State); Technical Appendix ECON-12 (NERA
Report)
NAC 704.9357 2a (a) Capital expenditures for land and facilities located within the State or equipment manufactured in the State;
Supply Plan Narrative, Section 3.H (Environmental Externalities and Economic
Net Benefits to the State); Technical Appendix ECON-12 (NERA
Report)
NAC 704.9357 2b (b) The portion of the cost of materials, supplies and fuel purchased in the State;
Supply Plan Narrative, Section 3.H (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix ECON-15 (NERA
Report)
NAC 704.9357 2c (c) Wages paid for work done within the State;
Supply Plan Narrative, Section 3.H (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix ECON-12 (NERA
Report)
NAC 704.9357 2d (d) Taxes and fees paid to the State or subdivisions thereof; and
Supply Plan Narrative, Section 3.H (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix ECON-12 (NERA
Report)
NAC 704.9357 2e (e) Fees paid for services performed within the State.
Supply Plan Narrative, Section 3.H (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix ECON-15 (NERA
Report)
NAC 704.9357 3
3. requires that “in the analysis, the utility shall consider only the net benefit added to the economy of the State of that portion of expenditures made within the State.”
Supply Plan Narrative, Section 3.H (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix ECON-12 (NERA
Report)
NAC 704.9357 4
4. requires that “the present worth of societal costs of the competing resources must then be adjusted by the Commission to take into consideration either all, or only a portion, of the calculated economic benefit.”
Supply Plan Narrative, Section 3.H (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix ECON-12 (NERA
Report)
NAC 704.9357 5
5. states that “as used in this section, ‘net economic impact of a renewable resource’ means the present worth of economic costs of a contract for a renewable resource minus the present worth of economic development benefits to the State over a 20-year period.
Supply Plan Narrative, Section 3.H (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix ECON-12 (NERA
Report)
NAC 704.9359
NAC 704.9359 Determination of environmental costs to State: requires that “the environmental costs to the State associated with operating and maintaining a supply plan or demand side plan must be quantified for air emissions, water and land use. Environmental costs are those costs, wherever they may occur, that result from harm or risks of harm to the environment after the application of all mitigation measures required by existing environmental regulation or otherwise included in the resource plan.” (NRS 703.025, 704.210, 704.741)
Supply Plan Narrative, Section 3.H (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix ECON-12 (NERA
Report)
10 Page 52 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9361
NAC 704.9361 Elimination or modification of environmental factors, emission rates and environmental costs: requires that “the emission rates and environmental costs set or otherwise authorized by the Commission may be subject to elimination or modification, and new factors may be added for consideration, as new scientific, engineering, economic or other technical information becomes available to the Commission. Information purporting to establish a need for the deletion or addition of any environmental factor or the revision of any authorized emission rates or environmental costs may be presented by any party at the time of a hearing on the utility's resource plan.” (NRS 703.025, 704.210,
The Company is not claiming a need for the deletion or addition of any environmental
factor or the revision of any authorized emission rates or environmental costs.
NAC 704.937
List of options for supply of capacity and electric energy; criteria for selection of options; comparison of and requirements for alternative plans; identification of preferred plan. (NRS 703.025, 704.210, 704.741)
NAC 704.937 1
1. requires that “a utility's supply plan must contain a list of options for the supply of capacity and electric energy that includes a description of all existing and planned facilities for generation and transmission, existing and planned power purchases, and other resources available as options to the utility for the future supply of electric energy. The description must include the expected capacity of the facilities and resources for each year of the supply plan.”
Technical Appendix Items: GEN-1 Existing Unit Characteristics Table GEN-2 New Generation Performance and
Cost Summary ECON-6 (L&R Tables)
REN-1 through REN-4 Top Projects PPA 12x24 Supply Tables, Generic Placeholder 12x24 Supply Table, Generic Placeholder Pricing, All Renewable and Market Cases
NAC 704.937 2
2. requires that “a utility shall identify the criteria it has used for the selection of its options for meeting the expected future demands for electric energy and shall explain how any conflicts among criteria are
Supply Plan Narrative, Section 3.A . (Overview);
Supply Plan Narrative, Section 3.D. (Alternative Plan Development).
NAC 704.937 3
3. requires that “in comparing alternative plans containing different resource options, the utility shall calculate the present worth of future requirements for revenue for each alternative plan for the supply of power. A comparison of the present worth of future requirements for revenue for each alternative plan must be presented in the resource plan.”
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Technical Appendix Item ECON-8 (Production Cost and Capital PWRR)
NAC 704.937 4
4. requires that “the utility shall calculate the present worth of societal costs for each alternative plan for the supply of power. The present worth of societal costs of a particular alternative plan must be determined by adding the environmental costs to the present worth of future requirements for revenue."
Supply Plan Narrative, Section 3.H - (Environmental Externalities and Economic
Benefit to the State); Technical Appendix Item ECON-15 (NERA
Report)
NAC 704.937 5 5. requires that “the utility shall consider for each alternative plan the mitigation of risk by means of:
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
NAC 704.937 5a (a) Flexibility;
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
NAC 704.937 5b (b) Diversity;
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
11 Page 53 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.937 5c (c) Reduced size of commitments;
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
NAC 704.937 5d (d) Choice of projects that can be completed in short periods;
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
NAC 704.937 5e (e) Displacement of fuel;
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
NAC 704.937 5f (f) Reliability;
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
Plans)
NAC 704.937 5g (g) Selection of fuel and energy supply portfolios; and
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
Plans)
NAC 704.937 5h (h) Financial instruments or electricity products.”
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
Plans)
NAC 704.937 6 6. Requires that “the alternative plans of the utility must:
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
Plans)
NAC 704.937 6a (a) Provide adequate reliability;
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
Plans)
NAC 704.937 6b (b) Be within regulatory and financial constraints;
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
Plans)
NAC 704.937 6c (c) Meet the portfolio standard; and
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
Plans)
NAC 704.937 6d (d) Meet the requirements for environmental protection.”
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
Plans)
NAC 704.937 7 7. requires “the utility shall identify its preferred plan and fully justify its choice by setting forth the criteria that influenced the utility's choice.”
Supply Plan Narrative, Section 3.E (Economic Analysis Results);
Supply Plan Narrative, Section 3.F (Selection of Preferred and Alternative
Plans)
12 Page 54 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9378
NAC 704.9378 Time-line graphs for proposed resources for supply: requires that “time-line graphs for proposed resources for supply. (NRS 703.025, 704.210, 704.741) The supply plan must contain time-line graphs for the utility's proposed resources for supply that include major activities, milestones and points of decision. The following subjects must be included in the time-line graphs for each proposed resource:
NAC 704.9378 1 1. Preparation of any required environmental impact statements;
N/A - No environmental impact statements in this IRP filing.
NAC 704.9378 2 2. Applications for significant permits N/A - No permit applications planned for
this IRP filing. NAC 704.9378 3 3. Commitments of significant expenditures; Supply Plan Narrative, Section 2.A.4 NAC 704.9378 4 4. Periods for construction; and Technical Appendix REN-6
NAC 704.9378 5 5. The commercial operation date." Technical Appendix REN-6
NAC 704.9385 NAC 704.9385 Contents; tables; transmission plan; information regarding purchase of power; maps
NAC 704.9385 1 1. requires that “the supply plan of the utility must develop and document the origins of:
NAC 704.9385 1a (a) The assumptions, data and projections used by the utility to calculate the costs and benefits of its options.
Technical Appendix Items: LF-1 2018 IRP Load Forecast
FPP-1 Fuel and Purchased Power Price Forecasts
GEN-1 Generating Unit Characteristics Table;
GEN-2 New Generation Characteristics Table;
GEN-3 2017 Plant Emission Rates;
NAC 704.9385 1b (b) The assessment of current and anticipated electric market conditions by the utility for the region in which the utility operates.
Load Forecast and Market Fundamentals Narrative, Section 2.A
NAC 704.9385 1c (c) The basic economic and financial limitations of the utility.
Supply Plan Narrative, Section 4.C. (External Financing Requirements, Section 4.G. (Risk Management Strategy, Section
4.H. (Financial Risks))
NAC 704.9385 1d
(d) The assumptions used by the utility for developing the environmental costs and the net economic benefits to the State from each of the options of the utility for future supply.
Supply Plan Narrative, Section 3.H - (Environmental Externalities and
NetEconomic Benefit to the State); Technical Appendix Item ECON-12 (NERA
Report)
NAC 704.9385 1e (e) The criteria used by the utility for determining the reserve margin.
Supply Plan Narrative, Section 3.G (Loads and Resources Tables);
Supply Plan Narrative, Section 3.C (Key Modeling Assumptions);
Technical Appendix Item ECON-9 (Operating Reserves Calculation)
NAC 704.9385 1f (f) The assumptions used by the utility for renewable resources.
REN-1 through REN-4 Top Projects PPA 12x24 Supply Tables, Generic Placeholder 12x24 Supply Table, Generic Placeholder Pricing, All Renewable and Market Cases
NAC 704.9385 1g (g) The assumptions used by the utility for independent power producers.
Technical Appendix: FPP-1
13 Page 55 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9385 1h
(h) The assumptions used by the utility for the reduction in demand and energy requirements associated with customers exiting service from the utility and customers utilizing distributed generation resources.
Technical Appendix LF-1, Sections IV.B Table LF-44 and LF-45 for sales reductions;
Section V.B and C, Figure LF-41, Tables LF-61-62 contain the solar distributed
generation forecasted peak demand reductions; Section IX discusses how the
DG reductions were calculated and Tables LF-80 and LF-81 show the MWh reduction and installed MW. Section II.B discusses the methodology for accounting for 704B
customers. Narrative Section 1.A contains a paragraph describing recent customers
transitioning to 704B service.Section V.D discusses current 704B customers and
current DG impacts at the time of peak.
NAC 704.9385 2
2. requires that “regarding generation, a utility's supply plan must contain a table of all its existing and planned facilities for electric generation that it expects to be operating in each of the 20 years covered by its forecast. Each of the following items of information must be set forth in the table if applicable to a listed facility:
NAC 704.9385 2a (a) The planned or actual commercial operation date of the facility;
Supply Plan Narrative, Section 2.A (Generation Table GEN-1);
Supply Plan Narrative, Section 3.D (Plan Development);
Supply Plan Narrative, Section 3.G (Loads and Resources Tables);
See Technical Appendix Items: ECON-6 (L&R Tables)
NAC 704.9385 2b (b) The date of the planned retirement of the facility, including the criteria used to select that date;
Supply Plan Narrative, Section 2.A (Generation Table GEN-1);
Supply Plan Narrative, Section 3.D (Alternative Plan Development);
Supply Plan Narrative, Section 3.G (Loads and Resources Tables);
See Technical Appendix Item: ECON-6 (L&R Tables)
NAC 704.9385 2c (c) The type of facility;
Supply Plan Narrative, Section 2.A (Generation Table GEN-1);
Supply Plan Narrative, Section 3.D (Alternative Plan Development);
Supply Plan Narrative, Section 3.G (Loads and Resources Tables);
See Technical Appendix Item: ECON-6 (L&R Tables)
NAC 704.9385 2d (d) The rated generating capacity and net expected generating capacity of the facility;
Supply Plan Narrative, Section 2.A (Generation Table GEN-1);
Supply Plan Narrative, Section 3.D (Alternative Plan Development);
Supply Plan Narrative, Section 3.G (Loads and Resources Tables);
See Technical Appendix Item: ECON-6 (L&R Tables)
14 Page 56 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9385 2e (e) The fuel used;
Supply Plan Narrative, Section 2.A (Generation Table GEN-1);
Supply Plan Narrative, Section 3.D (Alternative Plan Development);
Supply Plan Narrative, Section 3.G (Loads and Resources Tables);
See Technical Appendix Item: ECON-6 (L&R Tables)
NAC 704.9385 2f (f) The capacity of the facility for storing fuel; and
Supply Plan Narrative, Section 2.A (Generation Table GEN-1);
Supply Plan Narrative, Section 3.D (Alternative Plan Development);
Supply Plan Narrative, Section 3.G (Loads and Resources Tables);
See Technical Appendix Item: ECON-6 (L&R Tables)
NAC 704.9385 2g (g) The designation of the capacity type of the facility, such as base load, intermediate or peaking.
Supply Plan Narrative, Section 2.A (Generation Table GEN-1);
Supply Plan Narrative, Section 3.D (Plan Development);
Supply Plan Narrative, Section 3.G (Loads and Resources Tables);
See Technical Appendix Item: ECON-6 (L&R Tables)
NAC 704.9385 3
3. requires that “the supply plan of a utility must include a transmission plan for the 20 years covered by the forecast in the supply plan. The transmission plan must include, without limitation:
NAC 704.9385 3a
(a) A summary of the capabilities of the transmission system, including import, export and the rating of significant transmission paths within the system of the utility, and of the existing and planned transmission system of the utility for each year in the period covered by the resource plan.
Transmission Plan Narrative; Sections 3, 4, 5
NAC 704.9385 3b
(b) A description of the transmission projects the utility is considering for expanding or upgrading the capabilities of its transmission system, the anticipated timing of those projects and the impact of the projects on the transmission capabilities of the existing and planned transmission system of the utility.
Transmission Plan Narrative; Section 2, 4, 10
NAC 704.9385 3c
(c) Identification of the transmission capacity required to serve bundled retail transmission customers, unbundled retail transmission customers and those wholesale transmission customers for whom the utility has an obligation to provide transmission services, for annual and peaking periods throughout the period covered by the resource plan.
Transmission Plan Narrative; Section 6
NAC 704.9385 3d
(d) Identification of all existing and proposed transmission service agreements, and their expiration dates, with transmission customers for transmission service on the transmission system of the utility and the impact of these agreements on available capacity for bundled retail transmission customers on the proposed or existing transmission facilities.
Transmission Plan Narrative; Section 6
NAC 704.9385 3e
(e) A table identifying all the transmission capacity that the utility has secured for its bundled retail transmission customers on both its transmission system and the transmission systems of other entities
Transmission Plan Narrative; Section 6
15 Page 57 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9385 3f
(f) A description of the participation of the utility in regional planning organizations and an explanation of the role of those organizations in the transmission planning process of the utility.
Transmission Plan Narrative; Section 11
NAC 704.9385 3g (g) A summary of the impacts of relevant orders of the Federal Energy Regulatory Commission issued since the utility filed its last resource plan.
Transmission Plan Narrative; Section 14
NAC 704.9385 3h (h) A demonstration that the utility has attempted to reduce the impact of line losses upon its future resource requirements.”
Transmission Plan Narrative; Section 12
NAC 704.9385 4 4. Requires “regarding the purchase of power, the supply plan must contain a list showing:
NAC 704.9385 4a
(a) All sources from which the utility has contracted to buy, or has plans or potential opportunities to buy, electric power during the 20 years covered by the supply plan; and
Supply Plan Narrative, Section 2.B. (Long-Term Purchase Power Agreements);
NAC 704.9385 4b
(b) The amount of electric power that the utility has contracted to buy, or has plans or potential opportunities to buy, from each source and the years for which delivery of the electric power is contracted or planned.”
Supply Plan Narrative, Section 2.B. (Long-Term Purchase Power Agreements)
NAC 704.9385 5
Requires that “the utility shall include in its supply plan a map or maps that identify the location of each existing or planned generation or transmission facility, renewable energy system and independent power producer that are projected to be relied upon during the period covered by the action plan.”
Supply Plan Narrative, Section 2.A; Supply Plan Narrative, Section 2.D
NAC 704.9385 6
States, "In addition to the transmission plan required by subsection 3, the supply plan of a utility must include, as a discrete but integrated item in the supply plan, a conceptual renewable energy zone transmission plan for the 20 years covered by the forecast in Supply Plan. The renewable energy zone transmission plan must include distinct conceptual transmission plans, which may include capacity for export to other states, for serving each of the renewable energy zones designated by the Commission pursuant to section 1 of LCB File No. R146-09, which was adopted by the Commission and filed with the Secretary of State on January 28, 2010. Each of the distinct conceptual transmission plans must include:
NAC 704.9385 6a (a) A description of the construction or expansion of transmission facilities required to be added to the utility's existing transmission system.
Transmission Plan Narrative; Section 13 & Technical Appendix TRAN-10
NAC 704.9385 6b
(b) An estimate of cost at the planning level, including, without limitation, estimates for permitting and other expenses of transmission development and estimated development schedules for the transmission facilities included in the transmission plan, based on information known by the utility at the time the transmission plan is submitted to the Commission.
Transmission Plan Narrative; Section 13 & Technical Appendix TRAN-10
NAC 704.9385 6c
c) A description of any restrictions or limitations on the construction or expansion of transmission facilities, including, without limitation, generator tie-lines in the applicable transmission plan due to any local topographical, environmental, governmental, land use or other factors or limitations that are known by the utility at the time the transmission plan is
Transmission Plan Narrative; Section 13 & Technical Appendix TRAN-10
16 Page 58 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9385 6d
(d) An estimate of the capacity of the renewable energy resources capable of being developed in the applicable zone, base on information that is known to the utility at the time the transmission plan is submitted to the Commission."
Transmission Plan Narrative; Section 13 & Technical Appendix TRAN-10
NAC 704.9385 7
The supply plan of a utility must include the list of all assets of the utility required by section 10 of Senate Bill No. 416, chapter 395, Statutes of Nevada 2015, at page 2214.1.If a utility owns only part of an asset included on the list, the identity of every other owner and the percentage of the asset owned by each owner must be set forth on the list.
Supply Side Narrative, Section 2.A & Technical Appendix GEN-1
NAC 704.9489 5
The action plan must include a renewable energy zone transmission action plan for serving one or more of the renewable energy zones designated by the Commission or an explanation of why no renewable energy zone transmission action plan is contained in the action
Transmission Plan Narrative; Section 13 & Technical Appendix TRAN-10
NAC 704.9395
NAC 704.9395 Resource plan: Information on financial and economic characteristics of planned facilities. Requires that “a utility's resource plan must contain information on the financial and economic characteristics of planned facilities. The information must include:
NAC 704.9395 1 1. The estimated costs of construction, including:
NAC 704.9395 1a (a) Annual flows of expenditures with allowance for money expended during construction; and
Technical Appendix Item GEN-2
NAC 704.9395 1b (b) Annual flows of expenditures without allowance for money expended during construction;
Technical Appendix Item GEN-2
NAC 704.9395 2 The estimated costs of operation, including:
NAC 704.9395 2a (a) Variable costs per kilowatt-hour, with expenses for fuel and other items indicated separately; and
Technical Appendix Item GEN-2
NAC 704.9395 2b (b) Fixed costs per kilowatt-hour; Technical Appendix Item GEN-2
NAC 704.9395 3 3. Net environmental costs and net economic benefits to the State;
Supply Plan Narrative, Section 3.H (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix Item ECON-12 (NERA
Report) NAC 704.9395 4 (4) The rates of escalation of cost, including: NAC 704.9395 4a (a) Capital costs; Technical Appendix Item GEN-2 NAC 704.9395 4b (b) Variable fuel costs; Technical Appendix Item GEN-2 NAC 704.9395 4c (c) Nonfuel operating costs; Technical Appendix Item GEN-2 NAC 704.9395 4d (d) Environmental costs; and Technical Appendix Item GEN-2 NAC 704.9395 4e (e) Fixed operating costs; and Technical Appendix Item GEN-2
NAC 704.9395 5 5. The average cost per kilowatt-hour at projected loads in current dollars for each year of the plan for each existing and planned facility.
Technical Appendix Item ECON-3 (Average Generation Cost)
NAC 704.9401 NAC 704.9401 Financial information and assumptions used to develop financial plan (NRS 703.025, 704.210, 704.741)
NAC 704.9401 1
1. requires that “the assumptions and methodologies for modeling used to develop the utility's financial plan must be described in the resource plan of the utility. The following estimated financial information for the preferred plan must be included in the financial plan:
NAC 704.9401 1a (a) Present worth of revenue requirements; Supply Plan Narrative, Section 4.E (Electric
Revenue Requirement)
NAC 704.9401 1b (b) Nominal revenue requirements by year; Supply Plan Narrative, Section 4.E (Electric
Revenue Requirement)
NAC 704.9401 1c (c) Average system rates per kilowatt-hour by year; Supply Plan Narrative, Section 4.H
(Financial Risks)
17 Page 59 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9401 1d (d) Total rate base by year; Supply Plan Narrative, Section 4.D (Total
Rate Base)
NAC 704.9401 1e (e) Financial results attributed to the risk management strategy of the utility.
Supply Plan Narrative, Section 4.H (Financial Risks)
NAC 704.9401 2
2. Requires that “the financial assumptions used by the utility to develop its supply plan must be stated in the financial plan. The following items must be stated for each year in the financial plan:
NAC 704.9401 2a (a) The general rate of inflation; Supply Plan Narrative, Section 4.F
(Common Methodologies / Assumptions)
NAC 704.9401 2b (b) The AFUDC rates used in the supply plan; Supply Plan Narrative, Section 4.F
(Common Methodologies / Assumptions)
NAC 704.9401 2c (c) The cost of capital rates used in the supply plan; Supply Plan Narrative, Section 4.F
(Common Methodologies / Assumptions)
NAC 704.9401 2d (d) The discount rates used in the calculations to determine present worth;
Supply Plan Narrative, Section 4.F (Common Methodologies / Assumptions)
NAC 704.9401 2e (e) The tax rates used in the supply plan; Supply Plan Narrative, Section 4.F
(Common Methodologies / Assumptions)
NAC 704.9401 3f (f) Other assumptions used in the supply plan. Supply Plan Narrative, Section 4.F
(Common Methodologies / Assumptions)
NAC 704.944
NAC 704.944 Supply plan: Discussion of alternative strategies: Requires that “a utility shall include in its supply plan a comprehensive discussion of the alternative strategies that the utility would pursue if any preferred resource or facility were not available as described in the supply plan.” (NRS 703.025, 704.210, 704.741)
Summary Volume (Supply Side Alternative Plans)
NAC 704.945 NAC 704.945 Resource Plan: Inclusion of certain tables and graphs (NRS 703.025, 704.210, 704.741)
NAC 704.945 1
1. Requires that “a utility shall include in its resource plan a table of loads and resources for each supply plan analyzed. The table must include the following data for each year of the resource plan:
NAC 704.945 1a (a) The capacity provided by each supply resource; Supply Plan Narrative, Section 3.G. (Loads
and Resources Tables); Technical Appendix Item ECON-6
NAC 704.945 1b (b) The total expected capacity of all resources; Supply Plan Narrative, Section 3.G. (Loads
and Resources Tables); Technical Appendix Item ECON-6
NAC 704.945 1c (c) The forecasted peak demand; Supply Plan Narrative, Section 3.G. (Loads
and Resources Tables); Technical Appendix Item ECON-6
NAC 704.945 1d (d) The estimated impact of new programs for conservation and demand management;
Supply Plan Narrative, Section 3.G. (Loads and Resources Tables);
Technical Appendix Item ECON-6
18 Page 60 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.945 1e (e) The expected capacity and energy provided by renewable resources, categorized by type;
Supply Plan Narrative, Section 3.G. (Loads and Resources Tables);
Technical Appendix Item ECON-6
NAC 704.945 1f (f) The required planning reserves; Supply Plan Narrative, Section 3.G. (Loads
and Resources Tables); Technical Appendix Item ECON-6
NAC 704.945 1g (g) The total capacity required; Supply Plan Narrative, Section 3.G. (Loads
and Resources Tables); Technical Appendix Item ECON-6
NAC 704.945 1h (h) The excess or deficiency of capacity without additional resources; and
Supply Plan Narrative, Section 3.G. (Loads and Resources Tables);
Technical Appendix Item ECON-6
NAC 704.945 1j (i) The excess or deficiency of capacity with additional planned resources.”
Supply Plan Narrative, Section 3.G. (Loads and Resources Tables);
Technical Appendix Item ECON-6
NAC 704.945 2 2. Requires “a graph must be included for the preferred plan of the utility showing, over the 20-year planning period:
NAC 704.945 2a (a) The total resources requirements; Supply Plan Narrative, Section 3.F.
(Selection of Preferred Plan, Figure EA-14 (Preferred Plan 2019-2038))
NAC 704.945 2b (b) The total demand without new programs for conservation and demand management;
Supply Plan Narrative, Section 3.F. (Selection of Preferred Plan, Figure EA-15
(Preferred Plan 2019 - 2038 - NO DSM/ACLM))
NAC 704.945 2c (c) The total demand with new programs for conservation and demand management;
Supply Plan Narrative, Section 3.F. (Selection of Preferred Plan, Figure EA-
214(Preferred Plan 2019-2038))
NAC 704.945 2d (d) The total capacity with additional planned resources; and
Supply Plan Narrative, Section 3.F. (Selection of Preferred Plan, Figure EA-14
(Preferred Plan 2019 - 2038))
NAC 704.945 2e (e) The total capacity without additional resources.
Supply Plan Narrative, Section 3.F. (Selection of Preferred Plan, Figure EA-16 (Preferred Plan 2019-2038 - No Planned
Resources))
NAC 704.945 3
3. requires “a graph must be included for the preferred plan that shows, for each year of the 20-year planning period, the excess or required capacity both with and without the additional planned resources.”
Supply Plan Narrative, Section 3.F. (Selection of Preferred Plan, Figure EA-14
(Preferred Plan 2019 - 2038) and Figure EA-16 (Preferred Plan 2019 - 2038 - No
Planned Resources))
NAC 704.945 4
4. Requires “a graph or table must be provided that shows the allocation of the capacity of the transmission system of the utility between bundled retail transmission customers, unbundled retail transmission customers and wholesale transmission
Supply Plan Narrative, Section 3.G. (Loads and Resources Tables); Technical Appendix
Item ECON 6.
NAC 704.9465
NAC 704.9465 Integrated analysis to establish priorities among options; consideration of results as basis for preferred plan. (NRS 703.025, 704.210, 704.741)
NAC 704.9465 1 1. requires “the utility shall perform an analysis integrating:
NAC 704.9465 1a (a) Planning based on demand; Supply Plan Narrative, Section 3.F.
(Selection of the Preferred Plan)
NAC 704.9465 1b (b) Planning based on supply; Supply Plan Narrative, Section 3.F.
(Selection of the Preferred Plan)
19 Page 61 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9465 1c (c) Financial planning; and Supply Plan Narrative, Section 3.F.
(Selection of the Preferred Plan)
NAC 704.9465 1d (d) Planning to meet other applicable regulatory constraints.
Supply Plan Narrative, Section 3.F. (Selection of the Preferred Plan)
NAC 704.9465 2
2. States that “the primary function of the integrated analysis is to establish priorities among the utility's options for demand and supply so that the utility can demonstrate the minimum costs of providing electric energy to its customers.”
Supply Plan Narrative, Section 3.F. (Selection of the Preferred Plan)
NAC 704.9465 3
3. requires that “the utility shall consider the results of the integrated analysis as a basis for its preferred plan along with the other selection criteria set forth in NAC 704.937.”
Supply Plan Narrative, Section 3.F. (Selection of the Preferred Plan)
NAC 704.9475 NAC 704.9475 Analysis of sensitivity for major assumptions and estimates used in resource plan. (NRS 703.025, 704.210, 704.741)
NAC 704.9475 1 1. requires that “a utility shall conduct an analysis of sensitivity for all major assumptions and estimates used in its resource plan. The analysis must include
NAC 704.9475 1a (a) Forecast of peak demand and energy consumption; Supply Plan Narrative,
Section 3.D. (Plan Development); Technical Appendix Item ECON-6
NAC 704.9475 1b (b) Dates when proposed acquisitions will be in service;
Supply Plan Narrative, Section 3.D. (Plan Development);
Technical Appendix Item ECON-6
NAC 704.9475 1c (c) Unit availability; Technical Appendix Items GEN-1 (Unit
Characteristics Table) and ECON-4 (Energy Mix for all Cases)
NAC 704.9475 1d (d) Costs of power plants; Technical Appendix Item GEN-2 (New
Generation Performance and Cost NAC 704.9475 1e (e) Prices of fuel; Technical Appendix Items FPP-1
NAC 704.9475 1f (f) Amounts of purchased power and corresponding costs;
Supply Plan Narrative, Section 3.E. (Economic Analysis Results)
NAC 704.9475 1g (g) Schedule, impact and costs of programs for conservation and demand management;
DSM Narrative and Technical Appendices; Technical Appendix Item LF-1
NAC 704.9475 1h (h) Capacity of plants in megawatts; Technical Appendix Item GEN-1 (Unit
Characteristics Table)
NAC 704.9475 1i (i) Discount rates; Supply Plan Narrative, Section 4.F.
(Common Methodologies / Assumptions)
NAC 704.9475 1j (j) Rate of inflation; Supply Plan Narrative, Section 4.F.
(Common Methodologies / Assumptions)
NAC 704.9475 1k (k) Cost of capital; Supply Plan Narrative, Section 4.F.
(Common Methodologies / Assumptions)
NAC 704.9475 1l (l) Environmental costs; and
Supply Plan Narrative, Section 3.E. (Economic Analysis Results);
Supply Plan Narrative, Section 3.H. (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix Item ECON-12 (NERA
Report)
20 Page 62 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9475 1m (m) Economic benefit.”
Supply Plan Narrative, Section 3.E. (Economic Analysis Results);
Supply Plan Narrative, Section 3.H. (Environmental Externalities and Net
Economic Benefits to the State); Technical Appendix Item ECON-12 (NERA
Report)
NAC 704.9475 2
2. requires that “the utility shall state the ranges and consequences of uncertainty for each of the assumptions and describe methods of combining various uncertainties.”
Supply Plan Narrative, Section 3.B. (Analysis Methodology, Figure EA-1 Sensitivities Conducted for Economic
Analysis)
NAC 704.948 NAC 704.948 Analysis of decisions (NRS 703.025, 704.210, 704.741)
NAC 704.948 1 1. requires that “a utility shall analyze its decisions, taking into account its assessment of risk and identifying particular risks with respect to:
Supply Plan Narrative, Section 3.F (Selection of Preferred Plan)
NAC 704.948 1a (a) Costs; Supply Plan Narrative, Section 3.F
(Selection of Preferred Plan)
NAC 704.948 1b (b) Reliability; Supply Plan Narrative, Section 3.F
(Selection of Preferred Plan)
NAC 704.948 1c (c) Finances; Supply Plan Narrative, Section 3.F
(Selection of Preferred Plan)
NAC 704.948 1d (d) The volatility of the price of purchased power and fuel; and
Supply Plan Narrative, Section 3.F (Selection of Preferred Plan)
NAC 704.948 1e (e) Any other uncertainties the utility has identified. Supply Plan Narrative, Section 3.F
(Selection of Preferred Plan)
NAC 704.948 2
2. requires that “the utility's analysis must address the relationship among the factors used in making the utility's decision, including the relationship between mitigating risk, minimizing cost and volatility, and maximizing reliability.”
Supply Plan Narrative, Section 3.F (Selection of Preferred Plan)
NAC 704.9482
NAC 704.9482 Requirements for energy supply plan, purchased power procurement plan, fuel procurement plan and risk management strategy; consistency with action plan; annual filings (NRS 703.025, 704.210, 704.741)
NAC 704.9482 1
1. requires that “the resource plan of a utility must contain an energy supply plan for the 3 years covered by the action plan of the utility. The resource plan of a utility must be consistent with the action plan of the utility.”
Energy Supply Plan Volume
NAC 704.9482 2 2. requires that “an energy supply plan must be developed by a utility using its base forecast and target planning reserve margin.”
Energy Supply Plan Volume, Section 2.A (Power and Fuel Requirements); Figures
ESP-1, ESP-4A, ESP-4B, ESP 4C (2019 - 2021 Loads and Resources)
NAC 704.9482 3
3. requires that “as part of its energy supply plan, a utility shall develop a purchased power procurement plan. The purchased power procurement plan of a utility must include, without limitation:
Energy Supply Plan Volume, Section 4 (Power Procurement Plan)
NAC 704.9482 3a (a) The proposed mix of purchased power products by: Energy Supply Plan Volume, Section 4
(Power Procurement Plan)
NAC 704.9482 3a1 (1) Type of resource; Energy Supply Plan Volume, Section 4
(Power Procurement Plan)
NAC 704.9482 3a2 (2) Delivery profile; and Energy Supply Plan Volume, Section 4
(Power Procurement Plan)
NAC 704.9482 3a3 (3) The term that the utility considers appropriate for the expected demand.
Energy Supply Plan Volume, Section 4 (Power Procurement Plan)
21 Page 63 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9482 3b (b) A description of the criteria used to determine the proposed mix of power products and the material factors influencing the selection of the criteria;
Energy Supply Plan Volume, Section 4.A (Current Power Portfolio and Portfolio
Optimization Procedures)
NAC 704.9482 3c (c) The proposed schedule for procuring the purchased power products, including a description of any competitive procurement processes to be undertaken
Energy Supply Plan Volume, Section 4.B (Summary of Power Procurement Plan)
NAC 704.9482 3d (d) A regional assessment of the availability of fuel and purchased power resources for the period covered by the energy supply plan;
Energy Supply Plan Volume, Section 3 (Market Fundamentals and Price Forecasts)
NAC 704.9482 3e
(e) A projection of remaining capacity and energy requirements for each year of the period covered by the energy supply plan, after accounting for all existing resources and proposed long-term purchased power obligations;
Energy Supply Plan Volume, Section 2.A (Power and Fuel Requirements); ESP-4A, ESP-4B, ESP 4C (2019 - 2021 Loads and
Resources), Section 2.B (Capacity Requirements), Section 2.C (Energy
Requirements)
NAC 704.9482 3f (f) A description, by type and term, of each existing purchased power contract with deliveries during the period covered by the energy supply plan
Energy Supply Plan Volume, Section 4.A (Current Power Portfolio and Portfolio
Optimization Procedures)
NAC 704.9482 3g
(g) A description, by type, delivery profile and term, of the purchased power products expected to be available to the utility during the period covered by the energy supply plan.”
Energy Supply Plan Volume, Section 4.C.2 (Open Power Positions - Potential Products)
NAC 704.9482 4
4. Requires that “as part of its energy supply plan, a utility shall develop a fuel procurement plan for each fuel that the utility uses to generate at least 5 percent of its annual energy requirements. The fuel procurement plan must include, without limitation:
Energy Supply Plan Volume, Section 5.A (Physical Gas Procurement Plan), Section
6.B (Coal Supply Plan)
NAC 704.9482 4a
(a) For each year of the energy supply plan, a projection of the quantity of each fuel the utility expects to use for each generating unit owned or controlled by the utility;
Energy Supply Plan Volume, Section 2.F (Physical Gas Requirements); Figure ESP-16 (Physical Gas Supply Under Contract), Section 2.H (Coal Requirements); Figure
ESP-17 (North Valmy Coal Requirements)
NAC 704.9482 4b
(b) A description of each existing fuel contract with deliveries during the period covered by the energy supply plan, including the type of product, the quantity to be delivered, the delivery point and the term of the contract;
Energy Supply Plan Volume, Section 2.F (Physical Gas Requirements)and Section
6.A (Current Coal Purchase and Transportation Agreements)
NAC 704.9482 4c
(c) A description of the fuel products available to the utility during the period covered by the energy supply plan, including the type of product, the pricing method, the delivery point and the term of the availability of the fuel products;
Energy Supply Plan Volume, Section 3.B (Natural Gas Fundamentals), Section 3.C
(Coal Fundamentals)
NAC 704.9482 4d (d) The proposed mix of fuel products; Energy Supply Plan Volume, Section 5 (Gas Procurement Plan), Section 6 (Coal Supply
Plan)
NAC 704.9482 4e (e) A description of the criteria used to determine the proposed mix of products and the material factors influencing the selection of the criteria;
Energy Supply Plan Volume, Section 5 (Gas Procurement Plan), Section 6 (Coal Supply
Plan)
NAC 704.9482 4f (f) The proposed schedule for procurement of the fuel, including a description of any competitive procurement process to be undertaken.”
Energy Supply Plan Volume, Section 5 (Gas Procurement Plan), Section 6 (Coal Supply
Plan)
NAC 704.9482 5 5. requires that “as part of its energy supply plan, a utility shall include a risk management strategy that includes, without limitation:
Energy Supply Plan Volume, Section 7 (Risk Management Strategy)
NAC 704.9482 5a (a) A description of how the risk management strategy was reflected in the determination of the energy supply plan proposed by the utility;
Energy Supply Plan Volume, Section 7.B (Risk Management Strategy)
22 Page 64 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9482 5b
(b) A description of the criteria used to select the proposed risk management strategy and identification of the material factors that influenced the selection of the criteria by the utility;
Energy Supply Plan Volume, Section 7.C (Selection Criteria)
NAC 704.9482 5c (c) A description of each technique for mitigating risk that was considered;
Energy Supply Plan Volume, Section 7.A (Elements of the Strategy)
NAC 704.9482 5d (d) The criteria to be used to evaluate the effectiveness of the risk management strategy.”
Energy Supply Plan Volume, Section 7.D (Evaluation Criteria)
NAC 704.9482 6
6. requires that “a utility shall annually file with the Commission an evaluation of its purchased power procurement plan, its fuel procurement plan, its risk management strategy and, if applicable, the results of any performance-based methodology for the recovery of costs for natural gas for each year included in its deferred energy application filed pursuant to NAC 704.023 to 704.195, inclusive.”
See Docket Nos. 18-03002 and 18-03003
NAC 704.9482 7 7. requires “the energy supply plan of a utility must include a technical appendix that conforms to NAC 704.922.”
Energy Supply Plan Volume, Technical Appendix Volume(s)
NAC 704.9484 NAC 704.9484 Critical facility: Procedure and purpose for designation; financial incentives (NRS 703.025, 704.210, 704.741)
NAC 704.9484 1
1. states that “the Commission may, upon the request of a utility or an intervening party pursuant to subsection 2 or upon its own motion, make a determination as to whether to designate a facility of the utility as a critical facility. Such a determination may be made in conjunction with an order issued by the Commission pursuant to subsection 1 of NAC 704.9494 or in another proceeding on the matter.”
Not Applicable
NAC 704.9484 2
2. states that “a utility and any party granted intervener status may request that the Commission designate a facility of the utility as a critical facility for the purpose of:
Not Applicable
NAC 704.9484 2a (a) Protecting reliability; Not Applicable
NAC 704.9484 2b (b) Promoting diversity of supply and demand side sources;
Not Applicable
NAC 704.9484 2c (c) Developing renewable energy resources; Not Applicable NAC 704.9484 2d (d) Fulfilling specific statutory mandates; Not Applicable NAC 704.9484 2e (e) Promoting retail price stability; or Not Applicable NAC 704.9484 2f (f) Any combination of paragraphs (a) to (e), inclusive. Not Applicable
NAC 704.9484 2g
Such a request must be accompanied by supporting analysis and documentation.
Not Applicable
NAC 704.9484 3
3. states that “if the Commission designates a facility as a critical facility, the utility may request that incentives associated with that facility be included in rates in an application to change general rates filed pursuant to NAC 703.2201 to 703.2481, inclusive. The incentives may include, without limitation:
Not Applicable
NAC 704.9484 3a (a) Earning an enhanced return on equity on the designated critical facility over the life of the facility;
Not Applicable
NAC 704.9484 3b (b) The inclusion in the rates of construction work in progress associated with the designated facility; and
Not Applicable
NAC 704.9484 3c
(c) Designating costs incurred to construct the designated critical facility in a regulatory asset account, to be recorded as a subaccount to Account 182.3 (Other Regulatory Assets). The utility may recover the regulatory asset pursuant to subsection 3 of NAC 704.9523.”
Not Applicable
23 Page 65 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9486
NAC 704.9486 Performance-based methodology for recovery of costs for natural gas used as fuel for generation: Proposal for establishment; report of results (NRS 703.025, 704.210, 704.741)
NAC 704.9486 1
1. states that “as part of its energy supply plan, a utility may propose the establishment of a performance-based methodology for the recovery of costs for natural gas used as a fuel for generation. Any proposed performance methodology must be based upon objective standards and criteria.
The Companies are not proposing the establishment of a performance-based
methodology for the recovery of costs for natural gas used as a fuel for generation.
NAC 704.9486 2
2. requires that “a proposal for the establishment of a performance-based methodology for the recovery of costs for natural gas must include information sufficient to enable the Commission to evaluate the proposal, including, without limitation:
The Companies are not proposing the establishment of a performance-based
methodology for the recovery of costs for natural gas used as a fuel for generation.
NAC 704.9486 2a (a) The criteria to be used in measuring the performance of the utility;
The Companies are not proposing the establishment of a performance-based
methodology for the recovery of costs for natural gas used as a fuel for generation.
NAC 704.9486 2b (b) The rationale for using the selected criteria;
The Companies are not proposing the establishment of a performance-based
methodology for the recovery of costs for natural gas used as a fuel for generation.
NAC 704.9486 2c (c) If appropriate, the proposed sharing allocation between the utility and its consumers;
The Companies are not proposing the establishment of a performance-based
methodology for the recovery of costs for natural gas used as a fuel for generation.
NAC 704.9486 2d (d) The duration of the program; and
The Companies are not proposing the establishment of a performance-based
methodology for the recovery of costs for natural gas used as a fuel for generation.
NAC 704.9486 2e (e) Supporting documentation.”
The Companies are not proposing the establishment of a performance-based
methodology for the recovery of costs for natural gas used as a fuel for generation.
NAC 704.9486 3
3. requires “if the Commission authorizes a performance-based methodology, the utility shall report the results of the methodology approved by the Commission in the deferred energy application filed by the utility pursuant to NAC 704.023 to 704.195, inclusive. At a minimum, the report must cover the period between the adjustment date for the most recent deferred energy application and the adjustment date for the application which includes the report of the results of the approved methodology.”
The Companies are not proposing the establishment of a performance-based
methodology for the recovery of costs for natural gas used as a fuel for generation.
NAC 704.9486 4 states that “as used in this section, ‘adjustment date’ has the meaning ascribed to it in NAC 704.024.
The Companies are not proposing the establishment of a performance-based
methodology for the recovery of costs for natural gas used as a fuel for generation.
NAC 704.9489 NAC 704.9489 Requirements for Action Plan (NRS 703.025, 704.210, 704.741)
NAC 704.9489 1
1. Requires “resource plan of a utility must include a detailed action plan based on an integrated analysis of the demand side plan and supply plan of the utility. In its action plan, the utility shall specify all its actions that are to take place during the 3 years commencing with the year following the year in which the resource plan is filed. The action plan must contain:
24 Page 66 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9489 1a (a) An introductory section that explains how the action plan fits into the longer-term strategic plan of the utility;
Action Plan, Section I. (Introduction)
NAC 704.9489 1b (b) a list of actions for which the utility is seeking the approval of the Commission;
Action Plan, Section II. (List of Actions)
NAC 704.9489 1c (c) A schedule for the acquisition of data , including planned activities to update and refine the quality of the data used in forecasting;
Action Plan, Section III. (Load Forecasting Data Acquisition)
NAC 704.9489 1d (d) A specific timetable for acquisition of options for the supply of electric energy and for programs for conservation and demand management;
Action Plan, Section IV. (Timetable and Budget for Programs)
NAC 704.9489 1e
(e) If changes in the methodology are being proposed, a description fully justifying the proposed changes, including an analysis of the costs and benefits. Any changes in methodology that are approved by the Commission must be maintained for the period described in the action plan;
No changes in planning methodology are being proposed.
NAC 704.9489 1f (f) A section describing any plans of the utility to acquire additional modeling instruments;
The Company is not proposing to acquire new modeling instruments.
NAC 704.9489 1g (g) A section for the utility's program for conservation and demand management, including:
NAC 704.9489 1g1 (1) A description of continued planning efforts; Action Plan VII. (Demand Side Plan
Programs)
NAC 704.9489 1g2 (2) A plan to carry out and continue selected measures for conservation and demand management that have been identified as desirable; and
Action Plan, Section VII. (Demand Side Plan Programs)
NAC 704.9489 1g3 (3) Any impacts of imputed debt calculations associated with energy efficiency contracts in the preferred plan.
Action Plan, Section VII. (Demand Side Plan Programs)
NAC 704.9489 1h (h) A section for the utility's program for acquisition of resources for the supply of electric energy for the period covered by the action plan, including:
NAC 704.9489 1h1 (1) The immediate plans of the utility for construction of facilities or long-term purchases of power;
Action Plan, Section VIII. (Acquisition of Resources)
NAC 704.9489 1h2 (2) The expected time for construction of facilities and acquisition of long-term purchases of power identified in subparagraph (1);
Not Applicable.
NAC 704.9489 1h3 (3) The major milestones of construction ; and Not Applicable.
NAC 704.9489 1h4 (4) Any impacts of imputed debt calculations associated with renewable energy contracts or energy efficiency contracts in the preferred plan.
Action Plan, Section VIII. (Acquisition of Resources)
NAC 704.9489 2 2. requires that “the action plan must contain an energy supply plan.”
Action Plan, Section II. (List of Actions)
NAC 704.9489 3
3. requires that “the action plan must contain a budget for planned expenditures suitable for comparing planned and achieved expenditures. Expenses must be listed in a format that is consistent with the categories and periods to be presented in subsequent filings . The budget must be organized in the following categories:
Action Plan, Section IV
NAC 704.9489 4
requires “the action plan must contain schedules suitable for comparing planned and actual activities and accomplishments. Milestones and points of decision committing major expenditures must be shown.”
Action Plan, Section IV
25 Page 67 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9489 5
The action plan must contain a renewable energy zone transmission action plan for serving one or more of the renewable energy zones designated by the Commission or an explanation of why no renewable energy zone transmission action plan is contained in the action plan. In addition to the other action plan requirements set forth in this section, the renewable energy zone transmission action plan must include, with supporting data and documentation, for each action item recommended by the utility:
NAC 704.9489 5(a)
The action plan must contain a renewable energy zone transmission action plan for serving one or more of the renewable energy zones designated by the Commission or an explanation of why no renewable energy zone transmission action plan is contained in the action plan. In addition to the other action plan requirements set forth in this section, the renewable energy zone transmission action plan must include, with supporting data and documentation, for each action item recommended by the utility:
NAC 704.9489 5(a)(1) How such expenditures will facilitate compliance with NRS 704.7821 in a manner consistent with NAC 704.8901 to 704.8937, inclusive; and
Action Plan, Section IX
NAC 704.9489 5(a)(2) All other benefits Nevada retail ratepayers will derive from the expenses;
Action Plan, Section IX
NAC 704.9489 5(b) For proposed construction and expansion of transmission facilities:
NAC 704.9489 5(b)(1)
Evidence of how the proposed construction and expansion will facilitate compliance with NRS 704.7821 in a manner consistent with NAC 704.8901 to 704.8937, inclusive;
Action Plan, Section IX
NAC 704.9489 5(b)(2)
A listing and description, including detailed cost estimates and development schedules, of the transmission facilities recommended by the utility for construction or expansion;
Action Plan, Section IX
NAC 704.9489 5(b)(3) A listing and description of transmission alternatives that were considered by the utility, including transmission development partnerships;
Action Plan, Section IX
NAC 704.9489 5(b)(4)
Data and economic analysis that supports the transmission projects recommended by the utility, including, without limitation, a comparison of the levelized cost, including transmission, of procuring renewable resources from the renewable energy zones proposed to be served by the utility’s recommended transmission projects to other renewable resource options, including those that are located in and out of renewable energy zones designated by the
Action Plan, Section IX
NAC 704.9489 5(b)(5) Evidence of the financial commitments from developers of renewable energy projects located in the affected renewable energy zones;
Action Plan, Section IX
NAC 704.9489 5(b)(6)
An estimate of the level of capacity and energy that the utility expects to utilize from the affected renewable energy zones in the next 20 years, commencing with the year following the year in which the resource plan is filed; and
Action Plan, Section IX
NAC 704.9489 5(b)(7) The estimated time frame to fully utilize the capacity of the construction and expansion of transmission facilities recommended by the utility; and
Action Plan, Section IX
26 Page 68 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9489 5(c)
In addition to the renewable energy zone transmission action plan requirements set forth in paragraph (b), for construction and expansion of transmission infrastructure that will serve both Nevada retail ratepayers and export markets outside of Nevada:
NAC 704.9489 5(c)(1)
Evidence that any renewable energy developers wishing to export energy outside of Nevada have a buyer for their energy and that the buyer has a means of delivering the energy from the transmission system of the Nevada utility to the point of delivery;
Action Plan, Section IX
NAC 704.9489 5(c)(2)
A strategic plan to mitigate the potential financial risks to Nevada retail ratepayers associated with stranded investment and infrastructure that is not intended to provide service to Nevada retail ratepayers, including, without limitation, safeguards to monitor the financial risk to Nevada’s retail ratepayers and criteria to trigger an amendment to the renewable energy transmission action plan should changes in circumstance occur which could expose Nevada retail ratepayers to such risks; and
Action Plan, Section IX
NAC 704.9489 5(c)(3)
Identification of the potential resources in the renewable energy zones, including the resources under contract, resources under development, known completion dates and the known amount of capacity and energy to be produced by renewable energy projects in the affected renewable energy zones for customers outside of Nevada.
Action Plan, Section IX
NAC 704.9489 6
The action plan must include the surplus asset retirement plan required by section 12 of Senate Bill No. 416, chapter 395, Statutes of Nevada 2015, at page 2215, for each asset that has been classified as sur1plus by the utility pursuant to section 10 of Senate Bill No. 416, chapter 395, Statutes of Nevada 2015, at page 2214, or reclassified as surplus by the Commission pursuant to section 11 of Senate Bill No. 416, chapter 395, Statutes of Nevada 2015, at page
NAC 704.9492
NAC 704.9492 Rates for long-term avoided cost: Inclusion of certain information in resource plan; estimation; specification of proposed limits concerning availability (NRS 703.025, 704.210, 704.741)
NAC 704.9492 1
1. requires that “a utility shall file, as part of its resource plan, the methodology for estimating the rates for long-term avoided cost of the utility, including the capacity and energy components. The rates for long-term avoided cost must be based upon the utility's preferred plan and be consistent with 18 C.F.R. § 292.304(a), (b), (c) and (e).”
Supply Plan Narrative, Section 3.I. (Long-Term Avoided Cost Methodologies)
NAC 704.9492 2 2. requires that “the estimated rate for long-term avoided cost must be established for various sizes of megawatt blocks, except that:
Supply Plan Narrative, Section 3.I. (Long-Term Avoided Cost Methodologies)
NAC 704.9492 2a (a) If the utility has a peak demand of at least 1,000 megawatts, the stated blocks must not exceed 100 megawatts; and
Supply Plan Narrative, Section 3.I. (Long-Term Avoided Cost Methodologies)
NAC 704.9492 2b (b) If the utility has a peak demand of less than 1,000 megawatts, the stated blocks must not exceed 10 percent of the system peak.
Supply Plan Narrative, Section 3.I. (Long-Term Avoided Cost Methodologies)
27 Page 69 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9492 3
3. requires that “the components for estimated long-term avoided cost capacity and energy rate must be stated on a cents per kilowatt-hour basis for daily and seasonal peak and off-peak periods and in such a manner that rates for various contract periods may be calculated. At a minimum, the utility shall provide estimated rates for long-term avoided cost for a 20-year contract and the long-term avoided cost by year for 5 years commencing in the year following the filing of the resource plan.”
Supply Plan Narrative, Section 3.I. (Long-Term Avoided Cost Methodologies)
NAC 704.9492 4
4. requires that “in developing the estimated rates for long-term avoided cost, the proposed rates must not be applied to renewable energy or to energy that is subject to the qualified energy recovery process as defined in NRS 704.7809.”
Supply Plan Narrative, Section 3.I. (Long-Term Avoided Cost Methodologies)
NAC 704.9492 5 5. requires that “the utility shall specify its proposed limits concerning the availability of the rates for long-term avoided cost.”
Supply Plan Narrative, Section 3.I. (Long-Term Avoided Cost Methodologies)
NAC 704.9492 6 6. requires that “the resource plan of the utility must include the analyses and calculations used to determine the proposed rates.”
Supply Plan Narrative, Section 3.I. (Long-Term Avoided Cost Methodologies)
NAC 704.9492 7
7. requires that “the resource plan must include a description of the methodology that will be used to derive the rates for long-term avoided costs from the solicitation of proposals performed pursuant to subsection 5 of NAC 704.9496.”
Supply Plan Narrative, Section 3.I. (Long-Term Avoided Cost Methodologies)
NAC 704.9494
NAC 704.9494 Approval of action plan; determination that elements of energy supply plan are prudent; recovery of costs to carry out approved plans (NRS 703.025, 704.210, 704.741, 704.751)
NAC 704.9494 1 1. states that “the Commission will issue an order: NAC 704.9494 1a (a) Approving the action plan of the utility as filed; or Not Applicable
NAC 704.9494 1b (b) If the plan is not approved as filed, specifying those parts of the action plan the Commission considers inadequate.”
Not Applicable
NAC 704.9494 2
2. states that “approval by the Commission of an action plan constitutes a finding that the programs and projects contained in that action plan, other than the energy supply plan, are prudent, including, without limitation, construction of facilities, purchased power obligations, programs for conservation and demand management and impacts of imputed debt calculations associated with renewable energy contracts or energy efficiency contracts. If the Commission subsequently determines that any information relied upon when issuing its order approving the action plan was based upon information that was known or should have been known by the utility to be untrue or false at the time the information was presented, the Commission may revoke, rescind or otherwise modify its approval of the
Not Applicable
NAC 704.9494 3
3. states that “if, at the time that the Commission approves the action plan of the utility, the Commission determines that the elements of the energy supply plan are prudent, the Commission will specifically include in the approval of the action plan its determination that the elements contained in the energy supply plan are prudent. For the Commission to make a determination that the elements of the energy supply plan are
Not Applicable
28 Page 70 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9494 3a
(a) The energy supply plan must not contain any feature or mechanism that the Commission finds would impair the restoration of the creditworthiness of the utility or would lead to a deterioration of the creditworthiness of the utility.
Energy Supply Plan Volume, Section 8 (Determination of Prudence), see the Energy
Supply Plan Testimony of Mr. Cole Q&A 22
NAC 704.9494 3b (b) The energy supply plan must optimize the value of the overall supply portfolio for the utility for the benefit of its bundled retail customers.
Energy Supply Plan Volume, Section 4.A (Current Power Portfolio and Portfolio
Optimization Procedures), see the Energy Supply Plan Testimony of Mr. Taylor
NAC 704.9494 3c
(c) The utility must demonstrate that the energy supply plan balances the objectives of minimizing the cost of supply, minimizing retail price volatility and maximizing the reliability of supply over the term of the plan.
Energy Supply Plan Volume, Section 8 (Determination of Prudence), see the Energy
Supply Plan Testimony of Mr. Reyes
NAC 704.9494 3e
Failure by a utility to demonstrate that its energy supply plan is prudent in accordance with this subsection does not otherwise affect approval of the action plan, including the energy supply plan, and the utility may subsequently seek a determination that the energy supply plan is prudent in the appropriate deferred energy proceeding.”
Not Applicable
NAC 704.9494 4
4. states that “a utility may recover all costs that it prudently and reasonably incurs in carrying out an approved action plan in the appropriate separate rate proceeding. A utility may recover all costs that are prudently and reasonably incurred in carrying out the approved energy supply plan, including deviations pursuant to subsection 1 of NAC 704.9504 approved by the Commission in the appropriate deferred energy application filed pursuant to NAC 704.023 to 704.195, inclusive.”
Not Applicable
NAC 704.9496
NAC 704.9496 Estimated rates for long-term avoided cost: General requirements; action by Commission; solicitation of proposals. (NRS 703.025, 704.210, 704.741)
NAC 704.9496 1
1. states that “in conjunction with its order on the action plan, the Commission will issue an order addressing the utility's proposed estimated rates for long-term avoided cost, including the methodology and limits to be used by the utility for its filing pursuant to NAC 704.9492. The Commission will consider the factors listed in 18 C.F.R. § 292.304(a), (b), (c) and (e) in its evaluation of the utility's proposed estimated rates for long-term avoided cost.”
Not Applicable at time of filing.
NAC 704.9496 2
2. requires that “the utility shall file with the Commission the utility's estimated rates for long-term avoided cost within 60 days after the Commission issues its order pursuant to subsection 1 specifying the methodology for estimating the rates for long-term avoided cost.”
Not Applicable at time of filing.
NAC 704.9496 3 3. requires that “the estimated rates for long-term avoided cost filed by the utility with the Commission pursuant to subsection 2 must:
NAC 704.9496 3a
(a) Be consistent with the methodology for estimating the long-term avoided cost approved by the Commission and be based upon the resource plan approved by the Commission;
Not Applicable at time of filing.
29 Page 71 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9496 3b
(b) Unless otherwise ordered by the Commission, be consistent with the format set forth in subsections 2 and 3 of NAC 704.9492 and be limited to those rates proposed by the utility pursuant to subsection 5 of NAC 704.9492.”
Not Applicable at time of filing.
NAC 704.9496 4
4. states that “if required, the Commission will hold a hearing on the estimated rates for long-term avoided cost within 90 days after the utility files the estimated rates for long-term avoided cost pursuant to subsection 2. If a hearing is held, the Commission will issue an order on the matter within 45 days after the conclusion of the hearing.”
Not Applicable at time of filing.
NAC 704.9496 5
5. states that “Within 30 days after the date on which the Commission issues an order pursuant to subsection 4, the utility shall solicit proposals to provide the utility capacity or energy, or both, in a manner that complies with the methodology for estimating long-term avoided cost approved by the Commission.”
Not Applicable at time of filing.
NAC 704.9496 6
6. requires that “within 90 days after issuing a solicitation of proposals pursuant to subsection 5, the utility shall file with the Commission a report concerning the results of the solicitation.”
Not Applicable at time of filing.
NAC 704.9496 7
7. requires that “the utility's rate for long-term avoided cost for each block must be the estimated rate for long-term avoided cost established pursuant to this section or the competitive rate solicited pursuant to subsection 5, whichever is lower.”
Not Applicable at time of filing.
NAC 704.9498 NAC 704.9498 Report on progress of action plan: Filing; service; contents; form; hearing. (NRS 703.025, 704.210, 704.741)
NAC 704.9498 1
1. requires that “not earlier than 15 months and not later than 21 months after the date on which the utility files its action plan, the utility shall file a report on the progress of its action plan with the Commission and serve a copy of the progress report on all parties of record. The progress report must include:
Not Applicable at time of filing.
NAC 704.9498 1a (a) Information concerning the status of planned facilities approved by the Commission, including any cost or schedule variances;
Not Applicable at time of filing.
NAC 704.9498 1b
(b) Information concerning the status of all programs for conservation and demand management, including planned and achieved reductions in kilowatt-hours and reduction in demand in kilowatt-hours;
Not Applicable at time of filing.
NAC 704.9498 1c (c) A comparison of budgeted and actual costs for the entire action plan;
Not Applicable at time of filing.
NAC 704.9498 1d (d) An identification of and justification for any significant deviation from the approved action plan, including supporting information;
Not Applicable at time of filing.
NAC 704.9498 1e (e) An updated forecast of energy consumption and peak demand; and
Not Applicable at time of filing.
NAC 704.9498 1f (f) An updated table for loads and resources for the remaining years covered by the 20-year plan.”
Not Applicable at time of filing.
NAC 704.9498 2 2. requires that “the progress report must be in the same form as the action plan and will be assigned a new docket number by the Commission.”
Not Applicable at time of filing.
NAC 704.9498 3
3. requires “the utility or any party of record may request a hearing on the progress report, specifying in its request the reason the utility or party believes a hearing is required. Upon a finding of good cause, the Commission will order a hearing on the matter.”
Not Applicable at time of filing.
30 Page 72 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9503 NAC 704.9503 Monitoring and amendment of action plan. (NRS 703.025, 704.210, 704.741)
NAC 704.9503 1 requires “a utility shall continually monitor its action plan and shall amend the plan before it submits its next action plan if any of the following circumstances exist:
Not Applicable at time of filing.
NAC 704.9503 1a
(a) The utility anticipates submitting an application for a permit to construct a utility facility pursuant to NRS 704.820 to 704.900, inclusive, which was not previously approved as part of the action plan.
Not Applicable at time of filing.
NAC 704.9503 1b (b) The utility makes a commitment for the acquisition or construction of a facility that was not previously approved as part of the action plan.
Not Applicable at time of filing.
NAC 704.9503 1c (c) The utility makes a commitment for a long-term purchased power obligation which was not previously approved as part of the action plan.
Not Applicable at time of filing.
NAC 704.9503 1d
(d) The utility is unable to place a resource in service or secure a resource in accordance with the schedule for the resource that is included in the action plan approved by the Commission and the modified schedule results in a significant deviation from the planned reserve margin for any period in the 3-year
Not Applicable at time of filing.
NAC 704.9503 1e (e) The utility makes a commitment for an option that was not available at the time the action plan was approved.
Not Applicable at time of filing.
NAC 704.9503 1f
(f) The basic data used in the formation of the plan requires significant modification that affects the choice of a resource which was approved as part of the action plan.”
Not Applicable at time of filing.
NAC 704.9503 2 2. states that “the conditions under which an amendment is sought must be specifically set forth in the application for amendment.”
Not Applicable at time of filing.
NAC 704.9504 NAC 704.9504 Deviation from and amendment of energy supply plan. (NRS 703.025, 704.210, 704.741)
NAC 704.9504 1
states that “notwithstanding the approval by the Commission of the energy supply plan of a utility, the utility may deviate from the approved energy supply plan to the extent necessary to respond adequately to any significant change in circumstances not contemplated by the energy supply plan. A significant change in circumstances includes, without limitation:
NAC 704.9504 1a (a) A material change in the market price of fuel or purchased power;
The Company acknowledges in the Energy Supply Plan Volume, Section 2.D.5 that it
may deviate from its approved energy supply plan.
NAC 704.9504 1b (b) An extended forced outage of a major generating unit of the utility;
The Company acknowledges in the Energy Supply Plan Volume, Section 2.D.5 that it
may deviate from its approved energy supply plan.
NAC 704.9504 1c (c) A material change in customer demand; and
The Company acknowledges in the Energy Supply Plan Volume, Section 2.D.5 that it
may deviate from its approved energy supply plan.
NAC 704.9504 1d (d) Any other circumstance that the utility demonstrates to the Commission warrants a deviation.”
The Company acknowledges in the Energy Supply Plan Volume, Section 2.D.5 that it
may deviate from its approved energy supply plan.
NAC 704.9504 2 2. states that “if a utility deviates from its approved energy supply plan:
31 Page 73 of 260
Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9504 2a (a) The utility shall, as soon as practicable, inform the staff of the deviation from the energy supply plan;
The Company will comply with the requirements of NAC § 704.9504(2) if it
deviates from the approved Energy Supply Plan.
NAC 704.9504 2b
(b) The utility shall include in the deferred energy application filed pursuant to NAC 704.023 to 704.195, inclusive, in which costs associated with the deviation are first sought to be recovered, a description of and justification for the deviation;
The Company will comply with the requirements of NAC § 704.9504(2) if it
deviates from the approved Energy Supply Plan.
NAC 704.9504 2c
(c) The Commission will determine on a retrospective factual basis the prudence of the deviation from the energy supply plan in the appropriate proceeding held on the deferred energy application;
The Company will comply with the requirements of NAC § 704.9504(2) if it
deviates from the approved Energy Supply Plan.
NAC 704.9504 2d
(d) If the deviation from the energy supply plan is of a continuing nature, the utility shall seek authority from the Commission to deviate prospectively from the energy supply plan in an update of the energy supply plan filed pursuant to NAC 704.9506, or by filing an amendment to the energy supply plan in accordance with subsection 3.”
The Company will comply with the requirements of NAC § 704.9504(2) if it
deviates from the approved Energy Supply Plan.
NAC 704.9504 3 3. requires that “an amendment to the energy supply plan of a utility must contain:
NAC 704.9504 3a (a) A section that identifies the specific approvals requested by the utility in the amendment;
The Company will comply with the requirements of NAC § 704.9504(3) should it file an amendment to the Energy Supply
Plan.
NAC 704.9504 3b (b) A section that specifies any changes in assumptions or data that have occurred since the utility's last resource plan was filed; and
The Company will comply with the requirements of NAC § 704.9504(3) should it file an amendment to the Energy Supply
Plan.
NAC 704.9504 3c (c) As applicable, information required in subsections 1 to 5, inclusive, and 7 of NAC 704.9482.
The Company will comply with the requirements of NAC § 704.9504(3) should it file an amendment to the Energy Supply
Plan.
NAC 704.9506 NAC 704.9506 Update of energy supply plan: Filing; requirements (NRS 703.025, 704.210, 704.741)
NAC 704.9506 1
1. requires that “on or before September 1 of the first and second years after the action plan of a utility is filed, the utility shall file an update of the energy supply plan that will be applicable for each year remaining in the period covered by the action plan.”
Not Applicable
NAC 704.9506 2
2. requires that “the update of the energy supply plan must comply with the requirements of subsections 1 to 5, inclusive, and 7 of NAC 704.9482, except that the load forecast must be the most recent forecast available at the time the plan is prepared.”
Not Applicable
NAC 704.9508 NAC 704.9508 Update of energy supply plan: Action by Commission (NRS 703.025, 704.210, 704.741)
NAC 704.9508 1
1. states that “the Commission will conduct a hearing within 60 days after a utility files an update of its energy supply plan pursuant to NAC 704.9506 and issue an order within 120 days after the filing of that update by the utility pursuant to NAC 704.9506.”
Not Applicable
NAC 704.9508 2 2. states that “the Commission will conduct its evaluation of the update of the energy supply plan in accordance with NAC 704.9494.”
Not Applicable
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Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9512
NAC 704.9512 Submission to Commission of certain purchased power obligations; disclosure of certain affiliate relationships (NRS 703.025, 704.210, 704.741)
NAC 704.9512 1 1. requires that “the utility shall submit to the Commission a copy of:
NAC 704.9512 1a (a) Each long-term purchased power obligation; and Supply Plan Narrative, Section 2.B
NAC 704.9512 1b
(b) Any other purchased power obligation for which the utility is seeking the approval of the Commission, to which the utility is committed or plans to become committed during the period covered by the action plan.”
Supply Plan Narrative, Section 2.D
NAC 704.9512 2
2. requires that “for any such contract that is not executed at the time the action plan is filed, the utility shall submit the contract, upon execution, to the Commission for review. The utility shall, for each such contract, disclose the existence of any affiliate relationship between the parties.”
Not Applicable
NAC 704.9514
NAC 704.9514 Preapproval of certain fuel and purchased power agreements: states that “to the extent the Commission deems appropriate, the Commission may preapprove and deem prudent fuel and purchased power agreements by a utility that are less than 3 years in duration.” (NRS 703.025, 704.210, 704.741)
Not Applicable
NAC 704.9516 NAC 704.9516 Contents of amendment to action plan (NRS 703.025, 704.210, 704.741)
NAC 704.9516 1 1. requires that “an amendment to an action plan submitted by a utility pursuant to NAC 704.9503 must contain:
Not Applicable
NAC 704.9516 1a (a) A section that identifies the items for which the utility is requesting specific approval;
Not Applicable
NAC 704.9516 1b (b) A section that specifies any changes in assumptions or data that have occurred since the utility's last resource plan was filed;
Not Applicable
NAC 704.9516 1c (c) As applicable, information required in paragraphs (d) and (e) of subsection 1 of NAC 704.9489, and subsections 3 and 4 of NAC 704.9489;
Not Applicable
NAC 704.9516 1d
(d) As applicable, data and information required pursuant to NAC 704.922 to 704.948, inclusive, necessary to facilitate an evaluation of the items specified pursuant to paragraph (a) for which the utility is requesting specific approval;
Not Applicable
NAC 704.9516 1e (e) A current peak demand forecast; Not Applicable
NAC 704.9516 1f (f) A table indicating the current loads and resources; and
Not Applicable
NAC 704.9516 1g
(g) If the utility seeks an amendment related to a renewable energy contract or energy efficiency contract, information about the imputed debt mitigation.”
Not Applicable
NAC 704.9516 2
2. requires that “for amendments submitted pursuant to paragraphs (a) and (f) of subsection 1 of NAC 704.9503, a utility shall file with the Commission the information required pursuant to paragraph (d) of subsection 1 of this section.
Not Applicable
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Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9518
NAC 704.9518 Approval of amendment to action plan or energy supply plan: states that “for amendments filed pursuant to NAC 704.9503 and in accordance with subsection 3 of NAC 704.9504, the Commission will issue an order approving the amendment as filed or specifying those parts of the amendment the Commission considers inadequate.” (NRS 703.025, 704.210, 704.741)
Not Applicable
NAC 704.952
NAC 704.952 Sessions for reviewing plans: Scheduling; procedure for resolving issues; summary of topics and conclusions; overview of anticipated filing or amendment of resource plan (NRS 703.025, 704.210, 704.741)
NAC 704.952 1 1. states that “a utility may schedule sessions for reviewing plans and providing an opportunity for interested persons to:
NAC 704.952 1a (a) Learn of progress by the utility in developing plans and amendments to plans;
Technical Appendix ECON-1, Technical Appendix DSM-1
NAC 704.952 1b (b) Determine whether key assumptions are being applied in a consistent and acceptable manner;
Technical Appendix DSM-1
NAC 704.952 1c (c) Determine whether key results are reasonable; and Technical Appendix DSM-1 NAC 704.952 1d (d) Offer suggestions on other matters as appropriate.” Technical Appendix DSM-1
NAC 704.952 2
2. states that “if the utility, the Bureau of Consumer Protection in the Office of the Attorney General, the staff or any other person participating in the process cannot agree to schedule sessions for reviewing plans, any of those persons may petition the Commission to schedule the sessions.
Not Applicable a time of filing.
NAC 704.952 3
3. states that “the parties involved in the review sessions may establish, at the beginning of the sessions, a procedure to resolve any technical issues that are discussed during the sessions.”
Not Applicable a time of filing.
NAC 704.952 4
4. states that “if review sessions are held pursuant to subsection 1, the utility shall prepare a brief summary of the major topics on the agendas and the conclusions reached by the parties during the review sessions. The summary must be provided to the Commission in conjunction with testimony supporting the utility's plan.”
Technical Appendix ECON-1, Technical Appendix DSM-1
NAC 704.952 5
5. requires that “at least 4 months before the anticipated date for filing the resource plan, the utility shall meet with staff and the personnel of the Bureau of Consumer Protection to provide an overview of the anticipated filing.
Technical Appendix Item ECON-1 (Notice of Public Meeting and Overview of the
2018 IRP)
NAC 704.952 6
6. requires that “before a utility may file an amendment to its resource plan, the utility must meet with staff and the personnel of the Bureau of Consumer Protection to provide an overview of the
Not Applicable a time of filing.
NAC 704.9522 NAC 704.9522 Measurement and verification protocol for energy efficiency measures: Duties of utility provider.
NAC 704.9522 1
1. requires that “a utility provider shall propose a measurement and verification protocol for all energy efficiency measures submitted pursuant to NAC 704.9005 to 704.9525, inclusive.
DSM Narrative Section 4, Technical Appendix DSM-4
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Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9522 2
2. requires that “the utility provider shall comply with, and shall ensure that all energy efficiency contracts entered into by the utility provider comply with, the most recent measurement and verification protocol approved by the Commission at the time an energy efficiency measure is implemented.”
Technical Appendices DSM-5 - DSM 20
NAC 704.9523
NAC 704.9523 Costs of implementing programs for conservation and demand management: Accounting; recovery. (NRS 703.025, 704.210, 704.741, 704.751)
NAC 704.9523 1
1. requires that “all costs of implementing programs for conservation and demand management must be accounted for in the books and records of a utility separately from amounts attributable to any other activity. All accounts must be maintained in a manner that will allow costs attributable to specific programs to be readily identified.”
See DSM Narrative, Section 4
NAC 704.9523 2
2. states that “a utility may, pursuant to subsection 3, recover all prudent and reasonable costs incurred in implementing programs for conservation and demand management that have been approved by the Commission as part of the action plan of the utility, including, without limitation, the costs for labor, overhead, materials, incentives paid to customers, advertising, marketing and evaluation. The utility may recover approved costs associated with monitoring and evaluating programs for conservation and demand management through a general rate case.”
See DSM Narrative, Section 4
NAC 704.9523 3 3. requires “to recover costs incurred in implementing programs for conservation and demand management, a utility must:
NAC 704.9523 3a
(a) Calculate, on a monthly basis, the costs incurred in implementing each program since the end of the test period or period of certification in its last proceeding to change general rates;
See DSM Narrative, Section 4
NAC 704.9523 3b
(b) Record the cost of implementing each program, as calculated pursuant to paragraph (a), in a separate subaccount of Account 182.3 (Other Regulatory Assets) for each program and make an appropriate offset to other subaccounts;
See DSM Narrative, Section 4
NAC 704.9523 3c
(c) Maintain subsidiary records of the subaccounts of Account 182.3 for each program. These records must clearly delineate all costs incurred by the utility in implementing each program approved by the Commission;
See DSM Narrative Section 4
NAC 704.9523 3d
(d) Apply a carrying charge at the rate of 1/12 of the authorized overall rate of return to the balance in the subaccounts of Account 182.3 for each program not included in the rate base;
See DSM Narrative, Section 4
NAC 704.9523 3e
(e) Clear any balance accumulated in the subaccounts of Account 182.3 for each program as a component of an application by the utility to change general rates as follows:
NAC 704.9523 3e1
(1) The Commission will adjust the rate to amortize the balance over a period determined by the Commission to be appropriate for clearing the account and consistent with the life of the investment.
See DSM Narrative, Section 4
NAC 704.9523 3e2 (2) The utility must begin amortizing costs on the date that the change in general rates becomes effective.
See DSM Narrative, Section 4
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Exhibit B
Code Sub-Section Description IRP Location
NAC 704.9523 3e3
(3) The utility must include the balance in the subaccounts of Account 182.3 for each program, including carrying charges, in the rate base as of the date that ends the test period used in the utility's application to change general rates or as of the date that ends the period of certification, whichever is later.
See DSM Narrative, Section 4
NAC 704.9523 3e4
(4) To calculate revenue requirements, the utility must base the rate of return to be applied to the balance in the subaccounts of Account 182.3 for each program that the utility has carried out on the authorized return on equity plus 5 percent.
See DSM Narrative, Section 4
NAC 704.9525
NAC 704.9525 Severability: states that “if any provision of NAC 704.9005 to 704.9525, inclusive, is held invalid, the Commission intends that such invalidity not affect the remaining provisions to the extent that they can be given effect.”
Not Applicable
NAC 704.8885 (2)(a thru x)
To approve a long-term portfolio energy credits contract, long-term renewable energy contract or energy efficiency contract executed by a utility provider, the Commission must determine that the terms and conditions of the contract are just and reasonable. In making its determination, the Commission will consider, as applicable and without limitation.
See IRP Technical Appendices: REN-6-DFS (c), REN-6-FSR (c), REN-6-BMS (c), REN-6-ESM (c), REN-6-TS5 (c)
and REN-6-CMS5 (c)
NAC 704.8887 (1), (2)(a thru
l), (3)
(1) For the purposes of this section, each utility provider shall calculate the price for electricity acquired or saved pursuant to a long-term portfolio energy credits contract, long-term renewable energy contract or energy efficiency contract by calculating the levelized market price for the electricity. (2) After the utility provider calculates the price pursuant to subsection 1, the Commission will determine whether the price is reasonable. (3)If a utility provider will be using a long-term portfolio energy credits contract, long-term renewable energy contract or energy efficiency contract to comply with the solar energy requirements of its portfolio standard, the price for electricity acquired pursuant to that contract will be evaluated separately from the price for electricity
See IRP Technical Appendices: REN-6-DFS (c), REN-6-FSR (c), REN-6-BMS (c), REN-6-ESM (c), REN-6-TS5 (c)
and REN-6-CMS5 (c)
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EXHIBIT C
DRAFT NOTICE
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PUBLIC UTILITIES COMMISSION OF NEVADA DRAFT NOTICE
(Applications, Tariff Filings, Complaints, and Petitions)
Pursuant to Nevada Administrative Code (“NAC”) 703.162, the Commission requires that a draft notice be included with all applications, tariff filings, complaints and petitions. Please complete and include ONE COPY of this form with your filing. (Completion of this form may require the use of more than one page.)
A title that generally describes the relief requested (see NAC 703.160(4)(a)):
Application of Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy, seeking approval to add 1001 MW of renewable power purchase agreements and 100 MW of energy storage capacity, among other items, as part of their joint 2019-2038 integrated resource plan, for the three year Action Plan period 2019-2021, and the Energy Supply Plan period 2019-2021
The name of the applicant, complainant, petitioner or the name of the agent for the applicant, complainant or petitioner (see NAC 703.160(4)(b)):
Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy.
A brief description of the purpose of the filing or proceeding, including, without limitation, a clear and concise introductory statement that summarizes the relief requested or the type of proceeding scheduled AND the effect of the relief or proceeding upon consumers (see NAC 703.160(4)(c)):
Nevada Power Company and Sierra Pacific Power Company are seeking approval of their first joint 2019-2038 Integrated Resource Plan, their three year Action Plan for 2019-2021, and their Energy Supply Plans for 2019-2021. The Application requests that the Public Utilities Commission of Nevada approves six new renewable power purchase agreements, network upgrades associated with the new renewable projects, transmission upgrades to ensure reliable service in southern Nevada and the conditional retirement of North Valmy 1 generating station.
1
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A statement indicating whether a consumer session is required to be held pursuant to Nevada Revised Statute (“NRS”) 704.069(1)1:
No. A consumer session is not required by NRS § 704.069.
If the draft notice pertains to a tariff filing, please include the tariff number AND the section number(s) or schedule number(s) being revised.
Not Applicable
1 NRS 704.069 states in pertinent part:
1. The Commission shall conduct a consumer session to solicit comments from the public in any matter pending before the Commission pursuant to NRS 704.061 to 704.110 inclusive, in which: (a) A public utility has filed a general rate application, an application to recover the increased cost of purchased fuel, purchased power, or natural gas purchased for resale or an application to clear its deferred accounts; and (b) The changes proposed in the application will result in an increase in annual gross operating revenue, as certified by the applicant, in an amount that will exceed $50,000 or 10 percent of the applicant’s annual gross operating revenue, whichever is less.
2
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SHAWN M. ELICEGUI
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy
2018 Joint Integrated Resource Plan (2019-2038) Docket No. 18-06____
PREPARED DIRECT TESTIMONY OF
Shawn M. Elicegui
I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS
AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is Shawn M. Elicegui. My current position is Senior Vice President,
Business Plan, Regulatory and Legislative Strategy for Nevada Power Company
d/b/a NV Energy (“Nevada Power”) and Sierra Pacific Power Company d/b/a NV
Energy (“Sierra,” and together with Nevada Power, the “Companies” or “NV
Energy”). My business address is 6100 Neil Road in Reno, Nevada. I am filing
testimony on behalf of the joint applicants, Nevada Power and Sierra.
2. Q. PLEASE DESCRIBE YOUR JOB RESPONSIBILITIES.
A. My responsibilities include supervision of NV Energy’s regulatory pricing,
regulatory policy, and resource planning functions, and the development of
business, regulatory, legislative and policy strategies and positions. I am also
responsible for supervising the preparation of filings with the Public Utilities
Commission of Nevada (“Commission”), including energy supply plans (“ESPs”),
integrated resource plans (“IRPs”), fuel and purchased power prudency review and
general rate review filings.
Elicegui-IRP DIRECT 1
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3. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE
UTILITY INDUSTRY.
A. I hold a Bachelor of Arts Degree with a major in Political Science and International
Affairs. The degree was conferred by the University of Nevada, Reno. I earned a
law degree from the University of California, Davis. Before joining the Companies
in 2009, I was a shareholder in the law firm of Lionel, Sawyer and Collins. Between
2009 and 2013, I served as an Associate General Counsel for the Companies,
focusing on matters related to rate making and resource planning. Since 2014, I
have held several positions with NV Energy, including positions in the customer
operations, regulatory, resource planning and strategic planning functions.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE COMMISSION?
A. Yes, I have.
5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. I explain how the Preferred Plan fits with Nevada’s energy policy, delivers the
services requested by customers, and advances NV Energy’s corporate strategy. I
provide policy testimony in support of the Preferred Plan. I also introduce each of
the witnesses providing testimony and sponsoring portions of the 2018 Joint IRP
narrative and technical appendices.
6. Q. ARE YOU SPONSORING ANY EXHIBITS?
A. Yes. I am sponsoring the following Exhibits:
Exhibit Elicegui-Direct-1 Statement of Qualifications
Exhibit Elicegui-Direct-2 Conditions and Metrics for Assessing Retirement of
North Valmy Unit 1 in December 2021
Elicegui-IRP DIRECT 2
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II. WITNESSES
7. Q. PLEASE INTRODUCE THE WITNESSES WHO PROVIDE TESTIMONY
ON BEHALF OF NV ENERGY AND WHO SPONSOR PORTIONS OF THE
2018 JOINT IRP NARRATIVE AND TECHNICAL APPENDICES.
A. In addition to me, the following witnesses sponsor various portions of the 2018
Joint IRP narrative and Technical Appendices:
Terry Baxter, Manager of Load Forecasting, sponsors the long-term load
forecast used for the 2018 Joint IRP. That forecast and the data and methodologies
employed in building the forecast are described in the narrative in the Load Forecast
and Market Fundamentals volume, and supported by Technical Appendices LF-1
through LF-7.
Joseph Brignola, Manager, Coal Operations and Procurement, supports the
following portions of the Load Forecast and Market Fundamentals volume: Section
2.C. (Coal Fundamentals) and Section 3.G. (Coal Price Forecast). Mr. Brignola also
sponsors the coal price forecast contained in Technical Appendix FPP-1.
Michael Cole, Treasurer, sponsors Section 4 (Financial Plan) of the narrative in
the Supply Side Plan volume. The Financial Plan details the financial information
and assumptions that are utilized in the analyses of the options described in the
2018 Joint IRP, as well as the impact of the Preferred Plan on the Companies and
customers.
Kevin Geraghty, Senior Vice President, Operations, supports the Generation
discussion in the Supply Side Plan narrative and the Companies’ requests to modify
Elicegui-IRP DIRECT 3
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the retirement dates of several of the generating units based on the results of
analysis performed pursuant to the Commission-approved Life Span Analysis
Process. Mr. Geraghty also discusses the conditional early retirement of North
Valmy Unit 1 (from December 31, 2025 to December 31, 2021). Mr. Geraghty
sponsors Technical Appendices GEN-1 through GEN-4.
Dr. David Harrison, Jr., Economist and Senior Vice President at NERA
Economic Consulting, sponsors the discussion and analysis of environmental
externalities contained in the Economic Analysis discussion, as well as Technical
Appendix Item ECON-12.
Anita Hart, Director, Demand Side Management, describes and summarizes the
Companies’ joint demand side management (“DSM”) plan, supports the
Companies’ request for approval of the 2018 DSM Plan, and a determination that
the Companies have complied with directives from Docket Nos. 16-07007 and 16-
07001. Ms. Hart sponsors Technical Appendices DSM-1 through 4, and together
with Robert Oliver, sponsors Technical Appendix items DSM-5 through DSM-20,
the measurement and verification reports addressing the success of the 2017 DSM
programs. Together with Ingrid Rohmund, Ms. Hart supports the Market Potential
Study contained in Technical Appendix DSM-21.
Robert Oliver, Director/Project Manager for ADM Associates, Inc., describes
the work ADM Associates, Inc. conducted to measure and verify savings for the
Companies’ 2017 DSM portfolios, and discusses the standards that govern
measurement and verification analysis. Together with Ms. Hart, Mr. Oliver
Elicegui-IRP DIRECT 4
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sponsors the measurement and verification reports contained in Technical
Appendix Items DSM-5 through DSM-20.
Marc Reyes, Director, Resource Planning and Analysis, sponsors portions of the
market fundamentals discussion and the wholesale power and natural gas price
forecasts that are presented in the Load Forecast and Market Fundamentals Volume
and Technical Appendix item FPP-1. Mr. Reyes also sponsors the Economic
Analysis section of the Supply Side Plan narrative, including the inputs,
assumptions and methodology used to perform the economic analysis, avoided cost
calculations, and the Loads and Resource tables.
Patricia Rodriquez, Manager, Gas Transportation Planning, sponsors Section
2.C.1 (Fuel Supply - Current Physical Gas Supply), Section 2.C.2 (Fuel Supply –
Physical Gas Procurement) and Section 2.C.3 (Fuel Supply - Current Oil Supply)
of the Supply Side Plan in the 2018 Joint IRP.
Ingrid Rohmund, Senior Vice President for Applied Energy Group, Inc.,
describes and explains how the Market Potential Study was designed and how the
market potential for demand side management programs was estimated. Ms.
Rohmund presents high-level results for the Companies together, as well as Nevada
Power and Sierra individually.
Joseph Sinobio, Manager of Major Projects – Delivery, supports the
Distribution Planning section of the Supply Side Plan narrative and discusses the
effect of net energy metering on distribution system reliability, and distributed
resources planning.
Elicegui-IRP DIRECT 5
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Dave Ulozas, Senior Vice President, Renewable Energy and Origination,
sponsors the Companies’ Renewable Energy Plan, Section 2.D of the 2018 Joint
IRP as it relates to the both near-term outlook and long-term planning for Nevada’s
Renewable Portfolio Standard. Mr. Ulozas also sponsors and supports the processes
followed and results of the 2018 Renewable Energy Request for Proposals
(“Renewable RFP”), and the six power purchase agreements between the
Companies and several different counterparties. Mr. Ulozas sponsors Technical
Appendices REN-1 through REN-9, which include information regarding the 2018
Renewable RFP and the six purchased power agreements that are the heart of the
Companies’ Preferred Plan.
Sachin Verma, Director, Transmission System Planning, sponsors the section
of the Supply Side Plan narrative discussing the Companies’ transmission systems
and associated projects, as well as Technical Appendices TRAN-1 through TRAN-
9.
III. RESOURCE PLANNING PROCESS
8. Q. PLEASE PROVIDE AN OVERVIEW OF NEVADA’S INTEGRATED
RESOURCE PLANNING PROCESS.
A. Nevada’s unique and comprehensive integrated resource planning process is
designed to optimize expenditures on energy efficiency programs and investments
in electric system assets for the whole – that is, for all Nevadans. This is particularly
evident in this 2018 Joint IRP, which is the first joint IRP filed with the objective
to provide the best mix of resources for customers in both northern and southern
Nevada.
Elicegui-IRP DIRECT 6
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The IRP process starts with a forecast of customer loads and assesses a range of
alternatives, including investments in energy efficiency, demand response,
transmission, and energy supply to identify options for meeting Nevada’s energy
needs over the next 20 years. Resource planners use a variety of modeling tools to
determine the long-run impact of these alternatives on the operation of the electric
system, on electricity prices, on the State’s economy, and on the environment. After
performing that analysis, we assess the results and identify a preferred plan and at
least one alternative plan. Through this filing, Nevada Power and Sierra ask the
Commission to determine that the Preferred Plan we have selected is reasonable
and prudent, and authorize the Companies to take all actions necessary during the
three-year “Action Plan” period, 2019 through 2021, to implement the Preferred
Plan.
Unlike in many jurisdictions, the filing of an IRP in Nevada does not spell the end
of public review of the analysis, strategies and proposals set forth in the IRP. The
Commission conducts a public process through which stakeholders – governmental
agencies, large customers, small customers, non-governmental interest groups and
any other interested party – review, test, and comment on the Companies’ analytic
rigor and decision-making. After an evidentiary hearing, the Commission has the
power to accept the recommended plan, reject the plan, or propose modifications
to the plan. The goal of the Commission’s process is to evaluate the impact of the
proposed plan on customers, the State’s economy, and the environment, and
approve a plan that provides the best value to customers.
Elicegui-IRP DIRECT 7
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IV. THE PREFERRED AND ALTERNATIVE PLANS
9. Q. HAVE NEVADA POWER AND SIERRA IDENTIFIED A PREFERRED
AND AN ALTERNATIVE PLAN?
A. Yes. After assessing several different plans, we identified the Low Carbon Case as
the Preferred Plan and the Renewable Case as the Alternative Plan. As explained
below, both of these plans meet the energy needs of customers first by increasing
expenditures on energy efficiency programs and second by proposing power
purchase agreements with more than a gigawatt of new solar generating units and
100 megawatts (“MW”) of battery storage systems. The Low Carbon Case is a low-
cost, least-risk plan for meeting the electricity needs of customers in a safe and
reliable manner. If Question 3 fails in November 2018, we recommend that the
Commission approve the Low Carbon Case. We make this recommendation
because the Low Carbon Plan provides significant economic benefit to Nevada and
the best value for customers.
10. Q. PLEASE PROVIDE AN OVERVIEW OF THE LOW CARBON CASE AND
THE RENEWABLE CASE.
A. The two cases are very similar. Both cases are built on the same demand side plan.
Both cases look first to energy efficiency and demand response programs to meet
the volumetric energy and demand needs of customers. The energy efficiency
foundation for both plans increases expenditures on energy efficiency programs
resulting in a total investment of $197 million in DSM programs over the Action
Plan period. The portfolio of energy efficiency programs meets Nevada’s new
energy efficiency policy goals, producing forecasted energy savings that exceed 1.1
percent of projected retail sales.
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Both the Low Carbon and Renewable Cases include the same renewable energy
expansion plan. Both cases seek approval of six power purchase agreements
between NV Energy and renewable energy project developers, pursuant to which
companies such as NextEra, Sempra, and Techren will invest an estimated $2.175
billion in new Nevada-based solar photovoltaic farms that will deliver 1,001 MW
of electricity harvested from the sun and delivered to NV Energy for distribution,
without any cost markup, to customers. These six projects are located throughout
the State, bringing direct investments in Clark County, Humboldt County and
Washoe County and indirect and induced economic benefits to the entire State. The
Low Carbon Case is a concrete commitment to deliver more than one gigawatt of
clean, cost effective solar energy to Nevadans.
Both cases also include first-of-its-kind investments in battery storage. Three of the
new solar projects, all located in northern Nevada, come coupled with 100 MW of
battery storage (one 50 MW battery with the ability to discharge at that capacity for
four hours, and two 25 MW batteries with the ability to discharge at the full output
over four hours). These batteries will provide much needed capacity and flexibility
to northern Nevada’s system. Messrs. Geraghty, Reyes, and Verma discuss the need
for both capacity and flexibility within the northern Nevada system.
11. Q. WHAT IS THE DIFFERENCE BETWEEN THE LOW CARBON CASE
AND THE RENEWABLE CASE?
A. The only difference in the Low Carbon Case and the Renewable Case relates to the
operation of North Valmy Unit 1. Currently, the resource planning retirement date
of North Valmy Unit 1 – a 254 MW coal-fired generating unit located in Humboldt
County – is December 31, 2025. NV Energy owns a 50 percent interest in this unit,
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which provides NV Energy 127 MW of capacity. The Low Carbon Case retires
North Valmy Unit 1 on December 31, 2021, subject to certain conditions, while the
Renewable Case maintains the existing resource planning retirement date.
12. Q. IS THE LOW CARBON CASE THE LOWEST COST ALTERNATIVE
THAT NV ENERGY ANALYZED?
A. No, it is not. The Renewable case is the lowest cost case. This is true for the 5-year,
10-year, 20-year and 30-year present worth of revenue requirement analysis. The
present value of the difference in costs for the 5-year analysis is $11 million, or less
than 0.20 percent, and $22 million or 0.21 percent in the 10-year analysis, $22
million or 0.13 percent in the 20-year analysis and $22 million, or 0.09 percent in
the 30-year analysis. Relative to the two other cases that resource planning
analyzed, the Low Carbon Case provides savings for customers, however. In the
10-year analysis, the Low Carbon Case saves customers between $35 million and
$52 million. In the 30-year analysis, the savings relative to the Development Case
are reduced to $29 million, while the savings relative to the All Market Case grow
to $155 million.
13. Q. DOES THE SUPPLY SIDE COMPONENT OF THE 2018 JOINT IRP
TRANSFORM AND REDUCE THE RISK ASSOCIATED WITH THE
COMPANIES’ ENERGY SUPPLY PORTFOLIO?
A. Yes, we concluded that the Low Carbon Case embodies the low-cost, least-risk
approach to producing energy that the Commission and the public expect us to
deliver. As show in Figure Elicegui-Direct-1 through Figure Elicegui-Direct-2
below, the Low Carbon Case supply portfolio increases renewable energy capacity
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and production, reduces natural gas capacity and production and all but eliminates
coal-fired capacity and production by 2023.
Figure Elicegui-Direct-11
1 Renewable capacity includes hydroelectric generation, consistent with the presentation in NV Energy’s Securities and Exchange Commission reporting, and based on nameplate capacity rather than resource planning capacity.
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Figure Elicegui-Direct-22
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2 Renewable capacity includes hydroelectric generation, consistent with the presentation in NV Energy’s Securities and Exchange Commission reporting, and based on nameplate capacity rather than resource planning capacity.
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Coal 6%
Natural Gas 56%
Oil/Diesel 0%
Purchase Power (non-renewable)
24%
Figure Elicegui-Direct-33
2017 Energy Supply Mix
Renewables 14%
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3 Renewable production includes hydroelectric generation, consistent with the presentation in NV Energy’s Securities and Exchange Commission reporting, and based on nameplate capacity rather than resource planning capacity.
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Figure Elicegui-Direct-44
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14. Q. WHY DID NV ENERGY SELECT THE LOW CARBON CASE AS THE
PREFERRED PLAN?
A. The Low Carbon Case advances Nevada’s energy policy, delivers the services that
customers value, and fits closely with NV Energy’s corporate business strategy. In
addition to our short term goal of doubling our renewable resources by 2023, the
Companies’ have a longer-term aspirational goal to deliver 100 percent renewable
energy to customers. To do so, we need to continue to transform our generation
4 Renewable production includes hydroelectric generation, consistent with the presentation in NV Energy’s Securities and Exchange Commission reporting, and based on nameplate capacity rather than resource planning capacity. Coal production rounds down to 0 percent even though there is some production.
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fleet. Reducing carbon emissions not only benefits the environment but it also
reduces risk. By adding renewable energy facilities to our supply portfolio, we
reduce exposure to carbon costs and fuel prices. We have already taken significant
steps on the transformative path by retiring the Mohave and Reid Gardner
generating units, and exiting participating in the Navajo generating station no later
than December 31, 2019. The Low Carbon Case is the next logical step in
advancing Nevada’s energy policy goals and our strategy to deliver the services
that our customers value.
Both the Low Carbon Case and the Renewable Case add more than a gigawatt of
new, Nevada-based renewable projects to our supply portfolio. Both cases also
deliver significant economic benefits to Nevada’s economy. The selection of the
Preferred Plan turns on the impact to the environment. The Low Carbon Case
further reduces NV Energy’s impact on the environment, reduces the carbon
intensity of the Companies’ generation fleet, and moves NV Energy ever closer to
its aspirational goal. We selected this low-cost, least-risk, flexible plan because it
provides the best value for customers. The conditions I discuss in Section V below
are essential to mitigating the risk and, in fact, make the Low Carbon Case the least-
risk plan.
15. Q. NEVADA POWER ENTERED INTO CONTRACTS WITH THE THREE
RENEWABLE PROJECTS LOCATED IN SOUTHERN NEVADA AND
SIERRA ENTERED INTO CONTRACTS WITH THE THREE
CONTRACTS LOCATED IN NORTHERN NEVADA. THE PRODUCTION
COST MODELING RESULTS ASSIGN THE COSTS OF EACH
CONTRACT TO NEVADA POWER AND SIERRA BASED ON THE
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CONTRACTS. IS THAT THE ONLY OPTION THE COMMISSION HAS
FOR ASSIGNING POWER PURCHASE COSTS?
A. No. The Commission has the option of blending the energy purchase prices of all
of the contracts to create an average price and then allocating costs based on
consumption. This approach optimizes the portfolio of contracts for all of the
Companies’ customers. This could be more consistent with the process embodied
by SB 146, which requires joint planning for the benefit of all customers. The
alternative approach is to directly assign the costs of each contract to the contracting
utility, and rely on the joint dispatch process to account for the exchange energy
between the two companies.
16. Q. WHY DOES NV ENERGY’S RECOMMENDATION TO THE
COMMISSION OF THE LOW CARBON CASE AS THE PREFERRED
PLAN TURN ON VOTERS REJECTING QUESTION 3?
A. If voters approve Question 3 again in November, most stakeholders seem to agree
that NV Energy will sell its generation resources and assign its long-term purchase
power costs to some other entity. NV Energy’s focus will shift from long-term,
centralized planning that focuses on energy supply to short-term planning. The
Companies created a single case, the Question 3 Alternative Case to be pursued
only if Question 3 is approved by voters in November 2018. As explained below in
more detail, in a short-term planning scenario our recommendation is that a single
contract – the 8minutenergy contract – provides the best value for customers.
Adding six long-term obligations, as well as battery storage to a list of assets that
needs to be transferred and which add to the obligations backed by the full faith and
credit of the State is not necessary to meet customers’ needs through 2023.
Furthermore, the early retirement of North Valmy Unit 1 would reduce capacity in
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a capacity-constrained system, which increases the risks, costs and uncertainty
associated with deregulating the electric industry. Accordingly, those are items are
not included in the Question 3 Alternative Case.
17. Q. UNDER WHAT CONDITIONS SHOULD THE COMMISSION CONSIDER
THE ADOPTION OF THE ALTERNATIVE CASE?
A. The Renewable Case is the lowest cost case that we analyzed and it has essentially
the same impact on Nevada’s economy. The two attributes of the cases that differ
are the reliability characteristics and the impact on the environment. If the
Commission does not believe that the conditions NV Energy identified for the
retirement of North Valmy Unit 1 – which are discussed below, in the testimony of
Messrs. Geraghty, Reyes and Verma and in the Supply Side narrative – are
necessary to adequately ensure reliable operations, then the Commission should
select the Renewables Case, which also provides great value to customers.
18. Q. DO THE COMPANIES RECOMMEND THAT THE RENEWABLE CASE
(I.E., THE ALTERNATIVE PLAN) BE ADOPTED IN THE EVENT THAT
BALLOT QUESTION 3 IS ADOPTED?
A. No. We make this recommendation because this case also adds long-term
obligations that are not necessary in a short-term planning scenario. Instead, we
recommend that the Commission approve the Question 3 Alternative Case as
discussed below.
V. THE RETIREMENT OF NORTH VALMY UNIT 1
19. Q. WHY HASN’T NV ENERGY MADE AN UNEQUIVOCAL COMMITMENT
TO RETIRE NORTH VALMY UNIT 1 BY DECEMBER 31, 2021?
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A. It is important to recognize the current operational framework for the entire North
Valmy Generating Station. Today, the plant is winterized and placed in a reserve
operating shutdown for at least seven months every year. The plant is then used in
the summer to meet peak demand and provide reliability services within northern
Nevada. We operate the plant in a manner that minimizes the facility’s impact on
the environment while providing needed capacity and grid reliability.
As Mr. Verma explains, the North Valmy Generating Station provides flexibility,
as well as critical reliability and load service elements to the northern Nevada
system. Our load forecast and models show that, with the addition of 401 MW of
solar generation in northern Nevada, as well as battery storage systems that provide
reliable capacity, we should be able to retire North Valmy Unit 1 on December 31,
2021, without a significant deterioration in reliability or compromising our ability
to serve customers.
There is a gap between our current long-term planning tools and the tools that we
need to predict real time operating conditions. This fact is not unique to Nevada;
rather, it is highlighted by the difference in the 2018 summer capacity assessments
issued by the Federal Energy Regulatory Commission (“FERC”) and the California
Independent System Operator (“CAISO”) within two weeks of one another. The
FERC assessment concludes that adequate capacity exists to meet forecasted above
average loads in every North American region except Texas. In contrast, the
CAISO’s probabilistic assessment of real time operating conditions shows that
there is a significant chance of a stage 2 energy emergency in California, which
could result in the interruption of non-firm load – or, put in plain English, a
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significant probability that CAISO will discontinue electric service to some non-
essential loads.
On the surface, both of these reports seem to conflict. However, the devil is in the
details, which are found in the CAISO’s relatively new approach to taking a
probabilistic approach to assessing real time, not long-term, reliability. While our
current long-term reliability assessment indicates that we should be able to retire
North Valmy Unit 1 in 2021 without compromising our fundamental directive – to
safely and reliable deliver low-cost energy to customers – we need to confirm those
findings with additional analysis as 2021 approaches.
20. Q. ARE THERE OTHER REASONS THE LOW CARBON CASE CONTAINS
CONDITIONS THAT MUST BE SATISFIED BEFORE NORTH VALMY
UNIT 1 IS RETIRED ON DECEMBER 31, 2021?
A. Yes. The planning environment in which we normally operate has inherent
uncertainties, but it also is becoming increasingly fractured. While forecasting in
general involves uncertainties, and our resource planning rules recognize this fact,
our forecasts must be based on “substantially accurate data” which is defined as
data:
1. That the utility demonstrates has been gathered from the best sources of information available to it; or
2. The validity of which is inherently uncertain but the use of which does not substantially contribute to the risk of incorrect conclusions.
Nevada Administrative Code section 704.9163.
Our load forecast projects significant load growth in specific areas within northern
Nevada. However, this load growth has been discounted appropriately, based on
methods vetted with stakeholders and previously approved by the Commission, to
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reduce the risk of incorrect conclusions. Moreover, load growth projections do not
reflect load additions for certain customers – either potentially new distribution-
only service customers or existing distribution-only service customers. These
customers have told us not to plan for their energy supply needs; on the other hand,
these customers have not identified what their network resources will be, where
those resources will be located, or how those network resources will be delivered
to the distribution system. In light of this additional uncertainty and, recognizing
the fact that we have imperfect knowledge regarding the types and locations of
resources that will serve an increasing share of the system’s load, we have created
a list of tests that must be validated. Through this filing, we have committed to the
Commission, stakeholders and the public that we will conduct those tests as the
forecasted picture comes into focus and, if the tests are validated, we will retire
North Valmy Unit 1 before December 31, 2021.
21. Q. IF NORTH VALMY UNIT 1 IS RETIRED AT THE END OF 2021, HAVE
YOU CONSIDERED HOW THE COSTS OF DECOMMISSIONING THAT
UNIT AND ANY UNDEPRECIATED BOOK VALUE WILL BE
ACCOUNTED FOR AND TREATED FOR RATEMAKING PURPOSES?
A. Yes. The early retirement of North Valmy Unit 1 will not in itself trigger the
decommissioning of the North Valmy Generating Station. North Valmy Unit 2 will
remain in operation, and except for work to isolate North Valmy Unit 1 from the
remainder of the operating station, decommissioning will not commence until
North Valmy Unit 2 is retired. Therefore, a plan for decommissioning the North
Valmy Generating Station has not been established. However, consistent with the
tracking and accounting systems put in place at the Companies’ other retired
generating facilities generally and, more specifically, coal generating facilities, the
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costs of decommissioning the North Valmy Generating Station, including those
incurred to isolate and make safe North Valmy Unit 1, will be tracked and placed
into a regulatory asset. Consistent with the treatment afforded decommissioning
costs incurred upon the retirement of Clark Station Units 1, 2, and 3 (Docket No.
05-06038), Sunrise Units 1 and 2 (Docket No. 11-08011), and Reid Gardner Units
1, 2, 3, and 4 (Docket No. 17-07021), a carrying charge equal to Sierra’s currently
approved cost of capital would be applied to this regulatory asset. Upon completion
of decommissioning, the balance in the regulatory asset will be placed into rate
base. Sierra will apply in a future proceeding to collect the balance over an
appropriate amortization period.
Similarly, if North Valmy Unit 1 is retired early, at the end of 2021, it will not be
fully depreciated. Again, consistent with the tracking accounting treatment
authorized in prior dockets, upon its retirement, the undepreciated book value of
North Valmy Unit 1 will be placed into a regulatory asset where it would not earn
a carrying charge. Instead, until it is included in Sierra’s revenue requirement,5
Sierra will amortize the regulatory asset balance using the depreciation rate for
North Valmy Unit 1 at the time of its retirement. When the balance in the regulatory
asset is included in revenue requirement, it will be placed into rate base. Sierra will
apply in a future proceeding to collect the balance over an appropriate amortization
period.
5 Under the current general rate review schedule, Sierra would file in June 2022 for rates effective January 1, 2023.
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22. Q. IS NV ENERGY’S APPROACH TO THE RETIREMENT OF NORTH
VALMY UNIT 1 REASONABLE AND APPROPRIATE?
A. Yes. We take our commitment to environmental sustainability seriously, as
evidence by this filing which, if approved, will result in the single-largest private
investment in clean, renewable energy in Nevada’s history. We take our obligation
to safely and reliably produce, transmit and deliver electricity to meet the needs of
customers and the State’s growing economy equally seriously. The tests that we
have identified allow us to objectively assess the impact of retiring North Valmy
Unit 1 in 2021 would have on reliability as inherently uncertain assumptions
become more certain. This approach preserves flexibility and ensures reliability
while prioritizing the reduction of carbon emissions is both reasonable and
appropriate. The Commission, stakeholders, and the public should expect nothing
less than this type of rational, methodical approach to transforming and de-risking
our supply portfolio.
23. Q. WHAT ARE THE QUANTITATIVE RELIABILITY CONDITIONS
RELATED TO THE EARLY RETIREMENT OF NORTH VALMY UNIT 1?
A. The conditions related to the early retirement of North Valmy Unit 1 focus on
ensuring reliability and economics. The first quantitative condition relates to the
loss of load probability, a metric produced in standard production cost modeling
runs. The second relates to unserved energy, another output of standard production
cost modeling runs. Unserved energy is how resource planners describe a very
serious condition – the inability to serve load, which results in curtailment or, in
plain English, outages. The third condition relates to the loss of load expectation,
which must not exceed one day in 10 years. Finally, we will develop a probabilistic
analysis to assess forecasted real-time operating scenarios, similar to the analysis
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performed by the CAISO. A complete list of the qualitative and quantitative
conditions, including economic triggers, can be found in Exhibit Elicegui-Direct-
2.
24. Q. YOU NOTED THAT THE CAISO RECENTLY COMPLETED A
RELIABILITY ASSESSMENT USING STOCHASTIC AND
PROBABILISTIC ANALYSIS AND THAT NV ENERGY MIGHT
DEVELOP SIMILAR ASSESSMENT TOOLS. IS NV ENERGY
INVESTIGATING UPGRADES TO ITS PRODUCTION COST
MODELING SOFTWARE?
A. Yes, the Companies are investigating upgrades to the tools resource planners use to
assess system performance. We have identified options that improve optimization
engines. Specifically, the tools we are investigating use mixed-integer instead of
linear programming. This enables improved modeling of commitment and dispatch
of multi-stage generators such as NV Energy’s flexible combined-cycle generators
which can operate in multiple modes (e.g., 1x1, 2x1, and with and without duct
firing). This type of modeling tool becomes critical in order to forecast actual
operating conditions especially as the Companies evolve their operating practices
to integrate new technologies and resources.
The tools also have stochastic capabilities that allow the evaluating of probabilistic
inputs such as load, fuel and purchased power and production of variable units (e.g.,
wind and solar production). Finally, the tools have nodal capabilities that will
enhance and facilitate the full integration of distributed resources and technologies
into the planning process. The Companies are not seeking a determination of
prudence of this decision; instead, we are informing the Commission and
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stakeholders of the need to acquire new tools. NV Energy will use competitive
process to ensure that the best value is obtained for customers.
VI. QUESTION 3’S IMPACT ON THE PREFERRED PLAN
25. Q. WOULD APPROVAL OF QUESTION 3 CHANGE NV ENERGY’S
RECOMMENDATION?
A. Yes, if Question 3 passes, NV Energy recommends that the Commission approve
the Question 3 Alternative case. This case involves the addition of a single
renewable resource that is needed to meet Nevada’s Renewable Portfolio Standard.
That resource also has lower network upgrade costs, thus minimizing total costs in
short-run. This case does not provide the same economic development and
environmental benefits as the Low Carbon Case, but provides the best option in a
short-run planning scenario.
26. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A. Yes.
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SHAWN M. ELICEGUI 440 Octate Circle, Reno, Nevada 89511 ∣ H: 775.852.5236 ∣ O: 775.834.5697 ∣ M: 775.813.5697 ∣ [email protected]
EDUCATION
University of California – Davis, King Hall School of Law J.D., Order of the Coif – 1996 Honors: Teacher’s Aide, Constitutional Law I, Professor Allen Brownstein
Trial Practice Honors Board Am. Jur., Legal Research & Writing Am. Jur., Business Associations
University of Nevada – Reno B.A., Political Science and International Affairs, With Distinction – 1993 Honors: Pi Sigma Alpha, National Political Science Honors Society
PROFESSIONAL EXPERIENCE
NV Energy, Inc. SVP, Business Plan, Regulatory and Legislative Strategy November 2017 - Present
SVP, Customer Operations January 2017 – November 2017 SVP, Regulation & Strategic Planning February 2015 – December 2016 VP, Regulation December 2013 – February 2015 Associate General Counsel February 2009 – December 2013
• Senior Vice President, Business Plan, Regulatory and Legislative Strategy responsibilities include supervision of regulatory pricing, regulatory policy, and resource planning functions. Responsibilities also include load research and forecasting. • Senior Vice President, Customer Operations, responsibilities include overseeing the operation of several business units, including customer energy solutions, customer service, major accounts, customer programs and services, and meter services • Senior Vice President, Regulation and Strategic Planning, responsibilities included overseeing the rates and regulatory team, the resource planning team and strategic planning activities; responsibilities also included development and execution of legislative strategy in conjunction with Senior Vice President of Government Relations and Community Affairs • Vice President, Regulation, responsibilities included overseeing the rates and regulatory team and the resource planning team; providing policy testimony in administrative proceedings • Associate General Counsel, responsibilities included providing legal and regulatory advice to operating subsidiaries of NV Energy, representing the operating subsidiaries in contested proceedings before the Public Utilities Commission of Nevada; proceedings included independent regulatory rate review proceedings, fuel
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and purchased power review proceedings, rulemaking proceedings and investigations
Lionel, Sawyer & Collins Shareholder January 2005 – February 2009 Associate August 1997 – December 2004 Practice included representation of corporate and individual clients in a variety of regulatory matters before local, state and federal agencies and the Nevada legislature. Practice areas primarily included the representation of utilities and customers in the energy, telecommunications and water and wastewater industries. Practice areas also included financial institutions, and representation of professional licensees and individuals and juridical entities engaged in the gaming and hospitality industry. Civil litigation experience includes representation of clients in general commercial litigation, as well as appellate and judicial review proceedings.
Hon. Procter R. Hug, Jr., Chief Judge, United States Court of Appeals for the 9th Circuit Judicial Clerk August 1996 – July 1997 Prepared memoranda summarizing facts and applicable law, evaluating parties’ arguments and recommending course of action. Prepared draft case dispositions.
SELECTED SPEAKING ENGAGEMENTS, ARTICLES, AND HONORS
Customer First: Customer-centered Operations, Berkshire Hathaway Energy Executive Leadership Conference, 2018 The Net Energy Metering Rate Design Players: Understanding the Perspective of Different Rate Mechanisms, Western Conference of Public Service Commissioners, 2016 Clean Power Plan, Infocast California Energy Summit, 2016 High and Dry in Nevada: When Water Rights Trump Development, ABA Section of Business Law, Business Law Today, Volume 15, No. 4, March/April 2006 (with D. Reaser, W. McKean and D. Cannon) Rio Revs up the Power, Casino Enterprise Management, Volume 2, Iss. 6, June 2004 (profiling role in combined heat and power project at Rio All Suites Hotel) Best Lawyers in America 2008 & 2009 (Administrative Law and Energy Law) Top 20 under 40, Reno Gazette Journal and Reno-Tahoe Young Professionals’ Network, 2008
SELECTED TESTIMONY
PUCN Docket No. 16-06006, Sierra Pacific Power Company General Rate Review (2016) PUCN Docket Nos. 16-03003, 16-03004 & 16-03005, Nevada Power Company, Sierra Pacific Power Company Electric, and Sierra Pacific Power Company Gas Deferred Energy Accounting Adjustment (2016) PUCN Docket No. 15-11029, Sierra Pacific Power Company’s Third Amendment to its Integrated Resource Plan (2015)
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PUCN Docket No. 15-11028, Nevada Power Company’s Request for Approval of Renewable Energy Agreement with Switch, Ltd. (2015) PUCN Docket No. 15-11027, Nevada Power Company’s First Amendment to its Integrated Resource Plan (2015) PUCN Docket No. 15-11026, Nevada Power Company’s Request for Approval of Renewable Energy Agreement with the City of Las Vegas (2015) PUCN Docket No. 15-11025, Sierra Pacific Power Company’s Request for Approval of Renewable Energy Agreements with Switch, Ltd. and Apple, Inc. (2015) PUCN Docket Nos. 15-07041 & 15-07042, Nevada Power Company’s and Sierra Pacific Power Company’s Requests for Approval of Net Energy Metering Tariffs (2015) PUCN Docket No. 15-07003, Nevada Power Company’s First Amendment to its 2014 Emissions Reduction and Capacity Replacement Plan (2015) PUCN Docket No. 15-06019, Nevada Power Company’s and Sierra Pacific Power Company’s Application to Amendment Action Plans to Approve an Amended and Restated Transmission Usage Agreement for the One-Nevada Transmission Line (2015) PUCN Docket No. 14-11007, Application of Switch, Ltd. for Authorization to Purchase Energy, Capacity and Ancillary Services from an Alternative Supplier (2014) PUCN Docket Nos. 14-05004, Nevada Power Company’s General Rate Review (2014) PUCN Docket No. 14-05003, Nevada Power Company’s First Amendment to its Integrated Resource Plan and its Emissions Reduction and Capacity Replacement Plan (2014) PUCN Docket No. 14-04024, Nevada Power Company’s and Sierra Pacific Power Company’s Request for Approval of Plan to Participate in Energy Imbalance Market (2014)
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EXHIBIT ELICEGUI-DIRECT-2
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Exhibit Elicegui Direct-2
Retirement of North Valmy Unit 1 Additional Conditions
1. NV Energy must have adequate capacity to serve customer load, which will be determined using, at a minimum,1 the following metrics:
a. “Loss of Load Probability.” For any given hour, an increase in the LOLP by more than 100% would trigger the reevaluation of the North Valmy Unit 1 retirement.
b. “Expected Unserved Energy.” Any megawatt-hour increase in expected unserved energy under the North Valmy Unit 1 retirement scenario would trigger a reevaluation of the retirement.
c. “Loss of Load Expectation.” This metric does not exceed the one day in 10 year criterion.
2. Conditions in the western energy markets must be such that NV Energy has sufficient access to economic energy and capacity to mitigate the cost pressure and reduction in flexibility associated with having power available from Valmy Unit 1. While the PWRR difference between the Low Carbon and Renewable Cases is relatively small, the Companies will monitor the production cost impact of any North Valmy Unit 1 retirement on retail rates and reevaluate the retirement decision if the retirement of North Valmy Unit 1 increases Base Tariff Energy Rates by more than $0.00250 per kilowatt-hour versus the non-retirement scenario.
3. Transmission area load of 2,800 MW will trigger a re-evaluation and, possibly, delay of the retirement of North Valmy Unit 1.
4. Approval of the request, made consistent with the tracking and accounting systems put in place at the Companies’ other retired generating facilities, the costs of decommissioning the North Valmy Generating Station, including those incurred to isolate and make safe North Valmy Unit 1, will be tracked and placed into a regulatory asset, and a carrying charge equal to Sierra’s currently approved cost of capital would be applied. Upon completion of decommissioning, the balance in the regulatory asset will be placed into rate base. Sierra will apply in a future proceeding to collect the balance over an appropriate amortization period.
5. Approval of the request, also made consistent with the tracking accounting treatment authorized in prior dockets, upon its retirement, the undepreciated book value of North Valmy Unit 1 will be placed into a regulatory asset where it would not earn a carrying charge. Instead, until it is included in Sierra’s revenue requirement, Sierra will amortize the regulatory asset balance using the depreciation rate for North Valmy Unit 1 at the time of its retirement. When the balance in the regulatory asset is included in revenue requirement, it will be placed into rate base. Sierra will apply in a future proceeding to collect the balance over an appropriate amortization period.
Because real – time system reliability is paramount, additional analysis similar to that developed by the CAISO may be used by NV Energy to assess real-time reliability risk.
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TERRY A. BAXTER
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV Energy Sierra Pacific Power Company d/b/a NV Energy
2018 Joint Integrated Resource Plan (2019-2038)Docket No. 18-06____
PREPARED DIRECT TESTIMONY OF
Terry A. Baxter
1. Q. WOULD YOU PLEASE STATE YOUR NAME, EMPLOYER, JOB
TITLE, AND BUSINESS ADDRESS?
A. My name is Terry A. Baxter. I am the Manager of Load Forecasting for
Sierra Pacific Power Company d/b/a/ NV Energy (“Sierra”) and Nevada
Power Company d/b/a NV Energy (“Nevada Power” and together with
Sierra, the “Companies” or “NV Energy”). My business address is 6226
West Sahara Avenue, in Las Vegas, Nevada. I am filing testimony on
behalf of the Companies.
2. Q. WHAT ARE YOUR RESPONSIBILITIES AS MANAGER OF
LOAD FORECASTING?
A. As the Manager of Load Forecasting, my primary responsibilities include
forecasting sales volume, customer counts and peak demand for use in
development of financial budgets, general rate cases, Energy Supply Plans
(“ESP”) and Integrated Resource Plans (“IRP”).
3. Q. PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND
AND EMPLOYMENT EXPERIENCE IN THE UTILITY
INDUSTRY?
Baxter – IRP DIRECT 1
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A. I hold a Master of Arts in Economics from the University of Arkansas
located in Fayetteville, Arkansas and a Bachelor of Science in Economics
from the University of Missouri at Rolla (now Missouri University of
Science and Technology) located in Rolla, Missouri. I have been
employed by the Companies since July 2007. Prior to my current position,
I served as the Manager of Forecasting and Economic Analysis at Alliant
Energy in Cedar Rapids, Iowa, for nine years, where I was responsible for
load and revenue forecasting and load research. Prior to that, I was a
Group Manager for seven years with Aspen Systems Corporation (now a
division of Lockheed-Martin) overseeing analytical consulting projects for
utilities and the U.S. government. I also have served as Manager of Load
Research at Midwest Resources (now MidAmerican Energy Company)
and as the Load Research Analyst at Missouri Public Service Company
(now a part of Kansas City Power and Light Co., a division of Great Plains
Energy). I have submitted reports and testimony regarding load
forecasting and load research before the Iowa Utilities Board, the
Wisconsin Public Service Commission, the Illinois Commerce
Commission, the Minnesota Department of Commerce, the California
Energy Commission, the California Public Utilities Commission and the
Public Utilities Commission of Nevada (“Commission”).
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE
COMMISSION?
A. Yes I have testified in numerous proceedings before the Commission
including, most recently in Nevada Power’s ESP Update, Docket No. 17-
09001, and Sierra’s ESP Update for 2018-2019 in Docket No. 17-09002.
Baxter – IRP DIRECT 2
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5. Q. ARE ANY OF THE MATERIALS YOU ARE SPONSORING
CONFIDENTIAL?
A. Yes. Some numbers in the narrative and Technical Appendix are
confidential because they contain usage information of discrete and
specific customers.
6. Q. FOR HOW LONG DO THE COMPANIES REQUEST
CONFIDENTIAL TREATMENT?
A. The requested period for confidential treatment is for no less than five
years.
7. Q. WILL CONFIDENTIAL TREATMENT IMPAIR THE ABILITY OF
THE COMMISSION’S REGULATORY OPERATIONS STAFF
(“STAFF”) OR THE NEVADA ATTORNEY GENERAL’S BUREAU
OF CONSUMER PROTECTION (“BCP”) TO FULLY
INVESTIGATE THE INFORMATION SET FORTH IN THIS
FILING?
A. No, in accordance with the accepted practice in Commission proceedings,
the confidential material will be provided to Staff and the BCP under
standardized protective agreements with them.
8. Q. WHAT EXHIBITS ARE ATTACHED TO YOUR TESTIMONY?
A. I have attached the following exhibit to my testimony:
Exhibit Baxter-Direct-1.
9. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT
TESTIMONY IN THIS PROCEEDING?
Baxter – IRP DIRECT 3
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A. The purpose of my testimony is to support the forecast of native load used
in this filing. Specifically, I am sponsoring the long-term load forecast
used for the 2019 through 2038 Integrated Resource Plan (the “2018 IRP
Forecast”) and the following Technical Appendix Items:
LF-1 NVE 2019-2048 Load Forecast
LF-2 Population Forecasts: Long-Term Projections for Clark
County, Nevada 2016-2050, May, 2017
LF-3 State Demographer 2017 Population Forecasts
LF-4 Nevada State Demographer Intercensal Population
Estimates
LF-5 Population of Nevada’s Counties and Incorporated Cities
2000-2017
LF-6 Las Vegas Convention and Visitors Year to Date October
executive summary for 2017
LF-7 ADM Report on Energy Intensity Development
10. Q. PLEASE SUMMARIZE THE COMPANIES’ REQUESTS
REGARDING THE 2018 IRP FORECAST.
A. The Companies are making the following requests regarding the 2018 IRP
Forecast:
A finding, consistent with Nevada Administrative Code (“NAC”) §
704.9225, that the base, high and low cases are based upon, and
consistent with, the upper and lower limits of expected economic and
demographic change in the Companies’ service territory for 2019
through 2048.
Baxter – IRP DIRECT 4
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A finding, consistent with NAC § 704.9321, that the base, high and
low cases are based on substantially accurate data, adequately
demonstrated and defended, and adequately documented and justified.
A finding that the 2018 IRP Forecast, as described in the Narrative and
the Technical Appendices, as well as in my testimony, contain all of
the items required by NAC § 704.925 and other applicable regulations.
A finding that the 2018 IRP Forecast is suitable for making long term
planning decisions.
The 2018 IRP Forecast provides the foundation for all other load forecasts
including in this filing.
11. Q. HAVE HIGH AND LOW LOAD FORECAST SCENARIOS BEEN
DEVELOPED FOR THIS FORECAST?
A. Yes. High and low load forecasts were produced based on optimistic and
pessimistic economic, demographic and, large customer growth
assumptions. See Technical Appendix LF-1 for more details regarding the
development of the high and low load forecast scenarios.
12. Q. DOES THE 2018 IRP FORECAST CONSIDER THE IMPACT OF
DISTRIBUTED GENERATION AND CUSTOMERS WHO
ACQUIRE ENERGY PURSUANT TO NRS § 704.787 OR NRS
CHAPTER 704B (SEE NAC § 704.925(5))?
A. Yes. Customers who are expected to procure energy under distribution
only service (“DOS”) tariffs are no longer included in the load forecast.
These include both the Peppermill (Sierra) and Caesars (Sierra and
Nevada Power), which have been treated as DOS customers in this
Baxter – IRP DIRECT 5
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forecast. Senate Bill 146 (“SB146”) defines distributed resources as
including distributed generation systems, energy efficiency, energy
storage, electric vehicles and demand-response technologies. The 2018
IRP Forecast accounts for distributed generation systems, primarily solar
PV, installed on residential homes, small business, public buildings and
schools, as well as larger customer net metering projects. It also accounts
for energy efficiency and demand-response resources, and electric vehicle
installations. It also is important to note that certain prospective new
customers have sent the Companies correspondence directing the
Companies to exclude potential energy sales attributable to these
customers from the Companies’ retail sales forecast. Stated differently,
these prospective customers have indicated that they currently intend to
secure their own supply of energy. Accordingly, the Companies have not
included either the volume or demand associated with these potential load
additions in the 2018 IRP Forecast. See Technical Appendix LF-1, for the
sales and demand impacts of net metering projects, demand side
management (“DSM”) and demand response, and electric vehicles, as well
as new DOS customers for the 2018 IRP Forecast.
As is set forth in the Narrative, information regarding energy storage
devises is not yet available in sufficient detail to incorporate into the 2018
IRP Forecast.
13. Q. DOES THE 2018 IRP FORECAST CONSIDER THE IMPACT OF
APPLICABLE NEW TECHNOLOGIES AND THE IMPACT OF
APPLICABLE NEW GOVERNMENTAL PROGRAMS OR
REGULATIONS (SEE NAC § 704.925(4))?
Baxter – IRP DIRECT 6
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A. Yes. The customer class sales regression modeling for the 2018 IRP
Forecast includes variables constructed from estimated historical and
forecasted appliance saturations and efficiencies, building characteristics
and square footage. These estimates and forecasts include the effects of
new technologies and government programs.
14. Q. HAS NV ENERGY MADE ANY CHANGES TO ITS FORECAST
METHODOLOGY SINCE THE FILING OF COMPANIES’ 2017
ESP UPDATE FORECASTS (SEE NAC § 704.925(11))?
A. No.
15. Q. ARE YOU FILING WORKPAPERS WITH THIS 2018 IRP
FORECAST?
A. Yes, a comprehensive set of load forecasting files will be supplied on
electronic media for this 2018 IRP Forecast filing.
16. Q. WHAT IS YOUR OVERALL VIEW OF THIS 2018 IRP
FORECAST?
A. The 2018 IRP Forecast is based on substantially accurate data. More
specifically, the 2018 IRP Forecast is based on data such as DSM plans
and economic forecasts that were either gathered from the best sources
available to the Companies or, where the validity of the data is inherently
uncertain, the use of which does not substantially contribute to the risk of
incorrect forecast conclusions. The 2018 IRP Forecast covers 2019
through 2048 and takes into consideration, among other things, annual
system losses, company usage, the effect of distributed generation, as well
as customers who acquire energy pursuant to NRS § 704.787 and NRS
Baxter – IRP DIRECT 7
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Chapter 704B. The 2018 IRP Forecast is documented appropriately, and
has been adequately explained and defended. The forecast thus is a
reasonable basis upon which to make long-term planning decisions for the
IRP planning horizon as well as through 2048.
17. Q. DOES THAT CONCLUDE YOUR TESTIMONY?
A. Yes, it does.
Baxter – IRP DIRECT 8
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STATEMENT OF QUALIFICATIONS OF
TERRY A. BAXTER
Education Master of Arts University of Arkansas, Fayetteville, AR, 1979, Economics Bachelor of Science University of Missouri-Rolla, Rolla, MO, 1976 Economics
Related Professional Experience 2007 to Present Manager of Load Forecasting, Nevada Power Company d/b/a NV Energy
My primary duties are the forecasting of customers, sales, peak demand, gas therms and gas design day therms, for use in supply planning, rate cases and budgeting. Additional responsibilities include production of forecast variance reports actual to budget, weather adjustment of peaks and sales, and participation in local population forecasting working groups. I have filed testimony and supporting documents and testified on numerous occasions before the Public Utility Commission of Nevada.
2003 to 2007 Manager, Forecasting and Economic Analysis, Alliant Energy Responsible for the direction and technical work in the areas of statistical sample design and evaluation of load research samples, peak and energy forecasting, for both the gas and electric utilities, and associated regulatory filings, including Integrated Resource Plan filings in Iowa, Illinois, Minnesota and Wisconsin. In this position, I was also responsible for the monthly sales and revenue forecast and explanations of the monthly variance analysis, including actual to budget, year-over-year, and outlook for both operating companies: Wisconsin Power and Light Company and Iowa Power and Light Company. Also responsible for rate case sales and demand forecasts in Wisconsin and Minnesota. Filed direct testimony before the Minnesota Department of Commerce.
2001 to 2003 Private Consultant Assisted utility companies in sample design and analysis of load research programs.
1998 to 2003 Team Leader, Forecasting and Economic Analysis, Alliant Energy Responsible for the direction and technical work in the areas of statistical sample design and evaluation of load research samples, peak and energy forecasting, for both the gas and electric utilities, and associated regulatory filings for IES Utilities and Interstate Power Company and its successor company, Iowa Power and Light.
1991 to 1998 Group Manager, Aspen Systems Corporation Responsible for the technical direction of utility consulting projects in the areas of sample design, DSM performance evaluation, market and survey research.
1985 to 1991 Rate Engineer and Manager of Load Research, and Forecasting, Iowa Power, Inc. /Midwest Energy Responsible for all facets of the load research program, including sample design, analysis and equipment selection, as well as sales forecasting. Filed testimony before the Iowa Utilities Board.
1980 to 1995 Load Research Analyst, Missouri Public Service Company Responsible for all facets of the load research program as well as class cost of service and marginal cost studies.
1979 to 1980 Economic Analyst, Illinois Commerce Commission Responsible for examination of utility rate and regulatory filings.
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Other
2007 to present Steering Committee, EEI Load Forecasting Group
1998 to 2007 Member, AEIC Load Research Committee Marketing sub-committee chairman from 2001-2007.
Specialized Training Econometric Modeling Using SAS/ETS Software, February, 1991.
SAS Macro Language, August 1990.
Forecasting Techniques using SAS/ETS Software, April, 1990.
Sampling Methods and Statistical Analysis in Power Systems Load Research, April, 1989.
A.E.I.C. Seminar in Advanced Sample Design and Analysis of Load Research Data, July 1987.
Itron Statistically Adjusted End Use (SAE) Training Workshop, November 2008.
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JOSEPH R. BRIGNOLA
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy
2018 Joint Integrated Resource Plan (2019-2038) Docket No. 18-06____
PREPARED DIRECT TESTIMONY OF
Joseph R. Brignola
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, AND
BUSINESS ADDRESS.
A. My name is Joseph R. Brignola. I am Manager, Coal Operations &
Procurement for Sierra Pacific Power Company d/b/a/ NV Energy (“Sierra”)
and Nevada Power Company d/b/a/ NV Energy (“Nevada Power” and,
together with Sierra, the “Companies” or “NV Energy”). My business address
is 6226 West Sahara Avenue, Las Vegas, Nevada. I am filing testimony on
behalf of the Companies.
2. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS MANAGER,
COAL PROCUREMENT AND OPERATIONS FOR THE
COMPANIES.
A. As Manager, Coal Procurement & Operations, I am responsible for coal
supply and planning as well as the management of coal supply logistics for
the Companies.
Brignola – IRP DIRECT 1
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3. Q. DOES EXHIBIT BRIGNOLA-DIRECT-1 TO YOUR TESTIMONY
DESCRIBE YOUR EDUCATION AND EMPLOYMENT
EXPERIENCE?
A. Yes.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. Yes. I have appeared in numerous proceedings before the Commission and
most recently in the Companies’ annual Deferred Energy Accounting
Adjustment cases, Docket Nos. 18-03002 and 18-03003.
5. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT
TESTIMONY IN THIS PROCEEDING?
A. I support the following portions of the “Load Forecast and Market
Fundamentals” volume: Section 2.C. (“Coal Fundamentals”) and Section
3.G. (“Coal Price Forecast”). I also sponsor the portions of Technical
Appendix Item MF-1 that relate to the coal price forecast.
6. Q. ARE THE COMPANIES’ REQUESTING CONFIDENTIAL
TREATMENT OF CERTAIN INFORMATION RELATED TO THE
COAL PRICE FORECAST?
A. Yes. Confidential coal price forecasts have been redacted from the Integrated
Resource Plan and are provided in the Confidential Materials Volume. The
Brignola – IRP DIRECT 2
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Companies’ coal price forecasts constitute commercially sensitive and/or
trade secret information that derives independent economic value from not
being generally known. This information discloses the Companies’ views and
expectations of the relevant markets. Releasing this highly sensitive
information would disadvantage the Companies and customers by limiting
the Companies’ ability to foster competition among prospective suppliers,
compromising the Companies’ negotiating position and reducing its
bargaining leverage. Publication of this information would impair the
Companies’ ability to achieve the most favorable pricing and terms and
conditions from suppliers on behalf of its customers.
7. Q. FOR HOW LONG DO THE COMPANIES REQUEST
CONFIDENTIAL TREATMENT?
A. The requested period for confidential treatment is for no less than five years.
8. Q. WILL CONFIDENTIAL TREATMENT IMPAIR THE ABILITY OF
THE COMMISSION’S REGULATORY OPERATIONS STAFF
(“STAFF”) OR THE NEVADA ATTORNEY GENERAL’S BUREAU
OF CONSUMER PROTECTION (THE “BCP”) TO FULLY
INVESTIGATE THE 2018 INTEGRATED RESOURCE PLAN?
A. No, in accordance with the accepted practice in Commission proceedings, the
confidential material will be provided to Staff and the BCP under
standardized protective agreements with them.
Brignola – IRP DIRECT 3
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9. Q. DOES THIS CONCLUDE YOUR TESTIMONY?
A. Yes, it does.
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Brignola – IRP DIRECT 4
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Exhibit Brignola Direct-1 Page 1 of 1
QUALIFICATIONS OF WITNESS Joseph R. Brignola
Manager, Coal Procurement & Operations NV Energy
6226 West Sahara Avenue Las Vegas, NV 89151-001
(702) 402-5766
EMPLOYMENT EXPERIENCE
Fall 1999 – Present: NV Energy, Inc. Manager, Coal Procurement & Operations; Fuels Consultant
Responsible for conducting the Company’s coal supply and planning programs for the Reid Gardner, North Valmy and providing oversight for the Navajo Station’s coal supply.
July 1993 – Fall 1999: Nevada Power Company Director of Fuels Planning & Procurement; Manager of Fuels; Fuels Analyst
Responsible for administering and improving the Company’s fuels supply and planning program including coal and natural gas procurement, transportation, analysis, developing policies and formulating strategy. Led negotiating teams and administered coal and gas supply and transportation agreements.
April 1979 – July 1993: Atlantic Energy (now PEPCO) Manager, Fuels; Supervisor, Power Economics; Fuels Engineer
Responsible for administering all aspects of the Company’s fuels supply program encompassing contracting, procurement, transportation, developing policies and strategies for coal, natural gas, and fuel oil and regulatory relations. Also managed the heat rate improvement program and power plant water treatment activities.
EDUCATION
B.S. Chemical Engineering New Jersey Institute of Technology
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MICHAEL COLE
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV Energy Sierra Pacific Power Company d/b/a NV Energy
2018 Joint Integrated Resource Plan (2019-2038) Docket No. 18-06_____
PREPARED DIRECT TESTIMONY OF
Michael Cole
SECTION I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME, JOB TITLE, BUSINESS ADDRESS
AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is Michael Cole. I am the Treasurer for NV Energy, Inc. (“NV
Energy”), Nevada Power Company d/b/a NV Energy (“Nevada Power”),
and Sierra Pacific Power Company d/b/a NV Energy (“Sierra” and, together
with Nevada Power, the “Companies” or “NV Energy”). My business
address is 6226 West Sahara Avenue in Las Vegas, Nevada. I am filing
testimony on behalf of the Companies.
2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND.
A. I joined NV Energy in 2015 as the Treasurer and took over Risk Control
responsibilities in January 2018. I became a voting member of the Risk
Committee in 2018. Prior to joining NV Energy, I was the Treasurer for
two global manufacturing companies and for an electric and natural gas
utility. I previously worked at Standard and Poor’s Ratings Group (utilities)
and as a financial analyst for two state public utility commissions. I have an
undergraduate and graduate degree in business with an emphasis in finance.
Cole – IRP DIRECT 1
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Additional details regarding my professional background and experience
are in my Statement of Qualifications which is provided as Exhibit Cole-
Direct-1.
3. Q. PLEASE DESCRIBE YOUR CURRENT RESPONSIBILITIES.
A. My responsibilities, broadly speaking, include aspects of finance, treasury,
and risk control. In this latter capacity, I am responsible for identifying and
elevating to executive management any departures from approved policies
and procedures, including Energy Supply Plans (“ESPs”). Also, I am
responsible for several Sarbanes-Oxley controls relating to finance, treasury
and risk control (including the oversight of the fuel and purchase power
transaction and payment cycle). There have been no material changes to the
risk control function or controlling documents since the change in
responsibilities earlier this year.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. Yes, I have previously testified in proceedings before the Commission, most
recently in Docket No. 17-06003. I have also testified before regulatory
bodies in Maine and Illinois.
5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
PROCEEDING?
A. I sponsor Section 4 (“Financial Plan”) in the 2018 Joint Integrated Resource
Plan’s (“2018 Joint IRP”) Supply Side Plan narrative, and testify to the
Companies’ ability to finance the projects identified in the 2018 Joint IRP.
Cole – IRP DIRECT 2
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6. Q. ARE ANY OF THE MATERIALS YOU ARE SPONSORING
CONFIDENTIAL?
A. Yes. The Companies’ external financing requirements, which are described
in the Financial Plan, are confidential.
7. Q. WHAT EXHIBITS ARE ATTACHED TO YOUR TESTIMONY?
A. My statement of qualifications are attached as Exhibit Cole-Direct-1.
SECTION II – ABILITY TO FINANCE THE 2018 JOINT IRP
8. Q. WHAT ARE THE COMPANIES’ CAPITAL REQUIREMENTS FOR
THE 2018 JOINT IRP ACTION PLAN?
A. The capital expenditures (excluding AFUDC equity) of the Preferred Plan
and the Alternative Plan are shown below in Figure Cole-Direct-1 and
Figure Cole-Direct-2 for Nevada Power and Sierra, respectively. These
figures were constructed using the capital expense recovery (“CER”)
model. For Nevada Power, total capital expenditures for the 2019 – 2038
period are approximately $5 billion for both the Preferred and Alternatve
Plan. For Sierra, total capital expenditures for the 2019 – 2038 period are
about $2.8 billion for both plans.
Cole – IRP DIRECT 3
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FIGURE COLE-DIRECT-1 NEVADA POWER
CAPITAL EXPENDITURES ($ - MILLIONS)
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FIGURE COLE-DIRECT-2 SIERRA
CAPITAL EXPENDITURES ($ - MILLIONS)
Cole – IRP DIRECT 4
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9. Q. PLEASE DESCRIBE THE PROJECTS REFLECTED IN THE
COMPANIES’ PREFERRED AND ALTERNATIVE PLANS.
A. For both Nevada Power and Sierra, the projected capital expenditures for
the Preferred and Alternative plans represent total capital expenditures
necessary to support ongoing operations and previously approved capital
projects, as well as this 2018 Joint IRP.
10. Q. HOW WOULD THE COMPANIES FINANCE THE PREFERRED
OR ALTERNATIVE PLANS?
A. For both utilities, cash generated from operations during the 2019 – 2038
period should be sufficient to fund the capital projects set forth in the CERs
for the Preferred and Alternative plans. Nevertheless, the Companies will
have a continued need to access external financing in order to i) fund
working capital, ii) refinance maturing debt, and iii) maintain capital
structures that are appropriate for their investment grade credit ratings. For
Nevada Power, Figure FP-3 in the Financial Plan section of the 2018 Joint
IRP Supply Side Plan narrative shows annual total external financing over
the forecast horizon for the Preferred and Alternative plans. For Sierra,
external financing projections are shown in Figure FP-4.
11. Q. WILL THE COMPANIES BE ABLE TO ACCESS THE CAPITAL
MARKETS IN ORDER TO FINANCE THE PREFERRED OR
ALTERNATIVE PLANS, IF NEEDED?
A. Yes. However, in order to ensure continued access to debt and equity
capital and to serve customers at just and reasonable rates, regulatory
support is essential. Over-reliance on the debt markets to fund future
Cole – IRP DIRECT 5
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investments could lead to credit quality weakening and excessive financing
costs. Regulatory support is necessary to attract equity capital, maintain a
balanced capital structure, and prevent a deterioration in credit metrics.
12. Q. ARE THERE ANY ATTRIBUTES OF THE 2018 JOINT IRP THAT
COULD POTENTIALLY HAVE A NEGATIVE IMPACT ON THE
COMPANIES’ CREDIT RATINGS OR FINANCING COSTS?
A. Yes, even though the Companies’ creditworthiness have improved
materially over the past five years, credit quality can be impacted by the
funding requirements associated with capital expenditures and by financial
commitments created by contracts such as power purchase agreements
(“PPAs”). The Commission is well-familiar with the impact on credit
quality from funding requirements associated with capital expenditures
which can be estimated using changes in equity and debt capital balances.
PPAs are also part of the rating agencies’ evaluation process and have the
potential to negatively impact credit ratings, depending on the magnitude
and terms of a utility’s PPA portfolio, other pending uncertainties, and
issuer mitigation strategies.
The 2018 Joint IRP recommends the addition of 1,001 megawatts of solar
photovoltaic energy, all of which will be supplied through PPAs. If
executed, these contractual commitments are expected to negatively impact
credit quality unless mitigated by other actions. For Nevada Power, the
impact from the PPAs should be mitigated by maintaining a capital structure
with an equity ratio of between 50 percent - 52 percent. For Sierra, an equity
ratio at the higher end of that range (i.e., 52 percent) appears necessary to
Cole – IRP DIRECT 6
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maintain credit metrics that are appropriate for Sierra’s current credit rating.
The underlying assumption is that the Commission accepts these higher
equity ratios when establishing the Companies’ weighted average cost of
capital and revenue levels.
It is important to note that the rating agencies do not follow the same purely
quantitative and uniform approaches in incorporating reliance on purchased
power into their ratings evaluation processes. Standard & Poor’s takes a
heavily quantitative approach to evaluating and incorporating the impact of
PPAs on credit quality. They evaluate the specific characteristics of each
PPA and then impute an amout of debt into their ratio calculations to
represent a debt equivalent. Moody’s and Fitch take a more qualitative
approach. PPAs that are reported as ‘long-term debt and financial and
capital lease obligations’ in the Companies’ annual and quarterly financial
statements filed with the Securities and Exchange Commission are
incorporated directly into Moody’s and Fitch ratio calculations. For those
PPAs that are not reflected on the balance sheet, Moody’s and Fitch review
and consider their impact during the evaluation process. Irrespective of the
approach, PPAs represent a financial obligation that impairs credit quality
unless otherwise mitigated.
The additional PPAs detailed in the 2018 Joint IRP and the ESP will have
some impact on credit quality. However, the Companies expect to be able
to mitigate that impact through prudent financial management. If the
Preferred Plan was to trigger an adverse rating action, the Companies’
overall cost of capital would likely increase. These rating actions, however,
Cole – IRP DIRECT 7
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are unlikely to jeopardize the Companies’ ability to enter into the PPAs and
to implement the Preferred Plan (or the Alternative Plan).
13. Q. ARE THE COMPANIES REQUESTING CONFIDENTIAL
TREATMENT OF INFORMATION CONTAINED IN THE
FINANCIAL PLAN?
A. Yes. The financial analysis has been filed under seal because it contains
sensitive financial projections and non-public financial data. The
Companies request that the information set forth in the confidential material
remain subject to the rules governing the treatment of confidential material
for not less than five years.
14. Q. WILL CONFIDENTIAL TREATMENT OF THIS INFORMATION
IMPAIR THE ABILITY OF THE PUBLIC UTILITIES
COMMISSION OF NEVADA’S REGULATORY OPERATIONS
STAFF (“STAFF”) AND THE NEVADA ATTORNEY GENERAL’S
BUREAU OF CONSUMER PROTECTION (“BCP”) TO FULLY
INVESTIGATE THE COMPANIES’ PROPOSALS?
A. No. In accordance with the accepted practice in Commission proceedings,
the confidential material will be provided to Staff and the BCP under
standardized protective agreements. I am prepared to address any questions
the parties may have regarding the Financial Plan.
15. Q. DOES THIS CONCLUDE YOUR TESTIMONY?
A. Yes, it does.
Cole – IRP DIRECT 8
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Exhibit Cole-Direct-1
MICHAEL COLE TREASURER
NV Energy, Inc. 6226 West Sahara Avenue
Las Vegas, NV 89151 (702) 402-5623
SUMMARY
Michael Cole has been with NV Energy since August 2015, and has approximately 25 years of experience in corporate finance, treasury operations, and corporate development. In addition, Mr. Cole has about 20 years of diverse utility experience including Aquila, Inc., Standard & Poor’s Ratings Group, Maine Public Utilities Commission, and the Illinois Commerce Commission. Prior to joining NV Energy, Mr. Cole was the Treasurer for two separate, private-equity owned global manufacturing companies.
At NV Energy, Mr. Cole has primary responsibility for all finance and treasury-related items including capital structure, credit ratings, financings, debt management & compliance, cash management & liquidity, cash forecasting, and large project evaluations.
EMPLOYMENT
NV Energy, Inc. – Treasurer, Las Vegas NV (1 year)
WireCo World Group, Inc. – Vice President & Treasurer, Kansas City MO (2 years)
Polymer Group, Inc. – Treasurer, Charlotte NC (2 years)
The Calvin Group – Principle, Kansas City MO (2 years)
Aquila, Inc. (f/k/a Utilicorp United, Inc.) – Treasurer and Vice President Finance (previous positions included Director - Corporate Development and Assistant Treasurer - International Finance), Kansas City MO (11 years)
Standard & Poor’s Ratings Group – Associate Director Utilities, New York NY (3 years)
Maine Public Utilities Commission – Senior Financial Analyst, August ME (1 year)
Illinois Commerce Commission – Financial/Management Analyst, Springfield IL (5 years)
EDUCATION
Masters of Business Administration – Finance (Western Illinois University, Macomb IL) Bachelor of Business – Finance (Western Illinois University, Macomb IL)
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KEVIN GERAGHTY
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV Energy Sierra Pacific Power Company d/b/a NV Energy
2018 Joint Integrated Resource Plan (2019-2038) Docket No. 18-06_____
PREPARED DIRECT TESTIMONY OF
Kevin C. Geraghty
I. INTRODUCTION AND BACKGROUND
1. Q. PLEASE STATE YOUR NAME, TITLE, BUSINESS ADDRESS AND
IDENTIFY THE PARTY FOR WHOM YOU ARE FILING
TESTIMONY.
A. My name is Kevin Geraghty. I am the Senior Vice President, Operations for
Nevada Power Company d/b/a NV Energy (“Nevada Power”) and Sierra
Pacific Power Company d/b/a NV Energy (“Sierra” and together with Nevada
Power, the “Companies”). My business address is 6226 West Sahara Avenue
in Las Vegas, Nevada. I am filing testimony on behalf of the Companies.
2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
EXPERIENCE.
A. I hold a Bachelor of Science Degree in Electrical Engineering from the
University of Pittsburgh in Pittsburgh, Pennsylvania. Before joining the
Companies, I was employed by Allegheny Energy in various director-level
positions, where I managed all aspects of the operations of six coal plants,
seven small hydro plants, and several combustion turbine sites. While at
Allegheny I managed the siting and development of a 1,080 MW combined
Geraghty-IRP DIRECT 1
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cycle facility in La Paz County, Arizona, and several of Allegheny’s other
energy projects and/or contracts in Nevada, Arizona and California.
I am currently responsible for managing all of the Companies’ supply
resources, as well as transmission and distribution resources, including jointly-
owned assets, resource optimization for the Companies, and gas operations at
Sierra. My responsibilities include new business, operations, maintenance,
construction, planning, project development, capital management, power
marketing, fuel procurement and financial functions. More details regarding
my professional background and experience are set forth in Exhibit
Geraghty-Direct-1.
3. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. Yes, I have testified in numerous proceedings before the Commission. My most
recent appearance in an integrated resource plan (“IRP”) case was in Sierra’s
2017 IRP First Amendment, Docket No. 17-02007.
4. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
PROCEEDING?
A. I support the Supply Side Plan narrative sections for Generation. In Section II
below, I discuss the Companies’ requests for changes to the retirement dates
of several generating units. I also am the primary witness responsible for
discussing the conditional early retirement of North Valmy Unit 1 (from
December 31, 2025 to December 31, 2021).
5. Q. WHAT EXHIBITS ARE ATTACHED TO YOUR TESTIMONY?
Geraghty-IRP DIRECT 2
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A. I have attached Exhibit Geraghty-Direct-1, Statement of Qualifications, to
my testimony.
6. Q. ARE YOU SPONSORING ANY ITEMS IN THE TECHNICAL
APPENDICES ACCOMPANYING THIS IRP FILING?
A. Yes, I am sponsoring the following items in the Technical Appendices:
GEN-1 Unit Characteristics Table (Confidential)
GEN-2 New Generation Unit Performance Data (Confidential)
GEN-3 2017 Plant Emission Rates (Confidential)
GEN-4 Generating Plant Life Span Analysis Processes (“LSAP”)
7. Q. ARE ANY OF THE MATERIALS YOU ARE SPONSORING
CONFIDENTIAL?
A. Yes. GEN-1 and GEN-3 contain confidential cost and performance data. GEN-
2 includes confidential information regarding the Companies’ estimated
performance of potential future resources.
These Technical Appendices contain commercially sensitive and/or trade
secret information that derive independent economic value from not being
generally known. This information discloses the Companies’ views and
expectations of the relevant markets and its future procurement opportunities.
This information is not known outside the Companies and its distribution is
limited within the Companies. Releasing this highly sensitive information
would disadvantage the Companies and their customers by limiting their
ability to foster competition among prospective suppliers; compromising the
Companies’ negotiating position and reducing bargaining leverage.
Publication of this information would unfairly advantage competing suppliers
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and impair the Companies’ ability to achieve the most favorable pricing and
terms and conditions from suppliers on behalf of its customers.
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8. Q. FOR HOW LONG DO THE COMPANIES REQUEST
CONFIDENTIAL TREATMENT?
A. The requested period for confidential treatment is for no less than five years.
9. Q. WILL CONFIDENTIAL TREATMENT IMPAIR THE ABILITY OF
THE COMMISSION’S REGULATORY OPERATIONS STAFF
(“STAFF”) OR THE NEVADA ATTORNEY GENERAL’S BUREAU
OF CONSUMER PROTECTION (“BCP”) TO FULLY INVESTIGATE
THE 2018 RESOURCE PLAN OR THE INFORMATION SET FORTH
IN THESE TECHNICAL APPENDICES?
A. No, in accordance with the accepted practice in Commission proceedings, the
confidential material will be provided to Staff and the BCP under standardized
protective agreements with them.
II. LIFE SPAN ANALYSIS PROCESS (“LSAP”)
10. Q. PLEASE DESCRIBE THE REQUEST FOR APPROVALS RELATING
TO THE FIVE LSAPS FOR THE GENERATING STATIONS
IDENTIFIED BELOW.
A. I recommend that the Commission approve the requests to change the
retirement dates for the units described below. This request based on the
substantial analysis presented in the LSAPs provided in Technical Appendix
GEN 4.
Geraghty-IRP DIRECT 4
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11. Q. PLEASE BRIEFLY DESCRIBE THE LIFE SPAN ANALYSIS
PROCESS.
A. The LSAP provides structure, and follows a framework, within which
generation units are assigned a retirement date. The LSAP also addresses the
periodic reassessment of retirement dates for existing units. A significant
driver of the LSAP was a perceived need to review the retirement of generating
units outside the rate-setting process (through depreciation studies and rate
adjustment proceedings). The criteria for reassessment are specified in the
LSAP protocol and include annual business reviews, infrastructure issues, the
occurrence of significant events (e.g. catastrophic failure) and changes in
environmental regulations. In addition, being within the “last decade of a unit
life span,” automatically triggers a retirement date reassessment through the
LSAP. During the reassessment process, environmental regulations,
infrastructure implications, and unit condition are evaluated. Upon review of
these considerations, options are developed. Typically, at a minimum, a “retire
now” option is considered and a “invest to meet or move the retirement date”
option is considered. Additional options can be developed if appropriate. The
Resource Planning department determines how the capacity and energy
represented by a unit would be replaced. The costs (or savings) to continue
operation (or retire) are then subjected to additional economic analysis. The
LSAP economics can be evaluated two ways: through a conventional business
case analysis measuring cash flows, or through a resource planning analysis
measuring the present worth of revenue requirements (“PWRR”). The LSAP
also takes into account potential risk items as well as the economic analysis
when making a retirement date recommendations.
Geraghty-IRP DIRECT 5
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12. Q. WHAT ARE THE COMPANIES RECOMMENDING WITH REGARD
TO THE RESULTS OF THE LSAPS PERFORMED AS PART OF THIS
JOINT INTEGRATED RESOURCE PLAN?
A. The Companies are recommending that retirement dates be changed and that
the following units continue operating to at least the new projected dates:
GERAGHTY DIRECT FIGURE 1
Unit Commission
Approved Date Recommended
Date Clark Unit 4 2020 2030 Clark Mountain Units 3 & 4 2024 2034 Fort Churchill Unit 1 2025 2028 Harry Allen Unit 3 2025 2035 Sun Peak Units 3, 4, 5 2026 2031 North Valmy Unit 1 (Conditional) 2025 2021
13. Q. PLEASE DESCRIBE THE RESULTS OF THE LSAP REPORTS FOR
THESE UNITS?
A. The following is a summary of the LSAPs included in GEN-4:
Clark Unit 4 has a Commission-approved retirement date of 2020.
The unit is in good operating condition and is primarily expected to provide
capacity support for Nevada Power’s system, with few operating hours. The
Companies are recommending that the retirement date for Clark Unit 4 be
extended to 2030. This can be completed without major capital expenditures,
but due to the age of this unit, any major investment will trigger a reassessment
of an immediate retirement.
Clark Mountain Units 3 & 4 have Commission-approved retirement
dates for both units of 2024. The units are in good operating condition and are
expected to continue to provide peaking operational service as well as quick
support for non-dispatchable resources to support Sierra’s system, with few
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operating hours. The Companies are recommending that the retirement dates
for both Clark Mountain units be extended to 2034. Even though support for
non-distpatchable resources has been added to the operational mission for
these units, major non-routine, capital expenditures have not been identified
or are expected to be required to continue operating these units for another 10
years.
Fort Churchill Unit 1 has a Commission-approved retirement date of
2025. The unit is in good operating condition and is expected to primarily
provide capacity and energy to support the Carson load pocket within Sierra’s
system, as well as support for non-dispatchable generating resources. The
Companies are recommending that the retirement date for Fort Churchill 1 be
extended to 2028 to coincide with the retirement of Fort Churchill 2. No capital
expenditures are expected to be required to continue operating Fort Churchill
Unit 1 unit 2028.
Harry Allen Unit 3 has a Commission-approved retirement date of
2025. The unit is in good operating condition and is expected to primarily
provide peaking energy to Nevada Power’s system. The Companies are
recommending that the retirement date for Harry Allen Unit 3 be extended to
2035. No major capital expenditures have been identified or are expected to
be required to continue operating the unit for another 10 years.
Sun Peak Units 3, 4, & 5 have Commission approved retirement dates
of 2026. The units are in good operating condition and are expected to
primarily provide peaking energy for Nevada Power’s system. The Companies
are recommending that the retirement dates for the Sun Peak Units be extended
to 2031. No major capital expenditures have been identified or are expected to
be required to continue operating the units the additional five years.
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14. Q. HOW IS THE COMPANIES’ OPERATIONAL STRATEGY FOR ITS
GENERATION FLEET EVOLVING AS THE COMPANIES
TRANSFORM THEIR ENERGY SUPPLY PORTFOLIO?
A. The Companies’ preferred plan, the Low Carbon Case, and the Companies’
alternative plan, the Renewable Case, both request the approval of six power
purchase agreements with non-disptachable solar photovoltaic generating
resources totaling an addition of 1,001 megawatts (“MW”) (ac). In addition,
the two plans add 100 MW of dispatchable battery storage with 400 MWh of
energy delivery capability. The addition of these resources, which, as
witnesses Shawn M. Elicegui and Marc Reyes explain in more detail, were
selected based on economics, consistent with both the values of our customers
and trends in western energy markets.
The integration of this quantity of renewable resources requires at least two
operational proficiencies: a changing operational mindset and system
flexibility. The Companies’ operational mindset has changed – many
conventional generation resources, including what have long-been considered
base-loaded steam resources fueled by coal and natural gas, have moved to
seasonal operations, improved turndowns, ramp rates and start more
frequently. This preserves the generation capacity that is necessary to meet
customers’ peak needs, while accommodating the addition of non-
dispatchable renewable resources. This changed operational mindset is
reflected in the request to extend the retirement dates of the resources
discussed above.
A second key operational attribute is system flexibility. The integration of
non-dispatchable renewable resources highlights and reinforces the need for
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dispatchable generating units (including storage) that can respond quickly to
changing load and generation patterns. We analyzed data for the month of
February 2018 for the southern Nevada portion of the system, calculating
native load plus non-native load in southern Nevada and subtracting utility
scale solar output (i.e., south native load + south non-native load – south
utility-scale solar). As shown in Figure 2 below, during the month, the average
of that figure ramps from 1,730 MW of load at 1500 hours to 2,420 MW of
load at 1815 hours, requiring approximately 700 MW of generation ramping
in just over three hours. This gap can only be filled with either spinning reserve
capability, storage or a fast-starting peaking unit.
GERAGHTY DIRECT FIGURE 2
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15. Q. WHAT ARE YOUR OBSERVATIONS FROM THIS ANALYSIS?
A. I identify three such observations. First, this analysis highlights the difference
between long-term planning outlooks and real-time operational issues. As
Sachin Verma notes in his prepared direct testimony, the Federal Energy
Regulatory Commission recently issued its 2018 summer loads and resources
assessment for the United States. That assessment concludes that adequate
generation capacity exists in all regions (except the Electric Reliability
Council of Texas territory) to meet customer needs based on higher-than-
average temperature forecasts. However, the California Independent System
Operation (“CAISO”) released its 2018 summer loads and resources
assessment at just about the same time, and reached a different conclusion.
CAISO ran 2,000 production scenarios for the summer of 2018 and found that
potential Stage 2 emergency conditions (which can lead to the curtailment of
non-firm load) resulted in 52 percent of the scenarios run. Projections for 2018
show that the CAISO faces significant risk of encountering conditions that
could result in less than required operating reserves. The increased risk in 2018
over 2017 is primarily a result of hydro conditions and the retirement of
dispatchable generation that had been available to meet high load conditions
that persist after the solar generation ramps down in the late afternoon. The
report concludes that the CAISO is at greatest risk if seasonal peak producing
hot weather occurs in late August and early September.
The bottom line is that we need to develop additional tools to assess potential
operating conditions as we transform our energy supply portfolio. Traditional
long-term planning models that focus on generation capacity do not capture
the entire picture. Stochastic and probabilistic analyses need to be developed
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to assess operating conditions to ensure that our system is highly reliable and
maintains the flexibility necessary to incorporate additional renewable
resources.
16. Q. WHAT ARE THE OTHER KEY OBSERVATIONS?
A. The second observation is that what were traditionally viewed as benign or
“safe” shoulder months, now (and in the future) represent critical operational
and economic periods that require assessment and adaptation. This fact is
highlighted that NV Energy’s southern system experienced, on average, the
need for 700 MW of ramping capability in a three-hour period in February.
February is a month in which load conditions are typically low and is utilized
for facilitating maintenance and repair of conventional resources.
The third observation is similar to the second. The CAISO report notes that its
operational risk extends to hours that, traditionally, are later than the system
peak. Specifically, key risk periods extend to hour ending 20, or 8:00 p.m.
Again, this fact highlights the need for flexibility – resources that can
physically and economically respond to changing load and generation patterns
while maintaining constant system reliability as additional renewable energy
is integrated into the system.
17. Q. HOW DO THESE OBSERVATIONS INFORM THE COMPANIES’
SELECTION OF THE PREFERRED PLAN?
A. The key difference between the preferred plan (the Low Carbon Case) and the
alternative plan (the Renewable Case) relates to the retirement of North Valmy
Unit 1. Both plans add significant new, clean energy resources. As part of the
interconnection process, we have negotiated terms and conditions that allow
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the Companies’ to use not only the energy and capacity of these resources to
meet customer needs, but also utilizes the reactive power capabilities of the
electronic inverters to provide ancillary services such as voltage and frequency
support. Both plans add battery storage. We are excited about these elements
of the plan, as we will gain operational experience with an emerging energy
supply asset that will greatly assist in meeting the flexibility required for
increased dependence on intermittent resources.
18. Q. PLEASE DESCRIBE THE COMPANIES’ RECOMMENDATION FOR
NORTH VALMY UNIT 1.
A. The Companies’ preferred plan, the Low Carbon Case, provides for the
retirement of North Valmy Unit 1 on or before December 31, 2021. The
current retirement date of North Valmy Unit 1 is December 31, 2025.
The recommendation to retire North Valmy Unit 1 is not made lightly because
the unit provides needed operational flexibility to the overall northern system
and specifically the Carlin Trend mining area. As Mr. Verma explains, we are
capable of operating the northern Nevada system without North Valmy Unit 1
based on our current forecasts and modeling assumptions. There are,
however, conditions that could develop that would place the northern Nevada
system at an unacceptable level of risk without North Valmy Unit 1. In
addition, different from the CAISO 2018 summer assessment, the assessment
by the company is not a probabilistic examination of real-time reliability with
and without North Valmy Unit 1 .Accordingly, the following conditions would
have to be met in order for the Companies to retire North Valmy Unit 1 early.
Those conditions include: (a) Question 3 does not pass and (b) the three
renewable resources (identified below) are approved by the Commission and
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operational (or sufficiently far enough along to become operational before the
summer of 2022). Because all three projects are located in northern Nevada,
the generation and battery storage from these projects would provide
additional capacity and voltage support to mitigate the impact of retiring North
Valmy Unit 1.
GERAGHTY DIRECT FIGURE 3
Project PV Nameplate Capacity (MW)
Storage Capacity (MW)
Resource Planning Capacity
1. NextEra Dodge Flat
200 50 117
2. NextEra Fish Springs Ranch
100 25 58
3. Cypress Creek Battle Mountain Solar
101 25 59
Total 401 100 234
19. Q. ARE THERE OTHER CONDITIONS THAT WOULD PREVENT
THE COMPANIES FROM RETIRING NORTH VALMY UNIT 1
EARLY?
A. Yes. As described in the Supply Side Narrative, several additional conditions
must be met to retire North Valmy Unit 1:
Growth in total system load in Sierra’s system in excess of 2,600 MW will
trigger reevaluation and may delay the unit retirement.
Unexpected shutdown or retirement of other generation sources in Northern
Nevada
Approval and successful progress towards an operational date prior to May
2023 of dynamic reactive compensation at the North Valmy Substation.
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The Companies will monitor the fuel and purchase power markets for
adverse changes that may adversely impact customer bills due to the
retirement of North Valmy Unit 1
No increased or unacceptable risk to customer reliability as a result of retiring
North Valmy Unit 1
To monitor and ensure that the conditions identified are being satisfied, the
Companies will establish a process for reviewing the criteria no fewer than two times
per year. The Resource Planning department will track and provide the status of
conditions for Risk Committee review and approval. If all conditions are met
satisfactorily, then the unit would be retired early.
III. SUMMARY
20. Q. WOULD YOU PLEASE SUMMARIZE YOUR RECOMMENDATION
TO THE COMMISSION?
A. I recommend that the Commission approve the request to change the
retirement dates for the units discussed above and as presented in the LSAPs
provided in Technical Appendix GEN 4.
21. Q. DOES THIS CONCLUDE YOUR TESTIMONY?
A. Yes, it does.
Geraghty-IRP DIRECT 14
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Geraghty-Direct-1 Page 1 of 2
KEVIN C. GERAGHTY SVP, Operations
NV Energy, Inc 6226 West Sahara Avenue Las Vegas, NV 89146 (702) 402-5662
Mr. Geraghty joined NV Energy, Inc. (“NVE”) in June 2008 as Executive, Power Generation and currently serves as the company’s Senior Vice President for Operations. He has 30 years of experience in power generation with extensive knowledge of operations, maintenance, construction and management of coal, gas and hydro facilities. Mr. Geraghty has prepared and/or directed the preparation of various reports and analyses for submission to multiple state jurisdictions, EPA, NERC and FERC. Mr. Geraghty has also sponsored testimony before the Arizona Corporation Commission.
EMPLOYMENT HISTORY
NV Energy, Inc. 11/17 to Present
SVP, Operations Responsible for all energy and electric operations including transmission, electric delivery, gas delivery, generation and resource optimization.
NV Energy, Inc. 6/08 to 11/17
SVP, Energy Supply Responsible for managing all of NV Energy’s power generation assets, interests in jointly-owned assets, resource optimization and the gas local distribution company in northern Nevada. Responsibilities include resource optimization, coal procurement, operations, maintenance, construction, strategic planning, capital management and financialfunctions associated with gas operations, power production and procurement.
Allegheny Energy 12/87 to 6/08
Director Level Assignments: Smith, Western, Fort Martin and Harrison Regions 5/99 to 12/07
Managed all aspects of six (6) coal plants, seven (7) small hydro plants and multiple peaking combustion turbine sites. Managed the development and siting of a 1,080 MW combined cycle facility in La Paz County, Arizona. Managed the company’s interest in several other energy projects and/or contracts in Nevada, Arizona and California.
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Manager Level Assignments: Operations, Maintenance and Engineering – Hatfield’s Ferry and Harrison Power Stations 4/93 to 5/99
Managed all departmental-specific functions at two (2) large, coal-fired facilities; each facility had three (3) large (555-665) supercritical units.
Engineering Level Assignments: Plant (Hatfield’s Ferry) and Construction 12/87 to 4/93
Performed plant engineering assignments in support of production, reliability and performance at the 1,665 MW coal-fired Hatfield’s Ferry Power Station. Performed construction engineering assignments in support of large O&M and CAPEX projects at every facility in the fleet (including coal, gas, hydro and oil facilities).
EDUCATION
University of Pittsburgh, Pittsburgh, PA Bachelor of Science in Electrical Engineering
ASSOCIATIONS AND MEMBERSHIPS Board Member, Las Vegas Natural History Museum Board Member, FIRST Nevada
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Operations
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DAVID HARRISON, JR.
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy
2018 Joint Triennial Integrated Resource Plan (2019-2038) Docket No. 18-06____
PREPARED DIRECT TESTIMONY OF
David Harrison, Jr.
I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME, JOB TITLE, BUSINESS ADDRESS AND
PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is David Harrison, Jr. I am an economist and Managing Director at NERA
Economic Consulting (“NERA”), an international firm of economists specializing
in microeconomics. Established in 1961, NERA has earned wide recognition for its
work in energy, environmental economics and regulation, antitrust, public utilities
regulation, transportation, health care, and international trade. The work is
performed by more than 500 professional staff members qualified in economics,
statistics, mathematics, computer applications, and business administration. NERA
operates in numerous offices across North America, Europe, Asia and Australia.
My business address is 200 Clarendon Street, Boston, Massachusetts. I am filing
testimony on behalf of Nevada Power Company (“Nevada Power”) and Sierra
Pacific Power Company (“Sierra) (together the “Companies”).
2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
EXPERIENCE.
A. I received a Ph.D. in Economics from Harvard University, where I was a Graduate
Prize Fellow. I also hold a B.A. magna cum laude in Economics from Harvard
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College, where I was a member of Phi Beta Kappa, and a M.Sc. in Economics from
the London School of Economics, where I was the Rees Jeffreys Scholar.
Before joining NERA, I was an Associate Professor at the John F. Kennedy School
of Government at Harvard University, where I taught microeconomics, energy and
environmental policy, benefit-cost analysis, and other subjects for more than a
decade. I was a member of the Faculty Steering Committee of the Energy and
Environmental Policy Center at Harvard University, and a member of the Advisory
Board of the Interdisciplinary Program in Health at the Harvard School of Public
Health.
I earlier served as a Senior Staff Economist on the President’s Council of Economic
Advisors, where my areas of responsibility included energy and environment,
natural resources, occupational health and safety, and transportation. I also have
worked at the U.S. Department of Transportation, the U.S. Department of Housing
and Urban Development, and the National Bureau of Economic Research. My full
curriculum vita is provided in Exhibit Harrison-Direct-1.
3. Q. PLEASE SUMMARIZE YOUR BACKGROUND RELATED TO BENEFIT-
COST ANALYSIS OF ENVIRONMENTAL POLICIES.
A. My background includes extensive experience related to benefit-cost analysis,
particularly as it relates to environmental regulation. I have analyzed the benefits
and costs of environmental policy for more than 40 years, beginning in 1974, when
I participated in the benefit-cost study of the automotive emission standards
mandated by the 1970 Clean Air Act that was undertaken by the National Academy
of Sciences under a Congressional directive. I have authored or co-authored two
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books and numerous articles and consulting reports related to the benefits and costs
of environmental policies. At Harvard, the courses I taught in energy and
environmental policy and microeconomics included analyses of major
environmental policies, including those related to the Clean Air Act and other major
environmental legislation. At the President’s Council of Economic Advisors, I was
an acting member of the Regulatory Council, the group charged with the
responsibility of developing benefit-cost methodologies to evaluate federal
regulatory requirements. As the principal staff member on the Regulatory Analysis
Review Group, I participated in the review of major proposed regulations. These
reviews included analyzing information prepared by federal agencies on the costs
and benefits of proposed regulations, including those related to the Clean Air Act,
the Clean Water Act, and other major environmental statutes.
At NERA, I have directed numerous projects related to benefit-cost assessments of
environmental regulations, including air quality and climate change, water quality,
and other categories. In the area of water quality, I have carried out fish protection
analyses for numerous facilities on the East Coast, the Hudson River, the Great
Lakes, and the West Coast. I have been a consultant to the South Coast Air Quality
Management District, the Massachusetts Department of Environmental Protection,
the U.S. Environmental Protection Agency (“U.S. EPA”), the Organization of
Economic Cooperation and Development, the European Commission, the UK
Department for Environment, Food and Rural Affairs, the Italian Ministry of the
Environment, and other public agencies, as well as to numerous private companies
and organizations.
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4. Q. PLEASE SUMMARIZE YOUR BACKGROUND RELATED TO CLIMATE
CHANGE POLICY AND EMISSIONS TRADING PROGRAMS.
A. I have participated in the development and analysis of emissions trading programs
for more than 30 years, beginning in 1979 when I was on the senior staff of the
President’s Council of Economic Advisors and the U.S. EPA was developing its
emissions trading program to provide flexibility in meeting air quality objectives.
In terms of cap-and-trade programs developed to address air quality concerns, I was
a member of the advisory committee for the RECLAIM program, an innovative
emissions trading program in the Los Angeles air basin developed in the early
1990s, and I advised on the Acid Rain Trading Program for electricity generators
developed as part of the 1990 Clean Air Act Amendments. I have also participated
in the development and analysis of the averaging, banking, and trading programs
for mobile sources of air emissions.
With regard to climate change, I have participated actively in the development or
evaluation of greenhouse gas (“GHG”) emission trading programs and proposals
throughout the globe, including in the United States (California, the Northeast, the
Midwest, and various federal initiatives), Europe, Asia, and Australia. Along with
NERA colleagues, I have advised the European Commission and the UK
government on the development and implementation of the European Union
Emissions Trading Scheme (“EU ETS”), the major GHG cap-and-trade program
that has been implemented thus far. I have provided advice to government officials
developing the Regional Greenhouse Gas Initiative (“RGGI”) in the Northeast as
well as the California cap-and-trade program and have evaluated proposed
programs in various other jurisdictions. My colleagues and I have developed
numerous evaluations of various federal legislative proposals to create a U.S. cap-
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and-trade program, as well as evaluations of other climate change policies. I co-
directed a study evaluating the effects of a national carbon tax proposal and a study
of the final Clean Power Plan, the major regulation for carbon dioxide emissions at
existing power plants under the Clean Air Act (although as noted below, the U.S.
EPA recently has proposed to repeal the Clean Power Plan).
5. Q. PLEASE SUMMARIZE YOUR EXPERIENCE RELATED TO ECONOMIC
IMPACT ASSESSMENTS.
A. I have extensive experience evaluating the economic impacts of various
governmental policies and projects, both public and private, including major energy
facilities. In particular, I have led more than three dozen assessments of the
economic impacts of energy and environment policies and various infrastructure
programs. These assessments have involved a wide range of economic models and
have considered numerous areas in the U.S. and abroad, including virtually all
states in the United States (and assessments for the country as whole) as well as
France, Spain, the European Union, the Bahamas, and countries in Africa and the
Middle East.
6. Q. PLEASE SUMMARIZE YOUR SPECIFIC EXPERIENCE RELATED TO
ASSESSING ENVIRONMENTAL COSTS AND ECONOMIC IMPACTS
RELATED TO INTEGRATED RESOURCE PLANNING IN NEVADA.
A. In 1993, I directed two studies to evaluate the external costs of electric utility
resource selection, one in southern Nevada and one in northern Nevada. These
studies were prepared for Nevada Power Company d/b/a NV Energy (“Nevada
Power”) and Sierra Pacific Power Company d/b/a NV Energy (“Sierra,” the
“Company,” and together with Nevada Power the “Companies”). It is my
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understanding that the results from these studies were used by these Companies in
previous resource plan filings that were approved by the Commission.
In most years since 2006, I have directed studies evaluating the environmental costs
and economic benefits of the Integrated Resource Plans (“IRP”) and related
amendments for Nevada Power and Sierra. The Commission reviewed the 2006
study as well as my testimony on the subject as part of Nevada Power’s 2006 IRP
(Docket No. 06-06051) and Sierra’s Thirteenth Amendment to its 2005-2024 IRP
(Docket No. 06-07010). The Commission approved the Companies’ requests in
relevant part in April 2007. The Commission reviewed the 2007 study as well as
my testimony on the subject as part of Sierra’s 2007 IRP (Docket No. 07-06049)
and Nevada Power’s Fourth Amendment to its 2006 IRP (Docket No. 07-07013).
The Commission approved the Companies’ requests in relevant part in November
2007. The Commission reviewed the 2008 study as well as my testimony on the
subject as part of Nevada Power’s Eighth Amendment to its 2007-2026 IRP
(Docket No. 08-05014) and Sierra’s Third Amendment to its 2008-2027 IRP
(Docket No. 08-05015). The Commission approved the Companies’ requests in
relevant part in October 2008. The Commission reviewed the 2009-2010 study as
well as my testimony on the subject as part of Nevada Power’s 2009 IRP (Docket
No. 10-02009) and Sierra’s Eighth Amendment to its 2008-2027 IRP (Docket No.
10-03023). The Commission approved the Companies’ requests in relevant part in
July 2010. The Commission reviewed the 2010 study as well as my testimony on
the subject as part of Sierra’s 2010 IRP (Docket No. 10-07003). The Commission
approved the Companies’ requests in relevant part in December 2010. The
Commission reviewed two 2011 studies as well as my testimonies on the subject as
part of Nevada Power’s Second Amendment to its 2010-2029 IRP (Docket No. 11-
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08011) and First Amendment to its 2009 IRP (Docket No. 11-03014). The
Commission approved the Second Amendment to the 2010-2029 IRP in December
2011, and the First Amendment to the 2009 IRP in January 2012. I submitted the
2012 study as well as testimony on the subject on behalf of the Companies’ 2013-
2032 IRP in June 2012 (Docket No. 12-06053). In August 2012, I submitted a report
and testimony on Sierra’s Second Amendment to its 2010 IRP (Docket No. 12-
08009). In July 2013, I submitted a report and testimony on Sierra’s 2013 IRP
(Docket No. 13-07005). In May 2014, I submitted a report and testimony on
Nevada Power’s Emissions Reduction and Capacity Replacement Plan (Docket No.
14-05003). In June 2015, I submitted a report and testimony on behalf of the
Nevada Power’s IRP (Docket No. 15-07004). In July 2016 I submitted a report and
testimony on behalf of Sierra’s 2016 IRP (Docket 16-07001). In August 2016, I
submitted testimony on the second amendment to Nevada Power’s 2015 IRP
(Docket No. 16-08027). In September 2016 I submitted an additional report and
testimony of behalf of Sierra’s 2016 IRP in relation to the supplemental filing in
response to Procedural Order 1 (Docket No. 16-07001).
II. TESTIMONY OBJECTIVES
7. Q. WHAT ARE THE PURPOSES OF YOUR TESTIMONY?
A. I have been asked by the Company to offer my expert opinion in five areas related
to information on the alternative plans identified in its 2018 Integrated Resource
Plan: (1) future national regulation of carbon dioxide (“CO2”) emissions from
power plants, including the possibility of a “price” that would be placed on the
Company’s CO2 emissions as well as the implications of CO2 policies on the prices
of fuels used by the Company; (2) external environmental costs for air emissions
under the cases, including damage-based values for conventional and toxic
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emissions as well as illustrative estimates based upon the social cost of carbon
(“SCC”) for CO2 emissions not subject to a binding CO2 cap-and-trade program
since the effects of emissions subject to a binding CO2 cap are presumed to be
“internalized” with the impacts of the price trajectory reflected in the Present Worth
of Revenue Requirements (“PWRR”); (3) evaluation of the external costs of other
potential non-air environmental impacts; (4) external costs of the Company’s water
consumption that are not included in the PWRR for the cases; and (5) the economic
benefits (i.e., economic impacts) to the Nevada economy under the cases. The
results of my analyses are discussed in detail in a report I prepared in collaboration
with NERA colleagues (“NERA Report”), which is provided in Technical
Appendix Item ECON-12.
8. Q. PLEASE PROVIDE AN OVERVIEW OF THE ALTERNATIVE CASES
AND THE MAJOR ELEMENTS THAT DIFFERENTIATE THEM?
A. Nevada’s 2018 Integrated Resource Plan considers the following four primary
cases for meeting electricity demand and state renewable energy requirements from
2019 to 2048.
• “Low Carbon” case;
• “All Market” case;
• “Renewable” case; and
• “Development” case.
The Company has selected the Low Carbon case as the “Preferred Plan” and we
calculate differences in results relative to this case.
The following are differences in resource additions and renewable PPAs among the
four cases. These differences lead to differences in operation of various Company
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plants, purchases from other particular plants, and market purchases. Information
on the common elements of the four cases is provided in the NERA Report.
RESOURCE CHANGES NOT COMMON ACROSS IRP CASES
Low Carbon Plan:
• Conditional retirement of North Valmy Unit 1 on 12/31/2021.
All Market, Renewable and Development Cases:
• No unique resource changes.
POWER PURCHASE AGREEMENTS NOT COMMON ACROSS IRP
CASES
Low Carbon and Renewable Cases:
• PPAs for 401 MW of solar photovoltaic (PV) with 100 MW/400 MWh of
battery energy storage in Northern Nevada by 2022.
o NextEra – Dodge Flat Solar (200 MW) with battery energy storage
(50 MW/200 MWh).
o NextEra – Fish Springs Ranch (100 MW) with battery energy
storage (25 MW/100 MWh).
o Cypress Creek – Battle Mountain Solar (101 MW) with battery
energy storage (25 MW/100 MWh).
• PPAs for 600 MW of solar PV in Southern Nevada by 2022.
o 8minutenergy – Eagle Shadow Mountain Solar Farm (300 MW)
o Sempra – Copper Mountain 5 (250 MW)
o 174 Power Global – Techren V (50 MW)
All Market Plan:
• PPAs for 301 MW of solar PV in Northern Nevada by 2022.
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o NextEra – Dodge Flat Solar (200 MW)
o Cypress Creek – Battle Mountain Solar (101 MW)
Development Plan:
• PPAs for 401 MW of solar PV with 100 MW/400 MWh of battery energy
storage in Northern Nevada by 2022.
o NextEra – Dodge Flat Solar (200 MW) with battery energy storage
(50 MW/200 MWh)
o NextEra – Fish Springs Ranch (100 MW) with battery energy
storage (25 MW/100 MWh)
o Cypress Creek – Battle Mountain Solar (101 MW) with battery
energy storage (25 MW/100 MWh)
• PPAs for 600 MW of solar PV in Southern Nevada by 2022; and
• 299 MW of NV Energy-developed solar PV facilities by 2021.
o Dry Lake Solar (150 MW)
o Crescent Valley Solar (149 MW)
TRANSMISSION EXPENDITURES NOT COMMON ACROSS IRP CASES.
The cases include various transmission network upgrades associated with
integrating new solar PV PPAs into the electric distribution system. Of the above
identified PPAs, the following would require additional expenditures by NV
Energy related to network upgrades:
• Sierra:
o NextEra – Dodge Flat Solar (200 MW) with battery energy storage
(50 MW/200 MWh)
o NextEra – Fish Springs Ranch (100 MW) with battery energy
storage (25 MW/100 MWh)
• Nevada Power:
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o 8minutenergy – Eagle Shadow Mountain Solar Farm (300 MW)
o Sempra – Copper Mountain 5 (250 MW)
9. Q. PLEASE PROVIDE AN OVERVIEW OF THE FIFTH RESOURCE PLAN
YOU WERE ASKED TO EVALUATE?
A. The Company has developed a fifth case (referred to as “Question 3 Alternative”)
based upon the assumption that Nevada ballot Question 3 is approved by voters in
November 2018. If Question 3 were to be approved, the Nevada electricity system
would undergo substantial restructuring towards a competitive electricity market
by 2023. Thus, this fifth case only includes information for the first five years of
the planning period, from 2019 to 2023.
It is important to understand and characterize our evaluation of the Question 3
Alternative—what it represents and what it does not represent. Based on my
discussions with NV Energy, the Question 3 Alternative represents a change in NV
Energy’s planning philosophy. The Question 3 Alternative represents a shift from
the type of long-term planning required by Nevada regulations and embodied in the
primary cases—in which NV Energy undertakes long-term commitments on behalf
of customers—to a short-term planning mindset. In this latter case, as explained in
more detail in the testimony of Shawn M. Elicegui, NV Energy makes only the
minimum long-term commitments necessary to meet Nevada’s Renewable
Portfolio Standard through 2023. Our economic and environmental analysis thus
assesses the impact that NV Energy’s change in planning philosophy would have
on Nevada’s economy and the environment in the near term (from 2019 to 2023).
Our analysis does not (and should not be construed to) represent the effects of the
costs and benefits of restructuring or deregulating Nevada’s energy markets.
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In particular, this fifth case can be characterized by the following purchase and
transmission changes.
Question 3 Alternative:
• PPA for 300 MW of solar PV in Southern Nevada.
o 8minutenergy – Eagle Shadow Mountain Solar (300 MW)
• Network transmission upgrades associated with integrating the above-
mentioned PPA into the electric distribution system.
I have developed information on the environmental effects and economic impacts
of this fifth case for the period from 2019 to 2023. However, because this fifth case
is not comparable in time period to the four primary cases—which involve
projections for the 30-year period from 2019 to 2048—I present this information
separately.
CARBON DIOXIDE PRICE SCENARIOS
10. Q. PLEASE SUMMARIZE THE CARBON DIOXIDE PRICE SCENARIOS
DEVELOPED AND ANALYZED IN YOUR REPORT.
A. I developed four CO2 price scenarios to reflect uncertainty regarding the potential
future national regulation of CO2 emissions from existing power plants and the
extent to which regulations might impose a “price” on CO2 emissions from power
plants. On March 28, 2017, President Donald Trump signed the Executive Order
on Energy Independence (E.O. 13783), calling for a review of the Clean Power
Plan. On October 16, 2017, EPA formally proposed to repeal the CPP after
completing its initial review (See EPA 40 CFR Part 52, p. 48036). As of the
development of my testimony, there has not yet been a final ruling on the future of
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Clean Power Plan or on any other federal carbon regulation for the electric power
sector.
At this point, however, it seems very clear that the Clean Power Plan will not go
into effect in 2022, as it otherwise would according to the current schedule outlined
in the Final Rule. Indeed, neither the CPP nor a similar policy is likely to be
implemented by the Trump Administration. Given these circumstances, the first
scenario assumes a No Carbon Price scenario.
To take into account the possibility of national regulation of greenhouse gas
emissions in the future, however, I also modeled the effects of a national cap-and-
trade program similar in structure to programs that have been considered by the
U.S. Congress. Such a program has various well-recognized advantages over the
regulatory approach, including greater incentives to minimize the overall U.S. cost
of achieving carbon emission reductions. Moreover, relative to a carbon tax, a cap-
and-trade program provides more straightforward mechanisms to deal with
transitional costs as well as distributional concerns.
To model uncertainty in the stringency of a potential national CO2 program, I
developed three national CO2 cap-and-trade scenarios based upon different
potential price trajectories. The CO2 prices resulting from the caps are assumed to
begin in 2025 at $5 per metric ton (“low”), $10 per metric ton (“mid”), and $20 per
metric ton (“high”), respectively. As discussed below and in more detail in the
NERA Report, the NewERA modeling relies upon the Companies’ projections for
wholesale natural gas prices at Henry Hub and Rocky Mountain coal prices (Utah
and Colorado), as well as other inputs from the Annual Energy Outlook (AEO
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2018) released by the U.S. Information Administration (the latest available when
the NewERA modeling was done).
11. Q. HOW DID YOU DEVELOP ESTIMATES OF THE EFFECTS OF THE
CARBON DIOXIDE SCENARIOS ON THE CARBON DIOXIDE PRICES
AND THE PRICES THAT THE COMPANY WOULD PAY FOR FUELS?
A. I used the NewERA model, a model developed and maintained by NERA that
includes a detailed electric sector model and related integrated fuel price and
macroeconomic models, as explained in the NERA Report. The electric sector
model (the primary model used for my analysis) is a detailed model of the electric
and coal sectors. Each of the more than 17,000 electric generating units in the
United States is represented in the model. The model minimizes costs while
meeting all specified constraints, such as demand, peak demand, emissions limits,
and transmission limits. The model is similar to the National Energy Modeling
System (“NEMS”), developed and maintained by the U.S. Energy Information
Administration (“EIA”) in the Department of Energy.
I used NewERA to develop estimates of carbon dioxide prices and the impacts of
these prices on fuel prices under both the No Carbon Price scenario and the three
CO2 price scenarios. As requested by the Company, I estimated changes in prices
for Henry Hub natural gas and Rocky Mountain coal (Utah and Colorado) and
transmitted them to the Company for use in their PROMOD runs for the four cases.
12. Q. PLEASE EXPLAIN HOW THE CARBON DIOXIDE SCENARIOS AFFECT
NEVADA POWER’S MODELING OF ITS ALTERNATIVE CASES AND
ITS FINANCIAL PLAN.
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A. The regulatory treatment of power plant CO2 emissions and the associated fuel
price changes have been incorporated into the Company’s PROMOD runs and
financial planning model for the No Carbon Price and the Mid CO2 Price scenarios.
The prices of CO2 emissions under the Mid CO2 Price scenario are included in the
costs to dispatch fossil-fuel generating units, and thus affect the generation of
various units under the different expansion cases. In turn, I use the Company’s
PROMOD projections along with other information to develop estimates of the
environmental costs of various air emissions under the resource plans, including
conventional and toxic pollutants as well as CO2 emissions.
I also developed estimates of the potential value of free allowances that the
Companies might receive under the potential cap-and-trade program modeled in
the Mid CO2 Price scenario. These estimates are provided in the NERA Report. The
value of these free allowances will reduce the net costs incurred by the Companies
to comply with regulatory requirements. The net financial impact in a given year
for the emissions from the Company’s generation depends on the level of
emissions, the price, and the number of emission allowances the Companies would
receive for free under the program. I understand that the potential allowance
allocation is incorporated into the Company’s financial planning model.
III. ENVIRONMENTAL COSTS FOR CONVENTIONAL AND TOXIC AIR
EMISSIONS
13. Q. PLEASE SUMMARIZE THE METHODS YOU USED TO ESTIMATE
ENVIRONMENTAL COSTS FOR CONVENTIONAL AND TOXIC AIR
EMISSIONS.
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A. I applied a “damage-function” framework to evaluate the environmental costs of
air emissions for which sufficient data were available to estimate the potential
damages related to health effects. The specific emissions in this category include
nitrogen oxides (“NOx”), volatile organic compounds (“VOC”), particulate matter
(“PM”), mercury, and sulfur dioxide (“SO2”). As discussed in the NERA Report,
the national SO2 cap set in the Acid Rain Trading Program is not binding—with
allowance prices expected to be zero or close to zero—and thus SO2 emissions are
evaluated based on damage values rather than as covered by a binding cap-and-
trade program as was appropriate in some earlier IRP analyses. The damage-
function approach is a standard economic approach for assessing environmental
costs when emissions are not capped. The damage values that I used for these
emissions are primarily based on health effects associated with ambient PM (which
depend on NOx emissions that operate as precursors for PM as well as emitted PM)
and ground-level ozone (which is formed by NOx and VOC emissions), as
described in the NERA Report. To develop this information, I relied on data and
methodologies developed and used by the U.S. EPA as well as other information. I
also estimated damage values for mercury from information developed by U.S.
EPA in its assessments of the Mercury and Air Toxics Standards (“MATS”). As
noted in the NERA Report, I did not assess the validity of the EPA information I
used in these calculations.
14. Q. PLEASE SUMMARIZE OTHER SOURCES OF INFORMATION YOU
USED TO DEVELOP THE ENVIRONMENTAL COST ASSESSMENTS.
A. I also relied on information provided by the Companies regarding the various
resource plans. This information included emission rates for relevant facilities,
forecasted annual generation and heat input for relevant facilities (based on the
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PROMOD dispatch modeling results), and other information as described in the
NERA Report. The information provided by the Companies relates to both Nevada
Power and Sierra, because the two systems were modeled jointly, and thus the joint
resource plan involves emissions related to both the Nevada Power and Sierra
systems. I supplemented the information from the Companies with relevant
information from public sources; for example, as noted above, in estimating health
and other effects and dollar values for various emissions, I relied on data and
methodologies developed by U.S. EPA.
15. Q. PLEASE SUMMARIZE YOUR ESTIMATES OF THE ENVIRONMENTAL
COSTS OF AIR EMISSIONS.
A. Table 1 presents the estimated environmental costs for the four primary resource
cases related to air emissions (not carbon dioxide emissions) under the two carbon
scenarios. Table 2 summarizes the differences in estimates of the present values of
environmental costs of conventional and toxic air emissions relative to the
environmental costs of the Low Carbon case. Environmental costs were modeled
for the No Carbon Price and Mid CO2 Price scenarios. The table includes costs for
emissions subject to the National Ambient Air Quality Standards (“NAAQS”) and
the recent MATS rule proposed by U.S. EPA. Based on the NAAQS, I have
included NOx, VOC, PM, carbon monoxide CO, and SO2. Damage values for VOC
emissions are zero because air quality modeling results indicate that, given ambient
climatic conditions, changes in VOC emissions do not affect ozone concentrations
in Nevada (which are driven at the margin by NOx emissions). CO is not monetized
because the requisite site-specific data were unavailable; however, CO emissions
projections are provided in the NERA Report. Based on their inclusion in the
MATS rule, emissions of mercury and HCl are also included. HCl is not monetized
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because U.S. EPA did not develop the relevant information in the MATS regulatory
impact analysis; however, HCl emission projections are provided in the NERA
Report. Note that the MATS rule uses PM emissions as a proxy for non-mercury
metallic air toxics; however, since PM emissions are included based upon the
NAAQS, this element of the MATS rule does not lead to estimates of additional
environmental costs.
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Table 1. Present Values of Environmental Costs for Conventional Air Emissions and Toxics for Primary Cases (2019$ Millions)
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NOx No Carbon Price Mid CO2 Price
Low Carbon
$6.24 $6.28
All Market
$6.42 $6.45
Development
$6.21 $6.26
Renewable
$6.24 $6.28
PM No Carbon Price Mid CO2 Price
$154.60 $154.39
$163.07 $162.66
$151.64 $151.17
$154.60 $154.40
VOC No Carbon Price Mid CO2 Price
$0.00 $0.00
$0.00 $0.00
$0.00 $0.00
$0.00 $0.00
CO No Carbon Price Mid CO2 Price
--
--
--
--
SO2 No Carbon Price Mid CO2 Price
$9.84 $10.30
$10.00 $10.52
$9.95 $10.42
$9.87 $10.33
Mercury No Carbon Price Mid CO2 Price
$0.00 $0.00
$0.00 $0.00
$0.00 $0.00
$0.00 $0.00
HCl No Carbon Price Mid CO2 Price
--
--
--
--
Total No Carbon Price Mid CO2 Price
$170.68 $170.98
$179.49 $179.63
$167.81 $167.85
$170.71 $171.01
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2048 using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. Real annual values were converted to nominal annual values using inflation rate information, as provided by NV Energy.
Total may differ from the sum of the rows due to independent rounding.
“-” denotes that the environmental costs of the air emission are not monetized.
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Table 2. Present Values of the Differences in Environmental Costs of Conventional Air Emissions and Toxics for Primary Cases for 2019-2048, Relative to the Low
Carbon Case (2019$ Millions)
Low Carbon All Market Development Renewable No Carbon Price - $8.81 -$2.87 $0.03 Mid CO2 Price - $8.65 -$3.13 $0.03
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2048 using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. Real annual values were converted to nominal annual values using inflation rate information, as provided by NV Energy.
In addition to the potential health costs associated with conventional air emissions and
toxics, there are also potential non-health costs. As discussed in the report, we
expect non-health damages to be small relative to the health damages and thus we
would not expect their omission to have a major effect on the results, particularly
the comparative results for the different cases.
16. Q. PLEASE COMMENT ON DIFFERENCES IN ENVIRONMENTAL COSTS
RELATED TO CONVENTIONAL AND TOXIC AIR EMISSIONS UNDER
THE VARIOUS PRIMARY CASES.
A. These results indicate that the Low Carbon and Renewable cases have virtually the
same conventional and toxic air emissions costs. In contrast, the Development case
has noticeably smaller costs and the All Market case has noticeably larger costs
than these other two cases.
17. Q. PLEASE PROVIDE INFORMATION ON THE AIR EMISSION AND
TOXICS ENVIRONMENTAL COSTS UNDER THE FIFTH SCENARIO.
A. Table 3 provides information on the environmental costs for conventional air
emissions and toxics for the Q3 Alternative case. As noted above, since this case is
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only relevant for five years, the results are not comparable to those for the main
four scenarios.
Table 3. Present Values of Environmental Costs for Conventional Air Emissions and Toxics for Q3 Alternative (2019$ Millions)
Q3
NOx $2.09
PM $42.19
VOC $0.00
CO -
SO2 $2.59
Mercury $0.00
HCl -
Total $46.86
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2023 using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. Real annual values were converted to nominal annual values using inflation rate information, as provided by NV Energy. All values for the Q3 Alternative are based on the Mid CO2 Price scenario only. Since the Mid CO2 Price scenario assumes a binding cap in 2025, and the analysis period for the Q3 Alternative ends in 2023, using the No Carbon Price scenario as an alternative would have no effect on the results.
Total may differ from the sum of the rows due to independent rounding.
“-” denotes that the environmental costs of the air emission are not monetized.
ILLUSTRATIVE ENVIRONMENTAL COSTS OF CARBON DIOXIDE EMISSIONS
18. Q. PLEASE EXPLAIN THE METHODOLOGY FOR YOUR ILLUSTRATIVE
ESTIMATES OF THE COSTS OF CARBON DIOXIDE EMISSIONS.
A. For emissions of carbon dioxide (as well as for other pollutants), the conceptually
correct measure of the environment costs of emissions is the dollar value of the
effects caused by emissions related to the various cases, with emissions covered by
a binding cap-and-trade program excluded from this calculation. Thus, for the Mid
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CO2 Price scenario, CO2 emissions covered under the binding national cap-and-
trade program (years from 2025 to 2048) would not be included in damage-based
calculations. For the No Carbon Price scenario, by definition there would be no
binding cap, and thus emissions for the complete duration of the analysis period
(years 2019-2048) would be included.
Developing estimates of environmental damages for CO2 emissions is
extraordinarily difficult because of the enormous uncertainties regarding the
potential physical effects of CO2 (and other greenhouse gas emissions) and how
they should be valued, as well as the extent to which U.S. residents would be
affected and whether values based on global or U.S. effects are appropriate. Given
these enormous uncertainties, I refer to the estimates as “illustrative” estimates of
the potential environmental costs related to CO2 emissions. As noted, only
emissions not subject to a binding cap-and-trade program are included in these
calculations.
To develop illustrative estimates of the dollar value of the Companies’ carbon
dioxide emissions, the Company has instructed me to comply with the proposed
regulation, R060-18, of the Public Utility Commission of Nevada, issued on April
27, 2018. In addition to the existing requirement to quantify environmental costs
for air emissions, water and land use, Section 2 of this proposed regulation requires
environmental costs also to be quantified for the social cost of carbon. In particular,
Section 3 of the proposed regulation “requires that the social cost of carbon,
excluding the cost from emissions of carbon internalized as private costs to the
utility, be included in the calculation of such environmental costs.” Moreover,
“Section 3 also requires an electric utility to determine the social cost of carbon
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using the values set forth in the ‘Technical Support Document: Technical Update
of the Social Cost of Carbon for Regulatory Impact Analysis,’ released by the
Interagency Working Group on Social Cost of Greenhouse Gases in August 2016.”
(Hereafter, “IWG August 2016 Report”). Thus, I rely on the IWG August 2016
Report to calculate values for the social cost of carbon.
The IWG August 2016 Report provides estimates of the global marginal damages
of an emission of one metric ton of carbon dioxide for future years, estimates that
were intended for use by federal regulatory agencies in evaluations of federal
regulatory proposals that involve impacts on greenhouse gas emissions. The IWG
August 2016 Report provides a range of potential SCC trajectories and recommends
the use of four different sets of SCC estimates (which it provides for years from
2010 to 2050 in 2007 dollars per metric ton of CO2): the average SCC estimate at
discount rates of 2.5 percent, 3 percent, and 5 percent, and the 95th percentile in
the distribution of SCC estimates at a 3 percent discount rate (which it notes is
designed “to represent the higher-than-expected impacts from temperature change
further out in the tails of the SCC distribution”). The IWG August 2016 Report
identifies the “central value” as the average of the estimates based upon the 3
percent discount rate and the calculations that use three Integrated Assessment
Models (DICE, PAGE and FUND) and five modeling scenarios, calculations that
underlie the IWG values for the social cost of carbon.
The values provided in the IWG August 2016 Report cover a very large range and,
indeed, the full range of values reported by the IWG is much greater than the four
sets of SCC estimates. Appendix A of the IWG August 2016 Report provides
information on the range for the 2020 value. The “central value” for 2020 is $42,
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with the four recommended values ranging from $12 to $123; but the full set of
2020 values for all three models and five scenarios over uncertainty calculations
from the 1st percentile to the 99th percentile range from -$11 to $949 (2007$). Given
the very large uncertainties involved in IWG calculations, the wide range of
potential values, and the model limitations and research gaps and related
uncertainties affecting the calculation of the social cost of carbon that are
mentioned in the IWG August 2016 Report, there is no one set of estimates
(including the “central value” set of estimates) that can be considered a reliable
estimate of the potential global damages related to greenhouse gas emissions in
each year. As noted, I refer to the estimates of the environmental costs of CO2
emissions as “illustrative” to indicate their highly uncertain nature. Moreover, the
IWG in its original 2010 report provided information that allows the calculation of
values based on damages within the United States, rather than the global values
included in the tables. To provide a more complete range of possible values, I use
that information to develop U.S. values to supplement the global values.
19. Q. PLEASE SUMMARIZE YOUR ILLUSTRATIVE ESTIMATES OF THE
COSTS OF CARBON DIOXIDE EMISSIONS FOR THE FOUR PRIMARY
CASES.
A. Table 4 shows the range of illustrative SCC costs (as present values over the 30-
year period) based on the No Carbon Price and Mid CO2 Price scenarios using the
four sets of SCC estimates recommended by the IWG August 2016 Report,
including U.S. as well as global values. Table 5 shows the differences relative to
the Low Carbon case of the illustrative estimates of the SCC under the No Carbon
Price and Mid CO2 Price scenarios. As explained above, the illustrative SCC for
the No Carbon Price scenario are based on values for all years in the analysis period
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(2019-2048), while the SCC costs for the Mid CO2 Price scenario are based on
values only for the years 2019-2024, before the assumed implementation of a
national program in 2025. The lowest values in this table reflect the average SCC
estimate and a 5 percent discount rate, while the largest values in this table reflect
the 95th percentile in the distribution of SCC estimates at a 3 percent discount rate.
The figure shows ranges of SCC costs both for the United States and for the world
as a whole. Note that these illustrative present value estimates are not comparable
to the environmental costs calculated for the other emissions for several reasons:
(a) the illustrative SCC values are even more uncertain than those for other
environmental costs in part because they are based upon impacts in the distant
future; (b) the illustrative SCC values are based on the IWG discount rates that are
used to calculate the present value of other environmental costs; and (c) the
illustrative SCC values are based upon either global or U.S. damages, rather than
the Nevada-specific damages used for the environmental costs of air emissions.
Table 4. Present Values of Illustrative Estimates of Environmental Costs for Carbon Dioxide Emissions for Primary Cases, 2019-2048 (2019$ Millions)
United States No Carbon Price Mid CO2 Price
Low Carbon
$423 to $5,067 $122 to $1,300
All Market
$444 to $5,316 $128 to $1,366
Development
$417 to $4,991 $120 to $1,279
Renewable
$423 to $5,067 $122 to $1,299
Global No Carbon Price Mid CO2 Price
$2,821 $813
to to
$33,782 $8,664
$2,961 $854
to to
$35,440 $9,106
$2,778 $801
to to
$33,272 $8,527
$2,821 $813
to to
$33,782 $8,662
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2048 based on values reported by Interagency Group (2016). Minimum values reflect a 5 percent discount rate and the average of the damages distribution, while maximum values reflect a 3 percent discount rate and the 95th percentile of the damages distribution.
U.S. costs are calculated as 15 percent of global costs (the midpoint of the suggested range in Interagency Working Group 2010).
Source: NERA calculations as explained in text
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Table 5. Differences in Present Values of Illustrative Estimates of Environmental Costs for Carbon Dioxide Emissions for Primary Cases for 2019-2048, Relative to Low
Carbon Case (2019$ Millions)
Low Carbon All Market Development Renewable United States
No Carbon - $21 to $249 -$77 to -$6 $0 to $0 Mid CO2 Price - $6 to $66 -$20 to -$2 $0 to $0
Global No Carbon - $140 to $1,657 -$511 to -$43 -$1 to $0 Mid CO2 Price - $40 to $442 -$137 to -$12 -$2 to $0
Note: All values are present values as of January 1, 2019 in millions of dollars for the period 2019-2048 based on values reported by Interagency Group (2016). Minimum values reflect a 5 percent discount rate and the average of the damages distribution, while maximum values reflect a 3 percent discount rate and the 95th percentile of the damages distribution.
U.S. costs are calculated as 15 percent of global costs (the midpoint of the suggested range in Interagency Group 2010).
Source: NERA calculations as explained in text
20. Q. PLEASE COMMENT ON THE DIFFERENCES IN ILLUSTRATIVE
ENVIRONMENTAL COSTS RELATED TO CARBON DIOXIDE
EMISSIONS IN THESE CASES.
A. Under both carbon price scenarios, the Low Carbon case and the Renewable case
have very similar SCC costs. In contrast, the Development case has noticeably
lower SCC costs and the All Market case has noticeably higher costs than these
other two cases.
21. Q. PLEASE PROVIDE ILLUSTRATIVE ENVIRONMENTAL COSTS
RELATED TO CARBON DIOXIDE EMISSIONS FOR THE FIFTH PLAN
BASED UPON APPROVAL OF BALLOT QUESTION 3.
A. Table 6 provides estimates for this plan. As noted, these estimates are not
comparable to those for the four primary cases.
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Table 6. Present Values of Illustrative Estimates of Environmental Costs for Carbon Dioxide Emissions for Q3 Alternative, 2019-2023 (2019$ Millions)
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Q3 United States
SCC $110 to $1,161
Global SCC $734 to $7,743
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2023 based on values reported by Interagency Group (2016). Minimum values reflect a 5 percent discount rate and the average of the damages distribution, while maximum values reflect a 3 percent discount rate and the 95th percentile of the damages distribution.
All values for the Q3 Alternative are based on the Mid CO2 Price scenario only. Since the Mid CO2 Price scenario assumes a binding cap in 2025, and the analysis period for the Q3 Alternative ends in 2023, using the No Carbon Price scenario as an alternative would have no effect on the results.
U.S. costs are calculated as 15 percent of global costs (the midpoint of the suggested range in Interagency Working Group 2010).
Source: NERA calculations as explained in text
IV. ASSESSMENT OF OTHER ENVIRONMENTAL COSTS
22. Q. DID YOU CONSIDER THE COSTS OF ENVIRONMENTAL IMPACTS
OTHER THAN AIR EMISSIONS?
A. Yes, I also considered potential environmental impacts related to water quality,
solid waste disposal, and land use in Nevada. I concluded that environmental costs
related to these categories are not likely to be significant relative to the estimated
environmental costs of air emissions. Thus, I have not included values for these
other environmental costs in my analysis.
V. ASSESSMENT OF ADDITIONAL WATER CONSUMPTION COSTS NOT
INCLUDED IN THE PWRR
23. Q. PLEASE SUMMARIZE YOUR METHODOLOGY FOR ESTIMATING
THE ADDITIONAL COSTS OF WATER CONSUMPTION.
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A. I estimated the potential additional costs of water consumption based upon the
value of water use that is not included in the PWRR using plant-specific
information on water consumption and water ownership from the Company. I
developed proxies for existing and future NV Energy plants based on historic
information on agricultural, municipal, and groundwater values in Nevada. The
additional costs of water are based upon water use from wells owned by the
Companies and do not include water that is leased or purchased, since the value of
leased or purchased water is presumed to be included in the PWRR. In addition, no
additional water costs are calculated for power purchased by the Companies
through contracts or spot market transactions because I assume that all water costs
are included in the prices that the Companies pay and thus are included in the
PWRR. Similarly, no additional water costs are calculated for any power purchase
agreements because I assume that the costs of any water that is used by third-party
electricity generators—whether these are actual costs to the generators or
opportunity costs of using their own water supply—will be included in the price
paid by the Companies and thus in the PWRR. The methodology and data I used
are described in detail in the NERA Report.
24. Q. PLEASE SUMMARIZE YOUR ESTIMATES OF THE ADDITIONAL
COSTS OF WATER CONSUMPTION FOR THE FOUR PRIMARY CASES.
A. Table 7 shows the estimated additional costs of water consumption (i.e., the added
costs beyond those already included in the PWRR) for the four primary cases for
the No Carbon Price and Mid CO2 Price scenarios.
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Table 7. Present Value of Additional Water Cost for Primary Cases, 2019-2048 (2019$ Millions)
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Low Carbon All Market Development Renewable No Carbon Price $10.8 $11.8 $10.4 $10.7 Mid CO2 Price $10.5 $11.5 $10.1 $10.4
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2048 using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. Real annual values were converted to nominal annual values using inflation rate information, as provided by NV Energy.
25. Q. PLEASE COMMENT ON DIFFERENCES IN ADDITIONAL WATER
COSTS AMONG THE CASES.
A. Table 8 shows the differences in estimates of additional costs of water consumption
for the No Carbon Plan and Mid CO2 Price scenarios relative to the Low Carbon
plan. The differences are small, particularly for the Development and Renewable
cases. The All Market case has noticeably larger water costs than the other three
cases.
Table 8. Present Value of Differences in Additional Water Costs Relative to Low Carbon Case for Primary Cases, 2019-2048 (2019$ Millions) Low Carbon All Market Development Renewable
No Carbon Price - $1.1 -$0.4 -$0.1 Mid CO2 Price - $1.0 -$0.4 -$0.1
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2048 using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. Real annual values were converted to nominal annual values using inflation rate information, as provided by NV Energy.
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26. Q. PLEASE SUMMARIZE YOUR ESTIMATES OF THE ADDITIONAL COSTS
OF WATER CONSUMPTION FOR THE FIFTH RESOURCE PLAN.
A. Table 9 provides estimates for this plan. As noted, these estimates are not
comparable to those for the four primary cases.
Table 9. Present Value of Additional Water Cost for Q3 Alternative, 2019-2023 (2019$ Millions)
Q3 Additional Water Cost $5.8
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2023 using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. Real annual values were converted to nominal annual values using inflation rate information, as provided by NV Energy. All values for the Q3 Alternative are based on the Mid CO2 Price scenario only. Since the Mid CO2 Price scenario assumes a binding cap in 2025, and the analysis period for the Q3 Alternative ends in 2023, using the No Carbon Price scenario as an alternative would have no effect on the results.
VI. ASSESSMENT OF OVERALL ENVIRONMENTAL COSTS
27. Q. PLEASE SUMMARIZE YOUR ASSESSMENT OF THE OVERALL
ENVIRONMENTAL COSTS OF THE ALTERNATIVE CASES.
A. Table 10 summarizes my estimates of environmental costs for the four primary
cases for the No Carbon Price scenario. I have calculated overall values in two
ways. One way combines estimates for air and toxic emissions and water costs but
includes the range of SCC values separately. The ranges for SCC costs are from the
smallest values I calculated (i.e., the domestic US values based on a 5% discount
rate) to the largest values I calculated (global values based on 3% discount rate and
using the 95th percentile values). The other way includes the SCC range of values
with the other two values. Table 11 shows the differences in overall environmental
costs relative to the Low Carbon case based upon these two ways of showing the
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overall results. Table 12 and Table 13 present the analogous information for the
cases under the Mid CO2 Price scenario.
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Table 10. Present Values of Overall Environmental Costs for Primary Cases, 2019-2048, Based upon No Carbon Price Scenario (2019$ Millions)
Low Carbon All Market Development Renewable Conventional Air Emission Costs $170.7 $179.5 $167.8 $170.7 Additional Water Costs $10.8 $11.8 $10.4 $10.7 Cumulative Environmental Cost w/o SCC $181.4 $191.3 $178.2 $181.4 Illustrative Social Costs of Carbon $423.1 to $33,782.4 $444.1 to $35,439.5 $416.7 to $33,271.7 $423.1 to $33,781.6 Cumulative Environmental Cost w/ SCC $604.6 to $33,963.8 $635.4 to $35,630.8 $594.8 to $33,449.9 $604.5 to $33,963.0
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2048. For conventional air emissions and water cost present values are calculated using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. The illustrative SCC ranges include minimum values that reflect a 5 percent discount rate and the average of the damages distribution using United States damages only, and maximum values that reflect a 3 percent discount rate and the 95th percentile of the damages distribution using Global damages.
Table 11. Present Values of Differences in Overall Environmental Costs for Primary Cases, 2019-2048, Based upon No Carbon Price Scenario (2019$ Millions)
Low Carbon All Market Development Renewable Conventional Air Emission Costs - $8.8 -$2.9 $0.0 Additional Water Costs - $1.1 -$0.4 -$0.1 Cumulative Environmental Cost w/o SCC - $9.9 -$3.3 $0.0 Illustrative Social Costs of Carbon - $21.0 to $1,657.1 -$6.48 to -$510.67 -$0.01 to -$0.82 Cumulative Environmental Cost w/ SCC - $30.8 to $1,667.0 -$9.74 to -$513.93 -$0.04 to -$0.84
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2048. For conventional air emissions and water cost present values are calculated using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. The illustrative SCC ranges include minimum values that reflect a 5 percent discount rate and the average of the damages distribution using United States damages only, and maximum values that reflect a 3 percent discount rate and the 95th percentile of the damages distribution using Global damages.
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Table 12. Present Values of Overall Environmental Costs for Primary Cases, 2019-2048, Based upon Mid CO2 Price Scenario (2019$ Millions)
Low Carbon All Market Development Renewable Conventional Air Emission Costs $171.0 $179.6 $167.8 $171.0 Additional Water Costs $10.5 $11.5 $10.1 $10.4 Cumulative Environmental Cost w/o SCC $181.5 $191.1 $178.0 $181.5 Illustrative Social Costs of Carbon $122.0 to $8,663.7 $128.0 to $9,105.6 $120.1 to $8,527.1 $122.0 to $8,662.2 Cumulative Environmental Cost w/ SCC $303.5 to $8,845.2 $319.1 to $9,296.7 $298.1 to $8,705.1 $303.4 to $8,843.7
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2048. For conventional air emissions and water cost present values are calculated using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. The illustrative SCC ranges include minimum values that reflect a 5 percent discount rate and the average of the damages distribution using United States damages only, and maximum values that reflect a 3 percent discount rate and the 95th percentile of the damages distribution using Global damages.
Table 13. Present Values of Differences in Overall Environmental Costs Relative to Low Carbon Case for Primary Cases, 2019-2048, Based upon Mid CO2 Price Scenario
(2019$ Millions) Low Carbon All Market Development Renewable
Conventional Air Emission Costs - $8.6 -$3.1 $0.0 Additional Water Costs - $1.0 -$0.4 -$0.1 Cumulative Environmental Cost w/o SCC - $9.6 -$3.5 $0.0 Illustrative Social Costs of Carbon - $6.0 to $441.9 -$1.87 to -$136.62 -$0.02 to -$1.52 Cumulative Environmental Cost w/ SCC - $15.7 to $451.5 -$5.37 to -$140.12 -$0.05 to -$1.55
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2048. For conventional air emissions and water cost present values are calculated using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. The illustrative SCC ranges include minimum values that reflect a 5 percent discount rate and the average of the damages distribution using United States damages only, and maximum values that reflect a 3 percent discount rate and the 95th percentile of the damages distribution using Global damages.
28. Q. PLEASE COMMENT ON THE DIFFERENCES IN OVERALL
ENVIRONMENTAL COSTS AMONG THE VARIOUS CASES BASED ON
THESE TWO METHODS OF SUMMARIZING RESULTS.
A. These results indicate that the overall environmental costs are very similar for the
Low Carbon and the Renewable cases. In contrast, the overall environmental costs
are noticeably smaller for the Development case and noticeably larger for the All
Market case. These conclusions apply to both ways of summarizing overall
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environmental costs (i.e., treating SCC costs separately as well as summing SCC
costs and air emissions costs and additional water costs).
29. Q. PLEASE PROVIDE EQUIVALENT INFORMATION FOR THE FIFTH
PLAN, THE ONE BASED ON QUESTION 3 APPROVAL.
A. Table 14 provides information on environmental costs for this fifth plan. As noted,
the results for this case are not comparable to the other four cases. Table 14. Present Value of Cumulative Environmental Costs for Q3 Alternative, 2019-
2023 (2019$ Millions)
Q3 Conventional Air Emission Costs $5,679.8 Additional Water Costs $5.8 Cumulative Environmental Cost w/o SCC $5,685.6 Illustrative Social Costs of Carbon $110.2 to $7,743.3 Cumulative Environmental Cost w/ SCC $5,795.8 to $13,428.9
Notes: All values are present values as of January 1, 2019 in millions of 2019 dollars for the period 2019-2048. For conventional air emissions and water cost present values are calculated using nominal annual discount rates of 7.95 percent for Nevada Power and 6.65 percent for Sierra. The illustrative SCC ranges include minimum values that reflect a 5 percent discount rate and the average of the damages distribution using United States damages only, and maximum values that reflect a 3 percent discount rate and the 95th percentile of the damages distribution using Global damages. All values for the Q3 Alternative are based on the Mid CO2 Price scenario only. Since the Mid CO2 Price scenario assumes a binding cap in 2025, and the analysis period for the Q3 Alternative ends in 2023, using the No Carbon Price scenario as an alternative would have no effect on the results.
VII. ECONOMIC IMPACTS
30. Q. PLEASE SUMMARIZE THE CURRENT REGULATIONS RELATED TO
EVALUATING THE ECONOMIC IMPACTS OF INTEGRATED
RESOURCE PLANS IN NEVADA.
A. Section 704.9357 of the NAC requires the Company to assess the “net economic
benefits” of resource plans reflecting “both the positive and negative changes.”
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Section 704.9357 specifies that benefits to be calculated include in-state
expenditures related to capital, supplies, wages, fees, and taxes associated with the
resource plans. These expenditures would all produce positive economic impacts.
The regulation does not include any specific language on how to assess the negative
economic impacts of higher electricity prices.
31. Q. WHAT MODEL DID YOU USE TO ESTIMATE ECONOMIC IMPACTS
FOR THIS ANALYSIS?
A. This analysis uses the model developed by Regional Economic Models, Inc.
(“REMI”) to provide comprehensive estimates of economic impacts for the
alternative resource plans, including the positive effects of expenditures in Nevada
as well as the potential negative effects of greater electricity rates under more
expensive plans. The Companies provided NERA with additional information on
electricity revenue forecasts, which enabled the development of both the positive
economic impacts of expenditures associated with the resource plans and the
negative economic impacts of the electricity rate increases associated with these
expenditures.
32. Q. PLEASE SUMMARIZE THE SOURCES OF INFORMATION YOU USED
TO ASSESS THE ECONOMIC IMPACTS OF THE RESOURCE PLANS.
A. I relied on several sources of information as discussed in the NERA Report,
including information provided by the Companies as well as data from the EIA. As
described in the NERA Report, the Companies provided information including data
on overall construction costs, the timing of construction costs, fuel costs and other
operating costs for the relevant facilities, as well as additional information on
electricity forecasts, which enabled the development of both positive and negative
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economic impacts. I used cost data from EIA for renewable projects to assess the
economic benefits in Nevada of the Companies’ renewable power purchase
agreements. The Companies provided data related to projected electricity revenues
from 2019 to 2048, which represent the start and end points for the economic
impacts analysis.
I used this information to develop inputs for REMI. The REMI inputs include
estimates of the direct expenditures due to the various cases, including construction
and annual operating and maintenance expenditures, as well as the electricity
revenue requirements for various customer classes under the cases.
33. Q. PLEASE SUMMARIZE THE BASELINE OR REFERENCE SCENARIO
YOU USED AND THE MEASURES YOU USED TO DETERMINE
ECONOMIC IMPACTS.
A. I calculated “economic impacts” based on the data and methodologies discussed
above. REMI simulations require a “baseline” or reference forecast, including
assumptions on which NV Energy resource plan and which carbon price scenario
is consistent with that reference forecast. I assume that the All Market case and the
No Carbon Price scenario are consistent with the REMI reference forecast, since
these seem to involve the least changes to NV Energy’s generation fleet (and thus
seem to most closely approximate what resources might be implicit in REMI’s
reference scenario). These assumptions mean the inputs to the REMI model are not
the absolute values but rather the differences between expenditures and revenues
for each of the cases relative to the All Market case.
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I first develop the REMI model results, which provide estimates of how the Nevada
economy would grow under the primary cases, under both the No Carbon Price
scenario and under the Mid-CO2 Price scenario. As discussed below, the growth of
the Nevada economy is broadly similar for all of the resource plans. When I develop
tables that compare the differences in REMI model results among the primary cases,
I express the differences relative to the Companies’ preferred plan (the Low Carbon
case). Note that using the Low Carbon case to compare REMI model results is not
inconsistent with using the All Market case as the reference scenario for purpose
developing the REMI model inputs. Finally, I also present results for the fifth case,
the Question 3 case, which as emphasized, is not at all comparable to the four primary
cases.
I characterize the “economic impacts” following four primary impact categories:
(1) Gross state product, (2) Personal income, (3) State and local tax revenue, and
(4) Employment. As discussed in the NERA Report, state and local tax revenue is
calculated by NERA based on outputs from the REMI model, and the other three
impact categories come directly from the REMI model for each year of the analysis
period.
34. Q. PLEASE SUMMARIZE THE INPUTS TO YOUR ECONOMIC IMPACTS
ANALYSIS.
A. Table 15 and Table 16 show the average annual relevant expenditures for the
economic impacts analysis for both the No Carbon Price and Mid CO2 Price
scenarios over the period from 2019 to 2048 compared to the All Market case
(which as noted is the case presumed to be consistent with REMI’s reference case).
Only expenditures that occur in Nevada are included in these calculations because
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of the focus on estimating the economic impacts of alternative plans in Nevada. As
discussed in the NERA report, these values exclude certain categories of
expenditures, such as spot market purchases, because those expenditures are
assumed to flow to power producers outside Nevada (and thus not generate positive
economic impacts in Nevada). Note that these average annual values over the 30-
year period do not reflect differences in timing of expenditures over the 30-year
period.
Table 15. Average Annual Expenditures Compared to All Market Case for Primary Cases (2019$ Millions), 2019-2048, No Carbon Price Scenario
All Market Low Carbon Development Renewable Construction - $54 $73 $53 Fuel - -$28 -$40 -$28 O&M - $48 $54 $48 Total - $74 $87 $73
Notes: All values are average annual values over the period from 2019 to 2048 in millions of 2019 dollars. Real annual values were converted to nominal annual values using inflation rate information, as provided by NV Energy.
Table 16. Average Annual Expenditures Compared to All Market Case for Primary Cases (2019$ Millions), 2019-2048, Mid CO2 Price Scenario
All Market Low Carbon Development Renewable Construction - $54 $73 $53 Fuel - -$29 -$42 -$29 O&M - $48 $54 $48 Total - $73 $85 $73
Notes: All values are average annual values over the period from 2019 to 2048 in millions of 2019 dollars. Real annual values were converted to nominal annual values using inflation rate information, as provided by NV Energy.
Table 17 and Table 18 show the average annual Companies’ projected electricity
revenue from 2019 to 2048 apportioned by customer class, compared to the revenue
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of the Low Carbon case for both the No Carbon Price and the Mid CO2 Price
scenarios.
Table 17. Average Annual Electricity Revenue by Customer Class Compared to All Market Case for Primary Cases (2019$ Millions), 2019-2048, No Carbon Price
Scenario
All Market Low Carbon Renewables Development Total - -$9 -$10 -$6
Residential - -$4 -$5 -$3 Commercial - -$2 -$2 -$1 Industrial - -$3 -$3 -$2
Notes: All values are average annual over the period from 2019 to 2048 in millions of 2019 dollars.
Table 18. Average Annual Electricity Revenue by Customer Class Compared to All Market Case for Primary Cases (2019$ Millions), 2019-2048, Mid CO2 Price
Scenario
All Market Low Carbon Renewables Development Total - -$13 -$14 -$1
Residential - -$6 -$7 -$7 Commercial - -$3 -$3 -$3 Industrial - -$4 -$4 -$4
Notes: All values are average annual over the period from 2019 to 2048 in millions of 2019 dollars.
35. Q. PLEASE PROVIDE EQUIVALENT INFORMATION FOR THE FIFTH
PLAN, THE ONE BASED ON QUESTION 3 APPROVAL.
Table 19 shows the average annual relevant expenditures for the economic impacts
analysis for the Q3 Alternative over the period from 2019 to 2023.
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Table 19. Average Annual Relevant Expenditures for Q3 Alternative (2019$ Millions), 2019-2023
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Q3 Construction $290 Fuel $633 O&M $221 Total $1,144
Notes: All values are average annual values over the period from 2019 to 2023 in millions of 2019 dollars. Real annual values were converted to nominal annual values using inflation rate information, as provided by NV Energy. All values for the Q3 Alternative are based on the Mid CO2 Price scenario only. Since the Mid CO2 Price scenario assumes a binding cap in 2025, and the analysis period for the Q3 Alternative ends in 2023, using the No Carbon Price scenario as an alternative would have no effect on the results.
Table 20 shows the average annual Companies’ projected electricity revenue from
2019 to 2023 apportioned by customer class for the Q3 Alternative case.
Table 20. Average Annual Electricity Revenue by Customer Class for Q3 Alternative (2019$ Millions), 2019-2023
Q3
Notes:
Total $1,263 Residential $530 Commercial $327 Industrial $406
All values are average annual over the period from 2019 to 2023 in millions of 2019 dollars. All values for the Q3 Alternative are based on the Mid CO2 Price scenario only. Since the Mid CO2 Price scenario assumes a binding cap in 2025, and the analysis period for the Q3 Alternative ends in 2023, using the No Carbon Price scenario as an alternative would have no effect on the results.
36. Q. PLEASE SUMMARIZE THE RESULTS OF YOUR ECONOMIC IMPACTS
ANALYSIS.
A. Table 21 displays the growth in the Nevada economy from 2018 to six future years
(2019, 2021, 2023, 2028, 2038, and 2048) under the four primary cases for the No
Carbon Price scenario. The REMI modeling results show substantial growth across
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the economic impacts metrics for each of the cases. These results indicate that
growth in the Nevada economy would be similar under the four primary cases,
although there are differences in the economic impacts among the cases in various
years.
Table 21. Growth in the Nevada Economy, 2019-2048, No Carbon Price Scenario
Nevada Economic Impacts Compared to 2018 2019 2021 2023 2028 2038 2048
Low Carbon Gross State Product (millions of 2019 dollars) 4,196 11,707 19,994 41,355 97,297 170,066 Personal Income (millions of 2019 dollars) 4,556 11,806 19,174 37,250 87,399 160,582 State & Local Tax Revenue (millions of 2019 dollars) 469 1,216 1,975 3,837 9,002 16,540 Employment (total jobs) 18,800 22,064 20,715 39,144 110,599 202,697
All Market Gross State Product (millions of 2019 dollars) 4,196 11,401 19,622 41,662 97,279 169,768 Personal Income (millions of 2019 dollars) 4,556 11,603 18,917 37,432 87,379 160,389 State & Local Tax Revenue (millions of 2019 dollars) 469 1,195 1,948 3,855 9,000 16,520 Employment (total jobs) 18,800 18,983 17,878 41,669 110,462 200,885
Development Gross State Product (millions of 2019 dollars) 4,197 11,868 20,003 41,344 97,296 170,071 Personal Income (millions of 2019 dollars) 4,556 11,912 19,186 37,245 87,400 160,591 State & Local Tax Revenue (millions of 2019 dollars) 469 1,227 1,976 3,836 9,002 16,541 Employment (total jobs) 18,804 23,488 20,688 39,020 110,599 202,768
Renewable Gross State Product (millions of 2019 dollars) 4,196 11,707 19,989 41,356 97,297 170,065 Personal Income (millions of 2019 dollars) 4,556 11,806 19,172 37,251 87,399 160,582 State & Local Tax Revenue (millions of 2019 dollars) 469 1,216 1,975 3,837 9,002 16,540 Employment (total jobs) 18,800 22,064 20,696 39,151 110,594 202,694
Notes: The All Market case (under the No Carbon Price Scenario) is assumed to be the REMI Baseline scenario; expenditure and electricity revenue inputs for the other three cases are in comparison to this plan. Employment values include full time and part time jobs.
Table 22 displays estimates of growth for selected years in Nevada gross state
product, personal income, state tax revenue and employment compared to those of
the Low Carbon case under the No Carbon Price scenario. The Low Carbon case
and the Renewable case have virtually the same economic impacts. In contrast, the
growth in the Nevada economy would be noticeably greater under the Development
case in one year (2021) and noticeably smaller under the All Market case under the
majority of the years (on the order of 2,000 to 3,000 jobs).
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Table 22. Growth of the Nevada Economy Compared to the Low Carbon Plan, 2019-2048,
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No Carbon Price Scenario Nevada Economic Impacts Compared to 2018
2019 2021 2023 2028 2038 2048 Low Carbon Gross State Product (millions of 2019 dollars) - - - - - -Personal Income (millions of 2019 dollars) - - - - - -State & Local Tax Revenue (millions of 2019 dollars) - - - - - -Employment (total jobs) - - - - - -
All Market Gross State Product (millions of 2019 dollars) 0 -306 -371 308 -19 -298 Personal Income (millions of 2019 dollars) 0 -203 -257 182 -20 -193 State & Local Tax Revenue (millions of 2019 dollars) 0 -21 -26 19 -2 -20 Employment (total jobs) 0 -3,081 -2,837 2,525 -137 -1,812
Development Gross State Product (millions of 2019 dollars) 1 161 9 -11 -1 5 Personal Income (millions of 2019 dollars) 0 106 12 -5 1 9 State & Local Tax Revenue (millions of 2019 dollars) 0 11 1 -1 0 1 Employment (total jobs) 4 1,424 -27 -124 0 71
Renewable Gross State Product (millions of 2019 dollars) 0 0 -5 2 0 -1 Personal Income (millions of 2019 dollars) 0 0 -2 1 -1 -1 State & Local Tax Revenue (millions of 2019 dollars) 0 0 0 0 0 0 Employment (total jobs) 0 0 -19 7 -5 -3
Notes: The All Market case (under the No Carbon Price scenario) is assumed to be the REMI Baseline scenario; expenditure and electricity revenue inputs for the other three cases are in comparison to this plan. Note that this table presents the deltas relative to the Low Carbon Case for the No Carbon Price scenario and not the REMI Baseline. Employment values include full time and part time jobs.
Table 23 displays the growth in the Nevada economy from 2018 to six future years
(2019, 2021, 2023, 2028, 2038, and 2048) under the four cases for the Mid CO2
Price scenario.
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Table 23. Growth in the Nevada Economy, 2019-2048, Mid CO2 Price Scenario Nevada Economic Impacts Compared to 2018
2019 2021 2023 2028 2038 2048 Low Carbon Gross State Product (millions of 2019 dollars) 4,196 11,707 19,994 41,357 97,291 170,018 Personal Income (millions of 2019 dollars) 4,556 11,806 19,174 37,245 87,369 160,523 State & Local Tax Revenue (millions of 2019 dollars) 469 1,216 1,975 3,836 8,999 16,534 Employment (total jobs) 18,800 22,064 20,715 39,066 110,228 202,228
All Market Gross State Product (millions of 2019 dollars) 4,196 11,401 19,622 41,664 97,272 169,722 Personal Income (millions of 2019 dollars) 4,556 11,603 18,917 37,425 87,348 160,333 State & Local Tax Revenue (millions of 2019 dollars) 469 1,195 1,948 3,855 8,997 16,514 Employment (total jobs) 18,800 18,983 17,878 41,569 110,077 200,447
Development Gross State Product (millions of 2019 dollars) 4,197 11,868 20,003 41,347 97,290 170,025 Personal Income (millions of 2019 dollars) 4,556 11,912 19,186 37,241 87,370 160,533 State & Local Tax Revenue (millions of 2019 dollars) 469 1,227 1,976 3,836 8,999 16,535 Employment (total jobs) 18,804 23,488 20,688 38,953 110,231 202,305
Renewable Gross State Product (millions of 2019 dollars) 4,196 11,707 19,989 41,359 97,290 170,018 Personal Income (millions of 2019 dollars) 4,556 11,806 19,172 37,246 87,368 160,523 State & Local Tax Revenue (millions of 2019 dollars) 469 1,216 1,975 3,836 8,999 16,534 Employment (total jobs) 18,800 22,064 20,696 39,073 110,223 202,224
Notes: The All Market case (under the Mid CO2 Price scenario) is assumed to be the REMI Baseline scenario. All four of the Mid CO2 Price cases above are modeled in comparison to that plan. Employment values include full time and part time jobs.
Table 24 displays estimates of growth for selected years in Nevada gross state
product, personal income, state tax revenue and employment compared to those of
the Low Carbon case for the Mid CO2 Price scenario. Results are very similar to
those for the No Carbon Price scenario. The Low Carbon case and the Renewable
case have virtually the same economic impacts. In contrast, the growth in the
Nevada economy would be noticeably greater under the Development case in one
year (2021) and noticeably smaller under the All Market case under the majority of
the years (on the order of 2,000 to 3,000 jobs).
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Table 24. Growth of the Nevada Economy Compared to Low Carbon Plan, 2019-2048,
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Mid CO2 Price Scenario Nevada Economic Impacts Compared to 2018
2019 2021 2023 2028 2038 2048 Low Carbon Gross State Product (millions of 2019 dollars) - - - - - -Personal Income (millions of 2019 dollars) - - - - - -State & Local Tax Revenue (millions of 2019 dollars) - - - - - -Employment (total jobs) - - - - - -
All Market Gross State Product (millions of 2019 dollars) 0 -306 -371 307 -19 -296 Personal Income (millions of 2019 dollars) 0 -203 -257 180 -21 -190 State & Local Tax Revenue (millions of 2019 dollars) 0 -21 -26 19 -2 -20 Employment (total jobs) 0 -3,081 -2,837 2,503 -151 -1,781
Development Gross State Product (millions of 2019 dollars) 1 161 9 -10 -1 7 Personal Income (millions of 2019 dollars) 0 106 12 -4 1 10 State & Local Tax Revenue (millions of 2019 dollars) 0 11 1 0 0 1 Employment (total jobs) 4 1,424 -27 -113 3 77
Renewable Gross State Product (millions of 2019 dollars) 0 0 -5 2 -1 -1 Personal Income (millions of 2019 dollars) 0 0 -2 1 -1 -1 State & Local Tax Revenue (millions of 2019 dollars) 0 0 0 0 0 0 Employment (total jobs) 0 0 -19 7 -5 -4
Notes: The All Market case (under the No Carbon Price scenario) is assumed to be the REMI Baseline scenario. All four of the Mid CO2 Price cases above are modeled in comparison to that plan. Note that this table presents the deltas relative to the Low Carbon case for the Mid CO2 Price scenario and not the REMI Baseline. Employment values include full time and part time jobs.
37. Q. PLEASE SUMMARIZE YOUR ESTIMATES OF THE ECONOMIC IMPACTS
OF THE FIFTH RESOURCE PLAN.
A. Table 25 provides estimates for this plan, which assumes a Mid CO2 Price scenario.
As explained in question and answer 9, Table 25 depicts the modeled impact that a
shift in NV Energy’s planning philosophy from a long-term mindset to a short-term
mindset would have on Nevada’s economy in the period from 2019 to 2023. The
Question 3 Alternative includes only one long-term commitment by NV Energy, in
particular to 300 MW of new solar PV. While Nevada’s economy continues to grow
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under the Question 3 Alternative between 2018 and 2023, the growth rate is slower
through 2023 than in any of the four primary cases. As noted, however, these
estimates are not comparable to those for the other four cases because they do not
cover the full period.
Table 25. Growth in the Nevada Economy for the Q3 Alternative, 2019-2023 Nevada Economic Impacts Compared to 2018
2019 2020 2021 2022 2023 Q3 Gross State Product (millions of 2019 dollars) 4,196 7,505 11,119 15,848 19,663 Personal Income (millions of 2019 dollars) 4,556 7,851 11,417 15,958 18,939 State & Local Tax Revenue (millions of 2019 dollars) 469 809 1,176 1,644 1,951 Employment (total jobs) 18,800 16,155 16,146 19,513 18,060
Notes: The All Market case (under the No Carbon Price Scenario) is assumed to be the REMI Baseline scenario; expenditure and electricity revenue inputs for the other three cases are in comparison to this plan. Employment values include full time and part time jobs. All values for the Q3 Alternative are based on the Mid CO2 Price scenario only. Since the Mid CO2 Price scenario assumes a binding cap in 2025, and the analysis period for the Q3 Alternative ends in 2023, using the No Carbon Price scenario as an alternative would have no effect on the results.
VIII. CONCLUSION
38. Q. DOES THIS COMPLETE YOUR TESTIMONY?
A. Yes, it does.
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Exhibit Harrison Direct-1
David Harrison, Ph.D. Managing Director
National Economic Research Associates, Inc. 200 Clarendon Street, 11th Floor Boston, Massachusetts 02116 +1 617 927 4500 Fax +1 617 927 4501 Direct dial: +1 617 927 4512 [email protected]
David Harrison Managing Director
Dr. David Harrison is a Managing Director at NERA Economic Consulting and co-head of NERA’s global environment practice. He has extensive experience evaluating the economic effects of a wide range of policies and programs as a consultant, academic and government official.
Dr. Harrison has extensive experience over more than two decades evaluating the costs and benefits of air quality regulations under the Clean Air Act and other social regulatory policies, including various health and safety regulations. This experience includes evaluating the potential environmental benefits/damages associated with air emissions taking into account information on emissions, air quality concentrations, population exposure, and dose-response relationships. The various cost-benefit and cost-effectiveness studies have been done for a large number of sectors, including electricity, automobile, trucking, marine, chemical, iron and steel, petroleum, pulp and paper, small utility engines, small handheld equipment, snowmobiles, construction equipment, and others. He and his colleagues have worked closely with company officials and collaborated with various technical consultants in the development of information on these programs. The results of these analyses have been presented to company officials, government agencies, and the media.
Dr. Harrison has been active in the development and economic assessment of climate change policies around the world. He participated in the development or evaluation of major greenhouse gas programs and proposals in the United States, including those in California, the Northeast, the Midwest and various federal initiatives, as well as programs in Europe and Australia. He and his colleagues assisted the European Commission and the UK government with the design and implementation of the European Union Emissions Trading Scheme and national European programs related to climate change, renewable policies, and energy efficiency policies. He also has directed numerous projects for individual companies and trade associations—including those in electricity, oil and gas, refining, petrochemical, pulp and paper, cement, iron and steel, chemical, aluminum and other sectors—to evaluate the potential effects of climate change policies. Dr. Harrison and his colleagues have used NERA’s proprietary energy-macroeconomic
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Exhibit Harrison Direct-1 David Harrison
model (NewERA) to evaluate the potential economic impacts of a U.S. carbon tax and to evaluate the potential economic impacts of federal regulations on carbon dioxide emissions from existing power plants. He has lectured frequently on climate change and related topics at numerous conferences in the United States and abroad.
Dr. Harrison has directed benefit-cost analyses for numerous electric power plants under Section 316(b) of the Clean Water Act and other regulations related to water quality. These have included facilities on the major water bodies, including the Atlantic Coast, the Great Lakes, the Pacific Coast, and various rivers. The power plants have included numerous nuclear and fossil units. These assessments have included estimates of the potential impacts on electricity cost and reliability using detailed electricity market models in various electricity regions of the United States. Dr. Harrison has testified regarding these cost-benefit assessments in numerous state workshops and administrative hearings. He also has assisted the Utility Water Act Group (UWAG), the Edison Electric Institute (EEI) and individual utilities in their evaluation of the EPA 316(b) regulations as well as of EPA effluent guideline regulations. He has presented the results of these assessments to senior EPA and OMB officials. Dr. Harrison was a co-signer of an Amicus Brief submitted to the Supreme Court of the United States regarding the comparison of benefits and costs under Section 316(b) of the Clean Water Act.
Dr. Harrison has directed numerous studies of the local and state economic impacts of policies and programs, including those related to transportation (airports, highways, airlines), housing and tourism activities, energy (power plants, natural gas pipelines and others), remediation (Superfund and other environmental remediation), manufacturing and mining activities (including mining, chemical, petrochemical, automotive, and many others), and large commercial and retail developments. He has developed estimates of the cumulative national and global contributions of these local and state contributions. The local and state analyses have used state-of-the-art model developed by Regional Economic Models, Inc. (REMI) and IMPLAN, as well as customized models developed by NERA based upon available data. These economic impact projects have been developed for numerous metropolitan areas within the U.S. and the rest of the world, for virtually all states in the U.S. as well as for individual countries in Africa, Europe, and the Caribbean. The results of these studies have been presented to numerous public and private groups as well as to the media.
On the national level, in addition to developing estimates of the cumulative national impacts on local economies, Dr. Harrison has worked with colleagues to develop macroeconomic assessments of the impacts of major national policies and programs on the U.S. and state economies. Assessments have included studies of the U.S. Environmental Protection Agency’s (EPA’s) Clean Power Plan to reduce carbon dioxide emissions, EPA’s potential regulations for ambient air quality standards for ozone, EPA’s proposed effluent guidelines, cumulative effects of EPA air, coal combustion residuals, and cooling water regulations, and a potential carbon tax, all of which were based upon the use of the NewERA model, NERA’s integrated electricity, energy and macroeconomic model.
Before joining NERA, Dr. Harrison was an Associate Professor at the John F. Kennedy School of Government at Harvard University, where he taught microeconomics, energy and
NERA Economic Consulting
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Exhibit Harrison Direct-1 David Harrison
environmental policy, cost-benefit analysis, transportation policy, regional economic development, and other courses for more than a decade. He also served as a Senior Staff Economist on the U.S. government’s President’s Council of Economic Advisors, where he had responsibility for environment and energy policy issues. He is the author or co-author of two books on environmental policy and numerous articles on various topics in professional journals.
Dr. Harrison received a Ph.D. in Economics from Harvard University, where he was a Graduate Prize Fellow. He holds a B.A. magna cum laude in Economics from Harvard College, where he was a member of Phi Beta Kappa, and a M.Sc. in Economics from the London School of Economics, where he was the Rees Jeffreys Scholar.
Education
Harvard University Ph.D., Economics, 1974 M.A., Economics, 1972
London School of Economics and Political Science M.Sc., Economics, 1968
Harvard University B.A., Economics, magna cum laude, 1967
Professional Experience
National Economic Research Associates, Inc. 1988- Managing Director, Senior Vice President, Vice President. Directs projects in the
economics of the environment, energy, transportation, regional economic development and other areas.
1987-1988 Putnam, Hayes & Bartlett, Inc. Senior Associate. Directed projects in the economics of energy, antitrust, and other areas.
1985-1987 Dun & Bradstreet Technical Economic Services Director of Product Development. Directed economic studies in energy, transportation, and industrial location.
1980-1985 John F. Kennedy School of Government, Harvard University Associate Professor. Areas of instruction: microeconomics; benefit-cost analysis; environment; energy; natural resource economics; urban economics; public finance; transportation; law and economics. Participant, Harvard Faculty Project on Regulation. Faculty Steering Committee, Energy and Environmental Policy Center. Principal investigator in research grants.
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1979-1980 President’s Council of Economic Advisors Senior Staff Economist. Worked with other White House staff and agency officials on domestic issues. Areas of responsibility included energy, environment and transportation. Principal staff on the Regulatory Analysis Review Group. Principal White House staff for the review of Administration policy regarding the automotive industry.
1974-1979 Department of City and Regional Planning, Harvard University Assistant and Associate Professor. Areas of instruction: microeconomics; statistics; econometrics; transportation; environment; urban development; and housing policy. Participant, MIT-Harvard Joint Center for Urban Studies. Faculty Chairman, Concentration in Land Use and Environment.
1974 National Bureau of Economic Research Research Associate. Co-author of benefit-cost study of automotive air pollution prepared by the National Academy of Sciences for the Committee on Public Works, U.S. Senate.
1973-1974 U.S. Department of Transportation Economist. Performed economic studies of transportation issues, including urban mass transportation, automobile emission and safety programs, and highway finance.
1970-1974 Department of Economics, Harvard University Teaching Fellow and Assistant Head Tutor. Areas of instruction: microeconomics; macroeconomics; econometrics; transportation; public finance; environmental policy; and housing policy.
1971 The Urban Institute Research Economist. Participated in econometric studies as participant in the Program on Local Public Finance.
1969 U.S. Department of Housing and Urban Development Economist. Participated in economic evaluations of HUD infrastructure programs, primarily the water and sewer grant program.
Honors and Professional Activities
Summa cum Laude, Senior Honors Thesis, Harvard University.
Phi Beta Kappa, Harvard University.
Rees Jeffreys Scholar in the Economics of Transport, London School of Economics.
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Graduate Prize Fellowship, Harvard University.
Member, American Economic Association.
Member, Association of Environmental and Resource Economists.
Member, International Association of Energy Economists.
Member, Public Policy for Surface Freight Transportation Study, Transportation Research Board, National Research Council.
Member, Advisory Committee, Massachusetts Department of Environmental Quality Engineering.
Member, Peer Review Panel, National Acid Precipitation Assessment Program.
Member, Public Health and Socio-Economic Task Force, South Coast Air Quality Management District (Los Angeles).
Member, Marketable Permits Advisory Committee, South Coast Air Quality Management District (Los Angeles).
Member, Socioeconomic Technical Review Committee, South Coast Air Quality Management District (Los Angeles).
Member, Harvard Graduate Society Council.
Member, RECLAIM Advisory Committee (Los Angeles).
Member, Board of Trustees, Cambridge Health Alliance (Harvard Medical School Teaching Hospital).
Participant, Aspen Institute Dialogue on Climate Change.
Member, U.S. Government Accountability Office Expert Panel on International Greenhouse Gas Emissions Trading.
Consultant to the following public and private organizations:
U.S. Environmental Protection Agency; U.S. Department of Transportation; Massachusetts Port Authority; Organization for Economic Cooperation and Development (OECD, Paris); European Commission Directorate-General Environment; Civil Aeronautics Board; Italian Ministry of Environment; Massachusetts Department of Environmental Protection; UK Department of Transport; UK Department for Environment, Food and
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Rural Affairs, UK Department of Trade and Industry, City of Chicago Department of Aviation; Conference Board of Canada; South Coast Air Quality Management District; Massachusetts Department of Environmental Management; and numerous state and local governments, trade associations, and private firms.
Reviewer for the following professional journals:
American Economic Review; Review of Economics and Statistics; Journal of Political Economy; Journal of Environmental Economics and Management; Journal of Urban Economics; Journal of Regional Science; Journal of Policy Analysis and Management; and Public Policy.
I. Publications
A. Books
Who Pays for Clean Air. Cambridge, MA: Ballinger Publishing Company, 1975.
The Automobile and the Regulation of Its Impact on the Environment (co-author). Norman, OK: Oklahoma University Press, 1975.
B. Articles and Published Reports
Economics in Environmental Decision-Making: US Environmental Protection Agency Provides for Site-Specific Cost-Benefit Analysis in Setting 316(b) Clean Water Standards (with Noah Kaufman), NERA Economic Consulting, May 2014.
“Economic Policy Instruments for Reducing Greenhouse Gas Emissions” (with Andrew Foss, Per Klevnas, and Daniel Radov), chapter in Oxford Handbook of Climate Change, edited by David Schlosberg, John Dryzek, and Richard Norgaard, August 2011.
Climate Change Risks and Opportunities: How Companies Can Develop Information to Comply with SEC Guidance Regarding Climate Change Disclosure (with Andrew Foss), NERA Economic Consulting, February 2010.
A Victory for Economic and Environmental Rationality: Supreme Court Allows Cost-Benefit Analysis in Setting Important Clean Water Act Standards, NERA Economic Consulting, May 2009.
What Every Company Should Do to Prepare for a Mandatory US Greenhouse Gas Cap-and-Trade Program, in Climate Policy Economics Insights, NERA Economic Consulting, March 2009.
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Now the Hard Work: How to Get the “Biggest Bang for the Buck” from the Federal Economic Stimulus Package, NERA Economic Consulting, February 2009.
Evaluation of Borrowing as a Method to Contain Costs in a Greenhouse Gas Emissions Cap-and-Trade Program (with Albert Nichols), Electric Power Research Institute, December 2008.
“Using Emissions Trading to Combat Climate Change: Programs and Key Issues” (with Per Klevnas, Albert Nichols and Dan Radov) in Environmental Law Reporter, June 2008.
Complexities of Allocation Choices in a Greenhouse Gas Emissions Trading Program (with Per Klevnas and Dan Radov), International Emissions Trading Association (IETA), September 2007.
“State Restrictions on Mercury Trading Could Prove Expensive, Ineffective” (with James Johndrow) in Natural Gas Electricity, Volume 24, Number 2. Isabelle Cohen, Hoboken, NJ: Wiley Periodicals, Inc., September 2007.
“Experience for Member States in Allocating Allowances: United Kingdom” (with Dan Radov) in Allocation in the European Emissions Trading Scheme. A. Denny Ellerman, Barbara K. Buchner and Carlo Carraro, Cambridge, UK: Cambridge University Press, 2007.
Interactions of Cost-Containment Measures and Linking of Greenhouse Gas Emissions Cap-and-Trade Programs, Electric Power Research Institute, November 2006.
Interactions of Greenhouse Gas Emission Allowance Trading with Green and White Certificate Schemes, European Commission Directorate-General Environment, November 2005.
Carbon Markets, Electricity Prices and “Windfall Profits”—Emerging Information from the European Union Emissions Trading Scheme, Electric Power Research Institute, September 2005.
Economic Instruments for Reducing Ship Emissions in the European Union, European Commission, Directorate-General Environment, June 2005.
Evaluation of the Feasibility of Alternative Market-Based Mechanisms to Promote Low-Emission Shipping in European Union Sea Areas, European Commission, Directorate-General Environment, March 2004.
“Assessing the Financial Consequences to Firms and Households of a Downstream Cap-And-Trade Program to Reduce U.S. Greenhouse Gas Emissions” in A Climate Policy Framework: Balancing Policy and Politics, John A. Riggs, ed., Washington, DC: The Aspen Institute, 2004.
Alternatives for Implementing the UK’s National Allocation Plan, Department for Environment, Food and Rural Affairs, with AEA Technology and SPRU, August 2003.
Report on UK’s Implementation of the CO2 National Allocation Plan Under the European Union Greenhouse Gas Emissions Trading Programme, Department for Environment, Food and Rural Affairs, with AEA Technology and SPRU, July 2003.
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“Ex Post Evaluation of the RECLAIM Emissions Trading Program for the Los Angeles Air Basin,” National Policies Division, OECD Environment Directorate, June 2003.
Emission Trading in the U.S.: Experience, Lessons, and Considerations for Greenhouse Gases (with Denny Ellerman and Paul Joskow). Pew Center on Global Climate Change, May 2003.
“Carbon Emission Trading: Creating a New Traded Commodity Market in Europe,” in WorldPower, October 2002.
“A Groundbreaking Proposal: European Greenhouse Gas Emissions Trading,” in Infrastructure Journal, August 2002.
“Europe Warms to Emissions Trading,” in Energy Regulation Brief, NERA Economic Consulting, April 2002.
Evaluation of Alternative Initial Allocation Methods in a European Union Greenhouse Gas Emissions Cap-and-Trade Programme, European Commission Directorate-General Environment, March 2002.
“Economics Issues in Section 316(B) Decisions,” in A Towering Challenge, C. Richard Bozek, Electric Perspectives, January/February 2002.
“Tradable Permit Programs for Air Quality and Climate Change,” in International Yearbook of Environmental and Resource Economics, Volume VI, Henk Folmer and Thomas Tietenberg (Eds.). London: Edward Elgar, 2002.
Energy-Environment Policy Integration and Coordination Study (contributor), Palo Alto, CA: Electric Power Research Institute, December 2000.
Critical Issues in International Greenhouse Gas Emissions Trading: Setting Baselines for Credit-Based Trading Programs-Lessons Learned from Relevant Experience. Palo Alto, CA, Electric Power Research Institute, June 2000.
“Tradable Permits for Air Pollution Control: The United States Experience,” in Domestic Tradable Permit Systems for Environmental Management: Issues and Challenges, J.P. Barde and T. Jones (Eds.). Paris: Organization for Economic Cooperation and Development, 1999.
“Emissions Trading: Turning Theory Into Practice in the Los Angeles Air Basin,” in Pollution for Sale: Emissions Trading and Joint Implementation, S. Sorrell and J. Skea (Eds.). London: Edward Elgar, 1999.
“Commentary: International Greenhouse Gas Trading and the Kyoto Protocol,” in Climate Change Policy: Practical Strategies to Promote Economic Growth and Environmental Quality, C. Walker, M. Bloomfield and M. Thorning (Eds.). Washington, DC: The American Council for Capital Formation Center for Policy Research, May 1999
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“Priorities for the Development of GHG Trading Programs: Implications of the U.S. Experience,” in Global Climate Change: Science, Policy, and Mitigation/Adaptation Strategies, C.V. Mathai and J. Kinsman (Eds.). Washington, DC: Air & Waste Management Association, October 1998.
“Commentary on ‘Tradable Emissions Rights and Joint Implementation for Greenhouse Gas Abatement: A Look Under the Hood,’” in The Impact of Climate Change Policy on Consumers: Can Tradable Permits Reduce the Cost? C. Walker, M. Bloomfield, and M. Thorning (Eds.). Washington, DC: The American Council for Capital Formation Center for Policy Research, April 1998.
“Considerations in Designing and Implementing an Effective International Greenhouse Gas Trading Program,” Global Climate Coalition, October 1997.
“The Use of Externality Adders for Greenhouse Gas Emissions in Electric Utility Resource Planning,” in Internalization of Social Costs of Energy Conversion and Transportation in the United States and Europe for a Sustainable Development, O. Hohmeyer and R. Ottinger (Eds.). Berlin: Springer-Verlag, 1996.
“Environmental Adders in the Real World,” (with A. Nichols), in Resources and Energy Economics, December 1996.
“Recent Evidence on the Appropriate Timing of Reductions in Greenhouse Gas Emissions,” (with A. Nichols), Global Climate Coalition, July 1996.
The Distributive Effects of Economic Instruments for Global Warming. Paris: Organization for Economic Cooperation and Development, 1996.
The Distributive Effects of Economic Instruments for Environmental Policy. Paris: Organization for Economic Cooperation and Development, 1994.
“The Socioeconomic Effects of Externality Adders for Electric Utility Emissions,” in Technical Review of Externalities Issues. Electric Power Research Institute, December 1994.
“Utility Externalities and Emissions Trading: California is Developing a Better Way,” in Social Costs of Energy - Present Status and Future Trends, R. Ottinger and O. Hohmeyer (Eds.). Berlin: Springer-Verlag 1994.
“Who Wins and Who Loses from Economic Instruments?” The OECD Observer 180:29-31, February/March 1993.
“Tradable Permits and Social Costing: The California Experience,” prepared for the American Economic Association and Allied Social Science Association Meeting, Anaheim, California, January 6, 1993.
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“Emissions Trading: A Better Way to Include Environmental Costs in Electric Utility Resource Planning,” American Planning Association and Edison Electric Institute, March 1992.
“Economists’ Contribution to the Environment,” Journal of Air and Waste Management Association, October 1991.
“Potential Cost Savings and Environmental Effects of Using Emissions Trading to Manage NOx in Ontario,” (with A. Nichols), in Air and Waste Management Through the 90’s, R. E. Clement (Ed.), Air and Waste Management Association, Ontario, Canada, April 1990.
“Market-Based Approaches for Environmental Protection: Implications for Business,” (with A. Nichols), in Special Report on Global Environmental Issues, B. Gentry (Ed.). Washington, DC: The Bureau of National Affairs, 1990.
“Environmental Policy in Europe: Economic Lessons from the United States Experience,” in Environmental Damages. Rome, V. Polidoro (Ed.). Italy: Italian Government Printing Office, August 1990.
Comments before the Department of Interior on Advanced Notice of Proposed Rulemaking Regarding Revision of Natural Resource Damage Assessment Regulations, 43 CFR Part 11, (with J. Hausman), November 1989.
“To Live and Breathe in L.A.,” (with P. Portney, A. Krupnick, and H. Dowlatabadi), Issues in Science and Technology Vol(4): Summer 1989.
“Policy Approaches for Controlling Greenhouse Gases,” Energy Research Group, May 1989.
“Yes to Clean Air, But at What Cost?” The New York Times, March 26, 1989.
“Realistic Air-Quality Goals Will Prevent Cost Explosion,” Los Angeles Times, January 11, 1989.
“Put the Clock on Landing Fees,” The Journal of Commerce, November 10, 1988.
“Reforming Airport Pricing to Reduce Congestion,” Conference on Transportation Options for the 21st Century, Boston, Massachusetts, July 1988.
“Awaiting the Second Shoe at Congested Logan,” The Boston Globe, March 29, 1988.
“Banning Hazardous Material from Land Disposal Facilities,” Hazardous Waste 1(1984).
“Benefit-Cost Analysis of Environmental Regulation: Case Studies of Hazardous Air Pollutants,” (with J. Haigh and A. Nichols), Harvard Environmental Law Review 8(1984).
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Research and Demonstration of Improved Methods for Carrying Out Benefit-Cost Analysis of Individual Regulations, Volumes I - IV, (Principal Investigator), prepared for the U.S. Environmental Protection Agency, Final Report, November 1984.
“Using the Hedonic Housing Value Method to Estimate the Benefits of Hazardous Waste Cleanup,” (with J. Stock), U.S. Environmental Protection Agency, November 1984.
“Using the Averting Cost Method to Estimate the Benefits of Hazardous Waste Cleanup,” (with M. O’Keeffe), U.S. Environmental Agency, November 1984.
“The Value of Acquiring Information Under Section 8(a) of the Toxic Substances Control Act: A Decision-Analytic Approach,” (with A. Nichols, L. Boden, and R. Terrell), U.S. Environmental Protection Agency, November 1984.
“Hedonic Housing Values, Local Public Goods, and the Benefits of Hazardous Waste Cleanup,” (with J. Stock), Discussion Paper, Energy and Environmental Policy Center, Harvard University, November 1984.
“The Regulation of Aircraft Noise,” in Incentive Arrangements for Environmental Protection, T. Schelling (Ed.). Cambridge, MA: MIT Press, 1983.
“Benefit-Based Flexibility in Environmental Regulation,” (with A. Nichols), Discussion Paper, Energy and Environmental Policy Center, Harvard University, April 1983.
“Who Loses from Reform of Environmental Regulation,” (with P. Portney), in Reform of Environmental Regulation, Wesley Magat (Ed.). Cambridge, MA: Ballinger Publishing Company, 1982.
“Regulatory Reform in the Large and in the Small,” (with P. Portney), in Reforming Government Regulation, LeRoy Graymer (Ed.). Beverly Hills, CA: Sage Publications, 1982.
“Imports and the Future of the U.S. Automobile Industry,” (with J. Gomez-Ibanez), American Economic Review, Papers and Proceedings 72 (May 1982).
“Regulation and Distribution: An Agenda for Research,” in Creating An Agenda for Regulatory Research, A. Ferguson (Ed.). Cambridge, MA: Ballinger Publishing Company, 1981.
“Cost-Benefit Analysis and the Regulation of Environmental Carcinogens,” in Management of Carcinogenic Risk, W. Nicholson (Ed.). New York: New York Academy of Sciences, 1981.
“Distributional Objectives in Health and Safety Regulation,” in The Benefits of Health and Safety Regulation, A. Ferguson (Ed.). Lexington, MA: D.C. Heath and Company, 1981.
“The Local Government Role in Energy Policy,” (with M. Shapiro), in Energy and Environment: Conflict and Resolution, R. Axelrod (Ed.). Lexington, MA: D.C. Heath and Company, 1981.
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“Making Ready for the Clean Air Act,” (with P. Portney), Regulation 5(March/April 1981).
“Discussion of Robert C. Ellickson, ‘Public Property Rights: Vicarious Intergovernmental Rights and Liabilities as a Technique for Correcting Intergovernmental Spillovers,” in Essays on the Law and Economics of Local Government, D. Rubinfeld (Ed.). Washington, D.C: The Urban Institute, 1979.
“Simulating the Impacts of Transportation Policy on Urban Land Use,” Discussion Paper, Department of City and Regional Planning, Harvard University, April 1979. (Presented at meeting of the Eastern Economics Association, May 1979.)
“Income and Urban Development,” Discussion Paper, Department of City and Regional Planning, Harvard University, April 1979.
“The Distribution of Benefits from Improvements in Urban Air Quality,” (with D. Rubinfeld), Journal of Environmental Economics and Management 5(December 1978).
“The Impact of Transit Systems on Land Use Patterns in the Pre-Automobile Era,” Discussion Paper, Department of City and Regional Planning, Harvard University, December 1978.
“The Air Pollution and Property Value Debate: Some Empirical Evidence,” (with D. Rubinfeld), Review of Economics and Statistics 60(November 1978).
“Transportation Technology and the Dynamics of Urban Land Use Patterns,” paper presented to the Conference on Urban Transportation, Planning, and the Dynamics of Land Use, Northwestern University, June 1978.
“Hedonic Housing Values and the Demand for Clean Air,” (with D. Rubinfeld), Journal of Environmental Economics and Management 5(March 1978).
“Controlling Automotive Emissions: How to Save More Than $1 Billion per Year and Help the Poor Too,” Public Policy 2 (Fall 1977).
“Reply to Michelle White’s Comment on ‘Cumulative Urban Growth and Urban Density Functions,’” (with J. Kain), Journal of Urban Economics 4(January 1977).
“Cumulative Urban Growth and Urban Density Functions,” (with J. Kain), Journal of Urban Economics 1(January 1974).
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II. Consulting Reports for Directed Projects
A. Climate Change
Environmental Costs and Economic Impacts of 100 MW Generic Technology/Resource Options (Supplemental Report to 2016 IRP), prepared for Sierra Pacific Power Company, September 2016.
Environmental Costs and Economic Impacts of the 2016 Integrated Resource Plan, prepared for Sierra Pacific Power Company, June 2016.
Potential Electricity and Energy Price Outcomes under EPA’s Federal Plan Alternatives for the Clean Power Plan, prepared for Group of Energy-Intensive Industry Associations, January 2016.
Energy and Consumer Impacts of EPA’s Clean Power Plan, prepared for the American Coalition for Clean Coal Electricity, November 2015.
Environmental Costs and Economic Impacts of the 2015 Integrated Resource Plan, prepared for Nevada Power Company, June 2015.
Investing in a Time of Climate Change, prepared with Mercer for a group of asset-owner and manager partners, June 2015.
Impacts of the EPA Clean Power Plan Building Blocks on Texas Energy Markets, prepared for Luminant, November 2014.
Potential Energy Impacts of the EPA Proposed Clean Power Plan, prepared for the American Coalition for Clean Coal Electricity and other organizations, October 2014.
A Carbon Dioxide Standard for Existing Power Plants: Impacts of the NRDC Proposal, prepared for the American Coalition for Clean Coal Electricity, March 2014.
Linkage of a Potential South African GHG Cap and-Trade Program: Initial Scoping Study,” prepared for Sasol, June 13, 2013.
Environmental and Economic Impacts of the 2013 Integrated Resource Plan, prepared for Sierra Pacific Power Company, June 2013.
Economic Outcomes of a U.S. Carbon Tax, prepared for National Association of Manufacturers, February 26, 2013.
Environmental and Economic Impacts of the Second Amendment to the 2010 Integrated Resource Plan, prepared for Sierra Pacific Power, August 2012.
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Analysis of EPA’s Proposed GHG, New Source Performance Standard for Electric Generating Units, prepared for American Coalition for Clean Coal Electricity, June 25, 2012
Environmental and Economic Impacts of the 2012 Integrated Resource Plan, prepared for Nevada Power Company, June 2012.
Evaluation of Incentives in International Sectoral Crediting Mechanisms, prepared for Enel S.p.A., October 2011.
Environmental and Economic Impacts of the First Amendment Supplemental Filing to the 2009 Integrated Resource Plan, prepared for Nevada Power Company, October 2011.
Environmental Costs and Economic Impacts of the Second Amendment to the 2009 Integrated Resource Plan, prepared for Nevada Power Company, August 2011.
Environmental Costs and Economic Impacts of the 2010 Integrated Resource Plan, prepared for Sierra Pacific Power Company, July 2010.
Environmental Costs and Economic Impacts of the 2009 Integrated Resource Plan, prepared for Nevada Power Company, February 2010.
Follow-up letter to US Environmental Protection Agency Clarifying Key Conclusions from Review of EPA’s Approach to Aggregating Emissions Across Time in Proposed Revisions of Renewable Fuel Standards, prepared on behalf of Growth Energy, January 2010.
Review of EPA’s Approach to Aggregating Emissions across Time in Proposed Revisions of Renewable Fuel Standards, prepared for Growth Energy for submission to U.S. EPA, Docket ID No. EPA-HQ-OAR-2005-0161, September 2009.
Differentiation among Batches of Conventional Biofuels based on Greenhouse Gas Emissions, prepared for Growth Energy, September 2009.
Impacts of Waxman-Markey Bill on US Refiners: Preliminary Estimates, prepared for major industrial sector, July 2009.
Effects of Waxman-Markey on Natural Gas and Electricity Businesses: Phase 1, prepared for a Midwest utility, July 2009.
Environmental Costs and Economic Benefits of Electric Utility Resource Selection, prepared for Nevada Power Company, March 2009.
Impacts of the California Greenhouse Gas Emission Standards on Motor Vehicle Sales, prepared for the Alliance of Automobile Manufacturers, April 2009.
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Accounting for Differences in the Timing of Emissions in Calculating Carbon Intensity for the California Low Carbon Fuels Standard, prepared for the Renewable Fuels Association, April 2009.
Environmental Costs and Economic Benefits of Electric Utility Resource Selection, prepared for Nevada Power Company, March 2009.
Evaluation of Alternative Benchmarked Sector-Level Allocation Formulas, prepared for a major U.S. industrial trade group, October 2008.
Evaluation of NHTSA’s Benefit-Cost Analysis of 2011-2015 CAFE Standards, prepared for the Alliance of Automobile Manufacturers, July 2008.
Impacts of Climate Change Policies Using the NERA Carbon Financial Impacts Model (Phase 2 Study, prepared for a major U.S. industrial manufacturer, June 2008.
Effects of the Regional Greenhouse Gas Initiative on Regional Electricity Markets, prepared for AES and Dynegy, June 2008.
Environmental Costs and Economic Benefits of Electric Utility Resource Selection, prepared for Nevada Power Company, May 2008.
Impacts of Potential Climate Change Policy using the NERA Carbon Financial Impacts Model, prepared for a major U.S. trade association, April 2008.
Market Conditions and the Pass-Through of Compliance Costs in a Carbon Emission Cap-and-Trade Program, prepared for Conoco Phillips, January 2008.
Evaluation of the Financial Impacts of Alternative Climate Change Cap-and-Trade Programs using the NERA Carbon Financial Impacts Model, prepared for a major U.S. industrial manufacturer, December 2007.
Evaluation of the Financial Impacts of Alternative Climate Change Cap-and-Trade Programs using the NERA Carbon Financial Impacts Model, prepared for a major U.S. energy company, November 2007.
Evaluation of the Financial Impacts of Alternative Climate Change Cap-and-Trade Programs using the NERA Carbon Financial Impacts Model, prepared for a major U.S. industrial manufacturer, October 2007.
Evaluation of the Financial Impacts of Alternative Climate Change Cap-and-Trade Programs using the NERA Carbon Financial Impacts Model, prepared for a major U.S. energy company, September 2007.
Environmental Costs and Economic Benefits of Electric Utility Resource Selection, prepared for Sierra Pacific Power Company, June 2007.
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Evaluation of the Financial Impacts of Alternative Climate Change Cap-and-Trade Programs using the NERA Carbon Financial Impacts Model, prepared for a major U.S. energy company, March 2007.
Effectiveness of the California Light Duty Vehicle Regulations As Compared to Federal Regulations, in collaboration with Sierra Research, Inc. and Air Improvement Resource, Inc., prepared for the Alliance of Automobile Manufacturers, June 2007.
Financial Impacts of Potential Mandatory CO2 Cap-and-Trade Programs using the NERA Carbon Financial Impacts Model, prepared for a major U.S. trade association, January 2007.
Modeling the Fleet Population Effects of the Rhode Island Proposal to Reduce Greenhouse Gas Emissions from Motor Vehicles, prepared for the Alliance of Automobile Manufacturers, November 2005.
Review of Potential Expansion of the UK Phase II National Allocation Plan to the Petrochemical Sector, prepared for UK Department for the Environment, Food and Rural Affairs (DEFRA) and Department of Trade and Industry (DTI), November 2005.
The Impacts of CO2 Prices on European Electricity Prices, prepared for Electricité de France (EDF), October 2005.
Modeling the Fleet Population Effects of the Massachusetts Proposal to Reduce Greenhouse Gas Emissions from Motor Vehicles, prepared for the Alliance of Automobile Manufacturers, October 2005.
Modeling the Fleet Population Effects of the Maine Proposal to Reduce Greenhouse Gas Emissions from Motor Vehicles, prepared for the Alliance of Automobile Manufacturers, October 2005.
Modeling the Fleet Population Effects of the New Jersey Proposal to Reduce Greenhouse Gas Emissions from Motor Vehicles, prepared for the Alliance of Automobile Manufacturers, September 2005.
Modeling the Fleet Population Effects of the Connecticut Proposal to Reduce Greenhouse Gas Emissions from Motor Vehicles, prepared for the Alliance of Automobile Manufacturers, September 2005.
Modeling the Fleet Population Effects of the Vermont Proposal to Reduce Greenhouse Gas Emissions from Motor Vehicles, prepared for the Alliance of Automobile Manufacturers, August 2005.
Modeling the Fleet Population Effects of the New York State Proposal to Reduce Greenhouse Gas Emissions from Motor Vehicles, prepared for the Alliance of Automobile Manufacturers, July 2005.
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Initial Review of Potential Expansion of the UK Phase 2 NAP to Additional CO2 Sources, prepared for the Department for the Environment, Food and Rural Affairs, May 2005.
Environmental and Economic Impacts of the ARB Staff Proposal to Control Greenhouse Gas Emissions from Motor Vehicles, prepared for the Alliance of Automobile Manufacturers, September 2004. Submitted to the California Air Resources Board.
Reviews of Studies Evaluating the Impacts of Motor Vehicle Greenhouse Gas Emissions Regulations in California, for the Alliance of Automobile Manufacturers, September 2004. Submitted to California Air Resources Board.
TXU Activities Regarding Actual and Potential US Air Emissions and Climate Change Policies, prepared for TXU Corporation, September 2004.
Strategies for Chubu Electric Power Co., Ltd., to Take Advantage of Opportunities Under Greenhouse Gas Emissions Trading Programs, in collaboration with Japan NUS Co., Lt, for Chubu Electric Power Co., Ltd, January 2004.
Impacts of ZEV Sales Mandate on California Motor Vehicle Emissions: Responses to Comments of Air Resource Board Staff and Related Documents Provided as Part of the 15-Day Notice (with Sierra Research, Inc.), prepared for the Alliance of Automobile Manufacturers, November 2001.
KEPCO’s Role in a Greenhouse Gas Emissions Trading Program, prepared for Kansai Electric Power Company, February 2001.
International Carbon Emissions Trading Practices: Review of Recent Literature, prepared for Chubu Electric Power Company, February 2001.
Strategic Environmental Issues Facing Fossil-Fired Electric Generating Plants in Canada, draft prepared for Ontario Hydro and TransAlta Corporation, June 1996.
The Timing of Plant Replacement and the Cost-Effectiveness of CO2 Reductions from Two Canadian Utilities, prepared for Ontario Hydro and TransAlta Corporation, July 1996.
Scoping Study to Assess the External Costs of Electric Utility Resource Selection in Minnesota, prepared for Otter Tail Power Company with assistance from Systems Applications International, March 1993.
Preliminary Draft Scoping Study to Assess Residual Emissions Valuation in Alberta, prepared for TransAlta Utilities Corporation, September 1992.
Distributional Effects of Economic Instruments for Environmental Policy, prepared for the U.S. Environmental Protection Agency and the Organization for Economic Cooperation and Development, May 1992.
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Tradable Permits and Other Economic Incentives for Environmental Protection, prepared for The Canadian Electrical Association and presented at a Workshop on Tradable Permits, June 1990.
B. Economic Impact
Methodology for Evaluating the Macroeconomic Impacts of Energy Efficiency Programs using REMI, prepared for New York State Energy Research and Development Administration, August 2017.
Impacts of Potential Aluminum Tariffs on the U.S. Economy, prepared for Emirates Global Aluminum, June 2017.
Airbnb’s Global Support to Local Economies: Output and Employment, prepared for Airbnb, March 2017.
Economic Impacts of EPA Portland Harbor Superfund Remedial Alternatives, prepared for the Portland Harbor Sustainability Project, September 2016.
Environmental Costs and Economic Impacts of 100 MW Generic Technology/Resource Options (Supplemental Report to 2016 IRP), prepared for Sierra Pacific Power Company, September 2016.
Environmental Costs and Economic Impacts of the 2016 Integrated Resource Plan, prepared for Sierra Pacific Power Company, June 2016.
Environmental Costs and Economic Impacts of the 2015 Integrated Resource Plan, prepared for Nevada Power Company, June 2015.
Economic Impacts of a 65 ppb National Ambient Air Quality Standard for Ozone, Executive Summary, prepared for National Association of Manufacturers, February 2015.
Assessing Economic Impacts of a Stricter National Ambient Air Quality Standard for Ozone, prepared for National Association of Manufacturers, July 2014.
Environmental Costs and Economic Impacts of the Emissions Reduction and Capacity Replacement Plan, prepared for NV Energy Inc., May 2014.
Economic Implications of Recent and Anticipated EPA Regulations Affecting the Electricity Sector, prepared for American Coalition for Clean Coal Electricity, October 2012.
Potential Impacts of EPA Air, Coal Combustion Residuals, and Cooling Water Regulations, prepared for the American Coalition for Clean Coal Electricity, September 2011.
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Socioeconomic Gains to Pennsylvania of the Muddy Run Pumped Storage Project and the Conowingo Hydroelectric Project, prepared for Exelon Generation Company, LLC, November 2012.
Socioeconomic Gains to Maryland of the Muddy Run Pumped Storage Project and the Conowingo Hydroelectric Project, prepared for Exelon Generation Company, LLC, November 2012.
Effects of a Gas-to-Liquid Facility on the Alberta and Canadian Economies, prepared for Sasol Ltd and Talisman Energy, March 2012.
Effects on State Economies of Tightening of 8-Hour Ozone NAAQS, prepared for American Petroleum Institute, May 2010.
Impacts of Continental Airlines Operations on the New York- New Jersey Regional Economy, prepared for Continental Airlines, November 2009.
Potential Jobs Impacts of Energy Efficiency Expenditures, prepared for Commonwealth Edison, December 2008.
Potential Jobs Impacts of “Smart Grid” Implementation, prepared for Commonwealth Edison, December 2008.
Potential Jobs Impacts of Electric Utility Asset Renewal, prepared for Commonwealth Edison, December 2008.
Economic Impact of Delta’s JFK Presence, prepared for Delta Air Lines, July 2008.
The Flemings Strategy for Grand Bahama Island (contributor), prepared for Global Fulfillment Services Ltd., July 2008.
Estimated Attainment Costs and Economic Impacts in Selected Regions of Proposed Revisions to the EPA 8-Hour Ozone Standard , prepared for National Association of Manufacturers, January 2008.
The Economic Impacts of Attaining the 8-Hour Ozone Standard: Cleveland Case Study, prepared for the American Petroleum Institute, October 2005.
The Economic Impacts of Attaining the 8-Hour Ozone Standard: Philadelphia Case Study, prepared for the American Petroleum Institute, September 2005.
The Past, Present, and Future Socioeconomic Effects of the Niagara Power Project, prepared for the New York Power Authority, August 2005.
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Exhibit Harrison Direct-1 David Harrison
Environmental and Economic Impacts of the ARB Staff Proposal to Control Greenhouse Gas Emissions from Motor Vehicles, prepared for the Alliance of Automobile Manufacturers, September 2004. Submitted to California Air Resources Board.
Impacts of Alternative California Air Resources Board Tier 3 Non-Handheld Exhaust Emission Proposals on the California Economy, prepared for Briggs & Stratton Corporation, September 2003.
Impacts of Eliminating the Withholding Tax on International Wagering in U.S. Pools, prepared for National Thoroughbred Racing Association, May 2003.
Impacts of a Premature Shutdown of Indian Point: Updated Results and Comments on February 2003 Report by Synapse Energy Economics Inc., prepared for Entergy Nuclear General Company, April 2003.
Study of the Impact of the Future Chemicals Policy, prepared for Union des Industries Chimiques of France, April 2003.
Economic Projections Relevant to Traffic Demand Projections for the Chicago Skyway Project, prepared for Wilbur Smith Associates, March 2003.
Assessing the Potential Indirect Effects of Electricity Infrastructure on Regional Growth Patterns, prepared for Southern California Edison, November 2002.
Economic Benefits of PSEG Power Facilities to Bergen County, prepared for PSEG Power Development LLC, April 2002.
The Economic Benefits of the Whitecap Energy System to the Chicago Region, prepared for Whitecap Energy System LLC, January 2001
Evaluation of the Economic Impacts of Proposed Development of the Galleria at Long Wharf in New Haven, Connecticut, prepared for Cowdery, Ecker & Murphy, L.L.C., July 2000.
Contributions of Continental Airlines’ Hopkins Hub to the Economy of the Cleveland Metropolitan Area, prepared for Continental Airlines, June 2000.
Contributions of Continental Airlines’ Newark Hub to the Economy of Newark/New Jersey/New York City, prepared for Continental Airlines, March 2000.
Critical Review of, Economic Impacts of On Board Diagnostic Regulations, prepared for Alliance of Automobile Manufactures, January 2000.
Economic Benefits of Barajas Airport to the Madrid Region and the Neighboring Communities, prepared on behalf of the Spanish Government, January 1999.
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Exhibit Harrison Direct-1 David Harrison
Northwest Regional Jetport: Traffic Forecast and Economic Impact, prepared for and with Mercer Management Consulting, September 1998
Impacts on the Hawaii Economy of Alternative Resource Plans for Oahu, prepared for Hawaiian Electric Company, December 1997.
Economic and Environmental Effects of the Maritimes & Northeast Pipeline Project in New Hampshire, with assistance from the Center for Business and Economic Research at the University of Southern Maine, E.H. Pechan & Associates, Inc., and Rose Communications, Inc., prepared for The Maritimes & Northeast Pipeline Project, March 1997.
Economic and Environmental Effects of the Maritimes & Northeast Pipeline Project in Massachusetts, with assistance from the Center for Business and Economic Research at the University of Southern Maine, E.H. Pechan & Associates, Inc., and Rose Communications, Inc., prepared for The Maritimes & Northeast Pipeline Project, January 1997.
Economic and Environmental Effects of the Maritimes & Northeast Pipeline Project, with assistance from the Center for Business and Economic Research at the University of Southern Maine, E.H. Pechan & Associates, Inc., and Rose Communications, Inc., prepared for The Maritimes & Northeast Pipeline Project, November 1996.
Contributions of American Airlines to the Economy of Dade County, prepared for American Airlines, October 1996.
Socioeconomic Effects of Alternative Electric Utility Resources, prepared for Northern States Power Company, June 1995.
Contributions of the Chicago Airport System to the Chicago Regional Economy, prepared for the City of Chicago Department of Aviation, March 1993.
An Economic Analysis of the RECLAIM Trading Program for the South Coast Air Basin, prepared for the Regulatory Flexibility Group and the California Council for Environmental and Economic Balance, March 1992.
Tax Impacts of Alternative Future Airport Systems for the Chicago Region, prepared for the City of Chicago Department of Aviation, January 1992.
Economic Impacts of Alternative Airport Systems for the Chicago Region, prepared for the City of Chicago Department of Aviation, November 1991.
The Lake Calumet Airport and Chicago's Economic Future, prepared for the Lake Calumet Airport Advisory Committee, September 1991.
Updated Economic Impacts of Alternative Future Airport Systems, prepared for the City of Chicago Department of Aviation, September 1991.
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Exhibit Harrison Direct-1 David Harrison
The Impact on Ontario Hydro of Emissions Trading for Nitrogen Oxides: A Preliminary Analysis, prepared for Ontario Hydro, December 1990.
The Economic Impacts of Locating a New Airport in the Lake Calumet Area, prepared for the City of Chicago Department of Aviation, January 1990.
Economic Impacts of the Cranberry Industry in Massachusetts, prepared for The Cranberry Institute, November 1989.
Economic Impacts of Rule 1135 Proposed by the South Coast Air Quality Management District, prepared for the Southern California Utility Air Group, May 1989.
Economic Impacts of the Draft Air Quality Management Plan Proposed by the South Coast Air Quality Management District, prepared for the California Council for Environmental and Economic Balance, December 1988.
C. Air Quality
Environmental Costs and Economic Impacts of 100 MW Generic Technology/Resource Options, prepared for Sierra Pacific Power Company, September 2016.
Environmental Costs and Economic Impacts of the 2016 Integrated Resource Plan, prepared for Sierra Pacific Power Company, June 2016.
Environmental Costs and Economic Impacts of the 2015 Integrated Resource Plan, prepared for Nevada Power Company, June 2015.
EPA Regulatory Impact Analysis of Proposed Federal Ozone Standard: Potential Concerns Related to EPA Compliance Cost Estimates, prepared for National Association of Manufacturers, March 2015.
Economic Impacts of a 65 ppb National Ambient Air Quality Standard for Ozone, Executive Summary, prepared for National Association of Manufacturers, February 2015.
Assessing Economic Impacts of a Stricter National Ambient Air Quality Standard for Ozone, prepared for National Association of Manufacturers, July 2014.
Environmental Costs and Economic Impacts of the Emissions Reduction and Capacity Replacement Plan, prepared for NV Energy Inc., May 2014.
Cost-Effectiveness Analysis of Alternative Woodstove New Source Performance Standards, prepared for Hearth, Patio and Barbecue Association, May 2014.
Assessment of EPA Economic Analyses for Proposed Wood Heater New Source Performance Standards, prepared for Hearth, Patio and Barbecue Association, May 2014.
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Exhibit Harrison Direct-1 David Harrison
Cost-Effectiveness Analysis of Alternative Hydronic Heater New Source Performance Standards, prepared for Hearth, Patio and Barbecue Association, May 2014.
Environmental and Economic Impacts of the First Amendment Supplemental Filing to the 2009 Integrated Resource Plan, prepared for Nevada Power Company, October 2011.
Environmental Costs and Economic Impacts of the Second Amendment to the 2009 Integrated Resource Plan, prepared for Nevada Power Company, August 2011.
Environmental Costs and Economic Impacts of the 2010 Integrated Resource Plan, prepared for Sierra Pacific Power Company, July 2010.
Environmental Costs and Economic Impacts of the 2009 Integrated Resource Plan, prepared for Nevada Power Company, February 2010.
Economic Analysis of Proposed U.S. EPA Biocide Data Requirements, prepared for The American Chemistry Council, March 2009.
Environmental Costs and Economic Benefits of Electric Utility Resource Selection, prepared for Nevada Power Company, March 2009.
Customer Behavior in Response to the 2007 Heavy-Duty Emission Standards: Implications for the 2010 NOx Standard, prepared for Navistar International Corporation, November 2008.
Environmental Costs and Economic Benefits of Electric Utility Resource Selection, prepared for Nevada Power Company, May 2008.
Evaluation of Potential Attainment Costs and Economic Impacts under a Potential Revised EPA 8-Hour Ozone Standard, prepared for the National Association of Manufacturers, January 2008.
Evaluation of a Voluntary SO2 Trading Program for the Pulp and Paper Sector, prepared for the American Pulp and Paper Association, February 2007.
An Evaluation of Alternative Approaches to Reducing Pennsylvania Mercury Emissions, prepared for PPL Corporation, August 2006.
An Evaluation and Empirical Analysis of a National Cap-and-Trade Program to Reduce Montana Mercury Emissions, prepared for PPL Corporation, July 2006.
Environmental Costs and Economic Benefits of Electric Utility Resource Selection, prepared for Nevada Power Company, June 2006.
Economic Assessments of Alternative Emission Standards for Small Nonroad Engines, with Air Improvement Resource, Inc. and Sierra Research, Inc., prepared for Briggs and Stratton Corporation, June 2006.
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Exhibit Harrison Direct-1 David Harrison
Preliminary Sector Cost Estimates for Potential Emissions Abatement Regulation, prepared for the American Chemistry Council, January 2006.
Economic and Environmental Impacts of EPA’s 2007 Heavy-Duty Emissions Standards, prepared for the Engine Manufacturers Association, January 2005.
Evaluation of the Costs of Potential National Caps on Sulphur Dioxide Emissions and Nitrogen Oxide Emissions from Facilities in the Pulp and Paper Industry, prepared for the American Forest & Paper Association, March 2004.
Cost-Effectiveness Analyses of Alternative California Air Resources Board Tier 3 Non-Handheld Exhaust Emission Proposals, prepared for Engine Manufacturers Association and Outdoor Power Equipment Institute, September 2003.
Fleetwide Emissions and Cost-Effectiveness of the Pull-Ahead Requirements for Heavy Heavy-Duty Diesel Engines: Response to Comments Provided by ICF Consulting and Sonoma Technology, Inc., prepared for Detroit Diesel Corporation, July 2002.
Economic Assessments of Alternative Emission Standards for Snowmobile Engines, prepared for International Snowmobile Manufacturers Association, July 2002.
Fleetwide Emissions and Cost-Effectiveness of the Consent Decree Pull-Ahead Requirements for Heavy-Duty Diesel Engines, prepared for Detroit Diesel Corporation, May 2002.
Agenda for the Future: Expanding Policy Innovations to Reconcile Energy and Environmental Objectives, prepared for Edison Electric Institute, March 2001.
Impact of Alternative ZEV Sales Mandates on California Motor Vehicle Emissions: A Comprehensive Study (with Sierra Research, Inc.), prepared for the Alliance of Automobile Manufacturers and the Association of International Automobile Manufacturers, January 2001.
Impacts of the Zero Emission Vehicle Mandate on the California Economy, prepared for General Motors Corporation, January 2001.
Review of ADL and UCS Presentations to the California Air Resources Board Regarding the ZEV Mandate, prepared for the Alliance of Automobile Manufacturers and the Association of International Automobile Manufacturers, January 2001.
The Effects of Environmental Regulations on United States Nuclear Power Generation, prepared for Kansai Electric Power Company, January 2001.
Economic Assessment of the Cost-Effectiveness of Alternative MACT Standards for the Metal Coil Surface Coating Industry, prepared for National Coil Coater Association, September 2000.
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Exhibit Harrison Direct-1 David Harrison
Addendum Report: Economic Assessment of the Cost-Effectiveness of Alternative Phase 2 Regulations for Handheld Engines, prepared for Husqvarna AB, Husqvarna Forest & Garden Products Co., and Frigidaire Home Products, November 1999.
Economic Assessment of the Cost-Effectiveness of Alternative Phase 2 Regulations for Handheld Engines, prepared for Husqvarna AB, Husqvarna Forest & Garden Products Co., and Frigidaire Home Products, September 1999.
Energy-Environment Policy Integration and Coordination Study (E-EPIC) Phase 1 Executive Report (Contributor), prepared for the Electric Power Research Institute, February 1999.
Economic Analyses of Alternative California Standards for Exhaust Emissions from Marine Engines, prepared for the National Marine Manufacturers Association, October 1998.
Detailed Comments of the Alliance for Constructive Air Policy (“ACAP”) on EPA’s Supplemental Notice of Proposed Rulemaking Regarding a Model NOX Cap-and-Trade Rule, submitted by ACAP, June 1998.
Comments on EPA’s Draft Regulatory Impact Analysis: Control of Emissions from Nonroad Diesel Engines, prepared for the Equipment Manufacturers Institute, December 1997.
Economic Evaluation of Regulations on Exhaust Emissions from Large Nonroad, Compression Ignition Engines, prepared for the Engine Manufacturers Association and the Equipment Manufacturers Institute, October 1997.
Economic Evaluation of Alternative Regulations of Exhaust Emissions from Small Utility Engines, prepared for Briggs & Stratton Corporation, February 1996
The New York State Environmental Externalities Cost Study: An Overview of Key Elements and Issues, prepared for the Electric Power Research Institute, April 1995.
External Benefits from Increasing Electric Vehicles in the Los Angeles Department of Water and Power Service Territory, prepared for the Los Angeles Department of Water and Power, January 1995.
Consideration of Environmental Externality Values in Minnesota Electric Utility Resource Planning, prepared for Northern States Power Company, November 1994.
Evaluation of Phase I Standards for Small Utility Engines, prepared for Briggs & Stratton Corporation, November 1994.
Evaluation of Additional Tier I Standards for 0-25 HP Engines, prepared for Briggs & Stratton Corporation, October 1994.
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Key Issues in the Design of Emission Trading Programs to Reduce Ground-Level Ozone, prepared for Electric Power Research Institute, July 1994.
Environmental Externality Policies in New York State: Comments on the 1994 Draft State Energy Plan, prepared for the New York Power Pool, April 1994.
Environmental Considerations in Power Plant Licensing Decisions in Florida, prepared for the Center for Energy and Economic Development, April 1994.
The Benefits of Reducing Emissions of Nitrogen Oxides Under Title IV of the 1990 Clean Air Act Amendments, prepared for the U.S. Environmental Protection Agency Office of Policy, Planning and Evaluation, Air Policy Branch, March 1994.
Scoping Study for a Regional Visibility Trading Program, prepared for Electric Power Research Institute, Energy Analysis Program, February 1994.
Comments on RCG/Hagler, Bailly, Inc. Revised Draft Task 3 Methodological Report, prepared for Empire State Electric Energy Research Company, February 1994.
A Framework for the Empirical Evaluation of Externality Adders for Electric Utilities, prepared for Electric Power Research Institute, Integrated Systems Division, January 1994.
The Environmental and Economic Benefits of Electricity: Positive Externalities and Other Impacts, prepared for Electric Power Research Institute, Integrated Systems Division, December 1993.
External Costs of Electric Utility Resource Selection in Northern Nevada, prepared for Sierra Pacific Power Company with assistance from Systems Applications International, December 1993.
Economic Evaluation of Alternative Strategies for Regulating Marine Engine Emissions, prepared for the National Marine Manufacturers Association, October 1993.
Consideration of Environmental Externalities in New York Electric Utility Decisions, prepared for the New York Power Pool, October 1993.
Emissions Trading Options for Marine Engine Manufacturers, preliminary results prepared for National Marine Manufacturers Association, May 1993.
Comments on RCG/Hagler, Bailly, Inc. Draft Task 3 Methodological Report, prepared for Empire State Electric Energy Research Corporation, April 1993.
Internalization of Externalities from Electric Utility Generation in Alberta, draft prepared for TransAlta Utilities Corporation, March 1993.
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External Costs of Electric Utility Resource Selection in Nevada, prepared for Nevada Power Company, March 1993.
Valuation of Air Pollution Damages, prepared for Southern California Edison Company, March 1992.
Adding Rail, Bus and Fleet Sources to the Regional Clean Air Incentives Market (RECLAIM) Program: A Preliminary Analysis, prepared for Southern California Edison, March 1992.
Market-Based Approaches to Managing Air Emissions in Alberta, prepared for Alberta Energy, Alberta Environment and Canadian Petroleum Association, February 1991.
Using Emissions Trading to Reduce Ground-Level Ozone in Canada: A Feasibility Analysis, prepared for Environment Canada, November 1990.
Market-Based Approaches to Reduce the Cost of Clean Air in California’s South Coast Basin, prepared for California Council for Environmental and Economic Balance, November 1990.
Addressing Canada's Ozone Problem: Recommendations for a Cost-Effective Strategy for Controlling Emissions of Nitrogen Oxides and Volatile Organic Compounds, prepared for TransAlta Utilities Corporation and submitted to the Federal/Provincial Long Range Transport of Air Pollutants Steering Committee, April 1990.
Benefits of the 1989 Air Quality Management Plan for the South Coast Air Basin: A Reassessment, prepared for the California Council for Environmental and Economic Balance, March 1990.
Preliminary Comments on Economic Assessment of the Health Benefits from Improvements in Air Quality in the South Coast Air Basin, prepared for California Council for Environmental and Economic Balance, August 1989.
“Response to ‘Review of CCEEB-NERA Study’ Concerning the Economic Impacts of the Draft Air Quality Management Plan,” prepared for the California Council for Environmental and Economic Balance, submitted to the South Coast Air Quality Management District, March 1989.
Comments on the Draft 1988 Air Quality Management Plan and the Draft Environmental Impact Report Issued by the South Coast Air Quality Management District in September 1988, prepared for the California Council for Environmental and Economic Balance, submitted to the South Coast Air Quality Management District, October 1988.
D. Water Quality
Economic Costs of Entrainment Reduction Technologies at B.L. England Generating Station, prepared for AKRF, Inc., January 2018.
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Exhibit Harrison Direct-1 David Harrison
Economic Benefits of Entrainment Reduction Technologies at B.L. England Generating Station, prepared for AKRF, Inc., January 2018.
Economic Evaluation of Two Entrainment Reduction Technologies at Merrimack Station, prepared for Public Service Company of New Hampshire (PSNH), December 2017.
Non-use Benefits of Entrainment Reduction Technologies at B.L. England Generating Station, prepared for AKRF, Inc., October 2017.
Benefit-Cost Analysis of Plume-abated Mechanical Draft Cooling Towers. Chapter 5 in ADDENDUM to the Comprehensive Evaluation of Cooling Water System Alternatives at Millstone Power Station (MPS), prepared for Dominion Energy, April 2017.
Economic Analyses of Alternative Technologies and Operational Measures Related to 316(b) Regulation at Millstone Power Station (MPS). Contributions to Chapter 10 and Chapter 11 of 40 CFR 122.21(r) Submittals for MPS, prepared for Dominion Energy, April 2017.
Economic Analyses of Permanent Mandatory Summertime Outages at IPEC, prepared for Entergy Nuclear Indian Point 2, LLC, and Entergy Indian Point 3, LLC, June 2015.
Economic Costs of Technologies to Reduce Impingement and Entrainment at Bridgeport Harbor Station, prepared for Public Service Enterprise Group (PSEG), March, 2015.
Economic Benefits of Technologies to Reduce Impingement and Entrainment at Bridgeport Harbor Station, prepared for Public Service Enterprise Group (PSEG), March, 2015.
Cost-Effectiveness Analysis of Scrubber Wastewater Alternatives at Merrimack Station, prepared for Public Service of New Hampshire, October 2014.
Impacts to the New York State Electricity System if Indian Point Energy Center Were Not Available, prepared for Entergy Nuclear Indian Point 2, LLC, and Entergy Indian Point 3, LLC, December 2013.
Benefits and Costs of Cylindrical Wedgewire Screens and Cooling Towers at IPEC, Prepared for Entergy Nuclear Indian Point 2, LLC and Entergy Nuclear Indian Point 3, LLC, December 2013.
Wholly Disproportionate” Assessments of Cylindrical Wedgewire Screens and Cooling Towers at IPEC, prepared for Entergy Nuclear Indian Point 2, LLC and Entergy Nuclear Indian Point 3, LLC, December 2013.
Cost-Effectiveness Analyses of EPA’s Proposed Effluent Limitations Guidelines and Standards for Steam Electric Power Plants, prepared for Utility Water Act Group, September 2013.
EPA Proposed Effluent Guidelines: Compliance Costs, Electricity Sector Costs and Coal Retirements, prepared for the American Coalition for Clean Coal Electricity, September 2013.
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Exhibit Harrison Direct-1 David Harrison
Benefits and Costs of Cylindrical Wedgewire Screens at Indian Point Energy Center, prepared for Entergy Nuclear Indian Point 2, LLC and Entergy Nuclear Indian Point 3, LLC, March 2013.
Benefit-Cost Analysis of Alternative Technologies and Operational Measures. Chapter 9 in Comprehensive Evaluation of Cooling Water System Alternatives at Millstone Power Station (MPS), prepared for Dominion Resource Services, Inc., August 15, 2012.
Comments on EPA’s Notice of Data Availability for §316(b) Stated Preference Survey, prepared for Utility Water Act Group and Edison Electric Institute, July 2012.
Potential Energy and Environmental Impacts of Denying Indian Point’s License Renewal Applications, prepared for Entergy Nuclear Operations Inc., March 2012.
Preliminary Economic Analysis of Cooling Water Intake Alternatives at Merrimack Station, prepared for Public Service of New Hampshire, February 2012.
Comments on Economic Issues Related to EPA’s Proposed Regulations for Cooling Water Intake Structures at Existing Facilities, prepared for Utility Water Act Group, August 2011.
Cost-Benefit Comparisons of Fish-Protection Alternatives for AES Cayuga, prepared for AES Corporation, January 2011.
Comments on EPA’s Proposed Survey to Estimate the Potential Benefits of Alternative Cooling Water Intake Policies, prepared for American Chemistry Council, American Forest & Paper Association, American Petroleum Institute, and Utility Water Act Group, September 2010.
Cost-Benefit Analysis for Fish Impingement and Entrainment Reduction at Pickering Nuclear Generating Station, prepared for Ontario Power Generation, Inc., December 2009.
Preliminary Costs and Benefits of Cooling Water Intake Alternatives for Mandalay and Ormond Beach Generating Stations, prepared for RRI Energy, Inc., September 2009.
Preliminary Costs and Benefits of California Draft Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling, prepared for California Council for Environmental and Economic Balance, September 2009.
Economic Assessment of Installing Wedgewire Screens at Point Beach Nuclear Power Station, prepared for Florida Power & Light Point Beach Nuclear Station, February 2009.
AES Somerset Generating Station Comprehensive Biological Requirements and Technical Review Report, prepared for AES Somerset LLC, January 2009.
Economic Assessment of Fish-Protective Alternatives at Pilgrim Nuclear Power Station, prepared for Entergy Nuclear Generation Company, June 2008.
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Exhibit Harrison Direct-1 David Harrison
Social Costs of Alternative Cooling Procedures at Vermont Yankee Nuclear Power Station, prepared for Entergy Nuclear Vermont Yankee LLC, February 2007.
Assessment of Alternative Intake Technologies: Costs and Benefits of Fish Protection Alternatives at the Salem Facility, prepared for Public Service Electric & Gas Incorporated, January 2006.
White Paper on the Use of Benefit-Cost Analysis in Site-Specific 316(b) Decisions Under the Clean Water Act, prepared for PSEG and Entergy, May 2003.
Valuation of Power Costs in Assessing the Costs of Alternatives Under Section 316(b) of the Clean Water Act, prepared for Edison Electric Institute, August 2002.
Economic Evaluation of the Habitat Replacement Cost Methodology in the U.S. EPA’s 316(b) Benefits Case Study for Pilgrim Station, prepared for Entergy Nuclear Generating Company, August 2002.
Economic Evaluation of the Delaware Estuary Case Study in the U.S. EPA’s 316(b) Existing Facilities Benefits Case Studies, prepared for Public Service Electric and Gas Company, August 2002.
Mercer Generating Station Supplemental 316(b) Report, prepared for Public Service Electric and Gas Company, December 2000.
Economic Evaluation of EPA’s Proposed Rules for Cooling Water Intake Structures for New Facilities, prepared for Utilities Water Act Group, November 2000.
Costs and Benefits of Fish Protection Alternatives at the Salem Facility, prepared for Public Service Electric and Gas Company, March 1999.
Costs and Benefits of Alternatives for Modifying Cooling Water Intake at the Hudson Facility, prepared for Public Service Electric and Gas Company, November 1998.
E. Transportation and Other Infrastructure
Forecasts of Transit Indices for the Indiana Toll Road Based on the CPI and Nominal GDP per Capita, prepared for potential bidder, December 2005.
Socioeconomic Forecasts for the Indiana Toll Road Service Area and the U.S., prepared for potential bidder, December 2005.
Values for Wetlands and Recreational Open Space Relevant to the Harrison, New Jersey Waterfront Site, prepared for AKRF, Inc., October 2005.
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Exhibit Harrison Direct-1 David Harrison
Fueling Electricity Growth for a Growing Economy, prepared for Edison Electric Institute, January 2001.
Prospects for the U.S. Nuclear Industry, prepared for Kansai Electric Power Company, January 2001.
Potential Impacts of Environmental Regulations on Diesel Fuel Prices: Evaluation of An Assessment of the Potential Impacts of Proposed Environmental Regulations on U.S. Refinery Supply of Diesel Fuel, prepared for American Petroleum Institute, August 2000, prepared for the Alliance of Automobile Manufacturers, December 2000.
Evaluation of the Economic Analysis of the Bureau of Land Management’s Proposed Regulations on Hardrock Mining, prepared for National Mining Association, July 2000.
Evaluation of the Economic Analysis of the U.S. Forest Service Proposed Rule on Roadless Area Conservation, prepared for the National Mining Association, July 2000.
Benefits and Costs of Underground Conversion of Overhead Distribution Lines in New York State, prepared for New York Electric Utilities, July 1994.
Potential Impacts of the Clean Harbors Proposed Rotary Kiln Incinerator on Aesthetics, Recreation, Tourism and Property Values, prepared for Clean Harbors, Inc., June 1989.
Airport Congestion in the United States, prepared for the UK Department of Transport, May 1989.
III. Testimony in Regulatory and Judicial Proceedings
Before the Public Utilities Commission of Nevada, Prepared Direct Testimony of David Harrison, Jr. in Response to Procedural Order 1, on behalf of Sierra Pacific Power Company d/b/a NV Energy, Wednesday, November 30, 2016.
Before the Public Utilities Commission of Nevada, 2016 General Rate Case, Prepared Rebuttal Testimony of David Harrison, Jr. on behalf of Sierra Pacific Power Company d/b/a NV Energy, November 14, 2016.
Before the Public Utilities Commission of Nevada, 2016 Integrated Resource Plan, Prepared Direct Testimony of David Harrison, Jr. on behalf of Nevada Power Company d/b/a NV Energy, October 24, 2016.
Before the Public Utilities Commission of Ohio, Direct Testimony of David Harrison on behalf of the Dayton Power and Light Company, February 22, 2016.
Before the State of New York Department of Environmental Conservation, Combined Prefiled Rebuttal of David Harrison, Jr., Ph.D, and Eugene Meehan on behalf of Entergy Nuclear Indian
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Point 2, LLC, Entergy Nuclear Indian Point 3, LLC, and Entergy Nuclear Operations, Inc., August 10, 2015.
Before the State of New York Department of Environmental Conservation, Combined Pre-filed Testimony of David Harrison, Jr., Ph.D, and Eugene Meehan on behalf of Entergy Nuclear Indian Point 2, LLC, Entergy Nuclear Indian Point 3, LLC, and Entergy Nuclear Operations, Inc., June 26, 2015.
Before the Public Utilities Commission of Nevada, 2015 Integrated Resource Plan, Prepared Direct Testimony of David Harrison, Jr. on behalf of Nevada Power Company d/b/a NV Energy, June 23, 2015.
Declaration of David Harrison, Jr., Regarding the Likely Impacts of Retiring SO2 Allowances under the Cross-State Air Pollution Rule, prepared on behalf of Westvaco Corporation, June 12, 2015.
Before the United States House of Representatives, Committee on Oversight and Government Reform, Prepared Statement of David Harrison, Jr. at a Hearing on Impacts of U.S. Environmental Protection Agency Regulations, Washington, DC, February 26, 2015.
Before the Public Utilities Commission of Nevada, 2014 Emissions Reduction and Capacity Replacement Plan, Prepared Direct Rebuttal of David Harrison, Jr. on behalf of Nevada Power Company d/b/a NV Energy, September 6, 2014.
Before the New Hampshire Public Utilities Commission, Prepared Direct Testimony of David Harrison Jr. and Noah Kaufman, Docket No. DE 11-250. Public Service Company of New Hampshire. Investigation of Merrimack Station Scrubber Project and Cost Recovery. Submitted on behalf of Public Service of New Hampshire, July 11, 2014.
Before the Public Utilities Commission of Nevada, 2014 Emissions Reduction and Capacity Replacement Plan, Prepared Direct Testimony of David Harrison, Jr. on behalf of Nevada Power Company d/b/a NV Energy, May 1, 2014.
Before the State of New York Department of Environmental Conservation, Rebuttal Testimony of David Harrison, Jr. on behalf of Entergy Nuclear Indian Point 2, LLC, Entergy Nuclear Indian Point 3, LLC, and Entergy Nuclear Operations, Inc., March 28, 2014.
Before the State of New York Department of Environmental Conservation, Pre-filed Testimony of David Harrison, Jr. on behalf of Entergy Nuclear Indian Point 2, LLC, Entergy Nuclear Indian Point 3, LLC, and Entergy Nuclear Operations, Inc., February 28, 2014.
Before the Public Utilities Commission of Nevada, 2nd Amendment to the 2010 Integrated Resource Plan, Pre-filed Direct Testimony of David Harrison, Jr. on behalf of Sierra Pacific Power Company, August 7, 2012.
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Before the Public Utilities Commission of Nevada, 2013-2032 Integrated Resource Plan, Pre-filed Direct Testimony of David Harrison, Jr. on behalf of Nevada Power Company, June 21, 2012.
Before the United States of America Nuclear Regulatory Commission, before the Atomic Safety and Licensing Board, Testimony of David Harrison Jr. on Contention NYS-37 on behalf of Entergy Nuclear Operations, Inc., March 30, 2012.
Before the Public Utilities Commission of Nevada, Eleventh Amendment to its 2010-2029 Integrated Resource Plan, Pre-filed Direct Testimony of David Harrison, Jr. on behalf of Nevada Power Company, February 1, 2010.
Before the Public Utilities Commission of Nevada, Eleventh Amendment to its 2007-2026 Integrated Resource Plan, Pre-filed Direct Testimony of David Harrison, Jr. on behalf of Nevada Power Company, March 3, 2009.
Before the Public Utilities Commission of Nevada, Eighth Amendment to the 2006 - 2025 Integrated Resource Plan, Pre-filed Rebuttal Testimony of David Harrison, Jr. on behalf of Nevada Power Company, August 26, 2008.
Brief of Amicus Curiae the AEI Center for Regulatory and Market Studies and 33 Individual Economists in Support of Petitioners, submitted to the Supreme Court of the United States. Entergy Corp, PSEG Fossil LLC and PSEG Nuclear LLC, and the Utility Water Act Group, petitioners, v. Riverkeeper Inc. et al., respondents, on writs of certiorari to the United States Court of Appeals for the Second Circuit. July 21, 2008.
Affidavit of David Harrison, Jr., Ph.D., on behalf of AES and Dynegy, Regarding New York State Department Of Environmental Conservation’s Proposed 6 NYCRR Part 242, CO2 Budget Trading Program, Revisions To 6 NYCRR Part 200, June 16, 2008.
Before the Public Utilities Commission of Nevada, Eighth Amendment to the 2007 - 2026 Integrated Resource Plan, Pre-filed Direct Testimony of David Harrison, Jr. on behalf of Nevada Power Company, May 16, 2008.
Before the Public Utilities Commission of Nevada, Seventh Amendment to the 2006 Integrated Resource Plan, Pre-filed Direct Testimony of David Harrison, Jr. on behalf of Nevada Power Company, March 15, 2008.
Affidavit of David Harrison, Jr., Ph.D. in support of Public Service Company of New Hampshire’s comments on Department of Environmental Service’s Preliminary Responses to Requests for Bonus Carbon Dioxide and Nitrogen Oxides Allowances Pursuant to RSA 125-O and Env-A, September 12, 2007.
Prefiled Testimony of David Harrison, Jr., Ph.D. in support of Entergy Nuclear Vermont Yankee, LLC, on behalf of Entergy Nuclear Vermont Yankee LLC, June 22, 2007.
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Before the Public Utilities Commission of Nevada, Application for Approval of the 2008 – 2027 Integrated Resource Plan, Pre-filed Direct Testimony of David Harrison, Jr. on behalf of Sierra Pacific Power Company, June 20, 2007.
Direct Testimony of David Harrison, Jr., Ph.D., in the Matter of Green Mountain Chrysler Plymouth Dodge Jeep, et al v. Thomas W. Torti, et al (Case No. 05-cv-302), on behalf of Plaintiffs, April 19, 2007, before Hon. William K. Sessions III, Vermont District Court, Burlington, VT.
Affidavit of David Harrison, Jr., Ph.D. in support of Entergy Nuclear Vermont Yankee, LLC’s Opposition to Motions to Renew Stay, on behalf of Entergy Nuclear Vermont Yankee LLC, February 27, 2007.
Rebuttal Testimony of David Harrison, Jr., Ph.D., in the Matter of Green Mountain Chrysler Plymouth Dodge Jeep, et al v. Thomas W. Torti, et al (Case No. 05-cv-302), on behalf of Plaintiffs, October 9, 2006.
Supplemental Testimony of David Harrison, Jr., Ph.D., in the Matter of Central Valley Chrysler Jeep, Inc. et al. v. Witherspoon, on behalf of Plaintiffs, October 9, 2006.
Before the Public Utilities Commission of Nevada, Application for Approval of the Thirteenth Amendment to the 2005 – 2024 Integrated Resource Plan, Environmental Costs and Economic Benefits of Proposed Expansion Plans, Direct Testimony of David Harrison, Jr. on behalf of Nevada Power Company and Sierra Pacific Power Company, October 3, 2006.
Before the Public Utilities Commission of Nevada, Application for Approval of the 2007-2026 Integrated Resource Plan, Rebuttal Testimony of David Harrison, Jr. on behalf of Nevada Power Company, Sept 20, 2006.
Before the Public Utilities Commission of Nevada, Application for Approval of the 2007-2026 Integrated Resource Plan, Supplemental Testimony of David Harrison, Jr. on behalf of Nevada Power Company, Sept 8, 2006.
Before the Public Utilities Commission of Nevada, Application for Approval of the Thirteenth Amendment to the 2005 – 2024 Integrated Resource Plan, Environmental Costs and Economic Benefits of Proposed Expansion Plans, Pre-filed Direct Testimony of David Harrison, Jr. on behalf of Sierra Pacific Power Company, July 14, 2006.
Before the Public Utilities Commission of Nevada, Application for Approval of the 2007 – 2026 Integrated Resource Plan, Environmental Costs and Economic Benefits of Proposed Expansion Plans, Pre-filed Direct Testimony of David Harrison, Jr. on behalf of Nevada Power Company, Docket No. 06-06051, June 30, 2006.
Rebuttal Testimony of David Harrison, Jr., Ph.D., in the Matter of Central Valley Chrysler Jeep, Inc. et al. v. Witherspoon, on behalf of Plaintiffs, June 12, 2006.
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Testimony of David Harrison, Jr., Ph.D., in the Matter of Green Mountain Chrysler Plymouth Dodge Jeep, et al v. Thomas W. Torti, et al (Case No. 05-cv-302), on behalf of Plaintiffs, May 18, 2006.
Testimony of David Harrison, Jr., Ph.D., in the Matter of Central Valley Chrysler Jeep, Inc. et al. v. Witherspoon, on behalf of Plaintiffs, May 2, 2006.
Rebuttal Testimony of David Harrison, Jr., Ph.D., in the Matter of the Renewal/Modification of the State Pollution Discharge Elimination System Permit of Dynegy Danskammer Generation Station, on behalf of Dynegy Northeast Generation, Inc., November 7, 2005.
Direct Testimony of David Harrison, Jr., Ph.D., in the Matter of the Renewal/Modification of the State Pollution Discharge Elimination System Permit of Dynegy Danskammer Generation Station, on behalf of Dynegy Northeast Generation, Inc., October 17, 2005.
Prepared Direct Testimony of David Harrison, Jr., Ph.D., on Behalf of the American Electric Power System. In the Matter of the American Electric Power Company, Inc.: File No. 3-11616. December 7, 2004.
Testimony of David Harrison, Jr., in the Matter of the Arbitration Between BASF Corp., Claimant, and Albaugh, Respondent, prepared on behalf of BASF, February 22, 2002.
Affidavit of David Harrison, Jr., on behalf of PSEG Power New York, Inc., Regarding an Application for a Certificate of Environmental Compatibility and Public Need to Construct and Operate a 750 Megawatt Natural Gas-Fired Combined Cycle, Combustion Turbine Generating Facility in the Town of Bethlehem, Albany County, November 30, 2001.
Second Declaration of David Harrison, Jr., in Response to Notice of Availability of Modified Text and Supporting Documents and Information Released on October 31, 2001, prepared on behalf of General Motors, November 2001.
Declaration of David Harrison, Jr., Regarding the Environmental Disbenefits of the California Zero Emission Vehicle Mandate, prepared on behalf of General Motors Corporation, January 2001.
Oral testimony on behalf of plaintiff Stewart Hutchings, et al vs. Connecticut Department of Economic and Community Development and Office of Policy and Management, Superior Court J. D. of Hartford, March 20, 2000.
Supplemental Report Relating to Damages Incurred to Investigate and Remediate the Bound Brook, New Jersey Site on behalf of Cyanamid Co., et al. V. The Aetna Casualty & Surety Co., et al., Civil Action No. PAS-L-8275-91 (NJ Super. Ct. Law Div), December 3, 1999.
Assessment of Economic Values Associated with Alternative Hydrocarbon Emissions Scenarios, prepared on behalf of Toyota Motor Corporation, in the Matter of the Accusation Against Toyota
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Motor Corporation (MY 1996-1998 Passenger Cars and Light-Duty Trucks with Evaporative Leak Check Diagnostic Systems) Before the California Air Resources Board, Case No. 519, August 30, 1999.
Affidavit of David Harrison, Jr. on behalf of Tecumseh Products Company regarding remedy proposed by EPA Region V for the Sheboygan River and Harbor Site, August 1999.
Reply Comments Submitted to DOT in Response to Advance Notice of Proposed Policy Regarding Airport Rates and Charges, Docket No. 29303, prepared on behalf of the Airport Council International-North America, March 1, 1999.
Airports and Competition: Comments Submitted to DOT Request for Comments on Policy Statement, prepared on behalf of the Airport Council International-North America in response to Advance Notice of Proposed Policy Regarding Airport Rates and Charges, Docket No. 29303, February 1, 1999.
Rebuttal Report of Plaintiff’s Expert in American Cyanamid Co. et al. v. The Aetna Casualty & Surety Co., et al., Civil Action No. PAS-L-8275-91 (N.J. Superior Court Law Division), “Relating to Damages Incurred to Investigate and Remediate the Piney River, Virginia Site,” December 21, 1998.
Rebuttal Report of Plaintiff’s Expert in American Cyanamid Co. et al. v. The Aetna Casualty & Surety Co., et al., Civil Action No. PAS-L-8275-91 (N.J. Superior Court Law Division), “Relating to Damages Incurred to Investigate and Remediate the Nascolite Site, Cumberland County, New Jersey,” December 21, 1998.
Report of Plaintiff’s Expert in American Cyanamid Co. et al. v. The Aetna Casualty & Surety Co., et al., Civil Action No. PAS-L-8275-91 (N.J. Superior Court Law Division), “Relating to Damages Incurred to Investigate and Remediate the Piney River, Virginia Site,” October 28, 1998.
Report of Plaintiff’s Expert in American Cyanamid Co. et al. v. The Aetna Casualty & Surety Co., et al., Civil Action No. PAS-L-8275-91 (N.J. Superior Court Law Division), “Relating to Damages Incurred to Investigate and Remediate the Nascolite Site, Cumberland County, New Jersey,” October 28, 1998.
Rebuttal Report of Plaintiff’s Expert in American Cyanamid Co. et al. v. The Aetna Casualty & Surety Co., et al., Civil Action No. PAS-L-8275-91 (N.J. Superior Court Law Division), “Relating to Damages Incurred to Investigate and Remediate the Wallingford, Connecticut Site,” October 9, 1998.
Rebuttal Report of Plaintiff’s Expert in American Cyanamid Co. et al. v. The Aetna Casualty & Surety Co., et al., Civil Action No. PAS-L-8275-91 (N.J. Superior Court Law Division), “Relating to Damages Incurred to Investigate and Remediate the Bound Brook, New Jersey Site,” September 16, 1998.
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Report of Plaintiff’s Expert in American Cyanamid Co. et al. v. The Aetna Casualty & Surety Co., et al., Civil Action No. PAS-L-8275-91 (N.J. Superior Court Law Division), “Relating to Damages Incurred to Investigate and Remediate the Wallingford, Connecticut Site,” August 4, 1998.
Report of Plaintiff’s Expert in American Cyanamid Co. et al. v. The Aetna Casualty & Surety Co., et al., Civil Action No. PAS-L-8275-91 (N.J. Superior Court Law Division), “Relating to Damages Incurred to Investigate and Remediate the Bound Brook, New Jersey Site,” July 16, 1998.
Affidavit on Behalf of Briggs & Stratton Corporation, Petition for Alternative Emission Standards for Small (0-25 hp) Gasoline Powered Engines, submitted to the California Air Resources Board, July 1995.
Before the Minnesota Public Utilities Commission, Considerations in the Development of Externality Values for Greenhouse Gas Emissions, surrebuttal testimony prepared on behalf of Northern States Power Company In the Matter of the Establishment of Environmental Cost Values, Docket No. E-999/CI-93-583, April 1995.
Before the Minnesota Public Utilities Commission, Considerations in the Development of Externality Values, rebuttal testimony prepared on behalf of Northern States Power Company In the Matter of the Establishment of Environmental Cost Values, Docket No. E-999/CI-93-583, March 1995.
Before the Public Service Commission of Nevada, Environmental Externality Cost Values, prepared testimony on behalf of Nevada Power Company, Docket No. 94-7001, February 1995.
Before the Minnesota Public Utilities Commission, Considerations in the Development of Externality Values, direct testimony on behalf of Northern States Power Company In the Matter of the Establishment of Environmental Cost Values, Docket No. E-999/CI-93-583, November 1994.
Before the Public Utilities Commission of the State of California, External Benefits from Increasing Electric Vehicles in the Southern California Edison Service Territory, testimony prepared on behalf of Southern California Edison Company In the Matter of the Order Instituting Investigation and Order Instituting Rulemaking to Develop Rules, Procedures, and Policies Governing Utility Involvement in the Market for Low-Emissions Vehicles, October 1993.
Before the Public Utilities Commission of the State of California, External Benefits from Increasing Electric Vehicles in the Pacific Gas & Electric Service Territory, testimony prepared on behalf of Pacific Gas & Electric Company In the Matter of the Order Instituting Investigation and Order Instituting Rulemaking to Develop Rules, Procedures, and Policies Governing Utility Involvement in the Market for Low-Emissions Vehicles, October 1993.
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Before the Public Utilities Commission of the State of California, External Benefits from Increasing Electric Vehicles in the San Diego Gas & Electric Service Territory, testimony prepared on behalf of San Diego Gas & Electric Company In the Matter of the Order Instituting Investigation and Order Instituting Rulemaking to Develop Rules, Procedures, and Policies Governing Utility Involvement in the Market for Low-Emissions Vehicles, October 1993.
Affidavit on the Economic Impacts of Chicago Area Airports on the Chicago Regional Economy, prepared on behalf of The City of Chicago in the People of the State of Illinois et al. v. The City of Chicago et al., in the Circuit Court for the Eighteenth Judicial Circuit, DuPage County, Wheaton, Illinois, December 1992.
Before the Public Utilities Commission of the State of California, Air Quality Issues and Disaggregation of LEV Benefits by Rate Class, rebuttal testimony prepared on behalf of Southern California Edison Company in the Matter of the Order Instituting Investigation and Order Instituting Rulemaking to Develop Rules, Procedures, and Policies Governing Utility Involvement in the Market for Low-Emissions Vehicles, Docket Nos. I.91-10-029 and R.91-10-028, August 1992.
Before the California Energy Commission ER-92 Hearing on Valuing Air Quality Impacts of Energy Resources, Revised Damage-Based Values for Residual Emissions Valuation, (with M. B. Deming), testimony prepared on behalf of Southern California Edison Company, Sacramento, California, May 1992.
Before the State of California Energy Resources Conservation and Development Commission, Valuing Air Quality Impacts of Alternative Energy Resources, testimony prepared on behalf of Southern California Edison Company, Docket No. 90-ER-2, March 1992.
Before the California Energy Commission ER-92, Group I Hearing Issues: Air Quality, (with Southern California Edison), 1992 Electricity Report, testimony prepared on behalf of Southern California Edison Company, Docket No. 90-ER-92, submitted by Southern California Edison, November 1991.
Affidavit on Landing Fees at Logan International Airport, prepared on behalf of the defendant in New England Legal Foundation, et al. v. Massachusetts Port Authority and National Business Aircraft Association, Inc., et al., United States District Court, District of Massachusetts, June 1988. (Also submitted to the U.S. Department of Transportation.)
Defendant’s Expert Witness Disclosure on Summary of Damages Claimed by the State of Michigan for Fish Killed by the Luddington Pumped Storage Plant, prepared on behalf of Consumers Power Company and The Detroit Edison Company in Frank J. Kelley, ex rel Michigan Natural Resources Commission; Michigan Department of Natural Resources; and Gordon Guyer, Director of the Michigan Department of Natural Resources v. Consumers Power Company and The Detroit Edison Company, Case No. 86-57075-CE in the Circuit Court for the County of Ingham, June 1988.
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IV. Presentations
A. Climate Change
“Energy and Economic Impacts of the Clean Power Plan”, presented to the American Coalition for Clean Coal Electricity, November 2015.
“A Carbon Dioxide Standard for Existing Power Plants: Impacts of the NRDC Proposal”, presented to the American Coalition for Clean Coal Electricity, March 2014.
“Offsets in Potential EPA GHG Tradable Performance Standard for Existing Power Plants: Preliminary Assessment,” Presentation to the Electric Power Research Institute Environment & Renewable Program Advisory Meeting, Kansas City, Missouri, September 24, 2013.
“The Interactions of Complementary Policies with a GHG Cap-and-Trade Program: The Case of Europe,” presentation at the EPRI-IETA Joint Symposium, San Francisco, April 16, 2013.
“Incentives for International Sectoral Crediting Mechanisms,” presented at the Workshop on New Market Mechanisms organized by the International Emissions Trading Association and Enel S.p.A., Brussels, October 13, 2011.
“The Copenhagen Conference: International Climate Policy and Implications for US Policy,” presented at the Fenway Colleges Climate Change Teach-In, Washington, DC, February 25, 2010.
“U.S. Greenhouse Gas Cap-and-Trade Programs and Cost Containment,” presented at the EUEC 2010 Energy & Environment Conference, AZ, Phoenix, February 1, 2010.
“Financial Implications of a US Cap-and-Trade Program for Sectors and Companies,” presented at 2nd Annual Carbon Trading Summit, New York City, January 13, 2010.
“Lessons Learned from the European Union Emissions Trading Scheme,” presented to California State Senate Select Committee on Climate Change and AB 32 Implementation, Sacramento, CA, January 7, 2010.
“Greenhouse Gas Emissions Cap-and-Trade Program: Key Design Elements,” presented at the IETA Fall 2009 Symposium, Washington, DC, November 3, 2009.
“Compliance Flexibility in Domestic Greenhouse Gas Cap-and-Trade Programs,” presented to the 9th Annual Workshop on Greenhouse Gas Emissions Trading sponsored by the Electric Power Research Institute, the International Energy Agency, and the International Emissions Trading Association, Paris, September 14, 2009.
“Allocation Decisions in the European Union Emissions Trading Scheme,” presented to the California Economic and Allocation Advisory Committee, July 1, 2009.
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“Economic Analysis of Waxman-Markey Climate Bill (ACES),” presented as part of Environmental Markets Association Webinar, June 4, 2009.
“Climate Policy Risks for Electric Utilities: Economic Modeling to Assist Utilities in Responding to Climate Change Programs,” presented at the Utility Rate Case Conference organized by Law Seminars International, Las Vegas, NV, February 6, 2009.
“Cost-Containment in a U.S. Greenhouse Gas Cap-and-Trade Program,” presented at the EEI Fall 2008 Legal Conference, Boston, October 30, 2008.
“Climate Change and Electricity Prices: What Should Electricity Companies Do,” presented at the EUCI Conference on Electricity, Chicago, September 30, 2008.
“The EU Energy and Climate Package: Interactions between EU Policies and Targets and Implications for CO2 Price Uncertainty,” presented at the IEA/IETA/EPRI 8th Annual Workshop on Greenhouse Gas Emissions Trading, Paris, September 23, 2008.
“European Union Emissions Trading Scheme: Overview and Implications for the U.S.,” presented at the Second Carbon Trading Summit, New York, NY, June 24, 2008.
“Carbon Emissions Trading and Allocation: Complexities of Policy Choices,” presented at the IETA/AIGN Workshop, Canberra, Australia, March 5, 2008.
“Climate Change: What Every Company Should Do to Get Ready for a Mandatory Emissions Trading Program,” presented at NERA Economic Consulting Workshop, Sydney, Australia, March 4, 2008.
“Workshop on Carbon Emissions Trading: EU and US Experience and Implications for IP/Australia,” presented before International Power, Melbourne, Australia, March 3, 2008.
“Design Elements for Potential Canadian GHG Cap-and-Trade Program,” presented at the Cap and Trade Working Group Retreat, Toronto, Ontario, January 31, 2008.
“Allocation in the EU ETS: What Have We Learned?” presented at the MIT workshop on EU ETS, Washington, DC, January 24, 2008.
“Emissions Trading: Background, Prior Programs and Implications for a U.S. Carbon Cap-and-Trade Program,” presented at ALI-ABA Course on Clean Air: Law, Policy and Practice, Washington, DC, November 9, 2007.
“Overview of the European Union Emissions Trading Scheme for Carbon Dioxide,” presented at EEI’s 2007 Fall Legal Conference, Napa, California, October 4, 2007.
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“Evaluating the Financial Impacts of Potential Carbon Cap-and-Trade Programs on Electricity Companies: What Every Electricity Company Should Do to Get Ready for Mandatory Climate Change Policy,” presented at the Carbon Constraint Conference, Chicago, September 13, 2007.
“EU ETS Allocation Options: Reconciling Complexities and Simplicity/Transparency,” presented before the IETA-CEPS Climate Change Conference, Brussels, Belgium, June 26, 2007.
“Overview of Allocation Methodologies and Principles,” presented before the European Climate Change Programme working group on emissions trading, Brussels, Belgium, May 21, 2007.
“Allocation Choices for a Carbon Trading Program,” presented at the Carbon Expo, Cologne, Germany, May 3, 2007.
“Allocation Choices and International Considerations,” presented to Senate staff members, Washington, DC, February 2, 2007.
“Carbon Financial Analyses for Electricity Companies,” presented at the Electric Utilities Environmental Conference, Tucson, Arizona, January 23, 2007.
“Carbon Emissions and State Electric Utility Regulation,” presented at the Electric Utilities Environmental Conference, Tucson, Arizona, January 22, 2007.
“European Union Emissions Trading Scheme for Carbon Dioxide: Lessons and Implications,” presented at North America and The Carbon Markets Conference hosted by Point Carbon and Pew Center on Global Climate Change, Washington, DC, January 18, 2007.
“Policy Design Side By Side: What Elements Matter,” presented at North America and the Carbon Markets Conference hosted by Point Carbon and Pew Center on Global Climate Change, Washington, DC, January 17, 2007.
“European Union,” presented at North America and the Carbon Markets Conference hosted by Point Carbon and Pew Center on Global Climate Change, Washington, DC, January 17, 2007.
“Carbon Markets, Linking, and Cost Containment,” presented at the IEA/IETA/EPRI 6th Annual Emissions Trading Workshop, Paris, France, September 27, 2006.
“Auctioning Experience in Other Sectors and Implications for Designing a Carbon Auction,” presented at the IETA Workshop on Allocation Methodologies, Paris, France, September 25, 2006.
“European Carbon Markets and Implications for a US Carbon Constrained Future,” presented at Preparing for a Carbon Constrained Future Conference hosted by Electric Utility Consultants, Inc., Arlington, Virginia, June 28, 2006.
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“Overview of the European Union Emissions Trading Scheme,” presented to staff of the Senate Committee on Energy and Natural Resources, Washington, DC, June 16, 2006.
“Policies to Address Potential EU ETS Impacts on Power Prices and Industrial Competitiveness,” presented at the CEPS/IETA Climate Change Conference, Brussels, Belgium, May 30, 2006.
“Learning from Experience: First Year of the European CO2 Emissions Trading Scheme,” presented to New Prospects for Climate Change Regulation Panel organized by Harvard Law School, March 10, 2006.
“Carbon Policies and Electric Utility Rate Cases,” presented at the Managing the Modern Utility Rate Case Conference organized by Law Seminars International, Las Vegas, NV, February 14, 2006.
“Beyond Cost: Carbon Markets, Electricity Prices and ‘Windfall Profits,’” presented to Electric Utilities Environmental Conference, Tucson, AZ, January 23, 2006.
“European CO2 Emissions Trading Scheme: First Year Accomplishments and Implications,” presented at an International Emissions Trading Association side event at the 11th Conference of the Parties to the Kyoto Protocol, Montreal, December 5, 2005.
“Allocation Choices for a U.S. Carbon Dioxide Emissions Trading Scheme,” presented to National Commission on Energy Policy, Workshop on Allowance Allocation, Washington, DC, September 30, 2005.
“Carbon Markets, Electricity Prices and Windfall Profits: Emerging Information on the European Union Emissions Trading Scheme” presented to IEA-IETA-EPRI Emissions Trading Workshop, Paris, September 27, 2005.
“U.S. State-level Climate Regimes: Lessons from the U.S. and Europe, presented to Fourth Annual Green Trading Summit, New York, NY, May 2, 2005.
“Overview of Allocation Choices: Alternatives and Implications,” presented to Stakeholder Workshop, Regional Greenhouse Gas Initiative, Boston, MA, October 14, 2004.
“Emissions Trading: Concepts, Experience, Lessons, and Implications Greenhouse Gas Programs,” presented to Iberdrola, Cambridge, MA, March 25, 2004.
“How CEPCO Can Gain from CO2 Trading,” presented to Chubu Electric Power Co., Inc., Nagoya, Japan, November 25, 2003.
“The Rise of Emissions Trading in Air Quality and Climate Change Policy,” presented to EPRI Environmental Sector Council, San Antonio, Texas, September 12, 2003.
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“Greenhouse Gas Emissions Trading and Firm Risk Management Behavior”, presented to the ARPEL-IPIECA Workshop, A Practical Approach to Identifying Emission Reduction Opportunities: Examples under the Kyoto Mechanisms in Latin America and the Caribbean, San Jose, Costa Rica, December 3, 2002.
“Initial Allocations in Various Systems of Emissions Trading” presented to the Exploring New Approaches in Regulating Industrial Installations (ENAP) Workshop on Emissions Trading for NOX and SOx in Europe, The Hague, Netherlands, November 22, 2002.
“Overview of Alternative Allocations for European GHG Trading Program,” presented to IEA-EPRI-IETA Workshop on Greenhouse Gas Emissions Trading, Paris, September 17, 2002.
“Evaluation of Alternative Allocations for European GHG Trading Program,” presented to IEA-EPRI-IETA Expert Meeting: Allocation of GHG Objectives, Paris, September 16, 2002.
“Greenhouse Gas Emission Trading Programs,” presented to Chubu Electric Company, Cambridge, MA, July 16, 2002.
“Evaluation of Alternative Allocations for European GHG Trading Program,” presented to Chubu Electric Company, Cambridge, MA, July 16, 2002.
“Corporate Strategies and Practices for GHG Emission Reduction,” presented to Chubu Electric Company, Cambridge, MA, July 15, 2002.
“Emission Trading: Concepts, Experience, and Lessons from Non-Greenhouse Gas Programs,” presented to Chubu Electric Company, Cambridge, MA, July 15, 2002.
“Prospects for the EU Greenhouse Gas Trading Program,” presented to EPRI Global Climate Change Research Seminar, Washington, DC, June 4, 2002.
“Evaluation of Alternative Allocations for European GHG Trading Program,” presented to European Commission, Brussels, Belgium, November 13, 2001.
“Evaluation of Alternative Allocations for European GHG Trading Program,” presented to ENVECO, Brussels, Belgium, November 13, 2001.
“CO2 Permit Allocations: Evaluation of Alternatives for the EC,” presented to the European Commission, Brussels, Belgium, March 5, 2001.
“Setting Baselines for Greenhouse Gas Trading: Lessons from Experience,” presented to United Nations Framework Convention on Climate Change, Bonn, Germany, June 10, 2000.
“Setting Baselines for Greenhouse Gas Programs: Lessons from Experience,” presented at the EPRI Global Climate Change Research Seminar, Washington, DC, May 18, 2000.
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“Emissions Trading and Developing Countries: Implications of U.S. Experience and World Bank Role,” presented at World Bank – Energy Week 2000, Washington, DC, April 13, 2000.
“Domestic GHG Trading: Assessing Impacts on Electric Utilities,” presented to Electric Power Research Institute, Washington, DC, February 17, 2000.
“Energy-Environmental Policy Integration & Coordination (E-EPIC), U.S. Economic Growth & Health,” presented to Electric Power Research Institute, Washington, DC, May 13, 1999.
“Priorities for the Development of GHG Trading Programs: Implications of the United States Experience,” presented to the EPRI Global Climate Change Area Meeting, San Diego, California, January 26, 1999.
“Priorities for the Development of GHG Trading Programs: Implications of the United States Experience,” presented to the Air & Waste Management Association Specialty Conference on Global Climate Change, Washington, DC, October 14, 1998.
“International Greenhouse Gas Trading,” presented to the American Council for Capital Formation, Washington, DC, September 23, 1998.
“International Greenhouse Gas Emission Trading: Promise and Performance,” presented to the EPRI Global Climate Change Research Seminar, Washington, DC, May 27, 1998.
“International Greenhouse Gas Trading: A ‘Silver Bullet’ Train?” presented to Sidebar Meeting, United Nations Framework Convention on Climate Change, Bonn, Germany, October 23, 1997.
“International Greenhouse Gas Trading,” presented to the American Council for Capital Formation Conference on Global Warming, Washington, DC, September 24, 1997.
“International Greenhouse Gas Trading,” presented to the National Association of Manufacturers, Washington, DC, September 17, 1997.
“International Greenhouse Gas Trading,” presented to the American Automobile Manufacturers Association, Washington, DC, May 1, 1997.
“Emission Trading: Alternative Approaches, Experience and Implications for CO2,” prepared for the AAMA Climate Change Task Force, Washington, DC, September 27, 1996.
“Treatment of Greenhouse Gas Emissions in Electric Utility Resource Planning,” prepared for the Third Conference on External Costs, Internalization of Social Costs of Energy Conservation and Transportation in the United States and Europe for a Sustainable Development, Ladenburg, Germany, May 29, 1995.
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“Distributive Impacts of Economic Instruments for Greenhouse Gas Abatement,” presented at the Air & Waste Management Association International Specialty Conference Global Climate Change: Science, Policy and Mitigation Studies, Phoenix, Arizona, April 6, 1994.
“New Approaches for Controlling Global Warming,” presented to the Conference on Global Warming, Vermont Law School, South Royalton, Vermont, February 16, 1990.
B. Economic Impact
Economic Impacts of a 65 ppb National Ambient Air Quality Standard for Ozone, Webinar, (with Anne E. Smith), prepared for the Association of Air Pollution Control Agencies, March 2, 2015.
“Cumulative Energy Market Impacts of Various Environmental Regulations,” presented at Law Seminars International, Utility Rate Case Issues and Strategies 2013, Las Vegas, Nevada, February 21, 2013.
“Financial Implications of a US Cap-and-Trade Program for Sectors and Companies,” presented at 2nd Annual Carbon Trading Summit, New York City, January 13, 2010.
“Evaluating the Impact of Future E.U. Chemical Policy on the French Economy,” presented to REMI Northeast Policy Analysis and Users’ Conference, Boston, MA, January 31, 2006.
“Background on NERA Study ‘Socioeconomic Effects of the Niagara Power Project and Local NYPA Presence’,” presented to Niagara Power Project Relicensing Stakeholder Meeting, Niagara Falls, NY, November 13, 2003.
“Economic Benefits to the Chicago Region from the Whitecap Energy System,” presented to the Illinois Department of Natural Resources, Springfield, Illinois, January 30, 2001.
“Fueling Electricity Growth for a Growing Economy,” presented to Edison Electric Institute, Palm Springs, California, January 13, 2000.
“Economic Impact Analyses with REMI: Two Case Studies,” presented to the REMI Seminar, Miami, Florida, October 6, 1997.
“Impacts on the Hawaii Economy of Alternative Resource Plans for Oahu,” presented to the Hawaiian Electric Company IRP Advisory Group, Honolulu, Hawaii, July 24, 1997.
“Economic and Environmental Effects in Maine of the Maritimes & Northeast Pipeline Project,” presented to the Maine Economic Development Council, Rockland, Maine, February 12, 1997.
“Economic and Environmental Effects of the Maritimes & Northeast Pipeline Project,” presented to a media conference and Editorial Boards of the Bangor Daily News, the Portland Press Herald, and the Kennebec Journal, Bangor and Augusta, Maine, November 21, 1996.
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“Assessing the Economic Impacts of Alternative HECO Resource Plans,” presented to the PSP&ED Advisory Group of the Hawaiian Electric Company, Honolulu, Hawaii, July 3, 1996.
“The Lake Calumet Airport and Chicago’s Economic Future,” presented to the Lake Calumet Airport Advisory Committee, Chicago, Illinois, July 2, 1991.
“Socioeconomic Impacts of Proposed Rule 431.2,” prepared for Southern California Edison and presented to the South Coast Air Quality Management District, Los Angeles, California, May 4, 1990.
“An Economist Looks at the Federal Regulation of Biotechnology,” presented to the Conference on Emerging Issues in Biotechnology, sponsored by Boston University Law School, Boston, Massachusetts, March 2, 1990.
C. Air Quality
Economic Impacts of a 65 ppb National Ambient Air Quality Standard for Ozone, Webinar, (with Anne E. Smith), prepared for the Association of Air Pollution Control Agencies, March 2, 2015.
“Cost-Effectiveness of Alternative Wood Stove New Source Performance Standards,” (with Andrew Foss), presentation to the U.S. Environmental Protection Agency, Raleigh, NC, February 28, 2013.
“Potential Impacts of EPA Air, Coal Combustion Residuals, and Cooling Water Regulations,” presented to the U.S. Environmental Protection Agency, November 21, 2011.
“Potential Impacts of EPA Air, Coal Combustion Residuals, and Cooling Water Regulations,” presented to the U.S. Office of Management and Budget, November 8, 2011.
“Potential Impacts of EPA Air, Coal Combustion Residuals, and Cooling Water Regulations,” presented to the U.S. Treasury Department, October 26, 2011.
“Potential Impacts of EPA Air, Coal Combustion Residuals, and Cooling Water Regulations,” presented to the White House Office of Public Engagement, October 25, 2011.
“Economic Effects of State Restrictions on Interstate Mercury Trading,” presented at the Electric Utilities Environmental Conference, Tucson, Arizona, January 22, 2007.
“Using Emissions Trading to Regulate Mercury Emissions in Montana,” presented at a Public Hearing, Billings, Montana, June 1, 2006.
“Developing an Emissions Trading Program for Regional Haze,” presented to Midwest RPO Regional Air Quality Workshop, Chicago, IL, June 28, 2005.
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“Developing an Emissions Trading Program for Regional Haze,” presented to the Visibility Improvement State and Tribal Association of the Southeast (VISTAS), via conference call from Boston, MA, June 1, 2005.
“Economic and Environmental Analyses of CARB Tier 3 Non-Handheld Exhaust Emission Regulations,” presented to the California Air Resources Board staff in Sacramento, CA via videoconference from Boston, MA, September 18, 2003.
“Market Based Instruments and Shipping Emissions,” presented to conference sponsored by DG Environment, Brussels, September 5, 2003.
“Economic and Environmental Analyses of CARB Tier 3 Non-Handheld Emission Regulations: Status Report and Preliminary Results”, presented to Outdoor Power Equipment Institute and Engine Manufacturers Association (OPEI & EMA), Washington, DC, August 26, 2003.
“Ex Post Evaluation of the RECLAIM Emissions Trading Program for the Los Angeles Air Basin”, presented to OECD Workshop on Ex Post Evaluation of Tradable Permits: Methodological and Policy Issues, Paris, January 21, 2003.
“Emissions and Cost-Effectiveness of the Pull-Ahead Requirements for Heavy Heavy-Duty Diesel Engines,” presented to U.S. Office of Management and Budget, Washington, DC, July 24, 2002.
“Economic Analysis of Alternative EPA Snowmobile Regulations,” presented to U.S. Environmental Protection Agency Office of Mobile Sources, Ann Arbor, Michigan, May 1, 2002.
“Impacts of ZEV Sales Mandate on California Fleet Emissions,” presented to the California Air Resource Board, Sacramento, CA, September 7, 2000.
“Economic Assessment of the Cost-Effectiveness of Alternative MACT Standards for the Metal Coil Surface Coating Industry,” presentation to the U.S. Environmental Protection Agency, Research Triangle Park, North Carolina, August 2, 2000.
“Economics and Environmental Regulation: Opportunities and Obstacles,” presented to Crowell & Moring, LLP, Washington, DC, March 22, 2000.
“RECLAIM: A Comprehensive Approach to Air Quality Regulation,” presented to Edison Electric Institute, Washington, DC, March 6, 2000.
“Economic Assessment of the Cost-Effectiveness of Alternative Phase 2 Regulations for Handheld Engines,” presented to the U.S. Environmental Protection Agency and Office of Management and Budget, Washington, DC, February 14, 2000.
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“Economic Assessment of the Cost-Effectiveness of Alternative Phase 2 Regulations for Handheld Engines,” presented to the U.S. Environmental Protection Agency, Office of Mobile Sources, Washington, DC, October 12, 1999.
“Economic Assessment of the Cost-Effectiveness of Alternative Phase 2 Regulations for Handheld Engines,” presented to the U.S. Environmental Protection Agency, Office of Mobile Sources, Ann Arbor, Michigan, October 8, 1999.
“Costs & Benefits of Fish Protection Alternatives at the Salem Generating Facility,” presented to the New Jersey Department Environmental Protection, Trenton, New Jersey, May 4, 1999.
“Economic Impacts of ARB Staff Proposed Marine Emission Standards,” presented to the California Air Resources Board Hearing, Sacramento, California, December 10, 1998.
“Cost-Benefit Analysis of MACT Standards for Boat Manufacturing,” presented to the National Marine Manufacturers Association, Tampa, Florida, October 15, 1998.
“Economic Analyses of Alternative California Standards for Exhaust Emissions from Marine Engines,” presented to California Air Resources Board, Sacramento, California, October 9, 1998.
“Tradable Permits for Air Pollution Control: The United States Experience,” presented to the Organization for Economic Cooperation and Development Workshop on Domestic Tradable Permit Systems for Environmental Management, Paris, September 24, 1998.
“NOX Trading Program to Implement EPA’s SIP Call,” presented to Indiana Department of Environmental Management, Indianapolis, Indiana, May 4, 1998.
“Economic Analysis of Alternative EPA Standards for Large CI Non-Road Engines: Draft NERA Results,” presented to the Engine Manufacturers Association and the Equipment Manufacturers Institute, Chicago, Illinois, September 4, 1997.
“Cost-Effectiveness of ARB Small Off-Road Engine Regulations: Preliminary Results,” presented to the California Air Resources Board, Sacramento, California, May 2, 1997.
“RECLAIM: Turning Theory Into Practice for Emissions Trading in the Los Angeles Air Basin,” presented to the NERA Seminar on Tradable Permits, London, United Kingdom, April 11, 1997.
“RECLAIM: Turning Theory Into Practice for Emissions Trading in the Los Angeles Basin,” presented to the International Workshop on Tradable Permits, Tradable Quotas and Joint Implementation, University of Sussex, Brighton, United Kingdom, April 9, 1997.
“Economic Analyses of Alternative ARB Regulatory Requirements for Small SI Non-Handheld Engines,” presented to the California Air Resources Board staff, El Monte, California, February 4, 1997.
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Exhibit Harrison Direct-1 David Harrison
“Cost-Effectiveness of Alternative Emission Control Technologies for Small Utility Engines,” presented to California Air Resources Board staff, El Monte, California, December 18, 1996.
“Emission Regulations for Non-Road Engines,” presentation to the U.S. Environmental Protection Agency, Ann Arbor, Michigan, July 17, 1996.
“Valuation of Externalities: Methods and Examples,” presented to the PSP&ED Advisory Group of the Hawaiian Electric Company, Honolulu, Hawaii, April 3, 1996.
“Valuation of Externalities: Experience and Methods,” presented to the Hawaiian Electric Company Externalities Advisory Group, Honolulu, Hawaii, January 31, 1996.
“Emission Regulations for Small Utility Engines,” presented to Small Non-Road Engine Regulatory Negotiations, Ann Arbor, Michigan, December 13, 1995.
“Economic Evaluation of Alternative Regulations of Exhaust Emissions from Small Utility Engines,” presented to U.S. Environmental Protection Agency, Ann Arbor, Michigan, November 28, 1995.
“Emission Regulations for Small Utility Engines,” presented to California Air Resources Board staff, El Monte, California, October 3, 1995.
“Briggs & Stratton/NERA Phase 2 Economic Study,” presented to U.S. Environmental Protection Agency, Ann Arbor, Michigan, September 22, 1995.
“RECLAIM: Turning Theory Into Practice for Emissions Trading in the Los Angeles Basin,” presented to the Stanford Law School Environmental Markets Seminar, Stanford, California, March 8, 1995.
“Emission Trading for NOX: Experience with RECLAIM,” presented to Edison Electric Institute, Washington, DC, May 26, 1994.
“Emission Trading for NOX: The RECLAIM Experience,” presented to Edison Electric Institute, May 13, 1994.
“Projecting the Price of RECLAIM Trading Credits for NOX,” presented at a California Energy Commission Workshop, Sacramento, California, February 4, 1994.
Comments on “Presumptive Pigouvian Tax: Complementing Regulation to Mimic an Emissions Fee,” presented to the Conference on Market Approaches to Environmental Protection, Stanford University, Palo Alto, California, December 3, 1993.
“Economic Effects of Regulatory Requirements to Protect Grand Canyon Visibility,” presented to the Grand Canyon Visibility Transport Commission, Salt Lake City, Utah, October 21, 1993.
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Exhibit Harrison Direct-1 David Harrison
“Evolving Role of Externalities in Utility Activities,” presented to the Electric Power Research Institute Energy Analysis Task Force, Nashville, Tennessee, September 29, 1993.
“External Costs of Electricity Generation in Southern Nevada,” presented on behalf of Nevada Power Company, at a workshop sponsored by the Nevada Public Service Commission, Las Vegas, Nevada, May 19, 1993.
“Environmental Externalities,” presented to Central and Southwest Corporation, Dallas, Texas, May 4, 1993.
“Creating Markets for Environmental Protection: Overview of Experience with Tradable Permit Systems,” presented at The Claremont Institute
Conference Environmental Protection Through Market Incentives: A Strategy for the Future, Los Angeles, California, January 20-21, 1993.
“Tradable Permits and Social Costing: The California Experience,” presented at the American Economic Association and Allied Social Science Association Meetings, Anaheim, California, January 6, 1993.
“The Distributive Impacts of Economic Instruments for Environmental Policy,” presented to the OECD Group on Economic and Environmental Policy Integration, Paris, November 19, 1992.
“Emissions Trading: A Better Way to Incorporate Environmental Costs in Electric Utilities Resource Planning,” presented at the Pace University
Center for Environmental Legal Studies Conference on Incorporation of Social Costs of Energy in Resource Acquisition Decisions, Racine, Wisconsin, September 8-11, 1992.
“Banking and Trading of Air Emission Reduction Credits,” presented to the State of Connecticut Office of Policy and Management Meeting on Emissions Trading, Hartford, Connecticut, July 22, 1992.
“The Distributive Effects of Economic Instruments for Environmental Policy,” presented to the OECD Group on Economic and Environmental Coordination, Paris, June 18, 1992.
“A Marketable Permits Program for the Los Angeles Air Basin,” prepared for MIT Center for Energy and Environmental Policy Research 1992 New Developments Workshop, Cambridge, Massachusetts, April 30, 1992.
“The Road From Theory to Practice: Developing a Marketable Permits Program for the Los Angeles Air Basin,” seminar presented to the MIT Center for Energy and Environmental Policy Research, Cambridge, Massachusetts, March 11, 1992.
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Exhibit Harrison Direct-1 David Harrison
“Southern California Edison Damage-Based Values for Residual Emissions Valuation,” presented to the California Energy Commission ER 92 Committee Workshop on Air Emission Damage Functions, Sacramento, California, January 29, 1992.
“Turning Theory Into Practice: Developing a Marketable Permits Program for the Los Angeles Basin,” prepared for Project 88 -- Round II Seminar, John F. Kennedy School of Government, Harvard University, Cambridge, Massachusetts, December 11, 1991.
“Workshop on Economic Instruments,” prepared for Imperial Oil Ltd., Toronto, Canada, October 1-2, 1991.
“Market-Based Approaches to Air Quality Improvement,” presented to the Board of Directors of the California Council for Environmental and Economic Balance, San Diego, California, July 1991.
“Environment and Equity,” presented to the Board of Directors of the California Council for Environmental and Economic Balance, San Diego, California, July 1991.
“Contribution of Economists to Environmental Policy: Comments on the Gruenspect-Lave Critical Review,” presented to the Air and Waste Management Association, Vancouver, British Columbia, June 19, 1991.
“Airports and Economic Development,” presented to the Southeast Chicago Development Commission, Chicago, Illinois, May 24, 1991.
“Environmental Economics in the 1990s,” presented to the OECD Group of Economic Experts, Paris, May 16, 1991.
“The Clean Air Act: How to Make the Mandate Worth the Effort,” presented to the Workshop on Emerging Environmental Policies and Business, North Carolina State University, Raleigh, North Carolina, April 18, 1991.
“Market-Based Approaches to Managing Air Emissions in California’s South Coast Basin,” presented to Workshop on Market Incentives, South Coast Air Quality Management District, El Monte, California, January 29, 1991.
“Market-Based Approaches to Managing Air Emissions in California’s South Coast Basin,” presented to the Steering/Advisory Committee on Market Incentives, South Coast Air Quality Management District, Los Angeles, California, December 11, 1990.
“How Environmental Policies Influence Natural Gas Markets,” presented to the Conference on Emerging Competition in California Gas Markets, sponsored by the California Energy Commission, San Diego, California, November 9, 1990.
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Exhibit Harrison Direct-1 David Harrison
“Air Quality and Electric Vehicles,” presented to the Electric Vehicle Symposium, sponsored by the Western Energy Supply and Transmission Associates, Ontario, California, November 8, 1990.
“Incorporating Environmental Impacts in Public Utility Commission Regulation,” presented to the Energy Research Group, Washington, DC, November 6, 1990.
“The Promise and Performance of the Acid Rain Allowance Program,” presented to the Conference on the New Acid Rain Legislation: Capitalizing on a Market-Based Approach, sponsored by Public Utilities Reports, Inc., Washington, DC, October 24, 1990.
“What Environmental Legislation Means for Crude Oil Marketers: A U.S. Overview,” prepared for the Oxford College of Petroleum Studies, Long Beach, California, presented October 1, 1990.
“Market-Based Approaches for Environmental Improvement,” presented to the Eleventh Annual Antitrust and Trade Regulation Seminar, sponsored by National Economic Research Associates, Santa Fe, New Mexico, July 5-7, 1990.
“Using Market-Based Approaches in the Energy Sector,” presented to the OECD Economic Incentives Working Group, Paris, June 19-20, 1990.
“Emissions Trading: Concepts and Experience,” prepared for The Canadian Electrical Association and presented at the Workshop on Tradable Permits, Toronto, Canada, June 13, 1990.
“Prototypical Trading Policy: Stationary Sources of NOX,” prepared for NOX/VOC Task Force and presented at the Workshop on Flexible Mechanisms, Montreal, Canada, June 6-7, 1990.
“Emissions Trading: An Overview of Concepts and Experience,” prepared for NOX/VOC Task Force and presented at the Workshop on Flexible Mechanisms, Montreal, Canada, June 6-7, 1990.
“Market-Based Approaches for Environmental Improvement,” presented to the Board of Directors, The Conference Board of Canada, Edmonton, Canada, May 30, 1990.
“Market-Based Approaches for Environmental Protection: Lessons from the U.S. Experience,” presented to the Advisory Board, Research Program on Business and the Environment, The Conference Board of Canada, Toronto, Canada, April 24, 1990.
“Ozone and Economics,” presented to the Air and Waste Management Association, Los Angeles, California, March 20, 1990.
“Clear Thinking on Clear Air: Agenda for the 1990’s,” paper and panel discussion presented at the American Enterprise Institute’s Thirteenth Annual Policy Conference, Washington, DC, December 4, 1989.
“The Acid Rain Allowance Program,” presented to the Energy Research Group, Washington, DC, November 3, 1989.
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Exhibit Harrison Direct-1 David Harrison
D. Water Quality
“Social Cost Analysis in Section 316(b) Cost Evaluation Studies,” presented to Electric Power Research Institute Section 316(b) Conference on Technical Challenges for Ohio/Tennessee River Basin Power Plants, Columbus, Ohio, March 15, 2017.
“Benefits Evaluation and Monetization in EPA's §316(b) Final Rule: Economic Determinations and Issues,” presented at EUCI Conference on 316(b) Final Rule, September 29, 2016.
“Cost-Benefit Assessments for 316(b): Some Implementation Issues,” presented at UWAG Webinar on 316(b) Implementation Issues, August 5, 2015.
“Benefit-cost Assessment of Section 316(b) Entrainment Alternatives,” presented at the EUCI Conference on 316(b), Providence, Rhode Island, October 8, 2014
“Benefit-Cost Analysis in Section 316(b) BTA Determinations: The Road Ahead,” presented at the American Fisheries Society Symposium, Seattle, Washington, September 6, 2011.
“Cost-Benefit Analysis for Fish Impingement and Entrainment Reduction at Pickering Nuclear Generating Station,” presented to Canadian Nuclear Safety Commission, Ottawa, Canada, October 29, 2009.
“Cost-Benefit Analysis for Fish Impingement and Entrainment Reduction at Pickering Nuclear Generating Station,” presented at Ontario Power Generation Inc. Stakeholder Workshop, Ontario, Canada, September 29, 2009
Uncertainty in §316(b) Compliance Demonstration: Case Study Including Monte Carlo Analysis,” presented at the UWAG/EPRI Conference on Technologies and Techniques for §316(b) Compliance, Atlanta, Georgia, September 7, 2006.
“Electricity System Impacts of Nuclear Shutdown Alternatives,” presented to New York City Council, New York, NY, May 7, 2002.
“Electricity System Impacts of Nuclear Shutdown Alternatives,” presented to Westchester County Board of Legislators Committee on Environment and Health, Westchester, New York, April 29, 2002.
“An Economic Approach to 316(b) BTA Determination,” presented to the UWAG 316(b) Technical Workshop for the Environmental Protection Agency, Annapolis, Maryland, January 25, 2001.
“Methodology for Cost-Benefit Assessment of Fish Protection Alternatives for the Mercer Facility,” presentation to the Mercer 316(b) Permit Team, Newark, New Jersey, August 8, 2000.
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Exhibit Harrison Direct-1 David Harrison
“Roadmap for Costs & Benefits of Fish Protection Alternatives for the Salem Facility,” presented to the Monitoring Advisory Committee, Mt. Laurel, New Jersey, December 9, 1999.
“Natural Resource Damage Assessments: Economic Techniques,” presented to PSE&G, Newark, New Jersey, December 9, 1997.
“Use of Economic Analysis in Environmental Impact Statements and Other Regulatory Proceedings,” presented to Hudson River Utilities, New York, New York, November 19, 1997.
“Combining Science and Economics: The Case of Superfund,” presented to ENVIRON, Princeton, New Jersey, May 16, 1995.
“Social Costing: Policy Overview,” presented to the British Columbia Utilities Commission Social Costing Workshop, Vancouver, British Columbia, March 29, 1995.
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1 AFFIRMATION
2STATE Of uS )
)ssCOUNTY Of Su FjThL1— )
5
6
7 I, DAVID HARRISON, do hereby swear under penalty of perjury the following:
8 That I am the person identified in the attached Prepared Testimony and that such
9 testimony was prepared by me or under my direct supervision; that the answers and
10 information set forth therein are true to the best of my knowledge and belief as of the
11 date of this affirmation; that I have reviewed and approved any modifications after the
12 date of this affirmation; and that if asked the questions set forth therein, my answers
13 thereto would, under oath, be the same.
4
c
16 DAVID HARRISON
17
18 Subscribed and sworn to before me
19 this d- day of May, 2018.
22 NOTARY PUBLIC
23 SILVIA E. SANTOS
*4Commonw.alth of Massachu5ett
24 ‘l My Commission ExpiresSeptember 14, 2018
25
26
27
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