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 3 OF 18
TESTIMONY
DESCRIPTION PAGE NUMBER
TESTIMONY
Anita L. Hart 2
Robert R. Oliver 54
Marc D. Reyes 68
Patricia Rodriguez 91
Ingrid Rohmund 103
Joseph Sinobio 126
David Ulozas 132
Sachin Verma 185
ANITA L. HART
Page 2 of 198 1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Nevada Power Company d/b/a NV Energy Sierra Pacific Power Company d/b/a NV Energy 3 2018 Joint Integrated Resource Plan (2019-2038) 4 Docket No. 18-06_____
5 PREPARED DIRECT TESTIMONY OF
6 Anita Hart
7
8 I. INTRODUCTION AND PURPOSE OF TESTIMONY
9 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS
10 ADDRESS AND PARTY FOR WHOM YOU ARE FILING
11 TESTIMONY.
12 A. My name is Anita L. Hart. My current position is Director, Demand Side
13 Management, for Nevada Power Company d/b/a NV Energy (“Nevada d/b/a NV Energy 14 Power”) and Sierra Pacific Power Company d/b/a NV Energy (“Sierra” Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 together with Nevada Power, the “Companies”). My business address is
16 6226 West Sahara Avenue in Las Vegas, Nevada. I am filing testimony on
17 behalf of the Companies.
18
19 2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE
20 IN THE UTILITY INDUSTRY.
21 A. My professional experience includes 25 years in the utility industry and I
22 have a Master of Arts in Economics with an emphasis in Public Utility
23 Regulation. I have worked for the Companies since 2008. In addition to
24 Hart - IRP DIRECT 1
Page 3 of 198 1 Director and Consultant Staff positions in the Demand Side Management
2 organization, I was also assigned to the resource planning organization in
3 the role of Manager of Gas Transportation Planning. In that role I was
4 responsible for the planning and analysis of natural gas transportation
5 needs and ensuring sufficient supply to the generation fleet and Sierra’s
6 natural gas customers.
7
8 Prior to joining the Companies, I was employed as the Manager of
9 Demand Side Management and Market Research at Southwest Gas
10 Corporation (“SWG”). Over a span of 15 years my key responsibilities at
11 SWG included: 1) resource planning and demand forecast modeling and
12 analysis; 2) development and maintenance of tariffs, applications, and
13 filings before three state regulatory agencies, consistent with regulatory, d/b/a NV Energy 14 legal and company requirements; 3) development, approval, Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 implementation and management of demand side management (“DSM” or
16 conservation and energy efficiency “CEE”) and low-income programs;
17 and 4) market research. More details regarding my background and
18 experience are provided in Exhibit Hart-Direct-1.
19
20 3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS DIRECTOR,
21 DEMAND SIDE MANAGEMENT.
22
23
24 Hart - IRP DIRECT 2
Page 4 of 198 1 A. As the Director of Demand Side Management I am responsible for the
2 development, analysis and implementation of a cost-effective portfolio of
3 electric and natural gas DSM and CEE programs.
4
5 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
6 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
7 A. Yes, I have testified in several proceedings before the Commission, in
8 addition to the California Public Utilities Commission and the Arizona
9 Corporation Commission. Most recently I provided testimony addressing
10 demand side issues before this Commission in Docket Nos. 17-06043 and
11 17-06044.
12
13 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? d/b/a NV Energy 14 A. My testimony describes and summarizes the Companies’ joint DSM Plan (the Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 “DSM Plan”). The DSM Plan provides the results of the 2017 program year,
16 a status update on the 2018 program year, and documents the analysis used
17 by the Companies to develop a new joint DSM Plan for the three year Action
18 Plan period 2019-2021. The DSM Plan is built around a portfolio of programs
19 that is cost-effective at the plan level, that allocates at least 5 percent of the
20 budget for low income customers, and results in annual energy savings of at
21 least 1.1 percent of the statewide (Nevada Power and Sierra combined)
22 weather normalized retail sales forecast. Also included with the DSM Plan
23 are Measurement and Verification (“M&V”) reports for the 2017 program
24 Hart - IRP DIRECT 3
Page 5 of 198 1 year, for which the Companies’ seek approval. Together with Mr. Robert
2 Oliver, I sponsor the M&V reports contained in Technical Appendices DSM-
3 5 through DSM-20. In addition, together with Ms. Rohmund, I support the
4 Market Potential Study contained in Technical Appendix DSM-21. I sponsor
5 and support all parts of the DSM Plan not sponsored or supported by
6 witnesses Mr. Oliver and Ms. Rohmund.
7
8 Also related to the DSM Plan, I support the Companies’ request that the
9 Commission find that the Companies have complied with Directives
10 paragraph 6 of the Commission’s Order dated December 23, 2016 in
11 consolidated Docket Nos. 16-07007 and 16-07001.
12
13 6. Q. ARE YOU SPONSORING ANY EXHIBITS? d/b/a NV Energy 14 A. Yes. I am sponsoring the following exhibits: Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 Exhibit Hart-Direct-1 Statement of Qualifications
16 Exhibit Hart-Direct-2 2017 DSM Program Results
17 Exhibit Hart-Direct-3 2019-2021 DSM Plan Targets
18
19 7. Q. PLEASE PROVIDE AN OVERVIEW OF YOUR TESTIMONY.
20 A. Section II of my testimony, discusses the 2017 program year results.
21 Section III, provides an overview of Senate Bill 150 (“SB 150”) and
22 Assembly Bill 223 (“AB 223”) adopted in 2017. Section IV, describes the
23 process of developing a Demand Side Plan. Section V, summarizes the
24 Hart - IRP DIRECT 4
Page 6 of 198 1 DSM Plan and discusses enhancements the Companies have made in this
2 filing to the portfolio of programs. Finally, in Section VI, I address
3 compliance items and directives.
4
5 SECTION II: SUMMARY OF PROGRAM YEAR 2017 RESULTS
6 8. Q PLEASE SUMMARIZE THE PERFORMANCE OF NEVADA
7 POWER’S DSM PORTFOLIO FOR 2017.
8 A. At Nevada Power, the portfolio of DSM programs delivered in 2017
9 achieved a total resource cost (“TRC”) benefit to cost ratio of 2.30 and
10 will provide more than $97 million dollars of net benefits to customers
11 over the lives of the measures installed. Nevada Power surpassed its
12 energy savings targets but fell slightly short of its demand savings targets.
13 Expenditures remained within the approved budget. Total verified energy d/b/a NV Energy 14 savings for the 2017 program were 191,057,956 kWh (129.4 percent of Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 the target of 147,597,000 kWh). The demand savings totaled 247,720 kW
16 (94.8 percent of the target of 261,426 kW). Total DSM portfolio
17 expenditures were $39,390,297 (91.6 percent of the budget of
18 $43,000,000, includes recaptured funds1).
19
20
21
22 1 “Recaptured funds” refers to prorated rebates that were provided to NRS Chapter 704B customers 23 Wynn and MGM during 2017, and that as a condition of their authorization to transition to Distribution Service Only status were required to be refunded to retail customers. 24 Hart - IRP DIRECT 5
Page 7 of 198 1 Notable among the program results were the savings achieved through the
2 Commercial Services program, Schools program and the Commercial
3 Demand Response – Manage program. Each of these programs
4 significantly exceeded its targeted energy savings for 2017. Residential
5 Air Conditioning, Residential Demand Response – Manage, Residential
6 Demand Response – Build and Commercial Demand Response - Build
7 programs fell short of targeted energy savings.
8
9 Table DSM-4A, 2017 Financial Results, and Table DSM-5A, 2017
10 Demand and Energy Savings Results, found in Section 2 of the DSM
11 Narrative in this filing provides the performance for the portfolio in
12 aggregate and for each program at Nevada Power. A more detailed
13 description and analysis of the performance of each program in 2017 is d/b/a NV Energy 14 included in the program data sheet for each program provided in Sections Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 5 through 7 and in the M&V Reports for each program provided in
16 Technical Appendix Items DSM-5 through DSM-20.
17
18 As explained in Sections 5 through 7, the performance and results for each
19 program at Nevada Power in 2017 were evaluated and became a key input
20 for the design of the programs proposed for implementation in the 2019-
21 2021 Action Plan period.
22
23
24 Hart - IRP DIRECT 6
Page 8 of 198 1 9. Q PLEASE SUMMARIZE THE PERFORMANCE OF SIERRA’S
2 DSM PORTFOLIO FOR 2017.
3 A. At Sierra, the portfolio of DSM programs delivered in 2017 achieved a
4 TRC of 1.71 and will provide more than $18 million dollars of net benefits
5 to customers over the lives of the measures installed. Sierra surpassed both
6 its energy savings targets and demand savings targets. Expenditures
7 remained within the approved budget. Total verified energy savings for
8 the 2017 program were 56,366,537 kWh (142.3 percent of the target of
9 39,601,000 kWh). The demand savings totaled 25,325 kW (112.2 percent
10 of the target of 22,581 kW). Total DSM portfolio expenditures were
11 $10,960,177 (93.7 percent of the budget of $11,700,000).
12
13 Notable among the program results were the savings achieved through the d/b/a NV Energy 14 Residential Demand Response – Manage program, Schools program and Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 Commercial Services program. Each of these programs significantly
16 exceeded its targeted energy savings for 2017. Residential Demand
17 Response – Build, Commercial Demand Response – Manage and
18 Commercial Demand Response - Build programs fell short of targeted
19 energy savings.
20
21 Table DSM-4B, 2017 Financial Results, and Table DSM-5B, 2017
22 Demand and Energy Savings Results, found in Section 2 of the DSM
23 Narrative in this filing provides the performance for the portfolio in
24 Hart - IRP DIRECT 7
Page 9 of 198 1 aggregate and for each program at Sierra. A more detailed description and
2 analysis of the performance of each program in 2017 is included in the
3 program data sheet for each program provided in Sections 5 through 7 and
4 in the M&V Reports for each program provided in Technical Appendix
5 Items DSM-5 through DSM-20.
6
7 As explained in Sections 5 through 7, the performance and results for each
8 program at Sierra in 2017 were evaluated and became a key input for the
9 design of the programs proposed for implementation in the 2017-2019
10 Action Plan period.
11
12 10. Q. PLEASE DESCRIBE THE PROCESS EMPLOYED BY THE
13 COMPANIES TO MEASURE AND VERIFY ENERGY SAVINGS d/b/a NV Energy 14 THAT FOLLOW FROM THE IMPLEMENTATION OF DSM Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 PROGRAMS.
16 A. To ensure that its M&V objectives are met, the Companies employ an
17 M&V process that is based on generally accepted industry standards and
18 procedures. A third party M&V evaluation contractor with considerable
19 experience performs this work. The purpose of M&V activities is to
20 collect and analyze data to calculate the energy and demand savings that
21 result from DSM programs and measures implemented at sites that
22 participate in the Companies’ DSM programs. The Companies have
23 committed to using best practice M&V for two key reasons. First, M&V
24 Hart - IRP DIRECT 8
Page 10 of 198 1 provides systematic measurement of the performance of DSM programs
2 and technologies. Second, engineering methods and technical data provide
3 valid and reliable results.
4
5 As part of performing the M&V evaluation, the M&V contractor selects a
6 random sample of projects that will allow the determination of savings to
7 be made with r10.0 percent precision at the 90 percent confidence level.
8
9 A more in depth description of the M&V process is provided in the
10 prepared direct testimony of Mr. Oliver, a member of the team of
11 independent M&V evaluators who prepared M&V Reports for the 2017
12 DSM portfolios, and in the overview of the M&V process provided in
13 Technical Appendix Item DSM-4. d/b/a NV Energy 14 Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 The M&V Reports for the 2017 programs are provided in Technical
16 Appendix Items DSM-5 through DSM-20. The M&V Reports provide the
17 key input for determining the performance of each Company’s portfolio
18 of DSM programs for the 2017 program year. The Companies request that
19 the Commission approve the M&V reports pursuant to NAC § 704.9524
20 6(b).
21
22
23
24 Hart - IRP DIRECT 9
Page 11 of 198 1 SECTION III: 2017 LEGISLATIVE CHANGES
2 11. Q. PLEASE PROVIDE AN OVERVIEW OF SB150 AND AB223 PASSED
3 BY THE 2017 NEVADA LEGISLATURE.
4 A. Both SB150 and AB223 provide guidance on several activities related to
5 the deployment and approval of a DSM Plan; SB150 contains the same
6 provisions as AB223, and in addition addresses energy savings goals. An
7 outline of the new guidelines is provided below.
8 x The plan must have benefit-cost ratio of 1.0 or higher at the plan level
9 and the cost-effectiveness test selected by the Commission must
10 account for non-energy benefits.
11 x The Plan must direct at least 5 percent of the expenditures related to
12 energy efficiency programs towards low income customers.
13 x The Commission shall establish by regulation goals for energy d/b/a NV Energy 14 savings. Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 x The Commission may modify a goal for energy savings it has previously
16 established for an electric utility.
17
18 12. Q. WERE INVESTIGATION AND RULEMAKING DOCKETS OPENED
19 BY THE COMMISSION TO ADDRESS THE REVISED STATUTES?
20 A. Yes, two investigation and rulemaking dockets were opened, Docket Nos.
21 17-07011 and 17-08023, which were consolidated by the presiding
22 Commissioner. A series of comments and workshops have been held and
23
24 Hart - IRP DIRECT 10
Page 12 of 198 1 proposed regulations were submitted to the Legislative Counsel Bureau
2 (“LCB”) for pre-adoption on March 23, 2018.
3
4 13. Q. DID THE COMPANIES INCORPORATE THE CHANGES MADE BY
5 SB150 AND AB223 INTO THE DSM PLAN?
6 A. Yes, the Companies addressed the key changes described in Q&A 11 above.
7 The DSM Plan is cost-effective at the plan level by company and statewide.
8 In addition, the Companies calculated and have presented in the DSM Plan
9 the standard five-benefit-cost test ratios along with the resulting ratio from a
10 modified version of the TRC test, labeled NEB (for non-energy benefits)
11 Total Resource Cost or “NTRC.” The NTRC incorporates a percentage adder
12 for non-energy benefits (10 percent adder for non-low-income programs, 15
13 percent for programs that have a mix of low-income and non-low-income d/b/a NV Energy 14 participants and 25 percent for low-income programs). These adders are Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 similar to non-energy benefit percentages used at other utilities. The results
16 for the TRC test, which are summarized in Tables DSM-13A, DSM-13B and
17 DSM-13C, demonstrate a TRC of 2.17 for Nevada Power’s portion of the
18 DSM Plan, a TRC of 2.11 for Sierra’s portion of the DSM Plan, and a TRC
19 of 2.15 for the DSM Plan.
20
21 The DSM Plan expands offerings to low-income customers, consistent with
22 the State’s policy decisions. Between a new low-income program and
23 targeted low-income offerings within multiple programs proposed in this
24 Hart - IRP DIRECT 11
Page 13 of 198 1 instant filing, the Companies will meet or exceed the 5 percent expenditure
2 threshold.
3
4 While the proposed regulations being reviewed by the LCB are not final, they
5 do provide insight into the energy savings goal being contemplated by the
6 Commission. The draft regulations state “The goals for gross energy savings
7 resulting from all energy efficiency programs implemented by an electric
8 utility shall average no less than 1.1 percent of forecasted weather
9 normalized sales over the triennial period of 2019 through 2021.”2 The
10 combined energy savings from the DSM Plan is projected to exceed the 1.1
11 percent goal statewide each year of the Action Period. Individually Nevada
12 Power is projected to achieve an average of 1.3 percent and Sierra 0.9 percent
13 over the Action Plan period. These energy savings levels are representative d/b/a NV Energy 14 of the market achievable results in the 2018 Market Potential Study (see Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 Technical Appendix DSM-21). Recognizing the achievable level of energy
16 savings at Nevada Power and Sierra are uniquely different, the Companies
17 have prepared a plan that meets the statewide energy savings goal as
18 expressed in the Commission’s draft regulations.
19
20 14. Q. DOES THE RETAIL SALES FORECAST PRESENTED BY MR.
21 TERRY BAXTER INCORPORATE THE ENERGY SAVINGS
22
23 2 Proposed Regulation, Docket Nos. 17-07011 and 17-08023, Section 4. 24 Hart - IRP DIRECT 12
Page 14 of 198 1 LEVELS PRESENTED IN THE NEVADA POWER AND SIERRA
2 DSM PLANS?
3 A. The retail sales forecast supported and presented by Mr. Baxter includes
4 projected joint energy savings of 1.0 percent. The sales forecast was
5 developed prior to the completion of the Market Potential Study and the
6 publication of the draft regulations. At that time, it appeared a 1.0 percent
7 goal was a reasonable projection for use in developing the retail sales
8 forecast. If the Commission approves the DSM Plan as a result of this docket,
9 future load forecasts will be prepared with the higher projected joint energy
10 savings of 1.1 percent of sales.
11
12 SECTION IV: DSM PLAN DEVELOPMENT
13 15. Q. PLEASE DESCRIBE THE PROCESS OF DEVELOPING A DSM d/b/a NV Energy 14 PLAN. Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 A. The DSM planning process for a triennial IRP includes the following three
16 steps: data gathering, preliminary evaluations and plan development. The
17 following paragraphs briefly describe each of these steps.
18
19 Data Gathering - The primary input for this first step is an evaluation of the
20 performance of current DSM programs. The primary source of data for this
21 evaluation is the M&V reports prepared by a third-party independent
22 evaluator. These reports provide a comprehensive analysis of each
23 company’s effectiveness in meeting energy and demand savings targets for
24 Hart - IRP DIRECT 13
Page 15 of 198 1 each program. Other inputs include market potential, market transformation
2 and net-to-gross studies,3 service concepts and proposals gathered at
3 conferences, discussions with vendors, data gathered through industry
4 literature, periodic formal requests for information along with input from the
5 DSM Collaborative.
6
7 Preliminary Evaluation - In this step, each of the products and services
8 identified in the information gathering process are screened to determine if
9 they are cost effective, feasible in the marketplace and likely to be adopted
10 by customers. The financial analysis includes five industry-developed and
11 Commission-approved tests. The Companies placed the most weight on the
12 TRC results.
13 d/b/a NV Energy 14 Plan Development. – The portfolios of DSM programs by the Companies Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 were carefully developed by examining market potential and having
16 extensive discussions with implementation contractors and vendors.
17 Developing DSM plans is complicated by the fact that the Companies must
18 examine not only the feasible level of energy savings in the present market
19 conditions, but also what is sustainable year over year. This means that
20
21
22 3 In simplest terms, a “net-to-gross” study provides an empirical basis for computing the share of gross 23 energy efficiency savings that are directly attributable to a company-sponsored DSM program. The calculations of net savings for DSM programs become inputs to any proper DSM benefit-to-cost analysis. 24 Hart - IRP DIRECT 14
Page 16 of 198 1 potential performance of each program must be thoroughly examined for the
2 full Action Plan period.
3
4 As a final step, a financial analysis was performed to review the economic
5 performance of each program in the plans. Hourly marginal avoided energy
6 costs as determined by PROMOD and avoided capacity costs are used as an
7 input to determine the final cost-effectiveness ratios for each program. This
8 final financial test was performed to ensure the portfolio of programs remain
9 cost-effective with the updated avoided costs.
10
11 16. Q. WHAT KEY FACTORS DID THE COMPANIES CONSIDER WHEN
12 DESIGNING DSM PLAN?
13 A. When designing the DSM Plan and determining energy savings targets, the d/b/a NV Energy 14 Companies considered the following factors: 1) achievable level of energy Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 savings at Nevada Power and Sierra individually; 2) rate impacts; 3)
16 participation impacts; 4) system benefits; and 5) non-energy benefits. Each is
17 addressed below.
18
19 Achievable Level of Energy Savings - The Companies conducted a new
20 market potential study, which identifies various levels of savings potential
21 given the most recent Nevada-specific market information available. The
22 achievable level of energy savings is bounded at one end by the “technical
23 potential” of a program. Technical potential is the theoretical upper limit of
24 Hart - IRP DIRECT 15
Page 17 of 198 1 efficiency potential, assuming that customers adopt all feasible measures
2 regardless of their cost or customer preference. This is considered
3 unachievable and represents the upper limit of savings. The “economic
4 potential” is described as the technical potential of those technologies,
5 measures and practices that are cost-effective when compared to supply side
6 alternatives. “Market potential” and “maximum achievable potential” refine
7 the economic potential analysis by applying customer participation rates that
8 account for market barriers, customer awareness and attitudes, program
9 maturity, and recent program history. More specifically:
10 x Market Potential maintains current levels of participation for mature
11 programs, but uses higher levels of participation where additional
12 opportunity was identified (e.g., residential cooling). It also includes
13 new measures, such as light-emitting diode or “LED” lighting, using d/b/a NV Energy 14 market adoption rates based on secondary research. Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 x Maximum Achievable Potential used secondary research on customer
16 attitudes to accelerate market adoption by 50 percent for residential
17 customers and by 40 percent for non-residential customers. This
18 assumes higher participation levels could be achieved with a
19 combination of reduced market barriers: increased utility spending,
20 and use of customer-preferred delivery mechanisms. Participation is
21 capped at 85 percent to reflect a small subset of the population who
22 will not participate in DSM programs.
23
24 Hart - IRP DIRECT 16
Page 18 of 198 1 The current market potential study was designed specifically for Nevada, and
2 its results are highly dependent upon unique characteristics of the Companies
3 and its customers.
4
5 Rate Impacts – The Companies have thoughtfully prepared a DSM Plan
6 focused on balancing the long-term benefits of energy savings with the short-
7 term impacts on rates (and customer bills). The Commission is required to
8 consider the rate impact of a DSM portfolio to customers, as provided in NRS
9 § 704.785(2) as follows:
10 When considering whether to approve an energy efficiency or conservation program proposed by an electric utility as part 11 of a plan filed pursuant to NRS 704.741, the Commission shall consider the effect of any recovery by the electric utility 12 pursuant to this section on the rates of the customers of the electric utility. 13 d/b/a NV Energy 14 Participation Impacts – The Companies have also been mindful of the Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 tradeoff between a portfolio of programs designed to have a high level of
16 customer participation with smaller amounts of individual savings potential
17 compared to a smaller set of larger customers who are more likely to provide
18 high levels of energy savings. If the DSM Plan had been designed solely on
19 the perspective of maximizing energy savings, the portfolio of programs
20 proposed would have been heavily weighted on the smaller subset of large
21 customers with highest energy savings potential. The Companies chose to use
22 a design approach that provides products and services for all customer
23 segments and still achieves a significant increase in energy savings.
24 Hart - IRP DIRECT 17
Page 19 of 198 1 System Benefits – The Companies also considered both system and non-
2 energy benefits when designing the DSM Plan. The Companies have been
3 offering DSM programs for many years; however in 2016, a fundamental
4 shift was made in the implementation process, away from siloed energy
5 efficiency and demand response (“DR”) programs to fully integrated
6 programs designed to optimize energy and demand savings. In addition to
7 direct bill savings for participants, all customers benefit from the
8 implementation of energy efficiency and DR programs. The DSM portfolios
9 presented have the ability to flatten the system load shape and improve the
10 system load factor. This effect is driven by two primary factors: permanent
11 peak demand savings and dispatchable peak demand savings. Permanent
12 peak demand savings are derived from the coincident peak demand savings
13 from energy efficiency programs. Programs such as the Commercial Services d/b/a NV Energy 14 programs have a significant impact on system peak demand. Dispatchable Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 peak demand savings are derived from the residential and commercial DR
16 programs. DR events avoid the purchase of peak market energy and provide
17 savings for all customers.
18
19 With respect to electricity grid benefits, the demand response program is
20 currently used for 10-minute operating reserves. It can also be strategically
21 dispatched by location to reduce congestion on the distribution system or in
22 response to a distribution system emergency. The system can operate in much
23 the same fashion as a supply-side peaking resource but also provides an added
24 Hart - IRP DIRECT 18
Page 20 of 198 1 suite of customer, environmental and locational dispatch benefits. Growth of
2 DR resources and distributed energy resource operational capabilities will
3 allow the Companies to more easily accommodate an ever increasing amount
4 of renewable energy on the grid.
5
6 Non-Energy Benefits – Beyond energy and demand savings there are other
7 benefits that are difficult to quantify without an extensive and costly study.
8 These benefits are often referred to as non-energy benefits. These include but
9 are not limited to, increase in on-time energy bill payments, job
10 creation/economic development, water infrastructure, broad health effects,
11 neighborhood impacts, increased comfort, improved maintenance, higher
12 productivity, along with improved health, and indoor/outdoor air quality.
13 d/b/a NV Energy 14 In addition to the criteria above, the Companies conducted a number of DSM Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 Collaborative workshops with representatives from the Staff, the BCP, and
16 other key stakeholders such as the Southwest Energy Efficiency Project,
17 National Resource Defense Council, the Governor’s Office of Energy and
18 SWG. Major topics of discussion included but were not limited to 2017
19 program results, new directives from legislation passed in 2017, the portfolio
20 of programs to be presented in the 2019-2021 DSM Plans, market potential
21 study, low-income programs and income qualifications, non-energy benefits
22 and cost-effectiveness analysis. The feedback and areas of consensus were
23 incorporated into the development of the DSM Plans.
24 Hart - IRP DIRECT 19
Page 21 of 198 1 17. Q. PLEASE DESCRIBE THE DSM PROGRAM SELECTION PROCESS.
2 A. Separate plan outlines for Nevada Power and for Sierra were developed
3 side-by-side, with the goal of crafting a DSM Plan that achieves or exceeds
4 a statewide energy savings goal of an average of 1.1 percent of weather
5 normalized retails sales over the Action Plan period. In addition the results
6 of the recently conducted market potential, net-to-gross and market
7 transformation studies were used to make informed decisions on projects
8 and project designs. The following describes the logic that was followed
9 in developing the set of programs within each of the component plans.
10
11 The Companies started with the 2018 portfolio of programs for Nevada
12 Power and Sierra previously approved by the Commission, and worked
13 with interested stakeholders to optimize the DSM product offerings and d/b/a NV Energy 14 meet a 1.1 percent energy savings goal statewide. In determining the mix Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 of programs, the Companies were guided by the results of the Market
16 Potential Study, supplemented with the legislatively mandated low-
17 income program.
18
19 Hundreds of energy efficiency and DR measures by sector, segments and
20 end use were evaluated in the Market Potential Study, from which they
21 were able to determine that a relatively small number of measures account
22 for the majority of savings in 2019-2021. In 2019, the following measures
23 account for 70 percent of market potential savings: commercial lighting,
24 Hart - IRP DIRECT 20
Page 22 of 198 1 residential smart thermostats, residential central air conditioning (“AC”)
2 (replace on burnout and retrofit), home energy reports, and residential
3 LED lighting. The pattern is fairly consistent across years, with the
4 exception of residential LEDs, where 2020 Energy Independence and
5 Security Act standard are set to take effect on January 1, 2020 which
6 causes savings to shift to the baseline. With the exception of residential
7 lighting and at Sierra a residential AC retrofit program, the Companies are
8 currently implementing programs that incorporate the top energy savings
9 measures. The process of identifying the top savings measures was then
10 applied at the company and sector level. This allowed the identification of
11 gaps in the residential sector compared to current set of programs. As a
12 result, the Nevada Power portfolio was expanded to include a residential
13 lighting program, a pool pumps program and expanded list of measures in d/b/a NV Energy 14 the residential air conditioning program. At Sierra, the proposed portfolio Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 adds a residential AC program and a residential lighting program. The
16 study also identified a greater potential for energy savings in the
17 commercial sector. The proposed DSM Plan expands Commercial
18 Services programs at both Companies to more accurately reflect the
19 market potential.
20
21 As noted earlier, the Companies are supportive of recent legislation that
22 extends their DSM offerings to low-income customers. The Companies
23 looked closely at low-income programs being conducted by other utilities
24 Hart - IRP DIRECT 21
Page 23 of 198 1 and/or state agencies to design a program that compliments rather than
2 competes with current low-income programs in Nevada. Several funding
3 sources already support bill assistance and weatherization in Nevada,
4 including the Universal Energy Charge. Thus the Companies have
5 designed a program that fills a gap by replacing older inefficient electric
6 appliances with new Energy Star® appliances.
7
8 18. Q. PLEASE DESCRIBE THE BENEFIT-COST RATIOS PRESENTED
9 IN THIS FILING.
10 A. The Table-Hart-Direct-1 below summarizes the potential benefits, the
11 relevant costs, and how each is allocated for each of the five perspectives
12 and the non-energy benefits test NTRC. Each assessment begins with the
13 benefits of DSM, measured by the Companies’ avoided cost, and subtracts d/b/a NV Energy 14 the costs associated with the program (such as equipment, labor, and Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 overhead). From a TRC perspective, an energy efficiency measure fails if
16 the net benefits are negative, meaning that the costs of achieving the
17 savings outweigh the value of the achieved savings. Often a program may
18 pass one test while failing others.
19
20
21
22
23
24 Hart - IRP DIRECT 22
Page 24 of 198 1 TABLE-HART-DIRECT -1
2
3
4
5
6
7
8 The six benefit-cost test ratio results presented in the DSM filings provide
9 guidance from multiple perspectives. The Companies emphasize that the
10 results should be used as only a guide and the Commission should use them
11 as such. For example, the Ratepayer Impact Measure ratio provides guidance
12 on the direction rates will be affected but does not give a clear reflection of
13 the magnitude of the rate impact. The Companies recommend the d/b/a NV Energy 14 Commission use a balanced approach when reviewing and approving a Nevada Power Company Company Power Nevada portfolio of DSM programs. The implementation of these programs can and and Sierra Pacific Power Company and Sierra Pacific Power Company 15
16 should strive to meet multiple objectives. Participants and all customers will
17 benefit in the short- and long-term if the Commission takes this balanced
18 approach. It is for this reason the Companies propose reasonable and
19 achievable energy savings targets that are a stretch goal but would allow
20 Nevada Power and Sierra to continue to provide multiple benefits to all
21 customer classes while limiting the rate impact to customers.
22
23
24 Hart - IRP DIRECT 23
Page 25 of 198 1 SECTION V: THE DSM PLAN FOR THE ACTION PLAN PERIOD
2 19. Q. PLEASE SUMMARIZE AND DESCRIBE THE DSM PLAN FOR
3 THE ACTION PLAN PERIOD?
4 A. The DSM Plan is the summation of the Nevada Power and Sierra
5 component plans, and is designed to meet or exceed statewide energy
6 savings averaging 1.1 percent of the weather normalized retail sales for
7 the 2019 through 2021 Action Plan period. Nevada Power and Sierra are
8 requesting Commission approval of the DSM Plan.
9
10 The DSM Plan contains a suite of programs that address the needs of both
11 the residential and business customers. The DSM Plan budget for the
12 Action Plan period is as follows: $64,600,000 ($49,800,000 at Nevada
13 Power and $14,800,000 at Sierra) in year 2019, $65,700,000 ($50,200,000 d/b/a NV Energy 14 at Nevada Power and $15,500,000 at Sierra) in year 2020, and Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 $66,700,000 ($50,600,000 at Nevada Power and $16,100,000 at Sierra) in
16 year 2021. Tables DSM-2A, DSM-2B, and DSM-2C in the DSM
17 Narrative of this filing provides the budgets broken out by company,
18 program, and year. The attendant estimated annual incremental energy
19 savings in megawatt-hours (“MWh”) for the DSM Plan is 346,410 MWh
20 (266,880 MWh at Nevada Power and 79,531 MWh at Sierra) in 2019,
21 340,118 MWh (258,421 MWh at Nevada Power and 81,697 MWh at
22 Sierra) in 2020 and 346,462 MWh (260,498 MWh at Nevada Power and
23 85,963 MWh at Sierra) in 2021. Tables DSM-12A, DSM-12B, and DSM-
24 Hart - IRP DIRECT 24
Page 26 of 198 1 12C provide the energy savings broken out by company, program and
2 year. The estimated incremental annual demand savings in megawatts
3 (“MW”) for the DSM Plan are 73.6 MW (57.1 MW at Nevada Power and
4 16.4 MW at Sierra) in 2019, 73.2 MW (56.5 MW at Nevada Power and
5 16.7 MW at Sierra) in 2020 and 73.9 MW (56.7 MW at Nevada Power
6 and 17.2 MW at Sierra) in 2021. Tables DSM-12A, DSM-12B, and DSM-
7 12C also provide the demand savings broken out by company, program,
8 and year.
9
10 20. Q. DID THE COMPANIES MAKE ANY FUNDAMENTAL CHANGES
11 TO THEIR IMPLEMENTATION STRATEGIES TO DELIVER THE
12 PORTFOLIO OF PROGRAMS PROPOSED IN THE FILING?
13 A. No. The Companies are continuing their implementation strategies, which d/b/a NV Energy 14 integrate energy efficiency and DR programs, by customer segment. Nevada Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 Power and Sierra are proposing integrated sets of services designed to
16 maintain a practical budget, optimize energy and demand savings, and
17 increase participation, all while using a more personalized and customized
18 approach. The programs have been bundled into the following offerings: 1)
19 Outreach and Program Development; 2) Home Services; and 3) Business
20 Services. Budgets, savings, and cost-effectiveness have been presented at the
21 program level to provide the same level of transparency as prior year filings.
22
23
24 Hart - IRP DIRECT 25
Page 27 of 198 1 21. Q. PLEASE EXPLAIN THE BENEFITS OF AN INTEGRATED
2 APPROACH.
3 A. A fully integrated approach is optimal because it leverages the benefits of
4 multiple programs based on individual customer needs. This implementation
5 style simplifies the process for customers to participate in one or more
6 program at the same time, and it achieves economies of scale by spreading
7 costs over multiple programs.
8
9 In addition, the Companies continue to utilize previous investments in
10 upgraded technologies and systems to proactively use comprehensive
11 analytic tools, such as disaggregated energy consumption data, powerful data
12 analytic tools, billing histories, weather data, customer segmentation,
13 appliance analysis and information gathered from third party sources. These d/b/a NV Energy 14 modern tools provide relevant actionable analysis, which leads to specific Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 action plans, which may be used by the customer to manage energy use by
16 improving home function, upgrading appliances and equipment, and
17 changing energy use behavior.
18
19 22. Q. ARE EITHER NEVADA POWER OR SIERRA PROPOSING TO
20 DISCONTINUE ANY PROGRAMS THAT ARE CURRENTLY IN
21 THEIR INDIVIDUAL 2018 DSM PORTFOLIOS?
22 A. No.
23
24 Hart - IRP DIRECT 26
Page 28 of 198 1 23. Q. WHY SHOULD THE COMMISSION DETERMINE THAT THE
2 DSM PLAN REPRESENTS AN APPROPRIATE INVESTMENT IN
3 DSM PROGRAMS?
4 A. The DSM Plan is cost effective and provides multiple benefits to
5 customers and the communities in which they live. The following
6 summarize the most significant of these benefits:
7 1. The portfolio of programs included in the DSM Plan provides
8 customers with viable options for managing their energy consumption
9 and reducing their bills.
10 2. The DSM Plan helps address the future open capacity position of the
11 Companies through cost effective energy efficiency and demand
12 savings.
13 3. The energy savings provide very significant environmental benefits as d/b/a NV Energy 14 shown on Tables DSM-14A, DSM-14B and DSM-14C in the DSM Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 Narrative. Table DSM-14C depicts the Companies’ annual composite
16 emission savings for the DSM Plan. As an example of environmental
17 benefits, over the life of the measures installed carbon dioxide
18 emissions statewide will be reduced by 1,213,661 tons. The energy
19 savings provide very significant environmental benefits as shown on
20 Tables DSM-19A, DSM-19B and DSM-19C in the DSM Narrative.
21 4. The TRC cost-benefit ratio for the DSM Plan is 2.15 (2.17 at Nevada
22 Power and 2.11 at Sierra). The TRC results show that the estimated
23 benefits provided by the portfolio of programs exceed the costs
24 Hart - IRP DIRECT 27
Page 29 of 198 1 associated with the portfolio. A TRC ratio exceeding 1.0 means the
2 cost for electric energy is reduced for the community in aggregate. As
3 proposed, the portfolio of programs would provide a statewide net
4 benefit of over $295 million ($227 million at Nevada Power and $68
5 million at Sierra) as shown on Tables DSM-13A, DSM-13B and
6 DSM-13C in the DSM Narrative.
7 5. The DSM Plan provides opportunities for all retail customers to
8 participate in energy efficiency programs.
9 6. As described in the DSM Narrative of this filing, the DSM Plan will
10 create approximately 1,820 jobs each year of the three-year plan.
11 7. The DSM Plan continues almost two decades of momentum produced
12 through the existing fleet of Commission-approved programs, and
13 keeps intact the core of local contractors who have become important d/b/a NV Energy 14 program partners (and community members) in the delivery of the Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 programs. These benefits will be provided for all customers and
16 communities served.
17
18 24. Q. WHAT PROGRAMS ARE INCLUDED IN THE PROPOSED DSM
19 PLAN?
20 A. The following programs are included in the DSM Plan.
21 1. Outreach and Program Development
22 a. Energy Education Program
23 b. Energy Reports Program
24 Hart - IRP DIRECT 28
Page 30 of 198 1 c. Energy Assessments Program
2 d. Program Development
3 2. Home Services
4 a. Residential Lighting Program
5 b. Pool Pumps Program (Nevada Power only)
6 c. Low Income Program
7 d. Residential Air Conditioning Program
8 e. Direct Install Program
9 f. Residential Demand Response (Manage and Build)
10 3. Business Services
11 a. Schools Program
12 b. Commercial Program (including Non-Profit)
13 c. Commercial Demand Response (Manage and Build) d/b/a NV Energy 14 Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 25. Q. PLEASE DESCRIBE THE PROGRAMS WITHIN THE OUTREACH
16 AND EDUCATION PROGRAM DEVELOPMENT CATEGORY.
17 A. The Outreach and Education category of programs focuses on increasing
18 awareness and participation in the Companies’ DSM products and services.
19 The Outreach component is represented by three programs: Energy
20 Education, Energy Reports and Energy Assessments. In addition, Program
21 Development, formerly known as Market and Technology Trials Program, is
22 presented in this section.
23
24 Hart - IRP DIRECT 29
Page 31 of 198 1 The Commission has noted that energy use education is a vital part of
2 promoting awareness of energy efficiency opportunities. 4 Education is a
3 very significant part of the DSM portfolio because it provides a gateway for
4 awareness that will lead customers to participate in DSM programs or
5 undertake energy efficiency measures independent of the available DSM
6 programs.
7
8 The Energy Reports category of programs as proposed is comprised of two
9 sections: Home Energy Reports and Business Energy Reports. The Energy
10 Reports program provides periodic energy usage reports to residential and
11 business customers to inform and motivate them to take actions to save
12 energy by using electricity more efficiently and to drive participation in other
13 DSM programs. Based upon two primary objectives, the Energy Reports d/b/a NV Energy 14 program focuses on achieving two results. First, it seeks to motivate Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 customers to change or modify their behavior in context with similar
16 households or businesses. Second, it seeks to provide customers with
17 personalized information, energy-saving products and services, and practical
18 ways to save energy and money.
19
20 The Energy Assessments category of programs provide energy assessment
21 services to a large number customers, enabling them to save energy and
22
23 4 See, Commission’s Modified Order issued February 12, 2016 in Sierra’s and Nevada Power’s Consolidated Dockets Nos. 15-06065 and 15-07004, Paragraph 60, page 21. 24 Hart - IRP DIRECT 30
Page 32 of 198 1 reduce energy bills. This program supplements and supports the Energy
2 Education Program, and also works as a gateway to participation in other
3 DSM programs. The program is comprised of two components: a remote or
4 online assessment, and an assessment conducted in the home by a certified
5 energy consultant. The overall goal of this program is to educate customers
6 about wise energy use and choices, and to assist them in taking action to
7 reduce energy consumption and lower energy bills.
8
9 The Program Development category focuses on the development and
10 testing of innovative DSM technologies and program delivery models.
11 Program Development may span residential, commercial, industrial, or
12 agricultural customer segments and aims to identify new methods to increase
13 customer satisfaction and realize energy and demand savings through d/b/a NV Energy 14 delivering energy services to customers. Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15
16 Details of each program are provided in Section 5 of the DSM Plan.
17
18 26. Q. PLEASE DESCRIBE THE PROGRAMS WITHIN HOME SERVICES
19 CATEGORY.
20 A. A variety of residential services will be available to the approximately 1.1
21 million residential electric customers in the Companies’ combined service
22 territories. Residential customers reside in single-family or multi-family
23 homes. To address this varied set of customers, the Company will continue
24 Hart - IRP DIRECT 31
Page 33 of 198 1 to offer a bundled set of products and services targeted to reach the vast
2 majority of the residential market and provide customers with multiple
3 opportunities to participate.
4
5 The portfolio of home services seeks to provide customers with simple ways
6 to begin to participate in the program, while encouraging them to make long-
7 term commitments to reduce their energy usage. The proposed portfolio of
8 home services is therefore designed with multiple points of entry, through
9 Residential Lighting, Pool Pumps, Low Income, Direct Install, Residential
10 Air Conditioning, Residential Demand Response, Energy Education, Energy
11 Assessments and Energy Reports.
12
13 The Residential Lighting Program provides incentives to encourage d/b/a NV Energy 14 customers to purchase and install energy efficient lighting products through Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 an upstream model that partners with manufacturers and retailers. The
16 Residential Lighting Program will provide discounted pricing on high quality
17 LEDs at participating retail locations. The Residential Lighting Program
18 measures will consist of ENERGY STAR®-qualified general service,
19 reflectors and specialty LEDs. LED lamps will be available in various
20 wattage equivalents and will be sold by participating retailers within the
21 Company’s service territory. The Companies will provide incentives to
22 manufactures for participating LEDs that will be discounted at point of
23 purchase so customers will see immediate price reductions.
24 Hart - IRP DIRECT 32
Page 34 of 198 1 The Pool Pump Program provides incentives for upgrading inefficient
2 single-speed pumps to more energy efficient variable-speed pumps.
3 Swimming pool filtration pumps are typically the second largest user of
4 energy in homes with residential swimming pools in the hot and dry
5 southwest desert climate. The vast majority of existing pool pumps are
6 conventional, single-speed units.
7
8 Replacing an inefficient single-speed pump with a variable-speed pump can
9 decrease energy use up to 80 percent. This can be achieved by operating pool
10 pumps at optimal speeds with additional savings achieved by properly sizing
11 the pool pump for the application. Variable-speed pool pumps are designed
12 to reduce heat and friction losses within the motor for additional energy
13 savings and longer equipment life. d/b/a NV Energy 14 Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 The Pool Pump Program will target residential customers in Nevada Power’s
16 service territory only, via retail, builder and pool sales channels. The Pool
17 Pump Program will provide incentives to these industry partners for offering
18 instant, point-of-purchase discounts (incentives) on variable-speed pumps.
19
20 The Low Income Program is designed to provide energy efficient
21 appliances and products to low or limited income customers who experience
22 high energy bills due to the costs of operating old and inefficient appliances.
23 The Low Income Program will work in collaboration with state and local
24 Hart - IRP DIRECT 33
Page 35 of 198 1 agencies, including the Southern Nevada Housing Authority, state
2 weatherization programs and other agencies serving this market sector to
3 develop delivery mechanisms to reach customers quickly and directly.
4 Appliances and products provided under this program will all be ENERGY
5 STAR® rated. The appliances included in the proposed program are
6 refrigerators, dishwashers, plug load controllers, clothes dryers, window air
7 conditioners (as replacements to existing window units only), LED bulbs and
8 residential lighting controls, also known as proximity sensors.
9
10 The Residential Air Conditioning Program uses a mid-stream approach
11 that is expected to encourage homeowners to purchase premium efficiency
12 air conditioners and heat pumps. Options will be available to customers both
13 as an early replacement to more efficient equipment option, or to a high- d/b/a NV Energy 14 efficiency upgrade option upon equipment failure. A reduction in the required Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 air conditioning tonnage may also off-set the incremental cost associated with
16 the higher efficiency unit.
17
18 The program will also promote high-efficiency air conditioning installed by
19 builders at the time of construction in both single and multi-family housing
20 along with a low income component that provides air conditioning tune-ups,
21 repair work, and covers the most if not all of the cost of upgrading to higher
22 efficiency air conditioning when an air conditioning system fails.
23
24 Hart - IRP DIRECT 34
Page 36 of 198 1 The Direct Install Program provides residential customers with direct
2 installation of low-cost energy efficient measures in their homes. The
3 installation of the measures is performed by a trained and certified
4 PowerShift, Energy Advisor and will further enhance the value proposition
5 when implemented in combination with energy assessments and smart
6 thermostat offerings. The measures are intended to introduce the customers
7 to products available in the market which reduce the associated costs of
8 energy consumption. Available direct installation measures include, air
9 filter/furnace filter change out; LED lighting; photocells installed in each
10 socket of indoor and outdoor lighting fixtures; refrigerator thermometer; and
11 air conditioner refrigerant line insulation on outside condenser unit.
12
13 The DR Program recruits customers into an ongoing program in which the d/b/a NV Energy 14 customers allow the Companies to temporarily interact with their end-use Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 loads such as air conditioning on hot summer days when system peak loads
16 occur or during emergency conditions in order to help the Company reduce
17 peak demand. This is accomplished through DR events in which devices
18 controlling customers’ end-use loads receive signals from utility DR systems
19 to reduce energy consumption. These events shift a significant amount of
20 energy consumption outside of the peak demand hours. In return for their
21 participation in these events, the DR Program delivers a package of enabling
22 technology that helps customers save energy and money all year round. The
23 Company’s primary strategy for engaging customers in DR has been to
24 Hart - IRP DIRECT 35
Page 37 of 198 1 provide customers with technologies and services that create tangible
2 operational and energy efficiency benefits.
3
4 Details of each program are provided in Section 6 of the DSM Plan.
5
6 27. Q. PLEASE DESCRIBE THE DSM PROGRAMS WITHIN BUSINESS
7 SERVICES CATEGORY.
8 A. DSM Business Services will continue to offer programs to approximately
9 156,000 electric commercial and industrial customers. The Companies divide
10 business customers into two large sub-segments for outreach purposes: large
11 customers, and small/medium business customers. Large customers are
12 typically single or aggregated electric customers with demand usage of over
13 500 kW. These are often national customers, such as fast-food chains. Large d/b/a NV Energy 14 customers have Companies account managers assigned to them to serve as a Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 liaison. Small business customers work with our Business Solutions Center
16 to get answer any questions they may have on their accounts and to
17 investigate potential energy efficiency projects. The portfolio of business
18 services is based on Schools Program, Commercial Program, and
19 Commercial Demand Response Programs and is augmented by the
20 educational programs; Energy Education and Energy Reports.
21
22 The Schools Program is designed to facilitate energy efficiency and peak
23 demand reduction in public schools. The Schools Program offers two types
24 Hart - IRP DIRECT 36
Page 38 of 198 1 of energy services to school administrators. First, rebates help offset a portion
2 of the first cost associated with efficiency investments for energy efficiency
3 projects. Second, the program provides a high level of technical assistance
4 that serves to offset the staffing needs for school facility management that
5 would be required for administering energy efficiency projects.
6
7 The Commercial Program is designed to generate long-term energy savings
8 and peak demand reduction. A longer term goal of the Commercial Program
9 is to influence building owners, managers, architects, engineers, contractors
10 and others to realize the benefits of incorporating energy efficiency into both
11 retrofit and new construction projects. The Commercial Program facilitates
12 the implementation of energy efficient measures in both existing and new
13 commercial and industrial facilities through providing rebates and d/b/a NV Energy 14 comprehensive technical services. The retrofit portion of the Commercial Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 Program offers per-unit prescriptive rebates for energy efficient lighting,
16 cooling, motors, commercial kitchens, refrigeration and miscellaneous
17 energy conservation measures. Additionally, custom rebates for most
18 measures not covered under the prescriptive component that results in
19 verifiable energy savings. The new construction portion of the Commercial
20 Program offers rebates for single pieces of equipment, entire systems, and
21 whole buildings. In order for projects to qualify for a rebate, projects must
22 exceed the applicable IECC or applicable local building code by at least 10
23 percent of the 2009 IECC or 5 percent of the 2012 IECC.
24 Hart - IRP DIRECT 37
Page 39 of 198 1 The Non-Profit Agency Grant component of the Commercial Program
2 offers qualifying non-profit organizations the financial means to implement
3 energy efficiency measures. This component provides financial assistance in
4 the form of rebates and technical support to non-profit organizations for the
5 identification and installation of energy efficiency measures in new or
6 existing buildings. To qualify, an agency must be a 501(c)3 of the Internal
7 Revenue Code entity located within the Companies’ service territories. The
8 Companies aid these organizations by identifying areas where they can
9 incorporate energy saving materials, equipment and/or construction methods
10 into their buildings to reduce energy consumption. Non-profit agencies
11 benefit from this Program in two ways: First, by receiving free technical
12 support and reducing or eliminating the cost associated with installing energy
13 efficiency measures; and second, by effectively lowering the monthly utility d/b/a NV Energy 14 cost that enables the non-profit organizations to provide more services to the Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 community.
16
17 The Commercial DR Program recruits customers into an ongoing program
18 in which the customers allow the Companies to temporarily interact with their
19 end-use loads such as air conditioning on hot summer days when system peak
20 loads occur or during emergency conditions in order to help the Companies
21 reduce peak demand. This is accomplished through “DR events” in which
22 devices controlling customers’ end-use loads receive signals from utility DR
23 systems to reduce energy consumption. These events shift a significant
24 Hart - IRP DIRECT 38
Page 40 of 198 1 amount of energy consumption outside of the peak demand hours. In return
2 for their participation in these events, the program delivers a package of
3 enabling technology that helps customers save energy and money all year
4 round. The Companies’ primary strategy for engaging customers in DR has
5 been to provide customers with technologies and services that create tangible
6 operational and energy efficiency benefits.
7
8 Details of each program are provided in Section 7 of the DSM Plan.
9
10 28. Q. WILL THE PROPOSED DSM PLAN PROVIDE THE MAXIMUM
11 CONTRIBUTION TO THE RENEWABLE PORTFOLIO
12 STANDARD (“RPS”) THAT IS ALLOWED FROM ENERGY
13 EFFICIENCY THROUGHOUT THE 2019-2021 PERIOD? d/b/a NV Energy 14 A. Yes. Pursuant to NRS § 704.7821(2)(b) the Companies can use portfolio Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 credits generated by energy efficiency measures to meet a declining
16 portions of the annual RPS requirement. The Companies estimate that
17 including the projected energy savings in the DSM Plan for the Action
18 Plan period, they will have in place adequate measured and verified
19 savings from energy efficiency measures to provide the full annual amount
20 allowed through at least 2020.
21
22
23
24 Hart - IRP DIRECT 39
Page 41 of 198 1 29. Q. WHY DID THE COMPANIES INCLUDE ENERGY SAVINGS FROM
2 THE OUTREACH AND EDUCATION PROGRAMS IN ITS ENERGY
3 SAVINGS CALCULATIONS?
4 A. The draft regulations implementing SB150 and AB223 state “Establishment
5 of goals for energy savings resulting from all energy efficiency programs
6 implemented by an electric utility each…”5 The energy savings produced
7 through the DSM Plan should be included in the Companies’ annual total
8 energy savings. It is not uncommon for utilities to conduct M&V on outreach
9 and education programs and claim the resulting savings. As seen in 2017,
10 both the Energy Reports and Energy Assessments programs produced
11 verified savings based on the M&V conducted by ADM Associates.
12
13 30. Q. DID THE COMPANIES PRESENT ENERGY SAVINGS FROM THE d/b/a NV Energy 14 SITE OR THE SOURCE PERSPECTIVE? Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 A. The Companies present the more conservative energy savings values at the
16 site level (at the customers home or business) only, and do not include
17 additional energy and demand savings from the generating source. Energy
18 and demand savings are subject to line loss as the energy moves from
19 generating source to the customer home. While not claimed in the savings
20 values presented in the M&V reports or in the projected energy savings
21 tables, line loss is an input used in the cost-effectiveness modeling. The line
22
23 5 Proposed Regulation, Docket Nos. 17-07011 and 17-08023, Section 4. 24 Hart - IRP DIRECT 40
Page 42 of 198 1 losses for energy at Nevada Power are 3.8 percent and 6.3 percent at Sierra.
2 It is important to note that the implementation of DSM programs will also
3 provide line loss savings of 15,205 MWh statewide (10,195 MWh at Nevada
4 Power and 5,010 MWh at Sierra) in 2019, 15,019 MWh statewide (9,872
5 MWh at Nevada Power and 5,147 MWh at Sierra) in 2020, and 15,367 MWh
6 statewide (9,951 MWh at Nevada Power and 5,416 MWh at Sierra) in 2021.
7
8 31. Q. WHY DID THE COMPANIES CHOOSE TO REINSTATE THE
9 RESIDENTIAL LIGHTING AND POOL PUMP PROGRAMS,
10 WHICH WERE PREVIOUSLY DISCONTINUED?
11 A. The Companies have chosen to redesign and reinstate the residential lighting
12 program and the pool pump program (Nevada Power only), due in large part
13 to the significant energy and demand savings identified in the Market d/b/a NV Energy 14 Potential Study. The measures in the programs are in the top ten of all DSM Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 measures that save the majority of the overall savings. The programs have
16 been redesigned to better deliver these measures, and their savings potential.
17 As now proposed, both offerings are cost effective, as demonstrated by the
18 TRC results presented in Tables DSM-13A, DSM-13B and DSM-13C of the
19 DSM Narrative.
20
21 SECTION VI: COMPLIANCE ITEMS AND DIRECTIVES
22 32. Q. PLEASE DESCRIBE THE DIRECTIVE CONTAINED IN THE
23 STIPULATION APPROVED BY THE COMMISSION IN DOCKET
24 Hart - IRP DIRECT 41
Page 43 of 198 1 NOS. 16-07001 AND 16-07007, WHICH REQUIRES THE
2 COMPANIES TO REPORT IN THEIR 2018 JOINT INTEGRATED
3 RESOURCE PLAN ON THEIR ASSESSMENT OF THE
4 INTERACTION BETWEEN DR PROGRAMS AND PHOTO-
5 VOLTAIC SYSTEMS.
6 A. In Docket Nos. 16-07001 and 16-07007 the Companies agreed in a
7 Stipulation that was subsequently approved by the Commission that to report
8 in this filing their assessment of the interaction, if any, between DR and
9 photo-voltaic systems. After the order accepting the stipulation was issued
10 (December 23, 2016), Senate Bill 146 (“SB 146”) was enacted by the 2017
11 session of the Nevada Legislature. This bill requires the Companies to
12 develop and file distributed energy resources (“DER”) plans, the first of
13 which must be filed no later than April 1, 2019. The statute characterizes both d/b/a NV Energy 14 solar PV and DR as Distributed Energy Resources. Regulations Nevada Power Company Company Power Nevada
and Sierra Pacific Power Company and Sierra Pacific Power Company 15 implementing SB 146 are currently being drafted, but the interplay between
16 distributed energy resources as well as between traditional utility solutions to
17 distribution constraints are expected to be necessary components of the DER
18 analysis.
19
20 33. Q. DOES THIS COMPLETE YOUR TESTIMONY.
21 A. Yes, it does.
22
23
24 Hart - IRP DIRECT 42
Page 44 of 198 Exhibit Hart-Direct-1 Page 1 of 1
STATEMENT OF QUALIFICATIONS ANITA L. HART NEVADA POWER COMPANY d/b/a NV Energy SIERRA PACIFIC POWER COMPANIES d/b/a NV Energy 6226 W. Sahara Ave. Las Vegas Nevada 89146 (702) 402-2165
EDUCATION NEW MEXICO STATE UNIVERSITY – Las Cruces, New Mexico Master of Art in Economics – Emphasis in Public Utilities and Regulatory Economics Bachelor of Art in Economics
PROFESSIONAL EXPERIENCE NV ENERGY – Las Vegas, Nevada (August 2008 to Present) Director – Demand Side Management, Customer Strategy and Programs x Oversight of the Demand Side Management team x Development and implementation, analysis and cost recovery of cost-effective statewide demand side management programs which provide exceptional service to customers.
Manager – Gas Transportation Planning, Resource Planning and Analysis x Planning and analysis of natural gas transportation needs to ensure sufficient supply to the generation fleet and natural gas customers. x Development and implementation of work plans to support corporate contract negotiations, planning, budgeting, controls, portfolio optimization, cost reduction, and risk management.
Consultant Staff – DSM Planning, Customer Strategy & Programs x Team member assisting in the development and implementation, analysis and cost recovery of statewide demand side management programs.
SOUTHWEST GAS CORPORATION – LAS Vegas, Nevada (1993 to 2008) Manager – State Regulatory Affairs/Research, Conservation and DSM x Oversight of the Demand Side Management team x Development, implementation, evaluation and reporting of DSM and low income assistance programs in the Southwest Gas Corporation’s tristate service territories. x Directed the development and implementation of customer market research.
Page 45 of 198 Exhibit Hart-Direct-1 Page 1 of 1
Senior Specialist – State Regulatory Affairs x Prepared and maintained tariffs, applications, and filings before three state regulatory agencies, consistent with regulatory, legal and company requirements.
Administrator and Specialist – Marketing/Conservation and DSM x Team member assisting in the development, implementation, evaluation and reporting of DSM and low income assistance programs in the Southwest Gas Corporation’s tristate service territories.
Regulatory Analyst – Revenue Requirements and Resource Planning x Collection, maintenance and statistical analysis of customer profile data.
PUBLIC SERVICE COMPANY OF NEW MEXICO – ALBUQUERQUE, New Mexico (Summer 1992) Student Intern – Regulation and Market Communication x Completion of a retail wheeling study.
BOARDS AND HONORS
SOUTHWEST ENERGY EFFICIENCY PROJECT (“SWEEP”) x 2016 Board of Directors, Member
LAS VEGAS METRO CHAMBER OF COMMERCE FOUNDATION x 2015 Leadership Las Vegas, Graduate
Page 46 of 198 Exhibit Hart-Direct-2 Page 1 of 3
Nevada Power Company - 2017 Financial Results
Variance from Programs 2017 Approved 2017 Actual Approved Budget Budget Expenditures (%) Energy Education $400,000 $400,567 0.1% Energy Reports $1,200,000 $943,606 (21.4%) Energy Assessments $3,500,000 $2,222,104 (36.5%) Program Development $400,000 $334,268 (16.4%) Education Services Total $5,500,000 $3,900,544 (29.1%)
Residential Air Conditioning $7,000,000 $6,237,363 (10.9%) Residential Demand Response - Manage $7,600,000 $5,852,210 (23.0%) Residential Demand Response - Build $7,500,000 $7,016,381 (6.4%) Residential Services Total $22,100,000 $19,105,955 (13.5%)
Schools $1,600,000 $1,402,427 (12.3%) Commercial Services $11,150,000 $12,439,622 11.6% Commercial Demand Response - Manage $1,150,000 $895,044 (22.2%) Commercial Demand Response - Build $1,500,000 $1,470,947 (1.9%) Market Potential Study $175,758 0.0% Commercial Services Total $15,400,000 $16,383,798 6.4%
Total DSM Programs $43,000,000 $39,390,297 (8.4%) Note: Includes recapture funds
Nevada Power Company – 2017 Energy and Demand Saving Results
Demand kW Energy kWh Variance Verified Variance Verified Over Lifetime Programs Target Demand Over Target Energy EUL (Under) savings Savings (Under) % Savings %
Residential Air Conditioning 7,125 5,267 (26.1%) 13,300,000 10,937,357 (17.8%) 13.0 142,185,641 Residential Demand Response - Manage 189,044 180,890 (4.3%) 21,982,000 19,753,922 (10.1%) 4.0 79,015,688 Residential Demand Response - Build 23,000 23,590 2.6% 4,535,000 3,659,813 (19.3%) 10.0 36,598,130 Residential Services Total 219,169 209,747 (4.3%) 39,817,000 34,351,092 (13.7%) 9.0 257,799,459
Schools 505 2,749 444.4% 10,660,000 12,542,061 17.7% 12.5 156,148,659 Commercial Services 9,568 15,798 65.1% 90,000,000 135,176,397 50.2% 11.7 1,581,563,845 Commercial Demand Response - Manage 27,184 16,529 (39.2%) 4,420,000 7,677,895 73.7% 5.0 38,389,475 Commercial Demand Response - Build 5,000 2,897 (42.1%) 2,700,000 1,310,511 (51.5%) 10.0 13,105,110 Commercial Service Total 42,257 37,973 11.3% 107,780,000 156,706,864 45.4% 9.8 1,789,207,089
Total DSM 261,426 247,720 (5.2%) 147,597,000 191,057,956 29.4% 18.8 2,047,006,548
Page 47 of 198 Exhibit Hart-Direct-2 Page 2 of 3
Sierra Pacific Power Company – 2017 Financial Results
2017 Variance from Programs 2017 Actual Approved Approved Budget Expenditures Budget (%) Energy Education $300,000 $282,156 (5.9%) Energy Reports $700,000 $597,572 (14.6%) Energy Assessments $1,700,000 $1,224,157 (28.0%) Program Development $100,000 $54,055 (45.9%) Education Services Total $2,800,000 $2,157,940 (22.9%)
Residential Demand Response - Manage $500,000 $448,643 (10.3%) Residential Demand Response - Build $2,200,000 $2,428,553 10.4% Residential Services Total $2,700,000 $2,877,196 6.6%
Schools $400,000 $361,400 (9.7%) Commercial Services $4,600,000 $4,425,553 (3.8%) Commercial Demand Response - Manage $450,000 $261,775 (41.8%) Commercial Demand Response - Build $750,000 $801,004 6.8% Market Potential Study $75,309 0.0% Commercial Services Total $6,200,000 $5,925,041 (4.4%)
Total DSM Programs $11,700,000 $10,960,177 (6.3%)
Sierra Pacific Power Company – 2017 Energy and Demand Saving Results
Demand kW Energy kWh Variance Variance Verified Verified Over Over Lifetime Programs Target Demand Target Energy EUL (Under) (Under) savings Savings Savings % %
Residential Demand Response - Manage 7,419 7,373 (0.6%) 1,004,000 1,188,915 18.4% 8.00 9,511,320 Residential Demand Response - Build 7,000 6,503 (7.1%) 1,272,000 761,727 (40.1%) 10.00 7,617,270 Residential Services Total 14,419 13,876 (3.8%) 2,276,000 1,950,642 (14.3%) 9.00 17,128,590
Schools 314 471 50.0% 2,500,000 3,253,549 30.1% 15.00 48,803,235 Commercial Services 4,648 7,000 50.6% 34,000,000 50,803,353 49.4% 12.70 645,202,583 Commercial Demand Response - Manage 1,200 2,405 100.4% 375,000 130,440 (65.2%) 9.00 1,173,960 Commercial Demand Response - Build 2,000 1,573 (21.3%) 450,000 228,553 (49.2%) 10.00 2,285,530 Commercial Service Total 8,162 11,449 40.3% 37,325,000 54,415,895 45.8% 11.68 697,465,308
Total DSM 22,581 25,325 12.2% 39,601,000 56,366,537 42.3% 20.68 714,593,898
Page 48 of 198 Exhibit Hart-Direct-2 Page 3 of 3
NV Energy – 2017 Financial Results
Variance from Programs 2017 Approved 2017 Actual Approved Budget Budget Expenditures (%) Energy Education $700,000 $682,723 (2.5%) Energy Reports $1,900,000 $1,541,178 (18.9%) Energy Assessments $5,200,000 $3,446,261 (33.7%) Program Development $500,000 $388,323 (22.3%) Education Services Total $8,300,000 $6,058,484 (27.0%)
Residential Air Conditioning $7,000,000 $6,237,363 (10.9%) Residential Demand Response - Manage $8,100,000 $6,300,853 (22.2%) Residential Demand Response - Build $9,700,000 $9,444,934 (2.6%) Residential Services Total $24,800,000 $21,983,151 (11.4%)
Schools $2,000,000 $1,763,827 (11.8%) Commercial Services $15,750,000 $16,865,175 7.1% Commercial Demand Response - Manage $1,600,000 $1,156,819 (27.7%) Commercial Demand Response - Build $2,250,000 $2,271,951 1.0% Market Potential Study $0 $251,067 0.0% Commercial Services Total $21,600,000 $22,308,839 3.3%
Total DSM Programs $54,700,000 $50,350,474 (8.0%)
NV Energy – 2017 Energy and Demand Saving Results
Demand kW Energy kWh Variance Variance Verified Verified Over Over Lifetime Programs Target Demand Target Energy EUL (Under) (Under) savings Savings Savings % %
Residential Air Conditioning 7,125 5,267 (26.1%) 13,300,000 10,937,357 (17.8%) 13.0 142,185,641 Residential Demand Response - Manage 196,463 188,263 (4.2%) 22,986,000 20,942,837 (8.9%) 6.0 88,527,008 Residential Demand Response - Build 30,000 30,093 0.3% 5,807,000 4,421,540 (23.9%) 10.0 44,215,400 Residential Services Total 233,588 223,623 (4.3%) 42,093,000 36,301,734 (13.8%) 9.7 274,928,049
Schools 819 3,220 293.2% 13,160,000 15,795,610 20.0% 13.7 204,951,894 Commercial Services 14,216 22,798 60.4% 124,000,000 185,979,750 50.0% 12.2 2,226,766,428 Commercial Demand Response - Manage 28,384 18,934 (33.3%) 4,795,000 7,808,335 62.8% 7.0 39,563,435 Commercial Demand Response - Build 7,000 4,470 (36.1%) 3,150,000 1,539,064 (51.1%) 10.0 15,390,640 Commercial Service Total 50,419 49,422 2.0% 145,105,000 211,122,759 45.5% 10.7 2,486,672,397
Total DSM 284,007 273,045 (3.9%) 187,198,000 247,424,493 32.2% 20.4 2,761,600,446
Page 49 of 198 Exhibit Hart-Direct-3 Page 1 of 3
Nevada Power Company – 2019-2021 DSM Targets 3 6 3 5 1 2 8 4 2 4 4 5 1 4 4 7 6 9 5 3 8 6 6 6 3 1 1 2 5 6 2 2 1 8 ...... N/A 1 1 5 1 2 2 6 0 1 0 0 2 2 2 0 2 0 10.68 TRC Ratio N/A Net Benefits $ 10,837,507 $ 67,471,315 $ 89,919,844 $ 49,391,603 $ 82,673,684 $ 5,361,812 $ 6,249,210 $ 3,503,095 $ 3,587,544 $ 4,594,782 $ 4,367,917 $ (5,115,305) $ (4,059,416) $ (1,430,062) $ (780,547) $ (909,539) $ 138,683,880 $ 227,173,662 4.0 1.8 0.1 1.5 0.2 0.3 0.7 1.5 0.6 0.1 1.9 N/A 18.0 23.8 28.0 31.1 56.7 TBD TBD 2021 4.0 1.8 0.1 1.5 0.2 0.3 0.7 1.5 1.0 0.1 1.9 N/A 17.4 23.2 28.0 31.4 56.5 TBD TBD 2020 4.0 1.7 0.1 1.5 0.2 0.3 0.6 1.5 1.2 0.1 1.9 N/A 18.0 23.7 28.0 31.6 57.1 TBD TBD 2019 Demand Savings (MW) Demand Savings (MW) N/A 1,000 3,600 1,000 1,435 2,700 6,490 5,314 1,155 15,500 10,148 27,414 58,796 13,543 13,300 17,155 2021 157,900 184,548 260,498 N/A 1,000 3,600 1,000 1,435 2,700 6,490 8,537 1,155 15,500 10,148 27,414 62,019 13,543 13,300 17,155 2020 152,600 179,248 258,421 N/A Energy Savings (MWh) Savings (MWh) Energy 1,000 3,600 1,000 1,435 2,700 5,310 1,155 14,500 10,148 27,414 62,977 13,543 13,300 10,675 17,155 2019 161,100 186,748 266,880 2021 $500,000 $300,000 $500,000 $1,700,000 $1,700,000 $1,000,000 $7,300,000 $7,700,000 $7,000,000 $2,000,000 $2,500,000 $1,200,000 $1,200,000 $1,000,000 $4,500,000 $15,000,000 $19,400,000 $50,600,000 $26,700,000 2020 $900,000 $500,000 $300,000 $500,000 $1,700,000 $1,700,000 $7,100,000 $7,500,000 $7,000,000 $2,000,000 $2,500,000 $1,200,000 $1,200,000 $1,600,000 $4,500,000 Budget ($) $14,500,000 $18,800,000 $50,200,000 $26,900,000 2019 $800,000 $500,000 $200,000 $500,000 $1,700,000 $1,600,000 $7,000,000 $7,300,000 $7,000,000 $2,000,000 $2,500,000 $1,000,000 $1,200,000 $2,000,000 $4,400,000 $14,500,000 $18,600,000 $49,800,000 $26,800,000 Subtotal - Home Services Subtotal - Business Services Total DSM Programs DSM Programs Total Nevada Power CompanyNevada Power Commercial Services Services Commercial Commercial Demand Response - Build Demand Response - Build Commercial Commercial Demand Response - Manage Demand Response - Manage Commercial Schools Program Program Schools Residential Demand Response - Build Demand Response - Build Residential Residential Demand Response - Manage Demand Response - Manage Residential Direct Install Install Direct Program Development Development Program Residential Air Conditioning Conditioning Air Residential Low Income Energy Assessments Assessments Energy Pool PumpsPool Energy Reports Energy Residential Lighting Lighting Residential Energy Education Education Energy total - Outreach & Program Development b
Page 50 of 198 Exhibit Hart-Direct-3 Page 2 of 3
Sierra Pacific Power Company – 2019-2021 DSM Targets 4 2 0 1 3 0 3 3 3 1 7 4 4 4 0 4 4 2 3 1 3 9 1 7 2 8 0 1 8 5 6 2 ...... N/A 0 0.29 0 2 2 2 1 1 3 2 2 2 0 1 3 5 0 TRC Ratio N/A Net Benefits $ 43,937,016 $ 68,366,739 $ 32,186,586 $ 23,688,755 $ 10,311,226 $ 14,238,041 $ 2,722,807 $ 3,427,862 $ 4,302,004 $ 4,020,564 $ 4,226,748 $ (1,962,103) $ (1,412,960) $ 740,968 $ (2,729,495) $ (208,256) $ (756,285) 0.0 0.1 0.1 9.2 2.0 0.3 6.7 1.5 0.5 0.2 6.5 6.0 1.3 0.1 N/A 17.2 TBD TBD 2021 0.0 0.1 0.1 0.5 8.9 2.0 6.4 1.2 0.5 0.2 6.6 6.0 1.0 0.1 N/A 16.7 TBD TBD 2020 0.0 0.1 0.0 0.7 8.5 2.0 6.0 1.1 0.5 0.1 6.8 6.0 0.9 0.1 N/A 16.4 TBD TBD 2019 Demand Savings (MW) Demand Savings (MW) 400 789 483 500 627 909 867 N/A 2,785 2,804 4,300 8,170 1,300 85,963 64,327 58,900 13,467 11,300 2021 400 789 483 500 627 909 867 N/A 2,785 4,038 4,300 9,404 1,300 8,900 81,697 61,227 55,800 11,067 2020 400 998 368 500 627 909 867 N/A Energy Savings (MWh) Savings (MWh) Energy 2,785 5,878 9,867 4,600 1,200 7,800 79,531 58,327 52,600 11,337 2019 2021 $150,000 $500,000 $700,000 $900,000 $600,000 $600,000 $600,000 $100,000 $775,000 $400,000 $1,100,000 $7,700,000 $5,600,000 $2,650,000 $5,750,000 $2,700,000 $1,375,000 $16,100,000 2020 $900,000 $150,000 $500,000 $700,000 $900,000 $800,000 $500,000 $600,000 $100,000 $675,000 $400,000 $7,300,000 $5,300,000 $2,550,000 $5,650,000 $2,600,000 $1,375,000 Budget ($) $15,500,000 $50,000 2019 $800,000 $150,000 $600,000 $600,000 $900,000 $400,000 $600,000 $575,000 $400,000 $1,100,000 $6,900,000 $5,000,000 $2,150,000 $5,750,000 $2,500,000 $1,125,000 $14,800,000 Subtotal - Education Subtotal - Residential Subtotal - Commercial Total DSM Programs DSM Programs Total Sierra Pacific Power Company Pacific Power Sierra Residential Demand Response - Manage Demand Response - Manage Residential Direct Install Install Direct Residential Air Conditioning Conditioning Air Residential Low Income Residential Lighting Lighting Residential Commercial Demand Response - Build Demand Response - Build Commercial Commercial Demand Response - Manage Demand Response - Manage Commercial Commercial Services Services Commercial Schools Program Program Schools Program Development Development Program Energy Assessments Assessments Energy Residential Demand Response - Build Demand Response - Build Residential Energy Reports Energy Energy Education Education Energy
Page 51 of 198 Exhibit Hart-Direct-3 Page 3 of 3
NV Energy – 2019-2021 DSM Targets 7 0 0 7 7 5 3 5 8 6 4 5 2 4 1 5 1 5 7 5 4 5 3 0 2 5 2 9 1 9 9 2 0 9 7 1 ...... N/A 1 2 2 6 0 1 0 2 2 0 0 2 1 0 2 1 4 2 TRC Ratio N/A Net Benefits $ 10,269,774 $ 59,702,829 $ 96,911,725 $ 99,657,901 $ 15,139,511 $ 1,540,992 $ 3,587,544 $ 7,090,724 $ 8,821,530 $ 8,789,674 $ (5,472,376) $ (7,844,800) $ (1,665,824) $ (988,803) $ (689,094) $ 162,372,635 $ 133,856,860 $ 295,540,401 2.3 0.2 1.6 0.2 0.7 0.9 3.4 0.5 2.8 6.0 0.2 N/A 24.7 34.0 37.6 33.0 73.9 TBD TBD 2021 2.3 0.2 1.6 0.2 0.7 1.4 3.2 0.5 2.5 6.0 0.2 N/A 23.8 34.0 38.1 32.0 73.2 TBD TBD 2020 2.2 0.2 1.6 0.2 0.6 1.9 3.0 0.4 2.4 6.0 0.2 N/A 24.0 38.4 34.0 32.2 73.6 TBD TBD 2019 Demand Savings (MW) Demand Savings (MW) N/A 4,509 1,400 1,918 6,490 8,118 4,000 1,500 2,022 19,800 66,966 30,198 14,332 30,622 24,600 10,774 2021 216,800 248,874 346,462 N/A 4,509 1,400 1,918 6,490 4,000 1,500 2,022 19,800 71,422 30,198 14,332 12,575 28,222 22,200 10,774 2020 208,400 240,474 340,118 N/A Energy Savings (MWh) Savings (MWh) Energy 4,509 1,400 1,803 5,310 3,900 1,500 2,022 19,100 74,314 30,198 14,541 16,553 27,022 21,100 10,774 2019 213,700 245,074 346,410 2021 $650,000 $400,000 $900,000 $2,300,000 $8,800,000 $7,500,000 $2,700,000 $1,200,000 $1,600,000 $7,150,000 $3,875,000 $1,975,000 $2,600,000 $1,600,000 $20,600,000 $32,450,000 $10,000,000 $27,100,000 $66,700,000 2020 $650,000 $400,000 $900,000 $2,300,000 $9,700,000 $8,400,000 $7,500,000 $2,700,000 $1,200,000 $2,400,000 $7,050,000 $3,875,000 $1,875,000 $2,600,000 $1,400,000 Budget ($) $19,800,000 $32,550,000 $26,100,000 $65,700,000 2019 $650,000 $250,000 $900,000 $2,200,000 $9,500,000 $8,100,000 $7,600,000 $2,600,000 $1,000,000 $3,100,000 $6,550,000 $3,625,000 $1,775,000 $2,600,000 $1,200,000 $19,500,000 $32,550,000 $25,500,000 $64,600,000 Subtotal - Education Subtotal - Residential Subtotal - Commercial NV Energy NV Energy Total DSM Programs DSM Programs Total Commercial Services Services Commercial Schools Program Program Schools Residential Demand Response - Build Demand Response - Build Residential Residential Demand Response - Manage Demand Response - Manage Residential Direct Install Install Direct Residential Air Conditioning Conditioning Air Residential Low Income Pool PumpsPool Residential Lighting Lighting Residential Program Development Development Program Energy Assessments Assessments Energy Energy Reports Energy Commercial Demand Response - Manage Demand Response - Manage Commercial Demand Response - Build Commercial Energy Education Education Energy
Page 52 of 198 Page 53 of 198 ROBERT R. OLIVER
Page 54 of 198 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA 1 Nevada Power Company d/b/a NV Energy 2 Sierra Pacific Power Company d/b/a NV Energy
3 2018 Joint Integrated Resource Plan (2019-2038) Docket No. 18-06_____ 4 PREPARED DIRECT TESTIMONY OF 5 6 Robert R. Oliver 7
8 I. INTRODUCTION 9 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS 10 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
11 A. My name is Robert R. Oliver. I am filing testimony on behalf of Nevada Power 12 Company d/b/a NV Energy (“Nevada Power”) and Sierra Pacific Power Company
c Power Company c Power Company 13 d/b/a NV Energy (“Sierra” and together with Nevada Power, the “Companies”). 14 My current position is Director/Project Manager for ADM Associates, Inc. d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 (“ADM”), an independent third-party measurement and verification (“M&V”)
and Sierra Pacifi 16 contractor that has performed the M&V reports for the Companies as part of this 17 filing. My business address is 417 W. Plumb Lane in Reno, Nevada. 18
19 2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE 20 UTILITY INDUSTRY. 21 A. I have a Bachelor of Science in agricultural economics and business management
22 from Cornell University. I have been employed by ADM since 2010. I have 23 participated in the independent third-party measurement and verification activities
24 for the Companies’ energy efficiency programs since 2007, and consulted with 25 Nevada Power and Sierra in various assignments since 2005. I was previously a
26 consultant for the Nevada Task Force for Renewable Energy and Energy 27
28 OLIVER-IRP DIRECT 1
Page 55 of 198 1 Conservation during 2004 and 2005. More details regarding my professional 2 background and experience are set forth in my Statement of Qualifications, 3 included as Exhibit Oliver-Direct-1. 4
5 3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS PROJECT 6 MANAGER FOR MEASUREMENT AND VERIFICATION ACTIVITIES 7 FOR THE COMPANIES’ DEMAND SIDE MANAGEMENT (“DSM”) 8 PROGRAMS. 9 A. As project manager for ADM’s M&V activities, my responsibilities include various 10 analyses and quality assurance tasks on behalf of the following Demand Side 11 Management (“DSM”) programs: Commercial Services, Residential and 12 Commercial Demand Response, Schools, Energy Reports, Residential Air
c Power Company c Power Company 13 Conditioning, Residential Direct Install, Energy Education, and Home Energy 14 Assessments. d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15
and Sierra Pacifi 16 I also provide guidance and quality assurance for ADM’s development of energy 17 savings curves for the Companies’ DSM programs. I coordinate all of ADM’s 18 M&V activities and analyses for the cross-discipline team of economists, 19 statisticians, engineers and other professionals who participate in the independent 20 evaluation of the Companies’ portfolio of DSM programs. 21
22 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 23 UTILITIES COMMISSION OF NEVADA (“COMMISSION”) OR 24 SUPPORTED ADM’S TESTIMONY PROVIDED TO THE COMMISSION? 25 A. Yes. I previously testified before the Commission in the following dockets. 26 27
28 OLIVER-IRP DIRECT 2
Page 56 of 198 1 x Sierra’s and Nevada Power’s 2011 Annual DSM Update Reports – Docket Nos. 2 11-07026 and 11-07027, respectively.
3 x Nevada Power’s and Sierra’s Deferred Energy Accounting Adjustments 4 (“DEAA”) – Docket Nos. 12-03004 and 12-03005, respectively.
5 x Sierra’s 2012 Annual DSM Update Report and Nevada Power’s 2012 6 Integrated Resource Plan (“IRP”) – Docket Nos. 12-06052 and 12-06053, 7 respectively.
8 x Nevada Power’s and Sierra’s 2017 Annual DSM Update Reports – Docket Nos. 9 17-06043 and 17-06044, respectively. 10
11 I have also collaborated with and supported my ADM colleague, Sasha S. Baroiant, 12 with respect to his testimony before the Commission in the following dockets.
c Power Company c Power Company 13 x Nevada Power’s and Sierra’s DEAAs – Docket Nos. 13-03003 and 13-03004, 14 respectively. d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 x Nevada Power’s 2013 Annual DSM Update Report and Sierra’s 2013 IRP –
and Sierra Pacifi 16 Docket Nos. 13-07002 and 13-07005, respectively.
17 x Sierra’s and Nevada Power’s 2014 Annual DSM Update Reports – Docket Nos. 18 14-07007 and 14-07008, respectively.
19 x Sierra’s 2015 Annual DSM Update Report and Nevada Power’s 2015 IRP – 20 Docket Nos. 15-06065 and 15-07004, respectively.
21 x Sierra’s 2016 IRP and Nevada Power’s 2016 Annual DSM Update Report – 22 Docket Nos. 16-07001 and 16-07007, respectively. 23
24 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 25 A. Together with the Companies’ witness Ms. Anita Hart, I sponsor the M&V reports 26 contained in Technical Appendix Items DSM-5 through DSM-20. The M&V 27
28 OLIVER-IRP DIRECT 3
Page 57 of 198 1 reports document all analyses ADM performed to verify energy (kWh) savings and 2 critical peak demand (kW) savings achieved by the Companies’ 2017 portfolio of 3 DSM programs. 4
5 In my testimony, I describe the work ADM conducted to measure and verify 6 savings for the Companies’ 2017 DSM portfolios, and I discuss the standards that 7 govern M&V analysis. 8
9 II. M&V REPORTS FOR DSM PROGRAMS. 10 6. Q. PLEASE DESCRIBE THE WORK THAT IS PERFORMED IN 11 PREPARING M&V REPORTS FOR DSM PROJECTS. 12 A. ADM collects and analyzes data to independently determine energy savings and
c Power Company c Power Company 13 demand reductions for the Companies’ DSM programs. Data collection begins with 14 inspection of data entered by program implementers into DSMCentral, the data d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 management system used by Nevada Power and Sierra to track energy savings and
and Sierra Pacifi 16 demand reductions attributed to their DSM programs. The data recorded in DSM 17 Central is project-specific, listing both customer descriptive data and energy and 18 demand savings broken out, where practical, at the measure level. Primary data 19 collection does not stop with a review of the Companies’ records, but includes due- 20 diligence on-site audit visits, interviews and surveys, and inspections of a sample 21 of project documentation and sites to verify that measures claimed to be installed 22 through a program have been properly installed and are being utilized. Data needed 23 to analyze and calculate energy savings and demand reductions are also collected. 24 All data collection activities are guided by appropriate statistical sampling 25 procedures. 26 27
28 OLIVER-IRP DIRECT 4
Page 58 of 198 1 Using the data collected, ADM calculates and validates annual and monthly energy 2 savings and peak demand reductions for each DSM program in effect during a given 3 year. This analysis is performed using engineering calculations and statistical 4 analysis, as appropriate. 5
6 ADM provides annual reports on the results of its independent M&V work to 7 Nevada Power and Sierra. It is my understanding that the Companies use these 8 reports to evaluate and make improvements to the programs. These reports are also 9 submitted to the Commission for review and acceptance. 10
11 7. Q. PLEASE DESCRIBE IN MORE DETAIL THE GENERAL INDUSTRY 12 STANDARDS AND SPECIFICATIONS THAT GOVERN THE M&V OF
c Power Company c Power Company 13 ENERGY AND DEMAND SAVINGS. 14 A. The success of utility-sponsored DSM activity is closely scrutinized in many d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 regulatory jurisdictions to ensure that customer funds are being prudently spent and
and Sierra Pacifi 16 that DSM programs are delivering the energy savings and demand reductions that 17 are expected by system planners. Independent M&V has become the industry 18 standard, and is often a mandated activity for utilities performing DSM. Standards 19 and specifications that guide ADM’s independent M&V work are set out in several 20 guidebook documents that have been published over the past several years. These 21 include the following:
22 x American Society of Heating, Refrigeration and Air Conditioning Engineers 23 (“ASHRAE”). Measurement of Energy and Demand Savings, Guideline 14- 24 2014. 25 26 27
28 OLIVER-IRP DIRECT 5
Page 59 of 198 1 x M&V Guidelines: Measurement and Verification for Performance-Based 2 Contracts Version 4.0, U.S. Dept. of Energy Federal Energy Management 3 Program (“FEMP”), November 2015.1
4 x International Performance Measurement and Verification Protocol (“IPMVP”). 5 Volume 1, Concepts and Options for Determining Energy and Water Savings. 6 January 2012.2
7 x Energy Efficiency Program Impact Evaluation Guide, State and Local Energy 8 Efficiency Action Network, December 2012.3
9 x Protocols for evaluating, measuring and verifying savings for selected energy 10 efficiency measures, published through the Uniform Methods Project 11 (www.energy.gov/eere/about-us/ump-home) sponsored by the U.S. Dept. of 12 Energy (ongoing).4
c Power Company c Power Company 13 x National Standard Practice Manual (NSPM) for Assessing Cost-Effectiveness 14 of Energy Efficiency Resources, National Efficiency Screening Project, May d/b/a NV Energy Energy NV d/b/a 5 Nevada Power Company Company Power Nevada 15 2017.
and Sierra Pacifi 16 x California Public Utilities Commission. The California Evaluation Framework. 17 June 2004.6 18
19 8. Q. DID ADM FOLLOW INDUSTRY STANDARDS IN PERFORMING’S THE 20 M&V WORK REQUESTED BY NEVADA POWER AND SIERRA? 21 22 1 This FEMP document is available at www.energy.gov/sites/prod/files/2016/01/f28/mv_guide_4_0.pdf. 23 2 IPMVP Volume 1 is available at www.eeperformance.org/uploads/8/6/5/0/8650231/ipmvp_volume_i__2012.pdf or available through a subscription at evo-world.com. 24 3 The Energy Efficiency Program Impact Evaluation Guide is available at the following location: www4.eere.energy.gov/seeaction/system/files/documents/emv_ee_program_impact_guide_0.pdf 25 4 The protocols are available at www.energy.gov/eere/about-us/ump-protocols. 26 5 This NSPM document is available at nationalefficiencyscreening.org/wp-content/uploads/2017/05/NSPM_May- 2017_final.pdf. 27 6 This document is available at www.calmac.org/publications/California_Evaluation_Framework_June_2004.pdf.
28 OLIVER-IRP DIRECT 6
Page 60 of 198 1 A. Yes, all M&V work that we performed in evaluating the Companies’ 2017 DSM 2 programs complies with industry standards. Note that the accepted evaluation 3 methodologies described above sometime offer various approaches to evaluate a 4 given measure or program, so it is not possible to simultaneously comply with all 5 recommended approaches. Evaluators must select from available protocols to 6 achieve the best overall evaluation of a measure under the circumstances. 7
8 9. Q. PLEASE SUMMARIZE THE APPROACHES THAT ADM USED TO 9 MEASURE AND VERIFY SAVINGS FOR NEVADA POWER’S AND 10 SIERRA’S 2017 PROGRAMS. 11 A. The taxonomy presented in the Energy Efficiency Program Impact Evaluation 12 Guide identifies three major approaches for calculating estimates of energy savings
c Power Company c Power Company 13 and demand reductions.
14 x A site-specific or project-by-project M&V approach involves (1) selecting d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 a representative sample of customers or sites that participated in a project; (2)
and Sierra Pacifi 16 determining the savings for each customer or site in the sample, usually by 17 using one or more of the M&V options defined in the IPMVP; and (3) applying 18 the results of determining the savings for the sample to the entire population in 19 the project.
20 x A deemed savings approach involves using stipulated savings for energy 21 conservation measures for which savings values are well-known and 22 documented. For example, this approach may be acceptable for lighting retrofits 23 for common types of spaces (e.g., offices), where there is general agreement on 24 the hours of use for such spaces.
25 x A large-scale consumption data analysis approach involves determining 26 energy savings and demand reductions by applying one or more statistical 27
28 OLIVER-IRP DIRECT 7
Page 61 of 198 1 methods to measured energy consumption, utility meter billing data and 2 independent variable data. This approach usually (1) involves analysis of a 3 census of project sites versus a sample, and (2) does not involve on-site data 4 collection for model calibration. However, a sample of customers or sites may 5 be selected and visited to confirm that the energy conservation measures were 6 properly installed and are still operating. 7
8 In performing the M&V analysis of the Companies’ DSM programs, ADM 9 examined program documentation to identify (1) the types of energy efficiency 10 measures from which savings are expected to be realized, and (2) which of these 11 three types of analyses is most appropriate for determining savings for a particular 12 measure or program. In making this determination ADM takes account of several
c Power Company c Power Company 13 factors:
14 x The magnitude of expected savings from a program or measure affects the d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 choice of savings estimation approach. In particular, analysis of billing data
and Sierra Pacifi 16 may not be sufficient to detect savings of small magnitude for some measures.
17 x The number and complexity of the measures and technologies being promoted 18 through a program are factors in determining the savings estimation approach. 19 For example, if multiple measures can be installed at a single customer site, 20 there may be overlapping and/or interactive effects among the measures. 21 Identifying the effects of individual measures therefore requires using a savings 22 estimation approach that can account for the impact of interrelated measures.
23 x Costs associated with the approaches differ and therefore are also considered in 24 choosing the savings estimation approach. 25
26 III. UPDATES TO ENERGY SAVINGS CURVES 27
28 OLIVER-IRP DIRECT 8
Page 62 of 198 1 10. Q. WHY DID ADM UPDATE THE ENERGY SAVINGS CURVES FOR 2017 2 PROGRAMS? 3 A. ADM’s goal is to provide the best possible representation of the program- and 4 portfolio-level impacts each time a program is evaluated. As DSM programs 5 change from year to year (e.g., through inclusion of new measures, changes in 6 measure distributions, or even changes in code or market baselines), it may be 7 appropriate to update the analysis and select different energy savings curves. Our 8 experience has reinforced our commitment to constantly improving the quality of 9 energy savings curves, which in turn improves the accuracy and precision of M&V 10 determinations. 11
12 Updates related to savings curves fall into two broad categories: data updates and
c Power Company c Power Company 13 methodology updates. Opportunities for data updates include the availability of 14 new reputable sources of secondary data (e.g., a new end use metering study) or the d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 availability of program-specific primary data. Given that ADM samples and
and Sierra Pacifi 16 conducts on-site data collection for a large fraction of the projects, as weighted by 17 impacts, the latter opportunity is ever present. Reasons for data updates may include 18 new programs, new measures, or even a significant change in the relevance of a 19 measure within a program. 20
21 11. Q. HAVE SIGNIFICANT METHODOLOGY UPDATES BEEN APPLIED TO 22 THE 2017 ENERGY SAVINGS CURVES? 23 A. No. Significant methodology updates were not applied to the construction of the 24 2017 Energy Savings Curves. Consistent with ADM’s approach in the last five 25 years, ADM has developed project-specific curves for sampled projects, while non- 26 sampled projects are represented by measure-market specific curves that are 27
28 OLIVER-IRP DIRECT 9
Page 63 of 198 1 derived primarily from the California Commercial End Use Survey (“CEUS”). 2 ADM used 85 unique curves to describe the impacts of Nevada Power’s 3 Commercial Energy Services program; all 85 curves were project-specific curves, 4 derived from primary data collected during M&V. ADM used 43 unique curves to 5 describe the impacts of Sierra’s Commercial Energy Services program; all 43 6 curves were project-specific curves, derived from primary data collected during 7 M&V. The largest and most significant projects were sampled by ADM, and these 8 are the projects that benefit the most from customized energy savings curves. As 9 with previous years, lighting efficiency improvement projects are a key driver of 10 nonresidential sector impacts. ADM has used the same site-specific lighting 11 calculator since 2013. The calculator constructs site-specific savings curves at the 12 same time it calculates project-level verified impacts.
c Power Company c Power Company 13
14 12. Q. PLEASE DESCRIBE THE ENERGY SAVINGS CURVES THAT ADM d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 PROVIDED FOR NEVADA POWER AND SIERRA FOR USE IN THE
and Sierra Pacifi 16 PORTFOLIOPRO FINANCIAL MODELING. 17 A. For PortfolioPro financial modeling, ADM has provided Nevada Power and Sierra 18 energy savings curves for the following 2017 DSM programs: 19 1. Commercial Energy Services (includes Non-Profit Agency Grants) 20 2. Demand Response (Commercial Sector) 21 3. Demand Response (Residential Sector) 22 4. Direct Installation (Residential Sector) 23 5. Schools Program 24 6. Home Energy Assessments 25 7. Energy Reports 26 8. Residential Air Conditioning 27
28 OLIVER-IRP DIRECT 10
Page 64 of 198 1 I am informed that during the three years of the 2019 to 2021 DSM Action Plan 2 period, the Companies propose to implement these DSM programs in a similar 3 manner as in 2017. Thus, the program level energy savings curves from the 2017 4 programs are appropriate for PortfolioPro financial modeling for future years. 5
6 ADM has also provided Nevada Power and Sierra appropriate energy savings 7 curves for the Residential Lighting and Low-Income program designs that are 8 newly proposed for the DSM Action Plan described in this filing. 9
10 15. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY? 11 A. Yes. 12
c Power Company c Power Company 13 14 d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15
and Sierra Pacifi 16 17 18 19 20 21 22 23 24 25 26 27
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Page 65 of 198 Exhibit Oliver-Direct-1 Page 1 of 1
STATEMENT OF QUALIFICATIONS ROBERT R. OLIVER ADM ASSOCIATES, INC. 417 W. Plumb Lane Reno, NV 89509
Education Bachelor of Science in Agricultural Economics and Business Management, Cornell University
Professional Experience
2010 to Present Director ADM Associates, Inc. Responsible for evaluation, measurement and verification (EM&V) of Demand Side Management (DSM) portfolios that include various residential, commercial, agricultural, behavioral, solar, geothermal, energy education and other DSM programs. Currently responsible for directing DSM portfolio evaluations in Nevada, Ohio and Oklahoma. Provide electric and gas utility clients technical services including DSM portfolio design and related analyses; also provide technical reference manual (TRM) review, as well as participating in collaborative processes related to TRMs. Provide clients innovative approaches and methods for utilizing measure load shapes and program-level energy savings profiles to maximize accuracy of reporting for peak demand savings provided by DSM measures and programs. Provide guidance and quality assurance for EM&V sampling, ensuring that sampling is rigorous while exercising prudence with respect to EM&V budgets and resources. Serve as lead writer or editor for numerous EM&V reports and related technical documents.
2007 to 2009 Senior Program Manager Paragon Consulting Services Responsibilities included a range of EM&V technical assignments, such as managing various field engineering, data collection and data analysis activities, while also supporting the preparation of EM&V reports for DSM programs.
2005 to 2007 Southwest Regional Manager Ecos Consulting, Inc. Consulted for various southwestern utilities while responsible for providing clients DSM program design and execution. Successfully implemented innovative residential initiatives such as pool pump programs and Energy Star Lighting and Appliances programs.
2001 to 2005 Independent Consultant Responsibilities included consulting services for the Nevada Task Force for Renewable Energy and Energy Conservation (2004-2005). Also advised various clients regarding strategies for increasing market penetration of renewable energy systems, and for managing communications with internal and external stakeholders.
Page 66 of 198 Page 67 of 198
MARC D. REYES
Page 68 of 198
1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Nevada Power Company d/b/a NV Energy Sierra Pacific Power Company d/b/a NV Energy 3 4 2018 Joint Triennial Integrated Resource Plan (2019-2038) Docket No. 18-06____ 5 PREPARED DIRECT TESTIMONY OF 6 Marc D. Reyes 7 8 I. INTRODUCTION 9 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS
10 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
11 A. My name is Marc D. Reyes. I am the Director, Resource Planning and Analysis for
12 Nevada Power Company d/b/a NV Energy (“Nevada Power”) and Sierra Pacific 13 Power Company d/b/a NV Energy (“Sierra” and together with Nevada Power, the 14 “Companies” or “NV Energy”). My business address is 6226 West Sahara Avenue, d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Las Vegas, Nevada. I am filing testimony on behalf of Nevada Power and Sierra.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16
17 2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND 18 EXPERIENCE. 19 A. I have been employed by the Companies since May 2007 and have served as 20 Director of Resource Planning and Analysis since July 2017. 21 22 Prior to my current role, I was the Manager of Market Fundamentals from May 23 2011 to July 2017. As the Manager of Market Fundamentals, I was responsible for 24 the development of the market price forecasts for natural gas and wholesale
25 purchased power. I was also responsible for the regional market fundamental 26 analysis supporting the energy supply and resource planning functions. 27 28 Reyes-IRP DIRECT 1
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1 From May 2007 to May 2011, I was a Power Trader for the Companies, where I 2 performed analysis and negotiated short-term wholesale transactions to optimize 3 the Companies’ economic dispatch. Before joining the Companies, I was employed 4 as a Wholesale Power Trader for El Paso Electric Company. More details regarding 5 my professional background and experience are set forth in my Statement of 6 Qualifications, included as Exhibit Reyes-Direct 1. 7 8 3. Q. WHAT ARE YOUR RESPONSIBILITIES AS DIRECTOR, RESOURCE 9 PLANNING AND ANALYSIS?
10 A. I lead a staff of economists, planners, engineers and analysts in the development of
11 the Companies’ Integrated Resource Plans (“IRPs”) and Energy Supply Plans
12 (“ESPs”), and complex economic analysis of resource options. Working with other 13 groups in the Companies, the Resource Planning and Analysis department develops 14 and supports supply strategies, presents them to management for approval, and d/b/a NV Energy Nevada Power Company Company Power Nevada 15 facilitates ongoing communication of the status of the supply plans.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 18 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 19 A. Yes. I have provided testimony in IRP and ESP dockets before the Commission, 20 most recently in Nevada Power’s 2017 ESP Update, Docket No. 17-09001 and
21 Sierra’s 2017 ESP Update, Docket No. 17-09002. 22 23 II. OVERVIEW AND TESTIMONY ORGANIZATION 24 5. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT TESTIMONY
25 IN THIS CASE? 26 27 28 Reyes-IRP DIRECT 2
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1 A. I sponsor the economic analysis used in the evaluation of the resource plans in the 2 Joint Integrated Resource Plan for 2019-2038 (“2018 Joint IRP”). In Section III, I 3 discuss actions that the Companies will take during the Action Plan period (2019- 4 2021) to implement their Preferred Plan, a proposal that if approved will preserve 5 their ability to provide safe, reliable electric service to customers at reasonable 6 rates. In Section IV, I discuss the economic analysis used in the selection of the 7 Companies’ Preferred Plan. Finally, in Section V, I describe the market 8 fundamentals analysis and the wholesale power and natural gas price forecasts 9 (“price forecasts”) that are presented in the Load Forecast and Market
10 Fundamentals narrative of the Companies’ 2018 Joint IRP.
11
12 6. Q. WHAT EXHIBITS AND TECHNICAL APPENDICES ARE YOU 13 SPONSORING? 14 A. In addition to Exhibit Reyes-Direct-1, I am sponsoring the following Technical d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Appendix Items:
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 • ECON-1: Notice of Public Meeting and Overview of the 2018 IRP 17 • ECON-2: Description of Production Cost Modeling Software 18 • ECON-3: Average Generation Costs 19 • ECON-4: Energy Mix for All Cases 20 • ECON-5: Marginal Energy Costs 21 • ECON-6: Loads and Resources Tables 22 • ECON-7: Capital Projects (all cases and sensitivities) 23 • ECON-8: PWRR (Production Costs plus Capital Costs) 24 • ECON-9: Operating Reserves Calculation 25 • ECON-10: PROMOD Area Diagram 26 • ECON-11: Solar Photovoltaic Capacity Study 27 28 Reyes-IRP DIRECT 3
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1 • FPP-1: Fuel and Purchased Power Price Forecasts. 2 3 7. Q. ARE ANY OF THE MATERIALS YOU ARE SPONSORING 4 CONFIDENTIAL? 5 A. Yes. The following technical appendices are confidential:
6 • ECON-3: Average Generation Cost 7 • ECON-5: Marginal Energy Costs 8 • ECON-7: Capital Projects 9 • FPP-1: Fuel and Purchased Power Price Forecasts
10
11 III. RESOURCE PLANNING AND THE ACTION PLAN
12 8. Q. PLEASE DESCRIBE THIS 2018 IRP FILING. 13 A. In 2017, the enactment of Senate Bill 146 amended Nevada Revised Statutes 14 (”NRS”) § 704.741 to require the Companies to file a joint IRP every three years. d/b/a NV Energy Nevada Power Company Company Power Nevada 15 This filing represents the Companies first joint triennial IRP under the new
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 legislation. This filing contains new individual company and joint load forecasts, 17 joint fuel and purchased power forecasts, along with updated joint generation, 18 transmission, demand-side management (“DSM”) and renewables plans. 19 Embedded in 2018 Joint IRP is a Joint ESP, as required by Nevada Administrative 20 Code (“NAC”) § 704.9482. The Joint ESP and its associated technical appendices 21 are located in stand-alone volumes filed as part of the 2018 Joint IRP. The 2018 22 Joint IRP presents analysis of resource options (energy efficiency and conservation, 23 renewable generation, conventional generation and transmission) available to the 24 Companies to meet their bundled retail or native load over 20 years (as prescribed
25 by regulation) and 30 years. Based on that analysis, the Companies have selected a 26 Preferred Plan for meeting the needs of customers, and constructed a three-year 27 28 Reyes-IRP DIRECT 4
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1 Action Plan that identifies the steps to be taken and the costs to be expended over 2 the next three years to implement the Preferred Plan. This filing covers the 20-year 3 period 2019 to 2038 and the Action Plan period of 2019, 2020 and 2021. 4 5 9. Q. PLEASE DESCRIBE THE COMPANIES’ NEW JOINT LOAD FORECAST. 6 A. The Companies have prepared new individual company and joint load forecasts 7 taking into account updated economic and population data and projections. Long- 8 term load growth is expected to be modest and linked closely to a continued 9 moderate economic recovery. The updated load forecast is sponsored by the
10 Companies’ witness Mr. Terry Baxter.
11
12 10. Q. PLEASE DESCRIBE THE COMPANIES’ RESOURCE NEED OVER THE 13 ACTION PLAN PERIOD. 14 A. After taking into account the capacity contributions of the Companies’ proposed d/b/a NV Energy Nevada Power Company Company Power Nevada 15 portfolio of DSM projects (see, the joint DSM Plan and the testimony of Ms. Anita
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Hart), as well as other load reducing resources (e.g., third-party owned distributed 17 generation as described in the load forecast volume and Mr. Baxter’s testimony), 18 the Companies’ open capacity position grows to more than 1,000 MW in 2020 and 19 beyond. 20 21 11. Q. ARE THE COMPANIES REQUESTING PERMISSION TO ADD 22 COMPANY-OWNED GENERATING CAPACITY TO BEGIN TO CLOSE 23 THESE OPEN POSITIONS? 24 A. No. The Preferred Plan does not request approval to pursue any company-owned
25 generating resources. Instead, the Preferred Plan relies on energy conservation and 26 six long-term renewable energy power purchase agreements (“PPAs”) to address 27 28 Reyes-IRP DIRECT 5
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1 the Companies’ significant resource requirements. The six PPAs, negotiated with 2 five different renewable project developers, will add 1,001 megawatts (“MW”) of 3 solar photovoltaic (“PV”) resource to the Companies’ supply portfolios. Three of 4 the six projects are located in northern Nevada, and three are located in southern 5 Nevada. In addition, the three northern projects include 100 MW of co-located 6 battery storage, capable of providing 100 MW of capacity for four consecutive 7 hours (400 MWh). 8 9 12. Q. DO THE COMPANIES NEED TO INVEST IN TRANSMISSION
10 RESOURCES DURING THE ACTION PLAN PERIOD?
11 A. Yes. First, the Companies need to construct transmission network upgrades projects
12 to facilitate the interconnection of four of the six solar PV projects described above. 13 Second, the Companies are requesting Action Plan approval to upgrade conductor 14 on a 1.45 mile section of the Arden to McDonald 230 kilovolt (“kV”) line in d/b/a NV Energy Nevada Power Company Company Power Nevada 15 southern Nevada. Finally, the Companies are requesting approval to continue
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 participation in WestConnect with funding of approximately $675,000 distributed 17 equally over the three-year Action Plan period. 18 19 These transmission investments are discussed in the Transmission Plan section of 20 the Supply Side Plan narrative, Section 2.E. The Transmission Plan and projected 21 project expenditures are sponsored by Mr. Sachin Verma. 22 23 13. Q. ARE THERE CHANGES IN CIRCUMSTANCES THAT COULD REQUIRE 24 NV ENERGY TO INVEST IN TRANSMISSION ASSETS?
25 A. Yes. As discussed in the Transmission section of the Supply Side Plan narrative, 26 the Tahoe Reno Industrial Center located east of Reno, Nevada, has the potential to 27 28 Reyes-IRP DIRECT 6
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1 grow quite rapidly. NV Energy has received inquiries from several potential large 2 customers. If these projects materialize, NV Energy will need to improve two 3 elements of its transmission system. First, NV Energy will need to improve the 4 connectivity between the 345 kV and 120 kV systems. Second, NV Energy will 5 either need to construct, acquire or contract with generation resources located 6 within Nevada or expand import capabilities through the construction of new 7 transmission lines. 8 9 14. Q. PLEASE SUMMARIZE THE ACTIVITIES FOR WHICH THE
10 COMPANIES ARE REQUESTING AUTHORITY TO DEPLOY FUNDS
11 DURING THE THREE-YEAR ACTION PLAN PERIOD IN PURSUIT OF
12 THE PREFERRED PLAN? 13 A. The Companies are seeking Commission approval of its Preferred Plan, including 14 the following items: d/b/a NV Energy Nevada Power Company Company Power Nevada 15 1) The Preferred DSM portfolio of programs and budget, which totals $197.0
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 million over the Action Plan period; 17 2) Transmission projects necessary to interconnect the renewable energy 18 projects totaling $22.94 million over the Action Plan period; 19 3) Transmission Arden to McDonald upgrade at a total cost of $720,000 over 20 the Action Plan period; 21 3) Funding to continue participation in WestConnect totaling $675,000 over 22 the Action Plan period. 23 24 In this filing the Companies are not requesting authority to proceed with the
25 construction of any future generating units at this time. 26 27 28 Reyes-IRP DIRECT 7
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1 15. Q. ARE THE COMPANIES ASKING FOR ACTION PLAN APPROVAL FOR 2 ANY NEW CONTRACTS RELATED TO NATURAL GAS SUPPLY OR 3 NATURAL GAS TRANSPORTATION? 4 A. No. Presently, the Companies are seeking to maintain their four-season ahead gas 5 supply strategy, and are not seeking to add to or discontinue their gas transportation 6 contracts. The renewal of several of Sierra’s expiring gas transportation contracts 7 is discussed in Section 2.C. of the Supply Side Plan narrative and is supported by 8 the testimony of Ms. Patricia Rodriguez. 9
10 IV. ECONOMIC ANALYSIS
11 16. Q. PLEASE DESCRIBE THE METHODOLOGY USED TO PERFORM THE
12 ECONOMIC ANALYSIS OF THE ALTERNATIVE PLANS CONSIDERED 13 IN THIS FILING. 14 A. The Companies’ analysis of future resource requirements begins with the Loads d/b/a NV Energy Nevada Power Company Company Power Nevada 15 and Resources Tables (“L&R Tables”). A long-term forecast of annual peak loads,
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 planning reserve requirements, and a forecast of an annual peak capacity for supply- 17 side and demand-side resources are used to determine the open capacity position 18 (“Open Position”) for each year under base (or mid) load conditions. The Open 19 Position is defined as any value resulting from the peak load, net of demand-side 20 and private generation resources, plus planning reserves that is greater than the sum 21 of the peak capacities for all of the available supply-side resources. The Companies’ 22 review of the projected yearly Open Positions determines the year or years when 23 resources are needed, and triggers the development of alternative plans (or “cases”) 24 that address the identified needs.
25 26 27 28 Reyes-IRP DIRECT 8
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1 After developing the L&R Tables, the Companies utilize two economic models to 2 evaluate the alternative plans over the planning period. The first is a production 3 cost model, “PROMOD.”1 PROMOD simulates the operation of electric system 4 and computes production costs (fuel, purchase power, variable and fixed costs to 5 operate) by performing hourly, chronological economic unit commitment and 6 dispatch of the Companies’ electric production resources and market purchases to 7 satisfy hourly load requirements in a least cost solution over the planning period. 8 A more detailed description of PROMOD can be found in Technical Appendix Item 9 ECON-2. Additional details about the key modeling inputs into PROMOD can be
10 found in the Economic Analysis section of the Supply Side Plan narrative.
11
12 The second model used is a Companies-designed Capital Expense Recovery model 13 (“CER”). The CER computes the annual revenue requirement for capital projects 14 based on the costs of constructing or acquiring resources. Additional details about d/b/a NV Energy Nevada Power Company Company Power Nevada 15 the key modeling inputs into the CER can be found in the Economic Analysis
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 section of the Supply Side Plan narrative. 17 18 The annual production costs from PROMOD, plus the annual revenue requirements 19 for capital projects from the CER, are summed over the planning period for each 20 alternative plan. This provides the total revenue requirement over the planning 21 period. The total revenue requirement is then discounted by the Companies’ 22 weighted cost of capital to determine the Present Worth of Revenue Requirement 23 (“PWRR”) for each of the alternative plans. A comparison of the PWRRs of each 24 alternative plan provides a basis for economically ranking of the plans from least
25 26 27 1 PROMOD is a proprietary software product that the Company licenses from ABB Group. 28 Reyes-IRP DIRECT 9
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1 cost to most expensive. The PWRR ranking is one factor used to determine the 2 Preferred Plan. 3 4 The Companies then conduct scenario analysis around the major assumptions of 5 load forecasts, fuel and purchase power forecasts, and carbon forecasts. The 6 scenario analysis tests how the economic analysis results change under variations 7 (high and low) around those major assumptions. The major assumptions of load, 8 fuel and purchase power forecasts, and carbon forecasts have inherent volatility 9 since no one forecast for these major assumptions can be assumed to have perfect
10 certainty. Analyzing the alternative plans across varying levels of assumptions
11 allows the Companies to evaluate how the cases perform under a range of load,
12 market, and carbon outcomes. Material PWRR differences between cases under one 13 scenario versus another often factor into the selection of the Preferred Plan. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 17. Q. HOW MANY SCENARIOS WERE PERFORMED FOR EACH CASE?
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. Nine scenarios were performed for each case. The scenarios included variations of 17 load, carbon price forecasts, and fuel and purchase power forecasts. Further 18 information on the load forecasts and fuel and purchase power forecasts can be 19 found in the Load Forecast and Market Fundamentals Volume of this filing. 20 Additional information on the carbon price forecasts is contained in the NERA 21 Report, Technical Appendix ECON-12. 22 23 A complete listing of the nine scenarios with various combinations of load, fuel and 24 purchase power, and carbon forecasts analyzed can be found in Figure EA-1 in the
25 Economic Analysis section of the Supply Side Plan narrative. 26 27 28 Reyes-IRP DIRECT 10
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1 18. Q. PLEASE DESCRIBE THE COMPANIES’ ASSESSMENT OF THEIR OPEN 2 POSITIONS. 3 A. Under the Base Load scenarios, the Companies have an Open Position every year 4 beginning in 2019. The Open Position grows to more than 1,000 MW in 2020 and 5 beyond. 6 7 19. Q. PLEASE DESCRIBE THE ALTERNATIVE PLANS THAT WERE 8 DEVELOPED AND EVALUATED FOR THIS IRP. 9 A. The Companies make efforts to evaluate alternative plans that provide the same
10 amount of planning capacity in each plan to maintain a consistent Open Position,
11 market reliance, and reliability between cases. The four alternative plans designed
12 for this 2018 Joint IRP are: 13 14 “All Market” Case: As is described in the Renewable Plan in Section 2.D of the d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Supply Side Plan, while Nevada Power is projected to satisfy Nevada’s Renewable
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Energy Portfolio Standard (“RPS”) through 2027. However, Sierra will not comply 17 with the RPS after 2021. Thus, the All Market case firsts satisfies Sierra’s 18 requirements under the RPS through two of the northern Nevada PPAs introduced 19 above, then relies on market purchases to satisfy remaining energy and capacity 20 requirements in the Action Plan period. 21 22 “Renewables” Case: This case includes the addition of 1,001 MW of solar PV 23 resources and 100 MW/400 MWh of battery energy storage systems through the 24 six PPAs mentioned above.
25 26 27 28 Reyes-IRP DIRECT 11
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1 “Low Carbon” Case: This case is a variation of the Renewables Case, but in 2 addition assumes the conditional retirement of North Valmy Generating Station 3 Unit 1 on December 31, 2021. 4 5 “Development” Case. This case further builds upon the Low Carbon case through 6 the addition of 299 MW of solar PV resources developed by NV Energy. 7 8 20. Q. DO THE COMPANIES ENSURE THAT ALL ALTERNATIVE PLANS 9 MEET THE RPS THROUGH THE PLANNING PERIOD?
10 A. Yes. Renewable resource additions (also referred to as “renewable placeholders”)
11 are modeled throughout the planning period in each case to ensure that the
12 Companies remain RPS compliant. The renewable placeholders in the Renewable 13 Case, Low Carbon Case, and Development Case are identical for the resource plan 14 period. This enables a pure comparison of the PWRRs of each case without d/b/a NV Energy Nevada Power Company Company Power Nevada 15 introducing bias from renewable placeholders.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 21. Q. DID THE COMPANIES TREAT THE RENEWABLE PLACEHOLDERS IN 18 THE LOW CARBON CASE DIFFERENTLY THAN IN PREVIOUS 19 ECONOMIC ANALYSES? 20 A. Yes. As required by NAC §§ 704.9355(1)(e) and 704.937(1), the Companies must 21 include a “low carbon intensity” plan as part of the alternative plans being 22 evaluated. This plan typically involves adding additional renewable generation 23 early in the planning period to address the identified need. In prior filings, the 24 Companies would use the early addition of renewable resources to defer renewable
25 placeholders. Under the Low Carbon case in this filing, the Companies did not defer 26 the renewable placeholders. Instead, the Companies kept the renewable 27 28 Reyes-IRP DIRECT 12
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1 placeholders consistent with the other alternative plans. This resulted in the 2 Companies exceeding the RPS for nearly the entirety of the planning period. 3 4 22. Q. THE COMPANIES HAVE ADDRESSED THE ACTION PLAN PERIOD 5 2019 THROUGH 2021 NEED AS WELL AS ADDING RENEWABLE 6 PLACEHOLDERS TO COMPLY WITH THE RPS. ALTHOUGH THE 7 RENEWABLE PLACEHOLDERS HELP TO MANAGE THE OPEN 8 POSITION THROUGH THE PLANNING PERIOD, OPEN POSITIONS 9 CAN REMAIN LARGE IN LATER YEARS. HOW DO THE COMPANIES
10 MANAGE THESE OPEN POSITIONS?
11 A. The Companies’ L&R Tables show that the Companies will have additional needs,
12 beyond 2019 through the 20 and 30-year planning periods. However, most of these 13 needs are sufficiently outside of the Action Plan period and Commission approval 14 of an Action Plan item, is not required at this time. In future years, an Open Position d/b/a NV Energy Nevada Power Company Company Power Nevada 15 was closed or reduced with conventional placeholder resource additions. The
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Companies are not asking the Commission to approve conventional placeholder 17 resource additions in this filing. Actions to add appropriate resources will be the 18 subject of future IRPs or IRP amendments. 19 20 When adding conventional placeholders, the size of the placeholder addition is 21 determined in much the same manner as is discussed above when determining the 22 alternative plans. That is, the Companies make efforts to add comparable amounts 23 of resources to reduce Open Positions and to maintain similar Open Positions and 24 reliability between the cases through the planning period.
25 26 27 28 Reyes-IRP DIRECT 13
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1 23. Q. AFTER ANALYZING THE ALTERNATIVE PLANS, WHAT WERE THE 2 RESULTS OF THE ECONOMIC ANALYSIS?
3 A. The significant findings of the economic analysis are:
4 • The Renewables Case consistently produced the lowest 20-year and 30-year 5 PWRR evaluation among the nine scenarios.
6 • The Low Carbon Case generally performed second in PWRR rankings in
7 the 20-year and 30-year PWRR evaluation among the nine scenarios.
8 • The All Market Case generally underperformed the Renewable and Low 9 Carbon cases in the 20-year and 30-year PWRR evaluation. This is an
10 expected outcome since the All Market case has higher Open Position costs
11 than the all other cases from 2021 through 2037.
12 13 24. Q. HAVE THE COMPANIES CHANGED THE PERCENT CAPACITY 14 CONTRIBUTION OF SOLAR PV RESOURCES IN THIS 2018 JOINT IRP? d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. Yes. The Commission’s final Order in Docket No. 15-07004, Nevada Power’s
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 2016-2035 IRP, directed Nevada Power to conduct a new solar PV capacity study 17 to be included in this IRP.2 In compliance with the Commission’s Order, the 18 Companies retained the services of Black & Veatch to conduct a study to determine 19 the effective load carrying capability (“ELCC”) of utility scale or universal solar 20 PV resources. Based on the study results the Companies updated the capacity 21 contribution percentage of solar PV resources from 38 percent to 33 percent. As the 22 Companies add additional solar PV resources to the grid, the ELCC of solar PV 23 resources drops in steps to 20 percent. The complete Black & Veatch study is found 24 in Technical Appendix ECON-11.
25 26
27 2 See Directive eight in the Commission’s Order issued December 23, 2015 in Docket No. 15-07004. 28 Reyes-IRP DIRECT 14
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1 V. MARKET FUNDAMENTALS AND PURCHASE POWER AND NATURAL GAS 2 PRICE FORECASTS 3 25. Q. PLEASE BRIEFLY DESCRIBE THE PURCHASE POWER AND 4 NATURAL GAS PRICE FORECASTS USED IN THIS 2018 JOINT IRP. 5 A. The base, high and low fuel and purchased power price forecasts used in this filing 6 have been prepared in a manner consistent with previous IRP filings made by the 7 Companies. The methodology used to prepare both the power and natural gas price 8 forecasts relies upon near-term observable market based price quotes (“quotes”) 9 that are blended into a long-term market fundamental price forecast. These price
10 forecasts are described in the Load Forecast and Market Fundamentals Volume.
11
12 26. Q. PLEASE DESCRIBE THE DATA SOURCES USED FOR THE MARKET- 13 BASED PRICE QUOTES AND MARKET FUNDAMENTAL PRICE 14 FORECAST. d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. The sources of data for natural gas quotes are the CME Group and Argus Media,
3 and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Inc. (“Argus”). These quotes reflect observed transactions at the following major 17 natural gas trading hubs: Henry Hub, Alberta NOVA Inventory Transfer (“AB- 18 NIT” or “AECO”), Sumas, Northwest Pipeline Rockies (“Rockies”), Malin, and 19 the Southern California Border (“SoCal”). Quotes for purchased power are 20 obtained from Argus. As with the natural gas quotes described above, the quotes 21 reflect observed transactions at the major power trading hubs: Mead, Palo Verde, 22 Mid-Columbia, and California-Oregon Border. 23 24
25
26 3 Argus is a leading provider of data on commodity prices and is widely relied upon for indexation of physical 27 trade. 28 Reyes-IRP DIRECT 15
Page 83 of 198
1 The long-term fundamental price forecast is obtained from Wood Mackenzie Ltd. 2 (“WoodMac”), a professional forecasting service. WoodMac publishes its 3 fundamental price forecast bi-annually, and the price curves in this filing are based 4 on the no carbon sensitivity of the North American Power and Renewables Long- 5 Term Outlook H2 2017 (“LTO”). WoodMac performs detailed modeling of 6 regional natural gas and power markets, taking into account supply-demand price 7 dynamics. The no-carbon sensitivity to the LTO was published in February 8, 2018 8 and assumes no federal regulation of greenhouse gas (“GHG”) emissions or federal 9 renewable energy standards. This sensitivity served as the foundation in building
10 the price forecasts included as Technical Appendix Items FPP-1.
11
12 27. Q. PLEASE DESCRIBE THE PROCESS USED TO PREPARE THE 13 NATURAL GAS AND POWER PRICE FORECASTS. 14 A. All alternatives were evaluated against a base case natural gas price forecast d/b/a NV Energy Nevada Power Company Company Power Nevada 15 assuming an adjustment to the Henry Hub price due to the expected effects
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 associated with the mid-carbon scenario implementation of a federal cap-and-trade 17 regime for GHG emissions. The near-term (April 2018 through October 2020) 18 market quotes for power and gas are based entirely on the average of settlement 19 prices during 21 trading days in March 2018. The price forecasts transition from 20 being entirely market-based price quotes to entirely long-term fundamental forecast 21 during a 24-month blending period from November 2020 through October 2022. 22 The near-term market-based quotes are incrementally blended with the long-term 23 fundamental forecast across this transition period.4 The Companies used the pure 24 fundamental forecast for the November 2022 through December 2040 portion of
25 the price forecast. Beyond 2040, monthly Henry Hub prices are escalated at the
26 4 27 The blending of market quotes and the fundamental forecast occurs across four gas seasons, or 24 months. 28 Reyes-IRP DIRECT 16
Page 84 of 198
1 compounded annual growth rate of the forecast for the period from 2035 through 2 2040. Thus the near-term market quotes, blending period, long-term forecast, and 3 the escalation period constitute the forecasted natural gas price curve for each of 4 the relevant Western natural gas trading hubs. The natural gas price forecasts are 5 provided in Technical Appendix Items FPP-1. The mid, high, and low carbon 6 scenarios included in FPP-1 reflect adjustments beginning in 2024 to the base, high 7 and low Henry Hub natural gas price forecasts due to changes in demand for natural 8 gas as a lower carbon alternative to coal. Additional information on the carbon price 9 trajectories and fuel price adjustments is available in the NERA Report, Technical
10 Appendix item ECON-12.
11
12 Power prices are derived by multiplying the forecasted gas prices and the forecasted 13 market implied heat rate (“MIHR”) defined as the ratio of power prices and the 14 corresponding gas price for that market. The MIHR forecast for the period from d/b/a NV Energy Nevada Power Company Company Power Nevada 15 April 2018 through October 2020 is the ratio of 21-day average power price quotes
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 from Argus Media and the 21-day average forward gas prices from CME Group 17 and Argus Media as described above. The second part of the curve, from November 18 2020 to October 2022, reflects a blend of market heat rates based on the market 19 quotes and fundamental forecast. In the blending process, the MIHR based on pure 20 market quotes are more heavily weighted in the initial period, with the MIHR based 21 on the fundamental portion of the curve receiving greater weight towards the end 22 of the blending period. The third part of the curve, from November 2022 until 23 December 2040, is entirely based on the MIHR curve from the fundamental 24 forecast. As described above, the MIHR forecast for the period from 2041 through
25 2048 is calculated from the compounded annual growth rate of fundamental prices 26 27 28 Reyes-IRP DIRECT 17
Page 85 of 198
1 over the period from 2035 through 2040. The power price forecasts are also 2 provided in Technical Appendix Item FPP-1. 3 4 With respect to coal, Mr. Joseph Brignola sponsors the long-term forecast of coal 5 prices delivered to the Companies’ single remaining coal plant in Nevada, the North 6 Valmy Generating Station. The base, high, and low coal prices for deliveries to the 7 North Valmy Generating Station were prepared by WoodMac. 8 9 28. Q. HOW DO THE COMPANIES CONSTRUCT THE HIGH AND LOW FUEL
10 AND PURCHASE POWER PRICE FORECASTS?
11 A. As described above, the Companies perform sensitivity analyses around the base
12 case projections to determine how alternative plans vary under a range of market 13 price conditions. High and low price curves for natural gas were calculated at one 14 standard deviation around the base case forecast (plus and minus). High and low d/b/a NV Energy Nevada Power Company Company Power Nevada 15 power price forecasts were prepared to reflect western energy prices that fluctuate
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 with the respective natural gas price forecasts, using the heat rate of a typical 17 combined-cycle unit. The profit margin (or “spark spread”) reflected in the base 18 case price forecast was added to both the higher and lower computed energy prices. 19 The spark spread is calculated as a dollar per megawatt-hour value. 20 21 29. Q. HOW DO YOU CAPTURE CAPACITY COSTS FOR PURPOSES OF THE 22 POWER PRICE FORECAST? 23 A. WoodMac’s regional power price forecast represents day-ahead firm energy prices; 24 it does not explicitly include the full cost of new capacity additions that would be
25 required to ensure resource adequacy over the forecast period. The regional price 26 forecast is used by the PROMOD model to economically dispatch market purchases 27 28 Reyes-IRP DIRECT 18
Page 86 of 198
1 against internal generation, while the capacity price forecast (dollars per kilowatt- 2 year) is multiplied by the Companies’ open capacity position as an additional fixed 3 fuel and purchased power cost. 4 5 30. Q. WHAT IS THE SOURCE OF THE COMPANIES’ LONG-TERM 6 CAPACITY PRICE FORECAST? 7 A. The Companies have utilized WoodMac’s capacity price forecast in the preparation 8 of the 2018 Joint IRP. As part of its LTO, WoodMac prepared an estimate of the 9 levelized cost of new entry (“CONE”) for the installed cost of future combined
10 cycle and combustion turbine generation. The CONE is an estimate of the annual
11 fixed costs associated with owning and operating a new generating facility (i.e.,
12 exclusive of variable costs such as fuel and emissions). WoodMac then calculates 13 the capacity price forecast (in dollars per kW-year) as the difference between the 14 CONE and the net energy and ancillary services margins reflected in the wholesale d/b/a NV Energy Nevada Power Company Company Power Nevada 15 power price forecast.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 31. Q. DOES THIS COMPLETE YOUR PREPARED DIRECT TESTIMONY. 18 A. Yes, it does. 19 20 21 22 23 24
25 26 27 28 Reyes-IRP DIRECT 19
Page 87 of 198 Exhibit Reyes-Direct-1 Page 1 of 2 STATEMENT OF QUALIFICATIONS
MARC D. REYES
My name is Marc D. Reyes. My business address is 6226 West Sahara Avenue, Las Vegas,
Nevada. I am the Director of Resource Planning and Analysis for Nevada Power Company, d/b/a NV Energy and Sierra Pacific Power Company, d/b/a NV Energy.
I graduated from New Mexico State University with a Bachelor of Arts Degree in
Economics in 2000 and earned a Certificate in Utility Management from Willamette
University in 2010.
I have been employed as the Director of Resource Planning and Analysis since July 2017.
I lead a staff of economists, planners, engineers, and analysts to develop Integrated
Resource Plans, Energy Supply Plans, and Gas Informational Reports. In addition, I develop and support supply strategies, and continually monitor and report on the status of the supply plans for management review.
Prior to my current role, I was the Manager of Market Fundamentals from May 2011 through July 2017. In that role, I was responsible for the preparation of fundamental analysis and market price forecasts for natural gas and wholesale power in the western U.S.
From May 2007 until May 2011, I was employed as an Energy Trader in Resource
Optimization for NV Energy. I was responsible for executing daily to monthly wholesale
1 Page 88 of 198 Exhibit Reyes-Direct-1 Page 2 of 2 power and natural gas transactions to optimize the Companies short-term portfolio. I performed market surveys to identify liquidity and obtain price discovery. I performed market research to identify new opportunities to reduce fuel and purchased power costs and worked with the credit and contracts groups to establish new counterparties. I mentored and developed junior traders.
From October 2005 until May 2007, I was employed as a Power Trader for El Paso Electric
Company. I was responsible for executing real time power trades as part of the wholesale power marketing group’s profit and loss book. I worked closely with the day-ahead and term traders to optimize the company portfolio in the Western Electric Coordinating
Council and Southwest Power Pool regions.
2 Page 89 of 198 Page 90 of 198
PATRICIA RODRIGUEZ
Page 91 of 198 1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy 3 4 2018 Joint Integrated Resource Plan (2019-2038) Docket No. 18-06____ 5 Prepared Direct Testimony of 6 Patricia Rodriguez 7
8 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS 9 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
10 A. My name is Patricia Rodriguez. My current position is Manager, Gas
11 Transportation Planning for Sierra Pacific Power Company d/b/a NV Energy
12 (“Sierra”) and Nevada Power Company d/b/a NV Energy (“Nevada Power,” and 13 together with Sierra, the “Companies” or “NV Energy”). My business address is 14 6226 West Sahara Avenue in Las Vegas, Nevada. I am filing testimony on behalf d/b/a NV Energy Nevada Power Company Company Power Nevada 15 of the Companies.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16
17 2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE 18 UTILITY INDUSTRY. 19 A. My professional experience includes more than 13 years in the utility industry. I 20 have a Bachelor of Science in Electrical Engineering and have been employed by 21 the Companies since May 2005. 22
23 Prior to my current position, I held positions in Distribution Planning, Demand Side 24 Management Planning and Project Controls. More details regarding my 25 professional background and experience are set forth in my Statement of 26 Qualifications, included as Exhibit Rodriguez-Direct-1. 27
28 Rodriguez-DIRECT 1
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1 3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS MANAGER OF GAS 2 TRANSPORTATION PLANNING. 3 A. As the Manager of Gas Transportation Planning, my responsibilities include the 4 planning and analysis of natural gas transportation needs and ensuring sufficient 5 supply to the generation fleet for the Companies along with the natural gas 6 distribution system for Sierra. These responsibilities include the development and 7 implementation of work plans to support corporate contract negotiations, planning, 8 budgeting, controls, portfolio optimization, cost reduction, and risk management. 9 Additional details regarding my background and experience are set forth in my
10 Statement of Qualifications, which is an exhibit to this testimony.
11
12 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 13 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 14 A. Yes. I have provided written testimony in various dockets in front of the d/b/a NV Energy Nevada Power Company Company Power Nevada
15 Commission, most recently in Docket Nos. 18-03002, 18-03003 and 18-03004.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 18 A. I am sponsoring Section 2.C.1 (“Fuel Supply - Current Physical Gas Supply”), 19 Section 2.C.2 (“Fuel Supply – Physical Gas Procurement”) and Section 2.C.3 20 (“Fuel Supply - Current Oil Supply”) of the Supply Side Plan in the 2018 Joint 21 Triennial Integrated Resource Plan (“IRP”). 22 23 6. Q. ARE YOU SPONSORING ANY EXHIBITS? 24 A. Yes. I am sponsoring the following Exhibits: 25 Exhibit Rodriguez-Direct-1 Statement of Qualifications 26 27
28 Rodriguez-DIRECT 2
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1 7. Q. PLEASE DESCRIBE THE COMPANIES’ CURRENT PHYSICAL GAS 2 SUPPLY. 3 A. Section 2.C.1 of the Supply Side Plan summarizes the Companies’ current physical 4 gas supply. 5 6 Nevada Power is connected directly through interstate pipeline systems with 7 several major gas producing regions including the Permian, San Juan, Anadarko, 8 and the Rocky Mountain supply basins, as well as California gas supply. The largest 9 producing region with the best connectivity into and through Nevada Power’s
10 control area is the Rocky Mountain supply basin. The Kern River Gas Transmission
11 Company (“Kern River”) connects the Rocky Mountain basin through Nevada into
12 southern California. Kern River delivers Nevada Power’s gas supplies to the Harry 13 Allen, Lenzie, Higgins, and Silverhawk plants. Nevada Power’s Edward W. Clark 14 Generating Station, Sun Peak Generating Station (“Sun Peak”) and LV Gen d/b/a NV Energy Nevada Power Company Company Power Nevada
15 facilities take gas supply via a transportation agreement with Southwest Gas
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 (“SWG”). The SWG transportation agreement provides for receipt of Kern River 17 supplies as well as limited quantities of gas from sellers off of the El Paso Natural 18 Gas Company and/or Transwestern Pipeline Company pipelines south of Las Vegas 19 (from the Topock, Arizona area, if SWG is not using these same capacity rights for 20 its own internal use). 21 22 Sierra takes delivery of natural gas from two interstate pipelines: Paiute Pipeline 23 Company (“Paiute”) and Tuscarora Gas Transmission Company (“Tuscarora”). 24 Paiute delivers gas supplies from upstream pipeline Williams – Northwest Pipeline 25 (“Northwest”). Northwest sources its gas supplies from British Columbia, the San 26 Juan Basin, and the Rocky Mountain region of Wyoming, Utah and Colorado. 27
28 Rodriguez-DIRECT 3
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1 Tuscarora delivers gas supply from upstream pipeline Gas Transmission Northwest 2 (“GTN”), which is connected to the gas producing regions of the Western Canada 3 Sedimentary Basin in Alberta, Canada through TransCanada Pipelines. Within 4 Alberta, TransCanada’s NOVA pipeline system carries gas from the AECO 5 producing areas to the Alberta/British Columbia border. From there the Alberta 6 System interconnects with TransCanada’s BC System, which transports gas to 7 TransCanada’s GTN system at the United States/Canadian border near Kingsgate, 8 Idaho. 9
10 The Companies’ proposed gas transportation strategy for the Action Plan period is
11 set forth in Section 5.B. of the 2018 Energy Supply Plan (“ESP”) for 2019-2021.
12 13 8. Q. DID THE COMPANIES EVALUATE THE ADEQUACY OF THE 14 CURRENT FIRM INTERSTATE GAS TRANSPORTATION CONTRACTS d/b/a NV Energy Nevada Power Company Company Power Nevada
15 TO ENSURE SUFFICIENT NATURAL GAS SUPPLY TO THE
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 COMPANIES’ GENERATION FLEET ALONG WITH SIERRA’S 17 NATURAL GAS LOCAL DISTRIBUTION COMPANY (“LDC”)? 18 A. Yes, the production cost model PROMOD was used to further evaluate the system 19 reliability and projected firm gas transportation needs for northern and southern 20 generation plants, and Sierra’s LDC. The One Nevada Transmission Line or “ON 21 Line” was assumed to be in service for these analyses. A summary of the results is 22 set forth below. 23 24 Nevada Power: For Nevada Power, a load forecast with a hot summer and a cold 25 winter (based on 1 in 10 peak cooling-degree-day and heating-degree-day 26 (“HDD”)) was created and PROMOD was used to evaluate projected firm gas 27
28 Rodriguez-DIRECT 4
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1 transportation needs. Additional details on the development of the hot summer/cold 2 winter load forecast are provided in the technical appendices sponsored by Mr. 3 Terry Baxter. The following two scenarios were evaluated: 1) normal weather 4 conditions with existing firm gas transportation contracts; and 2) hot summer/cold 5 winter weather conditions with existing firm gas transportation contracts. The 6 results of this analysis indicate that maximum daily quantities deliverable with 7 Nevada Power’s existing portfolio natural gas transportation contracts would be 8 exceeded between 100 days in 2019, 101 days in 2020 and 95 days in 2021 under 9 normal weather conditions and up to 105 days 2019, 111 days in 2020 and 98 days
10 in 2021 days during hot weather conditions.
11
12 Sierra: Sierra evaluated the following two scenarios: 1) Normal weather 13 conditions; and 2) extreme weather conditions (based on 70 HDDs). The key 14 finding from this analysis is that Sierra will have enough firm transportation/storage d/b/a NV Energy Nevada Power Company Company Power Nevada
15 under contract to meet the average daily gas supply required on a winter day under
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 normal weather conditions with the availability of generation from the southern 17 system via ON Line. However, during an extreme winter weather scenario, 86 18 percent of the firm gas transport capacity will be needed to supply the LDC 19 requirements, limiting the use of natural gas by Sierra’s generation plants to the 20 remaining 14 percent of firm transport capacity. In the extreme case the majority of 21 the electric requirements will be met with a combination of different fuel sources, 22 purchased power, renewable energy and inter-company exchange from the southern 23 system. In the extreme weather scenario, Sierra did not observe Loss Of Load Hours 24 (“LOLH”) on the electric system. Other than renewing existing gas transportation 25 contracts discussed in the ESP, Sierra is not of the view that changes to the current 26 gas transportation strategy are warranted at this time. 27
28 Rodriguez-DIRECT 5
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1 Sierra’s analysis demonstrates that it has adequate gas transportation capacity and 2 should maintain that capacity. Adding additional capacity would mitigate a remote 3 loss of load risk, but would increase costs. However, reducing capacity would 4 increase the risk of loss of load in the winter to a level that is unacceptable. 5 6 9. Q. PLEASE DESCRIBE THE COMPANIES’ PHYSICAL GAS 7 PROCUREMENT PLAN. 8 A. Section 2.C.2 of the Supply Side Plan summarizes the Companies’ physical gas 9 procurement plan. The Companies are requesting acceptance and approval of its
10 plan to continue to procure physical gas using the four-season laddering strategy
11 originally approved by the Commission in Docket No. 09-09001, and most recently
12 reaffirmed by the Commission in Docket Nos. 17-09001 and 17-09002. Pursuant 13 to the four-season laddering strategy, the Companies will procure 25 percent of 14 projected monthly physical gas requirements per season for four seasons, subject d/b/a NV Energy Nevada Power Company Company Power Nevada
15 to the availability of conforming bids and the willingness of suppliers to accept
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 reasonable commercial terms. Physical gas volumes are to be procured at indexed 17 prices, subject to a per-million Btu cap on the premium. The per-million Btu cap 18 may be exceeded with prior approval from the Risk Committee. However, if the 19 Companies exceed the premium cap, and the procured gas that exceeded the 20 premium cap is not the least cost supply alternative, the Companies will provide 21 written notice to the Commission’s Regulatory Operations Staff (“Staff”) and the 22 Bureau of Consumer Protection (“BCP”). Furthermore, targeted physical gas 23 volumes will exclude any potential gas-fired generation to meet forward sales; gas 24 needed to meet forward sales will only be procured in the short-term. 25 26 27
28 Rodriguez-DIRECT 6
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1 10. Q. ARE THE COMPANIES REQUESTING CONFIDENTIAL TREATMENT 2 FOR CERTAIN INFORMATION RELATED TO THE PHYSICAL GAS 3 PROCUREMENT PLAN OR THE GAS TRANSPORTATION PLAN? 4 A. Yes. Portions of the Companies’ physical gas procurement plan contain the 5 premiums that the Companies may be willing to pay for physical gas supplies. This 6 confidential information is commercially sensitive and/or trade secret information 7 that derives independent economic value from not being generally known. 8 Disclosure of this confidential information to any third party would adversely affect 9 the Companies’ ability to obtain favorable terms from their gas suppliers.
10
11 11. Q. FOR HOW LONG DO THE COMPANIES REQUEST CONFIDENTIAL
12 TREATMENT? 13 A. The requested period for confidential treatment is for no less than five years. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada
15 12. Q. WILL CONFIDENTIAL TREATMENT IMPAIR THE ABILITY OF THE
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 COMMISSION STAFF OR THE BUREAU OF CONSUMER 17 PROTECTION (“BCP”) TO FULLY INVESTIGATE THE IRP? 18 A. No, in accordance with the accepted practice in Commission proceedings, the 19 Companies will provide the confidential material to Staff and the BCP under 20 standardized protective agreements. 21 22 13. Q. PLEASE DESCRIBE THE COMPANIES’ CURRENT OIL SUPPLY. 23 A. Section 2.C.3 of the IRP summarizes the Companies’ current oil supply. Sierra’s 24 LDC operations rely on flowing gas supply through interstate pipelines to meet 25 retail customer requirements. During extreme cold weather events or during a force 26 majeure event on an interstate pipeline, gas supply scheduled to Sierra’s power 27
28 Rodriguez-DIRECT 7
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1 plants may be diverted to support LDC gas supply operations. For these infrequent 2 situations, Sierra will dispatch the Nevada Power units and transfer power from 3 south to north using the ON Line. Sierra will maintain diesel inventories at Clark 4 Mountain Peakers 3 and 4 as an alternate fuel during emergency events only to 5 allow the use of existing pipeline transportation capacity to support peak LDC use.
6
7 14. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY? 8 A. Yes.
9
10
11
12 13 14 d/b/a NV Energy Nevada Power Company Company Power Nevada
15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 18 19 20 21 22 23 24 25 26 27
28 Rodriguez-DIRECT 8
Page 99 of 198 STATEMENT OF QUALIFICATIONS
PATRICIA RODRIGUEZ
NEVADA POWER COMPANY d/b/a NV Energy SIERRA PACIFIC POWER COMPANIES d/b/a NV Energy 6226 W. Sahara Ave. Las Vegas Nevada 89146 (702) 402-2434 Education Bachelor of Science in Electrical Engineering, University of Nevada Las Vegas 2005.
Professional Experience 2015 through Present Manager, Gas Transportation Planning NV Energy Responsibilities include planning and analysis of gas transportation needs to ensure sufficient supply to the generation fleet and natural gas customers. Additional responsibilities include development and implementation of work plans to support corporate contract negotiations, planning, budgeting, controls, portfolio optimization, cost reduction and risk management.
2014 through 2015 Senior Engineer, Distribution Planning NV Energy Responsibilities included performing contingency analysis, distribution load flow analysis and providing service requirements for distribution load additions for area of responsibility (NVE Northeast Region). Additional responsibilities included working on different studies for renewable Rule 15 projects.
2012 through 2014 Staff Consultant, DSM Planning NV Energy Responsibilities included the planning, development and evaluation of Demand Side Management (DSM) programs including program selection and development, financial analysis, preparation of the DSM portion of the resource plan, measurement and verification of program results, analysis of results of programs and associated reporting.
2011 through 2012 Senior Engineer, Distribution Planning NV Energy Responsibilities included performing contingency analysis, distribution load flow analysis and providing service requirements for distribution load additions for area of responsibility (NVE Northwest Region). Additional responsibilities included working on different studies for mine additions served at the distribution level.
2008 through 2011 Engineer, Distribution Planning NV Energy Responsibilities included supporting the analysis and development of hot spot solutions, completing the Long Range Capacity Plan and providing service requirements for distribution load additions for area of responsibility. Additional responsibilities included the creation of the load
Page 100 of 198 forecast for substation transformers and feeders, distribution load flow analysis and updating the capital budget planning initiation documents based on the new forecast.
2007 through 2008 Senior Consultant, Project Controls NV Energy Responsibilities included monitoring and updating fully integrated design and construction project schedules, providing resource histograms, analyzing, reviewing and forecasting performance for various capital projects. Additional responsibilities included providing Primavera training to project managers, functional groups and project controls staff.
2005 through 2007 Associate Engineer, Project Controls Nevada Power Company Responsibilities and accomplishments included the development and maintenance of design and construction project schedules and the integration of them into the master project management schedule. Additional responsibilities included creating monthly reports and facilitating meetings with functional group leaders and project managers to review project progress.
2005 Student Intern, Project Controls Nevada Power Company Responsibilities and accomplishments included construction schedule updates, research and data entry for various systems.
Memberships
I participate as a Sierra representative on the WEG working group.
Page 101 of 198 Page 102 of 198 INGRID ROHMUND
Page 103 of 198 1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/ b/a NV Energy 3 2018 Joint Integrated Resource Plan (2019-2038) 4 Docket No. 18-06____
5 Prepared Direct Testimony of
6 Ingrid Rohmund 7
8 I. INTRODUCTION AND SUMMARY
9 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS
10 ADDRESS AND THE PARTY FOR WHOM YOU ARE FILING
11 TESTIMONY.
12 A. My name is Ingrid Rohmund. My business address is 500 Ygnacio Valley
Power Company 13 Road, Suite 250, in Walnut Creek, CA 94596. I am a Senior Vice President a d d/b/a NV Energy a v e 14 for Applied Energy Group, Inc. (“AEG”). I am providing testimony on behalf N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 of NV Energy (“the Company” or “Companies”), which is comprised of
16 Sierra Pacific Power Company d/b/a NV Energy (“Sierra”) and Nevada
17 Power Company d/b/a NV Energy (“Nevada Power”).
18
19 2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
20 EXPERIENCE.
21 A. I have more than 30 years of experience supporting utilities and other
22 agencies with Demand Side Planning (“DSM”) planning and end-use
23 forecasting. I have directed more than 60 DSM potential studies in the past
24 ROHMUND - IRP DIRECT 1
Page 104 of 198
1 10 years. A statement of my qualifications is attached as Exhibit Rohmund-
2 Direct-1 to this Direct Testimony.
3
4 3. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
5 A. I am presenting and co-sponsoring the DSM Market Potential Study
6 (“Study”) contained in Technical Appendix DSM-21. This Study was
7 completed as a collaboration between AEG and Tetra Tech (“Team”).
8
9 4. Q. ARE YOU SPONSORING ANY EXHIBITS?
10 A. Yes. I am sponsoring the following exhibit:
11 Exhibit Rohmund Direct-1 Statement of Qualification
12
Power Company 13 5. Q. PLEASE SUMMARIZE YOUR TESTIMONY IN THIS a d d/b/a NV Energy a v e 14 PROCEEDING. N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 A. In my direct testimony, I describe and explain how the Study was designed
16 and how the market potential for DSM programs was estimated. I also present
17 high-level results for the Companies together, as well as Nevada Power and
18 Sierra individually.
19
20 II. DSM POTENTIAL STUDY DESIGN DESCRIPTION
21 6. Q. WHAT IS THE PURPOSE OF A DSM POTENTIAL STUDY?
22 A. A study of this type provides an assessment of the market potential for
23 electricity savings for residential, commercial, industrial, street lighting and
24 ROHMUND - IRP DIRECT 2
Page 105 of 198
1 irrigation sectors within a defined geographic area, in this instance Nevada
2 Power’s and Sierra’s respective service territories. The Study prepared for
3 Nevada and Sierra identifies the potential to reduce annual gross electric
4 energy use and peak demand with energy efficiency efforts that can be
5 achieved by customers within the Nevada Power’s and Sierra’s respective
6 service territories and for the Study period (2019-2038). The Study focuses
7 on market potential within the three-year DSM Action Plan period, 2019-
8 2021.
9
10 7. Q. HOW WAS THE STUDY DESIGNED?
11 A. Although each market potential study is unique, each typically includes a
12 common set of tasks for estimating potential savings. The common set of
Power Company 13 tasks, as applied to the Companies’ Study, included the following: a d d/b/a NV Energy a v e 14 1. Gather primary and secondary data to support successful project work. N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 The Team identified, requested, and securely accessed the required data
16 items from each Company. This step also included other secondary data
17 sources such as the U.S. Energy Information Administration (“EIA”);
18 2. Perform a market characterization for Nevada Power and Sierra that
19 describes sector-level electricity use for the residential, commercial,
20 industrial, street lighting and irrigation sectors for the base year, 2016.
21 This included using the Company’s data and other secondary data sources
22 such as the EIA;
23
24 ROHMUND - IRP DIRECT 3
Page 106 of 198
1 3. Define and characterize a robust set of DSM measures to be applied to all
2 sectors, segments, and end uses;
3 4. Develop a baseline projection of energy consumption by sector, segment,
4 end use, and technology for 2017 through 2038 (“Baseline Projection”)
5 that assumes no future DSM programs; and
6 5. Estimate technical, economic, and achievable energy savings at the
7 measure level for the Study period.
8
9 The tasks above were completed for Sierra and Nevada Power separately
10 because they have distinct demographic and usage characteristics (i.e.,
11 population size and climate) that warrant separate analyses. However, the
12 Study was performed in the same way for Sierra and Nevada Power. For
Power Company 13 example, with one exception for Sierra’s irrigation sector, the same types of a d d/b/a NV Energy a v e 14 measures were assessed for both Companies. The irrigation sector was N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 analyzed only for Sierra, due to its concentration of agriculture. Results are
16 presented for the Companies as a whole and for Sierra and Nevada Power
17 separately in the Study report, which can be found in Technical Appendix
18 DSM-21.
19
20 8. Q. PLEASE DESCRIBE THE STUDY DATA COLLECTION TASK.
21 A. The Companies provided the Team with comprehensive customer billing
22 data, forecast assumptions, the 2016 Residential Appliance Saturation Study
23 (“RASS”) results, load forecasts, historical program achievements, and
24 ROHMUND - IRP DIRECT 4
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1 measurement and verification (“M&V”) reports to ensure that the modeling
2 was representative of its customer population. Secondary sources were used
3 to supplement the primary data. These included the EIA’s Annual Energy
4 Outlook (“AEO”), the Census Bureau’s American Community Survey, and
5 Team-developed energy databases and analysis tools. These secondary
6 resources are detailed within the Study report.
7
8 9. Q. PLEASE DESCRIBE THE MARKET CHARACTERIZATION TASK.
9 A. Market characterization requires a comprehensive description of how Nevada
10 Power and Sierra customers used electricity by end use and technology in
11 2016, the base year for the Study. Market profiles were developed that
12 disaggregate electricity usage into various end uses and technologies that
Power Company 13 reflect the market characteristics in the base year. Results of the RASS, which a d d/b/a NV Energy a v e 14 was completed by Tetra Tech, were used to ensure that the market profiles N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 were representative of market characteristics specific to Nevada Power and
16 Sierra customers.
17
18 10. Q. PLEASE DESCRIBE THE MEASURE LIST DEVELOPMENT TASK.
19 A. After the market profiles were developed, the next step was to develop the
20 list of DSM measures for consideration in the Study. The Team developed
21 the measure list in close collaboration with Company personnel to ensure that
22 all relevant energy efficiency measures and demand response options were
23 included in the list. Measures currently in Company programs were used as
24 ROHMUND - IRP DIRECT 5
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1 the basis for the measure list. Then, the Team used its proprietary Database
2 of Energy Efficiency Measures (“DEEM”) to identify additional measures to
3 include in the study. DEEM is a database that contains detailed measure
4 characterizations based on a multitude of sources including regional and state
5 technical reference manuals. DEEM is continually updated to reflect the most
6 recent source material and state-of-the-art technological advancements. As a
7 result, the Study measure list includes measures that are currently available
8 in the Companies’ marketplace, as well as emerging technologies that are
9 expected to come online in the future. The preliminary list was reviewed by
10 DSM collaborative stakeholders, including Southwest Energy Efficiency
11 Project, Natural Resources Defense Council, and the Nevada Governor’s
12 Office of Energy, and their comments were included in the final measure list
Power Company 13 for the Study. a d d/b/a NV Energy a v e 14 N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 11. Q. PLEASE DESCRIBE THE BASELINE PROJECTION TASK.
16 A. The Baseline Projection estimates by end use and technology what electricity
17 use is likely to be in the absence of future utility programs. The Baseline
18 Projection was prepared for the 2017 through 2038. The savings from past
19 programs are embedded in the base-year market profiles and the baseline
20 projection assumes that these past programs cease to exist in the future. Thus,
21 the potential analysis captures all possible savings from future programs.
22 Factors that impact the Baseline Projection include customer growth,
23 economic factors (like electricity prices), appliance standards, building codes,
24 ROHMUND - IRP DIRECT 6
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1 and trends in technology growth. Customer growth was based on Sierra’s and
2 Nevada Power’s respective load forecast assumptions and trends in appliance
3 and equipment saturation are based on the AEO, as well as the Company’s
4 and the Team’s knowledge and experience within the service territories.
5
6 To develop the Baseline Projection, the Team also developed forecasts of
7 expected customer purchase decisions. Baseline customer purchasing
8 decisions were developed using several sources including the AEO,
9 ENERGY STAR™ appliance shipment data, prior participation in DSM
10 programs, and feedback from Company personnel. These “purchase shares”
11 also reflect baseline shifts caused by changing federal appliance standards
12 over the time horizon of the Study.
Power Company 13 a d d/b/a NV Energy a v e 14 The Team used AEG’s Load Management Analysis and Planning tool N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 (LoadMAP™) to perform the analysis. LoadMAP™ is a rigorous end-use
16 model that utilizes stock-accounting algorithms to account for equipment
17 saturations and energy use by customer segment over the forecast horizon.
18
19 The Team consulted with the Company’s Resource Planning department to
20 ensure that the Baseline Projection was consistent with key drivers of the
21 Company’s forecast. The Baseline Projection is the metric against which
22 potential savings are calculated, so care is taken to ensure that the projection
23 is appropriately aligned before moving forward with the analysis.
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1 12. Q. HOW WAS EFFICIENCY POTENTIAL ESTIMATED?
2 A. The Study estimated potential savings from future programs for four
3 scenarios for all sectors and end uses: technical, economic, market potential
4 and maximum achievable potential. These are developed at the measure level,
5 and results are provided as gross savings impacts over the Baseline Projection
6 Period. LoadMAP™ analyzed each measure in each customer segment based
7 on the attributes defined in the market characterization.
8
9 13. Q. HOW ARE THE LEVELS OF POTENTIAL DEFINED?
10 A. The Study followed industry best practices for estimating potential,
11 including:
12 1. Technical potential is a theoretical construct that assumes all customers
Power Company 13 will choose the most efficient option available in the market when they a d d/b/a NV Energy a v e 14 take action to replace appliances and equipment that has failed. It also N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 assumes they will adopt all measures available. Each decision is made
16 solely on the basis of maximum energy savings, regardless of cost.
17 Therefore, technical potential represents the theoretical upper limit of
18 DSM potential.
19 2. Economic potential represents savings from the most efficiency, cost-
20 effective measures. Each measure in the study was assessed for cost-
21 effectiveness using the Total Resource Cost (“TRC”) test and the
22 Company provided inputs for avoided costs, line loss factors, and
23 discount rates. Measures were considered cost-effective if their benefits
24 ROHMUND - IRP DIRECT 8
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1 outweighed their costs (when the TRC ratio was greater than or equal to
2 1.0). As with technical potential, economic potential assumes 100 percent
3 adoption by customers.
4 3. Market potential (and maximum achievable potential) refines economic
5 potential by applying customer participation rates that account for market
6 barriers, customer awareness and attitudes, program maturity, and recent
7 program history. Market potential maintains current levels of
8 participation for mature programs, but uses higher levels of participation
9 where additional opportunity is identified (e.g., residential cooling). It
10 also includes new measures, such as LED lighting, using market adoption
11 rates based on secondary research. Market potential represents the amount
12 of energy savings that may be achieved under current and expected
Power Company 13 market conditions within each Company’s service territory. a d d/b/a NV Energy a v e 14 4. Maximum Achievable Potential uses secondary research regarding N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 customer attitudes to accelerate market adoption by 50 percent for
16 residential customers and by 40 percent for nonresidential customers.
17 This assumes higher participation levels could be achieved by a
18 combination of reduced market barriers, such as increased utility
19 spending, and use of customer-preferred delivery mechanisms that lead
20 to full customer awareness and acceptance of energy efficiency measures.
21 Participation is capped at 85 percent to reflect a small subset of the
22 population will not participate in DSM programs.
23
24 ROHMUND - IRP DIRECT 9
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1 III. OVERALL DSM POTENTIAL STUDY RESULTS
2 14. Q. WHAT ARE THE RESULTS OF THE STUDY FOR THE COMPANY
3 AS A WHOLE?
4 A. Study results indicate a considerable potential for savings across all sectors
5 in the Companies’ service territories for a wide variety of end uses. Results
6 are presented in two different views. The first is an incremental view, which
7 represents the annual results for the next program cycle, 2019-2021. The
8 second is a cumulative view, which represents the long-run results over a 20-
9 year timeframe, and which supports the IRP”. For both of these views, results
10 are shown for the Company as a whole, which adds together the results for
11 Nevada Power and Sierra. Separate results for Nevada Power and Sierra are
12 detailed in the Study report.
Power Company 13 a d d/b/a NV Energy a v e 14 Two different views are presented to delineate the different mixes of measure N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 savings, and because the results are utilized differently by the Companies
16 depending on the application. Incremental savings account for the savings
17 attributable to measures installed in a program year. Cumulative savings
18 account for the lifetime savings of measures installed in the current program
19 year as well as previous program years. Measures with short measure lives,
20 such as HVAC tune-up measures, will not contribute to cumulative savings
21 over the entire three-year Action Plan period.
22
23
24 ROHMUND - IRP DIRECT 10
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1 15. Q. WHAT ARE THE INCREMENTAL MARKET POTENTIAL AND
2 THE INCREMENTAL MAXIMUM ACHIEVABLE POTENTIAL
3 RESULTS FOR THE COMPANY AS A WHOLE?
4 A. Table Rohmund Direct- 1 presents incremental gross savings potential
5 savings for the next program-cycle years, 2019 through 2021. It also presents
6 the Baseline Projection and the incremental savings as a percent of the
7 Baseline. Across the Company, the market potential and maximum
8 achievable potential savings are in the range of 352 GWh to 448 GWh per
9 year, which corresponds to 1.2 percent to 1.6 percent of the Baseline
10 Projection.
11 Table Rohmund Direct-1. NV Energy Incremental Potential for Planning Cycle
NVE Total, All Sectors Three-Year Planning Horizon 12 2019 2020 2021 Baseline Projection (GWh) 29,618 30,147 30,511 Power Company 13 a
d Gross Incremental Savings (GWh) d/b/a NV Energy a v e 14 Market Potential 358 352 357 N Maximum Achievable Potential 448 436 446
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 Economic Potential 692 664 687
Gross Energy Savings (% of Baseline) 16 Market Potential 1.3% 1.2% 1.2% Maximum Achievable Potential 1.6% 1.5% 1.5% 17 Economic Potential 2.5% 2.4% 2.4%
18
19 16. Q. UNDER THE POTENTIAL STUDY, WHAT ACCOUNTS FOR THE
20 SAVINGS FOR THE COMPANY AS A WHOLE?
21 A. A relatively small number of measures accounts for the majority of savings
22 in 2019-2021. In 2019, the following measures account for 70 percent of
23 market potential savings: commercial lighting, residential smart thermostats,
24 ROHMUND - IRP DIRECT 11
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1 residential central air conditioning (replace on burnout and retrofit), home
2 energy reports, and residential LED lighting.
3
4 17. Q. WHAT IS THE CUMULATIVE MARKET POTENTIAL AND THE
5 CUMULATIVE MAXIMUM ACHIEVABLE POTENTIAL RESULTS
6 FOR THE COMPANY?
7 A. Table Rohmund Direct-2 presents the Baseline Projection and cumulative
8 gross savings in gigawatt (“GWh”) for the 20-year planning horizon. It also
9 presents savings as a percent of the Baseline Projection. Market potential
10 begins at 358 GWh in 2019 (1.2 percent of Baseline) and finishes with 4,141
11 GWh (12.8 percent of Baseline) by the end of the study projection in 2038.
12 Table Rohmund Direct-2. Long-run Savings Potential for NV Energy
NVE Total, All Sectors 2019 2023 2028 2033 2038
Power Company 13 a d
d/b/a NV Energy Baseline Projection (GWh) 29,618 30,131 30,556 31,404 32,327 a v e 14 Gross Cumulative Savings (GWh) N Market Potential 358 1,396 2,427 3,399 4,141
and Sierra Pacific Power Company Pacific Power Sierra and Company 15
Maximum Achievable Potential 448 1,755 3,129 4,410 5,383 Economic Potential 692 2,739 4,899 6,827 8,188 16 Technical Potential 1,084 4,437 7,748 10,180 11,689 Gross Energy Savings (% of Baseline) 17 Market Potential 1.2% 4.6% 7.9% 10.8% 12.8% Maximum Achievable Potential 1.5% 5.8% 10.2% 14.0% 16.7% 18 Economic Potential 2.3% 9.1% 16.0% 21.7% 25.3% Technical Potential 3.7% 14.7% 25.4% 32.4% 36.2% 19
20
21 18. Q. WHAT ARE THE INCREMENTAL MARKET POTENTIAL AND
22 THE INCREMENTAL MAXIMUM ACHIEVABLE POTENTIAL
23 RESULTS FOR NEVADA POWER?
24 ROHMUND - IRP DIRECT 12
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1 A. Table Rohmund Direct-3 presents incremental gross savings potential savings
2 for Nevada Power for the next program-cycle years, 2019 through 2021. It
3 also presents the Baseline Projection and the incremental savings as a percent
4 of the baseline. For Nevada Power, the market potential and maximum
5 achievable potential savings are in the range of 262 GWh to 344 per year,
6 which corresponds to 1.3 percent to 1.7 percent of the Nevada Power Baseline
7 Projection.
8 Table Rohmund Direct-3. Nevada Power Incremental Potential for Planning Cycle NPC Total, All Sectors Three-Year Planning Horizon 9 2019 2020 2021
10 Baseline Projection (GWh) 20,439 20,621 20,758 Gross Incremental Savings (GWh)
Market Potential 274 262 275 11 Maximum Achievable Potential 342 326 344 12 Economic Potential 529 502 532 Gross Energy Savings (% of Baseline)
Power Company 13 Market Potential 1.3% 1.3% 1.3% a d Maximum Achievable Potential 1.7% 1.6% 1.7% d/b/a NV Energy a v e 14 Economic Potential 2.6% 2.4% 2.6% N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15
16 19. Q. UNDER THE STUDY, WHAT ACCOUNTS FOR THE SAVINGS FOR
17 NEVADA POWER?
18 A. At Nevada Power, a relatively small number of measures account for the
19 majority of savings in 2019-2021. Key measures driving the market potential
20 results include: commercial lighting, residential smart thermostats, residential
21 central air conditioning (replace on burnout and retrofit), home energy
22 reports, and residential LED lighting.
23
24 ROHMUND - IRP DIRECT 13
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1 20. Q. WHAT ARE THE CUMULATIVE MARKET POTENTIAL AND THE
2 CUMULATIVE MAXIMUM ACHIEVABLE POTENTIAL RESULTS
3 FOR NEVADA POWER?
4 A. Table Rohmund Direct-4 presents the Baseline Projection and cumulative
5 gross savings in GWh for the 20-year planning horizon for Nevada Power. It
6 also presents savings as a percent of the Baseline Projection. Market potential
7 begins at 274 GWh in 2019 (1.3 percent of Baseline) and finishes with 3,193
8 GWh (13.9 percent of Baseline) by the end of the study projection in 2038.
9 Table Rohmund Direct-4. Long-run Savings Potential for Nevada Power
10 NPC Total, All Sectors 2019 2023 2028 2033 2038
Baseline Projection (GWh) 20,439 21,032 21,758 22,381 23,012
11 Gross Cumulative Savings (GWh) Market Potential 274 1,079 1,883 2,632 3,193 12 Maximum Achievable Potential 342 1,358 2,430 3,418 4,157 Economic Potential 529 2,127 3,822 5,312 6,346
Power Company 13 Technical Potential 818 3,398 5,960 7,823 8,966
a d Gross Energy Savings (% of Baseline) d/b/a NV Energy a v e 14 Market Potential 1.3% 5.1% 8.7% 11.8% 13.9% N Maximum Achievable Potential 1.7% 6.5% 11.2% 15.3% 18.1%
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 Economic Potential 2.6% 10.1% 17.6% 23.7% 27.6%
Technical Potential 4.0% 16.2% 27.4% 35.0% 39.0% 16
17 21. Q. WHAT ARE THE INCREMENTAL MARKET POTENTIAL AND
18 THE INCREMENTAL MAXIMUM ACHIEVABLE POTENTIAL
19 RESULTS FOR SIERRA?
20 A. Table Rohmund Direct-5 presents incremental gross savings potential savings
21 for Sierra for the next program-cycle years, 2019 through 2021. It also
22 presents the Baseline Projection and the incremental savings as a percent of
23 the baseline. For Sierra, the market potential and maximum achievable
24 ROHMUND - IRP DIRECT 14
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1 potential savings are in the range of 82 GWh to 110 per year, which
2 corresponds to 0.9 percent to 1.2 percent of the Sierra Baseline Projection.
3 Table Rohmund Direct-5. Sierra Incremental Potential for Planning Cycle SPPC Total, All Sectors Three-Year Planning Horizon 4 2019 2020 2021 5 Baseline Projection (GWh) 9,179 9,527 9,753 Gross Incremental Savings (GWh) 6 Market Potential 84 90 82 Maximum Achievable Potential 106 110 102 7 Economic Potential 163 162 156 Gross Energy Savings (% of Baseline) 8 Market Potential 0.9% 0.9% 0.8% Maximum Achievable Potential 1.2% 1.2% 1.0% 9 Economic Potential 1.8% 1.7% 1.6%
10
11 22. Q. UNDER THE STUDY, WHAT ACCOUNTS FOR THE SAVINGS FOR
12 SIERRA?
Power Company 13 A. As with Nevada Power, a relatively small number of measures account for a d d/b/a NV Energy a v e 14 the majority of savings in 2019-2021 for Sierra. Key measures driving market N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 potential results include: commercial lighting, commercial and industrial
16 networked thermostats, home energy reports, residential LED lighting, and
17 residential central air conditioning (replace on burnout and retrofit). Home
18 energy reports represent a higher share of total savings for Sierra, compared
19 with Nevada Power.
20
21 23. Q. WHAT ARE THE CUMULATIVE MARKET POTENTIAL AND THE
22 CUMULATIVE MAXIMUM ACHIEVABLE POTENTIAL RESULTS
23 FOR SIERRA?
24 ROHMUND - IRP DIRECT 15
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1 A. Table Rohmund Direct-6 presents the Baseline Projection and cumulative
2 gross savings in GWh for the 20-year planning horizon for Sierra. It also
3 presents savings as a percent of the Baseline Projection. Market potential
4 begins at 84 GWh in 2019 (0.9 percent of Baseline) and finishes with 948
5 GWh (10.2 percent of Baseline) by the end of the study projection in 2038.
6 Table Rohmund Direct-6. Long-run Savings Potential for Sierra 7 SPPC Total, All Sectors 2019 2023 2028 2033 2038 Baseline Projection (GWh) 9,179 9,099 8,798 9,023 9,315 8 Gross Cumulative Savings (GWh) Market Potential 84 317 544 767 948 9 Maximum Achievable Potential 106 397 699 992 1,226
Economic Potential 163 612 1,077 1,515 1,843 10 Technical Potential 258 1,033 1,785 2,354 2,721
Gross Energy Savings (% of Baseline)
11 Market Potential 0.9% 3.5% 6.2% 8.5% 10.2% Maximum Achievable Potential 1.2% 4.4% 7.9% 11.0% 13.2% 12 Economic Potential 1.8% 6.7% 12.2% 16.8% 19.8% Technical Potential 2.8% 11.3% 20.3% 26.1% 29.2%
Power Company 13 a
d d/b/a NV Energy a v e 14 24. Q. HOW SHOULD THE RESULTS OF THE STUDY BE UTILIZED BY N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 THE COMPANIES IN DESIGNING AND SELECTING DSM
16 PROGRAMS AND MEASURES?
17 A. The Study was customized to reflect Nevada Power’s and Sierra’s respective
18 service territories using utility-specific data. Throughout this study, the Team
19 worked with the Company to understand the baseline characteristics of each
20 service territory, including a detailed understanding of energy consumption
21 in the territory, the assumptions and methodologies used in Nevada Power’s
22 and Sierra’s respective load forecasts, and recent DSM program
23 accomplishments. Using as much Company-specific data as possible ensures
24 ROHMUND - IRP DIRECT 16
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1 that the results of the study are representative of the marketplaces in which
2 the Companies operate.
3
4 The results of the Study have aided the Companies in developing their
5 program portfolio for 2019 through 2021 and also support their IRP process.
6 Savings estimates have been provided for specific measures, some of which
7 are already captured by existing DSM programs, and some that will provide
8 additional savings. The Study quantifies the savings and, importantly,
9 identifies the customer segments that can provide additional savings.
10
11 While the Study provides estimates of annual savings for hundreds of
12 individual measures, the results come from a model and variation in the
Power Company 13 outcomes in the real world are to be expected. Therefore, the Study provides a d d/b/a NV Energy a v e 14 reliable guidance for the overall savings that the Companies can achieve in N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15 the future. However, the Study results also provide the Companies with the
16 opportunity to deviate from specific annual values developed in the Study as
17 they design future programs.
18
19 IV. CONCLUSION
20 25. Q. PLEASE SUMMARIZE YOUR TESTIMONY IN THIS
21 PROCEEDING.
22 A. The Market Potential Study prepared for Nevada Power and Sierra provides
23 a comprehensive view of how customers used energy in the base year of the
24 ROHMUND - IRP DIRECT 17
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1 study (2016), and uses that information as a solid foundation for estimating
2 savings from a wide variety of DSM measures in the future. As a result of
3 this Study, the Companies are able to revisit current customer electricity use
4 patterns and existing programs with an eye toward developing their program
5 portfolios for 2019 through 2021. This provides the Companies with
6 tremendous insight, regarding their current program designs, and the
7 opportunity to refine existing programs and develop new programs using a
8 solid analytical and data-driven foundation.
9
10 26. Q. DOES THIS COMPLETE YOUR TESTIMONY?
11 A. Yes, it does.
12
Power Company 13 a d d/b/a NV Energy a v e 14 N
and Sierra Pacific Power Company Pacific Power Sierra and Company 15
16
17
18
19
20
21
22
23
24 ROHMUND - IRP DIRECT 18
Page 121 of 198 Exhibit Rohmund-Direct-1 Page 1 of 3
EXHIBIT ROHMUND-DIRECT-1
INGRID ROHMUND SENIOR VICE PRESIDENT
Professional Experience Ms. Rohmund oversees AEG’s Utility Consulting group, which encompasses planning, implementation support, EM&V, and related services. In this role, she helps utilities and other organizations optimize their demand-side and load management activities and meet new challenges through rigorous research and analysis. Ms. Rohmund also leads AEG’s Energy Analysis and Planning Practice. She has more than 25 years of experience modeling and performing statistical analysis of energy use at the national, regional, and utility service-area levels. Ms. Rohmund has been the project director on more than 60 potential studies conducted by AEG (formerly EnerNOC and Global Energy Partners) for utilities and agencies since 2007. She has also directed development of software tools, including end-use forecasting models, energy-analysis software, building simulation software and technology assessment software.
Expertise/Specialties • Demand-side management (DSM) potential and planning studies that include demand response, distributed generation and site-level renewables, fuel switching and behavioral programs. • Load forecasting; energy and technology modeling; market assessment; strategic planning. • Expertise in residential, commercial and industrial energy-use practices and the application of end-use technologies.
Relevant Project Experience Ms. Rohmund directs comprehensive planning studies for utilities and agencies across North America. These studies typically include some or all of the following activities: customer surveys; characterization of end-user energy use; end-use forecasting; assessment of energy and peak-demand savings from energy efficiency, demand response analysis, distributed generation, fuel switching, behavioral programs; supply curves development, program design; stakeholder engagement; and regulatory support, including expert testimony. Her current and recent clients include:
Ameren (IL & MO) Indianapolis Power & Light PEPCO Avista Inland Power & Light PNGC BG&E Kansas City Power & Light Portland General Electric Black Hills Kentucky Power (AEP) PSEG Long Island Central Hudson Gas & Electric LA Dept. of Water & Power Public Service of New Mexico Citizens Energy Group Manitoba Hydro SMECO Con Edison of NY Midcontinent ISO Seattle City Light Cowlitz PUD New Jersey BPU SCE Empire District Electric NIPSCO State of Hawaii EPRI NV Energy State of New Mexico FERC Oklahoma Gas & Electric Tacoma Power Company Idaho Power Company Omaha Public Power District TVA Indiana & Michigan Utilities (AEP) Oregon Trail Energy Coop Vectren Institute of Energy Efficiency (EEI) PacifiCorp Xcel
Page 122 of 198 Exhibit Rohmund-Direct-1 Page 3 of 3
Employment History • Senior Vice President, AEG Inc., formerly EnerNOC, Inc. (Utility Solutions Consulting Services group) and Global Energy Partners, LLC, 2007 – Present • Practice Director, Energy Insights, 2006 – 2007 • Vice President, EPRI Solutions, formerly Primen (EPRI Family of Companies) 2000 – 2006 • Economist and Principal, Regional Economic Research, Inc. (now Itron), 1986 – 1999
Education & Certifications • M.B.A., University of California, Irvine • B.A. in Economics and Political Science, University of California, San Diego
Selected Publications & Reports • Avista Corporation: Electricity Conservation Potential Assessment Studies: Q4 2018 (forthcoming), June 2017, July 2015, May 2013 and August 2011; Natural Gas Conservation Potential Assessment Studies: May 2018, April 2014 and April 2012 Commercial & Industrial Demand Response Potential Study, November 2014 • Public Service of New Mexico: EE Potential Study and Residential Appliance Saturation Survey, May 2018 Regulatory support for rate case, 2015 – present End-use Load Forecast Report, May 2014 • Tacoma Power, City of Tacoma: Conservation Potential Assessment for 2018-2037, November 2017 Conservation Potential Assessment for 2016-2035, October 2015 • End-use Forecasts for TNB Malaysia, October 2017 • Vectren Energy Delivery: Ohio, Natural Gas DSM Market Potential Study and Action Plan, October 2017 Indiana, Natural Gas DSM Market Potential Study and Action Plan, January 2015; Indiana, Electricity Market Potential Study and Action Plan, January 2013 • Kansas City Power & Light: 2016 DSM Market Potential Study, April 2017 Program design and regulatory support, September 2014 – present • PacifiCorp: Demand-side Resource Potential Assessment for 2019-2038, forthcoming in Q3, 2018; Demand-side Resource Potential Assessment for 2017-2036, January 2017; Demand-Side Resource Potential Assessment for 2015-2034, January 2015 Energy Management Program Design, August 2015 • Indianapolis Power & Light (IPL): DSM Market Potential Study (2018-2037), October 2016 2017 Action Plan for DSM Programs, May 2016 EE Market Potential Study and Action Plan, December 2012
Page 123 of 198 Exhibit Rohmund-Direct-1 Page 3 of 3
• American Electric Power Company: Indiana Michigan Power, Energy Efficiency Market Potential Study, June 2016 Kentucky Power Company Market Potential Assessment, June 2015 • PSEG Long Island Energy Efficiency Potential Study, June 2016 • Ameren Illinois: Program planning and regulatory support - ongoing DSM Market Potential Study, March 2016 DSM Market Potential Study May 2013 • Midcontinent ISO: Assessment of EE, DR and DG for Midcontinent ISO, March 2018 Assessment of EE, DR and DG for Midcontinent ISO, March 2016 EE and DR Potential Study for Midwest ISO, November 2011 • EmPOWER Maryland DSM Market Potential Study, April 2016, included separate studies for BG&E, PEPCO, DelMarva Power, Potomac Edison, and Southern Maryland Electricity Cooperative • Omaha Public Power District Demand-Side Management Market Potential Study, Volumes 1-4, August 2014
• “Factors Affecting Electricity Consumption in the U.S. (2010-2035),” IEE Report, March 2013. http://www.edisonfoundation.net/iee/Documents/IEE_FactorsAffectingUSElecConsumption_Final.pdf • Seattle City Light Conservation Potential Assessment, 2014 and May 2012 • Tennessee Valley Authority Energy Efficiency and Demand Response Potential Assessment, January 2012 • State of New Jersey Energy Efficiency Market Potential Assessment. 2012 • State of New Mexico Potential Study, June 2011 • “Assessment of Electricity Savings in the U.S. Achievable through New Appliance/Equipment Efficiency Standards and Building Efficiency Codes (2010 - 2025)”, Institute for Electric Efficiency, May 2011 • Energy Efficiency Potential Study for Consolidated Edison Company of New York, Inc., Volumes 1-5, Global Report #1269, March 2010 • “A National Assessment of Demand Response Potential”, Federal Energy Regulatory Commission, June 2009. With The Brattle Group and Freeman Sullivan & Company. • “Assessment of Achievable Potential from Energy Efficiency and Demand Response Programs in the U.S. (2010-2030)”, Electric Power Research Institute, Technical Report 1016987, January 2009.
Energy Analysis Software • LoadMAP, Load Management Analysis and Planning tool, for end-use forecasting and DSM planning, 2007 - present • EnergyShape, AEG’s web-based load shape library and toolkit. Ongoing • COMMEND, EPRI’s Commercial End-Use Energy Forecasting Model, 1986 - 1995 • REEPS, EPRI’s Residential End-Use Energy Planning System, 1990-1995
Page 124 of 198 Page 125 of 198
JOSEPH SINOBIO
Page 126 of 198 1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA Nevada Power Company d/b/a NV Energy and 2 Sierra Pacific Power Company d/b/a NV Energy 3 2018 Joint Integrated Resource Plan (2019-2038) 4 Docket No. 18-06___
5 PREPARED DIRECT TESTIMONY OF 6 JOSEPH V. SINOBIO 7
8 1. Q. PLEASE STATE YOUR NAME, JOB TITLE, BUSINESS ADDRESS 9 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
10 A. My name is Joseph V. Sinobio. I am a Manager, Major Projects-Delivery for
11 Nevada Power Company d/b/a NV Energy (“Nevada Power”) and Sierra Pacific
12 Power Company d/b/a NV Energy (“Sierra” and, together with Nevada Power, Energy 13 the “Companies” or “NV Energy”). My business address is 6226 W. Sahara 14 Ave. in Las Vegas, Nevada. I am filing testimony on behalf of Nevada Power d/b/a NV Nevada Power Company Company Power Nevada
15 and Sierra.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16
17 2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND 18 EXPERIENCE. 19 A. I have been continuously employed by NV Energy since September 1988. I 20 have experience in electric utility transmission and distribution planning, and 21 distributed energy resources. More details regarding my professional 22 background and experience are set forth in my Statement of Qualifications, 23 included as Exhibit Sinobio-Direct-1. 24 25 26 27
28 Sinobio - IRP DIRECT 1
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1 3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS MANAGER, 2 MAJOR PROJECTS-DELIVERY. 3 A. As Manager, Major Projects-Delivery, my responsibilities include supporting 4 distributed energy resource planning, grid modernization, and distribution 5 automation issues and projects on the Companies’ distribution systems.
6
7 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 8 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 9 A. Yes. I have provided written testimony and appeared before the Commission in
10 various dockets, most recently the 2017 advice letter filings by the Companies
11 to modify their Generating Facility Interconnection Rule No. 15 (Nevada Power
12 in Docket No. 17-06014 and Sierra in Docket No. 17-06015). I have also Energy 13 participated in Commission workshops in various investigatory dockets, most 14 recently the 2017 Investigation and Rulemaking to implement Senate Bill 146 d/b/a NV Nevada Power Company Company Power Nevada
15 in investigatory Docket No. 17-08022.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 5. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT 18 TESTIMONY IN THIS CASE?
19 A. My testimony is in support of the Distribution Planning section of the Supply 20 Side Plan narrative. There I discuss the effect of Net Energy Metering on 21 distribution system reliability, and distributed resources planning. 22 23 6. Q. ARE YOU SPONSORING ANY EXHIBITS? 24 A. Yes, I am sponsoring Exhibit Sinobio-Direct-1. 25 26 7. Q. DOES THIS COMPLETE YOUR TESTIMONY? 27 A. Yes, it does.
28 Sinobio - IRP DIRECT 2
Page 128 of 198 Exhibit Sinobio_Direct-1 Page 1 of 2
Statement of Qualifications for JOSEPH V. SINOBIO
Summary of Qualifications
Over 29 years of electric utility experience, including 24 years of leadership experience, all for NV Energy (Nevada Power Company and Sierra Pacific Power Company) based in Las Vegas, NV. Highly experienced in electric utility distribution planning. Experienced in management and leadership techniques, goal-setting, process analysis, capital budgeting, technical writing, and providing written and verbal regulatory testimony. Growing expertise in distributed energy resources, smart grid technology, grid modernization, and integrated grid planning.
Professional Experience
Manager, Major Projects-Delivery June 2016 - Present Nevada Power Company and Sierra Pacific Power Company (d/b/a NV Energy)
Directly manage a team responsible for supporting distributed energy resource planning, grid optimization, and distribution automation issues and projects.
Manager, Distribution Planning January 2005 – June 2016 Nevada Power Company and Sierra Pacific Power Company (d/b/a NV Energy)
Directly managed a team responsible for the regional electric Distribution Planning function.
Director, Distribution Technical Services March 2001 – January 2005 Nevada Power Company and Sierra Pacific Power Company
Directed a team responsible for the regional Distribution Standards, electric Distribution Planning (34.5 kV and below), Central Mapping, and Distribution Operations Technical Support functions.
Manager, Regional Electric Technical Services May 2000 – March 2001 Nevada Power Company and Sierra Pacific Power Company
Managed a team responsible for the regional electric Distribution Planning, Central Mapping, and the Distribution Operations Technical Support functions.
Manager, Regional Electric Distribution Planning September 1999 - May 2000 Nevada Power Company and Sierra Pacific Power Company
Directly managed a team responsible for the regional electric Distribution Planning and Distribution Operations Technical Support.
Manager, Distribution Planning & Analysis January 1998 – September 1999 Nevada Power Company
Page 129 of 198 Exhibit Sinobio_Direct-1 Page 2 of 2
Directly managed a Distribution Planning team.
Manager, Distribution Planning, Standards & Analysis January 1994 – January 1998 Nevada Power Company
Managed a Distribution Planning and Distribution Standards team.
Engineer II - III, Transmission Planning July 1991 – January 1994 Nevada Power Company
Performed detailed engineering analysis to recommend transmission system capital improvement projects, transmission construction requirements for new load additions, and system transfer capability using WSCC powerflow software. Improved departmental analysis procedures by developing a transmission master plan for the southern Las Vegas Valley (+-100 square mile area).
Engineer I - II, Distribution Planning April 1989 – July 1991 Nevada Power Company
Performed engineering analysis in developing distribution master plans, distribution load forecasts, and in recommending distribution system capital improvement projects, distribution construction requirements for new load additions, and new distribution feeder and substation additions for the northern and western Las Vegas Valley (+-200 square mile area with an average annual growth rate of approximately 5%).
Training, Education, & Memberships
Leadership Development Program; Supervisor’s Workshop; Team Building; Lessons in Leadership; Change Management; Project Management; Finance & Accounting for Non-Financial Managers; Management Accounting; Managing Multiple Projects, Objectives & Deadlines; Media Training; Customer Relations Training; Situational Leadership II; Criticism & Discipline Techniques for Managers, Mutual Gains; Seven Management & Planning Tools; Managers and Supervisors Conference; Utility Finance & Accounting; Replacing Negativity with Enthusiasm; Coaching Skills for Managers & Supervisors; 7 Habits Fundamentals Workshop; Spatial Load Forecasting; Assertive Leadership Skills; The 4 Disciplines of Execution; Creative Leadership Workshop.
Bachelor of Engineering Degree in Electrical Engineering; State University of New York @ Stony Brook; Stony Brook, NY; 1988.
I.E.E.E. Power & Energy Society Member
Page 130 of 198 Page 131 of 198
DAVID ULOZAS
Page 132 of 198 1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Nevada Power Company d/b/a NV Energy Sierra Pacific Power Company d/b/a NV Energy 3 4 2018 Joint Integrated Resource Plan (2019-2038) Docket No. 18-06___ 5 PREPARED DIRECT TESTIMONY OF 6 Dave Ulozas 7 8 9 I. INTRODUCTION
10 1. Q. PLEASE STATE YOUR NAME, JOB TITLE, BUSINESS ADDRESS
11 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY. 12 A. My name is Dave Ulozas. I am the Senior Vice President of Renewable 13 Energy and Origination for Sierra Pacific Power Company d/b/a NV Energy /b/a NV Energy d
14 (“Sierra”) and Nevada Power Company d/b/a NV Energy (“Nevada Power” nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 and together with Sierra, the “Companies”). My business address is 6226 16 West Sahara Avenue in Las Vegas, Nevada. I am filing testimony on behalf 17 of the Companies. 18 19 2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND 20 AND EXPERIENCE. 21 A. I hold a Bachelor of Science Degree in Management from Bellevue 22 University in Bellevue, Nebraska. I served in the U. S. Navy from 1984 – 23 1993. Before joining the Companies, I served as Vice President, Generation 24 at MidAmerican Energy Company for more than seven years. In my current 25 role, I serve as Senior Vice President, Renewable Energy and Origination. 26 My responsibilities include the procurement, negotiation and contract 27 oversight of renewable energy resources. More details regarding my
28 Ulozas-IRP DIRECT 1 Page 133 of 198
1 professional background and experience are set forth in Exhibit Ulozas- 2 Direct-1. 3 4 3. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 5 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 6 A. No, I have not. 7 8 4. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT
9 TESTIMONY IN THIS PROCEEDING?
10 A. I sponsor the Companies’ Renewable Energy Plan, Section 2.D of the 2018
11 Joint Integrated Resource Plan (“IRP”) as it relates to the both near-term 12 outlook and long-term planning for the Nevada’s Renewable Portfolio 13 Standard (“RPS”). I also sponsor and support the processes followed and /b/a NV Energy d
14 results of the 2018 Renewable Energy Request for Proposals (“2018 nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 Renewable RFP”), including the six power purchase agreements (“PPAs”) 16 between the Companies and several different counterparties. 17 18 5. Q. WHAT EXHIBITS ARE ATTACHED TO YOUR TESTIMONY? 19 A. I have attached the following exhibits to my testimony:
20 • Exhibit Ulozas-Direct-1 Statement of Qualifications 21 • Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs 22 23 6. Q. WHAT MATERIALS ARE YOU SPONSORING? 24 A. I am sponsoring the following materials, which are included in the 25 Technical Appendices accompanying the Supply Side Plan:
26 • REN-1 – 2018 Renewable RFP, Top Projects PPA 12x24 Supply 27 Tables; 28 Ulozas-IRP DIRECT 2
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1 • REN-2 – 2018 IRP Generic Placeholder 12x24 Supply Table; 2 • REN-3 – CONFIDENTIAL - 2018 IRP Generic Placeholder Pricing; 3 • REN-4 – 2018 IRP All Renewable and market Cases; 4 • REN-5 – 2018 Renewable RFP Protocol with Attachments; 5 • REN-6-DFS(a) – CONFIDENTIAL -- Long-Term Renewable Power 6 Purchase Agreement for Dodge Flat Solar, LLC;1
7 • REN-06-DFS(b) – Dodge Flat Solar RPS Regulation Roadmap; 8 • REN-6-FSR(a) – CONFIDENTIAL -- Long-Term Renewable Power
2
9 Purchase Agreement for Fish Springs Ranch Solar, LLC;
10 • REN-06-FSR(b) – Fish Springs Ranch RPS Regulation Roadmap;
11 • REN-6-BMS(a) – Long-Term Renewable Power Purchase Agreement
12 for Battle Mountain Solar SP, LLC;
13 • REN-06-BMS(b) – Battle Mountain Solar RPS Regulation Roadmap; /b/a NV Energy d
14 • REN-6-ESM(a) – Long-Term Renewable Power Purchase Agreement nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 for 325MK 8ME, LLC;
16 • REN-06-ESM(b) – 8minutenergy RPS Regulation Roadmap; 17 • REN-6-CMS5(a) – Long-Term Renewable Power Purchase Agreement
18 for Copper Mountain Solar 5, LLC;
19 • REN-06-CMS5(b) – Copper Mountain Solar 5 RPS Regulation 20 Roadmap;
21 • REN-6-TS5(a) – Long-Term Renewable Power Purchase Agreement 22 for Techren Solar V LLC;
23 • REN-06-TS5(b) – Techren Solar V RPS Regulation Roadmap; 24 • REN-7 – CONFIDENTIAL - RFP Initial Short List Scoring Report 25 26 1 Only Exhibit 21 to this PPA is confidential 27 2 Only Exhibit 21 to this PPA is confidential.
28 Ulozas-IRP DIRECT 3
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1 • REN-8 – CONFIDENTIAL - Final Due Diligence and Selection 2 Reports
3 • REN-9 – CONFIDENTIAL - 2018 Renewable RFP Report of the IE or 4 Independent Evaluator 5 6 7. Q. ARE ANY OF THE MATERIALS YOU ARE SPONSORING 7 CONFIDENTIAL? 8 A. Yes. Confidential Technical Appendices REN-3, REN-6-DFS(a) and REN-
9 6-FSR(a), REN-7, REN-8 and REN-9 are confidential. REN-3 contains
10 forecasted pricing for renewable projects. This information must remain
11 confidential in order to provide the Companies with the best opportunity to 12 transact in the marketplace on behalf of their customers. Exhibits 21 in the 13 PPAs for the Dodge Flat and Fish Springs projects (REN-6-DFS(a) REN- /b/a NV Energy d
14 6-FSR(a) set for the site plans for these two projects, which the developer nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 has requested remain confidential in order to protect its own commercially 16 confidential and trade secret information. REN-7, REN-8 and REN-9 17 contain the results of the Companies’ and the Independent Evaluator’s 18 (“IE’s”) evaluation of the projects from the initial bidder short list coming 19 out of the 2018 Renewable RFP, including pricing and scoring results for 20 each of the bids submitted. This information was provided to the Companies 21 by bidders under a commitment, expressed through the 2018 Renewable 22 RFP, to not share confidential bidder information with competitors. In 23 addition, this information contains the due diligence reports from subject 24 matter experts evaluating projects that bid into the 2018 Renewable RFP. 25 Confidentiality of the Companies’ economic and technical evaluations of 26 bids is essential to a successful competitive solicitation. 27 28 Ulozas-IRP DIRECT 4
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1 8. Q. FOR HOW LONG DO THE COMPANIES REQUEST 2 CONFIDENTIAL TREATMENT OF THIS INFORMATION? 3 A. The requested period for confidential treatment is for no less than five years. 4 5 9. Q. WILL CONFIDENTIAL TREATMENT IMPAIR THE ABILITY OF 6 THE COMMISSION’S REGULATORY OPERATIONS STAFF 7 (“STAFF”) OR THE NEVADA ATTORNEY GENERAL’S BUREAU 8 OF CONSUMER PROTECTION (“BCP”) TO FULLY
9 INVESTIGATE THE INFORMATION SET FORTH IN THIS
10 FILING?
11 A. No, in accordance with the accepted practice in Commission proceedings, 12 the confidential material will be provided to Staff and the BCP under 13 standardized protective agreements with them. /b/a NV Energy d
14 nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 II. PLANNING TO COMPLY WITH NEVADA’S RPS 16 10. Q. PLEASE DESCRIBE THE RPS. 17 A. Nevada’s RPS requirement is currently set at 20 percent of retail sales. This 18 means that fully 20 percent of the energy that Nevada Power and Sierra 19 provide to retail customers must be sourced from qualified renewable 20 resources. The RPS increases to 22 percent in 2020, before increasing to 25 21 percent in 2025. The RPS contains a solar “carve out” that requires that a 22 minimum of 6 percent of the overall credit requirement be met with credits 23 from solar resources. 24 25 Nevada utilizes a portfolio energy credit (“PC”) system to enforce the RPS. 26 Eligible PCs can come from multiple sources beyond just net generation in 27 the current year. The renewable energy planning section of this IRP is based 28 Ulozas-IRP DIRECT 5
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1 on the existing statutes and regulations governing the eligibility for and 2 calculation of PCs. These rules include a limited allowance for PCs from 3 energy efficiency and conversation measures that can be used to meet the 4 RPS; the elimination of the solar multiplier for projects placed into 5 operation on January 1, 2016 or later; and the elimination of station usage 6 for projects placed into operation on January 1, 2016 or later (except in the 7 case of the geothermal facilities, where the station service energy is used 8 for the extraction, transportation, pumping or compressing of geothermal
9 brine).
10
11 11. Q. PLEASE DESCRIBE NEVADA POWER’S RPS OUTLOOK FOR 12 THE ACTION PLAN PERIOD. 13 A. Nevada Power exceeded the 2017 RPS requirement as well as the 2017 /b/a NV Energy d
14 solar RPS requirement, ending 2017 with and RPS compliance result of nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 23.1 percent, 44.5 percent of that from solar generation. Nevada Power is 16 also well positioned to meet its 2019 and 2020 RPS obligations and, 17 although in 2021 it expects to comply with the RPS, there is a risk it may 18 not comply. As discussed below, this risk primarily stems from whether 19 Crescent Dunes can be successful in resolving its operating issues. 20 21 While Nevada Power’s immediate RPS compliance outlook is positive, 22 there are risks that could shift Nevada Power’s compliance outlook to 23 tenuous. The primary reason for this caution is the Crescent Dunes facility. 24 Crescent Dunes is a large, 110 megawatt (“MW”), solar thermal generator 25 that was expected to deliver in excess of 500,000 kPCs (thousand PCs) 26 annually. Since declaring commercial operation in late 2015, Crescent 27 Dunes has experienced frequent and prolonged outages. The current 28 Ulozas-IRP DIRECT 6
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1 outlook shows a slow recovery in the amount of expected energy and PCs 2 from 25 percent in 2019, to 50 percent in 2020, and 75 percent in 2021. 3 Although the forecasting model indicates that Nevada Power should have 4 sufficient PCs to meet both the RPS and its other credit obligations during 5 the Action Plan period (2019-2021), it will begin to fall short in 2027. 6 However, experience has shown that renewable projects can prove 7 unpredictable. Assuming Crescent Dunes is able to resolve all of its 8 operating issues, performance issues may arise with another renewable
9 resource, or lost PCs may amass to a point that they must be replenished.
10
11 As a result, Nevada Power is seeking Commission approval of three new 12 PPAs, for a combined total of approximately 600 MW of new renewable 13 resources. Most of this new generation is not expected begin commercial /b/a NV Energy d
14 operation until 2022, just outside of the Action Plan period. However, this nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 new generation is essential for Nevada Power’s future compliance with the 16 RPS. 17 18 12. Q. PLEASE DESCRIBE SIERRA’S RPS OUTLOOK FOR THE 19 ACTION PLAN PERIOD. 20 A. Sierra’s current renewable portfolio no longer generates enough PCs to 21 sustain its future RPS credit needs. This is the result of expiring long-term 22 contracts, for which replacement contacts have not been secured. Sierra has 23 managed this situation in the short-term by drawing down on PCs banked 24 from prior years and by utilizing PC repayments from Nevada Power. 25 However, both options will not extend compliance beyond the end of the 26 Action Plan period. By 2021, the credit bank with Nevada Power will be 27 drawn down to near zero, and Nevada Power will have fully repaid its credit 28 Ulozas-IRP DIRECT 7
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1 obligation to Sierra. To address this impending PC shortfall, Sierra must 2 seek new renewable resources to not only replace what has or will be lost 3 due to expiring PPAs, but also to keep pace with scheduled increases to the 4 RPS. 5 6 13. Q. IS SIERRA EXPECTED TO COMPLY WITH THE RPS IN 2019- 7 2021? 8 A Yes. Sierra exceeded the 2017 RPS requirement and the 2017 solar RPS
9 requirement, ending 2017 with RPS compliance of 25.5 percent, with 31.0
10 percent from solar generation. Sierra can manage RPS compliance through
11 the Action Plan period by drawing down on PCs banked from prior years 12 and by utilizing PC repayments from Nevada Power. However, together, 13 both options will only extend compliance through 2021. By the end of 2021, /b/a NV Energy d
14 the credit bank will have been drawn down to near zero (27,000 kPCs), and nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 Nevada Power will have fully repaid its credit obligation to Sierra. 16 17 Sierra expects to comply with the RPS until 2021. Without securing 18 additional renewable energy and PCs in 2022, Sierra will not maintain 19 compliance with the RPS beyond 2021. To address the impending PC 20 shortfall, Sierra is seeking Commission approval of approximately 401 MW 21 of new renewable generation. This new generation is projected to declare 22 commercial operation in mid-to-late 2021, which will ensure Sierra’s future 23 compliance with the RPS going forward. 24 25 26 27
28 Ulozas-IRP DIRECT 8
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1 14. Q. PLEASE DESCRIBE GENERALLY THE RPS RENEWABLE PLAN 2 DEVELOPED FOR THE IRP. 3 A. The Companies use a model to forecast future PC requirements and PC 4 supplies. The purpose of the model is to determine whether the Companies 5 will have a sufficient number of PCs to meet their RPS obligations. If, 6 outside the Action Plan period, the model indicates that the PC supply is 7 insufficient to meet the RPS, generic placeholder projects are added, as 8 needed, to fill the credit gaps. A supply table for the generic renewable
9 placeholder project is set forth in Technical Appendix REN-2. Pricing for
10 the generic renewable placeholder is set forth in Confidential Technical
11 Appendix REN-3. 12 13 Key inputs to the model include a list of current operating renewable /b/a NV Energy d
14 resources, all approved renewable resources under development or nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 construction, and all other sources of eligible credits. The model 16 incorporates all statutory and regulatory limitations, as well as non-RPS 17 portfolio credit obligations, in order to calculate the total number of eligible 18 credits available to meet the RPS for each planning year. This total is then 19 compared against the forecast credit requirement to determine whether each 20 Company will have a sufficient number of credits to meet its RPS 21 obligation. Below are the key assumptions that are incorporated into the 22 model:
23 • Existing contracts will expire in accordance with their terms. The 24 Companies do not automatically assume that existing contracts are 25 renewed;3
26 3 This does not imply that the Companies would rule out renewing existing agreements. Rather, it recognizes the uncertainty as to whether the resource could continue to support ongoing generation and 27 whether the Companies and the counterparty can come to terms on renewing the agreement. 28 Ulozas-IRP DIRECT 9
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1 • The Companies adjusted the expected amount of energy and 2 associated PCs from renewable facilities for the action period 2019- 3 2021 in cases where the historic generation, based on two or more 4 years of data, consistently varied from that of the contractual or 5 expected supply table. This is consistent with the methodology that 6 the Companies used for the past several years in developing its 7 Energy Supply Plan (“ESP”). This adjustment recognizes that 8 options to address underperformance within a shorter planning
9 window are limited. It also aligns the short-term and long-terms
10 plans. No adjustment is made post action period generation;
11 • PCs from the Renewable Generations incentive programs will 12 continue until funds are exhausted and/or the programs expire in 13 2021, and solar systems placed into service after 2015 do not qualify /b/a NV Energy d
14 for the solar multiplier. The plan assumes that the number of credits nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 for Renewable Generations will plateau in 2022 and then remain 16 flat;
17 • The percent of annual PC requirements met from energy efficiency 18 and conservation measures would be limited to no more than 20 19 percent of the credit total, decreasing to no more than 10 percent of 20 the total in 2020, and finally 0 percent of the total starting in 2025;
21 • Surplus PCs are not sold but are instead carried forward without 22 limitation;
23 • Nevada Power will continue to repay all PCs borrowed from Sierra 24 and will fulfill its repayment obligation by the end in 2021. The 25 repayment scheduled will ensure that all credits are fully repaid 26 27
28 Ulozas-IRP DIRECT 10
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1 before Sierra would be required to contract for new renewable 2 resources;4
3 • Solar photovoltaic (“PV”) systems degrade starting the year 4 following the first full year of operation;
5 • Post 2016, geothermal projects and placeholders would continue to 6 qualify for station usage credits but all other technologies would no 7 longer qualify;
8 • The plan includes the projected energy from all Commission
9 approved Nevada GreenEnergy Rider (“NGR”) agreements as of
10 May 2018 where the PCs associated with output of these systems
11 has been assigned to the customer under the tariff, and therefore, 12 cannot be used by Sierra or Nevada Power towards meeting the 13 RPS; /b/a NV Energy d
14 • The plan assumes no further changes to the existing statutory and nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 regulatory regime; and
16 • Finally, the preferred plan upon which the 2018 ESP is based 17 assumes the approval of three new Sierra PPAs and three new 18 Nevada Power PPAs. If approved, the Companies would not realize 19 the full benefit of these projects until 2022. 20 21 15. Q. PLEASE EXPLAIN THE ASSUMPTIONS AND METHODOLOGY 22 UNDERLYING THE NEAR TERM ADJUSTMENTS MADE TO 23 THE RENEWABLE EXPANSION PLAN. 24
25 4 The repayment over a five-year period is a modeling protocol in the renewable planning process but 26 is not intended to reflect how and when actual repayments would be made since such amounts would depend on the factual circumstances that will occur during this time period (e.g., load, renewable generation, changes 27 in law, etc.). 28 Ulozas-IRP DIRECT 11
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1 A. The Companies have attempted to capture and reflect actual historical 2 generation trends of the current renewable fleet based on two or more years 3 of operating data. The Companies adjusted the supply table based on this 4 historical trend to reflect the most recent operating data after coordinating 5 with internal contract owners to account for potential short-term anomalies. 6 Historical output trends for renewable projects under contract with Sierra 7 resulted in a decrease in the amount of excepted energy and PCs for four 8 projects. In total, these decreases lowered the amount of projected energy
9 and PCs by an average of two percent over the 2019-2021 Action Plan
10 period.
11 12 The same approach for Nevada Power resulted in adjustments to the amount 13 of energy and PCs for 13 projects, with both increases (two projects) and /b/a NV Energy d
14 decreases (11 projects). In total, these adjustment lowered the amount of nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 renewable energy by an average 6.9 percent over the 2019-2021 Action 16 Period. The majority of this decrease is driven by the downward adjustment 17 from Crescent Dunes, as discussed above. This approach is more accurate 18 and increases the reliability of the overall energy supply used in long-term 19 planning. 20 21 16. Q. THE COMPANIES ARE PROPOSING TO EXECUTE SIX NEW 22 PPAS FOR OVER A GIGAWATT OF RENEWABLE ENERGY IN 23 THIS IRP. WHAT IS THE MINIMUM NEEDED TO MAINTAIN 24 COMPLIANCE? 25 A. The Companies modeled an alternative compliance plan that adds a single 26 project, 8minutenergy’s Eagle Mountain Shadow Solar Farm, to Sierra’s 27
28 Ulozas-IRP DIRECT 12
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1 renewable energy portfolio.5 This one low-cost contract would provide 2 sufficient PCs to extend Sierra’s compliance with the RPS for a single year, 3 through 2022. Sierra would need to seek the approval of additional 4 resource(s) in order to maintain compliance past 2022. 5 6 17. Q. WHAT IS THE RPS COMPLIANCE OUTLOOK FOR SIERRA AND 7 NEVADA POWER SHOULD ALL SIX OF THE PPAS PRESENTED 8 FOR APPROVED BE REJECTED?
9 A. Sierra will be RPS non-compliant starting in 2022. The deficit would
10 continue to grow as additional PPAs expire, and prior year deficits are
11 rolled forward. Nevada Power would also be at risk of being non-compliant 12 in 2027, depending on whether Crescent Dunes is able to resolve its current 13 operating issues. /b/a NV Energy d
14 nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 III. THE 2018 RENEWABLE RFP AND THE SIX NEW RENEWABLE PPAS 16 THAT RESULTED 17 18. Q. HOW HAVE YOU ORGANIZED THIS PORTION OF YOUR 18 TESTIMONY? 19 A. Beginning in Section III, the narrative provides a detailed description of the 20 2018 Renewable RFP process, beginning with the development of protocols 21 for the 2018 Renewable RFP through selection of the final proposals for 22 negotiation. My testimony will cover the following:
23 1. The reason for issuing the 2018 Renewable RFP; 24 2. The 2018 Renewable RFP Bid Protocol;
25 5 We also modeled a separate, compliance only plan that adds three renewable energy projects – Dodge Flats Solar, Fish Spring Ranch Solar and Crescent Valley Solar, all without battery storage, as a 26 compliance only case. These three projects provide 301 MW of renewable energy, providing for compliance for a shorter period of time, but do not require the use of the One Nevada Transmission line for delivery to 27 northern Nevada. 28 Ulozas-IRP DIRECT 13
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1 3. The issuance of the 2018 Renewable RFP and bids received; 2 4. The initial evaluation process and selection of the initial short list; 3 5. The additional analysis of the shortlisted bids, and the final selection; 4 and
5 6. The six new renewable PPAs. 6 7 19. Q. WHY WAS THE 2018 RENEWABLE RFP ORIGINALLY ISSUED? 8 A. The 2018 Renewable RFP was issued in response to a forecasted need for
9 PCs for Sierra beginning as early as 2021.
10
11 20. Q. PLEASE DESCRIBE THE 2018 RENEWABLE RFP PROTOCOL. 12 A. The Companies prepared a complete bid package or Protocol describing the 13 purpose of the 2018 Renewable RFP, the process by which the 2018 /b/a NV Energy d
14 Renewable RFP would be conducted, the schedule, a description of the nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 information required for each bid, bid submittal instructions and minimum 16 eligibility requirements. The Protocol also included a description of the 17 evaluation process that would be used to select winning bidders. The 18 Protocol included a pro-forma PPA for bidders to review and comment on. 19 The Protocol, including attachments, is set forth in Technical Appendix 20 REN-5. 21 22 21. Q. PLEASE DESCRIBE THE 2018 RENEWABLE RFP. 23 A. The 2018 Renewable RFP was issued on January 9, 2018. The Companies 24 requested proposals for projects that qualified as renewable energy 25 resources under Nevada Revised Statutes (“NRS”) § 704.7811, including 26 but not limited to solar, geothermal, wind, and biomass. Additionally, the 27 Protocol included a solicitation for supplemental battery energy storage 28 Ulozas-IRP DIRECT 14
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1 systems (“Battery Storage”) eligible for the Federal Investment Tax Credit 2 (“ITC”). The Companies solicited renewable energy resources ranging 3 from 35 MW up to approximately 330 MW in size, together with all 4 associated environmental and renewable energy attributes. The Companies 5 requested a commercial operation date on or before December 31, 2020 for 6 projects of at least 35 MW in size, and a commercial operation date of on 7 or before December 31, 2021 for projects up to an additional 295 MW.6 8 Projects were required to be integrated into the Companies’ transmission
9 system as a network resource, to be located in the Companies’ service
10 territories, and to be capable of delivering energy to serve the Companies’
11 retail loads. 12 13 Bids were received on February 2, 2018. The Companies received 24- /b/a NV Energy d
14 conforming bids from 18 counter-parties, totaling more than 3,700 MW. nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 Responses included one bid for a geothermal product, one bid for a wind 16 product, and one bid for a biomass power product. The balance of 17 conforming bids were for solar PV products. Four non-conforming bids 18 were submitted; two to be sited outside of Nevada, and two with stand-alone 19 Battery Storage systems that did not qualify for the ITC. 20 21 22. Q. PLEASE DESCRIBE THE INITIAL EVALUATION PHASE. 22 A. In the initial evaluation phase, bids were ranked based on a combination of 23 three criteria: price, non-price and economic benefits to the State of Nevada. 24
25 6 For proposals with a December 31, 2020 commercial operation date, bidders were invited to also 26 propose pricing for a May 31, 2020 commercial operation date. For proposals with a December 31, 2021 commercial operation date, bidders were invited to also propose pricing for a May 31, 2021 commercial 27 operation date. 28 Ulozas-IRP DIRECT 15
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1 Price was measured by calculating the levelized cost of energy (“LCOE”) 2 over the term of the proposed PPA. The LCOE included projected energy 3 payments under the PPA and the estimated cost of network upgrades for the 4 proposed project. The LCOE accounted for any proposed escalation of the 5 bid price, as well as any degradation in energy deliveries over the term of 6 the PPA, as indicated by the bidder in their bid submittal. The price score 7 was given a 60 percent weight. 8
9 The non-price scoring was based on four categories: (1) the bidder’s project
10 development experience, (2) the technology of the project, (3) conformity
11 to the pro-forma PPA and (4) project development milestones. The 12 technology review included scoring for: (1) flexibility; (2) environmental 13 benefits; (3) fuel diversity and hedging; and (4) other ancillary services. The /b/a NV Energy d
14 non-price score was given a 30 percent weight. nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 16 The economic benefit scoring was based on three categories: (1) location of 17 jobs created, (2) number of jobs created and (3) economic benefits to 18 Nevada. The economic benefits score was given a 10 percent weight. 19 20 Based on the resulting weighted scores of the bids, an initial short list was 21 developed. Bidders selected for the 2018 Renewable RFP initial short list 22 were notified of their status on March 7, 2018. Shortlisted bidders were 23 permitted to submit a “best and final” proposal by March 12, 2017. Bidders 24 not selected for the short list were also notified of their status on March 7, 25 2018. One bidder was later added to the initial short-list on March 9, 2018, 26 with their best and final proposal due on March 13, 2018. The initial short 27
28 Ulozas-IRP DIRECT 16
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1 list and descriptions of the analysis of these projects is included in 2 Confidential Technical Appendix Item REN-7. 3 4 23. Q. PLEASE DESCRIBE ANY ADDITIONAL ANALYSIS 5 CONDUCTED ON THE SHORTLISTED BIDS. 6 A. First, the Resource Planning group conducted a present worth revenue 7 requirement (“PWRR”) analysis of each of the shortlisted bids using the 8 PROMOD, the production cost model. The PWRR analysis is described in
9 the economic analysis narrative section of this filing.
10
11 Additional due diligence was conducted on the shortlisted bids. The due 12 diligence included: (1) status and timing of interconnection, (2) site control, 13 (3) status of material permits, (4) solar panels, (5) other material equipment, /b/a NV Energy d
14 (6) delivery profile, (7) milestone schedule, (8) material exceptions to the nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 pro-forma PPA, (9) development and operating experience, (10) financial 16 capability, (11) safety, (12) water supply and (13) project labor agreement. 17 Burns & McDonnell was retained to evaluate items (4), (5), (6), (7) and (9) 18 and internal subject matter experts evaluated the remaining items.7 Based 19 on this analysis, the top bidder(s) for negotiations were selected. No 20 material concerns were raised with the shortlisted bids at that time. The 21 Companies’ final due diligence reports for the shortlisted 2018 Renewable 22 RFP bids are included in Confidential Technical Appendix Item REN-8. 23 24
25 7 Burns & McDonnell possesses analysis tools and expertise to validate bidder-provided energy 26 production forecasts that the Companies do not. Additionally, they monitor the renewable equipment and construction markets and are therefore positioned to provide recommendations regarding technology and 27 developers. 28 Ulozas-IRP DIRECT 17
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1 An IE was engaged to oversee the 2018 Renewable RFP process. The IE 2 monitored RFP activities to ensure that a competitive, fair and transparent 3 RFP process was conducted. Among other tasks, the IE validated that the 4 2018 Renewable RFP evaluation criteria, methods, models, and other 5 processes were consistently and appropriately applied to all bids and 6 bidders, and that the assumptions, inputs, outputs and results were 7 appropriate and reasonable. The IE independently scored all bids to 8 determine whether the Companies’ initial and final selections were
9 reasonable. The IE also monitored negotiations. The IE’s report is provided
10 in Confidential Technical Appendix REN-9.
11 12 The Companies successfully completed negotiations for six PPAs with 13 NextEra, Techren, Cypress Creek Renewables, 8minutenergy, Sempra, and /b/a NV Energy d
14 174 Power Global. Each project is described in more detail below. nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 16 24. Q. PLEASE DESCRIBE THE NEXTERA DODGE FLAT PROJECT. 17 A. NextEra Energy Resources, LLC (“NextEra”) and Sierra have executed a 18 PPA for a 200 MW solar PV project located at Dodge Flat, Nevada. The 19 project will be located on roughly 1,200 acres of land in unincorporated 20 Washoe County, approximately 25 miles northeast of Reno, Nevada, and 21 3.5 miles northeast of the town of Wadsworth, Nevada. NextEra also
22 proposes to build a 50 MW capacity Battery Storage system collocated on 23 the same project site. 24
25 The Dodge Flat project is expected to utilize some 660,000 multi-crystalline 26 solar photovoltaic panels, each rated at approximately 425 watts, to 27 generate approximately 592,720 megawatt-hours (“MWh”) of electricity in 28 Ulozas-IRP DIRECT 18
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1 the first full year of production. NextEra projects that the energy supply 2 amount will degrade at approximately 0.5 percent per year. Sierra has 3 agreed to purchase all of the solar output of the Dodge Flat facility for 25 4 years from January 1 immediately following the commercial operation date 5 of December 1, 2021. The fixed price of the contract for the solar output is 6 $27.51 per MWh, with no annual price escalator. The price will be $26.51 7 per MWh should the Fish Springs Ranch project also be approved. Included 8 in the PPA is a 15 year capacity price for the collocated 50 MW, 200 MWh
9 Battery Storage system of $6,110 per MW-month with a 2 percent annual
10 escalation. The LCOE of the Dodge Flat PPA is $29.23 per MWh for the
11 energy only and $34.87 per MWh for the energy plus Battery Storage, 12 including $12,565,000 in Sierra-funded transmission network upgrades 13 investments necessitated to interconnect the project to the transmission /b/a NV Energy d
14 system. In addition to the low cost energy and capacity, the Sierra’s nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 customers will also benefit from all associated environmental and 16 renewable energy attributes as the Dodge Flat project will help displace 17 fossil-fueled generation. 18 19 The project is in an advanced stage of development and, if approved, is 20 expected to be operational in the fourth quarter of 2021. The project will 21 consist of monocrystalline high-efficiency photovoltaic panels mounted on 22 horizontal single axis trackers. The Battery Storage system uses Lithium- 23 ion technology. Dodge Flat will interconnect to a new on onsite 345 kV 24 switching station named Olinghouse, which will be looped into the existing 25 Valmy-Tracy 345 kV line #1 that crosses the project. The PPA between 26 Sierra and NextEra for the Dodge Flat project is included as Technical 27 Appendix Item REN-6-DFS (a). 28 Ulozas-IRP DIRECT 19
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1 25. Q. PLEASE DESCRIBE THE NEXTERA FISH SPRINGS RANCH 2 PROJECT. 3 A. The NextEra Fish Springs Ranch PPA is also with Sierra. The Fish Springs 4 Ranch project is a 100 MW solar PV facility that will be constructed on 5 roughly 707 acres of private land in unincorporated Washoe County, 6 approximately 40 miles north of Reno, near the town of Doyle, California. 7 NextEra also proposes to build a 25 MW capacity Battery Storage system 8 collocated on the same project site.
9
10 The Fish Springs Ranch project is expected to utilize some 341,000 multi-
11 crystalline solar photovoltaic panels, each rated at approximately 425 watts, 12 to generate approximately 270,632 MWh of electricity in the first full year 13 of production. NextEra projects that the energy supply amount will degrade /b/a NV Energy d
14 at approximately 0.5 percent per year. Sierra has agreed to purchase all of nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 the solar output of the NextEra Fish Springs Ranch facility for 25 years 16 from January 1 immediately following the commercial operation date of 17 December 1, 2021. The fixed price of the contract for the solar output is 18 $29.96 per MWh, with no annual price escalator. Included in the PPA is a 19 15-year capacity price for the collocated 25 MW, 100 MWh Battery Storage 20 system of $6,200 per MW-month with a 2 percent annual escalation. The 21 LCOE of the Fish Springs Ranch PPA is $30.67 per MWh for the energy 22 only and $36.94 per MWh for the energy plus Battery Storage, including 23 Sierra-funded transmission network upgrade investments of $2,380,000, 24 necessitated to interconnect the project to the transmission system. In 25 addition to the low cost energy and capacity, the Sierra’s customers will 26 also benefit from all associated environmental and renewable energy 27
28 Ulozas-IRP DIRECT 20
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1 attributes as the Fish Springs Ranch project will help displace fossil-fueled 2 generation. 3 4 The project is in an advanced stage of development and, if approved, is 5 expected to be operational in the fourth quarter of 2021. The project’s 6 monocrystalline high-efficiency photovoltaic panels will be mounted on 7 horizontal single axis trackers. The Battery Storage system uses Lithium- 8 ion technology. Fish Spring Ranch will interconnect to the transmission
9 system at the Fort. Sage 345 kV substation. The PPA between Sierra and
10 NextEra for the Fish Springs Ranch project is included as Technical
11 Appendix Item REN-6-FSR (a). 12 13 26. Q. PLEASE DESCRIBE THE CYPRESS CREEK BATTLE /b/a NV Energy d
14 MOUNTAIN SOLAR PROJECT. nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 A. The Cypress Creek Battle Mountain Solar PPA will provide Sierra’s 16 customers with a low-cost, long-term supply side resource that provides an 17 element of price predictability and stability. 18 19 Cypress Creek Renewables, LLC (“CCR”) has executed an option 20 agreement to purchase or lease roughly 640 acres of land in Humboldt 21 County, approximately 8.5 miles northwest of Battle Mountain, Nevada (on 22 the south side of Interstate 80), upon which it proposes to build a 101 MW 23 solar PV project. CCR also proposes to build a 25 MW capacity Battery 24 Storage system collocated on the same project site. 25 26 The Battle Mountain Solar PV project is expected to utilize 378,764 400- 27 watt crystalline solar photovoltaic panels to generate approximately 28 Ulozas-IRP DIRECT 21
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1 296,655 MWh of electricity in the first full year of production. CCR 2 projects that the energy supply amount will degrade at approximately 0.5 3 percent per year. Sierra has agreed to purchase all of the solar output of the 4 Battle Mountain Solar facility for 25 years from January 1 immediately 5 following the commercial operation date of June 1, 2021. The fixed price 6 of the contract for the solar output is $26.50 per MWh, with no annual price 7 escalator. No Sierra-funded transmission network upgrades are needed to 8 interconnect the project to the transmission system. Thus the LCOE of the
9 Battle Mountain PPA is also $26.50 per MWh for the energy only, $30.94
10 per MWh for energy plus Battery Storage. In addition to the solar PV, the
11 PPA includes a collocated 25 MW, 100 MWh Battery Storage system, with 12 a 10-year term at a cost of $7,755 per MW-month. Moreover, in addition to 13 the low cost energy and capacity, the Sierra’s customers will benefit from /b/a NV Energy d
14 all associated environmental and renewable energy attributes as the Battle nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 Mountain Solar project will help displace fossil-fueled generation. 16 17 The project is in an advanced stage of development and, if approved, is 18 expected to be operational in the second quarter of 2021. The project’s 19 monocrystalline high-efficiency photovoltaic panels will be mounted on 20 horizontal single axis trackers. The Battery Storage system uses Lithium- 21 ion technology. Battle Mountain Solar will interconnect to the 120 kV 22 Battle Mountain – Valmy #120 transmission line through the proposed 23 Izzenhood 120 kV switching station. The PPA between Sierra and CCR for 24 the Battle Mountain Solar project is included as Technical Appendix Item 25 REN-6-BMS (a). 26 27
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1 27. Q. PLEASE DESCRIBE THE 8MINUTENERGY EAGLE SHADOW 2 MOUNTAIN SOLAR FARM PROJECT. 3 A. Nevada Power and developer 8minutenergy have executed a PPA for the 4 output of 300 MW from the Eagle Shadow Mountain Solar Farm (“Eagle 5 Shadow”). The project will be located on approximately 3,200 acres of land 6 leased from the Moapa River Band of Indians, northeast of Las Vegas, 7 Nevada. 8
9 For Eagle Shadow, 8minutenergy intends to utilize a combination of solar
10 PV panels, DC to AC inverters and single axis trackers to generate
11 approximately 922,909 MWh of electricity in the first full year of 12 production. 8minutenergy projects that the energy supply amount will 13 degrade at approximately 0.3 percent per year. Nevada Power has agreed to /b/a NV Energy d
14 purchase all of the solar output of Eagle Shadow for 25 years from January nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 1 immediately following the commercial operation date of December 31, 16 2021. The fixed price of the contract for the solar output is $23.76 per MWh, 17 with no annual price escalator. The LCOE of the Eagle Shadow PPA, 18 including the PWRR associated with investment of $550,000 in 19 transmission network upgrades necessitated to interconnect the project to 20 the transmission system, is $23.81 per MWh. In addition to the low cost 21 energy and capacity, the Nevada Power’s customers will also benefit from 22 all associated environmental and renewable energy attributes as the Eagle 23 Shadow project will help displace fossil-fueled generation. 24 25 The project is expected to be operational in the fourth quarter of 2021. Eagle 26 Shadow will interconnect to the Reid Gardner 230 kV Bus. The PPA 27 between Nevada Power and 8minutenergy for the Eagle Shadow Mountain 28 Ulozas-IRP DIRECT 23
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1 Solar Farm project is included as Technical Appendix Item REN-6-ESM 2 (a). 3 4 28. Q. PLEASE DESCRIBE THE SEMPRA COPPER MOUNTAIN 5 5 PROJECT. 6 A. Nevada Power has executed a PPA with Sempra for the output of the 250 7 MW Copper Mountain 5 solar PV project, to be located on roughly 1,145 8 acres of land in the Eldorado Valley, approximately 28 miles south of
9 Henderson, Nevada.
10 The Copper Mountain 5 project is expected to utilize solar PV panels
11 mounted on single axis trackers to generate approximately 720,222 MWh 12 of electricity in the first full year of production. Sempra projects that the 13 energy supply amount will degrade at approximately 0.5 percent per year. /b/a NV Energy d
14 Nevada Power has agreed to purchase all of the solar output of the Copper nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 Mountain Solar 5 facility for 25 years from January 1 immediately 16 following the commercial operation date of December 31, 2021. The first 17 year price of the contract for the solar output is $21.55 per MWh, with an 18 annual price escalator of 2.5 percent. The LCOE of the Copper Mountain 19 Solar 5 PPA, including the $7,440,000 in transmission network upgrades 20 needed to interconnect the project to the transmission system, is $27.57 per 21 MWh. In addition to the low cost energy and capacity, Nevada Power’s 22 customers will also benefit from all associated environmental and 23 renewable energy attributes as the Copper Mountain Solar 5 project will 24 help displace fossil-fueled generation. 25 26 The project is in an advanced stage of development and, if approved, is 27 expected to be operational in the fourth quarter of 2021. Copper Mountain 28 Ulozas-IRP DIRECT 24
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1 Solar 5 will interconnect to 1.2 mile gen-tie which will loop into the existing 2 230 kV NSO-McCullough transmission line. The PPA between Nevada 3 Power and Sempra for the Copper Mountain Solar 5 project is included as 4 Technical Appendix Item REN-6-CMS5 (a). 5 6 29. Q. PLEASE DESCRIBE THE TECHREN SOLAR V PROJECT. 7 A. Nevada Power and Techren have entered into a PPA for the Techren Solar 8 V project. Located on 2,333 acres leased from Boulder City, Nevada
9 (enough land to support up to a 400 MW solar PV project), this 50 MW
10 project is expected to generate approximately 140,443 MWh in the first full
11 year of production. The developer projects that the energy supply amount 12 will degrade at approximately 0.3 percent per year. Nevada Power has 13 agreed to purchase all of the output of the Techren Solar V plant for 25 /b/a NV Energy d
14 years from January 1 immediately following the commercial operation date. nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 The first year price of the contract is $29.89 per MWh, and has no annual 16 price escalator. The LCOE of the Techren Solar V PPA, is $29.89 per 17 MWh. No network upgrades are required for the Techren Solar V project. 18 Moreover, in addition to the low cost energy and capacity, Nevada Power’s 19 customers will also benefit from all associated environmental and 20 renewable energy attributes as the Techren project will help displace fossil- 21 fueled generation.t. 22 23 The project is in an advanced stage of development and, if approved, is 24 expected to be operational in the fourth quarter of 2020. The project is 25 located in Boulder City, Nevada in a specially designated solar energy zone 26 where Hanwha is developing other solar PV facilities through its Techren 27
28 Ulozas-IRP DIRECT 25
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1 subsidiary.8 The project will consist of monocrystalline high-efficiency 2 photovoltaic panels mounted on horizontal single axis trackers. The project 3 will interconnect to Nevada Power’s Nevada Solar One substation. The 4 PPA between Nevada Power and Techren for the Techren Solar V project 5 is included as Technical Appendix Item REN-6-TS5 (a). 6 7 30. Q. WHAT KEY PROVISIONS HAVE THE COMPANIES 8 NEGOTIATED WITH THE SIX COUNTER-PARTIES AS A
9 RESULT OF THE RFP
10 A. Exhibit Ulozas-Direct-2 provides a table detailing the key provisions of
11 the Solar PPAs. 12 13 31. Q. WILL THE NEVADA ECONOMY BENEFIT FROM APPROVAL /b/a NV Energy d
14 OF THE 2018 RENEWABLE RFP PPAs? nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 A. Yes, the Nevada economy will benefit from the approval of the 2018 16 Renewable RFP PPAs. The 2018 Renewable RFP PPAs are expected to 17 produce a temporary increase in employment during the construction phase 18 of the projects. Moreover, the construction work will be completed pursuant 19 to work site agreements with the International Brotherhood of Electric 20 Workers Local 396, 357, 401 and 1245 as applicable. In addition to the 21 construction jobs and associated positive economic impacts, the facilities 22 are also expected to provide a permanent, long-term increase in 23 employment with the addition of up to 76 positions with a total payroll of 24 $191 million over 25 years.9 The local and state economies will benefit 25
26 8 The project is located contiguous to the Techren Solar I, II, III and IV projects approved by the Commission. 27 9 Aggregated figures from the six PPAs.
28 Ulozas-IRP DIRECT 26
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1 from the influx of jobs, tax base and business generated by these projects 2 The Supply Side Narrative sets forth a complete listing of the economic and 3 environmental benefits of each project, as required by the Commission’s 4 regulations.10 5 6 32. Q. WHY ARE THE COMPANIES RECOMMENDING COMMISSION 7 APPROVAL OF THE CO-LOCATED STORAGE FACILITIES AT 8 THE RENEWABLE ENERGY RESOURCE SITES?
9 A. As the RPS requires increasing penetrations of renewable energy resources,
10 the availability of near-instantaneous, dependable capacity becomes
11 increasingly important to provide for the safe, stable and reliable operation 12 of the bulk electric system. Storage facilities will help capture the rising 13 mid-morning solar energy that happens to correlate with low demand on the /b/a NV Energy d
14 Companies’ system and save that energy for late afternoon and early nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 evening use when system demand is high and solar generation is declining. 16 Collocated storage facilities provide the Companies’ balancing and 17 reliability operators with a variety of on demand capacity options to support 18 renewable resource intermittency in the locations where they are most 19 critical. Collocated storage facilities consist of a collection of Lithium-ion 20 batteries whose capacity may be deployed either fully and nearly 21 instantaneously, or at an extremely accurate and measured rate over the 22 course of several hours. Their availability as an on demand capacity 23 resource will allow the Companies’ balancing authority operators to 24 coordinate with the Companies’ resource optimization personnel to ensure 25 the complex interplay between renewable resource intermittency and peak 26
27 10 See, NAC § 704.8887(2)(c).
28 Ulozas-IRP DIRECT 27
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1 load demand is managed in a safe and reliable manner, lowering stress on 2 the other generating resources as well as Nevada’s interties. Finally, 3 because the Lithium-ion batteries are charged by the solar facilities they are 4 collocated near, they qualify for ITC monetization and therefore are a lower 5 cost resource than if they were charged from the electric grid. 6 7 33. Q. PLEASE EXPLAIN THE COMPANIES’ REQUESTS TO APPROVE 8 THE SIX NEW RENEWABLE PPAS, INCLUDING BATTERY
9 STORAGE.
10 A. Assuming that Question 3 is rejected by Nevada voters in November, 2018
11 the Companies propose that the Commission approve 401 MW of new 12 PPAs between Sierra and the following three renewable energy project 13 developers: /b/a NV Energy d
14 1) NextEra’s Dodge Flat Solar, LLC for a 200 MW (ac) solar PV nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 facility, with an associated 50 MW capacity Battery Storage system 16 with an expected Commercial Operation Date of December 1, 2021.
17 2) NextEra’s Fish Springs Ranch Solar, LLC for a 100 MW (ac) solar 18 PV facility, with an associated 25 MW capacity Battery Storage 19 system with an expected Commercial Operation Date of December 20 1, 2021.
21 3) CCR’s Battle Mountain Solar SP, LLC for a 101 MW (ac) solar PV 22 facility, with an associated 25 MW capacity Battery Storage system, 23 with an expected Commercial Operation Date of June 1, 2021. 24 25 Again, assuming that Question 3 is rejected by voters in November, 2018, 26 the Companies propose that the Commission approve 600 MW of new 27
28 Ulozas-IRP DIRECT 28
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1 PPAs between Nevada Power and the following three renewable energy 2 project developers:
3 1) 8minutenergy’s 325MK 8ME, LLC for the Eagle Shadow Mountain 4 Solar Farm, a 300 MW (ac) solar facility, with an expected 5 Commercial Operation Date of December 31, 2021.
6 2) Sempra’s Copper Mountain Solar 5, LLC for a 250 MW (ac) solar 7 facility with an expected Commercial Operation Date of December 8 31, 2021.
9 3) 174 Power Global’s Techren Solar V, LLC for a 50 MW (ac) solar
10 facility with an expected Commercial Operation Date of December
11 31, 2020. 12 13 These six PPAs fill identified customer needs at historically low pricing, /b/a NV Energy d
14 and fulfill the 2018 Renewable RFP procedural goal. They were selected nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 through a competitive process that was fair and transparent. Although not 16 required, through the RFP process, the Companies have selected proposals 17 that meet the criteria of NRS § 704.7316(2)(b)(4); that is, provide the 18 greatest economic benefit to this State; the greatest opportunity for the 19 creation of new jobs in this State; and the best value to customers of the 20 electric utility. 21 22 34. Q. WHAT DO THE COMPANIES RECOMMEND THE COMMISSION 23 APPROVE IN THE EVENT THAT QUESTION 3 PASSES IN 24 NOVEMBER, 2018? 25 A. In that event, the Companies recommend that the only action taken as a 26 result of the 2018 Renewable RFP is the securing of sufficient PCs for 27 Sierra to maintain its RPS compliance through 2023. Thus, in the event that 28 Ulozas-IRP DIRECT 29
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1 Question 3 passes, the Companies ask that the Commission approve the 2 assignment of the lowest price PPA of the six described above, the 3 8minutenergy project, to Sierra. With this PPA, Sierra should be able to 4 maintain its compliance with the RPS through the post-Question 3 5 transition period. 6 7 35. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT 8 TESTIMONY?
9 A. Yes, it does.
10
11 12 13 /b/a NV Energy d
14 nd Nevada Power Company a Sierra Pacific Power Company Pacific PowerSierra Company 15 16 17 18 19 20 21 22 23 24 25 26 27
28 Ulozas-IRP DIRECT 30
Page 162 of 198 Exhibit Ulozas-Direct-1 Page 1 of 2
David W. Ulozas SVP, Renewable Resources NV Energy, Inc. 6226 West Sahara Avenue Las Vegas, NV 89146 (702) 402-1738
Mr. Ulozas joined NV Energy, Inc. (“NVE”) in November 2017 and is currently the Senior Vice President, Renewable Resources. He has more than 25 years of experience in power generation and energy supply with extensive knowledge of operations, maintenance, construction, and management of coal, gas, and hydro facilities.
Employment History
NV Energy Senior Vice President, Renewable Resources 11/17 to present
MidAmerican Energy Company Vice President, Generation – 7 years 01/09 to 11/17
Nebraska Public Power District Generation Manager – 1 year Plant Manager – 7 years 09/02 to 1/09
Jefferson County CT & Ohio Falls Hydroelectric Plant O&M Supervisor 02/01 to 09/02
LG&E Production Leader – Cane Run Station Plant Technician – Power Operating Services 02/98 to 02/01
Indeck Energy Services Lead Mechanical Maintenance 06/94 to 02/98
UC Operating Services Shift Supervisor 06/93 to 06/94
Page 163 of 198 Exhibit Ulozas-Direct-1 Page 2 of 2
United States Navy 1984 to 1993
Education Bachelor of Science, Management, Bellevue University
Page 164 of 198 EXHIBIT ULOZAS-DIRECT-2
Page 165 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 1 of 18 KEY PROVISIONS OF THE EAGLE SHADOW MOUNTAIN SOLAR FARM PPA
PROVISION EAGLE SHADOW MOUNTAIN SOLAR FARM PPA Supplier 325MK 8ME LLC, LLC (a Sempra subsidiary) Buyer Nevada Power Company, dba NV Energy Term 25 years Net Capacity 300 MW Expected Commercial Operation December 31, 2021 Annual Supply Amount 922,909 MWh (Contract Year 1) Yearly PC Amount 922,909 kPCs (Contract Year 1) Maximum Amount 300 MWh in any hour. (Contract Year 1) Degradation Annual Supply Amount, hourly Supply Amounts, Yearly PC Amount and Maximum Amount each decline by 0.3% per year.
Pricing Product Rate $23.76 per MWh; no escalation. Excess Energy Rate For Excess Energy over 100% but less than 106% of the Annual Supply Amount, $17.59; for Excess Energy over 106% of the Annual Supply amount, the Test Product Rate. Excess Energy Delivered amounts above 100% of the Annual Supply Amount, adjusted for Excused Product. Test Product Rate Lesser of 1) 50% of Product Rate or 2) the Mead Index for the hour. Provisional Rate 75% of Product Rate Provisional Energy Net Energy (but not Test Energy) that is delivered by Supplier to Buyer prior to the Commercial Operation Date and at the request of Buyer in increments of no less than five (5) MW up to an aggregate maximum of fifty (300) MW. Maximum Amount No payment for amounts delivered above the Maximum Amount in any hour.
Energy Delivery Requirements Measurement Periods Two consecutive Contract Years; separate measurements for Summer On-Peak, and Non-Summer On-Peak Performance Factor (Shortfall 90% of total supply amount for the Measurement Period, adjusted Threshold) for Excused Product
Page 166 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 2 of 18
KEY PROVISIONS OF THE EAGLE SHADOW MOUNTAIN SOLAR FARM PPA (cont.) Shortfall Amount of undelivered energy below the 90% performance factor Replacement Cost Positive difference, if any, between the average Mead Index and the Product Rate, with a minimum replacement cost for Summer On- Peak period of 10% of the Product Rate.
PC Delivery Requirements Measurement Period Two consecutive Contract Years Performance Factor 90% PC Shortfall Amount Amount of undelivered PCs below 90% of the Yearly PC Amount PC Replacement Cost Determined by Buyer based on cost to replace PCs from market or from PCs in Buyer’s account including penalties associated with PC Shortfall Amount Replacement PCs At NV Energy’s option, Supplier can provide comparable PCs to cure a PC Shortfall, in lieu of payment of PC Replacement Costs.
Purchase Options Early Purchase Option Buyer has options to purchase the facility on or after the 10th, 15th, or 20th anniversaries of COD, at the greater of fair market value or the amount of any outstanding indebtedness owed to Supplier’s Lenders pursuant to any financing or refinancing of the Facility. End of Term Purchase Option Buyer has option to purchase facility at the end of the PPA term at the greater of fair market value or the amount of any outstanding indebtedness owed to Supplier’s Lenders pursuant to any financing or refinancing of the Facility. Right of First Offer Buyer has right of first offer for certain Restricted Transactions, as defined in the PPA.
Security Development Security $7,500,000 prior to PUCN approval $21,000,000 after PUCN approval Operating Security $21,928,400
Delay Damages, Deficit Damages Delay Damages If Supplier does not achieve commercial operation by January 1, 2022, Supplier pays $58,333.33 per day for days 1-60, $116,666.67 per day for days 61-120, $175,000.00 for days 121-180, that commercial operation has not been achieved. If commercial operation has not been achieved within 180 days after January 1, 2021, Buyer may terminate the PPA. Nameplate Damages If the Certified Nameplate Capacity Rating is less than the Expected Nameplate Capacity, Supplier will pay Deficit Damages
Page 167 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 3 of 18 of $200,000 per MW below 300MW, up to $6,000,000. If the Certified Net Capacity Rating is greater than the Expected Nameplate Capacity Rating by more than 2%, Supplier will pay an amount of one half of the Development Security to Buyer.
Termination Rights Event of Default The Non-Defaulting Party may terminate the PPA if the Defaulting Party has not cured an Event of Default within the applicable Cure Period. PUCN Approval, Energy Choice Buyer may terminate the PPA if it is not approved by the PUCN Approval Deadline. If the PPA is approved with conditions unacceptable to Buyer then Buyer may terminate. Buyer may terminate the PPA if the Energy Choice Initiative passes in the November 2018 election. Force Majeure Buyer may terminate the PPA if Suppliers’ obligations have been excused by an event of Force Majeure for longer than 12 consecutive months or 360 days in any 540 day period
Page 168 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 4 of 18 KEY PROVISIONS OF THE TECHREN SOLAR V, LLC PPA
PROVISION TECHREN SOLAR V PPA Supplier Techren Solar V, LLC Buyer Nevada Power Company, dba NV Energy Term 25 years Net Capacity 50 MW Expected Commercial Operation December 31, 2020 Annual Supply Amount 140,444 MWh (Contract Year 1) Yearly PC Amount 140,469 kPCs (Contract Year 1) Maximum Amount 50 MWh in any hour. (Contract Year 1) Degradation Annual Supply Amount, hourly Supply Amounts, Yearly PC Amount and Maximum Amount each decline by 0.3% per year.
Pricing Product Rate $29.89 per MWh; no escalation. Excess Energy Rate Test Product Rate. Excess Energy Delivered amounts above 100% of the Annual Supply Amount, adjusted for Excused Product. Test Product Rate Lesser of 1) 50% of Product Rate or 2) the Mead Index for the hour. Provisional Rate 75% of Product Rate Provisional Energy Net Energy (but not Test Energy) that is delivered by Supplier to Buyer prior to the Commercial Operation Date and at the request of Buyer in increments of no less than five (5) MW up to an aggregate maximum of fifty (50) MW. Maximum Amount No payment for amounts delivered above the Maximum Amount in any hour.
Energy Delivery Requirements Measurement Periods Two consecutive Contract Years; separate measurements for Summer On-Peak, and Non-Summer On-Peak Performance Factor (Shortfall 90% of total supply amount for the Measurement Period, adjusted Threshold) for Excused Product Shortfall Amount of undelivered energy below the 90% performance factor
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KEY PROVISIONS OF THE TECHREN 5 PPA (cont.)
Replacement Cost Positive difference, if any, between the average Mead Index and the Product Rate, with a minimum replacement cost for Summer On- Peak period of 10% of the Product Rate.
PC Delivery Requirements Measurement Period Two consecutive Contract Years Performance Factor 90% PC Shortfall Amount Amount of undelivered PCs below 90% of the Yearly PC Amount PC Replacement Cost Determined by Buyer based on cost to replace PCs from market or from PCs in Buyer’s account including penalties associated with PC Shortfall Amount Replacement PCs At NV Energy’s option, Supplier can provide comparable PCs to cure a PC Shortfall, in lieu of payment of PC Replacement Costs.
Purchase Options Early Purchase Option Buyer has options to purchase the facility on or after the 6th, 10th, 15th, or 20th anniversaries of COD, at the greater of fair market value or a fixed price. End of Term Purchase Option Buyer has option to purchase facility at the end of the PPA term at the greater of fair market value or a fixed price. Right of First Offer Buyer has right of first offer for certain Restricted Transactions, as defined in the PPA.
Security Development Security $1,250,000 prior to PUCN approval $3,500,000 after PUCN approval Operating Security $4,197,900
Delay Damages, Deficit Damages Delay Damages If Supplier does not achieve commercial operation by January 1, 2021, Supplier pays $9,722.22 per day for days 1-60, $19,444.44 per day for days 61-120, $29,166.67 for days 121-180, that commercial operation has not been achieved. If commercial operation has not been achieved within 180 days after January 1, 2021, Buyer may terminate the PPA. Nameplate Damages If the Certified Nameplate Capacity Rating is less than the Expected Nameplate Capacity, Supplier will pay Deficit Damages of $200,000 per MW below 50MW, up to $1,000,000. If the Certified Net Capacity Rating is greater than the Expected
Page 170 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 6 of 18 Nameplate Capacity Rating by more than 2%, Supplier will pay an amount of one half of the Development Security to Buyer.
Termination Rights Event of Default The Non-Defaulting Party may terminate the PPA if the Defaulting Party has not cured an Event of Default within the applicable Cure Period. PUCN Approval, Energy Choice Buyer may terminate the PPA if it is not approved by the PUCN Approval Deadline. If the PPA is approved with conditions unacceptable to Buyer then Buyer may terminate. Buyer may terminate the PPA if the Energy Choice Initiative passes in the November 2018 election. Force Majeure Buyer may terminate the PPA if Suppliers’ obligations have been excused by an event of Force Majeure for longer than 12 consecutive months or 360 days in any 540 day period
Page 171 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 7 of 18 KEY PROVISIONS OF THE BATTLE MOUNTAIN SP, LLC PPA
PROVISION BATTLE MOUNTAIN PROJECT PPA Supplier Battle Mountain SP, LLC (Cypress Creek Subsidiary) Buyer Nevada Power Company, dba NV Energy Term 25 years Net Capacity 101 MW Expected Commercial Operation June 1, 2021 Annual Supply Amount 296,655 MWh (Contract Year 1) Yearly PC Amount 296,655 kPCs (Contract Year 1) Maximum Amount 101 MWh in any hour. (Contract Year 1) Degradation Annual Supply Amount, hourly Supply Amounts, Yearly PC Amount and Maximum Amount each decline by 0.4% per year.
Pricing Product Rate $26.50 per MWh; no escalation. Excess Energy Rate Test Product Rate. Excess Energy Delivered amounts above 100% of the Annual Supply Amount, adjusted for Excused Product. Test Product Rate Lesser of 1) 50% of Product Rate or 2) the California Oregon Border (COB) Index for the hour. Provisional Rate 75% of Product Rate Provisional Energy Net Energy (but not Test Energy) that is delivered by Supplier to Buyer prior to the Commercial Operation Date and at the request of Buyer in increments of no less than five (5) MW up to an aggregate maximum of fifty (101) MW. Maximum Amount No payment for amounts delivered above the Maximum Amount in any hour.
Energy Delivery Requirements Measurement Periods Two consecutive Contract Years; separate measurements for Summer On-Peak, and Non-Summer On-Peak Performance Factor (Shortfall 90% of total supply amount for the Measurement Period, adjusted Threshold) for Excused Product Shortfall Amount of undelivered energy below the 90% performance factor
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KEY PROVISIONS OF THE BATTLE MOUNTAIN PROJECT PPA (cont.)
Replacement Cost Positive difference, if any, between the average California Oregon Border (COB) Index and the Product Rate, with a minimum replacement cost for Summer On-Peak period of 10% of the Product Rate.
PC Delivery Requirements Measurement Period Two consecutive Contract Years Performance Factor 90% PC Shortfall Amount Amount of undelivered PCs below 90% of the Yearly PC Amount PC Replacement Cost Determined by Buyer based on cost to replace PCs from market or from PCs in Buyer’s account including penalties associated with PC Shortfall Amount Replacement PCs At NV Energy’s option, Supplier can provide comparable PCs to cure a PC Shortfall, in lieu of payment of PC Replacement Costs.
Purchase Options Early Purchase Option Buyer has options to purchase the facility on or after the 6th, 10th, 15th, or 20th anniversaries of COD, at the greater of fair market value or a fixed price. End of Term Purchase Option Buyer has option to purchase facility at the end of the PPA term at the greater of fair market value or a fixed price. Right of First Offer Buyer has right of first offer for certain Restricted Transactions, as defined in the PPA.
Security Development Security $2,525,000 prior to PUCN approval $7,070,000 after PUCN approval Operating Security $7,861,400
Delay Damages, Deficit Damages Delay Damages If Supplier does not achieve commercial operation by June 2, 2021, Supplier pays $19,638.89 per day for days 1-60, $39,277.78 per day for days 61-120, $58,916.67 for days 121-180, that commercial operation has not been achieved. If commercial operation has not been achieved within 180 days after January 1, 2021, Buyer may terminate the PPA. Nameplate Damages If the Certified Nameplate Capacity Rating is less than the Expected Nameplate Capacity, Supplier will pay Deficit Damages of $200,000 per MW below 101MW, up to $2,020,000. If the Certified Net Capacity Rating is greater than the Expected
Page 173 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 9 of 18 Nameplate Capacity Rating by more than 2%, Supplier will pay an amount of one half of the Development Security to Buyer.
Termination Rights Event of Default The Non-Defaulting Party may terminate the PPA if the Defaulting Party has not cured an Event of Default within the applicable Cure Period. PUCN Approval, Energy Choice Buyer may terminate the PPA if it is not approved by the PUCN Approval Deadline. If the PPA is approved with conditions unacceptable to Buyer then Buyer may terminate. Buyer may terminate the PPA if the Energy Choice Initiative passes in the November 2018 election. Force Majeure Buyer may terminate the PPA if Suppliers’ obligations have been excused by an event of Force Majeure for longer than 12 consecutive months or 360 days in any 540 day period. Storage Provisions Total Storage Capacity 25 MW Term 10 years Storage Facility PV inverters with DC-Coupled Li-Ion Battery Energy Storage System. Storage Contract Capacity 100 MWh (25 MW over 4 hours) 300 Cycles per year. Storage Rate $7,755 per MW-month, adjusted in accordance with the Availability Test. Degradation Declining from 100 MWh to 82 MWh over the 10 year term (i.e. 0.5 MW per year). Guaranteed Storage Availability On-Peak Summer Months 98%
Page 174 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 10 of 18 KEY PROVISIONS OF THE DODGE FLAT SOLAR, LLC PPA
PROVISION DODGE FLAT SOLAR ENERGY CENTER PPA Supplier Dodge Flat Solar, LLC (NextEra Subsidiary) Buyer Nevada Power Company, dba NV Energy Term 25 years Net Capacity 200 MW Expected Commercial Operation December 1, 2021 Annual Supply Amount 574,307 MWh (Contract Year 1) Yearly PC Amount 574,307 kPCs (Contract Year 1) Maximum Amount 200 MWh in any hour. (Contract Year 1) Degradation Annual Supply Amount, hourly Supply Amounts, Yearly PC Amount and Maximum Amount each decline by 0.5% per year.
Pricing Product Rate $27.51 per MWh or $26.51 per MWh if the Fish Springs Solar, LLC PPA is approved by the Commission; no escalation. Excess Energy Rate Test Product Rate. Excess Energy Delivered amounts above 100% of the Annual Supply Amount, adjusted for Excused Product. Test Product Rate Lesser of 1) 50% of Product Rate or 2) the California Oregon Border (COB) Index for the hour. Provisional Rate 75% of Product Rate Provisional Energy Net Energy (but not Test Energy) that is delivered by Supplier to Buyer prior to the Commercial Operation Date and at the request of Buyer in increments of no less than five (5) MW up to an aggregate maximum of fifty (200) MW. Maximum Amount No payment for amounts delivered above the Maximum Amount in any hour.
Energy Delivery Requirements Measurement Periods Two consecutive Contract Years; separate measurements for Summer On-Peak, and Non-Summer On-Peak Performance Factor (Shortfall 90% of total supply amount for the Measurement Period, adjusted Threshold) for Excused Product Shortfall Amount of undelivered energy below the 90% performance factor
Page 175 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 11 of 18 KEY PROVISIONS OF THE DODGE FLAT SOLAR, LLC PPA (cont.)
Replacement Cost Positive difference, if any, between the average California Oregon Border (COB) Index and the Product Rate, with a minimum replacement cost for Summer On-Peak period of 10% of the Product Rate.
PC Delivery Requirements Measurement Period Two consecutive Contract Years Performance Factor 90% PC Shortfall Amount Amount of undelivered PCs below 90% of the Yearly PC Amount PC Replacement Cost Determined by Buyer based on cost to replace PCs from market or from PCs in Buyer’s account including penalties associated with PC Shortfall Amount Replacement PCs At NV Energy’s option, Supplier can provide comparable PCs to cure a PC Shortfall, in lieu of payment of PC Replacement Costs.
Purchase Options Early Purchase Option Buyer has options to purchase the facility on or after the 6th, 10th, 15th, or 20th anniversaries of COD, at the greater of fair market value or the amount of any outstanding indebtedness owed to Supplier’s Lenders pursuant to any financing or refinancing of the Facility. End of Term Purchase Option Buyer has option to purchase facility at the end of the PPA term at the fair market value. Right of First Offer Buyer has right of first offer for certain Restricted Transactions, as defined in the PPA.
Security Development Security $5,000,000 prior to PUCN approval $14,000,000 after PUCN approval Operating Security $15,799,200
Delay Damages, Deficit Damages Delay Damages If Supplier does not achieve commercial operation by December 2, 2021, Supplier pays $38,888.89 per day for days 1-60, $77,777.78 per day for days 61-120, $116,666.67 for days 121-180, that commercial operation has not been achieved. If commercial operation has not been achieved within 180 days after January 1, 2021, Buyer may terminate the PPA. Nameplate Damages If the Certified Nameplate Capacity Rating is less than the Expected Nameplate Capacity, Supplier will pay Deficit Damages of $200,000 per MW below 200 MW, up to $4,000,000. If the Certified Net Capacity Rating is greater than the Expected
Page 176 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 12 of 18 Nameplate Capacity Rating by more than 2%, Supplier will pay an amount of one half of the Development Security to Buyer.
Termination Rights Event of Default The Non-Defaulting Party may terminate the PPA if the Defaulting Party has not cured an Event of Default within the applicable Cure Period. PUCN Approval, Energy Choice Buyer may terminate the PPA if it is not approved by the PUCN Approval Deadline. If the PPA is approved with conditions unacceptable to Buyer then Buyer may terminate. Buyer may terminate the PPA if the Energy Choice Initiative passes in the November 2018 election. Force Majeure Buyer may terminate the PPA if Suppliers’ obligations have been excused by an event of Force Majeure for longer than 12 consecutive months or 360 days in any 540 day period. Storage Provisions Total Storage Capacity 50 MW Term 15 years Storage Facility AC Li-Ion Battery Energy Storage System. Storage Contract Capacity 200 MWh (50MW over 4 hours) 300 Cycles per year. Storage Rate $6,110 per MW-month, 2.0% escalation. Degradation No degradation, seller maintains 50MW x 4 hours for term Guaranteed Storage Availability On-Peak Summer Months 98%
Page 177 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 13 of 18 KEY PROVISIONS OF THE FISH SPRINGS SOLAR, LLC PPA
PROVISION FISH SPRINGS RANCH SOLAR ENERGY CENTER PPA Supplier Fish Springs Ranch Solar, LLC (NextEra Subsidiary) Buyer Nevada Power Company, dba NV Energy Term 25 years Net Capacity 100 MW Expected Commercial Operation December 1, 2021 Annual Supply Amount 270,632 MWh (Contract Year 1) Yearly PC Amount 270,632 kPCs (Contract Year 1) Maximum Amount 100 MWh in any hour. (Contract Year 1) Degradation Annual Supply Amount, hourly Supply Amounts, Yearly PC Amount and Maximum Amount each decline by 0.5% per year.
Pricing Product Rate $29.96 per MWh; no escalation. Excess Energy Rate Test Product Rate. Excess Energy Delivered amounts above 100% of the Annual Supply Amount, adjusted for Excused Product. Test Product Rate Lesser of 1) 50% of Product Rate or 2) the California Oregon Border (COB) Index for the hour. Provisional Rate 75% of Product Rate Provisional Energy Net Energy (but not Test Energy) that is delivered by Supplier to Buyer prior to the Commercial Operation Date and at the request of Buyer in increments of no less than five (5) MW up to an aggregate maximum of fifty (100) MW. Maximum Amount No payment for amounts delivered above the Maximum Amount in any hour.
Energy Delivery Requirements Measurement Periods Two consecutive Contract Years; separate measurements for Summer On-Peak, and Non-Summer On-Peak Performance Factor (Shortfall 90% of total supply amount for the Measurement Period, adjusted Threshold) for Excused Product Shortfall Amount of undelivered energy below the 90% performance factor
Page 178 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 14 of 18
KEY PROVISIONS OF THE FISH SPRINGS SOLAR, LLC PPA (cont.)
Replacement Cost Positive difference, if any, between the average California Oregon Border (COB) Index and the Product Rate, with a minimum replacement cost for Summer On-Peak period of 10% of the Product Rate.
PC Delivery Requirements Measurement Period Two consecutive Contract Years Performance Factor 90% PC Shortfall Amount Amount of undelivered PCs below 90% of the Yearly PC Amount PC Replacement Cost Determined by Buyer based on cost to replace PCs from market or from PCs in Buyer’s account including penalties associated with PC Shortfall Amount Replacement PCs At NV Energy’s option, Supplier can provide comparable PCs to cure a PC Shortfall, in lieu of payment of PC Replacement Costs.
Purchase Options Early Purchase Option Buyer has options to purchase the facility on or after the 6th, 10th, 15th, or 20th anniversaries of COD, at the greater of fair market value or the amount of any outstanding indebtedness owed to Supplier’s Lenders pursuant to any financing or refinancing of the Facility. End of Term Purchase Option Buyer has option to purchase facility at the end of the PPA term at the fair market value. Right of First Offer Buyer has right of first offer for certain Restricted Transactions, as defined in the PPA.
Security Development Security $2,500,000 prior to PUCN approval $7,000,000 after PUCN approval Operating Security $8,108,200
Delay Damages, Deficit Damages Delay Damages If Supplier does not achieve commercial operation by December 2, 2021, Supplier pays $19,444.44 per day for days 1-60, $38,888.89 per day for days 61-120, $58,333.33 for days 121-180, that commercial operation has not been achieved. If commercial operation has not been achieved within 180 days after January 1, 2021, Buyer may terminate the PPA. Nameplate Damages If the Certified Nameplate Capacity Rating is less than the Expected Nameplate Capacity, Supplier will pay Deficit Damages of $200,000 per MW below 100 MW, up to $2,000,000. If the
Page 179 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 15 of 18 Certified Net Capacity Rating is greater than the Expected Nameplate Capacity Rating by more than 2%, Supplier will pay an amount of one half of the Development Security to Buyer.
Termination Rights Event of Default The Non-Defaulting Party may terminate the PPA if the Defaulting Party has not cured an Event of Default within the applicable Cure Period. PUCN Approval, Energy Choice Buyer may terminate the PPA if it is not approved by the PUCN Approval Deadline. If the PPA is approved with conditions unacceptable to Buyer then Buyer may terminate. Buyer may terminate the PPA if the Energy Choice Initiative passes in the November 2018 election. Force Majeure Buyer may terminate the PPA if Suppliers’ obligations have been excused by an event of Force Majeure for longer than 12 consecutive months or 360 days in any 540 day period. Storage Provisions Total Storage Capacity 25 MW Term 15 years Storage Facility AC Li-Ion Battery Energy Storage System. Storage Contract Capacity 100 MWh (25 MW over 4 hours) 300 Cycles per year. Storage Rate $6,200 per MW-month, 2.0% escalation. Degradation No degradation, seller maintains 25 MW x 4 hours for term Guaranteed Storage Availability On-Peak Summer Months 98%
Page 180 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 16 of 18 KEY PROVISIONS OF THE COPPER MOUNTAIN SOLAR 5, LLC PPA PROVISION COPPER MOUNTAIN SOLAR 5 PPA Supplier Copper Mountain Solar 5, LLC (a Sempra subsidiary) Buyer Nevada Power Company, dba NV Energy Term 25 years Net Capacity 250 MW Expected Commercial Operation December 31, 2021 Annual Supply Amount 720,222 MWh (Contract Year 1) Yearly PC Amount 720,222 kPCs (Contract Year 1) Maximum Amount 250 MWh in any hour. (Contract Year 1) Degradation Annual Supply Amount, hourly Supply Amounts, Yearly PC Amount and Maximum Amount each decline by 0.5% per year.
Pricing Product Rate $21.55 per MWh; 2.5% annual escalation. Excess Energy Rate Test Product Rate Excess Energy Delivered amounts above 100% of the Annual Supply Amount, adjusted for Excused Product. Test Product Rate Lesser of 1) 50% of Product Rate or 2) the Mead Index for the hour. Provisional Rate 75% of Product Rate Provisional Energy Net Energy (but not Test Energy) that is delivered by Supplier to Buyer prior to the Commercial Operation Date and at the request of Buyer in increments of no less than five (5) MW up to an aggregate maximum of fifty (250) MW. Maximum Amount No payment for amounts delivered above the Maximum Amount in any hour.
Energy Delivery Requirements Measurement Periods Two consecutive Contract Years; separate measurements for Summer On-Peak, and Non-Summer On-Peak. Performance Factor (Shortfall 90% of total supply amount for the Measurement Period, adjusted Threshold) for Excused Product. Shortfall Amount of undelivered energy below the 90% performance factor.
Page 181 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 17 of 18 KEY PROVISIONS OF THE COPPER MOUNTAIN SOLAR V, LLC PPA (cont.)
Replacement Cost Positive difference, if any, between the average Mead Index and the Product Rate, with a minimum replacement cost for Summer On- Peak period of 10% of the Product Rate.
PC Delivery Requirements Measurement Period Two consecutive Contract Years. Performance Factor 90% PC Shortfall Amount Amount of undelivered PCs below 90% of the Yearly PC Amount. PC Replacement Cost Determined by Buyer based on cost to replace PCs from market or from PCs in Buyer’s account including penalties associated with PC Shortfall Amount. Replacement PCs At NV Energy’s option, Supplier can provide comparable PCs to cure a PC Shortfall, in lieu of payment of PC Replacement Costs.
Purchase Options Early Purchase Option Buyer has options to purchase the facility on or after the 10th, 15th, or 20th anniversaries of COD, at the greater of fair market value or a fixed price. End of Term Purchase Option Buyer has option to purchase facility at the end of the PPA term at the greater of fair market value or a fixed price. Right of First Offer Buyer has right of first offer for certain Restricted Transactions, as defined in the PPA.
Security Development Security $6,250,000 prior to PUCN approval $17,500,000 after PUCN approval Operating Security $15,520,800
Delay Damages, Deficit Damages Delay Damages If Supplier does not achieve commercial operation by January 1, 2022, Supplier pays $48,611.11 per day for days 1-60, $97,222.22 per day for days 61-120, $145,833.33 for days 121-180, that commercial operation has not been achieved. If commercial operation has not been achieved within 180 days after January 1, 2021, Buyer may terminate the PPA. Nameplate Damages If the Certified Nameplate Capacity Rating is less than the Expected Nameplate Capacity, Supplier will pay Deficit Damages of $200,000 per MW below 245MW, up to $4,980,000. If the Certified Net Capacity Rating is greater than the Expected Nameplate Capacity Rating by more than 2%, Supplier will pay an amount of one half of the Development Security to Buyer.
Page 182 of 198 Exhibit Ulozas-Direct-2 Key Provisions of the New PPAs Page 18 of 18 KEY PROVISIONS OF THE NEW QF RENEWABLE ENERGY PPA (cont.)
Termination Rights Event of Default The Non-Defaulting Party may terminate the PPA if the Defaulting Party has not cured an Event of Default within the applicable Cure Period. PUCN Approval, Energy Choice Buyer may terminate the PPA if it is not approved by the PUCN Approval Deadline. If the PPA is approved with conditions unacceptable to Buyer then Buyer may terminate. Buyer may terminate the PPA if the Energy Choice Initiative passes in the November 2018 election. Force Majeure Buyer may terminate the PPA if Suppliers’ obligations have been excused by an event of Force Majeure for longer than 12 consecutive months or 360 days in any 540 day period.
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SACHIN VERMA
Page 185 of 198
1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Nevada Power Company d/b/a NV Energy Sierra Pacific Power Company d/b/a NV Energy 3
4 2018 Joint Triennial Integrated Resource Plan (2019-2038) Docket No. 18-06____ 5 PREPARED DIRECT TESTIMONY OF 6 7 Sachin Verma
8 9 1. Q. PLEASE STATE YOUR NAME, JOB TITLE BUSINESS ADDRESS
10 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
11 A. My name is Sachin Verma. I am the Director of Transmission System
12 Planning for Nevada Power Company d/b/a NV Energy (“Nevada 13 Power”) and Sierra Pacific Power Company d/b/a NV Energy (“Sierra, 14 and together with Nevada Power, the “Companies” or “NV Energy”). My d/b/a NV Energy 15 business address is 6100 Neil Road, Reno, Nevada. I am filing testimony Nevada Power Company Company Power Nevada 16 on behalf of the Companies. and Sierra Pacific Power Company Pacific Power Sierra and Company
17
18 2. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS THE 19 DIRECTOR OF TRANSMISSION SYSTEM PLANNING? 20 A. I am responsible for all transmission planning associated with Integrated 21 Resource Planning (“IRP”), compliance, generator interconnections and 22 transmission load addition functions for the Companies. 23 24 25 26 27
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1 3. Q. PLEASE BRIEFLY DESCRIBE YOUR EDUCATIONAL 2 BACKGROUND AND EMPLOYMENT EXPERIENCE? 3 A. I have a Bachelor of Science Degree in Electrical Engineering and a 4 Master of Business Administration Degree with a focus in Finance, both 5 from the University of Nevada, Reno. I am a registered Professional 6 Engineer in the State of Nevada. I began my employment with the 7 Companies as a student engineer in 2007. I have experience in 8 transmission planning, distribution service, electric metering and system 9 protection. More details regarding my professional background and
10 experience are set forth in my Statement of Qualifications, included as
11 Exhibit Verma-Direct-1.
12 13 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 14 UTILITIES COMMISSION OF NEVADA? d/b/a NV Energy 15 A Yes, I have testified in several IRPs and IRP amendments, including most Nevada Power Company Company Power Nevada 16 recently in Docket Nos. 17-11003 and 11004. and Sierra Pacific Power Company Pacific Power Sierra and Company
17 18 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 19 A. I sponsor the section of the supply-side narrative discussing the
20 Companies’ transmission systems and associated projects, as well as 21 Technical Appendices TRAN-1 through TRAN-9. 22 23 Technical Appendix TRAN-1 (Confidential) is an analysis completed by 24 Transmission Planning to identify the timing of when additional
25 transmission sources will need to be added into the Sierra system due to 26 the aggressive load growth that is occurring. 27
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1 Technical Appendices TRAN-2-7 include the Large Generator 2 Interconnection Agreements (“LGIAs”), Facilities Studies, and System 3 Impact Studies that support the Companies’ requests for approval of the 4 network upgrades associated with six renewable generator 5 interconnections. These LGIAs correspond to the six renewable energy 6 projects with which the Companies have executed purchased power 7 agreements, and for which the Companies are seeking approval as part of 8 the Preferred Plan. 9
10 Technical Appendix TRAN-8 is a study that describes the need to upgrade
11 a section of 230 kV conductor between McDonald and Arden substations.
12 This work is associated with the previously approved McDonald 230/138 13 kV transformer transmission upgrade project. 14 d/b/a NV Energy 15 Technical Appendix TRAN-9 is the Renewable Energy Zone Nevada Power Company Company Power Nevada 16 Transmission Plan (“REZTP”). NV Energy did not produce new studies and Sierra Pacific Power Company Pacific Power Sierra and Company
17 for the REZTP for this filing. There has been no interest by any parties 18 outside the Companies to pursue any studies with respect to this plan. 19
20 6. Q. ARE ANY OF THE MATERIALS YOU ARE SPONSORING 21 CONFIDENTIAL? 22 A. Yes. Portions of Appendix TRAN-1 are confidential, as they set forth 23 customer-specific load information provided to the Companies with the 24 understanding that it would remain confidential.
25 26 27
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1 7. Q. FOR HOW LONG DO THE COMPANIES REQUEST 2 CONFIDENTIAL TREATMENT? 3 A. The requested period for confidential treatment is for no less than five 4 years. 5 6 8. Q. WILL CONFIDENTIAL TREATMENT IMPAIR THE ABILITY 7 OF THE COMMISSION’S REGULATORY OPERATIONS STAFF 8 (“STAFF”) OR THE NEVADA ATTORNEY GENERAL’S 9 BUREAU OF CONSUMER PROTECTION (“BCP”) TO FULLY
10 INVESTIGATE THE INFORMATION SET FORTH IN THIS
11 FILING?
12 A. No, in accordance with the accepted practice in Commission proceedings, 13 the confidential material will be provided to Staff and the BCP under 14 standardized protective agreements with them. d/b/a NV Energy 15 Nevada Power Company Company Power Nevada 16 9. Q. ARE YOU SPONSORING ANY EXHIBITS? and Sierra Pacific Power Company Pacific Power Sierra and Company
17 A. Yes, I sponsor the following exhibit: 18 Exhibit Verma-Direct-1 Statement of Qualifications 19
20 10. Q. PLEASE EXPLAIN THE LARGE GENERATOR 21 INTERCONNECTIONS AND ASSOCIATED NETWORK 22 UPGRADES? 23 A. As a result of a request for renewable energy resources issued by the 24 Companies in January 2018, power purchase agreements have been
25 negotiated with several developers for specific renewable projects. The 26 majority of these projects have already entered into Large Generator 27 Interconnection Agreements with the Companies. These agreements were
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1 processed and executed pursuant to the Companies’ FERC-approved 2 OATT generator interconnection process. The process defines the 3 interconnection requirements for the generator as well as the allocation of 4 costs (i.e., identifies interconnection facilities and transmission network 5 upgrades). Entities who file requests to interconnect generation facilities 6 are responsible for generation interconnection costs; the Companies are 7 responsible for the cost of transmission network upgrades triggered by the 8 interconnection of generation facilities. Four of the six solar photovoltaic 9 generating facilities included in the Low Carbon and Renewable Cases
10 analyzed for this IRP require the construction of network upgrades.
11
12 11. Q. WHY ARE THE COMPANIES RESPONSIBLE FOR THE COSTS 13 OF NETWORK UPGRADES REQUIRED TO INTERCONNECT A 14 RENEWABLE PROJECT TO THE TRANSMISSION GRID? d/b/a NV Energy 15 A. The FERC has determined that facilities that are not directly and Nevada Power Company Company Power Nevada 16 exclusively required to interconnect a generator to the transmission system and Sierra Pacific Power Company Pacific Power Sierra and Company
17 shall be classified as network upgrades, and has determined how the costs 18 of network upgrades will be 1) securitized, and 2) allocated. FERC has 19 determined as a matter of policy that even though driven by requests for
20 interconnection, network upgrades are considered betterments to the 21 overall system. Thus the associated costs are allocated to the 22 interconnecting electric utility, and passed through to customers through 23 FERC-jurisdictional transmission rates as well as state-jurisdictional 24 bundled rates. Examples of network upgrades are the construction of a
25 substation on an existing transmission line in order to interconnect a 26 generator, a terminal addition at an existing substation that is configured 27 as a ring or breaker and a half, or an upgrade to an existing transmission
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1 element in the system due to the injection of additional generation. 2 FERC’s policy on network upgrades is reflected in the Companies’ OATT. 3 4 12. Q. REGARDING THE RENEWABLE GENERATOR 5 INTERCONNECTIONS IN THE TRANSMISSION NARRATIVE, 6 WHY DO SOME PROJECTS HAVE SIGNIFICANT NETWORK 7 UPGRADES AND OTHERS NONE? 8 A. The Companies’ FERC-approved OATT identifies upgrades based on an 9 established system of classification. If a generator is connecting to part of
10 the system that is classified as distribution, the associated upgrades are
11 also considered distribution and are funded by the generator. In these
12 situations, no costs are allocated to other customers. Where a generator is 13 connecting to part of the system that is considered transmission, necessary 14 system upgrades are considered network upgrades and are securitized by d/b/a NV Energy 15 the generator. While securitized by the generator, the Companies are Nevada Power Company Company Power Nevada 16 responsible for making the investment and these investments eventually and Sierra Pacific Power Company Pacific Power Sierra and Company
17 are reflected in the utilities’ cost of service. 18 19 13. Q. PLEASE EXPLAIN THE ADDITIONAL EXPENSE ASSOCIATED
20 WITH THE PREVIOUSLY APPROVED MCDONALD 230/138 KV 21 TRANSFORMER ADDITION. 22 A. After the Commission approved the installation of a new transformer and 23 associated facilities at the McDonald Substation (Docket No. 17-11004), 24 additional analysis was completed that identified an overload on a 1.45
25 mile section of the Arden to McDonald 230 kV line that resulted from a 26 contingency on the Arden to Sinatra 230 kV, Decatur to Sinatra 230 kV 27 and Decatur to Westside to Northwest 230 kV lines. This overload
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1 condition occurs under higher import conditions in the southern system. 2 The study, included in the TA TRAN-9, concludes that a 1.45 mile section 3 of the McDonald - Arden must be re-conductored at an estimated cost of 4 $720,000. This line upgrade is discussed in more detail in the 5 Transmission Plan narrative at Section 9, item I. and shown in Technical 6 Appendix TRAN-8. 7 8 14. Q. THE LOW CARBON CASE DIFFERS FROM THE RENEWABLE 9 CASE IN ONLY ONE RESPECT – THE FORMER
10 ACCELERATES THE RETIREMENT OF NORTH VALMY UNIT
11 1 TO 2021, WHILE THE LATTER DOES NOT. FROM A
12 TRANSMISSION PLANNING VIEW, CAN THE SYSTEM BE 13 OPERATED RELIABLY WITH THE RETIREMENT OF NORTH 14 VALMY UNIT 1 BY DECEMBER 31, 2021? d/b/a NV Energy 15 A. Our current analysis shows that the transmission system can operate in Nevada Power Company Company Power Nevada 16 compliance with NERC standards if conditions in 2021 are consistent with and Sierra Pacific Power Company Pacific Power Sierra and Company
17 the conditions we have modeled. However, reliability is paramount and 18 North Valmy Unit 1 is key to reliability within the constrained northern 19 Nevada transmission system. The Generation section of the Supply Plan
20 narrative describes the conditions that must be met before early retirement 21 of North Valmy Unit 1 is confirmed. The Transmission Plan section of the 22 Supply Narrative describes the significant potential load growth that could 23 alter the conditions modeled. 24
25 26 27
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1 15. Q. PLEASE EXPLAIN THE TRANSMISSION SYSTEM 2 RELIABILITY RISKS ASSOCIATED WITH THE POSSIBLE 3 RETIREMENT OF NORTH VALMY UNIT 1 BY DECEMBER 31, 4 2021? 5 A. Under the current system configuration, the operation of generation 6 interconnected at the North Valmy substation is critical. Moreover, 7 generation located within the constrained portion of the northern Nevada 8 transmission system provides essential ancillary services and allows NV 9 Energy to maintain import capability. There is significant uncertainty with
10 load growth in northern Nevada, particularly load within two areas critical
11 to the northern Nevada economy - the Carlin Trend and Tahoe Reno
12 Industrial Center and surrounding area. 13 14 A second factor - the disaggregation of centralized planning processes - d/b/a NV Energy 15 further complicates the situation. Much of the potential load growth in the Nevada Power Company Company Power Nevada 16 Tahoe Reno Industrial Center and surrounding areas may be served by and Sierra Pacific Power Company Pacific Power Sierra and Company
17 “providers of new electric service” as that term is defined in Nevada 18 Revised Statute Chapter 704B. At this point in the planning process, the 19 location, attributes and operating characteristics of the generation that
20 would meet the energy supply needs of this potential load growth are not 21 required to be identified by potential 704B customers - sources of 22 generation - do not have to be identified until a customer actually files a 23 request with the Commission to take service under Chapter 704B. 24 Depending on the extent to which these Chapter 704B customers identify
25 generation sources located outside the Companies’ transmission system, 26 serving load growth for 704B customers could require an increase in 27 import capability through investments in transmission facilities, or the
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1 need to maintain internal generation interconnected at the North Valmy 2 substation, or both. Finally, there also is uncertainty related to the TS 3 Power Plant connected at Falcon substation. Because transmission 4 additions in Nevada often require a long lead time (7-10 years), if a supply 5 deficiency were projected, NV Energy would need to take action to add or 6 maintain generation interconnected at the North Valmy substation. 7 8 16. Q. ARE THESE RISKS AND UNCERTAINTIES UNIQUE TO NV 9 ENERGY AND NEVADA?
10 A. Some are, yes. FERC’s open access transmission policy is ubiquitous, and
11 all entities subject to FERC’s jurisdiction face the same challenges.
12 However, Nevada’s energy policy is in flux at a time when segments of 13 the local economy are growing at record pace, both utilities have large 14 open positions and portions of the transmission system are constrained. d/b/a NV Energy 15 These Nevada-specific conditions highlight the difference between long- Nevada Power Company Company Power Nevada 16 term planning models and operational realities, emphasizing the need for and Sierra Pacific Power Company Pacific Power Sierra and Company
17 those responsible for the long-term planning function to develop new 18 stochastic and probabilistic reliability measurements. 19
20 For example, recently, the FERC issued its 2018 Summer Market and 21 Reliability Assessment. The assessment concludes that generation 22 capacity is sufficient to meet projected above average summer 23 temperatures in every NERC region except the Electric Reliability Council 24 of Texas. At the same time, the California Independent System Operator
25 issued its Summer Loads and Resources Assessment. Notwithstanding 26 FERC’s assessment, the California Independent System Operator’s 27 probabilistic analysis (complied from 2,000 separate modeling runs)
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1 indicated resulted in at least one hour of potential Stage 2 Emergency 2 conditions in 52 percent of the simulations. A Stage 2 Emergency could 3 lead to curtailment of non-firm load. The California Independent System 4 Operator attributed the results primarily to hydro conditions and the 5 potential retirement of dispatchable generation. 6 7 In summary, while transmission planning’s current analysis (which 8 include scenario and sensitivity techniques, but is not probabilistic or 9 stochastic), indicates that we can reliably operate the system in northern
10 Nevada without North Valmy Unit 1, we need to be vigilant and reassess
11 real-time operating conditions and load growth as 2021 approaches. The
12 conditions spelled out in the narrative discussing the Low Carbon Case 13 will allow us to maintain reliability and provide a framework for ensuring 14 that the decisions we make are consistent with prudent utility practices. d/b/a NV Energy 15 Nevada Power Company Company Power Nevada 16 and Sierra Pacific Power Company Pacific Power Sierra and Company
17 17. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT 18 TESTIMONY? 19 A. Yes it does.
20 21 22 23 24
25 26 27
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STATEMENT OF QUALIFICATIONS SACHIN VERMA
My name is Sachin Verma. My business address is 6100 Neil Road, Reno,
Nevada. I have been employed with Sierra Pacific Power Company ("Sierra" or
“the Company”) since 2007. I am currently the Director of Transmission System
Planning for NV Energy.
I have been in a transmission planning management role since June of
2015 and have worked as a transmission planning engineer for a cumulative three years. As a transmission planning engineer I have performed studies for significant load and generation additions as well as assisted in the compilation of
NERC Compliance studies focused on the reliability of the Company’s transmission grid and its ability to serve its customers.
Also, I have worked in Electric Meter Operations as both a supervisor and an engineer. In this position, I inspected installation of renewable generation, reviewed and approved electrical panels for new service and designed metering installation for high voltage generation projects. As a distribution engineer I worked with commercial and residential customers to analyze power quality concerns, performed distribution design for equipment replacement and additions and coordinated fuse protection on the system.
I am a Registered Professional Engineer in Nevada -- License #021884. I graduated from the University of Nevada, Reno in 2008 with a Bachelor of
Page 196 of 198 Exhibit Verma-Direct-1 Page 2 of 2
Science Degree in Electrical Engineering focused in power systems and in 2014 with a Master of Business Administration focused in finance.
By virtue of my employment, background, experience and education, I am
a qualified witness in regard to the NV Energy’s system and all transmission
planning issues associated with the Companies’ PUCN and FERC filings.
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