Volume 2

BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Application of Sierra Pacific Power Company d/b/a NV
Energy Seeking Acceptance of its Triennial Integrated
Resource Plan covering the period 2014-2033 and
Approval of its Energy Supply Plan for the period 20142016.
Docket No. 13-07___
VOLUME 2 OF 16 APPLICATION, EXHIBITS AND TESTIMONY DESCRIPTION
APPLICATION
Exhibit A – Action Plan
Exhibit B – Roadmap
Exhibit C – Draft Notice
TESTIMONY
James Doubek,
Terry A. Baxter
Marc Reyes
Joseph R. Brignola
Anita L. Hart
Lawrence M. Holmes
Michelle A. Lindsay
Kelly Vagianos
Zeljko Vukanovic
Michael O. Brown
Dr. Donald Dohrmann
Robert R. Oliver
Dr. Sasha S. Baroiant
Hossein Haeri
Jeffrey R. Bohrman
PAGE NUMBER 2
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393
APPLICATION
3DJHRI
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
1
2
3
4
5
6
Application of Sierra Pacific Power
Company d/b/a NV Energy Seeking
Acceptance of its Triennial Integrated
Resource Plan covering the period 2014­
2033 and Approval of its Energy Supply
Plan for the period 2014-2016.
)
)
)
)
)
)
)
Docket No. 13-07______
7
APPLICATION
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
8
9
Sierra Pacific Power Company d/b/a NV Energy (“Sierra” or “Company”) respectfully
10
submits its triennial integrated resource plan for supply and demand-side resources (the
11
“IRP”). The IRP covers the twenty year period between 2014 and 2033, with a 2014, 2015 and
12
2016 action plan period (the “Action Plan Period”). Sierra files this IRP pursuant sections
13
704.741 of the Nevada Revised Statutes (“NRS”) and Section 704.9208 of the Nevada
14
Administrative Code (“NAC”).
15
(“ESP”) for the Action Plan Period pursuant to NAC 704.9482. The IRP and ESP are based on
16
this application (the “Application”), the prepared direct testimony filed in support of the
17
Application, the narrative volumes that accompany the Application, the exhibits to this
18
Application, 1 and the technical appendices filed simultaneously with the Application.
19
I.
Within the IRP, Sierra included an energy supply plan
The Applicant
20
Sierra provides electric service to the public in portions of fourteen Nevada counties,
21
including the communities of Carson City, Minden and Gardnerville, Reno and Sparks, and
22
Elko. 2 Sierra owns and operates a certificated local distribution company (“LDC”) through
23
which it sells natural gas to retail customers in the Reno-Sparks metropolitan area. Sierra is a
24
public utility within the meaning of NRS 704.020 and, as such, is subject to the jurisdiction of
25
the Public Utilities Commission of Nevada (the “Commission”).
26
1
27
28
There are three exhibits to this Application: Exhibit A – the Action Plan; Exhibit B – the Roadmap; and,
Exhibit C – Draft Notice.
2
Sierra is a wholly-owned subsidiary of NV Energy, Inc., a holding company incorporated under Nevada
law.
1
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1
Sierra’s primary business office is located at 6100 Neil Road in Reno, Nevada. All
2
correspondence related to this Application (including all pleadings, notices, orders and
3
discovery requests) should be served electronically at the following email address:
4
[email protected] Hardcopy documents should be transmitted to Sierra’s counsel
5
and to Sierra’s Manager, Regulatory Services, whose names and addresses are set forth below:
6
Elizabeth Elliot
Shawn M. Elicegui
Associate General Counsel
Tel: 775-834-5694
Fax: 775-834-4098
Email: [email protected]
[email protected]
7
8
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
9
10
11
II.
Trevor Dillard
Manager, Regulatory Services
Tel: 775-834-5823
Fax: 775-834-4484
Email: [email protected]
Overview of the Filing
12
NRS 704.741 requires Sierra to submit to the Commission on or before July 1 of every
13
third year and in a manner specified by the Commission a plan to increase its supply of
14
electricity or decrease the demands made on its systems by customers. 3 Sierra prepared the
15
IRP in accordance with the Commission’s resource planning regulations, NAC 704.9005 to
16
704.9525, inclusive, and prior Commission orders regarding preparation of resource plans.
17
The filing contains 16 non-confidential volumes.
18
volume.
The Table of Contents identifies each
19
NRS 704.751(1) provides that the Commission “shall issue an order accepting” the IRP
20
or “specifying any portions of the plan it deems to be inadequate” within 180 days after the
21
filing. 4 Similarly, the Commission shall issue an order accepting” the ESP or “specifying any
22
portions of the plan it deems to be inadequate” within 135 days after the filing. 5 To
23
accommodate different procedural schedules for the IRP and the ESP, Sierra placed all
24
material specific to the ESP in separate volumes.
25
26
27
3
4
28
5
Nev. Rev. Stat. § 704.741; see also Nev. Admin. Code § 704.9208.
Nev. Rev. Stat. § 704.751(1)(b).
Nev. Rev. Stat. § 704.751(1)(a).
2
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1
A.
Prepared Direct Testimony Supporting the IRP
2
The prepared direct testimony of 25 witnesses supports the IRP. This section of the
3
Application identifies each witness who filed prepared direct testimony in support of the
4
Application and the IRP, and briefly describes the prepared direct testimony of the witness. 6
5
1.
6
James Doubek, Executive, Resource Planning and Analysis, sponsors Power
Purchase & Portfolio Energy Credit Agreements, Section 2.B of the Supply Side
Volume. In addition, Mr. Doubek provides overall policy support for the IRP.
7
Summary of the Plan and Policy
8
2.
Load Forecast and Market Fundamentals
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
9
Terry A. Baxter, Manager of Load Forecasting, sponsors Section 1 of the Load
Forecast and Market Fundamentals Volume and Technical Appendix Items LF-1
through LF-6.
10
11
12
Marc D. Reyes, Manager of Market Fundamentals, sponsors the market
fundamentals discussion and the wholesale power and natural gas price forecasts
that are presented in the Load Forecast and Market Fundamentals Volume.
13
14
Joseph R. Brignola, Manager, Coal Operations and Procurement, sponsors Section
2.C. and portions of Section 3.G. of the Load Forecast and Market Fundamentals
Volume, and Section 2.C.4 of the Supply Side Plan Volume.
15
16
18
Anita L. Hart, Manager, Gas Transportation Planning, sponsors the following
portions of the Supply Side Plan Volume: Section 2.C.1, Section 2.C.2, Section
2.C.3 and Section 2.C.5.
19
3.
20
Lawrence M. Holmes, Manager, Customer Strategy and Programs, along with
witnesses Michael Brown, Kelly Vagianos, Zeljko Vukanovic and Michelle
Lindsay, sponsors the Demand Side Management Plan.
17
21
Demand Side Management Plan
22
Michelle A. Lindsay, Consultant Staff, DSM Planning, together with Lawrence
Holmes, Michael Brown and Kelly Vagianos, sponsors the Demand Side
Management Plan.
23
24
Kelly A. Vagianos, Consultant Staff, DSM Planning, along with Lawrence Holmes,
Michelle Lindsay, Zeljko Vukanovic and Michael Brown, sponsors the Demand
Side Management Plan.
25
26
27
6
28
The order of witnesses listed in the Application does not necessarily reflect the order in which Sierra
intends to call witnesses in its direct case if this matter proceeds to a hearing.
3
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2
Zeljko G. Vukanovic, Consultant Staff, DSM Planning, along with Lawrence
Holmes, Michelle Lindsay, Kelly Vagianos and Michael Brown, sponsors the
Demand Side Management Plan.
3
4
5
6
7
8
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
9
Michael O. Brown, Manager of Demand Response Programs, presents the Demand
Response Program set forth in the Demand Side Management Plan.
Dr. Donald R. Dohrmann, Principal and Director of Economics for ADM
Associates, Inc., together with Sasha Baroiant, Robert Oliver and Kelly Vagianos,
sponsors the 2012 measurement and verification reports found in the DSM
Technical Appendices.
Robert R. Oliver, Director/Project Manager ADM Associates, Inc., together with
Sasha Baroiant, Donald Dohrmann and Kelly Vagianos, sponsors the 2012
measurement and verification reports found in the DSM Technical Appendices.
10
11
12
13
14
15
16
17
18
19
Dr. Sasha Baroiant, Director/Project Manager ADM Associates, Inc., together with
Donald Dohrmann, Robert Oliver and Kelly Vagianos, sponsors the 2012
measurement and verification reports found in the DSM Technical Appendices.
Dr. Hossein Haeri, Executive Director at The Cadmus Group, Inc., describes the
method and the associated software tool used for calculating the projected impact of
utility investments in DSM on projected rates and customer bills, and how the tool
was applied to assess the likely effect on rates and customer bills from Sierra’s
implementation of its 2014-2016 Demand Side Plan. Additionally, Dr. Haeri jointly
sponsors the fuel diversity study with Ms. Hart.
Jeffrey Bohrman, Senior Analyst in the Regulatory Pricing and Economic Analysis
section of the Rates and Regulatory Affairs Department, sponsors technical aspects
of the energy efficiency implementation rate revenue requirement calculations
presented in this docket.
20
4.
21
Bobby J. Hollis, Executive, Renewable Energy, sponsors and supports the
Renewable Energy Plan and Sierra’s request for approval of the Fort Churchill Solar
Array Transaction.
22
23
24
Renewable Resources (Including Purchased Power)
Laura I. Walsh, Manager of Regulatory Pricing and Economic Analysis, explains
and supports the calculation of the Green Rate component of the Fort Churchill
Solar Array Transaction.
25
26
27
Patricia M. Franklin, Manager, Revenue Requirements, Regulatory Accounting &
FERC, sponsors and supports how Sierra will account for revenues and expenses
associated with the Ft. Churchill Solar Array Transaction.
28
4
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5.
1
Conventional Generation Resources (including Purchased Power)
John W. Lescenski, Manager, Plant Engineering and Technical Services, sponsors
the conventional generation discussion in the Supply Side Plan Narrative and related
Technical Appendix items.
2
3
4
Starla Lacy, Executive, Environmental, Health and Safety, supports the
environmental discussion of regulations impacting the generating plants presented in
the filing.
5
6
6.
Transmission Plan
7
Charles A. Pottey, Manager of Network and IRP Transmission Planning, sponsors
the Transmission Plan section of the Supply Side Plan with the exception of the
2033 Transmission Study and the Renewable Energy Zone Transmission Plan.
8
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
9
Edi Von Engeln, Staff Engineer, Transmission Planning, sponsors the 2033
Transmission Study and the Renewable Energy Zone Transmission Plan.
10
11
7.
12
Economic Analysis
Robert R. Kocour, Jr., Manager, Long-Term Resource Planning, sponsors the
selection of the preferred and alternate plans including the inputs, assumptions and
methodology used to perform the economic analysis and the Loads and Resource
(“L&R”) tables.
13
14
15
Dr. David Harrison, Jr., economist and Senior Vice President at NERA Economic
Consulting, sponsors the discussion and analysis of environmental externalities
contained in the Supply Side Plan, Economic Analysis, and Financial Plan volume,
Section 3.H, as well as Technical Appendix Item ECON-17.
16
17
18
8.
19
William Harty, Manager, Corporate Finance, sponsors the financial plan contained
in the Supply Side Volume.
20
21
B.
22
23
24
Financial Plan
Prepared Direct Testimony Supporting the ESP
The prepared direct testimony of 10 witnesses supports the ESP. This section of the
Application identifies each witness who filed prepared direct testimony in support of the
Application and the ESP, and briefly describes the prepared direct testimony of the witness. 7
25
James Doubek, Executive, Resource Planning and Analysis, is the overall policy
witness for the ESP. Mr. Doubek introduces the Company’s witnesses; describe the
26
27
7
28
The order of witnesses listed in the Application does not necessarily reflect the order in which Sierra
intends to call witnesses in its direct case if this matter proceeds to a hearing.
5
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2
preparation of the ESP, and give an overview of the ESP. Mr. Doubek also sponsors
Section 2.B, Section 2.C., Section 4.B, Sierra’s gas hedging strategy, as set forth in
Section 5.C, and the 2014-2016 cost-to-serve estimates for Sierra in Figure ESP-1 of
Section 1.D.5.
3
4
5
6
7
8
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
9
Bobby Hollis, Executive, Renewable Energy, sponsors Section 2.D of the ESP,
which provides information relating to Nevada’s Renewable Energy Portfolio
Standard. Mr. Hollis also sponsors the portions of Section 4 of the ESP that relate to
renewable energy contracts; namely, Sections 4.A.3 and 4.A.4 of the ESP.
Gregory A. Kern, Executive, Resource Optimization, sponsors Sections 4.A.5 and
4.D of the ESP . Those sections relate to Current Portfolio Optimization Procedures
and Continuous Monitoring and Optimization of the Power Portfolio. Mr. Kern
sponsors those portions of Section 8 of the ESP that relate to the determination of
prudence of elements of the ESP. Mr. Kern also sponsors Technical Appendix Item
Power-1.
10
11
12
13
14
15
16
Naveed Mughal, Executive, Financial Strategy and Treasury Services, co-sponsors
portions of the ESP, namely a part of Section 8.
Vernon W. Taylor, Director of Risk Control, sponsors Section 7 of the ESP , which
relates to the Risk Control organization. Mr. Taylor describes the role of the Risk
Control organization in managing Sierra’s energy supply risk. Mr. Taylor also
sponsors Technical Appendix Items RM-1 through RM-3.
Terry A. Baxter, Manager of Load Forecasting, sponsors the ESP load forecast,
which is found in Section 2.A of the ESP and Technical Appendix Items LF-1
through LF-7.
17
18
19
20
21
22
23
24
25
26
27
Joseph R. Brignola, Manager, Coal Procurement & Operations, sponsors Section
2.H, Section 3.C, the portions of Section 3.D that relate to coal, and Section 6. Mr.
Brignola also co-sponsors Technical Appendix Item MF-1; specifically, Mr.
Brignola sponsors the portions of Technical Appendix Item MF-1 that relate to the
Company’s coal price forecast.
Anita Hart, Manager, Gas Transportation Planning, sponsors ESP Section 2.E,
Section 2.F, Section 2.G, Section 5.A, and Section 5.B.
Marc D. Reyes, Manager of Market Fundamentals, sponsors several sections of the
ESP relating to the fundamental attributes of natural gas and power markets.
Specifically, Mr. Reyes sponsors Section 3.A, Section 3.B, Section 3.D.1, and
Section 3.D.2. Together with Mr. Brignola, Mr. Reyes sponsors Technical
Appendix Item MF-1, which contains the fuel and purchased power price forecasts.
Elena P. Mello, Team Leader, Revenue Requirements & FERC, sponsors Technical
Appendix Item Gas-2, which provides projected Base Tariff Energy Rates and
Deferred Energy Accounting Adjustment rates for 2014-2016.
28
6
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Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
1
III.
Key Elements of the IRP and ESP
2
A.
3
The IRP load forecast is presented in the Load Forecast and Market Fundamentals
4
volume. 8 The Load Forecast and Market Fundamentals volume of the filing contains a series
5
of forecasts of Sierra’s peak demand and annual energy consumption.
6
represent the range of future load that Sierra might be required to serve and are consistent with
7
the upper and lower limits of expected economic and demographic change within Sierra’s
8
service territory between 2014 and 2033.
9
Fundamentals volume contains a base growth, high growth and low growth forecast, as
10
required by NAC 704.9225. As explained by Mr. Baxter and the Technical Appendices, the
11
forecasts account for customer response to changes in the price of electricity, substitute sources
12
of energy, as well as the effects of energy efficiency programs, demand response programs and
13
distributed generation resources. Furthermore, the peak demand and annual sales forecasts are
14
internally consistent; equally important, both forecasts are normalized for weather in a manner
15
that is consistent with NAC 704.9245.
The Load Forecast
These forecasts
More specifically, Load Forecast and Market
16
The load forecast is based on substantially accurate data, is adequately demonstrated
17
and defended, and is adequately documented and justified. Together with the Technical
18
Appendices, the Load Forecast and Market Fundamentals Volume contains each of the
19
elements required by NAC 704.9225, covers the periods required by NAC 704.923, is
20
normalized for weather pursuant to NAC 704.9245, and meets the requirements of NAC
21
704.925 and NAC 704.9281. Thus, the load forecast is a reasonable basis upon which to make
22
the resource planning decisions that are addressed in this filing.
23
The following tables, Figure APP-1 and Figure APP-2, show the low, base and high
24
sales and peak demand forecasts for the 20-year planning period, both with and without the
25
effects of demand side management programs.
26
27
8
28
Section II of the Summary Volume, Forecast of Growth, briefly describes key elements of the load
forecast.
7
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FIGURE APP-1
LOW, BASE, AND HIGH SALES SCENARIOS
WITH AND WITHOUT DSM
1
2
3
SALES (GWH) WITH DSM/DR
REDUCTIONS
SALES (GWH) WITHOUT
DSM/DR REDUCTIONS
4
5
6
7
8
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
9
10
11
12
13
14
15
16
17
Year
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
LOW
7,938
8,068
8,199
8,398
8,418
8,441
8,464
8,512
8,537
8,573
8,603
8,639
8,664
8,694
8,725
8,764
8,790
8,822
8,858
8,903
8,933
BASE
8,025
8,385
8,625
9,322
9,628
9,698
9,764
9,856
9,923
10,000
10,072
10,151
10,215
10,286
10,360
10,442
10,511
10,587
10,665
10,752
10,822
HIGH
8,099
8,693
9,294
10,737
11,479
11,598
11,709
11,844
11,950
12,068
12,178
12,298
12,401
12,511
12,624
12,745
12,851
12,966
13,088
13,221
13,335
LOW
7,975
8,160
8,380
8,674
8,778
8,872
8,961
9,075
9,163
9,261
9,352
9,449
9,533
9,621
9,694
9,756
9,797
9,832
9,870
9,917
9,950
BASE
7,552
8,460
8,641
9,043
9,337
9,513
9,860
9,968
10,072
10,200
10,301
10,413
10,518
10,630
10,726
10,828
10,917
11,002
11,072
11,150
11,230
HIGH
8,136
8,768
9,414
10,900
11,676
11,826
11,968
12,134
12,270
12,417
12,557
12,706
12,838
12,975
13,100
13,221
13,327
13,442
13,563
13,696
13,811
18
Includes the effects of small solar, wind and hydro projects.
19
20
21
22
23
24
25
26
27
28
8
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FIGURE APP-2
LOW, BASE, AND HIGH PEAK DEMAND SCENARIOS
WITH AND WITHOUT DSM
1
2
3
PEAK DEMAND (MW) WITH
DSM/DR REDUCTIONS
4
Year
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
5
6
7
8
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
9
10
11
12
13
14
15
16
17
LOW
1,615
1,612
1,598
1,523
1,505
1,518
1,514
1,521
1,527
1,538
1,545
1,554
1,556
1,562
1,569
1,578
1,592
1,590
1,596
1,605
1,611
BASE
1,637
1,679
1,691
1,707
1,732
1,758
1,762
1,777
1,792
1,812
1,827
1,850
1,859
1,875
1,890
1,909
1,934
1,941
1,954
1,972
1,988
HIGH
1,651
1,738
1,811
2,026
2,115
2,156
2,172
2,191
2,215
2,248
2,271
2,305
2,320
2,342
2,367
2,393
2,433
2,448
2,467
2,496
2,521
PEAK DEMAND (MW)
WITHOUT DSM/DR
REDUCTIONS
LOW
BASE
HIGH
1,623
1,645
1,659
1,640
1,700
1,754
1,663
1,736
1,841
1,642
1,788
2,074
1,658
1,835
2,181
1,687
1,869
2,229
1,697
1,882
2,252
1,719
1,904
2,278
1,738
1,927
2,308
1,763
1,955
2,348
1,784
1,977
2,377
1,806
2,007
2,418
1,821
2,023
2,439
1,840
2,046
2,467
1,856
2,065
2,495
1,871
2,084
2,521
1,888
2,109
2,561
1,886
2,117
2,576
1,893
2,130
2,595
1,902
2,148
2,624
1,909
2,165
2,649
18
Includes the effects of small solar, wind and hydro projects.
19
20
B.
21
The DSM Plan represents a moderate expansion of program activity relative to the
22
previously approved 2013 DSM Plan. The preferred DSM Plan provides for the expenditure of
23
approximately $23 million on energy efficiency programs over the Action Plan Period. In
24
addition, the preferred DSM Plan includes, for the first time, a full-scale demand response
25
program with proposed expenditures of approximately $12.5 million over the Action Plan
26
Period. The incremental investment in energy efficiency and demand response programs has a
27
total resource cost ratio of 1.54 and should produce an estimated net benefit of almost $9 million
The Demand Side Management Plan
28
9
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1
for the communities served by Sierra. Figure APP-3 identifies each program included in the
2
preferred DSM Plan, as well as the proposed annual expenditures for each year during the Action
3
Plan Period.
4
FIGURE APP-3
DEMAND SIDE ACTION PLAN BUDGET
5
Budget
Home Energy Reports
Residential Lighting
Refrigerator Recycling
Solar Thermal Water Heating
Subtotal - Residential
2014
$600,000
$800,000
$500,000
$200,000
$2,100,000
2015
$520,000
$1,200,000
$500,000
$200,000
$2,420,000
2016
$520,000
$1,400,000
$500,000
$200,000
$2,620,000
Total
$1,640,000
$3,400,000
$1,500,000
$600,000
$7,140,000
Non-Profit Agency Grants
Energy Smart Schools
Commercial Incentives
Subtotal - Commercial
$110,000
$400,000
$4,500,000
$5,010,000
$110,000
$400,000
$4,500,000
$5,010,000
$110,000
$400,000
$4,500,000
$5,010,000
$330,000
$1,200,000
$13,500,000
$15,030,000
14
Energy Education
Market and Technology Trials
Subtotal - Other
$250,000
$100,000
$350,000
$250,000
$100,000
$350,000
$250,000
$100,000
$350,000
$750,000
$300,000
$1,050,000
15
Total Energy Efficiency
$7,460,000
$7,780,000
$7,980,000
$23,220,000
Demand Response
Total Demand Response
$2,950,000
$2,950,000
$3,950,000
$3,950,000
$5,600,000
$5,600,000
$12,500,000
$12,500,000
$10,410,000
$11,730,000
$13,580,000
$35,720,000
6
7
8
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
9
10
11
12
13
16
17
18
Total Demand Side Programs
19
20
After considering the effects of new technologies on its options, Sierra prepared a DSM
21
Plan that identifies end-use energy efficiency and conservation programs in accordance with
22
NAC 704.934. Specifically, the preferred DSM plan contains four residential end-use energy
23
efficiency programs, three commercial end-use programs and two additional programs (the
24
Energy Education and Market Technology Trials programs). Pursuant to NAC 704.934(4), the
25
preferred DSM Plan also contains a solar thermal water heating program. As shown in Figure
26
APP-3, the preferred DSM Plan contains a demand response program designed to provide
27
targeted peak demand savings.
28
10
3DJHRI
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
1
The DSM narrative volume includes an assessment of technically feasible energy
2
efficiency and conservation programs. The DSM volume ranks proposed programs according
3
to the level of both energy and demand savings. Exhibit A to the DSM Plan contains a
4
“program data sheet” for each program included in the preferred DSM plan. The program data
5
sheet estimates peak demand and energy savings, contains an assessment of the costs of the
6
program, an evaluation of the program’s effect on Sierra’s load shape, and economic analysis
7
related to the program. The DSM Plan also contains a report on the status of all energy
8
efficiency programs as required by NAC 704.934(7).
9
The DSM Plan also includes measurement and verification reports evaluating the
10
performance of each program that Sierra offered customers in 2012. These reports, contained
11
in the Technical Appendix, identify the measurable and verifiable effects of energy efficiency
12
and demand response programs on Sierra. These reports show the energy and demand savings
13
by program, by month and by customer class.
14
C.
Supply Side Plan and Resources
15
The Supply Side Volume assesses a diverse set of capacity and energy alternatives and
16
options.
The supply side assessment begins with a description and review of existing
17
generation units, transmission facilities, power purchase contracts and other resources that are
18
available to Sierra. The alternative plans include a low carbon intensity plan that involves the
19
acquisition of renewable energy in excess of that required by Nevada’s Renewable Portfolio
20
Standard. After describing the alternative plans, the Supply Side Volume identifies the criteria
21
Sierra used to evaluate the alternative plans (including the present worth of revenue
22
requirement and the present worth of societal costs that are not internalized as private costs to
23
the utility) and, using the criteria, compares and contrasts each of the alternative plans.
24
Technical Appendix SS-1 contains time-line graphs for each of the proposed supply side
25
resources included in Sierra’s preferred plan.
26
transmission plan as well as a plan for serving renewable energy zones.
The Supply Side Volume also contains a
27
28
11
3DJHRI
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
1
Sierra has developed and documented the origin of the assumptions, data and
2
projections that it used to calculate the costs and benefits of each alternative plan and each
3
supply side option.
4
includes an assessment of current and anticipated regional fuel and purchase power market
5
conditions. As it has done in the past, Sierra retained NERA Economic Consulting to develop
6
environmental costs and the net economic benefits to Nevada associated with each alternative
7
plan. The Supply Side Volume and Sierra’s supply side plan, in short, satisfy the requirements
8
of NAC 704.937 to NAC 704.948, inclusive. The following paragraphs highlight the major
9
elements of Sierra’s preferred supply side plan.
Furthermore, the Load Forecast and Market Fundamentals Volume
10
Sierra requests five specific generation related items. First, Sierra requests permission
11
to complete a greenfield siting study. The purpose of this study is to identify potential
12
locations for a new generating unit required to serve Sierra’s customers in 2022. The siting
13
study represents a limited step towards the construction of a new generating unit; however, the
14
siting study does not commit Sierra or its customers to a specific course of action. Instead, the
15
study, at an estimated cost of $1.25 million during the Action Plan Period, preserves the option
16
of constructing a generating unit to fill the capacity position identified in 2022. Second, Sierra
17
requests permission to complete capital improvements required to continue to operate the
18
North Valmy 1 Unit in compliance with federal environmental regulations. This project is
19
estimated to cost at total of $14.2 million. 9
20
Third, Sierra requests approval to establish regulatory assets for the previously
21
authorized decommissioning of Tracy Units 1 and 2. The following costs would be booked to
22
the regulatory asset accounts:
1)
23
of retirement;
24
2)
25
A monthly credit reflecting depreciation expense (if any) included in the
revenue requirement for general rates;
26
3)
27
28
The net book value of the generators and related electric investments on the date
9
All decommissioning and remediation costs;
Sierra’s will be responsible for 50 percent of the cost.
12
3DJHRI
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
1
4)
Credits for all salvage proceeds; and
2
5)
Carrying charges equal to the currently approved Allowance for Funds Used
3
During Construction or “AFUDC” rate on the monthly balance in the regulatory
4
asset subaccount.
5
Fourth Sierra seeks approval to eliminate “oil firing” capability at Tracy Unit 3 and Ft.
6
Churchill Units 1 and 2. Fifth, Sierra seeks approval of the agreements necessary to facilitate
7
the Ft. Churchill Solar Array Project and approval to acquire, through a lease agreement, a new
8
solar generating unit. 10 Sierra also requests permission to account for the Fort Churchill Solar
9
Array transaction as specified in the testimony of Ms. Franklin. Ms. Franklin explains:
10
The Company has requested approval to recover all costs associated
with leasing and operating the Solar Array through Deferred Energy
Accounting as a cost of purchased capacity. The Green Rate revenue
which represents the sale of PC’s to Apple will be credited to the
Deferred Energy Balance offsetting the capacity cost. By accounting for
both the revenue and expense in Deferred Energy, customers pay no
more than the avoided cost of energy for generation from the Solar
Array. In this transaction, the avoided cost is what customers would pay
absent the generation from the Solar Array and is a cost that would be
subject to Deferred Energy Accounting.
11
12
13
14
15
16
17
Sierra’s twenty-year plan for meeting the transmission needs of its native load
18
customers, as well as third-party service requests includes modest investment in transmission
19
system infrastructure during the Action Plan Period. The transmission plan is built upon the
20
load forecasts prepared for this filing, system characteristics, and existing and future
21
transmission facilities and obligations. Based in part on these key system characteristics, the
22
transmission plan examines the capabilities of the existing transmission system to determine
23
the need for and timing of any additional transmission facilities.
24
Sierra is requesting approval of the following:
25
•
26
27
28
A new 345/120 kV substation at Oreana;
10
As explained in the Prayers for Relief section of this Application, Sierra is not requesting authorization to
purchase the Ft. Churchill Solar Array. The Company is not, in other words, requesting authorization to exercise
the option to purchase the Ft. Churchill Solar Array. If the Company decides to exercise the option, Sierra will
seek Commission approval of that decision in a subsequent integrated resource plan filing or resource plan
amendment.
13
3DJHRI
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
1
•
Carlin Trend Area UVLS Project;
2
•
A second 280 MVA 345-120KV transformer at Falcon;
3
•
Coyote Creek 120KV Breaker Addition Project;
4
•
Carlin Trend Transmission Additions;
5
•
Changes in the scope of the Fallon 230 kV Project;
6
•
Changes in the schedule of the Bordertown to Cal Sub 120 kV Project;
7
•
Changes to the 345kV Voltage Support Project;
8
•
Continued participation in WestConnect;
9
•
Approval of its Renewable Energy Zone Transmission Plan.
10
11
Turning to renewable energy, Sierra filed its Portfolio Standard Annual Report for
12
Compliance Year 2012 (“2012 Annual Report”) on March 29, 2013. In the 2012 Annual
13
Report, Sierra reported that it exceeded both the 2012 RPS requirement and the 2012 solar RPS
14
requirement (15% of retail sales from RPS-eligible resources and 5% of the RPS from solar
15
resources), achieving 29.2% and 14.4% respectively. Sierra will carry forward a surplus of
16
solar and non-solar credits to meet the 2013 renewable compliance requirements. Sierra also
17
forecasted that it will exceed the overall RPS for the Action Plan Period January 1, 2014
18
through December 31, 2016. In addition, Sierra will carry forward any surplus PCs as a result
19
of energy efficiency or conservation measures (referred to as Demand Side Management or
20
“DSM”).
21
While Sierra’s RPS outlook is positive well into the future, it must continue to balance
22
a number of variables that could potentially affect its RPS compliance outlook, including load
23
growth, supplier challenges or changes in law. Although Sierra is fortunate to have a mature
24
portfolio of renewable resources for RPS compliance, the age of some of the facilities and their
25
associated contract expiration dates present a challenge on how to treat existing contracts and
26
fill voids that arise as the portfolio continues to age. Sierra developed a renewable expansion
27
plan that contemplates renegotiating existing contracts as those projects are likely to continue
28
14
3DJHRI
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
1
operating for some period after the initial contracts expire. The renewable energy plan that
2
Sierra developed to ensure RPS compliance focuses largely on portfolio management of
3
existing projects.
4
In summary, the first RPS compliance gap requiring a generic placeholder project
5
addition to the current portfolio of projects is in 2033 and the first RPS compliance gap that
6
requires extension of a PPA past the original expiration is in 2025, both well outside of the
7
current Action Plan Period.
8
D.
9
Pursuant to NAC 704.9061, an “Energy Supply Plan” means a plan that:
1.
10
11
The Energy Supply Plan
Establishes the parameters of an energy supply portfolio for a utility for
the 3-year period covered by its Action Plan and which balances the objectives of:
12
a)
Minimizing the cost of supply;
13
b)
Minimizing retail price volatility; and
14
c)
Maximizing the reliability of energy supply over the term of the energy
15
supply plan; and
16
2.
Is composed of a purchased power procurement plan, fuel procurement
17
plan and risk management strategy.
18
Pursuant to NAC 704.9494, the Commission can make a predetermination that the ESP
19
20
is prudent if the following requirements are met:
x
price volatility and maximizing the reliability of supply over the term of the plan;
21
22
23
The ESP balances the objectives of minimizing the cost of supply, minimizing retail
x
The ESP optimizes the value of the overall supply portfolio of the utility for the benefit of its bundled retail customers; and
24
x The ESP does not contain any feature or mechanism that the Commission finds
25
would impair the restoration of the creditworthiness of the utility or would lead to a
26
deterioration of the creditworthiness of the utility.
27
28
15
3DJHRI
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
1
The ESP provides the Company’s recommended power procurement plan, fuel
2
procurement plan, and risk management strategy based on current conditions. The ESP may
3
need to be adjusted over the Action Plan Period to adequately respond to changes in the
4
market, changes in the Company’s expected loads and resources, and other significant changes
5
in circumstances. Pursuant to NAC 704.9504, Sierra may deviate from an approved ESP “to
6
the extent necessary to respond adequately to any significant change in circumstances not
7
contemplated by the Energy Supply Plan.” If Sierra deviates from a Commission-approved
8
ESP, it will inform Staff of the deviation as soon as practical. In addition, Sierra will include
9
in its next deferred energy application filed pursuant to NAC 704.023 to 704.195, inclusive, a
10
description of and justification for the deviation. If the deviation from the ESP is of a
11
continuing nature, Sierra will seek authority from the Commission to deviate prospectively
12
from the ESP in an update of the ESP filed pursuant to NAC 704.9506, or in an amendment to
13
the ESP filed pursuant to NAC 704.9504(3).
14
Sierra has an open position for 2014, 2015 and 2016. However, Sierra does not plan to
15
fill the open positions at this time for several reasons. First, Sierra plans to reassess its open
16
positions after the completion of the One Nevada Transmission Line and following the
17
completion of Docket No. 13-05056. Second, the Western Electric Coordinating Council
18
reports, there is more than adequate capacity in 2014. Accordingly, there is little reliability
19
risk associated with leaving the 2014 position open as long as Sierra continues to monitor
20
markets. If market conditions change, Sierra will take reasonable and necessary steps to close
21
the open position in a cost effective manner. Third, with respect to the 2015 and 2016 open
22
positions, Sierra has sufficient time to update its ESP and, if necessary, take appropriate steps
23
to close the open positions. Any proposed purchases of greater than three years in duration
24
will be submitted to the Commission for approval in accordance with NAC 704.9113 and
25
704.9512. In addition, Sierra will continue to make forward and short-term sales of resources
26
not expected to be needed to serve native load.
27
28
16
3DJHRI
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
1
Sierra proposes no changes to its four-season laddering strategy for physical gas
2
purchases.
Sierra will continue to exercise its annual evergreen rights on any contracts
3
expiring during the Action Plan Period. Sierra proposes to continue its existing hedging
4
strategy. Sierra does not currently plan to procure natural gas hedges covering the Action Plan
5
Period at this time.
6
Sierra proposes a more flexible coal supply plan. Specifically, Sierra does not currently
7
plan to issue an RFP for coal supply for 2014 and beyond. Sierra will monitor relevant
8
conditions and markets and, if necessary, make spot market purchases if coal supplies in excess
9
of minimum contract receipts are needed. Sierra proposes no significant changes to existing
10
risk management strategies.
11
The ESP balances the objectives of minimizing the cost of supply, minimizing retail
12
price volatility and maximizing the reliability of supply over the term of the plan. Sierra
13
completed production cost modeling to show the estimated cost-to-serve with the
14
recommended power procurement plan, fuel procurement plan, and risk management strategy
15
in place, under base, high, and low pricing scenarios. As shown in Figure ESP-61, the
16
expected cost to serve and forecasted rates are expected to remain within a reasonable band
17
under the Sierra’s proposed procurement strategies. Sierra then evaluated the potential costs of
18
unhedged gas volumes using its gas hedge simulation tool. The results of this analysis, which
19
show a wider range of potential cost outcomes, are presented in the ESP, Section 5.C., and in
20
the ESP Technical Appendix GAS-1. Finally, Sierra calculated the projected energy and
21
deferred rates for 2014 - 2016 under the low, base, and high fuel and purchased power price
22
forecasts. See ESP Technical Appendix GAS-2. Sierra’s analysis shows that the ESP balances
23
the objectives of minimizing the cost of supply, minimizing retail price volatility, and
24
maximizing the reliability of supply over the term of the plan by using competitive
25
procurement processes to ensure that prices paid on behalf of customers are reasonable and by
26
securing firm resources to ensure that forecasted load requirements can be met.
27
28
17
3DJHRI
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
1
The ESP optimizes the value of the overall supply portfolio of the utility for the benefit
2
of its bundled retail customers. Sierra will continue to monitor and adjust the power portfolio.
3
Day-ahead or day-of power purchases are expected to be made if there is an open position, or if
4
system costs of decremental energy exceed the additional cost of market purchases. Similarly,
5
day-ahead or day-of power sales are expected to be made as opportunities appear, including
6
spot, fixed price, or indexed agreements as specified in the Energy Risk Management and
7
Control Policy. Finally, Sierra will continue to seek opportunities for forward sales of heat rate
8
call options and other products through direct negotiations with counterparties or the issuance
9
of reverse RFPs
10
This ESP does not contain any feature or mechanism that would impair the restoration
11
of the creditworthiness of the utility or would lead to a deterioration of the creditworthiness of
12
the utility. Over the past several years, the Commission has implemented an energy supply
13
planning process and the Company’s credit has improved. Currently, the Company is able to
14
provide financing for this ESP without impairing its creditworthiness, assuming timely
15
recovery under current rate recovery mechanisms.
16
IV.
Compliance with Statutes and Regulations
17
To assist the Commission in tracking the numerous regulations impacting this Resource
18
Plan, and locating where information responsive to each section of the regulations can be
19
located within the filing, Sierra has prepared a roadmap, which is attached here to as Exhibit B.
20
V.
Confidential Information
21
Pursuant to NRS 703.190(2) and NAC 703.527 to 703.5282, Sierra requests
22
confidential treatment of certain information contained in the Resource Plan and ESP. This
23
request is being served on the Commission’s Staff and the Consumer’s Advocate, pursuant to
24
NAC 703.5274(2). In its cover letter and through witness testimony, Sierra describes with
25
particularity the information to be treated as confidential, and specifies the grounds for the
26
confidential treatment and the periods of time that the confidential information must not be
27
disclosed, pursuant to NAC 703.5274(2)(a)-(c).
28
18
3DJHRI
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
1
Concurrently with the filing of this application, Sierra has filed with the Secretary of
2
the Commission three bound volumes titled “Confidential Material” which contains an
3
unredacted copy of each confidential page of the Resource Plan (in a sealed envelope with a
4
copy of the first page of this Application securely fastened thereon) and with each confidential
5
page stamped “CONFIDENTIAL AND UNREDACTED.”
6
Sierra requests that the period for confidential treatment of the economic and financial
7
information and other commercially sensitive matters be as stated in the applicable
8
testimony. 11
9
will not impair the ability of the Staff and the BCP to fully investigate the economic and
10
financial data that is the subject of this IRP and ESP and provide recommendations to the
11
Commission.
12
confidential material will be provided to Staff and the BCP under a protective agreement as
13
required by NAC 703.5274(8).
14
VI.
In accordance with the accepted practice in Commission proceedings, the
Prayer for Relief
Sierra respectfully requests that the Commission proceed in the manner required by law
15
16
See NAC 703.5274(2)(c). Confidential treatment of the redacted information
and, in accordance its regulations, that:
1.
17
Approves the long-term load forecast for the IRP and the 3-year load forecast
18
for the ESP as meeting the requirements of (a) NAC 704.9321 and (b) NAC 704.9482(7) and
19
NAC 704.922;
2.
20
Approves the long-term load forecast for the IRP and the 3-year load forecast
21
for the ESP comply with the requirements of NAC 704.9245, NAC 704.925 and NAC
22
704.9281;
23
3.
Approves the fuel and purchased power forecasts presented in the Load
24
Forecast and Market Fundamentals Volume and the 3-year fuel and purchased power forecast
25
presented in the ESP as presenting the best and most accurate information upon which to base
26
long-term planning decisions through the Action Plan period;
27
11
28
But if Sierra wishes continued confidential treatment it may file a request with the Commission for a future
determination.
19
3DJHRI
1
Approves Sierra’s request to perform a comprehensive study and conceptual
2
design, with an estimated cost of $1.25 million, for a company-owned generating facility
3
suitable for commercial operation as early as 2022;
4
5
6
5.
Approves the retirement of oil-firing capability on Tracy Unit 3 and Ft.
Churchill Units 1 and 2;
6.
Approves Sierra’s request to complete a capital project involving the installation
7
of dry sorbent injection equipment at North Valmy Unit 1 with an estimated cost of $14.2
8
million, of which Sierra would be responsible for approximately $7.1 million;
9
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
4.
10
11
12
13
14
15
7.
Authorizes Sierra to establish a regulatory asset for the cost associated with the
retirement of Tracy Units 1 and 2;
8.
Approves the agreements necessary to facilitate the Ft. Churchill Solar Array
Project;
9.
Authorizes the accounting treatment related to the Ft. Churchill Solar Array
transaction requested by Sierra, and
10.
Authorizes Sierra to acquire, through the lease agreement, a new solar
16
generating unit in connection with the Ft. Churchill Solar Array transaction, without
17
authorizing, at this time, Sierra to exercise the option to purchase the Ft. Churchill Solar Array;
18
19
11.
Approves modifications to scope of the Fallon 230 kV Project, the schedule for
the Bordertown to Cal Sub, and the schedule of the 345 kV Voltage Support Project;
20
12.
Approves the construction of a new 345/120 kV substation at Oreana;
21
13.
Approves the Carlin Trend Area under voltage load shedding project;
22
14.
Approves the construction of a second 345/120 kV transformer at Falcon;
23
15.
Approves the Coyote Creek 120 kV Breaker Addition Project;
24
16.
Approves the Carlin Trend Transmission Additions;
25
17.
Approves Sierra’s Renewable Conceptual Transmission Plan as meeting the
26
27
requirements of NAC 707.9385(6);
18.
Authorizes Sierra to continue to participate as member in WestConnect;
28
20
3DJHRI
1
Approves and accepts the measurement and verification reports for program year
2
2012 and a finding they are adequate for the calculation of the NRS 704.785 revenue
3
requirement caused by the programs delivered in the 2012 program year;
4
20.
Approves the renewable energy plan presented in the Supply Side Volume as
5
presenting the best and most accurate information upon which to base the planning decisions
6
described in the Action Plan period;
7
8
9
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
19.
21.
Approves the DSM Preferred Plan as part of the Sierra’s Action Plan pursuant
to NAC 704.934(4);
22.
Finds that Sierra has satisfied the directives contained in Ordering Paragraphs
10
11, 12, 13, 14, 15, 16, 17, and 18 of the Commission’s Order dated December 24, 2012, in
11
Docket Nos. 12-06052 and 12-06053 and Ordering Paragraph 13 of the Commission’s Order
12
dated March 23, 2012 in Docket Nos. 11-07026 and 111-07027;
13
14
23.
Accepts and approves Sierra’s power procurement plan and its constituent
elements, which specifies, among other things, that Sierra will:
a)
15
Leave open at this time its positions for each year of the Action Plan
16
Period, but will monitor the portfolio continuously and seek to make short-term and forward
17
purchases when economic or needed to serve native load. If Sierra determines that there is a
18
need for additional capacity and/or energy, Sierra would procure any needed firm products
19
through a competitive bidding process, and any proposed purchases of greater than three-years
20
in duration would be submitted to the Commission for approval in a resource plan filing or
21
amendment;
22
23
24
b)
Continue to make purchases and sales to optimize the value of the
overall supply portfolio of the Company for the benefit of its retail customers;
c)
Continue to monitor its renewable portfolio on a continuous basis to
25
ensure that sufficient renewable energy and portfolio energy credits (“PCs”) are maintained to
26
comply with Nevada’s Renewable Portfolio Standard (“RPS”), and will undertake cost-
27
effective opportunities to fill any new needs that may arise
28
21
3DJHRI
1
2
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
3
24.
Finds that the proposed power procurement strategy is prudent pursuant to NAC
704.9494(3);
25.
Accepts and approves Sierra’s physical gas procurement plan, which provides,
4
among other things, that Sierra will continue to implement the four season laddering strategy
5
approved by the Commission in Docket No. 12-08010, which involves the acquisition of
6
physical gas volumes at indexed prices, subject to a cap on the premium which can be
7
exceeded with prior approval from the Energy Risk Committee.
8
Stipulation in Docket No. 09-09001, if Sierra exceeds the cap, the Company will provide
9
written notice to Staff and the BCP;
10
26.
11
NAC 704.9494(3);
12
27.
13
Consistent with the
Finds that the proposed physical gas procurement strategy is prudent pursuant to
Accepts and approves Sierra’s gas transportation plan which provides, among
other things, that Sierra will:
a)
14
Extend a total of 17 existing gas transportation contracts with
15
TransCanada Pipeline Ltd., Paiute Pipeline Co. and Northwest Pipeline pursuant to its
16
evergreen rights;
17
b)
18
19
20
21
22
23
28.
Extend a storage contract with NWPL for 2015-2016;
Finds that the proposed gas transportation plan is prudent pursuant to NAC
704.9494(3);
29.
Accepts and approves Sierra’s gas hedging strategy which continues the
existing strategy of procuring no hedging products at this time;
30.
Accepts and approves Sierra’s plan to continue quarterly workshops with Staff
and BCP to review implementation of the approved gas hedging strategy;
24
31.
Finds that the gas hedging strategy is prudent pursuant to NAC 704.9494(3);
25
32.
Accepts and approves Sierra’s revised coal supply plan, which reflects changes
26
to current and projected coal unit operations and the level of uncertainty surrounding these
27
operations, as well as market conditions. The major elements of the coal supply plan include
28
22
3DJHRI
1
the following:
2
•
Not issuing an RFP for coal supply for 2014 and beyond;
3
•
Suspending the practice of measuring coal commitments vs. laddering targets;
4
•
Continuing to report inventory levels compared to targets and maximum storage
5
capability on a frequent basis;
6
•
Continuing to monitor the relevant coal markets and fuel market fundamentals;
7
•
Relying on spot market solicitations if coal supplies in excess of minimum
8
contract receipts are needed;
•
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
9
Evaluating steps to reduce minimum contract coal takes and implement those
10
actions that are justified if expected coal-unit dispatch decreases and inventory levels approach
11
maximum storage capacity;
•
12
13
Attempting to negotiate revisions to transportation contract minimum volume
provision as necessary, appropriate or feasible;
14
•
15
Sierra is requesting an affirmative finding consistent with NAC § 704.9494(3) that its
16
Developing plans for a successor transportation arrangement;
coal procurement strategy is prudent.
17
33.
Finds that the coal supply plan is prudent pursuant to NAC 704.9494(3);
18
34.
Accepts and approves Sierra’s risk management plan and finds that the plan
19
identifies risks inherent in procuring and obtaining a supply portfolio and establishes the means
20
by which the utility plans to address and balance or hedge the identified risks related to cost,
21
price volatility and reliability;
35.
22
23
Finds that the risk management strategy is prudent pursuant to NAC
704.9494(3)
36.
24
Finds, pursuant to NAC 704.9494:
a)
25
That the ESP balances the objectives of minimizing the cost of supply,
26
minimizing retail price volatility and maximizing the reliability of supply over the term of the
27
plan.
28
23
3DJHRI
b)
1
2
utility for the benefit of its bundled retail customers.
c)
3
That the ESP does not contain any feature or mechanism that the
4
Commission finds would impair the restoration of the creditworthiness of the utility or would
5
lead to a deterioration of the creditworthiness of the utility.
6
7
8
Sierra Pacific Power Company
and Nevada Power Company
d/b/a NV Energy
That the ESP optimizes the value of the overall supply portfolio of the
37.
Grants Sierra’s request for protection of the confidential information filed under
38.
In accordance with NRS §704.746(3), determines that (1) Sierra’s forecasted
seal;
9
requirements are based on substantially accurate data and an adequate method of forecasting;
10
(2) the IRP identifies and takes into account present and projected reductions in demand for
11
energy that may result from measures to improve energy efficiency; and (3) the IRP adequately
12
demonstrates the economic, environmental and other benefits to the State of Nevada and
13
Sierra’s customers associated with improvement in energy efficiency, pooling of power,
14
purchases of power from neighboring states, renewable energy generation, co-generation,
15
hydro-generation, and other generating resources;
16
39.
Accepts and approves Sierra’s IRP; and,
17
40.
Grants Sierra such other and further relief as the Commission may find
18
19
reasonable and appropriate under the circumstances.
Respectfully submitted this 1st day of July, 2013.
20
SIERRA PACIFIC POWER COMPANY
d/b/a NV ENERGY
21
22
23
24
25
26
27
By:
/s/ Shawn M. Elicegui
Elizabeth Elliot
Shawn M. Elicegui
6100 Neil Road
P.O. Box 10100
Reno, Nevada 89520
Tel: 775-834-5697
Fax: 775-834-4098
Email: [email protected]
28
24
3DJHRI
EXHIBIT A 3DJHRI
ACTION PLAN
Sierra Pacific Power Company d/b/a NV Energy
Action Plan Period: 2014, 2015 & 2016
SECTION I:
A.
INTRODUCTION -- NAC § 704.9489(1)(a)
The Integrated Resource Plan
Sierra Pacific Power Company d/b/a NV Energy (“Sierra” or the “Company”) has
significantly reduced its dependence on wholesale markets. The Company now has
sufficient Company-owned or controlled generation to meet most of its customers’ near
and mid-term needs. Sierra’s 2014-2033 Integrated Resource Plan (the “IRP”) reflects
this fact. The Company does not propose the addition of new conventional generation
resources during the Action Plan Period. Instead, the Company requests permission to
continue to field key demand side management (“DSM”) programs, invest in equipment
necessary to comply with federal environmental regulations, make transmission
investments that enhance reliability and meet the needs of existing and current customers,
and take discrete steps necessary to identify a location for a generating addition in 2022.
The Company also seeks approval of contracts that would allow Apple, Inc. (“Apple”) to
meet its “100 percent” renewable energy goal without imposing costs on Sierra’s
customers.
The Company did not arrive in this position serendipitously. Rather, under the
Commission’s supervision, the Company established and implemented a simple and
straightforward strategic plan. The goal of the plan is to provide clean, safe and reliable
electricity to customers at reasonable and predictable rates. Sierra built the plan on four
principles:
1. Empowering customers through more focused energy efficiency programs;
2. Pursuing cost-effective renewable energy initiatives;
3. Optimizing generation efficiency and transmission; and
4. Engaging employees to improve processes, reduce costs and enhance
performance.
Through the DSM plan, Sierra requests permission to spend an estimated total of $23.22
million in 2014, 2015 and 2016 (the “Action Plan Period”) on fewer but more targeted
energy efficiency programs. In addition, Sierra proposes to spend approximately $12.50
million during the Action Plan Period on demand response, the only DSM program that
generally passes the rate impact measure cost-benefit test. With respect to the second
principle, the Company presents the Ft. Churchill Solar Array transaction. This
arrangement with Apple adds a new renewable generating facility to Sierra’s system
without financially harming Sierra’s customers. Turning to the third element, Sierra
proposes transmission system investments that are designed to improve reliability for
existing customers and meet the needs of new customers in a cost-effective manner.
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Similarly, rather than propose new conventional generation additions, Sierra proposes
capital improvements to the North Valmy Unit 1 that are necessary to allow the unit to
continue to operate until its currently approved depreciation and resource planning
retirement date.
The IRP also includes a request to complete a greenfield site study at an estimated cost of
$1.25 million during the Action Plan Period. At first glance, this project seems
unremarkable; however, this study is an essential element of the IRP and advances the
fourth element of the Company’s strategic plan. Today, the Company has the ability to
participate in wholesale power markets when participation benefits Sierra’s customers.
That is, Sierra has the ability to make sales when doing so would reduce the cost of
providing electric service and buy electricity from other producers when the purchase
price is lower than the cost of producing electricity using the Company’s generation. The
Company is in this position because it has engaged in prudent long-term planning under
the Commission’s supervision and oversight. The greenfield study, in other words,
results from engaged employees that have the foresight to identify the steps that need to
be taken today in order to allow the Company to operate efficiently in 2022.
B.
Energy Supply Plan
Sierra’s Energy Supply Plan (“ESP”) for the Action Plan Period is the product of a
careful assessment of the costs and risks of a range of energy supply options. Integral
aspects of the analyses include Sierra’s expected capacity and energy positions, market
fundamentals and an assessment of the challenges that Sierra will face in balancing the
objectives of minimizing cost of service, minimizing rate volatility, maximizing
reliability of supply, and optimizing the portfolio for the benefit of retail customers.
The Company expects that it will have an open capacity position (“Open Position”) in
2014 of 111 MW; the Company anticipates that its Open Position will grow in 2015 to
261 MW and, in 2016, to 279 MW. At this point, Sierra plans to leave these positions
open instead of procuring a capacity product (e.g., a forward purchase of firm energy, a
heat rate call option, or entering into a tolling agreement) for several reasons. First,
Sierra plans to reassess its Open Position after the completion of the One Nevada
Transmission Line (“ON Line”) and following the completion of Docket No. 13-05056.
Second, the Western Electric Coordinating Council reports, that there is more than
adequate capacity in 2014. Accordingly, there is little reliability risk associated with
leaving the 2014 position open as long as Sierra continues to monitor markets. If market
conditions change, the Company will take reasonable and necessary steps to close the
Open Position in a cost effective manner. Third, with respect to the 2015 and 2016 Open
Positions, the Company has sufficient time to update its ESP and, if necessary, procure
appropriate steps to close the Open Positions.
With respect to hedging strategies, the Company evaluated alternatives that would use
fixed price contracts or call options with varying strike prices to determine the expected
performance of these approaches against two gas price blowout scenarios. The expected
performance of each of the scenarios did not indicate a large benefit to customers when
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compared to the expected premiums. Therefore, the Company selected as its preferred
option, consistent with the existing Commission approved strategy, acquiring no natural
gas hedges at this time.
SECTION II:
LIST OF ACTIONS -- NAC § 704.9489(1)(b)(d)
This section of the Action Plan lists the actions for which Sierra “is seeking the approval
of the Commission.” 1
LOAD FORECAST – IRP AND ESP
x
x
Approval of the long-term load forecast presented in the Load Forecast and Market
Fundamentals Volume.
Approval of the three-year load forecast presented in the ESP.
FUEL AND PURCHASED POWER FORECAST – IRP & ESP
x Approval of the long-term fuel and purchased power forecasts presented in the Load
Forecast and Market Fundamentals Volume.
GENERATION 2
x Approval to expend $1.25 million over the Action Plan Period to perform a
comprehensive study and conceptual design for a Company-owned greenfield or
brownfield facility, suitable for commercial operation as early as 2022.
x Approval to retire oil firing capability on Tracy Unit 3 and Ft. Churchill Units 1 and
2.
x Approval to expend funds to comply with MATS environmental requirements for
Valmy Unit 1.
x Approval to establish a regulatory asset for the cost associated with the retirement of
Tracy Units 1 and 2.
x Approval of the agreements necessary to facilitate the Ft. Churchill Solar Array
Project, including the requested accounting treatment, and approval to acquire,
through a lease agreement, a new solar generating unit.
1
Nev. Admin. Code § 704.9489(1)(b).
A detailed time-line graph showing permitting, environmental analysis, the points at which the
Company would make commitments of significant expenditures, construction periods and the anticipated commercial operation date for (a) new projects and (b) previously approved projects where the project
scope, budget or schedule has changed are included in Technical Appendix #. See Nev. Admin. Code § 704.9378.
2
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RENEWABLES
x Approval of the renewable energy plan presented in the Supply Side Volume as
presenting the best and most accurate information upon which to base the planning
decisions described in the Action Plan period.
TRANSMISSION 3
x Approval of modifications to budgets and schedules of previously approved projects:
o Fallon 230 kV Project- Reduced scope.
o Bordertown to Cal Sub- Delay from 2014 to 2016.
o 345 kV Voltage Support Project- Revised Schedule.
x Approval for construction of a new 345/120 kV substation at Oreana.
x Approval of the Carlin Trend Area UVLS Project.
x Approval for construction of and a second 345/120 kV transformer at Falcon.
x Approval of Coyote Creek 120 kV Breaker Addition Project.
x Approval of Carlin Trend Transmission Additions.
x Approval of the Company’s Renewable Conceptual Transmission Plan as meeting the
requirements of NAC § 707.9385(6).
x Approval to continue Sierra’s involvement and membership in WestConnect.
DEMAND SIDE PROGRAMS
x Approval of the measurement and verification reports for program year 2012 and a
finding they are adequate for the calculation of the NRS § 704.785 revenue
requirement caused by the programs delivered in the 2012 program year.
x Approval of the program scopes, measurement and verification plans, budgets,
timetables and measures set forth in the DSM plan and as set forth in Figure AP-04
below
3
A detailed time-line graph showing permitting, environmental analysis, the points at which the
Company would make commitments of significant expenditures, construction periods and the anticipated
commercial operation date for (a) new projects and (b) previously approved projects where the project
scope, budget or schedule has changed are included in Technical Appendix #. See Nev. Admin. Code §
704.9378.
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FIGURE AP-01
Demand Side Action Plan Budget
Low Income Weatherization
Home Energy Reports
Residential Lighting
Refrigerator Recycling
Solar Thermal Water Heating
Subtotal - Residential
2014
2015
2016
Total
$0
$600,000
$800,000
$500,000
$200,000
$2,100,000
$0
$520,000
$1,200,000
$500,000
$200,000
$2,420,000
$0
$520,000
$1,400,000
$500,000
$200,000
$2,620,000
$0
$1,640,000
$3,400,000
$1,500,000
$600,000
$7,140,000
Non-Profit Agency Grants
Energy Smart Schools
Commercial Incentives
Subtotal - Commercial
$110,000
$400,000
$4,500,000
$5,010,000
$110,000
$400,000
$4,500,000
$5,010,000
$110,000
$400,000
$4,500,000
$5,010,000
$330,000
$1,200,000
$13,500,000
$15,030,000
Energy Education
Market and Technology Trials
Subtotal - Other
$250,000
$100,000
$350,000
$250,000
$100,000
$350,000
$250,000
$100,000
$350,000
$750,000
$300,000
$1,050,000
Total Energy Efficiency
$7,460,000
$7,780,000
$7,980,000
$23,220,000
Demand Response
Total Demand Response
$2,950,000
$2,950,000
$3,950,000
$3,950,000
$5,600,000
$5,600,000
$12,500,000
$12,500,000
$10,410,000
$11,730,000
$13,580,000
$35,720,000
Total Demand Side Programs
x A determination that Sierra has satisfied the directives contained in Ordering
Paragraphs 11, 12, 13, 14, 15, 16, 17, and 18 of the Commission’s Order dated
December 24, 2012, in Docket Nos. 12-06052 and 12-06053 (“2012 Order”).
ENERGY SUPPLY PLAN
Power Procurement/Sales Plan
x Acceptance and approval of the power procurement plan and its constituent
elements, which includes the following:
o Open Positions are currently expected in each year of the ESP forecast period.
However, Sierra plans to reassess these Open Positions following the
completion of ON Line and the anticipated merger with Nevada Power
Company. As such, the Company does not plan to secure firm products to fill
those Open Positions at this time, but will continue to monitor the portfolio on
an on-going basis. Sierra continuously monitors the portfolio and will seek to
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make short-term and forward purchases when economic or needed to serve
native load. Any proposed purchases of greater than three years in duration
will be submitted to the Commission for approval in a resource plan filing or
amendment in accordance with NAC §§ 704.9113 and 704.9512.
o Continue to make purchases and sales to optimize the value of the overall
supply portfolio for the benefit of its retail customers.
o Sierra will monitor its renewable portfolio on a continuous basis to ensure that
sufficient renewable energy and portfolio energy credits (“PCs”) are
maintained to comply with Nevada’s Renewable Portfolio Standard (“RPS”),
and will undertake cost-effective opportunities to fill any new needs that may
arise.
Current projections indicate that no additional purchases will be
required during the Action Plan Period for Sierra to meet the RPS.
x Sierra is requesting a finding, consistent with NAC § 704.9494(3), that the power
procurement strategy is prudent.
Physical Gas Procurement Plan 4
x Sierra is requesting acceptance and approval of its plan to continue to implement
the four-season laddering strategy approved by the Commission in Docket No.
12-08010 to procure physical gas. Projected physical gas requirements procured
through the laddering strategy will be procured with indexed products, subject to
a cap on the premium which can be exceeded with prior approval from the Energy
Risk Committee (“ERC”). Consistent with the Stipulation in Docket No. 09­
09001, if Sierra exceeds the premium cap, the Company will provide written
notice to Staff and BCP.
x Sierra is requesting an affirmative finding consistent with NAC § 704.9494(3)
that its physical gas procurement strategy is prudent.
Gas Transportation Plan
x Acceptance and approval of its gas transportation plan, which includes the
following elements:
o Approval to extend a total of 17 existing gas transportation contracts with
TransCanada Pipeline Ltd. (“TransCanada”), Paiute Pipeline Co. (“Paiute”)
and Northwest Pipeline (“NWPL”) pursuant to its evergreen rights. The total
projected cost of these contracts is approximately $28.1 million for the one
year period of 2015-2016. Additionally, Sierra is seeking approval to extend a
storage contract with NWPL for the same period at a cost of $131,000.
4
The Company’s “fuel procurement plan” consists of several distinct elements; namely, the physical gas
procurement plan, the gas transportation plan, the gas hedging plan and the coal procurement plan.
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x A finding, consistent with NAC § 704.9494(3), that its gas transportation strategy
is prudent.
Gas Hedging Plan
Sierra requests approval of its gas hedging plan, which includes the following
elements:
x Sierra is proposing to continue its current hedging strategy and acquire no natural
gas hedges covering the ESP period at this time. The Company will continue to
monitor the natural gas market fundamentals and recommend changes to the
hedging strategy in an ESP Update or ESP Amendment as necessary.
x Sierra will continue quarterly workshops with Staff and BCP to review
implementation of the approved gas hedging strategy.
x Sierra is requesting an affirmative finding, consistent with NAC § 704.9494(3),
that its gas hedging strategy is prudent.
Coal Supply Plan
x Sierra is requesting acceptance and approval of a revised Coal Supply Plan. This
plan considers changes to current and projected coal unit operations and the level
of uncertainty surrounding these operations, as well as market conditions. Major
elements of the Coal Supply Plan include the following:
•
•
•
•
•
•
•
•
x
Do not issue an RFP for Coal Supply for 2014 and beyond;
Suspend measuring coal commitments vs. laddering targets;
Continue to report inventory levels compared to targets and
maximum storage capability on a frequent basis;
Continue to monitor the relevant coal markets and fuel market
fundamentals;
Rely on spot market solicitations if coal supplies in excess of
minimum contract receipts are needed;
Evaluate steps to reduce minimum contract coal takes and
implement those actions that are justified if expected coal-unit
dispatch decreases and inventory levels approach maximum
storage capacity;
Attempt to negotiate revisions to the transportation contract
minimum volume provision as necessary, appropriate or feasible;
and
Develop plans for a successor transportation arrangement.
Sierra is requesting an affirmative finding consistent with NAC § 704.9494(3)
that its coal procurement strategy is prudent.
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Risk Management Strategy
x
Sierra is requesting acceptance and approval of its risk management strategy and a
finding that the strategy identifies risks inherent in procuring and obtaining a
supply portfolio and establishes the means by which the utility plans to address
and balance or hedge the identified risks related to cost, price volatility and
reliability.
x
Sierra is requesting an affirmative finding consistent with NAC § 704.9494(3)
that its risk management strategy is prudent.
Commission Directives
Sierra requests a finding that it has satisfied the following Commission directive:
x The Company was directed to continue conducting quarterly gas hedging
workshops as described in the Stipulation that the Commission accepted and
approved in Docket No. 11-09004.
Additional Findings. In addition to the above findings, Sierra is requesting that the
Commission make the following findings pursuant to NAC § 704.9494:
x Sierra requests a finding that the ESP balances the objectives of minimizing the
cost of supply, minimizing retail price volatility and maximizing the reliability of
supply over the term of the plan.
x Sierra requests a finding that the ESP optimizes the value of the overall supply
portfolio of the utility for the benefit of its bundled retail customers.
x Sierra requests a finding that the ESP does not contain any feature or mechanism
that the Commission finds would impair the restoration of the creditworthiness of
the utility or would lead to a deterioration of the creditworthiness of the utility.
SECTION III :
DATA ACQUISITION -- NAC § 704.9489(1)(c)
Sierra will continue to pursue improvements to the forecast models described in this
filing, including economic and price projections for all customer classes, end-use
saturations and efficiency trends, as well as projected improvements in thermal shell
integrity in the residential model. Sierra has not identified and is not proposing changes to
its data acquisition schedule for the preparation of future forecasts to be utilized for long­
term resource planning.
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SECTION IV:
TIMETABLE
§§704.9489(1)(d), (3)(a-d), (4)
BUDGET
AND
FOR
PROGRAMS
--
NAC
Figure AP-04 outlines the Action Plan budget for 2014, 2015 and 2016. Also shown is
the estimated budget for expenditures that are outside the three-year Action Plan Period.
Not shown are the budget categories for the cost to develop the IRP, including the load
forecast and the development of the financial plan. For many years, the costs for
developing the IRP have been internalized and no longer are tracked in a balancing
account.
FIGURE AP-02
Action Plan Budget—Preferred Plan
(Millions excluding AFUDC)
Action Plan Projects
Total
Total Pre
2014
Demand Side
Conservation/Energy Efficiency
Demand Response
Sub-Total Demand Side
2014
$7.46
$2.95
$10.41
Generation
Previously Approved Projects
T3 and FC BART Projects
New Projects
Valmy 1 MATS (Sierra Share)
Greenfield Site Study
Sub-Total Generation
$7.98
$5.60
$13.58
3-Year
Total
$23.22
$12.50
$35.72
$26.08
$26.08
$7.10
$0.00
$7.10
$0.50
$7.60
$0.38
$0.38
$0.38
$0.38
$7.10
$1.25
$8.35
$10.28
$30.04
$4.46
$0.26
$2.76
$4.08
$10.02
$1.12
$0.38
$0.00
$2.63
$0.00
$0.00
$22.05
$0.00
$10.02
$25.80
$0.38
$69.01
$0.46
$6.91
$1.19
$43.80
$4.57
$0.05
$0.35
$0.00
$0.05
$166.15
$12.12
$62.57
$0.41
$4.83
$0.36
$0.20
$0.14
$80.03
$1.88
$0.00
$1.73
$0.83
$0.20
$0.15
$7.42
$0.00
$0.00
$0.00
$0.00
$0.20
$0.15
$22.40
$64.45
$0.41
$6.56
$1.19
$0.60
$0.44
$109.85
$173.25
$12.12
$98.04
$19.52
$36.36
$153.92
$7.10
Total
$7.78
$3.95
$11.73
2016
$13.20
$39.27
Transmission
Previously Approved Projects
Falon Project (Carson Lake)*
Bordertown to Cal Sub
345 kV Voltage Suport Project
New Projects
Hycroft Mine Load Addition / Oreana 345/120 kV
Substaion**
Carlin Trend Under Voltage Load Shedding Scheme
Falcon Second 345/120 kV Transformer
Coyote Creek 120 kV Breaker Addition
Carlin Trend Transmission Additions
West Connect (Sierra Portion)
Sub-Total Transmission
2015
NonAction
Plan
Period
$38.50
$38.50
$38.50
* Carson Lake budget includes $2.8 million in TPIF costs paid by customer
** Hycroft mine is paid for by customer under rule 9
While Apple is responsible for permitting and construction of the Ft. Churchill Solar
Array, the currently anticipated commercial operation date is January 2015. After
commercial operation begins, Sierra will make payments to Apple pursuant to the facility
lease agreement. If commercial operation is not within ten days of January 1, the lease
payments will reflect avoided energy costs and will be paid in arrears annually. After
that (or if commercial operation begins from January 1st through 10th), Sierra will make a
fixed lease payment in arrears annually (see Confidential Technical Appendix # for the
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amount) for the prior year. Because of the unique nature of the transaction, Sierra created
a table showing the expected net costs associated with the transaction. Figure # in the
Confidential Technical Appendix shows those costs.
SECTION V:
CHANGES IN METHODOLOGY -- NAC § 704.9489(1)(e)
No changes in planning methodology are being proposed.
SECTION VI:
704.9489(1)(f)
ACQUISITION
OF
NEW MODELING INSTRUMENTS -- NAC §
The Company is not proposing to acquire new modeling instruments.
SECTION VII:
DEMAND
704.9489(1)(g)(1)(2)(3)
SIDE
PLAN
PROGRAMS
--
NAC
§
A description of continued planning efforts and the plan to carry out and continue
selected conservation and demand management measures is set forth in Section II above.
Sierra has not attempted to claim or calculate imputed debt associated with energy
efficiency contracts in the Preferred Plan.
SECTION VIII:
RESOURCES FOR SUPPLY -- NAC § 704.9489(1)(h)
A description of immediate plans for construction of utility facilities and long-term
purchases of power as well as in-service dates and budgets are set forth in Sections II and
IV above. Sierra has not attempted to claim or calculate imputed debt associated with
renewable energy or energy efficiency contracts in the Preferred Plan.
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EXHIBIT B 3DJHRI
SIERRA PACIFICPOWER COMPANY
INTEGRATED RESOURCE PLAN FOR 2014-2033 LIST OF APPLICABLE STATUTORY AND REGULATORY REQUIREMENTS
LIST OF APPLICABLE STATUTES
NRS 704.741(1) requires the Company to submit, in the manner specified by the
Commission, a plan to increase its supply of electricity or decrease the demands made on its
system by its customers to the Commission. Sierra Pacific Power Company d/b/a NV Energy
(“Sierra” or the “Company”) is submitting herewith its Integrated Resource Plan for 2014-2033
(“IRP” or “2013 Resource Plan”) which includes a plan to increase its supply of electricity and
decrease the demands made on its system by its customers.
NRS 704.741(2)(a) requires the Commission to prescribe the contents of the plan
including, but not limited to, the methods or formulas which are used by the utility to forecast the
future demands. The Company addresses below each of the Commission’s regulations regarding
the contents of the plan and the methods or formulas which are used to forecast the future
demands.
NRS 704.741(2)(b) requires the Commission to prescribe the contents of the plan
including, but not limited to, the methods or formulas that are used by the utility to determine the
best combination of sources of supply to meet the demands or the best method to reduce them.
The Company addresses below each of the Commission’s regulations regarding the contents of
the plan and the methods or formulas which are used to determine the best combination of
sources of supply to meet the demands or the best method to reduce them.
NRS 704.741(3)(a) requires the Commission to require the utility to include in its plan an
energy efficiency program for residential customers which reduces the consumption of electricity
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or any fossil fuel. The energy efficiency program must include, without limitation, the use of
new solar thermal energy sources. The Company addresses below each of the Commission’s
regulations regarding the contents of the plan. The 2013 Resource Plan includes a Demand Side
Plan which includes strategies for improving energy efficiency programs for the Company’s
customers, reducing the consumption of electricity or any fossil fuel, and increasing the use of
new solar thermal energy sources. See, among other portions of the filing, DSM Narrative and
Exhibit A to the DSM Narrative.
NRS 704.741(3)(b), as amended by SB 165 (2009 Session), requires the Commission to
require the utility to include in its plan “a comparison of a diverse set of scenarios of the best
combination of sources of supply to meet the demands or the best methods to reduce the
demands, which must include at least one scenario of low carbon intensity.” NRS 704.741(4), as
amended by SB 165 (2009 Session), defines “carbon intensity” as “the amount of carbon by
weight emitted per unit of energy consumed.”
In Docket No. 09-07013, the Commission
adopted regulations implementing SB 165 (2009 Session). The adopted regulations are included
in NAC 704.9355 and NAC 704.937, and are addressed below.
NRS 704.741, as amended by AB 387 (2009 Session) (“AB 387”), requires, among
other things, the Commission to adopt regulations designating “geographic areas where
renewable energy resources are sufficient to develop generation capacity and where transmission
constrains the delivery of electricity from those resources to customers” as “renewable energy
zones.” [1] The Commission adopted a regulation defining renewable energy zones (“REZs”) on
[1]
Assembly Bill 387, § 6(2)(b).
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December 21, 2009. [2]
See the Supply Side Plan, Economic Analysis, and Financial Plan
volume, Section 2.E.7 (Renewable Energy Transmission Development).
LIST OF REGULATIONS APPLICABLE TO THE ENERGY SUPPLY PLAN
NAC 704.9482
Requirements for energy supply plan, purchased power
procurement plan, fuel procurement plan and risk management strategy; consistency with
action plan; annual filings.
NAC 704.9482(1) requires that “the resource plan of a utility must contain an energy
supply plan for the 3 years covered by the action plan of the utility. The resource plan of a utility
must be consistent with the action plan of the utility.” The Energy Supply Plan for the 3 years
covered by the Action Plan (2014-2016) is provided in the Energy Supply Plan volume. The
Energy Supply Plan consists of a narrative and technical appendices that stand-alone and are
filed concurrently with the IRP.
NAC 704.9482(2) requires that “an energy supply plan must be developed by a utility
using its base forecast and target planning reserve margin.” The Energy Supply Plan for 2014­
2016 was developed using Sierra’s base forecast and target planning reserve margin, as reflected
in the loads and resources tables for 2014, 2015, and 2016 (see Energy Supply Plan, Figures
ESP-6A, 6B, and 6C, respectively).
NAC 704.9482(3) requires that “as part of its energy supply plan, a utility shall develop a
purchased power procurement plan. The purchased power procurement plan of a utility must
include, without limitation:
[2]
Rulemaking to adopt, amend, or repeal regulations regarding renewable energy zones, transmission plans,
renewable developer commitments, and other related utility matters in accordance with Assembly Bill 387, Order
(iss. Dec. 21, 2009).
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(a)
The proposed mix of purchased power products by: (1) Type of resource; (2)
Delivery profile; and (3) The term that the utility considers appropriate for the expected demand.
See Energy Supply Plan, Section 4 (Power Procurement Plan).
(b) A description of the criteria used to determine the proposed mix of power products
and the material factors influencing the selection of the criteria. See Energy Supply Plan,
Section 4 (First Paragraph).
(c) The proposed schedule for procuring the purchased power products, including a
description of any competitive procurement processes to be undertaken. See Energy Supply
Plan, Section 4.B. (Summary of Power Procurement Plan).
(d) A regional assessment of the availability of fuel and purchased power resources for
the period covered by the energy supply plan. See Energy Supply Plan, Section 3 (Market
Fundamentals and Price Forecasts) and Load Forecast and Market Fundamentals volume,
Section II (Market Fundamentals).
(e) A projection of remaining capacity and energy requirements for each year of the
period covered by the energy supply plan, after accounting for all existing resources and
proposed long-term purchased power obligations.
See Energy Supply Plan, Sections 2.B.
(Capacity Requirements) and 2.C (Energy Requirements) and Figures 6A, 6B, and 6C.
(f) A description, by type and term, of each existing purchased power contract with
deliveries during the period covered by the energy supply plan. See Energy Supply Plan, Section
4.A. (Current Portfolio).
(g) A description, by type, delivery profile and term, of the purchased power products
expected to be available to the utility during the period covered by the energy supply plan.” See
Energy Supply Plan, Section 4.C.2. (Potential Products).
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NAC 704.9482(4) requires that “as part of its energy supply plan, a utility shall develop a
fuel procurement plan for each fuel that the utility uses to generate at least 5 percent of its annual
energy requirements. (Sierra uses coal and natural gas to generate at least 5 percent of its annual
energy requirements). The fuel procurement plan must include, without limitation:
(a) For each year of the energy supply plan, a projection of the quantity of each fuel the
utility expects to use for each generating unit owned or controlled by the utility. See Energy
Supply Plan, Section 2.F. (Physical Gas Requirements) and Figure ESP-12; Section 2.H. (Coal
Requirements) and Figure ESP-14.
(b) A description of each existing fuel contract with deliveries during the period covered
by the energy supply plan, including the type of product, the quantity to be delivered, the
delivery point and the term of the contract. See Energy Supply Plan, Section 2.F. (Physical Gas
Requirements) and Figure ESP-57 (Existing Natural Gas Transportation Contracts); Section 6.A.
(Current Coal Purchase and Transportation Agreements).
(c) A description of the fuel products available to the utility during the period covered by
the energy supply plan, including the type of product, the pricing method, the delivery point and
the term of the availability of the fuel products. See Energy Supply Plan Section 3 (Market
Fundamentals and Price Forecasts).
(d) The proposed mix of fuel products. See Energy Supply Plan, Section 5 (Gas
Procurement Plan); Section 6 (Coal Supply Plan).
(e) A description of the criteria used to determine the proposed mix of products and the
material factors influencing the selection of the criteria. See Energy Supply Plan, Section 5 (Gas
Procurement Plan), Section 6 (Coal Supply Plan).
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(f) The proposed schedule for procurement of the fuel, including a description of any
competitive procurement process to be undertaken. See Energy Supply Plan, Section 5 (Gas
Procurement Plan), Figure ESP-55; Section 6 (Coal Supply Plan).
NAC 704.9482(5) requires that “as part of its energy supply plan, a utility shall include a
risk management strategy that includes, without limitation:
(a)
“A description of how the risk management strategy was reflected in the
determination of the energy supply plan proposed by the utility.” See Energy Supply Plan,
Section 7.B. (Elements of the Strategy Applied to the Energy Supply Plan).
(b) “A description of the criteria used to select the proposed risk management strategy
and identification of the material factors that influenced the selection of the criteria by the utility.
See Energy Supply Plan, Section 7.B. (Elements of the Strategy Applied to the Energy Supply
Plan).
(c) “A description of each technique for mitigating risk that was considered. See Energy
Supply Plan, Section 7.A. (Elements of the Strategy).
(d) “The criteria to be used to evaluate the effectiveness of the risk management
strategy.” See Energy Supply Plan, Sections 7.C. (Selection Criteria) and 7.D. (Evaluation
Criteria).
NAC 704.9482(6) requires that “a utility shall annually file with the Commission an
evaluation of its purchased power procurement plan, its fuel procurement plan, its risk
management strategy and, if applicable, the results of any performance-based methodology for
the recovery of costs for natural gas for each year included in its deferred energy application
filed pursuant to NAC 704.023 to 704.195, inclusive.” Sierra made such a filing on March 1,
2013, designated Docket No. 13-03004. Sierra’s next annual filing is due on March 1, 2014.
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NAC 704.9482(7) requires “the energy supply plan of a utility must include a technical
appendix that conforms to NAC 704.922.” Sierra’s Energy Supply Plan includes a Technical
Appendix that conforms to NAC 704.922.
NAC 704.9486 Performance-based methodology for recovery of costs for natural
gas used as fuel for generation: Proposal for establishment; report of results.
NAC 704.9486(1) states that “as part of its energy supply plan, a utility may propose the
establishment of a performance-based methodology for the recovery of costs for natural gas used
as a fuel for generation. Any proposed performance methodology must be based upon objective
standards and criteria.”
Sierra is not proposing establishment of a performance-based
methodology for the recovery of costs for natural gas used as a fuel for generation.
NAC 704.9486(2) requires that “a proposal for the establishment of a performance-based
methodology for the recovery of costs for natural gas must include information sufficient to
enable the Commission to evaluate the proposal, including, without limitation: (a) The criteria to
be used in measuring the performance of the utility; (b) The rationale for using the selected
criteria; (c) If appropriate, the proposed sharing allocation between the utility and its consumers;
(d) The duration of the program; and (e) Supporting documentation.” Sierra is not proposing
establishment of a performance-based methodology for the recovery of costs for natural gas used
as a fuel for generation.
NAC 704.9486(3) requires “if the Commission authorizes a performance-based
methodology, the utility shall report the results of the methodology approved by the Commission
in the deferred energy application filed by the utility pursuant to NAC 704.023 to 704.195,
inclusive. At a minimum, the report must cover the period between the adjustment date for the
most recent deferred energy application and the adjustment date for the application which
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includes the report of the results of the approved methodology.”
Sierra is not proposing
establishment of a performance-based methodology for the recovery of costs for natural gas used
as a fuel for generation.
NAC 704.9494 Approval of action plan; determination that elements of energy
supply plan are prudent; recovery of costs to carry out approved plans
NAC 704.9494(3) states that “if, at the time that the Commission approves the action
plan of the utility, the Commission determines that the elements of the energy supply plan are
prudent, the Commission will specifically include in the approval of the action plan its
determination that the elements contained in the energy supply plan are prudent.” For the
Commission to make a determination that the elements of the energy supply plan are prudent:
(a) “The energy supply plan must not contain any feature or mechanism that the
Commission finds would impair the restoration of the creditworthiness of the utility or would
lead to a deterioration of the creditworthiness of the utility.” See the Energy Supply Plan
Testimony of Mr. Naveed Mughal, Q&A 6 and the Energy Supply Plan, Section 8
(Determination of Prudence).
(b) “The energy supply plan must optimize the value of the overall supply portfolio for
the utility for the benefit of its bundled retail customers.”
See the Energy Supply Plan
Testimony of Mr. Gregory A. Kern; Energy Supply Plan, Section 4.A. (Current Power Portfolio
and Portfolio Optimization Procedures), Section 8 (Determination of Prudence).
(c) “The utility must demonstrate that the energy supply plan balances the objectives of
minimizing the cost of supply, minimizing retail price volatility and maximizing the reliability of
supply over the term of the plan.” See the Energy Supply Plan Testimony of Mr. James Doubek,
Q&A 14; Energy Supply Plan, Section 8 (Determination of Prudence).
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NAC 704.9504 Deviation from and amendment of energy supply plan.
NAC 704.9504(1) states that “notwithstanding the approval by the Commission of the
energy supply plan of a utility, the utility may deviate from the approved energy supply plan to
the extent necessary to respond adequately to any significant change in circumstances not
contemplated by the energy supply plan.
A significant change in circumstances includes,
without limitation: (a) A material change in the market price of fuel or purchased power; (b) An
extended forced outage of a major generating unit of the utility; (c) A material change in
customer demand; and (d) Any other circumstance that the utility demonstrates to the
Commission warrants a deviation.” Sierra acknowledges in the Energy Supply Plan, Section
1.B. (ESP Objectives and Regulatory Context), that it may deviate from its approved Energy
Supply Plan.
NAC 704.9504(2) states that “if a utility deviates from its approved energy supply plan:
(a) The utility shall, as soon as practicable, inform the staff of the deviation from the energy
supply plan; (b) The utility shall include in the deferred energy application filed pursuant to
NAC 704.023 to 704.195, inclusive, in which costs associated with the deviation are first sought
to be recovered, a description of and justification for the deviation; (c) The Commission will
determine on a retrospective factual basis the prudence of the deviation from the energy supply
plan in the appropriate proceeding held on the deferred energy application; (d) If the deviation
from the energy supply plan is of a continuing nature, the utility shall seek authority from the
Commission to deviate prospectively from the energy supply plan in an update of the energy
supply plan filed pursuant to NAC 704.9506, or by filing an amendment to the energy supply
plan in accordance with subsection 3.” Sierra will comply with these requirements if it deviates
from its approved Energy Supply Plan.
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NAC 704.9506 Update of energy supply plan: Filing; requirements.
NAC 704.9506(1) requires that “on or before September 1 of the first and second years
after the action plan of a utility is filed, the utility shall file an update of the energy supply plan
that will be applicable for each year remaining in the period covered by the action plan. Not
applicable.
NAC 704.9506(2) requires that “the update of the energy supply plan must comply with
the requirements of subsections 1 to 5, inclusive, and 7 of NAC 704.9482, except that the load
forecast must be the most recent forecast available at the time the plan is prepared.” This filing
is based on the most recent load forecast available at the time the plan was prepared. The
requirements of NAC 704.9482(1) to (5) are discussed above.
LIST OF REGULATIONS APPLICABLE TO THE INTEGRATED RESOURCE PLAN
NAC 704.9215 Summary of Resource Plan
NAC 704.9215(1) requires that “a utility's resource plan be accompanied by a summary
that is suitable for distribution to the public. The summary must contain easily interpretable
tables, graphs and maps and must not contain any complex explanations or highly technical
language. The summary must be approximately 30 pages in length.” See Summary Volume.
NAC 704.9215(2)(a) states that the summary must include “a brief introduction,
addressed to the public, describing the utility, its facilities and the purpose of the resource plan,
and the relationship between the resource plan and the strategic plan of the utility for the duration
of the period covered by the resource plan. See Summary Volume, Section I (Introduction).
NAC 704.9215(2)(b) requires the summary to include the “forecast of low growth, the
forecast of high growth and the forecast of base growth of the peak demand for electric energy
and of the annual electrical consumption, for the next 20 years, commencing with the year
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following the year in which the resource plan is filed, both with and without the impacts of
programs for conservation and demand management and an explanation of the economic and
demographic assumptions associated with each forecast.” See Summary Volume, Section II
(Forecast of Growth).
NAC 704.9215(2)(c) requires “a summary of the demand side plan listing each program
and its effectiveness in terms of costs and showing the 20-year forecast of the reduction of
demand and the contribution of each program to this forecast.” See Summary Volume, Section
III (Demand Side Plan Summary).
NAC 704.9215(2)(d) requires “a summary of the preferred plan showing each planned
addition to the system for the next 20 years, commencing with the year following the year in
which the resource plan is filed, with its anticipated capacity, cost and date of beginning
service.” See Summary Volume, Section IV (Summary of the Preferred Plan).
NAC 704.9215(2)(e) requires “a summary of renewable energy showing how the utility
intends to comply with the portfolio standard and listing each existing contract for renewable
energy and each existing contract for the purchase of renewable energy credits and the term and
anticipated cost of each such contract.” See Summary Volume, Section V (Summary of the
Renewable Energy Plan).
NAC 704.9215(2)(f) requires “a summary of (1) The energy supply plan for the next 3
years setting out the anticipated cost, price volatility and reliability risks of the energy supply
plan; (2) The risk management strategy; (3) The fuel procurement plan; and (4) The purchased
power procurement plan.” See Summary Volume, Section VI (Summary of Energy Supply
Plan).
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NAC 704.9215(2)(g) requires “a summary of the activities, acquisitions and costs
included in the action plan of the utility.” See Summary Volume, Section VII (A Summary of
the Activities, Acquisitions, and Costs included in the Action Plan of the Utility).
NAC 704.9215(2)(h) requires “an integrated evaluation of the components of the
resource plan which relates the preferred plan to the objectives of the strategic plan of the utility,
and any other information useful in presenting to the public a comprehensive summary of the
utility and its expected development.”
See Summary Volume, Section VIII (Integrated
Evaluation).
NAC 704.922 Technical Appendix to Resource Plan
NAC 704.922(1) states, “a utility's resource plan must include a technical appendix. The
appendix must contain sufficient detail to enable a technically proficient reader to understand
how the resource plan and its forecasts were prepared and to evaluate the validity of the
assumptions and the accuracy of the data used, including, without limitation, a list of the major
assumptions used, a description of the forecasting methods employed and a description of the
software utilized.” The 2012 Resource Plan includes a technical appendix with sufficient detail
to enable a technically proficient individual to understand how the resource plan and its forecasts
were prepared and to evaluate the validity of the assumptions and accuracy of the data used.
NAC 704.922(2) requires that “the appendix must contain sufficient information to
enable a technically proficient reader to reproduce the results from the computations shown,
including, without limitation:
(a) “Citations to the sources of all significant information used in the resource plan.”
See Technical Appendix Items LF-1 (Sierra 30-Year Load Forecast), F&PP-1 and F&PP-2 (Fuel
and Purchased Power Price Forecasts), GEN-1 (Unit Characteristics Table), GEN-3 (New
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Generation Units – Performance Data), GEN-4 (New Generation Units – Construction Cost and
Schedule Data), ECON-17 (NERA Report), REN-7 (Renewable Generic Buildout), and DSM-2
(PorfolioPro Model).
(b) “Descriptions of all data inputs to the models used in developing the resource plan
accompanied by an explanation of any modifications made to the data.”
See Technical
Appendix Items LF-1 (Sierra 30-Year Load Forecast), F&PP-1 and F&PP-2 (Fuel and Purchased
Power Price Forecasts), GEN-1 (Unit Characteristics Table), GEN-3 (New Generation Units –
Performance Data), GEN-4 (New Generation Units – Construction Cost and Schedule Data),
ECON-17 (NERA Report), REN-7 (Renewable Generic Buildout), and DSM-2 (PorfolioPro
Model).
(c) “Characteristics of the generation operation of the utility, including the:
(1) “Rates of forced outages.” See Technical Appendix Items ECON-4 (Unit
Forced Outage Rates) and GEN-1 (Unit Characteristics Table).
(2) “Rates of scheduled outages.”
See Technical Appendix Item ECON-5
(Scheduled Maintenance).
(3) “Heat rates.” See Technical Appendix Items GEN-1 (Unit Characteristics
Table), GEN-3 (New Generation Units - Performance Data).
(4) “Rates at which pollutants are emitted.”
See Technical Appendix Item
ECON-17 (NERA Report).
(5) “Controls required to mitigate pollution at planned facilities and estimates of
the costs of those controls.” Sierra is not proposing any new conventional generation
facilities in this filing. Therefore, there are no controls required to mitigate pollution at
planned facilities.
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(6) “Projections for the availability and price of fuels.” See Technical Appendix
Items F&PP-1 and F&PP-2 (Fuel and Purchased Power Price Forecasts).
(d) “Output characteristics or profiles of renewable resources for each type of renewable
resource that is being considered as a resource option or that is currently owned or under contract
with the utility.” See Technical Appendix Item REN-7 (Renewable Generic Buildout).
(e) “A summary of the impact of intermittent energy resources on the electric system of
the utility.” See Technical Appendix Item ECON-16 (Intermittent Impacts).
(f) “The final results derived from the models.” See Technical Appendix Items LF-1
(Sierra’s 30-Year Load Forecast), ECON-17 (NERA Report), ECON-13 (Production Costs),
ECON-14 (Capital Projects), ECON-15 (PWRR), DSM-2 (PortfolioPro Model), and F&PP-1
and F&PP-2 (Fuel and Purchased Power Price Forecasts).
(g) “Documentation of all models and formulas used consistent with any proprietary
requirements imposed upon the utility by outside suppliers of the models.” See Technical
Appendix Items ECON-2 (Description of Production Modeling Software), ECON-17 (NERA
Report), DSM-2 (PortfolioPro Model), LF-1 (Sierra’s s 30-Year Load Forecast), and LF-4
(Forecasting Using Statistically Adjusted End Use Models).
(h) “Such other information as is necessary to enable an informed reader to examine the
resource plan and verify the adequacy and accuracy of the data, assumptions and methods used
in developing the resource plan.” The Technical Appendix includes additional information that
the Company believes will be useful in examining the resource plan.
NAC 704.9225 Forecasts of Peak Demand and Annual Energy Consumption:
General Requirements
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NAC 704.9225(1) states that “a utility's resource plan must contain a series of forecasts
of the peak demand and annual energy consumption that represent the range of future load which
its system may be required to serve. The range of future peak demand and energy consumption
must be based upon and consistent with the upper and lower limits of expected economic and
demographic change in the utility's service territory in the next 20 years, commencing with the
year following the year in which the resource plan is filed, as follows: (a) A forecast of high
growth; (b) A forecast of base growth; and (c) A forecast of low growth.” The base, low and
high forecasts are included in the Technical Appendix Item LF-1 (Sierra’s 30-Year Load
Forecast), Figures 55 and 56.
NAC 704.9225(2) requires that “in each of the forecasts described in subsection 1, the
utility shall account for customer response to changes in the prices of electric energy and
substitute energy sources and to the impacts of existing and proposed programs undertaken by
the utility or required by governmental regulation to alter current energy use patterns.” The
Company included in its base, low, and high load forecasts reductions for demand side
management (“DSM”), demand response (“DR”) and small solar, wind and hydro programs. See
Load Forecast and Market Fundamentals Volume, Figure LF-32 for a graphical summary of the
Company’s Conservation and Energy Efficiency (“C&EE”) programs, as well as Tables LF-19
through LF-24 in Technical Appendix LF-1 (Sierra’s 30-Year Load Forecast).
Technical
Appendix LF-1, Tables LF-23 and LF-24 show the solar, wind and hydro net metering GWH
reductions and Table LF-41 shows the MW demand reductions on peak. DR reductions on peak
are shown in Table LF-42. A price variable is included in the Residential, Small C&I and Large
C&I (GS-3 rates) regression models.
See Figure LF-19 in the Load Forecast and Market
Fundamentals Volume as well as more discussion in Technical Appendix Item LF-1 (Sierra’s 30­
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Year Load Forecast). Section III (Model Specification) discusses how prices and governmentmandated appliance efficiency and building codes are modeled.
NAC 704.9225(3) states, “to the extent data is available, peak demand must be forecasted
before accounting for the effects of cogeneration.” The effects of cogeneration on the system
peak are discussed in Technical Appendix Item LF-1 (Sierra’s 30-Year Load Forecast), Section
V.E. (Co-Generation and Standby Demand).
NAC 704.9225(4) requires that the “utility shall maintain internal consistency among its
forecasts. The forecast of peak demand must be consistent with the forecast of energy
consumption and must be based on data which is normalized for weather pursuant to NAC
704.9245.” Hourly demand is forecasted using the sales forecast as an input. The sales forecast
is weather normalized using a 20-year monthly average of heating and cooling degree days.
Peak demand is weather normalized using the average of the past 20 years of peaking
temperatures. See Technical Appendix Item LF-1 (Sierra’s 30-Year Load Forecast) for more
details.
NAC 704.923 Periods to be Covered by Resource Plan
NAC 704.923(1) requires “for historical data, the 10-year period preceding the year in
which the resource plan is filed. If estimated data are used, the utility shall identify such data
and describe the procedure by which the estimates were made.” The 2013 Resource Plan
contains 10 years of historical peaks, sales, energy and load factors. See the Technical Appendix
Item LF-1 (Sierra’s 30-Year Load Forecast), Tables LF-1 and LF-3.
NAC 704.923(2) requires “for the forecasts of peak demand and energy consumption, the
20-year period beginning with the year in which the resource plan is filed.” See the Technical
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Appendix Item LF-1 (Sierra’s 30-Year Load Forecast), Figures 30 and 39 for the 20-year
forecast.
NAC 704.9235 Formats for Information Included in Resource Plan
NAC 704.9235(1) requires that “a utility shall, in consultation with the staff and subject
to the approval of the Commission, develop suitable formats to be used for all information
required in the resource plan of the utility.” Sierra has, in the past, consulted with the Regulatory
Operations Staff (“Staff”), regarding suitable formats to be used for information required in the
resource plan. The Company’s 2013 filing is consistent with past filings, in terms of formatting.
Furthermore, Sierra prepared the filing in accordance with the Commission’s regulations, which
generally dictate the format of most elements of the filing. Finally, Sierra provides executable
copies of non-confidential filing documents to Staff upon request.
NAC 704.9235(2) requires “graphical and tabular information must be accompanied by
explanatory narratives.” All graphical and tabular information is accompanied by explanatory
narratives.
NAC 704.9235(3) requires “a resource plan may include text which is not specifically
related to those formats but is of importance to the resource plan.” The 2013 Resource Plan
includes text which is of importance to the resource plan.
NAC 704.9245, Normalizing Forecast Values of Peak Demand and Energy
Consumption to Account for Normal Weather Conditions, requires “all forecast values of
peak demand and energy consumption must be normalized to account for normal weather
conditions within the service territory of the utility.” The sales forecast is weather normalized
using a 20-year monthly average of heating and cooling degree days. Peak demand is weather
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normalized using the average of the past 20 years of peaking temperatures. See Technical
Appendix Item LF-1 (Sierra’s 30-Year Load Forecast) for more details.
NAC 704.925 Resource plan: Inclusion, contents and evaluation of forecasts of
energy consumption and peak demand; consideration of certain impacts; identification of
change in methodology of forecasting.
NAC 704.925(1) requires that “a utility's resource plan must include forecasts of energy
consumption and the peak demand for summer and winter for the system, disaggregated by rate
schedule, for the 20-year period beginning with the year following the year in which the resource
plan is filed. The utility may combine rate schedules if necessary to protect the confidentiality of
individual customers.” This information is contained in Technical Appendix Item LF-1 (Sierra’s
30-Year Load Forecast), Table LF-31 for the sales and Table LF-45 for the class contribution to
peak demand.
NAC 704.925(2) requires that “the utility shall identify components of residential and
commercial energy and demand for which initiatives for conservation and demand management
are applicable. The utility shall include in its forecast an assessment of the impacts of such
initiatives on the identified components and on overall levels of energy consumption and demand
by residential and commercial customers.” This information is contained in the Technical
Appendix Item LF-1 (Sierra’s 30-Year Load Forecast), Tables 33 and 41, which summarize the
DSM, DR and small solar reductions by customer class for annual sales and at the time of the
system peak.
NAC 704.925(3) requires that “the utility's forecast must include: (a) Estimated annual
losses of energy on the system for the 20-year period of the resource plan; and (b) Estimated
annual energy to be used by the utility for the 20-year period of the resource plan.” These items
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are contained in the Technical Appendix Item LF-1 (Sierra’s 30-Year Load Forecast), Table LF­
39.
NAC 704.925(4) requires that “the utility shall consider the impact of applicable new
technologies and the impact of applicable new governmental programs or regulations.” The
class sales regression modeling includes variables constructed from estimated historical and
forecasted appliance saturations and efficiencies, building characteristics and square footage.
These estimates and forecasts include the effects of new technologies and government programs.
See Technical Appendix Item LF-1 (Sierra’s 30-Year Load Forecast), Section II. (Assumptions
and Data Development) and Section III (Model Specification) for a discussion of the
methodology that includes these items.
NAC 704.925(5) requires that “the utility shall consider the impact of distributed
generation and customers who acquire energy pursuant to NRS 704.787 or chapter 704B of
NRS.” See Technical Appendix Item LF-1 (Sierra’s 30-Year Load Forecast), Section E (CoGeneration and Standby Demand) for a discussion of distributed generation.
NAC 704.925(6) requires “the utility shall provide a reasonable estimate of the demand
from interruptible loads and the total demand of each type of interruptible load.” See Technical
Appendix Item LF-1 (Sierra’s 30-Year Load Forecast), Section V.G. (Interruptible Demand by
Type) for a discussion of the interruptible loads, and Table LF-47 for a summary of the
forecasted demand reduction at the time of system peak for each program.
NAC 704.925(7) requires “the utility shall identify all standby loads and the total demand
of each type of standby load and include an analysis of the likelihood and effect of incurring
such demands at the time of the system peak of the utility.” See Technical Appendix Item LF-1
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(Sierra’s 30-Year Load Forecast), Section V.F. (Effects of Stand-by Customers on the Peak
Demand) and Figure 46.
NAC 704.925(8) requires “all forecast values for the entire system of the utility must be
reported. The utility shall separately estimate the contribution to peak demand and energy
consumption for the components of the system located within the State of Nevada and for the
components of the system located outside the State of Nevada.” All forecast values for the entire
system of the Company are reported.
NAC 704.925(9) requires that “a resource plan must contain a graphical representation of
projected load duration curves for the year following the year in which the resource plan was
filed and every fifth year thereafter for the remainder of the period covered by the resource
plan.” See the Technical Appendix Item LF-1, Figures LF-10 and LF-11.
NAC 704.925(10) requires that “to verify and complete the final forecasts, the utility may
evaluate the forecasts with the results of alternative forecasting methods.”
No alternative
forecasting models are presented in this IRP filing.
NAC 704.925(11) requires that “any change in the methodology of forecasting used by
the utility from that used in the utility's previous resource plan must be identified in the current
resource plan of the utility.” As noted in the Energy Supply Plan Testimony of Mr. Terry A.
Baxter, Q&A 15, and Q&A 16 of Mr. Baxter’s IRP Direct testimony, there are no
methodological changes to this forecast compared to Sierra’s 2nd Amendment forecast.
NAC 704.9281
Resource plan: Contents of data relating to peak demand and
energy consumption.
NAC 704.9281(1) requires that “the historical data relating to peak demand and energy
consumption submitted in a utility's resource plan must contain:
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(a) “The recorded and coincident peak demand, normalized for weather, in the summer
and winter for the total system for the 10-year period immediately preceding the year in which
the resource plan is filed.” See the Technical Appendix Item LF-1 (Sierra’s 30-Year Load
Forecast), Tables LF-3, LF-10, and LF-11 for historical actual and weather normalized peaks
back to 2003.
(b) “The recorded and annual sales of energy consumption, normalized for weather, for
the total system for each year of the 10-year period immediately preceding the year in which the
resource plan is filed.” See the Technical Appendix Item LF-1 (Sierra’s 30-Year Load Forecast),
Tables LF-1 and LF-2 for historical actual and weather normalized sales back to 2003.
(c) “The estimated losses of energy for the system for each year of the 10-year period
immediately preceding the year in which the resource plan is filed.” See the Technical Appendix
Item LF-1 (Sierra’s 30-Year Load Forecast), Table LF-1 for historical losses back to 2003.
(d) “The estimated or actual amount of electric energy used by the utility in the operation
of its business for each year of the 10-year period immediately preceding the year in which the
resource plan is filed.” See the Technical Appendix Item LF-1 (Sierra’s 30-Year Load Forecast),
Table LF-1 for the historical energy used by the Company (“company use”) back to 2003.
NAC 704.9281(2) requires that “the data on energy consumption and peak demands must
include data on all consumption and demands of ultimate customers that reflect firm, contractual
commitments.” The data used to prepare the forecast include only ultimate customers and reflect
firm, contractual commitments. Distribution-only customers and control area wholesale sales are
not included in the system forecast.
NAC 704.9321 Reliability of assumptions, forecasts, conclusions and information;
adjustments to forecasts; maps of covered areas; supportive testimony.
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NAC 704.9321(1) requires that, “to the extent consistent with cost-effective procedures
generally accepted by the industry, all assumptions, forecasts, conclusions and information used
by a utility in its resource plan must be: (a) Based on substantially accurate data; (b) Adequately
demonstrated and defended; and (c) Adequately documented and justified.” The assumptions,
forecasts, conclusions and information used in this Resource Plan meet these requirements.
NAC 704.9321(2) requires that “adjustments to forecasts obtained from external or
published sources that are made on the basis of factors specifically relating to the utility must be
explained.” These adjustments were applied to the coal price forecast provided by the John T.
Boyd Company and to the natural gas and power price forecasts provided by Wood Mackenzie
Limited based on information provided by NERA Economic Consulting.
NAC 704.9321(3) requires that “each utility shall provide a suitable map or maps to
show all areas covered by the resource plan. Each such map must show at least:
(a) “The service territory covered by the resource plan.” See Summary Volume, Figure
S-1.
(b) “The locations of the utility's facilities for generation of electric energy.” See Supply
Side Plan, Economic Analysis, and Financial Plan Volume, Section 2.E. (Transmission Plan),
Figure TP-22.
(c) “The location of renewable resources, independent power producers and distributed
generation that are located within the service territory of the utility and are under contract with
the utility.” See Supply Side Plan, Economic Analysis, and Financial Plan Volume, Section 2.D.
(Renewable Energy Plan), Figure REN-1.
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(d) “The interconnections with other utilities and independent power producers.” See
Supply Side Plan, Economic Analysis, and Financial Plan Volume, Section 2.E. (Transmission
Plan), Figures TP-21 and TP-22.
(e) “The utility's facilities for transmission of electric energy.” See Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 2.E. (Transmission Plan), Figures TP­
21 and TP-22.
NAC 704.9321(4) requires that “all testimony offered in support of the resource plan
must be filed with the resource plan.” All of the testimony offered in support of the 2013
Resource Plan is filed with the 2013 Resource Plan.
NAC 704.934 Preparation, contents and submission of demand side plan; annual
filing of analyses regarding conservation and demand management programs.
NAC 704.934(1) requires that “as part of its resource plan, a utility shall submit a
demand side plan.” See the Demand Side Plan volumes.
NAC 704.934(2) requires that “the demand side plan must include:
(a) “An identification of end-uses for programs for conservation and demand
management.” See Demand Side Plan volume, Section 3 (The 2014-2016 Demand Side Plan);
Exhibit A.
(b) “An assessment of savings attributable to technically feasible programs for
conservation and demand management, as determined by the utility. The programs must be
ranked in a list according to the level of savings in energy or reduction in demand, or both.” See
Demand Side Plan volume, Section 3 (The 2014-2016 Demand Side Plan); Exhibit A.
(c) “An assessment of technically feasible programs to determine which will produce
benefits in peak demand or energy consumption. The utility shall estimate the cost of each such
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program. The methods used for the assessment must be stated in detail, specifically listing the
data and assumptions considered in the assessment.” See Demand Side Plan volume, Section 3
(The 2014-2016 Demand Side Plan); Exhibit A.
NAC 704.934(3) requires that “in creating its demand side plan, a utility shall consider
the impact of applicable new technologies on current and future demand side options. The
consideration of new technologies must include, without limitation, consideration of the potential
impact of advances in digital technology and computer information systems.” See Demand Side
Plan volume, Section 3 (The 2014-2016 Demand Side Plan).
NAC 704.934(4) requires that “the demand side plan must provide a list of the programs
for which the utility is requesting the approval of the Commission.” See Summary Volume,
Section VII (A Summary of the Activities, Acquisitions and Costs Included in the Action Plan of
the Utility), Demand Side Programs; Demand Side Plan Volume, Section 1 (Overview and
Compliance Items) and Table DS-1. The list must include:
(a) “An estimate of the reduction in the peak demand and energy consumption that would
result from each proposed program, in kilowatt-hours and kilowatts saved. The programs must
be listed according to their expected savings and their contribution to a reduction in peak demand
and energy consumption based upon realistic estimates of the penetration of the market and the
average life of the programs.” See Demand Side Plan Volume, Tables DS-9, DS-13, DS-14, DS­
22, DS-23, DS-28 and DS-29.
(b) “An assessment of the costs of each proposed program and the savings produced by
the program. If the program can be relied upon to reduce peak demand on a firm basis, the
assessment must include the savings in the costs of transmission and distribution.” See Demand
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Side Plan Volume, Sections 1 (Overview and Compliance Items) and 3 (The 2014-2016 Demand
Side Plan); Exhibit A.
(c) “An assessment of the impact on the utility's load shapes of each proposed and
existing program for conservation and demand management.” See Demand Side Plan Volume,
Section 3 (The 2014-2016 Demand Side Plan); Exhibit A.
(d) “If a program is an educational program, the projected expenses of the utility for the
educational program.” See Demand Side Plan Volume, Exhibit A.
NAC 704.934(5) requires that “the utility shall include with its demand side plan a report
on the status of all programs for conservation and demand management that have been approved
by the Commission. The report must include tables for each such program showing, for each
year, the planned and achieved reduction in kilowatt-hours, the reduction in kilowatts and the
cost of the program.” See Demand Side Plan Volume, Section 3 (Program Year 2012 and Prior
Year Results); Tables DS-3, DS-4, DS-5 and DS-7; Exhibit A.
NAC 704.9355 Analyses of options for supply
NAC 704.9355(1) requires that “a utility shall develop a set of analyses of its options for
supply to be considered for meeting the expected future demand on its system. These analyses
must include an examination of the environmental impact of each option, taking into account the
best available technologies and the environmental benefit of renewable resources. The options to
be analyzed must include:
(a) “Construction of new generation facilities or upgrades to existing generation facilities,
including retrofitting existing facilities with more efficient systems or converting to other fuels.”
See Supply Side Plan, Economic Analysis, and Financial Plan Volume, section 2.A. and 2.D.
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All environmental externalities were evaluated based on the output of the production cost
modeling (see Technical Appendix Item ECON-17 (NERA Report)).
(b) “Construction of new transmission facilities or upgrades to existing transmission
facilities.” See the Supply Side Plan, Economic Analysis and Financial Plan volume, Section
2.E. (Transmission Plan).
(c) “Purchase of long-term transmission rights on transmission facilities owned by other
persons.” See the Supply Side Plan, Economic Analysis and Financial Plan volume, Section 2.E.
(Transmission Plan); see also Supply Side Plan, Economic Analysis and Financial Plan volume,
Section 3. (Economic Analysis)
(d) “Improvements in the efficiency of operations and scheduling, including, without
limitation, improvements that are attributable to the proposed implementation of new digital and
computer information system technologies.” See the Demand Side Plan Volume, Section 3.
(Impact of New Technology and Computer Information Systems)
(e) “Options of low carbon intensity.” See, Supply Side Plan, Economic Analysis and
Financial Plan Volume, Section 3.G (Low Carbon Intensity Plan).
(f) “Transactions with other utilities, independent producers and utility customers for:
(1) “Pooling of power.” See EIM discussed in Supply Side Plan, Economic
Analysis and Financial Plan volume, Section E.4.
(2) “Purchases of power.” Existing purchases and PPAs are described in Supply
Side Plan, Economic Analysis and Financial Plan volume, Section 2.B. (Power Purchase
and Portfolio Credit Agreements); see also the Supply Side Plan, Economic Analysis, and
Financial Plan Volume, Sections 3. (Economic Analysis); and Technical Appendix Item
CON-1 (Existing Power Agreements).
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(3) “Exchanges of power.” See the Supply Side Plan, Economic Analysis, and
Financial Plan volume, Sections 3. (Economic Analysis).
NAC 704.9357 Analysis of net economic benefits to State.
NAC 704.9357(1) requires that “an analysis of the changes that result in net economic
benefits to Nevada from electricity-producing or electricity-saving resources must be conducted
by the utility in selecting a resource option. The net economic benefit to the State must be
quantified to reflect both the positive and negative changes and must include the net economic
impact of renewable resources. The projected present worth of societal cost of a competing
resource plan must be within 10 percent of the lowest societal costs plan before proceeding with
an analysis of the economic benefits to Nevada.” See Technical Appendix Item ECON-17
(NERA Report).
NAC 704.9357(2) requires that “the economic benefits analysis must be achieved by
calculating the portion of the present worth of future requirements for revenue that is expended
within the State, including the following for both the construction and operation phases of any
project:
(a) “Capital expenditures for land and facilities located within the State or equipment
manufactured in the State.” See Technical Appendix Item ECON-17 (NERA Report).
(b) “The portion of the cost of materials, supplies and fuel purchased in the State.” See
Technical Appendix Item ECON-17 (NERA Report).
(c) “Wages paid for work done within the State.” See Technical Appendix Item ECON­
17 (NERA Report).
(d) “Taxes and fees paid to the State or subdivisions thereof.” See Technical Appendix
Item ECON-17 (NERA Report).
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(e) “Fees paid for services performed within the State.” See Technical Appendix Item
ECON-17 (NERA Report).
NAC 704.9357(3) requires that “in the analysis, the utility shall consider only the net
benefit added to the economy of the State of that portion of expenditures made within the State.”
See Technical Appendix Item ECON-17 (NERA Report).
NAC 704.9359, Determination of environmental costs to State, requires that “the
environmental costs to the State associated with operating and maintaining a supply plan or
demand side plan must be quantified for air emissions, water and land use. Environmental costs
are those costs, wherever they may occur, that result from harm or risks of harm to the
environment after the application of all mitigation measures required by existing environmental
regulation or otherwise included in the resource plan.” See Technical Appendix Item ECON-17
(NERA Report).
NAC 704.9361, Elimination or modification of environmental factors, emission rates
and environmental costs, states that “the emission rates and environmental costs set or
otherwise authorized by the Commission may be subject to elimination or modification, and new
factors may be added for consideration, as new scientific, engineering, economic or other
technical information becomes available to the Commission. Information purporting to establish
a need for the deletion or addition of any environmental factor or the revision of any authorized
emission rates or environmental costs may be presented by any party at the time of a hearing on
the utility's resource plan.” The Company is not claiming a need for the deletion or addition of
any environmental factor or the revision of any authorized emission rates or environmental costs.
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NAC 704.937 List of options for supply of capacity and electric energy; criteria for
selection of options; comparison of and requirements for alternative plans; identification of
preferred plan.
NAC 704.937(1) requires that “a utility's supply plan must contain a diverse set of
alternative plans which include a list of options for the supply of capacity and electric energy that
includes a description of all existing and planned facilities for generation and transmission,
existing and planned power purchases, and other resources available as options to the utility for
the future supply of electric energy. The description must include the expected capacity of the
facilities and resources for each year of the supply plan. At least one alternative plan must be of
low carbon intensity and include: (a) The generation of acquisition of an amount of renewable
energy greater than required by NRS 704.7821; (b) Changes to the utility’s existing fleet of
resources for the generation of power; (c) The application of technology that would significantly
reduce emissions of carbon; or (d) Any combination thereof.” Existing resources are described
in the Supply Side Plan, Economic Analysis, and Financial Plan Volume, Sections 2.A.1.
(Existing and Previously Approved Generation), 2.B. (Power Purchase and Portfolio Energy
Credit Agreements), and 2.C. (Fuel Supply). Planned facilities are described in the Supply Side
Plan, Economic Analysis, and Financial Plan Volume, Sections 2.A.3. (Proposed Projects) and
2.E. (Transmission Plan).
Existing and planned purchases also are included in Technical
Appendix Item CON-1 (Power Purchase and Portfolio Credit Agreements). A description of the
list of options and criteria for the supply of capacity and electric energy is provided in the Supply
Side Plan, Economic Analysis, and Financial Plan volume, Section 3.A. (Summary), Section
3.B.2. (List of Alternative Plans), and Figures EA-4 through EA-6. Generation options, capital
costs and performance summaries are also described in the Supply Side Plan, Economic
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Analysis, and Financial Plan Volume, Section 3.B. (Analysis Methodology) and Technical
Appendix Items GEN-3 (New Generation Units –Performance Data) and GEN-4 (Construction
Cost and Schedule Data). The expected capacity of the facilities and resources for each year
analyzed in the supply plan are included in the loads and resources tables found in Technical
Appendix Items ECON-7 through ECON-12 (Economic Analysis).
NAC 704.937(2) requires that “a utility shall identify the criteria it has used for the
selection of its options for meeting the expected future demands for electric energy and shall
explain how any conflicts among criteria are resolved.” The criteria are described in the Supply
Side Plan, Economic Analysis, and Financial Plan Volume, Sections 3.A. (Summary) and 3.B.2
(List of Alternative Plans).
NAC 704.937(3) requires that “in comparing alternative plans containing different
resource options, the utility shall calculate the present worth of future requirements for revenue
for each alternative plan for the supply of power. A comparison of the present worth of future
requirements for revenue for each alternative plan must be presented in the resource plan. As
calculated pursuant to this subsection, the present worth of future revenue requirements for
revenue for each alternative plan must include, without limitation, a reasonable range of costs
associated with emissions of carbon in the 20-year period of the resource plan as private costs to
the utility.” See Technical Appendix Item ECON-15 (Present Worth Revenue Requirements).
NAC 704.937(4) requires that “the utility shall calculate the present worth of societal
costs for each alternative plan for the supply of power. The present worth of societal costs of a
particular alternative plan must be determined by adding the environmental costs that are not
internalized as private costs to the utility pursuant to subsection 3 to the present worth of future
requirements for revenue.” The present worth of societal costs for each alternative plan is
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summarized in the Supply Side Plan, Economic Analysis, and Financial Plan volume, Section
3.H. (Environmental Externalities and Economic Benefits to the State) and Technical Appendix
Item ECON-17 (NERA Report).
NAC 704.937(5) requires that “the utility shall consider for each alternative plan the
mitigation of risk by means of: (a) Flexibility; (b) Diversity; (c) Reduced size of commitments;
(d) Choice of projects that can be completed in short periods; (e) Displacement of fuel; (f)
Reliability; (g) Selection of fuel and energy supply portfolios; and (h) Financial instruments or
electricity products.” These items were considered for each alternative plan. See the Supply
Side Plan, Economic Analysis, and Financial Plan volume, Section 3 (Economic Analysis).
NAC 704.937(6) requires that “the alternative plans of the utility must: (a) Provide
adequate reliability; (b) Be within regulatory and financial constraints; (c) Meet the portfolio
standard; and (d) Meet the requirements for environmental protection.” The alternative plans
meet the above requirements. See the Supply Side Plan, Economic Analysis, and Financial Plan
Volume, Section 3 (Economic Analysis).
NAC 704.937(7) states that, “the utility shall identify its preferred plan and fully justify
its choice by setting forth the criteria that influenced the utility's choice.” The selection of the
Preferred Plan is described in the Supply Side Plan, Economic Analysis, and Financial Plan
volume, Section 3.D. (Selection of Preferred and Alternative Plans).
NAC 704.9378, Time-line graphs for proposed resources for supply, states that the
supply plan must contain time-line graphs for the utility's proposed resources for supply that
include major activities, milestones and points of decision. The following subjects must be
included in the time-line graphs for each proposed resource: (1) Preparation of any required
environmental impact statements; (2) Applications for significant permits; (3) Commitments of
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significant expenditures; (4) Periods for construction; and (5) The commercial operation date.
See the Technical Appendix Item SS-1 (Time-Line Graphs for Proposed Supply Resources).
NAC 704.9385
Contents; tables; transmission plan; information regarding
purchase of power; maps.
NAC 704.9385(1) requires that “the supply plan of the utility must develop and
document the origins of:
(a) “The assumptions, data and projections used by the utility to calculate the costs and
benefits of its options.” See Technical Appendix Items LF-1 (Sierra’s 30-Year Load Forecast),
F&PP-1 and F&PP-2 (Fuel and Purchased Power Price Forecasts), GEN -1 (Unit Characteristics
Table), GEN-3 (New Generation Units – Performance Data), GEN-4 (New Generation Units –
Construction Cost and Schedule Data), GEN-5 (Generating Plant Emission Rates, ECON-17
(NERA Report), and REN-7 (Renewable Generic Buildout).
(b) “The assessment of current and anticipated electric market conditions by the utility
for the region in which the utility operates.” See Load Forecast and Market Fundamentals
Volume, Section 2 (Market Fundamentals).
(c) “The basic economic and financial limitations of the utility.” See the Supply Side
Plan, Economic Analysis, and Financial Plan Volume, Section 4 (Financial Plan).
(d) “The assumptions used by the utility for developing the environmental costs and the
net economic benefits to the State from each of the options of the utility for future supply.” See
Technical Appendix Item ECON-17 (NERA Report).
(e) “The criteria used by the utility for determining the reserve margin.” See the Supply
Side Plan, Economic Analysis, and Financial Plan Volume, Section 3.E.
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(f) “The assumptions used by the utility for renewable resources.”
See Technical
Appendix Item REN-7 (Renewable Generic Buildout).
(g)
“The assumptions used by the utility for independent power producers.”
See
Technical Appendix Items F&PP-1 and F&PP-2 (Fuel & Purchased Power Forecasts).
(h)
“The assumptions used by the utility for the reduction in demand and energy
requirements associated with customers exiting service from the utility and customers utilizing
distributed generation resources.” No customers of Sierra have expressed an interest in leaving
the system under Nevada’s retail open access statute (AB 661 or SB 211, 2001 Nevada
Legislature).
NAC 704.9385(2) requires that “regarding generation, a utility's supply plan must contain
a table of all its existing and planned facilities for electric generation that it expects to be
operating in each of the 20 years covered by its forecast.” See the Loads and Resources tables
that are provided in the Supply Side Plan, Economic Analysis, and Financial Plan Volume,
Section 3.E (Loads and Resources Tables), Figures LR-1A through LREA-1D, and Technical
Appendix Items ECON-7 through ECON-12 (Economic Analysis).
NAC 704.9385(2) also states, “Each of the following items of information must be set
forth in the table if applicable to a listed facility.”
(a) “The planned or actual commercial operation date of the facility.” See the Supply
Side Plan, Economic Analysis, and Financial Plan Volume, Sections 2.A.1. (Summary) and 3.E.
(Loads and Resources Tables); see also Technical Appendix Items ECON-7 through ECON-12.
(b) “The date of the planned retirement of the facility, including the criteria used to
select that date.” See the Supply Side Plan, Economic Analysis, and Financial Plan Volume,
Section 3 (Economic Analysis) and Technical Appendix Items ECON-7 through ECON-12.
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(c) “The type of facility.” See the Supply Side Plan, Economic Analysis, and Financial
Plan Volume, Section 3 (Economic Analysis) and Technical Appendix Items ECON-7 through
ECON-12
(d) “The rated generating capacity and net expected generating capacity of the facility.”
See the Supply Side Plan, Economic Analysis, and Financial Plan Volume, Section 3 (Economic
Analysis) and Technical Appendix Items ECON-7 through ECON-12..
(e) “The fuel used.” See the Supply Side Plan, Economic Analysis, and Financial Plan
Volume, Section 3 (Economic Analysis) and Technical Appendix Items ECON-7 through
ECON-12.
(f) “The capacity of the facility for storing fuel.” See Supply Side Plan, Economic
Analysis, and Financial Plan volume, Section 2.C. (Fuel Supply).
(g) “The designation of the capacity type of the facility, such as base load, intermediate
or peaking.” See the Supply Side Plan, Economic Analysis, and Financial Plan Volume, Section
3 (Economic Analysis) and Technical Appendix Items ECON-7 through ECON-12.
NAC 704.9385(3) requires that “the supply plan of a utility must include a transmission
plan for the 20 years covered by the forecast in the supply plan.” See the Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 2.E. (Transmission Plan).
The
transmission plan must include, without limitation:
(a) “A summary of the capabilities of the transmission system, including import, export
and the rating of significant transmission paths within the system of the utility, and of the
existing and planned transmission system of the utility for each year in the period covered by the
resource plan.” See Supply Side Plan, Economic Analysis, and Financial Plan Volume, Sections
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2.F.9. (Sierra Transmission System Overview), 2.F.10. (Transmission Path Ratings), 2.F.11.
(Import Capability), and 2.F.12. (Export Capability).
(b) “A description of the transmission projects the utility is considering for expanding or
upgrading the capabilities of its transmission system, the anticipated timing of those projects and
the impact of the projects on the transmission capabilities of the existing and planned
transmission system of the utility.” See Supply Side Plan, Economic Analysis, and Financial
Plan Volume, Section 2.F.6. (Specific Requests for Commission Approval).
(c)
“Identification of the transmission capacity required to serve bundled retail
transmission customers, unbundled retail transmission customers and those wholesale
transmission customers for whom the utility has an obligation to provide transmission services,
for annual and peaking periods throughout the period covered by the resource plan.” See the
Supply Side Plan, Economic Analysis, and Financial Plan Volume, Sections 2.F.14. (Sierra’s
Transmission Service Obligations) and 3.E. (Loads and Resources Tables).
(d) “Identification of all existing and proposed transmission service agreements, and
their expiration dates, with transmission customers for transmission service on the transmission
system of the utility and the impact of these agreements on available capacity for bundled retail
transmission customers on the proposed or existing transmission facilities.” See Supply Side
Plan, Economic Analysis, and Financial Plan Volume, Section 2.F.14. (Sierra’s Transmission
Service Obligations).
(e) “A table identifying all the transmission capacity that the utility has secured for its
bundled retail transmission customers on both its transmission system and the transmission
systems of other entities.”
See Supply Side Plan, Economic Analysis, and Financial Plan
Volume, Section 2.F.14. (Sierra’s Transmission Service Obligations), Figures TP-26 and TP-27.
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(f) “A description of the participation of the utility in regional planning organizations
and an explanation of the role of those organizations in the transmission planning process of the
utility.” See Supply Side Plan, Economic Analysis, and Financial Plan Volume, Section 2.F.5.
(WestConnect).
(g) “A summary of the impacts of relevant orders of the Federal Energy Regulatory
Commission issued since the utility filed its last resource plan.”
See Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 2.F.16. (Regional and Federal
Regulatory Issues).
(h) “A demonstration that the utility has attempted to reduce the impact of line losses
upon its future resource requirements.” See Supply Side Plan, Economic Analysis, and Financial
Plan Volume, Section 2.F.15. (Transmission Losses).
NAC 704.9385(4) requires, “regarding the purchase of power, the supply plan must
contain a list showing:
(a) “All sources from which the utility has contracted to buy, or has plans or potential
opportunities to buy, electric power during the 20 years covered by the supply plan.” See the
Supply Side, Economic Analysis, and Financial Plan Volume, Section 2.B. (Power Purchase &
Portfolio Energy Credit Agreements), and Load Forecast and Market Fundamentals Volume,
Section 2.A. (Power Fundamentals).
(b) “The amount of electric power that the utility has contracted to buy, or has plans or
potential opportunities to buy, from each source and the years for which delivery of the electric
power is contracted or planned.” See the Supply Side, Economic Analysis, and Financial Plan
Volume, Sections 2.B. (Power Purchase & Portfolio Energy Credit Agreements) and 3.B.2. (List
of Alternative Plans).
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NAC 704.9385(5) requires that “the utility shall include in its supply plan a map or maps
that identify the location of each existing or planned generation or transmission facility,
renewable energy system and independent power producer that are projected to be relied upon
during the period covered by the action plan.” See the Supply Side Plan, Economic Analysis,
and Financial Plan Volume, Figures REN-1, TP-22 and TP-23.
NAC 704.9385(6) states, “In addition to the transmission plan required by subsection 3,
the supply plan of a utility must include, as a discrete but integrated item in the supply plan, a
conceptual renewable energy zone transmission plan for the 20 years covered by the forecast in
Supply Plan. The renewable energy zone transmission plan must include distinct conceptual
transmission plans, which may include capacity for export to other states, for serving each of the
renewable energy zones designated by the Commission pursuant to section 1 of LCB File No.
R146-09, which was adopted by the Commission and filed with the Secretary of State on January
28, 2010. Each of the distinct conceptual transmission plans must include:
(a)
“A description of the construction or expansion of transmission facilities required
to be added to the utility’s existing transmission system.” See the Supply Side Plan, Economic
Analysis, and Financial Plan Volume, Section 2.E.17. (Renewable Energy Zone Transmission
Plan) and Appendix Item TRAN-10 (Renewable Energy Zone Transmission Plan).
(b)
“An estimate of cost at the planning level, including, without limitation, estimates
for permitting and other expenses of transmission development and estimated development
schedules for the transmission facilities included in the transmission plan, based on information
known by the utility at the time the transmission plan is submitted to the Commission.” See the
Supply Side Plan, Economic Analysis, and Financial Plan Volume, Section 2.E.17. (Renewable
Energy Zone Transmission Plan) and Appendix Item TRAN-10 (Renewable Energy Zone
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Transmission Plan).
(c)
“A description of any restrictions or limitations on the construction or expansion
of transmission facilities, including, without limitation, generator tie-lines in the applicable
transmission plan due to any local topographical, environmental, governmental, land use or other
factors or limitations that are known by the utility at the time the transmission plan is submitted.”
See the Supply Side Plan, Economic Analysis, and Financial Plan Volume, Section 2.E.17.
(Renewable Energy Zone Transmission Plan) and Appendix Item TRAN-10 (Renewable Energy
Zone Transmission Plan).
(d)
“An estimate of the capacity of the renewable energy resources capable of being
developed in the applicable zone, based on information that is known to the utility at the time the
transmission plan is submitted to the Commission.” See the Supply Side Plan, Economic
Analysis, and Financial Plan Volume, Section 2.E.17. (Renewable Energy Zone Transmission
Plan) and Appendix Item TRAN-10 (Renewable Energy Zone Transmission Plan).
NAC 704.9489.5 states, “The action plan must include a renewable energy zone
transmission action plan for serving one or more of the renewable energy zones designated by
the Commission or an explanation of why no renewable energy zone transmission action plan is
contained in the action plan.” The Action Plan does not include a renewable energy zone
transmission Action Plan because, as is stated in the conceptual Renewable Energy Zone
Transmission Plan, the Company is not proposing to construct any of the facilities described in
the plan during the Action Plan period. See Technical Appendix Item TRAN-10, page 1.
NAC
704.9395,
Resource
plan:
Information
on
financial
and
economic
characteristics of planned facilities, requires a utility's resource plan to contain information on
the financial and economic characteristics of planned facilities. The information must include:
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(1) “The estimated costs of construction, including:
(a) “Annual flows of expenditures with allowance for money expended during
construction.” See Technical Appendix Item ECON-14(Capital Expense Recovery).
(b) “Annual flows of expenditures without allowance for money expended during
construction.” See Technical Appendix Item ECON-14(Capital Expense Recovery).
(2) The estimated costs of operation, including:
(a) “Variable costs per kilowatt-hour, with expenses for fuel and other items
indicated separately.” See Technical Appendix Item GEN-1 (Unit Characteristics Table);
see also discussion in Supply Side Plan, Economic Analysis and Financial Plan Volume,
Sections 2.A.1 (Existing and Previously Approved Generation), and 3.B. (Analysis
Methodology).
(b) “Fixed costs per kilowatt-hour.” See Technical Appendix Item GEN-1 (Unit
Characteristics Table); see also discussion in Supply Side Plan, Economic Analysis and
Financial Plan Volume, Sections 2.A.1 (Existing and Previously Approved Generation)
and 3.B. (Analysis Methodology).
(3) “Net environmental costs and net economic benefits to the State.” See Technical
Appendix Item ECON-17 (NERA Report).
(4) The rates of escalation of cost, including:
(a) “Capital costs.”
See Supply Side Plan, Economic Analysis, and
Financial Plan Volume, Section 4.F (Common Methodologies / Assumptions) and Figure
FP-6.
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(b) “Variable fuel costs(a) “Capital costs.”
See Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 4.F. (Common Methodologies /
Assumptions) and Figure FP-6.
(c) “Nonfuel operating costs.” (a) “Capital costs.” See Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 4.F. (Common Methodologies /
Assumptions) and Figure FP-6.
(d) “Environmental costs.”
See Technical Appendix Item ECON-17
(NERA Report).
(e) “Fixed operating costs.” (a) “Capital costs.” See Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 4.F. (Common Methodologies /
Assumptions) and Figure FP-6.
(5) The average cost per kilowatt-hour at projected loads in current dollars for each year
of the plan for each existing and planned facility. See Technical Appendix Item ECON-3
(Average Generation Cost).
NAC 704.9401 Financial information and assumptions used to develop financial
plan
NAC 704.9401(1) requires that “the assumptions and methodologies for modeling used
to develop the utility's financial plan must be described in the resource plan of the utility. The
following estimated financial information for the preferred plan must be included in the financial
plan: (a) Present worth of revenue requirements; (b) Nominal revenue requirements by year; (c)
Average system rates per kilowatt-hour by year; (d) Total rate base by year; (e) Financial results
attributed to the risk management strategy of the utility.” This information is provided in the
Supply Side Plan, Economic Analysis, and Financial Plan Volume, Sections 3 (Economic
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Analysis) and 4 (Financial Plan). The nominal revenue requirements by year are provided in
Figure FP-5. The average system rates per kilowatt-hour by year are provided in Figure FP-7.
The total rate base by year is provided in Figure FP-4. The financial results attributed to the risk
management strategy of the utility are discussed in Section 4.G. (Risk Management Strategy).
NAC 704.9401(2) requires that “the financial assumptions used by the utility to develop
its supply plan must be stated in the financial plan. The following items must be stated for each
year in the financial plan: (a) The general rate of inflation; (b) The AFUDC rates used in the
supply plan; (c) The cost of capital rates used in the supply plan; (d) The discount rates used in
the calculations to determine present worth; (e) The tax rates used in the supply plan; (f) Other
assumptions used in the supply plan.” This information is provided in the Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 4.F. (Common Methodologies /
Assumptions).
NAC 704.944 Supply plan: Discussion of alternative strategies, requires that “a utility
shall include in its supply plan a comprehensive discussion of the alternative strategies that the
utility would pursue if any preferred resource or facility were not available as described in the
supply plan.” See Supply Side Plan, Economic Analysis, and Financial Plan volume, Section
3.D. (Selection of Preferred and Alternative Plans).
NAC 704.945 Resource Plan: Inclusion of certain tables and graphs
NAC 704.945(1) requires that “a utility shall include in its resource plan a table of loads
and resources for each supply plan analyzed. The table must include the following data for each
year of the resource plan:
(a) The capacity provided by each supply resource;
(b) The total expected capacity of all resources;
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(c) The forecasted peak demand;
(d) The estimated impact of new programs for conservation and demand management;
(e) The expected capacity and energy provided by renewable resources, categorized by
type;
(f) The required planning reserves;
(g) The total capacity required;
(h) The excess or deficiency of capacity without additional resources; and
(i) The excess or deficiency of capacity with additional planned resources.”
See Supply Side Plan, Economic Analysis, and Financial Plan Volume, Section 3.E.
(Loads and Resources Tables), Figures LR-1A through LR-1D.
NAC 704.945(2) requires that a graph be included for the preferred plan of the utility
showing, over the 20-year planning period, showing:
(a) The total resources requirements;
(b) The total demand without new programs for conservation and demand management;
(c) The total demand with new programs for conservation and demand management;
(d) The total capacity with additional planned resources; and
(e) The total capacity without additional resources.”
See the Supply Side Plan, Economic Analysis, and Financial Plan Volume, Figures EA­
25 and EA-27.
NAC 704.945(3) requires “a graph must be included for the preferred plan that shows, for
each year of the 20-year planning period, the excess or required capacity both with and without
the additional planned resources.” See the Supply Side Plan, Economic Analysis, and Financial
Plan Volume, Figures EA-25 and EA-27.
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NAC 704.945(4) requires “a graph or table must be provided that shows the allocation of
the capacity of the transmission system of the utility between bundled retail transmission
customers, unbundled retail transmission customers and wholesale transmission customers.” See
Supply Side Plan, Economic Analysis, and Financial Plan Volume, Figures TP-26 and TP-27.
NAC 704.9465
Integrated analysis to establish priorities among options;
consideration of results as basis for preferred plan.
NAC 704.9465(1) requires “the utility shall perform an analysis integrating: (a) Planning
based on demand; (b) Planning based on supply; (c) Financial planning; and (d) Planning to meet
other applicable regulatory constraints.”
See Supply Side Plan, Economic Analysis, and
Financial Plan Volume, Section 3 (Economic Analysis and the Selection of the Preferred and
Alternative Plans).
NAC 704.9465(2) states that “the primary function of the integrated analysis is to
establish priorities among the utility's options for demand and supply so that the utility can
demonstrate the minimum costs of providing electric energy to its customers.” See the Supply
Side Plan, Economic Analysis, and Financial Plan Volume, Section 3.C. (Economic Analysis
Results).
NAC 704.9465(3) requires that “the utility shall consider the results of the integrated
analysis as a basis for its preferred plan along with the other selection criteria set forth in NAC
704.937.” See the Supply Side Plan, Economic Analysis, and Financial Plan Volume, Section
3.D. (Selection of Preferred and Alternative Plans).
NAC 704.9475 Analysis of sensitivity for major assumptions and estimates used in
resource plan.
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NAC 704.9475(1) requires that “a utility shall conduct an analysis of sensitivity for all
major assumptions and estimates used in its resource plan. The analysis must include the:
(a) “Forecast of peak demand and energy consumption.” Low, base, and high load
forecasts were prepared and analyzed. See the Supply Side Plan, Economic Analysis, and
Financial Plan Volume, Section 3.B.3. (Scenario Analyses).
(b)
“Dates when proposed acquisitions will be in service.”
See the Supply Side,
Economic Analysis and Financial Plan volume, Section 3.B.2. (List of Alternative Plans).
(c) “Unit availability.” See Technical Appendix Items ECON-4 (Unit Forced Outage
Rates) and ECON-5 (Unit Scheduled Maintenance).
(d) “Costs of power plants.” See Supply Side Plan, Economic Analysis, and Financial
Plan Volume, Section 3.B.1 (New Generation Capital Costs and Characteristics).
(e) “Prices of fuel.” See Supply Side Plan, Economic Analysis, and Financial Plan
Volume, Section 3.B.3. (Scenario Analyses) and Technical Appendix F&PP-1 and F&PP-2.
(f) “Amounts of purchased power and corresponding costs.” See Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 3.B.3. (Scenario Analyses).
(g) “Schedule, impact and costs of programs for conservation and demand management.”
Three DSM forecasts were prepared and analyzed. The program data sheets provided for each
program proposed in the DSM plan include a Preferred Plan, a Minimum Impact Alternative
Plan and a Maximum Net Benefits Alternative Plan. The program data sheets are presented in
the Demand Side Plan volume, Exhibit A; see also Technical Appendix Item LF-1 (Sierra’s 30­
Year Load Forecast).
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(h) “Capacity of plants in megawatts.” See the Supply Side Plan, Economic Analysis,
and Financial Plan Volume, Section 2.A.1. (Existing and Previously Approved Generation),
Figure GEN-1.
(i) “Discount rates.” See the Supply Side Plan, Economic Analysis, and Financial Plan
Volume, Section 4.F.(Common Methodologies / Assumptions).
(j) “Rate of inflation.” See the Supply Side Plan, Economic Analysis, and Financial Plan
Volume, Section 4.F.(Common Methodologies / Assumptions).
(k) “Cost of capital.” See the Supply Side Plan, Economic Analysis, and Financial Plan
Volume, Section 4.F.(Common Methodologies / Assumptions).
(l)
“Environmental costs.”
Low, mid, and high carbon cases were prepared and
analyzed. See Technical Appendix Item ECON-17 (NERA Report) and the Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 3.B.3. (Scenario Analyses).
(m) “Economic benefit.”
See the Supply Side Plan, Economic Analysis, and Financial
Plan Volume, Section 3.C. (Economic Analysis Results).
NAC 704.9475(2) requires that “the utility shall state the ranges and consequences of
uncertainty for each of the assumptions and describe methods of combining various
uncertainties.” See Technical Appendix Items ECON-7 through ECON-12 which provide the
Loads and Resources tables under different cases.
NAC 704.948 Analysis of decisions
NAC 704.948(1) requires that “a utility shall analyze its decisions, taking into account its
assessment of risk and identifying particular risks with respect to: (a) Costs; (b) Reliability; (c)
Finances; (d) The volatility of the price of purchased power and fuel; and (e) Any other
45
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uncertainties the utility has identified.” See Supply Side Plan, Economic Analysis, and Financial
Plan Volume, Section 3.D. (Selection of Preferred and Alternative Plans).
NAC 704.948(2) requires that “the utility's analysis must address the relationship among
the factors used in making the utility's decision, including the relationship between mitigating
risk, minimizing cost and volatility, and maximizing reliability.” See the Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 3.A. (Summary).
NAC 704.9484 Critical facility: Procedure and purpose for designation; financial
incentives
NAC 704.9484(1) states that “the Commission may, upon the request of a utility or an
intervening party pursuant to subsection 2 or upon its own motion, make a determination as to
whether to designate a facility of the utility as a critical facility. Such a determination may be
made in conjunction with an order issued by the Commission pursuant to subsection 1 of NAC
704.9494 or in another proceeding on the matter.” The Company is not requesting critical
facility designation of a facility in this filing.
NAC 704.9484(2) states that “a utility and any party granted intervener status may
request that the Commission designate a facility of the utility as a critical facility for the purpose
of: (a) Protecting reliability; (b) Promoting diversity of supply and demand side sources; (c)
Developing renewable energy resources; (d) Fulfilling specific statutory mandates; (e) Promoting
retail price stability; or (f) Any combination of paragraphs (a) to (e), inclusive. Such a request
must be accompanied by supporting analysis and documentation.”
The Company is not
requesting critical facility designation of a facility in this filing.
NAC 704.9484(3) states that “if the Commission designates a facility as a critical facility,
the utility may request that incentives associated with that facility be included in rates in an
46
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application to change general rates filed pursuant to NAC 703.2201 to 703.2481, inclusive. The
incentives may include, without limitation: (a) Earning an enhanced return on equity on the
designated critical facility over the life of the facility; (b) The inclusion in the rates of
construction work in progress associated with the designated facility; and (c) Designating costs
incurred to construct the designated critical facility in a regulatory asset account, to be recorded
as a subaccount to Account 182.3 (Other Regulatory Assets). The utility may recover the
regulatory asset pursuant to subsection 3 of NAC 704.9523.” The Company is not requesting
critical facility incentives in this filing.
NAC 704.9489 Requirements for Action Plan
NAC 704.9489(1) requires “resource plan of a utility must include a detailed action plan
based on an integrated analysis of the demand side plan and supply plan of the utility. In its
action plan, the utility shall specify all its actions that are to take place during the 3 years
commencing with the year following the year in which the resource plan is filed. The action plan
must contain:
(a) “An introductory section that explains how the action plan fits into the longer-term
strategic plan of the utility.” See Volume 2, Action Plan, Section I (Introduction).
(b) “A list of actions for which the utility is seeking the approval of the Commission.”
See Volume 2, Action Plan, Section II (List of Actions).
(c) “A schedule for the acquisition of data, including planned activities to update and
refine the quality of the data used in forecasting.” See Volume 2, Action Plan, Section III (Data
Acquisition).
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(d) “A specific timetable for acquisition of options for the supply of electric energy and
for programs for conservation and demand management.” See Volume 2, Action Plan, Sections
III (Data Acquisition) and IV (Timetable and Budget for Programs).
(e) “If changes in the methodology are being proposed, a description fully justifying the
proposed changes, including an analysis of the costs and benefits. Any changes in methodology
that are approved by the Commission must be maintained for the period described in the action
plan.” See Volume 2, Action Plan, Section V (Changes in Methodology).
(f)
“A section describing any plans of the utility to acquire additional modeling
instruments.”
See Volume 2, Action Plan, Section VI (Acquisition of New Modeling
Instruments).
(g) “A section for the utility's program for conservation and demand management,
including:
(1) “A description of continued planning efforts.” See Volume 2, Action Plan,
Section II (List of Actions).
(2) “A plan to carry out and continue selected measures for conservation and
demand management that have been identified as desirable.” See Volume 2, Action Plan,
Section II (List of Actions).
(3) “Any impacts of imputed debt calculations associated with energy efficiency
contracts in the preferred plan.” See Volume 2, Action Plan, Section VIII (Resources for
Supply).
(h) “A section for the utility's program for acquisition of resources for the supply of
electric energy for the period covered by the action plan, including:
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(1) “The immediate plans of the utility for construction of facilities or long-term
purchases of power.” See Volume 2, Action Plan, Section II (List of Actions).
(2) “The expected time for construction of facilities and acquisition of long-term
purchases of power identified in subparagraph (1).” See Volume 2, Action Plan, Section
II (List of Actions).
(3) “The major milestones of construction.” See Volume 2, Action Plan, Section
II (List of Actions).
(4) “Any impacts of imputed debt calculations associated with renewable energy
contracts or energy efficiency contracts in the preferred plan.” See Volume 2, Action
Plan, Section VIII (Resources for Supply).
NAC 704.9489(2) requires that “the action plan must contain an energy supply plan.”
See Volume 2 Action Plan, Section II (List of Actions), which describes the Energy Supply Plan
that is included in this filing. See also the Energy Supply Plan volume.
NAC 704.9489(3) requires that “the action plan must contain a budget for planned
expenditures suitable for comparing planned and achieved expenditures. Expenses must be
listed in a format that is consistent with the categories and periods to be presented in subsequent
filings.” See Volume 2, Action Plan, Section IV (Timetable and Budget for Programs), Figure
AP-07.
NAC 704.9489(4) requires “the action plan must contain schedules suitable for
comparing planned and actual activities and accomplishments. Milestones and points of decision
committing major expenditures must be shown.” See Volume 2, Action Plan, Section II (List of
Actions).
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NAC 704.9492 Rates for long-term avoided cost: Inclusion of certain information in
resource plan; estimation; specification of proposed limits concerning availability
NAC 704.9492(1) requires that “a utility shall file, as part of its resource plan, the
methodology for estimating the rates for long-term avoided cost of the utility, including the
capacity and energy components. The rates for long-term avoided cost must be based upon the
utility's preferred plan and be consistent with 18 C.F.R. § 292.304(a), (b), (c) and (e).” See
Supply Side Plan, Economic Analysis, and Financial Plan Volume, Section 3.I. (Long-Term
Avoided Costs Methodology).
NAC 704.9492(2) requires that “the estimated rate for long-term avoided cost must be
established for various sizes of megawatt blocks, except that: (a) If the utility has a peak demand
of at least 1,000 megawatts, the stated blocks must not exceed 100 megawatts; and (b) If the
utility has a peak demand of less than 1,000 megawatts, the stated blocks must not exceed 10
percent of the system peak.” Sierra has a peak demand of at least 1,000 megawatts, and the
stated blocks do not exceed 100 megawatts. See Supply Side Plan, Economic Analysis and
Financial Plan Volume, Section 3.I. (Long Term Avoided Costs Methodology).
NAC 704.9492(3) requires that “the components for estimated long-term avoided cost
capacity and energy rate must be stated on a cents per kilowatt-hour basis for daily and seasonal
peak and off-peak periods and in such a manner that rates for various contract periods may be
calculated. At a minimum, the utility shall provide estimated rates for long-term avoided cost for
a 20-year contract and the long-term avoided cost by year for 5 years commencing in the year
following the filing of the resource plan.” See Supply Side Plan, Economic Analysis and
Financial Plan Volume, Section 3.I. (Long Term Avoided Costs Methodology).
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NAC 704.9492(4) requires that “in developing the estimated rates for long-term avoided
cost, the proposed rates must not be applied to renewable energy or to energy that is subject to
the qualified energy recovery process as defined in NRS 704.7809.” The Company’s calculation
of the avoided cost rate as set forth in the Supply Side Plan, Economic Analysis and Financial
Plan Volume, Section 3.I. (Long Term Avoided Costs Methodology), is consistent with the
Commission’s regulation.
NAC 704.9492(5) requires that “the utility shall specify its proposed limits concerning
the availability of the rates for long-term avoided cost.” Sierra proposes that the availability of
long-term avoided cost rates be limited to a maximum of 25 MW of QF contracts. See Supply
Side Plan, Economic Analysis and Financial Plan Volume, Section 3.I. (Long Term Avoided
Costs Methodology).
NAC 704.9492(6) requires that “the resource plan of the utility must include the analyses
and calculations used to determine the proposed rates.” See Technical Appendix Item ECON-6
(Marginal Energy Cost).
NAC 704.9492(7) requires that “the resource plan must include a description of the
methodology that will be used to derive the rates for long-term avoided costs from the
solicitation of proposals performed pursuant to subsection 5 of NAC 704.9496.”
Sierra
calculated the long-term avoided cost based on the hourly marginal costs from a PROMOD
simulation for the preferred plan, which includes future potential carbon costs from the
Company’s mid-carbon case. During the July – September period, a capacity component is
added to the monthly average marginal energy costs, and is based in the market price forecast.
See Supply Side Plan, Economic Analysis and Financial Plan Volume, Section 3.I. (Long Term
Avoided Costs Methodology).
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NAC 704.9512 Submission to Commission of certain purchased power obligations;
disclosure of certain affiliate relationships
NAC 704.9512(1) requires that “the utility shall submit to the Commission a copy of: (a)
Each long-term purchased power obligation; and (b) Any other purchased power obligation for
which the utility is seeking the approval of the Commission, to which the utility is committed or
plans to become committed during the period covered by the action plan.” A listing of the
purchased power contracts can be found in Supply Side Plan, Economic Analysis, and Financial
Plan Volume, Section 2.B.(Power Purchase & Portfolio Energy Agreements) and Technical
Appendix CON 1 (Power Purchase and Portfolio Credit Agreements). See also Supply Side Plan,
Economic Analysis, and Financial Plan Volume, Section 2.D. (Renewable Energy Plan) for a
description of Ft. Churchill Solar Array Agreements.
NAC 704.9512(2) requires that “for any such contract that is not executed at the time the
action plan is filed, the utility shall submit the contract, upon execution, to the Commission for
review.
The utility shall, for each such contract, disclose the existence of any affiliate
relationship between the parties.” Not Applicable.
NAC 704.9514 Preapproval of certain fuel and purchased power agreements states
that “to the extent the Commission deems appropriate, the Commission may preapprove and
deem prudent fuel and purchased power agreements by a utility that are less than 3 years in
duration.” Sierra is not seeking preapproval of any purchased power agreements less than 3
years in duration in this filing.
NAC 704.952 Sessions for reviewing plans: Scheduling; procedure for resolving
issues; summary of topics and conclusions; overview of anticipated filing or amendment of
resource plan
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NAC 704.952(1) states that “a utility may schedule sessions for reviewing plans and
providing an opportunity for interested persons to: (a) Learn of progress by the utility in
developing plans and amendments to plans; (b) Determine whether key assumptions are being
applied in a consistent and acceptable manner; (c) Determine whether key results are reasonable;
and (d) Offer suggestions on other matters as appropriate.” Not applicable.
NAC 704.952(4) states that “if review sessions are held pursuant to subsection 1, the
utility shall prepare a brief summary of the major topics on the agendas and the conclusions
reached by the parties during the review sessions. The summary must be provided to the
Commission in conjunction with testimony supporting the utility's plan.” Not applicable.
NAC 704.952(5) requires that “at least 4 months before the anticipated date for filing the
resource plan, the utility shall meet with staff and the personnel of the Bureau of Consumer
Protection to provide an overview of the anticipated filing.”
The Company satisfied this
requirement. See Technical Appendix Items DSM-1 and ECON-1.
NAC 704.9522
Measurement and verification protocol for energy efficiency
measures: Duties of utility provider.
NAC 704.9522(1) requires that “a utility provider shall propose a measurement and
verification protocol for all energy efficiency measures submitted pursuant to NAC 704.9005 to
704.9525, inclusive.” See Demand Side Plan volume, Exhibit A.
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EXHIBIT C 3DJHRI
PUBLIC UTILITIES COMMISSION OF NEVADA
DRAFT NOTICE
(Applications, Tariff Filings, Complaints, and Petitions)
Page 1 of 2
Pursuant to Nevada Administrative Code (“NAC”) 703.162, the Commission requires
that a draft notice be included with all applications, tariff filings, complaints and
petitions. Please complete and include ONE COPY of this form with your filing.
(Completion of this form may require the use of more than one page.)
A title that generally describes the relief requested (see NAC 703.160(5)(a)):
Application of Sierra Pacific Power Company d/b/a NV Energy Seeking Acceptance
of its Triennial Integrated Resource Plan covering the period 2014-2033 and
Approval of its Energy Supply Plan for the period 2014-2016.
The name of the applicant, complainant, petitioner or the name of the agent for the
applicant, complainant or petitioner (see NAC 703.160(5)(b)):
Sierra Pacific Power Company d/b/a NV Energy
A brief description of the purpose of the filing or proceeding, including, without
limitation, a clear and concise introductory statement that summarizes the relief requested
or the type of proceeding scheduled AND the effect of the relief or proceeding upon
consumers (see NAC 703.160(5)(c)):
Every three years, Sierra is required by law to submit to the Commission a twenty
year plan to increase its supply of electricity or decrease the demands made on its
systems by customers. This filing also includes an energy supply plan; the energy
supply plan contains Sierra’s short-term plan for acquiring energy to meet the
electric needs of its customers. The resource plan must be decided within 180 days
of filing and the energy supply plan must be resolved within 135 days of the filing.
The integrated resource plan has a few key elements. This integrated resource plan
provides for the expansion of demand side management plans, including the
addition of a demand response program designed to reduce peak costs. The plan
also asks for permission to complete environmental upgrades on existing generating
units, a request for a study to identify a new site for a generating plant, and
permission to complete transmission projects needed to maintain reliable service to
customers.
A statement indicating whether a consumer session is required to be held pursuant to
Nevada Revised Statute (“NRS”) 704.069(1) 1:
1
NRS 704.069 states in pertinent part:
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This integrated resource plan and energy supply plan do not require a consumer
session.
If the draft notice pertains to a tariff filing, please include the tariff number AND the
section number(s) or schedule number(s) being revised.
Not applicable.
1. The Commission shall conduct a consumer session to solicit comments from the public in any matter
pending before the Commission pursuant to NRS 704.061 to 704.110 inclusive, in which:
(a) A public utility has filed a general rate application, an application to recover the increased cost of
purchased fuel, purchased power, or natural gas purchased for resale or an application to clear its deferred
accounts; and
(b) The changes proposed in the application will result in an increase in annual gross operating revenue, as
certified by the applicant, in an amount that will exceed $50,000 or 10 percent of the applicant’s annual
gross operating revenue, whichever is less.
3DJHRI
TESTIMONY 3DJHRI
JAMES DOUBEK 3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-07___
4
PREPARED DIRECT TESTIMONY OF
5
James Doubek
6
7 1.
Q.
BUSINESS ADDRESS.
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
PLEASE STATE YOUR NAME, JOB TITLE, EMPLOYER AND
A.
My name is James Doubek. I am the Executive, Resource Planning and Analysis
10
for Sierra Pacific Power Company d/b/a NV Energy (“Sierra” or “Company”) and
11
Nevada Power Company d/b/a NV Energy (“Nevada Power,” and together with
12
Sierra, the “Companies”). My business address is 6226 West Sahara Avenue in
13
Las Vegas, Nevada. I am filing testimony on behalf of Sierra.
14
15 2.
Q.
EXPERIENCE.
16
17
PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
A.
I have been employed by the Companies since April of 2005 and have served as
18
the leader of Resource Planning and Analysis since March 2010. My current
19
responsibilities include leading a staff of economists, planners, engineers and
20
analysts to develop the Companies’ Integrated Resource Plans and Energy Supply
21
Plans. In addition, working with other groups in the Companies, the Resource
22
Planning and Analysis Department develops and supports supply strategies,
23
presents
24
communication of the status of the supply plans.
25
Prior to my assignment in Resource Planning and Analysis, I held the position of
26
Development Director, Renewable Energy, where I worked on development,
them
to
management
for
approval,
and
facilitates
ongoing
27
28 Doubek-DIRECT
1
3DJHRI
1
construction, and operations and maintenance plans associated with potential
2
Company owned, utility scale, renewable energy projects. Before joining the
3
Renewable Energy department, I held management positions in the Generation
4
Department focused on the operations and maintenance of the Companies’ various
5
generation stations. I originally joined the Companies’ as Plant Director of Chuck
6
Lenzie power station in 2005.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
8
I began working in the power generation industry in 1991 and held positions of
9
increasing responsibility in power generating stations and engineering support
10
roles primarily focused on the operations and maintenance of gas turbine power
11
stations and cogeneration plants.
12
Please see Exhibit Doubek-Direct 1 for a Statement of Qualifications.
13
14
15 3.
Q.
IS
THE
PURPOSE
OF
YOUR
TESTIMONY
IN
THIS
PROCEEDING?
16
17
WHAT
A.
I provide overall policy support for Sierra’s Integrated Resource Plan for 2014­
18
2033 (“2013 IRP”).
I provide an overview of the filing and introduce the
19
witnesses supporting the various components of the IRP. Additionally, I sponsor
20
the Power Purchase & Portfolio Energy Credit Agreements, Section 2.B.
21
22 4.
Q.
PLEASE DESCRIBE THIS 2013 IRP FILING.
23
A.
The Companies are required to file full integrated resource plans every three
24
years. The filings are staggered, and this filing represents Sierra’s triennial IRP.
25
The IRP analyzes resource options (demand-side, renewables, conventional
26
generation and transmission) for Sierra over twenty years (as prescribed by
27
28 Doubek-DIRECT
2
3DJHRI
1
regulation) and thirty years. Based on that analysis, the Company has selected a
2
solution for meeting the long-term needs of its customers, and constructed a three-
3
year Action Plan that identifies the steps to be taken and the costs to be expended
4
over the next three years to implement this plan. This filing covers the twenty
5
year period 2014 to 2033, the thirty year period 2014-2043, and the Action Plan
6
period of 2014, 2015 and 2016.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
8
The 2013 IRP contains an updated load forecast and updated fuel and purchased
9
power forecasts. It also contains updated generation, transmission, demand-side
10
management (“DSM”) and renewables plans. Embedded in the triennial IRP is an
11
energy supply plan (“ESP”) as required by NAC 704.9215(f). The ESP is located
12
in a stand-alone volume to be filed concurrently with the IRP. Based on the
13
integrated analysis performed, the Company is seeking approval of expenditures
14
for DSM resources and moderate transmission system investments. The Company
15
is not seeking approval for major expenditures related to supply-side resource
16
additions during the Action Plan period.
17
18 5.
Q.
WHO ARE THE WITNESSES AND WHAT DOES EACH SUPPORT?
19
A.
The following is a listing by subject matter of the witnesses supporting this 2013
20
IRP:
21
22
Load and Fuel Price Forecasts
23
Mr. Terry A. Baxter, Manager of Load Forecasting, sponsors Section 1 (“Load
24
Forecast”) of the Load Forecast and Market Fundamentals Volume: and Technical
25
Appendix Items LF-1 through LF-6.
26
27
28 Doubek-DIRECT
3
3DJHRI
1
Mr. Marc D. Reyes, Manager of Market Fundamentals, sponsors market
2
fundamentals discussion and the wholesale power and natural gas price forecasts
3
that are presented in the Load Forecast and Market Fundamentals Volume.
4
5
Mr. Joseph R. Brignola, Manager, Coal Operations and Procurement, sponsors
6
the following portions of the Load Forecast and Market Fundamentals Volume:
7
Section 2.C. (“Coal Fundamentals”) and the portions of Section 3.G. (“Coal Price
8
Forecast”) and Section 2.C.4 (“Current Coal Purchase and Transportation
9
Agreements) of the Supply Side Plan Volume
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
Ms. Anita L. Hart, Manager, Gas Transportation Planning, sponsors the
12
following portions of the Supply Side Plan Volume: Section 2.C.1 (“Fuel Supply
13
- Current Physical Gas Supply”), Section 2.C.2 (“Fuel Supply – Physical Gas
14
Procurement”), Section 2.C.3 (“Fuel Supply - Current Oil Supply”) and Section
15
2.C.5 (“Fuel Supply – Fuel Diversity Evaluation”).
16
17
Demand-Side Resources
18
Mr. Lawrence M. Holmes, Manager, Customer Strategy and Programs, along
19
with witnesses Michael Brown, Kelly Vagianos, Zeljko Vukanovic and Michelle
20
Lindsay, sponsors the Demand Side Management Plan.
21
22
Ms. Michelle A. Lindsay, Consultant Staff, DSM Planning, together with
23
Lawrence Holmes, Michael Brown and Kelly Vagianos, sponsors the Demand
24
Side Management Plan.
25
26
27
28 Doubek-DIRECT
4
3DJHRI
1
Ms. Kelly A. Vagianos, Consultant Staff, DSM Planning, along with Lawrence
2
Holmes, Michelle Lindsay, Zeljko Vukanovic and Michael Brown, sponsors the
3
Demand Side Management Plan.
4
5
Mr. Zeljko G. Vukanovic, Consultant Staff, DSM Planning, along with
6
Lawrence Holmes, Michelle Lindsay, Kelly Vagianos and Michael Brown,
7
sponsors the Demand Side Management Plan.
8
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
Mr. Michael O. Brown, Manager of Demand Response Programs, presents the
Demand Response Program set forth in the Demand Side Management Plan.
11
12
Dr. Donald R. Dohrmann, Principal and Director of Economics for ADM
13
Associates, Inc., together with Sasha Baroiant, Robert Oliver and Kelly Vagianos,
14
sponsors the M and V Reports.
15
16
Mr. Robert R. Oliver, Director/Project Manager ADM Associates, Inc., together
17
with Sasha Baroiant, Donald Dohrmann and Kelly Vagianos, sponsors the M and
18
V Reports.
19
20
Dr. Sasha Baroiant, Director/Project Manager ADM Associates, Inc., together
21
with Donald Dohrmann, Robert Oliver and Kelly Vagianos, sponsors the M and V
22
Reports.
23
24
Dr. Hossein Haeri, Executive Director at The Cadmus Group, Inc., describes the
25
method and the associated software tool used for calculating the projected impact
26
of utility investments in DSM on projected rates and customer bills, and how the
27
28 Doubek-DIRECT
5
3DJHRI
1
tool was applied to assess the likely effect on rates and customer bills from
2
Sierra’s implementation of its 2014-2016 Demand Side Plan. Additionally, Dr.
3
Haeri jointly sponsors the fuel diversity study with Ms. Hart.
4
5
Mr. Jeffrey Bohrman, Senior Analyst in the Regulatory Pricing and Economic
6
Analysis section of the Rates and Regulatory Affairs Department, sponsors
7
technical aspects of the Energy Efficiency and Conservation (“EE&C”) lost
8
revenue requirement calculations presented in this docket.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
Renewable Resources (Including Purchased Power) 11
Mr. Bobby J. Hollis, Executive, Renewable Energy, sponsors and supports the 12
Renewable Energy Plan and Sierra’s request for approval of the Fort Churchill 13
Solar Array Transaction.
14
15
Ms. Laura I. Walsh, Manager of Regulatory Pricing and Economic Analysis,
16
explains and supports the calculation of the Green Rate component of the Fort
17
Churchill Solar Array Transaction. 18
19
Ms. Patricia M. Franklin, Manager, Revenue Requirements, Regulatory
20
Accounting & FERC, sponsors and supports how Sierra will account for revenues
21
and expenses associated with the Ft. Churchill Solar Array Transaction. 22
23
Conventional Generation Resources (including Purchased Power)
24
Mr. John W. Lescenski, Manager, Plant Engineering and Technical Services, 25
sponsors the conventional generation discussion in the Supply Side Plan Narrative
26
and related Technical Appendix items. 27
28 Doubek-DIRECT
6
3DJHRI
1
Ms. Starla Lacy, Executive, Environmental, Health and Safety, supports the
2
environmental discussion of regulations impacting the generating plants presented
3
in the filing.
4
5
Transmission Resources
6
Mr. Charles A. Pottey, Manager of Network and IRP Transmission Planning,
7
sponsors the Transmission Plan section of the Supply Side Plan in Sierra’s 2014­
8
2033 Integrated Resource Plan filing with the exception of the 2033 Transmission
9
Study and the Renewable Energy Zone Transmission Plan.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
Mr. Edi Von Engeln, Staff Engineer, Transmission Planning, sponsors the 2033
12
Transmission Study and the Renewable Energy Zone Transmission Plan.
13
14
Economic Analysis
15
Mr. Robert R. Kocour, Jr., Manager, Long-Term Resource Planning, sponsors
16
the selection of the preferred and alternate plans including the inputs, assumptions
17
and methodology used to perform the economic analysis and the Loads and
18
Resource (“L&R”) tables.
19
20
Dr. David Harrison, Jr., economist and Senior Vice President at NERA
21
Economic Consulting, sponsors the discussion and analysis of environmental
22
externalities contained in the Supply Side Plan, Economic Analysis, and Financial
23
Plan volume, Section 3.H, as well as Technical Appendix Item ECON-17.
24
25
26
27
28 Doubek-DIRECT
7
3DJHRI
1
Financial Resources
2
Mr. William Harty, Manager, Corporate Finance, sponsors the financial narrative
3
of the Sierra 2014 – 2033 Integrated Resource Plan.
4
5 6.
HAS THE COMPANY PREPARED A NEW LOAD FORECAST AND
6
UPDATED ITS PROJECTIONS OF FUEL AND PURCHASED POWER
7
MARKETS?
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
Q.
A.
Yes. The Company has prepared a new load forecast taking into account updated
9
economic and population data and projections. Long term load growth is expected
10
to be modest and linked closely to a moderate economic recovery. The updated
11
load forecast is sponsored by Mr. Terry Baxter. The Company also developed
12
new market fundamentals projections for fuel and purchased power based on
13
updated assessments of regional market conditions and environmental drivers.
14
The market fundamentals, purchased power and natural gas price forecast sections
15
are supported by Mr. Marc Reyes. Mr. Joseph Brignola sponsors the coal price
16
forecast.
17
18 7.
Q.
NEED.
19
20
PLEASE DESCRIBE THE COMPANY’S NEAR-TERM RESOURCE
A.
Load growth in Northern Nevada is projected to be relatively modest over the
21
Action Plan period with the possible exception of continued strong mining load
22
growth.
23
sufficient investment in DSM activities to maintain the viability of the energy
24
efficiency industry and preserve Sierra’s ability to access these types of resources
The Company has prepared a DSM Preferred Plan that commits
25
26
27
28 Doubek-DIRECT
8
3DJHRI
1
in future years.1 The DSM Preferred Plan represents a moderate expansion of
2
program activity relative to the previously approved plan, but will bring a net
3
benefit of nearly $29 million to the communities served by Sierra. After taking
4
into account the contributions of DSM resources, the Company has sufficient
5
resources to meet a large portion of projected need in the Action Plan period. Any
6
needs that cannot be met with company controlled resources are anticipated to be
7
met with energy and/or capacity market purchases. The analysis of alternatives
8
and the selection of the Supply Side Preferred Plan are sponsored by Mr. Robert
9
Kocour.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11 8.
Q.
GIVEN PROJECTED LOAD LESS DSM SAVINGS, CAN SIERRA DEFER
INVESTMENTS IN SUPPLY SIDE RESOURCE ADDITIONS?
12
A.
13
Yes. However, it is important for the Company to begin identifying and securing
14
options for siting new generation resources that can be used to meet customer
15
needs beginning in the 2022 time frame.
16
activities can require five years or more; so identifying appropriate siting locations
17
now is important to preserving low-cost resource addition options for meeting
18
future needs. Sierra is requesting $1.25M in this action plan to identify and study
19
both green-field and brown-field generation site options for both conventional and
20
renewable generation.
Pre-development and permitting
21
22 9.
Q.
DOES SIERRA NEED TO INVEST IN GENERATION RESOURCES
DURING THE ACTION PLAN PERIOD?
23
24
25
26
1
See the Prepared Testimony of Mr. Lawrence Holmes, Ms. Michelle Lindsay Ms. Kelly A. Vagianos and Mr.
27 Michael O. Brown.
28 Doubek-DIRECT
9
3DJHRI
1
A.
Possibly, however no investment approvals are being sought at this time. Should
2
Sierra determine that it needs to begin investing in additional resources during the
3
action plan period, the Company will bring forward an appropriate IRP
4
amendment for Commission consideration.
5
anticipated completion of the One Nevada Transmission Line (“ON Line”) project
6
will allow Sierra to benefit from generation resources located in Nevada Power’s
7
service territory, with the potential of mitigating some of Sierra’s open capacity
8
position.
It is important to note that the
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10 10.
Q.
DURING THE ACTION PLAN PERIOD?
11
12
DOES SIERRA NEED TO INVEST IN TRANSMISSION RESOURCES
A.
Yes.
Sierra has prepared a transmission plan that includes modification of
13
previously approved transmission projects and requests approval of new
14
transmission projects necessary to reliably meet the projected needs of its
15
customers.
16
sponsored by Mr. Charles Pottey.
The transmission plan and projected project expenditures are
17
18 11.
Q.
PLEASE DESCRIBE SIERRA’S PROPOSAL FOR THE CONTINUED USE
19
OF RENEWABLE ENERGY RESOURCES AND ITS PLANS FOR
20
COMPLIANCE WITH THE NEVADA RENEWABLE PORTFOLIO
21
STANDARD?
22
23
A.
Sierra met the Renewable Portfolio Standard (“RPS”) in 2010, 2011 and 2012,
and is positioned to continue to do so during the Action Plan period.
24
25
Although the Company anticipates compliance with the RPS during the Action
26
Plan period, Sierra must continue to diligently monitor its current portfolio of
27
28 Doubek-DIRECT
10
3DJHRI
1
operating projects and those under development/construction. A full description
2
of Sierra’s renewable performance and plans for RPS compliance is contained in
3
Section 2.D. of the Supply Side Volume, and supported by the direct testimony of
4
Mr. Bobby Hollis.
5
6 12.
Q.
CAPABILITIES AT FT. CHURCHILL AND TRACY 3?
7
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
8
WHY IS THE COMPANY REQUESTING TO ELIMINATE FUEL OIL
A.
The cost of updating and maintaining fuel oil capabilities at these units is
9
uneconomic. As configured, these units have the capability to burn No.6 fuel. In
10
compliance with BART regulations, these units will no longer be permitted to
11
combust No.6 fuel after December 31, 2014. Ms. Lacy further describes the
12
environmental regulations associated with these units. Converting these units to
13
use No. 2 fuel is capital intensive and the capability to utilize No. 2 fuel is
14
unlikely to be needed once Sierra has access to Nevada Power’s system via On-
15
Line. Mr. Lescenski describes the costs and complexities of this fuel conversion.
16
Even if No. 2 fuel oil capabilities are assumed to be available for planning
17
analysis, the production cost modeling simulations do not dispatch these units
18
using fuel oil. Therefore the capital investment required to maintain fuel oil
19
capabilities is never offset by any production cost savings in any of the scenarios
20
or sensitivities evaluated for this IRP.
21
22 13.
Q.
WHAT IS THE SIGNIFICANCE OF THE IRP FILING?
23
A.
A look at the near-term needs of the Company might lead one to assume that
24
Sierra is in a position to relax its planning efforts—the Company is meeting the
25
RPS, and the Preferred Plan does not indicate the need to add significant supply-
26
side resources until 2022. However, Sierra must remain vigilant in positioning
27
28 Doubek-DIRECT
11
3DJHRI
1
itself to cost-effectively meet the future needs of its customers. The Company is
2
currently positioned to cost-effectively satisfy customer demand throughout the
3
Action Plan period, fueling its newest and highly efficient generation plant, Tracy
4
Combined Cycle, with low-priced natural gas. Nonetheless, preparing for the
5
long-term by prudently identifying future generation sites (for both conventional
6
and renewable resources) and maintaining options for additional generation
7
resources is critical.
8
options to add new resources when necessary-- will ensure that the Company and
9
its customers are well-positioned to maintain a strong generation portfolio and
avoid the risks of high levels of energy market exposure in the future.
10
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
Taking appropriate planning steps now-- by protecting
11
12 14.
Q.
IS SIERRA REQUESTING AUTHORITY TO EXPEND ANY FUNDS
13
DURING THE THREE YEAR ACTION PLAN PERIOD IN PURSUIT OF
14
THE
15
PREFERRED OR THE ALTERNATIVE SUPPLY SIDE PLANS?
16
A.
GENERATION
ADDITIONS
INCLUDED
IN
EITHER
THE
Yes, but only the amount that is needed to identify and maintain options for a site
17
or sites for future generation additions. Sierra is not requesting authority to
18
proceed with the construction of any future generating units at this time. Once an
19
appropriate site has been identified, Sierra will request authorization to proceed
20
with construction in a future IRP or IRP amendment.
21
22 15.
Q.
NEW ITEMS RELATED TO NATURAL GAS TRANSPORTATION?
23
24
IS THE COMPANY ASKING FOR ACTION PLAN APPROVAL FOR ANY
A.
No. Presently, no new gas transportation contracts are recommended and no
25
contracts will be discontinued. A complete discussion of Sierra’s natural gas
26
transportation plan is contained in section 2.C.1 of the Supply Side Volume and
27
28 Doubek-DIRECT
12
3DJHRI
1
section 5.B. of the Energy Supply Plan, and is supported by the testimony of Ms.
2
Anita Hart.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
3
4 16.
Q.
BRIEFLY SUMMARIZE THE OBJECTIVE OF THIS IRP FILING.
5
A. Sierra currently has adequate supply side resources to meet the needs of its
6
customers during the Action Plan period in a cost effective manner. In addition, the
7
Company expects to have access to additional generating resources following the
8
completion of the ON Line. Nonetheless, prudent long-term planning dictates that
9
the Company take limited but thoughtful action during the Action Plan period.
10
Specifically, the Company needs to:
11
1.
12
new generating resources that will be needed within the next decade to meet the
13
needs of Nevadans;
14
2.
15
provides reliable service to existing and new customers in a cost effective manner;
16
3. Proceed with the Fort Churchill Solar Array Transaction; and,
17
4.
Undertake demand-side management programs that contribute to and
18
enhance the Company’s ability to provide cost-effective service.
Pursue generating site studies with a limited budget to identify locations for
Pursue transmission projects that are necessary to ensure that the Company
19
20
The actions that the Company proposes to take during the Action Plan period might
21
not seem as “significant” as the actions proposed in integrated resource plans filed
22
in the last ten years. For instance, the Company is not asking for permission to
23
construct a new natural gas-fired fired generating facility as it did in Docket No.
24
05-08004, or a significant transmission addition as it did in Docket No. 10-03023.
25
The Company and the Commission have consistently engaged in prudent long-term
26
resource planning over the last decade and Sierra is now comfortably positioned to
27
28 Doubek-DIRECT
13
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
1
meet the short-term needs of its customers. This filing reinforces the need to
2
continue making prudent long-term planning decisions.
3
proposes exemplify prudent long-term resource planning. With respect to
4
generation, Sierra proposes necessary incremental (but measured) steps that
5
preserve long-term options. With respect to transmission, the Company proposes
6
those actions that are necessary to provide reliable service to existing customers and
7
planned load additions. With respect to demand-side management, the Company
8
proposes a plan that preserves alternatives for meeting load growth. Finally, with
9
respect to the Fort Churchill Solar Array Transaction, the Company proposes a
10
mutually beneficial option that meets the renewable energy objectives of a large
11
customer. The Company respectfully requests that the Commission authorize these
12
actions and accept the Action Plan.
The actions Sierra
13
14 17.
Q.
DOES THIS COMPLETE YOUR TESTIMONY.
15
A.
Yes, it does.
16
17
18
19
20
21
22
23
24
25
26
27
28 Doubek-DIRECT
14
3DJHRI
Exhibit Doubek Direct-1
Page 1 of 3
STATEMENT OF QUALIFICATIONS JAMES DOUBEK EXECUTIVE, RESOURCE PLANNING AND ANALYSIS
NV Energy
6226 W. Sahara Avenue Las Vegas, Nevada 89146 702-402-5761
EDUCATION
MBA University of Nevada, Las Vegas, Las Vegas, Nevada
B.S.M.E. Rutgers University College of Engineering, New Brunswick, New Jersey
EXPERIENCE
4/13-Present
NV Energy-Executive, Resource Planning and Analysis
Reporting to the Exec. VP and CFO, responsible for leading the development of the companies Long and
Short Term planning strategies including the development and filling of the companies’ Integrated
Resource Plans and Energy Supply Plans. These strategies are developed and presented to management
for approval by leading a team of economists, planners, engineers and analysts in the assembly of these
plans for filling and procedural hearings with the Public Utilities Commission of Nevada (PUCN).
3/10-4/13
NV Energy-Director, Resource Planning and Analysis
Reporting to the Sr. VP, Energy Supply, responsible for leading the development of the companies Long
and Short Term planning strategies including the development and filling of the companies’ Integrated
Resource Plans and Energy Supply Plans. These strategies are developed and presented to management
for approval by leading a team of economists, planners, engineers and analysts in the assembly of these
plans for filling and procedural hearings with the Public Utilities Commission of Nevada (PUCN).
6/08-3/10
NV Energy-Renewable Energy, Development Director
Reporting to the Executive, Renewable Energy, responsible for the development of renewable energy
projects and evaluation of third party renewable projects for purchase contracts to meet the renewable
portfolio standard for utilities in Nevada. Capture industry standard operational expertise to allow
successful partnership participation in Renewable Energy projects with various counterparties. Prepare
and manage capital and operating budgets for proposed Renewable Energy projects.
3DJHRI
Exhibit Doubek Direct-1
Page 2 of 3
4/07-6/08
(temporary)
NV Energy-Generation Department, Generation Executive
Reporting to the Sr. V.P. Energy Supply, responsible for the operations and maintenance of NV Energy’s
fleet of conventional fueled power stations, including coal and gas fired boilers as well as simple cycle
and combined cycle gas turbines. Directed the activities of corporate generation engineering support
staff. Developed and implemented strategic programs to enhance plant safety, environmental
performance, standardized maintenance activities and efficient power production. Implemented cost
reduction initiatives to enhance competitive performance and reduce consumer’s energy costs. Oversaw
capital and operating budgets of approximately $250 million annually. Lead operations portion of due
diligence and acquisition teams in support of $500 million Big Horn plant acquisition. Responsible for
managing human resources of entire generation division, approximately 600 employees.
1/06-4/07
NV Energy-LNZ/SHS/HA Power Complex, Plant Director
Reporting to the Generation Executive, responsible for the operations and maintenance of a three-plant
power generation complexes. Plant technologies included GE gas and steam turbines and Siemens gas
turbines. Developed strategic programs to ensure complex safety, environmental compliance and
efficient and cost-effective power production. Prepared and managed capital and operating budgets of
approximately $50 million annually. Oversaw the activities of all plant personnel.
4/05-1/06
NV Energy-Lenzie/Harry Allen Power Station, Plant Director
Reporting to the Generation Executive, responsible for the operations and maintenance of a gas-fired
1150 MW 2x2x1 GE 7FA combustion turbine combined cycle power plant and 75 MW 2x GE 7EA
simple cycle peaking power plant. Coordinated production in accordance with market demands, power
trading activities and system demand. During initial start-up and construction served as a construction
representative for operations department. Completed initial staffing and participated initial plant start-up.
Organized effective work teams for ongoing plant operations and maintenance. Prepared and managed
capital and operating budgets of approximately $25 million annually. Participated on due diligence and
acquisition teams in support of $200 million Silverhawk plant acquisition. Supervised activities of all
plant personnel.
3/99-3/05
Dynegy-Rockingham Power, Plant Manager
Reporting to the Sr. V.P. Operations, responsible for the operations and maintenance of a dual fuel 900
MW five W501F combustion turbine simple cycle peaking plant. Coordinated production in accordance
with market demands, power trading activities and short term capacity contracts. During initial start-up
and construction, served as a construction representative for off-site Dynegy construction management.
Completed initial staffing and organized effective work teams for ongoing plant operations. Prepared and
managed capital and operating budgets of approximately $4 million annually. Supervised activities of all
plant personnel.
3DJHRI
Exhibit Doubek Direct-1
Page 3 of 3
7/96-3/99
Dynegy-High Sierra Cogen, Plant Supervisor
Under the direction of the O&M Manager, responsible for the operations and maintenance of a 50 MW
twin LM2500 gas turbine cogeneration plant. Coordinated production in accordance with steam, power
and O&M contracts. Established and administered maintenance activities contributing to 100%
availability at capacity for 1996 bonus peak months. Prepared and managed capital and operating budgets
of approximately $2.5 million annually, including coordination of annual plan presentations to equity
partners. Supervised activities of all plant personnel.
1/94-6/96
Destec Energy-McKittrick Cogen, Plant Supervisor
Under the direction of the O&M Manager, responsible for the operations and maintenance of a 50 MW
LM5000 gas turbine cogeneration plant. Coordinated production in accordance with steam, power and
O&M contracts. Established and administered maintenance activities contributing to ten consecutive
bonus peak months of 100% availability at capacity, including three perfect years of bonus peak
operation. Prepared and managed capital and operating budgets of approximately $3 million annually.
Supervised activities of all plant personnel including development leading to promotion to supervisory or
foreign assignments of five subordinates. Maintained safety standards contributing to five years of
accident-free operation.
8/92-1/94
Destec Energy, California Support Engineer
Under the direction of the O&M Manager, provided plant engineering, economic analysis, project
proposals and construction coordination for three 50 MW twin LM2500 and one 50 MW LM5000 gas
turbine cogeneration plants. Focused on plant optimization and improvement projects including
coordination of six $1 million gas turbine overhauls. With the gas turbine specialist, completed the first
DOC specification for LM2500 gas turbine overhaul.
7/91-8/92
Destec Energy-Corona Cogen, Plant Engineer
Under the supervision of the Plant Manager, provided plant engineering, economic analysis, project
proposals and construction coordination for a 50 MW LM5000 gas turbine cogeneration plant. Focused
on plant optimization and improvement projects including design and implementation of a total water
conservation project resulting in $100,000 projected annual savings.
3DJHRI
3DJHRI
TERRY A. BAXTER 3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-_____
4
PREPARED DIRECT TESTIMONY OF
5
Terry A. Baxter
6
7
1.
Q.
8
TITLE, AND BUSINESS ADDRESS?
9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
WOULD YOU PLEASE STATE YOUR NAME, EMPLOYER, JOB
A.
My name is Terry A. Baxter. I am the Manager of Load Forecasting for
10
Sierra Pacific Power Company d/b/a/ NV Energy (“Sierra” or
11
“Company”) and Nevada Power Company d/b/a NV Energy (“Nevada
12
Power,” and together with Sierra, the “Companies”). My business address
13
is 6226 West Sahara Avenue, in Las Vegas, Nevada. I am filing testimony
14
on behalf of Sierra.
15
16
2.
Q.
17
WHAT ARE YOUR RESPONSIBILITIES AS MANAGER OF
LOAD FORECASTING?
18
A.
As the Manager of Load Forecasting, my primary responsibilities include
19
forecasting sales volume, customer counts and peak demand for use in
20
development of financial budgets, general rate cases, Energy Supply Plans
21
and Integrated Resource Plans (“IRPs”).
22
23
3.
Q.
PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND
24
AND
25
INDUSTRY?
EMPLOYMENT
EXPERIENCE
IN
THE
UTILITY
26
27
28
Baxter-DIRECT
1
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company d/b/a NV Energy
1
A. I hold a Master of Arts in Economics from the University of Arkansas
2
located in Fayetteville, Arkansas and a Bachelor of Science in Economics
3
from the University of Missouri at Rolla (now Missouri University of
4
Science and Technology) located in Rolla, Missouri.
5
employed by the Companies since July 2007. Prior to my current position,
6
I served as the Manager of Forecasting and Economic Analysis at Alliant
7
Energy in Cedar Rapids, Iowa, for nine years, where I was responsible for
8
load and revenue forecasting and load research. Prior to that, I was a
9
Group Manager for seven years with Aspen Systems Corporation (now a
10
division of Lockheed-Martin) overseeing analytical consulting projects for
11
utilities and the U.S. government. I also have served as Manager of Load
12
Research at Midwest Resources (now MidAmerican Energy) and as the
13
Load Research Analyst at Missouri Public Service Company (now a part
14
of Kansas City Power and Light Co., a division of Great Plains Energy). I
15
have submitted reports and testimony regarding load forecasting and load
16
research before the Iowa Utilities Board, the Wisconsin Public Service
17
Commission, the Illinois Commerce Commission, the Minnesota
18
Department of Commerce, the California Energy Commission, the
19
California Public Utilities Commission and the Public Utilities
20
Commission of Nevada.
I have been
21
22
4.
Q.
DOES EXHIBIT BAXTER-DIRECT-1 ACCURATELY DESCRIBE
23
YOUR EDUCATIONAL BACKGROUND AND PROFESSIONAL
24
EXPERIENCE?
25
A.
Yes, it does.
26
27
28
Baxter-DIRECT
2
3DJHRI
1
5.
Q.
2
TESTIMONY IN THIS PROCEEDING?
3
Nevada Power Company
And Sierra Pacific Power Company d/b/a NV Energy
WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT
A. The purpose of my testimony is to support the forecast of native load used
4
in this filing. Specifically, I am sponsoring the long term load forecast
5
used for the 2013 Integrated Resource Plan (the “IRP Forecast”), and the
6
following Technical Appendix Items:
7
LF-1
Sierra Pacific Power Company’s 2014-2043 Load Forecast
8
LF-2
State Demographer October 2012 Population Forecast
9
LF-3
10
LF-4
Forecasting Using Statistically Adjusted End-Use Models
11
LF-5
2008 Natural Gas Statistically Adjusted End-Use Models
12
LF-6
Global Insight January 2013 Economic History and
13
2011 Residential Appliance Saturation Survey Report
Forecast
14
15
6.
Q.
16
17
18
PLEASE
SUMMARIZE
THE
COMPANY’S
REQUESTS
REGARDING THE IRP FORECAST.
A. The Company is making the following requests regarding the IRP
Forecast:
19
A finding, consistent with NAC 704.9225, that the base, high and low
20
cases are based upon and consistent with the upper and lower limits of
21
expected economic and demographic change in Sierra’s service
22
territory in the next 20 years.
23
A finding, consistent with NAC 704.9321, that the base, high and low
24
cases and the extreme temperature peak forecast for transmission
25
planning are based on substantially accurate data, adequately
26
demonstrated and defended, and adequately documented and justified.
27
28
Baxter-DIRECT
3
3DJHRI
1
A finding that the IRP Forecast as described in the narrative and the
2
Technical Appendices, and my testimony, contain all of the items
3
required by NAC 704.925 and other applicable regulations.
4
A finding that the IRP Forecast is suitable for making near and long
5
term planning decisions.
6
Nevada Power Company
And Sierra Pacific Power Company d/b/a NV Energy
7
7.
Q.
IS THE FORECAST THAT YOU ARE PRESENTING IN THIS
8
TESTIMONY THE SAME AS THE FORECAST THAT WAS
9
FILED IN DOCKET NO. 12-08009 AS PART OF SIERRA’S
10
SECOND AMENDMENT TO THE 2011-2030 INTEGRATED
11
RESOURCE PLAN FILING (“2ND AMENDMENT FORECAST”)?
12
A.
No. The 2nd Amendment Forecast was completed in January 2012, except
13
for the mine load forecast which was updated in May 2012. The IRP
14
Forecast was completed in January 2013.
15
For the IRP Forecast, inputs are updated for the following:
16
The IRP Forecast is based on Global Insight’s January 2013 Northern
17
Nevada economic forecast. Global Insight’s January 2013 Northern
18
Nevada economic forecast is defined as the Nevada state economic
19
forecast less the Las Vegas-Paradise Metropolitan Statistical Area
20
(“MSA”). This is the same definition used in the 2nd Amendment
21
Forecast. Historical and forecasted series include quarterly population,
22
household, real personal income, employment and real gross state and
23
metro output.
24
Population Growth. The 2010 Census was used as the benchmark for
25
both the IRP and 2nd Amendment Forecasts. The northern Nevada
26
2010 population is about 750,000.
27
northern Nevada population growth of 1.1 percent from 2012 to 2013,
28
Baxter-DIRECT
Global Insight (“GI”) projects
4
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
and a 1.0 percent average annual growth rate (“AAGR”) for 2013
2
through 2023. The State Demographer’s October 2012 forecast is
3
somewhat higher with 1.2 percent annual population growth from
4
2012 to 2013 and 1.1 percent AAGR from 2013-2023. Given the State
5
Demographer’s population forecast explicitly accounts for growth
6
related to increase in mining activity, we elected to use the State
7
Demographer’s higher population forecast. Through 2023, the IRP
8
population forecast is roughly the same as that used in the 2nd
9
Amendment Forecast. See Technical Appendix Item LF-1 for a full
10
discussion of the population forecast.1
11
Employment and Output Trends.
12
economic recovery with non-manufacturing employment growth of 1.3
13
percent in 2011 and 1.2 percent in 2012. Employment growth is
14
expected to increase 2.2 percent in 2013 before falling back to 1.0
15
percent in 2014. Over the next ten years, Global Insight projects real
16
average annual output growth of 2.4 percent and non-manufacturing
17
employment growth of 1.6 percent.
18
Amendment Forecast of 2.2 percent real output growth and 1.3 percent
19
non-manufacturing employment growth.
20
Mining Industry. The mining industry accounts for approximately 21.5
21
percent of Sierra’s 2012 billed sales. With the price of gold and other
22
metals at elevated levels compared to recent history, mining activity is
23
expected to increase significantly over the next five years. Mining
24
load is forecasted by month through 2017 and annually thereafter. The
Sierra has begun to see some
This compares with the 2nd
25
26
1
27
The 2nd Amendment Forecast used growth rates in between the GI and State Demographer forecasts until
2018, when the growth rate was set at the State Demographer growth rate. For the IRP, the State Demographer
growth rate was used until 2028 when it was flattened at 0.9 percent growth.
28
Baxter-DIRECT
5
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
forecast methodology is the same for the IRP and 2nd Amendment
2
Forecasts. Figure LF-19 shows the additional mining load forecast.
3
The IRP mining load forecast is slightly higher than the 2nd
4
Amendment Forecast.
5
MW by 2017 compared with 211 MW of new mining load in the 2nd
6
Amendment Forecast.
7
Weather Assumption. The IRP Forecast is based on s a 20-year normal
8
weather period of January 1993 through December 2012. Normal
9
weather concepts include monthly heating degree-days (“HDD”) and
10
cooling degree-days (“CDD”), and peak day temperatures. The 2nd
11
Amendment Forecast of normal weather was derived using the period
12
January 1992 through December 2011.
13
DSM. The incremental annual reductions in load attributed to DSM
14
used in the 2nd Amendment Forecast are based on the December 2011
15
stipulation in Docket No. 11-07026. The DSM savings estimate for
16
the IRP Forecast is consistent with the final Order for Sierra’s 2012
17
Annual Demand Side Management Update Report in Docket No. 12­
18
06053, issued by the Commission on December 24, 2012. The DSM
19
savings for the IRP Forecast are lower than the 2nd Amendment
20
Forecast savings for 2013 and 2014, but higher from 2015 to the end
21
of the forecast.
22
discussion.
23
Demand Response. Demand response (“DR”) program impacts are
24
significantly higher than the pilot program of 2 MW incorporated in
25
the 2nd Amendment Forecast. The preferred program is expected to
26
begin in the summer of 2014 with potential DR load reduction rising
New mining load is expected to reach 237
See Technical Appendix Item LF-1 for further
27
28
Baxter-DIRECT
6
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
from 5 MW in 2014 to 58 MW in 2016. More details can be found in 2
Technical Appendix LF-1. 3
Net metering. The effects of net metering (including Photovoltiac, 4
Wind, and Hydro) are roughly the same as that assumed in the 2nd
5
Amendment Forecast. More discussion of the net metering reductions 6
is contained in Technical Appendix Item LF-1.
7
Adjusting the EIA default lighting efficiencies for the Nevada Lighting
8
Law. Both the IRP and 2nd Amendment Forecasts include an
9
adjustment of the residential lumens per watt to simulate the lighting 10
usage reduction from Nevada’s recent lighting regulations codified in
11
NRS 701.260. In addition, an adjustment was made to C&I sales (both 12
Small and Large classes) based on discussions with Larry Holmes,
13
Manager of Customer Programs and Strategies at Sierra. The law is
14
now assumed to take effect in 2014, although there has been no
15
activity to develop the necessary regulations.
16
Integrating DSM Program Impacts.
17
Forecast, we took a more integrated approach for capturing the impact 18
of DSM program activity.
19
provided historical and expected future program savings by end-use.
20
Forecast end-use intensities (kWh per household in the residential
21
sector and kWh per square foot in the commercial sector) used to drive 22
the residential and class sales models are then adjusted downwards to 23
account for these savings projections. Program savings that cannot be
24
tied to specific end-uses are mapped to the miscellaneous end-use. In
25
the 2nd Amendment Forecast, non-specific end-use savings were
26
subtracted from the forecast.
27
assumed that 50 percent of the future savings was already captured by
28
Baxter-DIRECT
As in the 2nd Amendment
For the IRP Forecast, DSM Planning In the 2nd Amendment Forecast we 7
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
the baseline forecast (embedded savings); this assumption was based
2
on aggregate historical DSM expenditures. In the IRP Forecast we
3
developed separate embedded savings estimates for each DSM-
4
targeted end-use. The embedded savings estimates (defined in terms
5
of percentages) are based on new historical end-use savings estimates
6
developed by the DSM Planning Group. A detailed discussion of this
7
methodology is included in Technical Appendix LF-1.
8
The net metering reductions are also updated based on expected PV
9
and Wind installed capacity through the Renewable Generations
10
programs. There is also a small amount of hydro net metering. Total
11
net metering impacts are about the same as in the 2nd Amendment
12
Forecast. More discussion of these changes is contained in Technical
13
Appendix Item LF-1.
14
The IRP Forecast price estimates were updated from the 2nd
15
Amendment using more current revenue forecasts provided by the
16
Company’s Financial Planning and Analysis Department.
17
forecasts included lost revenues, while the IRP includes carbon costs
18
beginning in 2019 - one year later than in the 2nd Amendment
19
Forecast.
20
The California FERC jurisdiction forecast was updated based on a
21
December 2012 CalPeco (now Liberty Energy) sales forecast. The 2nd
22
Amendment Forecast utilized the CalPeco September 2011 forecast.
23
As with the Second Amendment, the anticipated effects of electric
24
plug-in vehicles (“EVs”) are included in the base, low and high case
25
forecasts. As agreed to with the PUCN Staff, the percentage of new
26
EV sales in the base load forecast are capped at one percent beginning
27
in 2016, vs. approximately seven percent of new cars on the road in
28
Baxter-DIRECT
Both
8
3DJHRI
1
2020 for the 2nd Amendment Forecast.2 This results in a sales increase
2
of approximately 4,400 MWh by 2020, or about 0.05 percent of total
3
sales.
4
There are no changes to the methodology for developing the extreme
5
weather transmission peak forecast. In the 2nd Amendment Forecast,
6
an adjustment factor of 3.86 percent was deemed reasonable by all
7
parties based on peak demand modeling results. The IRP peak load
8
adjustment is calculated by applying the 3.86 percent adjustment factor
9
to the IRP Forecast.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
11
8.
Q.
12
WERE ANY ADJUSTMENTS MADE TO THE EIA’S DEFAULT
APPLIANCE STOCKS AND EFFICIENCY ESTIMATES?
13
A.
Yes. The Energy Information Association (“EIA”) produces an annual
14
forecast of energy usage, including electricity use, for nine census regions.
15
Backup files include appliance saturation, efficiencies and end-use
16
electricity use per household for the residential sector and end-use
17
electricity use per square footage by building types for the commercial
18
sector. Sierra Pacific is in the Mountain Census Region, which includes
19
Montana in the north to Arizona in the south. To better reflect the Sierra
20
Pacific service territory, Sierra conducted residential appliance saturation
21
surveys in late 2008 and spring 2011. Survey results were used to modify
22
the default regional appliance saturations estimates.3
23
commercial and industrial (“C&I”) rate class, a telephone survey was
24
conducted from December 2008 through January 2009. The results of the
For the small
25
26
2
27
This agreement was included in the PUCN order for the 2 nd Amendment dated December 24, 2012.
3
See Appendix LF-3 for a report of the most recent residential survey.
28
Baxter-DIRECT
9
3DJHRI
1
survey and other employment analysis were used to calibrate the census
2
region end-use energy intensities to the Sierra service area.
3
4
9.
Q.
5
Nevada Power Company
And Sierra Pacific Power Company d/b/a NV Energy
6
HOW DOES THE IRP FORECAST COMPARE TO THE 2ND
AMENDMENT FORECAST?
A.
Excluding the impacts of DR programs, the IRP peak demand forecast is
7
slightly higher than the 2nd Amendment Forecast. The IRP Forecast peak
8
demand is higher in the starting years with a peak demand of 1,637 MW in
9
2013 (52 MW higher) and a forecast of 1,679 MW in 2014 (18 MW
10
higher). By 2020 the IRP peak demand forecast is 1,777 MW, 18 MW
11
higher than the 2nd Amendment. The higher starting load point in 2013 is
12
due to the upward re-basing of the 2013 forecasted peak demand as the
13
weather normalized (“WN”) peak demand for 2012 was 1,621 MW, 52
14
MW higher than the 2nd Amendment Forecast and 76 MW higher than the
15
2011 weather normalized peak demand.
16
includes a more aggressive DR program. After adjusting for expected DR
17
impacts, there is little change between the IRP and 2nd Amendment peak
18
forecasts after 2013 until the late 2030’s. The system energy forecast
19
increased 114 GWh (1.4 percent) in 2013, mainly due to the relatively
20
robust sales growth from 2011 to 2012 and decreased 924 GWh in 2014 (­
21
1.1 percent) before increasing significantly, reaching 9,856 GWh by 2020,
22
301 GWh higher than the 2nd Amendment Forecast (+3.2 percent). The
23
2014 through 2020 growth pattern is mainly due to changes in the timing
24
and size of the new mining load when compared to the 2nd Amendment
25
Forecast.
However, the IRP Forecast
26
27
28
Baxter-DIRECT
10
3DJHRI
1
10.
Q.
2
IN PREPARING THE IRP FORECAST, DID THE COMPANY USE
THE BEST ESTIMATES OF DSM AVAILABLE AT THE TIME?
3
A. Yes. However, since the IRP Forecast was completed in early January
4
2013 the DSM programs have been revised.
5
material with respect to the forecast.
These changes are not
6
7
11.
Q.
8
Nevada Power Company
And Sierra Pacific Power Company d/b/a NV Energy
9
HAVE NEW HIGH AND LOW LOAD FORECAST SCENARIOS
BEEN DEVELOPED FOR THE IRP?
A. Yes. New high and low load forecasts were produced based on optimistic
10
and pessimistic economic, demographic, mining growth, DSM, DR, net
11
metering and electric vehicle penetration assumptions.
12
Appendix LF-1 for more details regarding the development of the high
13
and low load forecast scenarios.
See Technical
14
15
12. Q.
DOES THE IRP FORECAST CONSIDER THE IMPACT OF
16
APPLICABLE NEW TECHNOLOGIES AND THE IMPACT OF
17
APPLICABLE
18
REGULATIONS (SEE NAC 704.925(4))?
19
A. NEW
GOVERNMENTAL
PROGRAMS
OR
Yes. The customer class sales regression modeling for the IRP Forecast
20
included variables constructed from estimated historical and forecasted
21
appliance saturations and efficiencies, building characteristics and square
22
footage.
23
technologies and government programs.
These estimates and forecasts include the effects of new
24
25
26
27
28
Baxter-DIRECT
11
3DJHRI
1
13.
Q.
HAVE YOU PREPARED A GRAPHICAL REPRESENTATION OF
2
PROJECTED LOAD DURATION CURVES FOR SIERRA’S
3
SYSTEM FOR 2014 AND EVERY FIFTH YEAR THEREAFTER
4
FOR THE REMAINDER OF THE PERIOD COVERED BY THE
5
IRP (SEE NAC 704.925(9))?
6
A. 7
Yes. Please see the Load Forecast Technical Appendix LF-1 for system
annual load duration curves.
8
Nevada Power Company
And Sierra Pacific Power Company d/b/a NV Energy
9
14.
Q.
HAS
THE
COMPANY
PROVIDED
HISTORICAL
DATA
10
RELATING TO PEAK DEMAND AND ENERGY CONSUMPTION,
11
NORMALIZED FOR WEATHER, FOR THE 10-YEAR PERIOD
12
IMMEDIATELY PRECEDING THE YEAR OF THE SECOND
13
AMENDMENT FILING (SEE NAC 704.9281(1)(A) AND (B))?
14
A. Yes. Please see the Load Forecast Technical Appendix which contains the
15
weather normalized sales for the total system and Nevada sales for 2003
16
through 2012, and weather normalized peak demand for the system for
17
2003-2012 and for 2011 and 2012 for Nevada only. The first year of
18
separate California hourly metering was in 2011.
19
20
15.
Q.
HAS
THE
COMPANY
PROVIDED
HISTORICAL
DATA
21
RELATING TO ESTIMATED LOSSES AND COMPANY USE OF
22
ENERGY FOR THE SYSTEM FOR THE 10-YEAR PERIOD
23
IMMEDIATELY
24
704.9281(1)(C) AND (D))?
25
26
A. PRECEDING
THIS
FILING
(SEE
NAC
Yes. Please see the Load Forecast Technical Appendix LF-1 for Sierra’s
system losses and Company use.
27
28
Baxter-DIRECT
12
3DJHRI
1
16.
Q.
HAS
THE
COMPANY
MADE
ANY
CHANGES
TO
ITS
2
FORECAST METHODOLOGY SINCE THE FILING OF THE 2ND
3
AMENDMENT TO ITS 2011-2030 IRP (SEE NAC 704.925(11)?
4
A.
N
o.
Q. ARE YOU FILING WORKPAPERS WITH THIS IRP?
A. Yes, a comprehensive set of load forecasting files will be supplied on
5
6
17.
7
8
electronic media for this IRP filing.
9
Nevada Power Company
And Sierra Pacific Power Company d/b/a NV Energy
10
18.
11
Q. WHAT IS YOUR OVERALL VIEW OF THIS IRP FORECAST?
A. The IRP Forecast is based on substantially accurate data.
More
12
specifically, the IRP Forecast is based on data (such as demand side
13
management plans and economic forecasts) that were gathered from the
14
best sources available to Sierra at the time I prepared the forecast. The
15
forecast covers the 20-year period beginning in 2014 and contains energy
16
consumption and summer and winter demand projections. The forecast
17
takes into consideration, among other things, annual system losses,
18
company usage, the effect of distributed generation, as well as customer
19
show acquire energy pursuant to NRS 704.787 and Chapter 704B of the
20
NRS. The forecast is documented appropriately, and has been adequately
21
explained and defended. The forecast thus is a reasonable basis upon
22
which to make both near and long term planning decisions for the period
23
2014 through 2033.
24
25
26
19.
Q. DOES THAT CONCLUDE YOUR TESTIMONY?
A. Yes, it does.
27
28
Baxter-DIRECT
13
3DJHRI
Exhibit Baxter-Direct-1
Page 1 of 2
STATEMENT OF QUALIFICATIONS
OF
TERRY A. BAXTER
Education
Master of Arts
Bachelor of Science
University of Arkansas, Fayetteville, AR, 1979, Economics
University of Missouri-Rolla, Rolla, MO, 1976 Economics
Related Professional Experience
2007 to Present
Manager of Load Forecasting, Nevada Power Company d/b/a NV Energy
My primary duties are the forecasting of customers, sales, peak demand, gas therms and gas design
day therms, for use in supply planning, rate cases and budgeting. Additional responsibilities include
production of forecast variance reports from actual, weather adjustment of peaks and sales, and
participation in local population forecasting working groups.
2003 to 2007 Manager, Forecasting and Economic Analysis, Alliant Energy
Responsible for the direction and technical work in the areas of statistical sample design and
evaluation of load research samples, peak and energy forecasting, for both the gas and electric
utilities, and associated regulatory filings, including Integrated Resource Plan filings in Iowa, Illinois,
Minnesota and Wisconsin. In this position, I was also responsible for the monthly sales and revenue
forecast and explanations of the monthly variance analysis, including actual to budget, year-over­
year, and outlook for both operating companies: Wisconsin Power and Light Company and Iowa
Power and Light Company. Also responsible for rate case sales and demand forecasts in Wisconsin
and Minnesota. Filed direct testimony before the Minnesota Department of Commerce.
2001 to 2003 Private Consultant
Assisted utility companies in sample design and analysis of load research programs.
1998 to 2003 Team Leader, Forecasting and Economic Analysis, Alliant Energy
Responsible for the direction and technical work in the areas of statistical sample design and
evaluation of load research samples, peak and energy forecasting, for both the gas and electric
utilities, and associated regulatory filings for IES Utilities and Interstate Power Company and its
successor company, Iowa Power and Light.
1991 to 1998 Group Manager, Aspen Systems Corporation
Responsible for the technical direction of utility consulting projects in the areas of sample design, DSM
performance evaluation, market and survey research.
1985 to 1991 Rate Engineer and Manager of Load Research, and Forecasting, Iowa Power, Inc. /Midwest
Energy
Responsible for all facets of the load research program, including sample design, analysis and equipment
selection, as well as sales forecasting. Filed testimony before the Iowa Utilities Board.
1980 to 1995 Load Research Analyst, Missouri Public Service Company
Responsible for all facets of the load research program as well as class cost of service and marginal cost
studies.
1979 to 1980 Economic Analyst, Illinois Commerce Commission
Responsible for examination of utility rate and regulatory filings.
3DJHRI
Exhibit Baxter-Direct-1
Page 2 of 2
Other
2007 to present
Steering Committee, EEI Load Forecasting Group
1998 to 2007
Member, AEIC Load Research Committee
Marketing sub-committee chairman from 2001-2007.
Specialized Training
Econometric Modeling Using SAS/ETS Software, February, 1991.
SAS Macro Language, August 1990.
Forecasting Techniques using SAS/ETS Software, April, 1990. Sampling Methods and Statistical Analysis in Power Systems Load Research, April, 1989.
A.E.I.C. Seminar in Advanced Sample Design and Analysis of Load Research Data, July 1987.
Itron Statistically Adjusted End Use (SAE) Training Workshop, November 2008.
3DJHRI
3DJHRI
MARC D. REYES 3DJHRI
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
1
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13­
4
PREPARED DIRECT TESTIMONY OF
5
Marc D. Reyes
2
6
7
1.
Q.
8
ADDRESS.
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
A.
My name is Marc D. Reyes. I am the Manager of Market Fundamentals
10
for Sierra Pacific Power Company d/b/a NV Energy (“Sierra” or
11
“Company”) and Nevada Power Company d/b/a NV Energy (“Nevada
12
Power” and together with Sierra, the “Companies”).
13
address is 6226 West Sahara Avenue, Las Vegas, Nevada. I am filing
14
testimony on behalf of Sierra.
My business
15
16
2.
Q.
17
18
PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND
AND EXPERIENCE.
A. I hold a Bachelor of Arts in Economics from New Mexico State
19
University. I have been employed by the Companies since May 2007
20
and have served as the Manager of Market Fundamentals since May
21
2011. Prior to my current role in Resource Planning and Analysis, I was
22
a Power Trader for the Companies, where I performed analysis and
23
negotiated short-term wholesale transactions to optimize the Companies
24
economic dispatch. Before joining the Companies, I was employed as a
25
Wholesale Power Trader for El Paso Electric Company. More details
26
27
28
Reyes-DIRECT
1
3DJHRI
1
regarding my professional background and experience are set forth in my
2
Statement of Qualifications, included as Exhibit Reyes-Direct 1.
3
4
3.
Q.
5
OF MARKET FUNDAMENTALS.
6
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE DESCRIBE YOUR RESPONSIBILITIES AS MANAGER
A.
As Manager of Market Fundamentals my responsibilities include the
7
development of market price forecasts for natural gas and wholesale
8
power delivered to the relevant regional market trading hubs.
9
Additionally, I am responsible for the regional market fundamental
10
analysis that supports the Companies’ energy supply and resource
11
planning functions.
12
13
4.
Q.
14
15
WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
PROCEEDING?
A. I am sponsoring the market fundamentals discussion and the wholesale
16
power and natural gas price forecasts (“price forecasts”) that are
17
presented in Volume 4 (“Load Forecast and Market Fundamentals”). I
18
also sponsor the following Technical Appendix items, which are
19
confidential:
20
F&PP-1
21
22
2014-2043 Sierra Pacific Power’s IRP - Fuel and
Purchased Power Price Forecasts –Carbon Cases; and
F&PP-2
23
2014-2043 Sierra Pacific Power’s IRP - Fuel and
Purchased Power Price Forecasts – No Carbon Cases.
24
25
26
27
28
Reyes-DIRECT
2
3DJHRI
1
5.
Q.
2
PURCHASED POWER PRICE FORECASTS USED IN THIS
3
PROCEEDING?
4
A.
The base, high and low fuel and purchased power forecasts used in this
5
filing have been prepared in a manner consistent with prior IRP related
6
filings. The methodology used to prepare both the power and natural gas
7
price forecasts relies upon near-term observable market based price
8
quotes (“quotes”) that are blended into a long-term market fundamental
9
price forecast. These price forecasts are described in the Load Forecast
10
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE BRIEFLY DESCRIBE THE NATURAL GAS AND
and Market Fundamentals volume.
11
12
6.
Q.
PLEASE DESCRIBE THE DATA SOURCES USED FOR THE
13
MARKET
14
FUNDAMENTAL PRICE FORECAST YOU DESCRIBE IN Q&A
15
5.
16
A. BASED
PRICE
QUOTES
AND
MARKET
The sources of data for natural gas quotes are the CME Group1 and
17
Amerex. The quotes consist of observed transactions at the following
18
hubs: Henry Hub, Alberta NOVA Inventory Transfer (“AB-NIT” or
19
“AECO”), Sumas, Northwest Pipeline Rockies (“Rockies”), Malin.
20
Quotes for power are obtained from TFS Energy and Tullett Prebon.
21
The quotes consist of observed transactions at the Mid-Columbia (“Mid-
22
C”) and Mead markets.
23
24
25
26
1
27
The quotes that are reported by the CME Group include open outcry trades on the NYMEX as well CME
ClearPort and CME Globex transactions.
28
Reyes-DIRECT
3
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
1
The long-term fundamental price forecast is from a professional
2
forecasting
3
WoodMac publishes their fundamental price forecast bi-annually, and
4
the price curves in this filing are based on the Fall 2012 WECC Long-
5
Term View (“LTV”). WoodMac performs detailed modeling of regional
6
natural gas and power markets, taking into account supply-demand price
7
dynamics. In January 2013, WoodMac published a No-Carbon case
8
sensitivity to the LTV which assumes no federal climate legislation
9
concerning greenhouse gas (“GHG”) regulation or renewable energy
10
standards given the current economic and political climate in the United
11
States. The market fundamentals in the No-Carbon case to the LTV
12
serve as the foundation in building the price forecasts included as
13
Technical Appendix Item F&PP-1 and F&PP-2.
service,
Wood
Mackenzie
Limited
(“WoodMac”).
14
15
7.
Q.
16
PLEASE DESCRIBE THE PROCESS USED TO PREPARE THE
NATURAL GAS AND POWER PRICE FORECASTS.
17
A.
The near-term (March 2013 through March 2015) market quotes for
18
power and gas are 100% based on the average of settlement prices during
19
the nineteen trading days in February 2013.
20
transition from being 100% market based price quotes to 100% long­
21
term fundamental forecast from April 2015 through March 2017. The
22
near-term market based quotes are incrementally blended with the long­
23
term fundamental forecast across the transition period.2 The Company
24
used the pure fundamental forecast for the April 2017 through December
The price forecasts
25
26
2
27
The blending of market quotes and the fundamental forecast occurs across four gas seasons, or 24 months,
with a weighting of the fundamental forecast increasing monthly by 4.0% per month.
28
Reyes-DIRECT
4
3DJHRI
1
2030 portion of the price forecast. Beyond 2030, the Company used the
2
real growth rate from the Energy Information Administration’s Annual
3
Energy Outlook 2013 to escalate Henry Hub natural gas though the end
4
of the forecast period.
5
period, long-term forecast, and the escalation period constitute the
6
forecasted natural gas price curve for each of the relevant Western
7
natural gas trading hubs. The natural gas price forecasts are provided in
8
Technical Appendix items F&PP-1 and F&PP-2.
Thus the near-term market quotes, blending
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
Power prices are derived by multiplying the forecasted gas prices and the
11
forecasted market implied heat rate (“MIHR”) defined as the ratio of
12
power prices and the corresponding gas price for that market.
13
MIHR forecast for March 2013 through March 2015 is the ratio of
14
nineteen-day average power price quotes from TFS and the nineteen-day
15
average forward gas prices from CME Group and Amerex as described
16
above. The second part of the curve, from April 2015 to March 2017, is
17
a blend of market heat rates based on the market quotes and fundamental
18
forecast. In the blending process the MIHR based on pure market quotes
19
are more heavily weighted in the initial period, with the MIHR based on
20
fundamental taking receiving greater weight towards the end of the
21
blending period. The third part of the curve, from April 2017 until
22
December 2030, is entirely based on the MIHR curve from the
23
fundamental forecast. The heat rate trend from 2026 to 2030 of the
24
fundamental forecast was used to calculate the MIHR curve through the
25
end of the forecast. The power price forecasts are provided in Technical
26
Appendix items F&PP-1 and F&PP-2.
The
27
28
Reyes-DIRECT
5
3DJHRI
1
With respect to coal fuels, Mr. Joseph Brignola sponsors the long-term
2
forecast of coal prices delivered to the Company’s plants that was
3
prepared by the professional coal consulting firm of John T. Boyd
4
Company (“Boyd”). Additionally, Boyd prepared high and low coal
5
price forecasts, which the Company used in PROMOD modeling with
6
the high and low gas and power price cases.
7
8
8.
Q.
9
AND PURCHASED POWER FORECASTS?
10
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
HOW DID SIERRA CALCULATE THE HIGH AND LOW FUEL
A.
Sierra includes sensitivity analyses around the base case projections to
11
determine how planning results could vary under a range of market price
12
conditions. High and low price curves for natural gas were calculated at
13
one standard deviation around the base case forecast (plus and minus).
14
The corresponding power price forecasts were prepared to reflect
15
western energy prices that fluctuate with the respective natural gas price
16
forecasts, using the heat rate of a typical combined-cycle unit. The profit
17
margin ($/MWh), or spark spread, reflected in the base case price
18
forecast was added to both the higher and lower computed energy prices.
19
20
9.
Q.
DID SIERRA DEVELOP PRICE FORECASTS THAT CONSIDER
21
THE IMPACT TO FUEL AND PURCHASED POWER COSTS
22
DUE TO THE POTENTIAL REGULATION OF GREENHOUSE
23
GAS EMISSIONS IN THIS FILING?
24
A. Yes, the Company developed base, high, and low fuel price forecasts
25
using a “Mid-carbon” price trajectory for GHG emission allowances
26
under a federal cap-and-trade program that would begin in 2019. The
27
28
Reyes-DIRECT
6
3DJHRI
1
Company developed price forecasts for “High-carbon” and “Low­
2
carbon” GHG allowance pricing under the base case fuel price scenario.
3
The price forecasts for the carbon price scenarios are included as
4
Technical Appendix Item F&PP-2. The sensitivity cases evaluating the
5
impact to fuel and purchased power costs are described in the Economic
6
Analysis section of the Supply Side Plan, Economic Analysis, and
7
Financial Plan volume sponsored by Mr. Robert Kocour.
8
9
10.
Q.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
PLEASE
DESCRIBE
THE
SOURCE
FOR
CARBON
ALLOWANCE PRICES AND ITS IMPACT ON FUEL PRICES.
11
A.
NERA Economic Consulting (“NERA”) developed three carbon price
12
trajectories (Low, Mid, and High) for GHG emission allowances under a
13
federal cap-and-trade program that would begin in 2019. NERA also
14
provided estimates on the changes to the prices of fuels that could occur
15
under a potential GHG cap-and-trade program. The effects of Low, Mid
16
and High carbon prices on fossil fuels are annual percentage adjustments
17
to wholesale fossil fuel prices. Details regarding development of the
18
allowance prices and fossil fuel price adjustors are sponsored by Dr.
19
David Harrison of NERA.
20
21
11.
Q.
PLEASE
DESCRIBE
22
ADDITIONAL
23
SENSITIVITIES
24
REGULATIONS.
25
26
A.
FUEL
THE
AND
THAT
CONTEXT
FOR
PREPARING
POWER
PRICE
FORECAST
CONSIDER
FEDERAL
GHG
The “Mid-carbon” scenario was considered under the three fuel and
power price cases (base, high, and low) to determine the effect of federal
27
28
Reyes-DIRECT
7
3DJHRI
1
GHG regulations on the various resource plans under consideration. In
2
addition to the “Mid-carbon” cases two additional carbon sensitivities
3
were prepared: (1) a “High-carbon” price scenario with the base fuel and
4
purchased power price forecast; and (2) a “Low-carbon” price scenario
5
with the base fuel and purchased power price forecast.
6
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
12.
Q.
BEFORE
DETAILING
THE
PREPARATION
OF
PRICE
REFLECT
GHG
8
FORECAST
9
REGULATION, PLEASE CLARIFY WHAT YOU DESCRIBE IN
10
Q&A 10 AS THE EFFECTS OF LOW, MID, AND HIGH CARBON
11
PRICES ON FOSSIL FUEL PRICES.
12
A.
SENSITIVITIES
TO
GHG regulation under the Low, Mid and High carbon price scenarios
13
will change demand for coal and natural gas. As Dr. Harrison explains
14
in his testimony, Sierra and other owners of power plants must “cover”
15
their GHG emissions with carbon allowances. This requirement will
16
lead electric companies to modify their fuel demands. These and other
17
market effects (e.g., changes in demand from residential and commercial
18
natural gas users) will lead to changes in wholesale fossil fuel prices.
19
20
The fossil fuel price changes estimated by Dr. Harrison do not reflect a
21
direct addition of carbon allowance costs to fuel prices—i.e., burdening
22
fuel prices with a cost of carbon before they are burned in power
23
plants—because the costs associated with GHG emissions are accounted
24
for in the allowances used by each generating unit.
25
26
27
28
Reyes-DIRECT
8
3DJHRI
1
13.
Q.
PLEASE PROVIDE AN OVERVIEW OF THE METHODOLOGY
2
USED TO CONSTRUCT THE GHG PRICE FORECAST
3
SENSITIVITIES.
4
A.
Three conceptual steps were taken to compute net adjustments to the
5
fundamental fuel and purchased power price forecasts for each of the
6
carbon sensitivities. First, the natural gas price forecasts were adjusted
7
for the expected changes in fuel demands caused by GHG regulations.
8
This was accomplished by applying the percentage adjustments to the
9
commodity prices.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
Second, once natural gas prices were adjusted for the respective carbon
12
price scenario, purchased power price levels also needed to be adjusted
13
because gas prices are a key driver of power prices in the WECC. The
14
second step was accomplished with spreadsheet computations, following
15
the same methodologies used to adjust on-peak and off-peak power
16
prices in the high and low gas price cases.
17
18
Third, after the purchased power prices were adjusted for changes in gas
19
prices, the cost of carbon emissions reflected in NERA’s first set of data
20
output (carbon allowance prices) needed to be added as well. This last
21
step was the most complex because of the inherent variability in the
22
nature of the generating units (fuel types and heat rates) that can be
23
setting market clearing prices for wholesale power through the course of
24
a long-term forecast. The Company prepared estimates of the potential
25
increases to regional power prices ($/MWh) due to NERA’s carbon
26
allowance price forecasts ($/Ton) using a regional market price
27
28
Reyes-DIRECT
9
3DJHRI
1
forecasting model (called MarketPower) developed by Ventyx. In the
2
last modeling step, these price increases were added to each of the three
3
“no-carbon” power price forecasts.
4
development of the carbon power adders by utilizing the MarketPower
5
model can be found in the Load Forecast and Market Fundamentals
6
volume.
More information regarding the
7
8
14.
Q.
9
OF THE POWER PRICE FORECAST?
10
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
HOW DO YOU CAPTURE CAPACITY COSTS FOR PURPOSES
A.
WoodMac’s regional power price forecast represents day-ahead firm
11
energy prices; it does not explicitly include the full cost of new capacity
12
additions that would be required to ensure resource adequacy over the
13
forecast period. Therefore, Sierra prepares a capacity price forecast for
14
market purchases to supplement the regional power price forecast from
15
WoodMac. The regional price forecast is used in the PROMOD model
16
for economic dispatch of market purchases against internal generation,
17
while the capacity price forecast ($/kW-yr) is multiplied by the
18
Company’s open capacity position as an additional fixed fuel and
19
purchased power cost.
20
21
15.
Q.
22
23
HOW DID SIERRA PREPARE ITS LONG-TERM CAPACITY
PRICE FORECAST?
A.
WoodMac prepared an estimate of the levelized cost of new entry
24
(“CONE”) for the installed cost of future combined cycle generation.
25
The CONE is an estimate of the annual fixed costs associated with
26
owning and operating a new generating facility (i.e., exclusive of
27
28
Reyes-DIRECT
10
3DJHRI
1
variable costs such as fuel and emissions). The CONE was used to
2
compute a long-term capacity price forecast. Annual capacity prices (in
3
$/kW-year) were calculated as the difference between the CONE and the
4
net energy margins reflected in the wholesale power price forecast (i.e,
5
spark spreads).
6
7
16.
Q.
8
CERTAIN INFORMATION RELATED TO THE MARKET
9
FUNDAMENTALS DISCUSSION AND THE POWER AND GAS
10
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
IS SIERRA REQUESTING CONFIDENTIAL TREATMENT FOR
11
PRICE FORECASTS?
A.
Yes. Portions of this filing that I sponsor contain commercially sensitive
12
and/or trade secret information that derives independent economic value
13
from not being generally known. The confidential materials include
14
price forecasts that are presented in the following figures from the Load
15
Forecast and Market Fundamentals volume:
16
FIGURE PF-1 - ANNUAL AVERAGE GAS PRICE FORECAST
17
FIGURE PF-2 - MARKET IMPLIED HEAT RATE FORECAST
18
FIGURE PF-3 - AVERAGE ANNUAL POWER PRICE FORECAST
19
FIGURE PF-5 - HIGH AND LOW GAS PRICE FORECAST AT
20
MALIN
21
FIGURE PF-6 - HIGH AND LOW POWER PRICE FORECAST
22
NORTHERN NEVADA
23
FIGURE PF-13 - PURCHASED POWER PRICE INCREASES DUE
24
TO CARBON
25
FIGURE PF-14 - POWER IMPLIED HEAT RATES IN THE CARBON
26
COSTS
27
28
Reyes-DIRECT
11
3DJHRI
1
Disclosure of the confidential information to any third party would
2
adversely affect Sierra’s ability to obtain fundamental price forecast
3
information from WoodMac, a fee subscription service and recognized
4
provider and consultant for the energy industry.
5
information was provided under a confidentiality agreement with the
6
Companies, and contains essential qualitative descriptions of the
7
assumptions and methodologies used to develop the price projections.
The forecast
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
8
9
Likewise, should Sierra have open positions for electric power and
10
natural gas, the Company’s ability to obtain competitive, independent
11
Request For Proposal (“RFP”) responses could be compromised. Sierra
12
issues RFPs to fill both near-term and long-term requirements, including
13
renewable energy solicitations, to meet expected power needs.
14
Therefore, it is fundamentally contrary to the interests of the Company’s
15
customers to provide easy access to Sierra’s price forecasts for market
16
energy and fuels.
17
18
17. Q.
19
FOR HOW LONG DOES SIERRA REQUEST CONFIDENTIAL
TREATMENT?
20
A. 21
The requested period for confidential treatment is for no less than five
years.
22
23
18.
Q. WILL CONFIDENTIAL TREATMENT IMPAIR THE ABILITY
24
OF THE COMMISSION’S REGULATORY OPERATIONS STAFF
25
(“STAFF”)
OR
THE
NEVADA
ATTORNEY
GENERAL’S
26
27
28
Reyes-DIRECT
12
3DJHRI
1
BUREAU OF CONSUMER PROTECTION (“BCP”) TO FULLY
2
INVESTIGATE THE INTEGRATED RESOURCE PLAN?
3
A. No, in accordance with the accepted practice in Commission
4
proceedings, Sierra will provide the confidential material to Staff and the
5
BCP under standardized protective agreements.
6
7
8
19.
Q.
DOES THIS CONCLUDE YOUR TESTIMONY?
A. Yes, it does.
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Reyes-DIRECT
13
3DJHRI
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 Manager of Market Fundamentals 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.
Since May 2011, I have been employed as the Manager of Market Fundamentals. I am
responsible for leading a staff of economists who perform fundamental analysis and
market price forecasting for natural gas and wholesale power in the western U.S. I
evaluate the process used to forecast natural gas and power prices and implement changes
as markets evolve.
I prepare reports and communicate the findings of analysis to
management.
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
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
1
3DJHRI
Exhibit Reyes-Direct-1
Page 2 of 2
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 dayahead and term traders to optimize the company portfolio in the Western Electric
Coordinating Council and Southwest Power Pool regions.
2
3DJHRI
3DJHRI
JOSEPH R. BRIGNOLA 3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-_____
4
PREPARED DIRECT TESTIMONY OF
5
Joseph R. Brignola
6
7
1.
Q.
STATE
YOUR
NAME,
OCCUPATION,
AND
BUSINESS ADDRESS.
8
A. 9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
PLEASE
My name is Joseph R. Brignola. I am Manager, Coal Supply &
10
Operations for Sierra Pacific Power Company d/b/a/ NV Energy (“Sierra
11
Pacific Power” or the “Company”) and Nevada Power Company d/b/a/
12
NV Energy (“Nevada Power” and, together with Sierra Pacific Power,
13
the “Companies”). My business address is 6226 West Sahara Avenue,
14
Las Vegas, Nevada. I am filing testimony on behalf of Sierra.
15
16
2. Q.
PLEASE DESCRIBE YOUR RESPONSIBILITIES AS MANAGER,
17
COAL
18
COMPANIES.
A. 19
PROCUREMENT
AND
OPERATIONS
FOR
THE
As Manager, Coal Procurement & Operations, I am responsible for all
20
aspects of coal supply and planning as well as the management of coal
21
supply logistics for the Companies.
22
23
3.
Q.
DOES EXHIBIT BRIGNOLA-DIRECT-1 TO YOUR TESTIMONY
24
DESCRIBE
25
EXPERIENCE?
26
A.
YOUR
EDUCATION
AND
EMPLOYMENT
Y
es.
27
28
Brignola – DIRECT 1
3DJHRI
1
4.
Q.
2
WHAT IS THE PURPOSE OF YOUR PREFILED DIRECT
TESTIMONY IN THIS PROCEEDING?
3
A.
I support the following portions of the “Load Forecast and Market
4
Fundamentals” volume: Section 2.C (“Coal Fundamentals”) and Section
5
3.G (“Coal Price Forecast”).
6
7
In addition, I support the following portion of the “Supply Side Plan,
8
Economic Analysis, and Financial Plan” volume:
9
(“Current Coal Purchase and Transportation Agreements”).
Section 2.C.4.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
11
I also sponsor the portions of Technical Appendix Items F&PP-1 and
12
F&PP-2, and that relate to the coal price forecast.
13
14
5. Q.
IS SIERRA REQUESTING CONFIDENTIAL TREATMENT OF
15
CERTAIN INFORMATION RELATED TO THE COAL PRICE
16
FORECAST?
17
A. Yes. The Company is requesting confidential treatment of its coal price
18
forecast, which incorporates projected coal transportation costs. Sierra’s
19
coal price forecast contains commercially sensitive and/or trade secret
20
information that derives independent economic value from not being
21
generally known.
22
expectations of the relevant markets and its future procurement plans.
23
This information is not known outside the Companies and its distribution
24
is limited within the Companies.
25
information would disadvantage Sierra by limiting its ability to foster
26
competition among prospective suppliers, compromising Sierra’s
27
negotiating position and reducing its bargaining leverage. Publication of
28
Brignola – DIRECT This information discloses Sierra’s views and
Releasing this highly sensitive
2
3DJHRI
1
this information would unfairly advantage competing coal buyers and
2
impair Sierra’s ability to achieve the most favorable pricing and terms
3
and conditions from suppliers on behalf of its customers.
4
5
6.
Q.
6
FOR HOW LONG DOES SIERRA PACIFIC POWER REQUEST
CONFIDENTIAL TREATMENT?
7
A. 8
The requested period for confidential treatment is for no less than five
years.
9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
7.
Q. WILL CONFIDENTIAL TREATMENT IMPAIR THE ABILITY
11
OF THE COMMISSION’S REGULATORY OPERATIONS STAFF
12
(“STAFF”) OR THE ATTORNEY GENERAL’S BUREAU OF
13
CONSUMER
14
INVESTIGATE THE 2013 RESOURCE PLAN?
PROTECTION
(THE
“BCP”)
TO
FULLY
15
A. No, in accordance with the accepted practice in Commission
16
proceedings, the confidential material will be provided to Staff and the
17
BCP under standardized protective agreements with them.
18
19
20
8.
Q. DOES THIS CONCLUDE YOUR TESTIMONY?
A. Yes, it does.
21
22
23
24
25
26
27
28
Brignola – DIRECT 3
3DJHRI
Exhibit Brignola Direct-1
Page 1 of 1
QUALIFICATIONS OF WITNESS
Joseph R. Brignola Manager, Coal Procurement & Operations
NV Energy
6226 West Sahara Avenue Las Vegas, NV 89151-001 (702) 402-5766
EMPLOYMENT EXPERIENCE
Fall 1999 – Present:
NV Energy, Inc.
Manager, Coal Procurement & Operations; Fuels Consultant
Responsible for conducting the Company’s coal supply and planning programs for the Reid
Gardner, North Valmy and jointly owned stations.
July 1993 – Fall 1999: Nevada Power Company
Director of Fuels Planning & Procurement; Manager of Fuels;
Fuels Analyst
Responsible for administering and improving the Company’s fuels supply and planning program
including coal and natural gas procurement, transportation, analysis, developing policies and
formulating strategy. Led negotiating teams and administered coal and gas supply and
transportation agreements.
April 1979 – July 1993:
Atlantic Energy (now PEPCO)
Manager, Fuels; Supervisor, Power Economics; Fuels Engineer
Responsible for administering all aspects of the Company’s fuels supply program encompassing
contracting, procurement, transportation, developing policies and strategies for coal, natural gas,
and fuel oil and regulatory relations. Also managed the heat rate improvement program and
power plant water treatment activities.
EDUCATION
B.S. Chemical Engineering
New Jersey Institute of Technology
3DJHRI
3DJHRI
ANITA L. HART 3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014-2033 Integrated Resource Plan
Docket No. 13-07____
4
PREPARED DIRECT TESTIMONY OF
5
Anita L. Hart
6
7
1.
Q.
8
AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
9
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS
A.
My name is Anita L. Hart. I am filing testimony on behalf of Sierra Pacific
10
Power Company d/b/a NV Energy (“Sierra” or the “Company”). My current
11
position is Manager, Gas Transportation Planning for Sierra and Nevada Power
12
Company d/b/a NV Energy (“Nevada Power,” and together with Sierra, the
13
“Companies”). My business address is 6226 West Sahara Avenue in Las Vegas,
14
Nevada.
15
16
2.
Q.
17
18
PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE
UTILITY INDUSTRY.
A.
My professional experience includes twenty years in the utility industry. In
19
addition, I have a Master of Arts in Economics with an emphasis in Public Utility
20
Regulation. Before joining the Resource Planning department, I held a position in
21
DSM Planning where I was responsible for evaluating and developing a portfolio
22
of cost-effective Energy Efficiency and Conservation (“EE&C”) programs for
23
implementation in the Companies’ service territories.
24
25
Prior to my commencement of employment with the Companies in 2008, I was
26
employed as the Manager of Demand Side Management and Market Research at
27
28
Hart-DIRECT
1
3DJHRI
1
Southwest Gas Corporation (“SWG”). Over a span of fifteen years my key
2
responsibilities at SWG included: 1) resource planning and demand forecast
3
modeling and analysis; 2) development and maintenance of tariffs, applications,
4
and filings before three state regulatory agencies, consistent with regulatory, legal
5
and company requirements; 3) development, approval, implementation and
6
management of DSM, Energy Efficiency and Low-Income programs and 4)
7
market research. Additional detail about my educational and employment history
8
is provided in Exhibit Hart-Direct-1.
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
9
10
3.
Q.
11
PLEASE DESCRIBE YOUR RESPONSIBILITIES AS MANAGER, GAS
TRANSPORTATION PLANNING.
12
A.
As the Manager of Gas Transportation Planning I am responsible for the planning
13
and analysis of natural gas transportation needs and ensuring sufficient supply to
14
the generation fleet for the Companies along with the natural gas Local
15
Distribution Company (“LDC”). These responsibilities include the development
16
and implementation of work plans to support the corporate contract negotiations,
17
planning, budgeting, controls, portfolio optimization, cost reduction, and risk
18
management.
19
20
4.
Q.
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
21
22
HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
A.
Yes, I have testified in several proceedings before the Commission, in addition to
23
the California Public Utilities Commission and the Arizona Corporation
24
Commission.
25
26
27
28
Hart-DIRECT
2
3DJHRI
1
5.
2
Q.
WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. I am sponsoring Section 2.C.1 (“Fuel Supply - Current Physical Gas Supply”),
3
Section 2.C.2 (“Fuel Supply – Physical Gas Procurement”), and Section 2.C.3
4
(“Fuel Supply - Current Oil Supply”) of Sierra’s 2013 Integrated Resource Plan.
5
In addition, together with Dr. Hossein Haeri, I am sponsoring Section 2.C.5
6
(“Fuel Supply – Fuel Diversity Evaluation”).
7
8
6.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
Q.
ARE YOU SPONSORING ANY EXHIBITS?
A. Yes. I am sponsoring the following Exhibits:
10
Exhibit Hart-Direct-1 Statement of Qualifications
11
12
13
7.
Q.
PLEASE DESCRIBE SIERRA’S CURRENT PHYSICAL GAS SUPPLY.
A. Section 2.C.1 of the Supply Side Plan summarizes the Company’s current
14
physical gas supply. Sierra takes delivery of natural gas from two interstate
15
pipelines: Paiute Pipeline Company (“Paiute”) and Tuscarora Gas Transmission
16
Company (“Tuscarora”). Paiute delivers gas supplies from upstream pipeline
17
Williams – Northwest Pipeline (“Northwest”). Northwest sources its gas supplies
18
from British Columbia, the San Juan Basin, and the Rocky Mountain region of
19
Wyoming, Utah and Colorado. Tuscarora delivers gas supplies from upstream
20
pipeline Gas Transmission Northwest (“GTN”), which is connected to the gas
21
producing regions of the Western Canada Sedimentary Basin in Alberta, Canada
22
through TransCanada Pipelines. Within Alberta, TransCanada’s NOVA pipeline
23
system carries the gas from the AECO producing areas to the Alberta/British
24
Columbia border.
25
TransCanada’s BC System, which transports gas to TransCanada’s GTN system
26
at the United States/Canadian border near Kingsgate, Idaho. The GTN pipeline is
From there the Alberta System interconnects with
27
28
Hart-DIRECT
3
3DJHRI
1
currently undersubscribed (i.e., has excess capacity) and as such Sierra can
2
procure any needed gas supplies at the Malin (Oregon) hub should its gas load
3
requirements exceed upstream gas transport contract volumes.
4
5
Q.
DID SIERRA EVALUATE THE ADEQUACY OF THE CURRENT FIRM
6
INTERSTATE GAS TRANSPORTATION CONTRACTS TO ENSURE
7
SUFFICIENT NATURAL GAS SUPPLY TO THE SIERRA GENERATION
8
FLEET ALONG WITH THE NATURAL GAS LDC?
9
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
8.
A.
Yes, for the 2014-2016 Sierra Energy Supply Plan (“ESP”), PROMOD was used
10
to further evaluate the system reliability and projected firm gas transportation
11
needs for both the plant and LDC with ON Line in service. The following three
12
scenarios were evaluated: 1) Normal weather conditions and existing natural gas
13
transportation contracts; 2) Extreme weather conditions (based on 70 HDDs) and
14
existing natural gas transportation contracts; and 3) Same as (“2”) above, except
15
with 10,000 MMBtus of capacity from existing natural gas transport contracts
16
Paiute removed.
17
18
The key finding from this analysis is that Sierra will have enough firm
19
transportation/storage contracts to meet the average daily gas supply required on a
20
winter day under normal weather conditions with the availability of generation
21
from the southern system via ON Line. However, during an extreme winter
22
weather scenario 75 percent of the firm gas transport capacity will be needed to
23
supply the LDC requirements, limiting the use of natural gas generation plants at
24
Sierra.
25
scenario only 25 percent of the electric requirements will be met with the natural
26
gas plants. In the extreme case, the majority of the electric requirements will be
The PROMOD results indicate that on the extreme winter weather
27
28
Hart-DIRECT
4
3DJHRI
1
met with a combination of coal, purchase power, renewable energy, Newmont,
2
and inter-company exchange from the southern system. Noteworthy in both the
3
extreme weather scenario and the extreme less 10,000 MMBTUs of capacity
4
scenario, there were loss of load hours on the electric system, albeit small
5
(approximately 0.1 percent). Sierra believes the low loss of load hours observed
6
in these extreme cases are not at a significant level that would warrant any
7
changes to the current gas transportation strategy at this time.
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
8
9
Sierra’s proposed gas transportation strategy for the Action Plan period including
10
the detailed results of the firm transportation analysis is set forth in Section 5.B of
11
Sierra’s 2013 ESP. Basically, my analysis demonstrates that the Company has
12
adequate gas transportation capacity. Adding additional capacity would mitigate
13
a remote loss of load risk, but would increase costs. Reducing capacity would
14
increase the risk of loss of load in the winter to a level that is, in the Company’s
15
view, unacceptable.
16
17
9.
Q.
18
19
PLEASE DESCRIBE SIERRA’S PHYSICAL GAS PROCUREMENT
PLAN.
A.
Section 2.C.2 of the IRP summarizes the Company’s physical gas procurement
20
plan. Sierra is requesting acceptance and approval of its plan to continue the
21
implementation of the four-season laddering strategy approved by the
22
Commission in the Stipulation in Docket No. 12-08010 to procure physical gas.
23
Pursuant to the four-season laddering strategy, the Company will procure 25
24
percent of projected monthly physical gas requirements per season for four
25
seasons, subject to the availability of conforming bids and the willingness of
26
suppliers to accept reasonable commercial terms. Physical gas volumes are to be
27
28
Hart-DIRECT
5
3DJHRI
1
procured at indexed prices, subject to a per MMBtu premium cap. The per
2
MMBtu premium cap may be exceeded with prior approval from the Company’s
3
Energy Risk Committee (“ERC”).
4
Company will provide written notice to Regulatory Operations Staff of the
5
Commission (“Staff”) and the Bureau of Consumer Protection (“BCP”).
6
Furthermore, targeted physical gas volumes will exclude any potential gas-fired
7
generation to meet forward sales; gas needed to meet forward sales will only be
8
procured in the short-term.
If Sierra exceeds the premium cap, the
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
10.
Q.
IS
SIERRA
REQUESTING
CONFIDENTIAL
TREATMENT
FOR
11
CERTAIN INFORMATION RELATED TO THE PHYSICAL GAS
12
PROCUREMENT PLAN?
13
A.
Yes. Portions of Sierra’s physical gas procurement plan contain the premiums
14
that the Company may be willing to pay for physical gas supplies.
15
confidential information is commercially sensitive and/or trade secret information
16
that derives independent economic value from not being generally known.
17
Disclosure of this confidential information to any third party would adversely
18
affect Sierra’s ability to obtain favorable terms from its gas suppliers.
This
19
20
11. Q.
21
22
FOR HOW LONG DOES SIERRA POWER REQUEST CONFIDENTIAL
TREATMENT?
A.
The requested period for confidential treatment is for no less than five years.
23
24
12. Q.
25
WILL CONFIDENTIAL TREATMENT IMPAIR THE ABILITY OF
STAFF OR THE BCP TO FULLY INVESTIGATE THE FILING?
26
27
28
Hart-DIRECT
6
3DJHRI
1
A. No, in accordance with the accepted practice in Commission proceedings, Sierra
2
will provide the confidential material to Staff and the BCP under standardized
3
protective agreements.
4
5
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
6
13.
Q.
PLEASE DESCRIBE SIERRA’S CURRENT OIL SUPPLY.
A.
Section 2.C.3 of the IRP summarizes the Company’s current oil supply. Sierra’s
7
LDC operations rely on flowing natural gas supply through interstate pipelines to
8
meet retail customer requirements. During extreme cold weather events or during
9
a force majeure event on an interstate pipeline, natural gas supply scheduled to
10
Sierra’s power plants may be diverted to support LDC natural gas supply
11
operations. Tracy Unit 3 and both Ft. Churchill units are currently capable of
12
firing No. 6 oil; however, No. 6 oil will be prohibited to be combusted under the
13
BART compliance regulations as of January 1, 2015. Thus, as part of this filing,
14
Sierra is requesting the retirement of oil firing capabilities on Tracy Unit 3 and
15
both Ft. Churchill units. The details of this request can be found in Section 2.A.3
16
of the Supply Side Plan and supported by Mr. Lescenski in his direct testimony.
17
Sierra will maintain diesel inventories at Clark Mountain Peakers 3 and 4 as an
18
alternate fuel during emergency events only to allow the use of existing pipeline
19
transportation capacity to support peak LDC use and for black start situations.
20
21
The No. 6 oil was recently removed from the storage tank at Clark Mountain.
22
The tank has undergone a thorough cleanse to remove the sludge at the bottom of
23
the tank and will be re-filled with approximately 634,000 gallons of No. 2 (diesel)
24
oil to run the plant for 48 hours during an emergency.
25
26
27
28
Hart-DIRECT
7
3DJHRI
1
14.
PLEASE DESCRIBE WHY SIERRA IS RECOMMENDING THE
2
REMOVAL OF OIL FIRING CAPABILITIES ON TRACY UNIT 3 AND
3
BOTH FT. CHURCHILL UNITS.
4
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
Q.
A.
In addition to the avoidance of the high capital costs related to compliance with
5
the 2015 BART regulations along with the higher costs of No. 6 oil as described
6
in Section 2.A.3 of the Supply Side Plan, the majority of the emergency
7
generation oil backup provided to this point can be met through the dispatch of
8
units in southern Nevada via ON Line. Thus, on days with extreme cold weather
9
or emergency situations when these units might be dispatched the void will be
10
filled by a combination of generation from the southern Nevada units and if
11
needed in an extreme emergency event (such as the disruption of a natural gas
12
pipeline) oil-fired generation at Clark Mountain.
13
14
Moreover, the Fuel Diversity Evaluation, included in Technical Appendix FUEL­
15
1, concludes that there is not a significant difference in the risk profile of these
16
units in a gas-firing and dual fuel-firing operating scenario for these units.
17
Additional details are also included in Fuel Supply section (Section 2.C.5) of the
18
Supply Side Plan.
19
20
15.
Q.
21
22
HOW DOES SIERRA EVALUATE THE FUEL DIVERSITY OF ITS
SUPPLY PORTFOLIO?
A.
Historically the Companies have regularly evaluated the operation of their energy
23
generation resources and the acquisition of new resources to meet customer
24
demand with an emphasis on least-cost planning. With historically lower natural
25
gas prices and increasing environmental regulation costs, the policy of least-cost
26
planning may lead the Companies to consider a future electric generation
27
28
Hart-DIRECT
8
3DJHRI
1
portfolio that is primarily focused on natural gas-fired generation. While such a
2
supply portfolio may be expected to cost less, it may expose the Companies and
3
its customers to higher than acceptable price risks in certain scenarios. Therefore,
4
through a competitive RFP process, NV Energy contracted with The Cadmus
5
Group, Inc. (“Cadmus”), in developing a methodology to evaluate the fuel
6
diversity of its supply portfolio.
7
8
16.
Q.
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
9
10
PLEASE SUMMARIZE THE METHODOLOGY USED IN THE FUEL
DIVERSITY EVALUATION?
A.
Cadmus used their proprietary model, RP Strategist, to develop a mean-variance
11
efficiency frontier (“Efficiency Frontier”) for the Companies electricity
12
generation portfolio. The Efficiency Frontier is a framework for comparing costs
13
and risks of alternative generation portfolios.
14
different scenarios, Cadmus was able to construct an Efficiency Frontier in which
15
it is not possible to reduce the risks (susceptibility to electric market and gas price
16
fluctuations) of a given portfolio without increasing its expected cost, and vice
17
versa.
By investigating a number of
18
19
Any portfolio of generation resources a utility chooses for further evaluation
20
should lie on or as close as possible to the Efficiency Frontier. A portfolio that
21
lies away from the Efficiency Frontier indicates that either cost can be reduced
22
without affecting the riskiness of the portfolio or risks can be lowered without
23
affecting the cost of the portfolio. Figure AH-1 illustrates the Efficiency Frontier
24
concept. The gray dotted line represents the Efficiency Frontier for portfolios,
25
including only fossil fuels, while the solid black line represents the frontier when
26
renewable generation is added to portfolios.
27
28
Hart-DIRECT
9
3DJHRI
1
Figure AH-1: Simple Efficiency Frontier Example
2
3
4
5
6
7
8
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
9
10
11
Renewable energy sources typically do not suffer from fuel price volatility but
12
tend to be more expensive. Natural gas falls on the other end of the spectrum: it is
13
susceptible to fuel price volatility but generally has a lower cost. Note that the
14
derivative of the Efficiency Frontier does not need to be continuous.
15
16
17
17.
Q.
WHAT WAS THE SCOPE OF THIS PROJECT?
A.
In addition to an evaluating the four current portfolios presented in the 2012
18
Nevada Power IRP, Docket No. 12-06053, the Cadmus study analyzed the risks
19
and costs associated with the following three assumptions:
20
x
21
The impact of early retirement of all or some of the operating coal plants
(scenarios 1 through 9);
x
22
23
The impact of retiring all or some of the oil backup plants at Sierra (scenario
12); and
x
24
The risk associated with reliance on one primary gas supply line for a
25
predominantly gas-based generation fleet at Nevada Power (scenarios 10, 11
26
and 12).
27
28
Hart-DIRECT
10
3DJHRI
1
18.
Q.
PLEASE DESCRIBE THE EFFICIENCY FRONTIER CREATED FOR
2
3
THE COMPANIES?
A.
In Figure AH-2 Cadmus plotted the positions of the various scenarios with respect
4
to their cost and risks. The dotted line approximates the Efficiency Frontier for
5
NV Energy’s various resource portfolios.
6
information in tabular format and includes the additional scenarios considered in
7
the Cadmus study.
8
Table AH-1 shows the same
Figure AH-2: NV Energy Efficiency Frontier
PORTFOLIO COST VS. RISK
10
10.0%
11
9.8%
12
9.6%
13
14
15
16
17
Risk: Total Costs (σ/μ)
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
2012 NPC IRP Case 3
2012 NPC IRP Case 2
2012 NPC IRP Case 1
9.4%
No Coal Beyond 2013
2012 NPC IRP Case 4
9.2%
Early Coal Retirement
Legislation - Early Market
Purchases
Early Coal Retirement Aggressive DSM
9.0%
Early Coal Retirement
Legislation - Early Replacement
with Gas
8.8%
EFFICIENCY FRONTIER
8.6%
8.4%
18
Early Coal Retirement
Legislation - Aggressive
Replacement with Solar
8.2%
19
8.0%
3.20
20
3.25
3.30
3.35
3.40
3.45
3.50
3.55
3.60
3.65
3.70
Mean Portfolio Cost: (¢/kWh)
21
22
23
The horizontal axis, ¢/kWh, is a measure of the mean present value of resource
24
costs over the 20-year planning horizon, compared with the total energy generated
25
over the same period.
26
market purchase costs, fuel costs, along with fixed and variable operations and
Resource costs include capital costs, emission costs,
27
28
Hart-DIRECT
11
3DJHRI
1
maintenance (O&M) costs. Portfolios on the far right portion of Figure AH-2 are
2
more expensive than portfolios to the left.
3
4
The vertical axis shows the risk of each portfolio, measured as the ratio of the
5
standard deviation and the mean of the present value of each portfolio’s cost over
6
the 20-year planning horizon, divided by the mean present value of resource costs
7
over the 20-year planning horizon also referred to as the coefficient of variation –
8
or CV.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
Table AH-1: NV Energy Efficiency Frontier Data
10
11
Scenario
Scenario Description
Mean
Portfolio Cost
(million $)
Mean Portfolio
Cost
(¢ / kWh)
Cost Risk
(σ/μ)
$24,537
3.301
9.4%
$24,866
3.345
9.5%
$24,372
3.279
9.6%
12
1
2012 NPC IRP Case 1
14
2
2012 NPC IRP Case 2
15
3
2012 NPC IRP Case 3
16
4
2012 NPC IRP Case 4
$24,971
3.359
9.2%
17
5
Early Coal Retirement Legislation - Early
Replacement with Gas
$26,234
3.529
8.8%
18
6
Early Coal Retirement Legislation - Early
Market Purchases
$25,843
3.477
9.3%
7
Early Coal Retirement Legislation ­
Aggressive Replacement with Solar
$27,171
3.656
8.3%
8
Early Coal Retirement - Aggressive DSM
$25,259
3.398
9.1%
9
No Coal Beyond 2013
$26,236
3.530
9.4%
10
2012 NPC IRP Case 2 - 10 year forecast /
200 iterations
$13,017
3.768
13.5%
11
2012 NPC IRP Case 2 - 10 year forecast /
500 iterations
$13,062
3.792
13.2%
12
2012 NPC IRP Case 2 - 10 year forecast /
500 iterations + Oil Backup
$13,191
3.829
13.1%
13
19
20
21
22
23
24
25
26
27
28
Hart-DIRECT
12
3DJHRI
1
19.
Q.
2
EVALUATION?
3
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
WHAT WERE THE RESULTS FROM THE FUEL DIVERSITY
A.
Based on the results of the analysis, as can be seen graphically in Figure AH-2,
4
the following conclusions may be drawn:
5
x
The early retirement of coal facilities increases the costs of the Companies
6
generation portfolio, owing to the additional capital costs required to
7
accelerate the development of replacement natural gas facilities, renewable
8
generation, and expanded DSM. Note that none of the four IRP scenarios
9
assumes an early retirement of coal (scenarios 1-4 vs. scenarios 5-9).
x
10
In the Early Coal Retirement - Aggressive DSM scenario (scenario 8), a bulk
11
of the lost generation from coal retirement is replaced by aggressive DSM
12
program savings. Of the early coal retirement scenarios, this is the least-cost
13
option and exhibits a moderate level of risk in relation to the other scenarios.
14
The lost revenue resulting from DSM programs is not factored into this
15
scenario, nor does this scenario consider the possible risks associated with the
16
realization of DSM savings. This scenario is likely to have slightly higher
17
risks and costs than the figure suggests1.
x
18
Aggressively expanding renewable generation results in a higher cost but
19
lower relative risk (Early Coal Retirement Legislation – Aggressive
20
Replacement with Solar, scenario 7). Costs are higher due to the capital costs
21
associated with renewable development, but risks are lower because a smaller
22
proportion of the total portfolio is susceptible to fuel price volatility.
23
24
25
1
26
27
28
All the scenarios analyzed in this study included existing and forecasted cost and savings assumptions from NV
Energy’s Preferred DSM Plan. Lost revenues and DSM cost and savings uncertainty were not incorporated for these
assumptions either. Including them would shift all points in Figure AH-2 slightly to the right and up, as including
these factors would slightly increase both cost and risks of the portfolios.
Hart-DIRECT
13
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
1
x The Early Coal Retirement Legislation – Early Replacement with Gas
2
scenario (scenario 6), in which retired coal generation is replaced with gas
3
generation early in the planning horizon, appears to lie close to the Efficiency
4
Frontier. The Early Coal Retirement Legislation – Early Market Purchases is
5
a similar scenario, except gas generation expansion is delayed until 2017 and
6
the retired coal generation is replaced in 2014 through 2016 with market
7
purchases. The latter scenario exhibits slightly lower costs but higher risks
8
than the former scenario, primarily due to its lower capital costs but higher
9
exposure to market price volatility in the early years.
10
x In the No Coal Beyond 2013 scenario (scenario 9), all coal facilities are
11
retired before 2014 and replaced with gas generation as early as possible.
12
This scenario lies away from the Efficiency Frontier. Capital costs are much
13
higher in this scenario relative to others, and risks increase because coal
14
generation, with more stable fuel prices, is being replaced with more volatile
15
fuel price gas generation.
16
17
Three additional scenarios (scenarios 10-12), not shown in Figure AH-2, were
18
considered to assess the impact on NV Energy of having one main gas supply line
19
for the southern system (which makes the utility susceptible to a major disruption
20
in natural gas supply). These scenarios were handled by adding a small number
21
of gas price shocks to the analysis to simulate a disruption, but this caused a near
22
negligible increase in mean portfolio costs and a small reduction in risk.
23
24
The results of this analysis were inconclusive due to the dramatic economy-wide
25
implications of such low-probability, extremely high-cost events with
26
consequences beyond the Companies production costs.
27
28
Hart-DIRECT
14
3DJHRI
1
As a final scenario, Cadmus tested the impacts of retaining oil backup at Ft.
2
Churchill and Tracy 3 (scenario 12). This portfolio resulted in slightly increased
3
costs coupled with small reductions in risk. The reason for this may be that the
4
oil generation adds to the capital costs of the portfolio, but does slightly reduce
5
NV Energy’s exposure to a large financial penalty for any disruption in gas
6
supply. Compared to the scenario in which oil backup was not retained, the
7
increase in costs and decrease in risk were both less than one percent, not
8
significant enough to justify making a decision on the results.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
20.
Q.
11
PLEASE EXPLAIN THE FUTURE USE OF THE CADMUS MODEL AND
RESULTS OF THE FUEL DIVERSITY EVALUATION.
12
A.
Cadmus’ analysis was not intended to provide the Companies with the optimal
13
electricity generation portfolio.
14
optimal portfolio; rather, it compared a set of portfolios from a risk/cost
15
perspective. The initial results provide informative correlations between various
16
fuel source mixes.
The Efficiency Frontier does not isolate an
17
18
In the future, the Companies may use RP Strategist as a screening tool and further
19
test some of the more efficient portfolio scenarios in PROMOD. With a more in-
20
depth, operational analysis of the costs and risks, the Companies will determine
21
the preferred portfolio.
22
23
The complete report from Cadmus may be found in Technical Appendix FUEL-1.
24
25
26
21.
Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A.
Yes.
27
28
Hart-DIRECT
15
3DJHRI
Exhibit Hart-Direct-1
Page 1 of 2
STATEMENT OF QUALIFICATIONS OF WITNESS
ANITA L. HART
NEVADA POWER & SIERRA PACIFIC POWER COMPANIES d/b/a NV Energy
6226 W. Sahara Ave.
Las Vegas Nevada 89146
(702) 402-2165
I am Anita L. Hart, Manager, Gas Transportation Planning responsible for the planning and
analysis of natural gas transportation needs and ensuring sufficient supply to the generation fleet
for the Companies along with the natural gas Local Distribution Company (“LDC”). These
responsibilities include the development and implementation of work plans to support the
corporate contract negotiations, planning, budgeting, controls, portfolio optimization, cost
reduction, and risk management. I began this position in June 2012.
I graduated from New Mexico State University (NMSU) in 1989 with a Bachelor of Art in
Economics. In 1992, I received a Master of Arts in Economics from NMSU with an emphasis in
public utilities and regulatory economics. During my Master’s studies, I completed an internship
at Public Service Company of New Mexico in their Regulation and Market Communication
department.
Following my studies at NMSU, I began work at Southwest Gas Corporation (Southwest) in
1993, as a Regulatory Analyst in the Revenue Requirements and Resource Planning Department.
My responsibilities included the collection, maintenance and statistical analysis of customer
profile data. In addition, I assembled and processed information necessary for exhibits and
commission filings.
In 1997, I transitioned into the Marketing/Conservation and DSM Department as a Specialist. In
1998, I was promoted to Administrator in the same department. While in these positions, I was
responsible for evaluating, developing and defending a portfolio of cost effective Energy
Efficiency and Conservation (“EE&C”) programs and low income assistance programs for
implementation in the Southwest’s tri-state service territories.
In 2005, I transferred to State Regulatory Affairs as a Senior Specialist. In this position I
prepared and maintained tariffs, applications, and filings before the state regulatory agencies,
consistent with regulatory, legal and company requirements. I represented the company at
meetings with executive staff of the respective state commissions and accompanied senior
management at meetings with Commissioners and their aides.
In 2007, I was promoted to Manager, State Regulatory Affairs/Research, Conservation and
DSM. In this position, I managed a professional staff (internal and external) responsible for
developing, implementing, administering, evaluating and reporting on DSM, EE&C and low
income assistance programs. Concurrently, I directed the development and implementation of
3DJHRI
Exhibit Hart-Direct-1
Page 2 of 2
customer market research information, including the appropriate statistical models to create the
required customer samples.
In August 2008, I joined NV Energy (previously Nevada Power) as Consultant Staff, DSM
Planning, Customer Programs and Strategy where I was responsible for evaluating and
developing a portfolio of cost effective EE&C programs for implementation in the NV Energy’s
service territories.
3DJHRI
3DJHRI
LAWRENCE M. HOLMES 3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13­
4
PREPARED DIRECT TESTIMONY OF
5
Lawrence M. Holmes
6
7
1.
Q.
8
ADDRESS.
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
A.
My name is Lawrence M. Holmes.
I am the Manager, Customer
10
Strategy and Programs for Sierra Pacific Power Company d/b/a NV
11
Energy (“Sierra” or the “Company”) and Nevada Power Company d/b/a
12
NV Energy (“Nevada Power” and, together with Sierra, the
13
“Companies”). My business address is 6226 West Sahara Avenue in Las
14
Vegas, Nevada. I am filing testimony on behalf of Sierra.
15
16
2.
Q.
17
18
PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND
AND EXPERIENCE.
A. I have a Master of Science degree in Electrical Engineering and I am a
19
Registered Professional Engineer in the State of Nevada. I also am a
20
Certified Energy Manager. Since starting at Sierra in 1981, I have held a
21
variety of positions with both management and technical responsibilities
22
in design, planning, customer operations, new business, economic
23
development and regulatory affairs.
24
professional background and experience are set forth in my Statement of
25
Qualifications, included as Exhibit Holmes-Direct-1.
More details regarding my
26
27
28
Holmes-DIRECT
1
3DJHRI
1
3.
Q.
2
3
PROCEEDING?
A.
Together with witnesses Michael Brown, Kelly Vagianos, Zelkjo
4
Vukanovic and Michelle Lindsay, I sponsor and present the Demand
5
Side Management Plan (“DSM Plan”) set forth in Sierra’s 2014 – 2033
6
Integrated Resource Plan (“IRP”).
7
summarizes Sierra’s request for approval of Sierra’s preferred demand
8
side management plan (the “Preferred DSM Plan”).
9
sponsor and support all parts of the DSM Plan not sponsored or
10
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
My testimony describes and
In addition, I
supported by witnesses Brown, Vagianos, Vukanovic, and Lindsay.
11
12
I also support Sierra’s requests that the Commission find that the DSM
13
Plan complies with:
14
a. Ordering Paragraph 11 of the Commission’s order issued
15
December 24, 2012 in consolidated Docket Nos. 12-06052 and
16
12-06053. That directive requires:
17
18
Nevada Power Company d/b/a NV Energy and Sierra Pacific
19
Power Company d/b/a NV Energy, for all Integrated
20
Resource Plan Demand Side Management Plans and Annual
21
Demand Side Management Update Reports, shall serve upon
22
Staff and the BCP at the same time it files its initial
23
application, all information and all supporting data in
24
executable format upon which it relies to develop benefit/cost
25
calculations related to Demand Side Management programs
26
and lost revenue calculations for Demand Side Management
27
28
Holmes-DIRECT
2
3DJHRI
1
programs. This information and supporting data includes, but
2
is not limited to, all spreadsheets and calculations prepared
3
by any out-side Measurement and Verification contractors
4
and consultants executable and manipulative format.
5
6
b. Ordering Paragraph 12 of the Commission’s order issued on
7
December 24, 2012 in consolidated Docket Nos. 12-06052 and
8
12-06053. That directive requires:
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
Nevada Power Company d/b/a NV Energy and Sierra
11
Pacific Power Company d/b/a NV Energy, for all future
12
Integrated Resource Plan Demand Side Management Plans
13
and Annual Demand Side Management Update Reports,
14
shall include a discussion of, and support for, the
15
development of load shapes (energy savings profiles).
16
17
c.
The first Ordering Paragraph 13 of the Commission’s order
18
issued December 24, 2012 in consolidated Dockets Nos. 12­
19
06052 and 12-06053. That paragraph provides:
20
21
Nevada Power Company d/b/a NV Energy and Sierra
22
Pacific Power Company d/b/a NV Energy, for all future
23
Integrated Resource Plan Demand Side Management Plans
24
and Annual Demand Side Management Update Reports,
25
shall include documentation for all incremental cost
26
calculations.
27
28
Holmes-DIRECT
3
3DJHRI
1
d.
Ordering Paragraph 14 of the Commission’s order issued March
2
23, 2012 in consolidated Docket Nos. 12-06052 and 12-06053.
3
That paragraph provides:
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
4
5
Nevada Power Company d/b/a NV Energy and Sierra Pacific
6
Power Company d/b/a NV Energy, for all future Integrated
7
Resource Plan Demand Side Management Plans and Annual
8
Demand Side Management Update Reports, shall utilize the
9
measure life as presented in the latest Measurement and
10
Verification reports unless documentation is provided to
11
support a changed measure life.
12
13
e.
O
rdering Paragraph 15 of the Commission’s order issued
14
December 24, 2012 in consolidated Docket Nos. 12-06052 and
15
12-06053. That paragraph provides:
16
17
Nevada Power Company d/b/a NV Energy and Sierra
18
Pacific Power Company d/b/a NV Energy, for all future
19
Integrated Resource Plan Demand Side Management Plans
20
and Annual Demand Side Management Update Reports,
21
shall provide a discussion of, and support for, rebates and
22
incentives offered for each appropriate program.
23
24
f.
Ordering Paragraph 16 of the Commission’s order issued
25
December 24, 2012 in consolidated Docket Nos. 12-06052 and
26
12-06053. That paragraph provides:
27
28
Holmes-DIRECT
4
3DJHRI
1
Nevada Power Company d/b/a NV Energy and Sierra
2
Pacific Power Company d/b/a NV Energy, for all future
3
Integrated Resource Plan Demand Side Management Plans
4
and Annual Demand Side Management Update Reports,
5
shall include, for those programs that do not have an
6
installed unit such as a refrigerator or pool pump but
7
instead utilize an aggregate measure, a detailed discussion
8
explaining and supporting the development of the
9
aggregate measure.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
g.
Ordering Paragraph 17 of the Commission’s order issued
12
December 24, 2012 in consolidated Docket Nos. 12-06052 and
13
12-06053. That paragraph provides:
14
15
Nevada Power Company d/b/a NV Energy and Sierra
16
Pacific Power Company d/b/a NV Energy, for all future
17
Integrated Resource Plan Demand Side Management Plans
18
and Annual Demand Side Management Update Reports,
19
shall provide deemed savings on a per unit measure basis
20
and present changes in Measurement and Verification
21
verified deemed savings including the reasons behind the
22
changes to future savings.
23
24
h. Ordering Paragraph 18 of the Commission’s order issued
25
December 24, 2012 in consolidated Docket Nos. 12-06052 and
26
12-06053. That paragraph provides:
27
28
Holmes-DIRECT
5
3DJHRI
1
Nevada Power Company d/b/a NV Energy and Sierra
2
Pacific Power Company d/b/a NV Energy, for all future
3
Integrated Resource Plan Demand Side Management Plans
4
and Annual Demand Side Management Update Reports,
5
shall present in its Demand Response datasheets, a
6
residential section, a commercial section and a combined
7
program section.
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
i.
Ordering Paragraph 13 of the Commission’s Order issued March
10
23, 2011 in consolidated Docket Nos. 11-07026 and 11-07026.
11
That paragraph provides:
12
13
Sierra Pacific Power Company d/b/a NV Energy shall as
14
part of its next Integrated Resource Plan filing at least
15
three energy efficiency and conservation portfolios, one
16
preferred and two alternatives, to address identified
17
strategic load objectives.
18
19
4.
Q.
20
21
PLEASE PROVIDE AN OVERVIEW OF YOUR TESTIMONY
FOR THE COMMISSION.
A.
First, in Section A of my testimony, I summarize the Preferred DSM
22
Plan and discuss enhancements the Company has made in this filing to
23
the included programs as well as improvements made to provide more
24
supporting data as compared to previous DSM filings.
25
26
27
28
Holmes-DIRECT
6
3DJHRI
1
Section B of my testimony supports the request by the Company for
2
findings by the Commission regarding the nine compliance items
3
previously listed.
4
5
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
6
5.
Q.
PLEASE DESCRIBE THE DSM PLAN.
A.
The DSM Plan consists of the Preferred DSM Plan and two alternative
7
plans.
All three plans contain portfolios of energy efficiency and
8
conservation programs for the January 1, 2014 through December 31,
9
2016 Action Plan period. Sierra is requesting Commission approval of
10
the Preferred DSM Plan.
The Preferred DSM Plan includes ten
11
programs. The Preferred DSM Plan budget for the Action Plan period is
12
as follows: $10,410,000 in year 2014, $11,730,000 in year 2015, and
13
$13,580,000 in year 2015. The attendant estimated annual incremental
14
energy savings in megawatt-hours (“MWh”) for the Preferred DSM Plan
15
are 49,062 MWh in year 2014, 55,355 MWh in year 2015, and 57,900
16
MWh in year 2016.
17
demand savings in megawatts (“MW”) for the Preferred DSM Plan are
18
15.6 MW in year 2014, 24.7 MW in year 2014, and 33.0 MW in year
19
2016.
The estimated aggregate incremental annual
20
21
The DSM Plan provides three levels of information and data. The first
22
level of information and data, the DSM Plan Narrative (the “DSM
23
Narrative”), includes three sections.
24
statement of the Preferred DSM Plan for which Sierra is requesting
25
approval. Section 2 provides a summary of the performance of Sierra’s
26
DSM programs for 2012 and prior years.
Section 1 provides a concise
Section 3 of the DSM
27
28
Holmes-DIRECT
7
3DJHRI
1
Narrative describes the planning process employed by Sierra in
2
evaluating and selecting programs for each of the alternatives. The
3
planning process description includes the basis for the selection of the
4
Preferred DSM Plan, a description of the financial analysis and the
5
results of that analysis, an overview of the program measurement and
6
verification and management processes, and a set of tables for each
7
alternative that summarizes by program the analysis of each alternative.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
8
9
The second level of data included in the DSM Plan is the program data
10
sheets found in Exhibit A to the DSM Narrative. The program data
11
sheets describe and analyze past program performance and describe and
12
analyze each program for each plan alternative for the 2014-2016 Action
13
Plan period. The third level of information and data provided consists of
14
the detailed measurement and verification reports, additional support for
15
the financial analysis, energy efficiency implementation revenue
16
(“EEIR”) revenue requirement calculations and other supporting data for
17
each of the programs where applicable. This additional information and
18
data are provided in the DSM Technical Appendix.
19
20
6.
Q.
21
22
WHY
SHOULD
THE
COMMISSION
APPROVE
THE
PREFERRED DSM PLAN?
A.
The Commission should approve the Preferred DSM Plan as it provides
23
multiple benefits to customers and the communities in which they live.
24
The following summarizes the most significant benefits:
25
1. The portfolio of programs provides customers with viable options for
26
managing their energy consumption and reducing their bills.
27
28
Holmes-DIRECT
8
3DJHRI
1
2. The Preferred DSM Plan helps address the growing open position of
2
the Company through cost effective energy efficiency energy and
3
demand savings.
4
5
3. The energy savings provide very significant environmental benefits
6
as shown on Table DS-15 in the DSM Narrative. Table DS-15
7
depicts annual composite emission savings for the Preferred DSM
8
Plan. As an example of environmental benefits, over the life of the
9
measures installed carbon dioxide emissions will be reduced by
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
101,272 tons.
11
12
4. The Preferred DSM Plan provides a net economic benefit to the
13
communities served of $28,954,248, as defined by the Total
14
Resource Cost (“TRC”) test.
15
16
5. The Preferred DSM Plan provides opportunities for all customers to
17
participate in energy efficiency programs with participation limited
18
only by program funding levels.
19
20
6. The Preferred DSM Plan aids the community in the continued
21
recovery from the recession as it creates jobs. As described in the
22
DSM Narrative, the Preferred DSM Plan will create approximately
23
116 jobs each year of the three year plan.
24
25
7. The Preferred DSM Plan keeps up the momentum of the good energy
efficiency work accomplished in previous twelve years including
26
keeping intact the core of contractors that have been developed and
27
28
Holmes-DIRECT
9
3DJHRI
1
have become important program partners in the delivery of the
2
programs.
3
4
These benefits are available for all customers and communities served.
5
6
7.
Q.
7
ACTION PLAN PERIOD?
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
HAS SIERRA ADDED ANY NEW PROGRAMS FOR THE
A.
In 2013 Sierra is offering only one DSM program for residential
9
customers, the Second Refrigerator Collection and Recycling program.
10
The Preferred DSM Plan expands opportunities for participation by
11
residential customers by including three programs.
12
include the Refrigerator Collection and Recycling program, the
13
reintroduction of the Energy Efficient Residential Lighting, and the
14
Home Energy Reports Program.
15
Lighting program has been reintroduced in a form that only supports
16
light-emitting diode (“LED”) measures.
These programs
The Energy Efficient Residential
17
18
Sierra has added one new program for the 2014-2016 Action Plan period.
19
The new program is the Home Energy Reports Program. This program
20
is information based and focuses on changing behaviors regarding
21
energy usage to save energy. The Home Energy Reports Program is
22
more fully described in the testimony of Michelle Lindsay.
23
24
SECTION A: THE PREFERRED DSM PLAN
25
26
8.
Q.
PLEASE SUMMARIZE THE PREFERRED DSM PLAN.
27
28
Holmes-DIRECT
10
3DJHRI
1
A. The Preferred DSM Plan contains a suite of energy efficiency programs
2
and a demand response program addressing the needs of both the
3
residential and commercial customers.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
4
5
The Preferred DSM Plan includes ten programs, one of which is a new
6
program and nine of which are enhanced designs of the programs from
7
the approved 2010 IRP Demand Side Plan Action Plan. Table DS-1,
8
Demand Side Action Plan Budget, in the DSM Narrative lists those
9
programs and provides the annual budgets for the Action Plan Period.
10
The scope and scale of the Preferred DSM Plan is described in my Q&A
11
5 above.
12
13
The details of the energy savings in the DSM Plan are provided in Table
14
DS-13, Preferred Plan Energy Savings Table, found in the DSM
15
Narrative. The demand savings details are provided in Table DS-14,
16
Preferred Plan On-Peak Demand Savings. The Preferred DSM Plan
17
budget details are provided in Table DS-10, Preferred Plan Demand Side
18
Action Plan Budget. Each of these tables is located in Section 3 of the
19
DSM Narrative.
20
alternative plans in compliance with the Commission’s directions. The
21
three plans are summarized in Section 3 of the DSM Narrative. The
22
Company seeks acceptance (per the statute) and approval (per the
23
regulation) of the Preferred DSM Plan.
Sierra has created a Preferred DSM Plan and two
24
25
26
9.
Q.
PLEASE EXPLAIN WHY THE PREFERRED DSM PLAN
REPRESENTS AN APPROPRIATE INVESTMENT IN ENERGY
27
28
Holmes-DIRECT
11
3DJHRI
1
EFFICIENCY AND DEMAND RESPONSE PROGRAMS FOR
2
SIERRA.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
3
A. The Company evaluated the DSM Plan by assessing the costs and
4
benefits of each of the programs. The TRC test’s cost-benefit ratio for
5
the Preferred DSM Plan is 1.54. In calculating this ratio, the costs of the
6
Energy Education and Consultation program and the Market and
7
Technology Trials program were included, but no benefits were included
8
because the measurable benefits for these programs cannot be reasonably
9
estimated in advance of program execution. The TRC results show that
10
the estimated benefits provided by the portfolio of programs exceed the
11
costs associated with the portfolio.
12
exceeding one means the cost for electric energy is reduced for the
13
community in aggregate. As proposed, the portfolio of programs would
14
provide a net benefit of $28,954,361.
15
believes that the Preferred DSM Plan as presented in this DSM Plan
16
represents an appropriate level of investment as part of its IRP.
In other words, a TRC value
Accordingly, the Company
17
18
10.
Q.
19
20
PLEASE
LIST
THE
PROGRAMS
INCLUDED
IN
THE
PREFERRED DSM PLAN.
A. Sierra has included ten programs in the Preferred Plan. The title of each
21
program and the witness sponsoring each program are provided in the
22
following Table LMH-1.
23
24
25
26
27
28
Holmes-DIRECT
12
3DJHRI
1
Table LMH-1: Preferred Plan Program and Witness Listing
Program Name
2
3
Witness
Home Energy Reports
Michelle Lindsay
Residential Energy Efficient Lighting
Kelly Vagianos
Second Refrigerator Recycling
Kelly Vagianos
7
Solar Thermal Water Heating
Zeljko Vukanovic
8
Non-Profit Agency Grants
Michelle Lindsay
9
Energy Smart Schools
Michelle Lindsay
Commercial Incentives
Michelle Lindsay
Energy Education
Michelle Lindsay
Market and Technology Trials
Kelly Vagianos
Demand Response
Michael Brown
4
5
6
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
12
13
14
15
16
17
11.
Q.
WHAT WERE THE FACTORS THAT SIERRA CONSIDERED IN
18
DETERMINING WHAT PROGRAMS TO INCLUDE IN THE
19
PREFERRED DSM PLAN?
20
A.
Sierra considered a number of factors in assessing which programs to
21
include in the three alternative plans for the 2014-2016 Action Plan
22
period.
23
significant factors:
24
1. The verified energy and demand savings achieved in 2012 were
25
reviewed to determine how those savings compare with the targets
26
for the program and whether they would be sustainable in the 2014­
27
2016 period.
28
Holmes-DIRECT
The following provides a brief description of the more
13
3DJHRI
1
2. The program expenditures, energy savings and demand savings for
2
2012 were reviewed to evaluate how they compared to budget and
3
targets for 2012 to provide a comparable basis for estimating
4
program performance in the 2014-2016 period.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
5
6
3. The TRC analysis as computed using the PortfolioPro model was
7
evaluated for each program based on the program results for 2012. A
8
TRC benefit-to-cost ratio greater than one indicates that the program
9
will provide a net benefit to the communities served by the
10
Company.
With the exception of the Residential Solar Thermal
11
Water Heating program or those for which a TRC is not applicable, a
12
program was required to demonstrate a TRC benefit-to-cost ratio of
13
greater than 1.0 before it was considered for inclusion in the 2014­
14
2016 DSM Plan.
15
16
4. The Measurement and Verification Reports (“M&V Reports”)
17
provided
by
the
Company’s
evaluation,
measurement
and
18
verification (“M&V”) contractor, ADM & Associates, Inc., contain
19
observations and recommendations regarding the programs which are
20
considered in the program evaluation process.
21
22
5. The implementation contractors that delivered programs for Sierra in
23
2012 and 2013 provided feedback on program performance and areas
24
in which program performance could be enhanced or where the
25
program is experiencing difficulties and where design changes would
26
improve the performance of the program.
27
28
Holmes-DIRECT
14
3DJHRI
1
6. Sierra’s Program Managers provided an assessment of program
2
performance in the previous program year in the form of lessons
3
learned.
4
5
7. Free-ridership rates were considered in determining how each
6
program will be delivered in the future years, including whether a
7
program should be continued. Program design and future delivery
8
strategies to reduce free-ridership impacts were evaluated.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
8. All programs were evaluated for potential redesign, modifications, or
11
changes that would enhance the performance of the program in terms
12
of market acceptance, energy or demand savings yield and cost
13
effectiveness.
14
15
9. Customer demand and market expectations were considered as
16
indicators of potential program performance the 2014-2016 period.
17
18
10. Sierra’s appetite for portfolio credits in 2014-2016 and in subsequent
19
years was considered. The requirement in NRS 704.7821(2)(b) that
20
50 percent of the portfolio credits derived from energy efficiency
21
measures that are used to comply with the Renewable Portfolio
22
Standard (“RPS”) increment must come from residential sources was
23
part of the evaluation process.
24
25
26
27
28
Holmes-DIRECT
15
3DJHRI
1
11. Changes orpotential changes to energy efficiency standards or
2
statutory or regulatory requirements that may affect energy efficiency
3
program energy savings yields were considered.
4
5
12. Feedback from program partners such as contractors and stores that
6
are the points of delivery of the programs to customers was
7
considered.
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
13. Equityamong customers was taken into account by including
10
programs that provide opportunities for a broad range of customers to
11
participate in a program.
12
13
12.
Q
14
15
WHAT WERE SOME OF THE PROGRAM CHANGES MADE
FOR THE ACTION PLAN PERIOD?
A.
The changes and enhancements incorporated in the Preferred DSM Plan
16
are summarized in the following paragraphs.
17
1. Commercial Incentives Program – This new program is a
18
combination of the previously offered Commercial Retrofit
19
Incentives Program and the Commercial New Construction Program.
20
With the continued lack of new construction activity, the
21
construction effort has been folded into the retrofit program to create
22
this new program. The consolidation seeks reduced fixed costs and
23
an optimization of resources.
24
25
2. Energy Education and Consultation Program – This program will
26
reduce the emphasis on events such as home shows and add a
27
28
Holmes-DIRECT
16
3DJHRI
1
component that will combine with other resources in the community
2
to work with schools to educate children regarding energy efficiency.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
3
4
3. Second Refrigerator Collection and Recycling – The design and
5
delivery of this program has been modified to reduce the free-
6
ridership rate generated by collecting primary refrigerators.
7
retailer component of the program, in which the retailer picked up the
8
old primary refrigerator when delivering the new refrigerator, was
9
eliminated to minimize the number of primary units collected. In
10
addition, the marketing of the program will focus on homes where
11
occupants have lived for a number of years, which increases the
12
probability that a second refrigerator has been in place for some time.
13
Not only will these changes address free-ridership but it will result in
14
older and less efficient units being collected, which will increase the
15
effectiveness of the program in terms of energy savings.
The
16
17
4. Home Energy Reports – This new program provides residential
18
customers with data that compares their energy usage with that of
19
comparable but anonymous neighbors. This information provides
20
motivation to reduce consumption. The reports also provide advice
21
tailored to each customer on how they can better manage their energy
22
usage. This information provides the how to save energy to go with
23
the motivation. This program targets those residential customers
24
with the greatest consumption. This program encourages energy
25
savings through changed behaviors.
26
27
28
Holmes-DIRECT
17
3DJHRI
1
5. Demand Response (“DR”) – An agricultural component has been
2
added to the DR Program. This new component provides demand
3
response through the temporary interruption of service to pivots used
4
for irrigation during DR events. The interruptions are made practical
5
because the program also provides irrigation optimization that
6
ensures crops are not harmed while at the same time saving the
7
farmer the added expense of providing excess water to crops.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
8
9
Each program in the Preferred DSM Plan and the two alternatives
10
include enhancements to improve performance and effectiveness ranging
11
from adjustments to incentive levels to refined marketing strategies.
12
These changes, enhancements and new programs listed above along with
13
the changes and enhancements made to other programs are more fully
14
described in the program data sheets for each program.
15
16
13.
Q.
WHAT CHANGES HAS SIERRA MADE TO THE PROGRAM
17
DATA SHEETS FOR EACH PROGRAM AS COMPARED TO
18
WHAT WAS SUBMITTED IN THE 2010 IRP?
19
A.
A number of changes have been made to the program data sheets to
20
better describe the programs being proposed. Program data sheets are
21
provided for each program. The program data sheets describe each
22
program, provide a discussion of prior year performance and present
23
details regarding the program in the Preferred DSM Plan and the two
24
alternative plans.
25
provided in Exhibit A of the DSM Narrative.
The program data sheets for each program are
26
27
28
Holmes-DIRECT
18
3DJHRI
1
Sierra made five significant changes to the program data sheets for this
2
filing. The most significant change was a major expansion of the section
3
on prior year program performance. Previously the prior year program
4
performance was mentioned at a summary level in the program data
5
sheet and described in detail in a separate Annual DSM Update Report.
6
The separate Annual DSM Update Report has been eliminated with the
7
key information incorporated in the program data sheet for each program
8
and summarized in Section 2 of the DSM Narrative.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
The second significant change made to the program data sheets is the
11
addition of a free-ridership discussion for each project where applicable.
12
The discussions present the results of the free-ridership study results and
13
the design and delivery strategies being employed by Sierra to mitigate
14
or potentially reduce free-ridership during the 2014-2016 Action Plan
15
period.
16
17
The third significant change is the expansion of the financial analysis
18
portion of the program data sheet to include the adjusted TRC results.
19
20
The fourth significant change is the expansion of the program data sheet
21
to provide supporting discussions for the six key program specific inputs
22
to the financial analysis. The following list identifies each of these six
23
discussions.
24
1. The development of the energy savings curves
25
2. The source of the incremental costs
26
27
28
Holmes-DIRECT
19
3DJHRI
1
3. The determination of whether the program is a rebate or incentive
2
program and the basis for the rebate or incentive levels
3
4. A description of the determination of the program measure life,
4
5. A discussion of the units that are used as inputs for the
5
PortfolioPro financial analysis
6
6. The basis used for the deemed savings that are used as inputs to
7
the 2014-2016 financial analysis of each program.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
8
9
The fifth change is that the discussion in the program data sheets has
10
been shortened by removing duplicate discussions and proving a more
11
concise description of the Preferred DSM Plan and the two alternative
12
plans.
13
14
The revisions to the program data sheets provide additional data but in a
15
more concise presentation format that makes the data presented more
16
accessible for the reviewer.
17
18
SECTION B: COMPLIANCE ITEMS AND DIRECTIVES
19
20
14.
Q.
DID THE COMPANY SERVE UPON STAFF AND THE BCP AT
21
THE SAME TIME IT FILED ITS INITIAL APPLICATION, ALL
22
INFORMATION AND ALL SUPPORTING DATA IN EXECUTABLE
23
FORMAT
24
BENEFIT/COST CALCULATIONS RELATED TO DEMAND SIDE
25
MANAGEMENT
UPON
WHICH
PROGRAMS
IT
RELIES
AND
TO
LOST
DEVELOP
REVENUE
26
27
28
Holmes-DIRECT
20
3DJHRI
1
CALCULATIONS
2
PROGRAMS?
A. 3
FOR
DEMAND
SIDE
MANAGEMENT
Yes. The Company has served on the Staff and BCP all information and
4
all supporting data in executable format upon which it relied upon to
5
develop the benefit/cost calculations related to Demand Side Management
6
programs and lost revenue calculations for Demand Side Management
7
programs. This supporting information and data includes all spreadsheets
8
and calculations prepared by any out-side M&V contractors and consultants
9
in an executable and manipulative format.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
Based on the information provided, Sierra requests that the Commission
12
find that Sierra has complied with the Commission’s Order at Directive
13
Paragraph 11 in Docket Nos. 12-06052 and 12-06053.
14
15
15.
Q.
DID THE COMPANY INCLUDE A DISCUSSION OF, AND
16
SUPPORT FOR, THE DEVELOPMENT OF LOAD SHAPES
17
(ENERGY
18
INTEGRATED
RESOURCE
PLAN
19
MANAGEMENT
PLANS
ANNUAL
20
MANAGEMENT UPDATE REPORTS?
21
A.
SAVINGS
PROFILES)
AND
FOR
ALL
FUTURE
DEMAND
DEMAND
SIDE
SIDE
Yes. Sierra has taken several actions to comply with this directive.
22
First, Sierra has clearly defined 8,760 hour shape of energy savings as
23
“energy savings curves”.
24
previous discussions in which these savings shapes were also referred to
25
as load shapes. The second action taken by the Company has been to
26
direct its M&V contractor, ADM, to include a discussion of energy
This action removes the ambiguity from
27
28
Holmes-DIRECT
21
3DJHRI
1
savings curves in all applicable M&V reports. The third action the
2
Company has taken is to provide a general discussion of energy savings
3
curves in the DSM Narrative. The fourth action the Company has taken
4
is to add a new section to each applicable program data sheet that
5
discusses the energy savings curves used for the analysis of that
6
program. The fifth action taken by the Company has been to request
7
ADM to address energy savings curves in the testimony provided for this
8
filing.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
Based on the information provided, Sierra requests that the Commission
11
find that Sierra has complied with Directive Paragraph 12 in Dockets
12
Nos. 12-06052 and 12-6053.
13
14
16.
Q.
DID COMPANY INCLUDE DOCUMENTATION FOR ALL
15
INCREMENTAL COST CALCULATIONS FOR ALL FUTURE
16
INTEGRATED
RESOURCE
PLAN
17
MANAGEMENT
PLANS
ANNUAL
18
MANAGEMENT UPDATE REPORTS?
19
A.
AND
DEMAND
DEMAND
SIDE
SIDE
The full and complete documentation for all incremental costs include
20
substantial spreadsheets that are not practical to print in a form that
21
would be meaningful in this filing.
22
directive the Company has taken three steps.
23
Company included a description of incremental costs in the DSM
24
Narrative. The second is that a section has been added to each program
25
data sheets that describes and provides the source for incremental costs
26
specific to that program. The third step taken was to include in the data
Therefore to comply with this
The first is that the
27
28
Holmes-DIRECT
22
3DJHRI
1
that is being served on the Staff and BCP the spreadsheets (in executable
2
format) and supporting materials that document the incremental cost
3
calculations.
4
5
Based on the information provided, Sierra requests that the Commission
6
find that Sierra has complied with the directive in Directive Paragraph 13
7
in Dockets Nos. 12-06052 and 12-06053.
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
17.
Q.
DID THE COMPANY USE THE MEASURE LIFE AS PRESENTED
10
IN
11
REPORTS
12
SUPPORT A CHANGED MEASURE LIFE FOR ALL FUTURE
13
INTEGRATED RESOURCE PLAN DEMAND SIDE MANAGEMENT
14
PLANS AND ANNUAL DEMAND SIDE MANAGEMENT UPDATE
15
REPORTS?
16
A.
THE
LATEST
MEASUREMENT
AND
UNLESS
DOCUMENTATION
IS
VERIFICATION
PROVIDED
TO
The Company has taken three steps to comply with this directive. Not
17
all M&V reports previously addressed measure life. The first step taken
18
was therefore to request that ADM include an analysis of measure life in
19
all M&V reports. The second step taken by the Company was to include
20
a general discussion of measure life in the DSM Narrative. The third
21
step taken by the Company is the inclusion of a discussion of measure
22
life in each program data sheet. This discussion includes a description of
23
the source of the measure life that was used in the analysis of the
24
program and, if different from that provided in M&V report, the
25
justification of why a different value is used in the analysis.
26
27
28
Holmes-DIRECT
23
3DJHRI
1
Based on the information provided, Sierra requests that the Commission
2
find that Sierra has complied with Directing Paragraph 14 in Dockets
3
Nos. 12-06052 and 12-06053.
4
5
18.
Q.
6
SUPPORT FOR, REBATES AND INCENTIVES OFFERED FOR
7
EACH
8
INTEGRATED
RESOURCE
PLAN
9
MANAGEMENT
PLANS
ANNUAL
10
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
DID THE COMPANY PROVIDE A DISCUSSION OF, AND
11
APPROPRIATE
PROGRAM
AND
FOR
ALL
FUTURE
DEMAND
DEMAND
SIDE
SIDE
MANAGEMENT UPDATE REPORTS?
A.
The Company has taken two steps to comply with this directive. The
12
first step was to include a general discussion of rebates and incentives in
13
the DSM Narrative. This section describes when a program is a rebate
14
program and when a program is an incentive program, and describes the
15
approach used for determining rebate or incentive levels. The second
16
step taken by the Company is the inclusion of a discussion of rebates and
17
incentives in each program data sheet.
18
determination of whether that program is an incentive or a rebate
19
program and a discussion that supports the rebate levels used in the
20
analysis of the program.
This discussion includes a
21
22
Based on the information provided, Sierra requests that the Commission
23
find that Sierra has complied with Directing Paragraph 15 in Dockets
24
Nos. 12-06052 and 12-06053.
25
26
27
28
Holmes-DIRECT
24
3DJHRI
1
19.
DID THE COMPANY INCLUDE, FOR THOSE PROGRAMS
2
THAT DO NOT HAVE AN INSTALLED UNIT SUCH AS A
3
REFRIGERATOR OR POOL PUMP BUT INSTEAD UTILIZE AN
4
AGGREGATE
5
EXPLAINING AND SUPPORTING THE DEVELOPMENT OF
6
THE
7
INTEGRATED
RESOURCE
PLAN
8
MANAGEMENT
PLANS
ANNUAL
9
MANAGEMENT UPDATE REPORTS?
10
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
Q.
A.
MEASURE,
AGGREGATE
A
DETAILED
MEASURE,
AND
FOR
DISCUSSION
ALL
FUTURE
DEMAND
DEMAND
SIDE
SIDE
The Company has taken three steps to comply with this directive. The
11
first step taken was to include a general discussion of units used for
12
analysis of programs in the DSM Narrative. The second step taken by
13
the Company is the inclusion of a discussion of units in each program
14
data sheet. This discussion includes a description of the source of the
15
units that were used in the analysis of the program. The third step taken
16
applies to those programs where the determination of units is based on a
17
spreadsheet analysis.
18
executable form, were included in the data served on Staff and BCP at
19
the time of this filing.
For these programs, the spreadsheets, in
20
21
Based on the information provided, Sierra requests that the Commission
22
find that Sierra has complied with Directing Paragraph 16 in Dockets
23
Nos. 12-06052 and 12-06053.
24
25
26
20.
Q.
DID THE COMPANY PROVIDE DEEMED SAVINGS ON A PER
UNIT
MEASURE
BASIS
AND
PRESENT
CHANGES
IN
27
28
Holmes-DIRECT
25
3DJHRI
1
MEASUREMENT AND VERIFICATION VERIFIED DEEMED
2
SAVINGS
3
CHANGES
4
INTEGRATED RESOURCE PLAN DEMAND SIDE MANAGEMENT
5
PLANS AND ANNUAL DEMAND SIDE MANAGEMENT UPDATE
6
REPORTS.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
A. INCLUDING
TO
THE
FUTURE
REASONS
SAVINGS
FOR
BEHIND
ALL
THE
FUTURE
The Company has taken three steps to comply with this directive. The
8
first step taken by the Company was to include a general discussion of
9
deemed savings in the DSM Narrative.
This discussion includes a
10
description of why deemed unit savings for the 2014-2016 Action Plan
11
period could vary from the savings reported in the M&V reports. The
12
second step taken by the Company was the inclusion of a discussion of
13
deemed savings in each program data sheet. This discussion includes a
14
description of the source of the deemed savings used in the analysis of
15
the program. The third step taken by the Company was the inclusion in
16
the information served on the Staff and BCP at the time of this filing of
17
spreadsheet, in executable form, for those programs where the
18
determination of deemed savings was made on a spreadsheet that is not
19
practical to include in this filing.
20
21
Based on the information provided, Sierra requests that the Commission
22
find that Sierra has complied with Directing Paragraph 17 in Dockets
23
Nos. 12-06052 and 12-06053.
24
25
26
21.
Q.
DID THE COMPANY PRESENT IN ITS DEMAND RESPONSE
DATASHEETS, A RESIDENTIAL SECTION, A COMMERCIAL
27
28
Holmes-DIRECT
26
3DJHRI
1
SECTION AND A COMBINED PROGRAM SECTION FOR ALL
2
FUTURE INTEGRATED RESOURCE PLAN DEMAND SIDE
3
MANAGEMENT
4
MANAGEMENT UPDATE REPORTS?
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
5
A. PLANS
AND
ANNUAL
DEMAND
SIDE
The Company has broken out the analysis of the residential and the
6
commercial and industrial components of the DR Program separately in
7
the DR Program data sheet. The Company has added a new agricultural
8
component to the DR Program for the Action Plan period. In keeping
9
with the spirit of the Commission’s directive, the agricultural component
10
has also been broken out separately from the residential, commercial,
11
and industrial segments. Discussions that apply to all three components
12
are provided in combined sections and sections that that apply to
13
individual components are provided in separate sections. Tables are
14
provided that clearly break out the budgets, kWh savings, kW savings,
15
TRC results and the financial analysis summary are provided for each of
16
the three components.
17
18
Based on the information provided, Sierra requests that the Commission
19
find that Sierra has complied with Directing Paragraph 18 in Dockets
20
Nos. 12-06052 and 12-06053.
21
22
22.
Q.
DID
SIERRA
INCLUDE
AT
LEAST
THREE
ENERGY
23
EFFICIENCY AND CONSERVATION PORTFOLIOS, ONE
24
PREFERRED AND TWO ALTERNATIVES, TO ADDRESS
25
IDENTIFIED STRATEGIC LOAD OBJECTIVES AS PART OF
26
ITS NEXT INTEGRATED RESOURCE PLAN FILING?
27
28
Holmes-DIRECT
27
3DJHRI
1
A. The DSM Plan includes a Preferred DSM Plan and two alternative plans,
2
the Minimum Impact Alternative Plan and the Maximum Net Benefits
3
Alternative Plan.
4
Alternatives” in Section 3 of the DSM Narrative provides a discussion of
5
the Preferred Plan and the two alternative plans.
6
program data sheet provided in Exhibit A to the DSM Plan describe if
7
and how each program would be delivered in each of the three
8
alternative plans presented.
The subsection “Development of the Three
In addition, each
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
Based on the information provided, Sierra requests that the Commission
11
find that Sierra has complied with at Ordering Paragraph 13 in Dockets
12
Nos. 11-07026 and 11-07027.
13
14
15
23.
Q.
DOES THIS COMPLETE YOUR TESTIMONY?
A. Yes, it does.
16
17
18
19
20
21
22
23
24
25
26
27
28
Holmes-DIRECT
28
3DJHRI
Exhibit Holmes-Direct-1
Page 1 of 2
Statement of Qualifications
Lawrence M. Holmes
February 6, 2013
Education
Bachelor of Science in Electrical Engineering, San Jose State University 1971
Masters of Science in Electrical Engineering, Georgia Institute of Technology 1979
Professional Experience
2005 To Date
Manager, Customer Strategy and Programs
NV Energy
Responsible for 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,
associated reporting and stakeholder collaborative. Participate in the development of customer owned
renewable annual plans for photovoltaic, solar thermal, wind and water resources.
1999 through 2004
Senior Tactical Planning Consultant
NV Energy
Responsibilities and accomplishments included updating the line extension and parallel
generation rules, development and negotiation of line extension agreement for large projects,
support of economic development activities, support of the development and implementation of
new standby tariffs, perform facilities cost studies in support of regulatory filings and special
projects.
1996 through 1998
Project Manager, New Business Activities
Sierra Pacific Power Company
Responsibilities and accomplishments included updating the line extension and parallel
generation rules, business process improvements for the line extension processes, planner
training, budgeting and management tracking, and special projects as assigned.
1994 through 1995
Director, Customer Services Support
Sierra Pacific Power Company
Responsibilities and accomplishments included system planning for electric, gas and water
distribution systems and non interstate transmission lines, preparing and monitoring the budgets
for the Operations Division, development and maintenance of standards, development and
operation of apprenticeship training programs and participation in the development of customer
satisfaction strategies.
1991 through 1993 Director, Customer Operations
Sierra Pacific Power Company
Responsibilities and accomplishments included the construction, operations, maintenance, and
emergency repairs of the electric distribution facilities in the Truckee Meadows District
including associated customer relations.
3DJHRI
Exhibit Holmes-Direct-1
Page 2 of 2
1989 through 1992
Manager, Customer Services Engineering
Sierra Pacific Power Company
Responsibilities and accomplishments included the design and planning of distribution facilities
required to serve expanding loads and new customers, the development and execution of line
extension agreements and for the customer relations surrounding these processes.
1984 through 1988
Supervisor, Substation Design
Sierra Pacific Power Company
Responsibilities and accomplishments included supervising the design of substations,
transmission lines, minor power plant improvements (electrical), and water system additions
(electrical).
1981 through 1984
Associate Engineer and Engineer
Electrical Engineering Department
Sierra Pacific Power Company
Responsibilities and accomplishments included the design of substations, transmission lines,
minor power plant improvements (electrical), and water system additions (electrical).
1971 through 1981
United States Navy Civil Engineer Corps
Responsibilities and accomplishments included construction management and facilities
management. Responsibilities for construction management included design and specification
review, contractor management, budget management, onsite inspection services, and client
relations. Responsibilities for facilities management included planning, budgeting, operations,
maintenance, minor construction, energy efficiency, and client relations for shore facilities
including the buildings, grounds, and utility systems.
Professional Certifications
Registered Professional Engineer in the State of Nevada
Certified Energy Manager - Association of Energy Engineers.
Boards and Honors
Southwest Energy Efficiency Project (SWEEP), Board of Directors, Chairman
Association of Energy Service Professional, member
Association of Energy Engineers, member
National Society of Professional Engineers, past member
Institute of Electrical and Electronic Engineers, past member
City of Reno Board of Adjustments, past Board Member and Chairman
Reno South Kiwanis, past Board Member, President and Secretary/Treasurer
2009 SWEEP Leadership in Energy Efficiency Award
U.S. Navy EEO Award for Outstanding Achievements as a Supervisor 1981
3DJHRI
3DJHRI
MICHELLE A. LINDSAY
3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-_____
4
PREPARED DIRECT TESTIMONY OF
5
Michelle A. Lindsay
6
7
1.
Q.
8
ADDRESS.
9
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
A.
My name is Michelle A. Lindsay. I am employed by Nevada Power Company
10
d/b/a NV Energy (“Nevada Power” or the “Company”) and Sierra Pacific Power
11
Company d/b/a NV Energy (“Sierra” and, together with Nevada Power, the
12
“Companies”) as Consultant Staff, DSM Planning in the Customer Strategy and
13
Programs Department. My business address is 6226 West Sahara Avenue in Las
14
Vegas, Nevada. I am filing testimony on behalf of Sierra.
15
16
2.
Q.
17
18
PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
EXPERIENCE.
A.
I have a Bachelor of Arts degree in Communications and a Master’s of Science in
19
Construction Management. I also have a certificate in Planning and Scheduling.
20
Since starting at Nevada Power in 2006, I have held two positions within the
21
Energy Delivery and the Customer Strategy and Programs Departments. More
22
details regarding my professional background and experience are set forth in my
23
Statement of Qualifications, included as Exhibit Lindsay-Direct-1.
24
25
26
27
28
Lindsay-DIRECT
1
3DJHRI
1
3.
Q.
2
IS
THE
PURPOSE
OF
YOUR
TESTIMONY
IN
THIS
PROCEEDING?
3
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
WHAT
A.
Together with witnesses Larry Holmes, Michael Brown, Kelly Vagianos, and
4
Zeljko Vukanovic, I sponsor the Demand Side Management Plan (“DSM Plan”)
5
set forth in Sierra Pacific Power’s 2014 – 2033 Integrated Resource Plan (“IRP”).
6
Specifically, I sponsor and support the following items:
7
1. 2012 Program Results
8
2. Potential Demand Side Management and Demand Response Programs
9
3. Low Income Weatherization Program
10
4. Energy Smart Schools Program
11
5. Non-Profit Agency Grants Program
12
6. Commercial Incentives Program
13
7. Energy Education Program
14
8. Home Energy Report Program
15
9. Process to Calculate Future Deemed Savings
16
17
18
19
4.
Q. PLEASE PROVIDE AN OVERVIEW OF YOUR TESTIMONY.
A. The first section of my testimony, Section A, summarizes the 2012 DSM Portfolio
Results.
20
21
Section B describes the process used to evaluate new proposed programs and
22
includes a discussion of the scope and scale of the individual programs in the
23
Preferred Plan that I sponsor.
24
25
The last section of my testimony, Section C, summarizes the process Sierra uses
26
to calculate future deemed savings for each program included in the portfolio.
27
28
Lindsay-DIRECT
2
3DJHRI
1
SECTION A: 2012 DSM PORTFOLIO RESULTS 2
5.
Q.
3
PORTFOLIO FOR 2012?
4
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE SUMMARIZE THE PERFORMANCE OF SIERRA’S DSM
A.
Collectively, the portfolio of programs achieved 122.6 percent of the kWh savings
5
target in 2012 and 35.3 percent of the demand reduction target.
6
expenditures were less than budgeted at 94.5 percent. The 2012 portfolio of
7
programs provided a total resource cost (“TRC”) benefit-to-cost ratio of 1.45.
8
The DSM Portfolio results for 2012 are summarized in the DSM Narrative in
9
Table DS-3, Program Year 2012 Financial Results, Table DS-4, Program Year
10
2012 Demand (kW) and Energy (kWh) Savings Results, and Table DS-5 Program
11
Year 2012 Non-Demand and Energy Results.
Program
12
13
The Company has also included Table DS-6, which provides an estimate of the
14
environmental impact of the 2012 program year results.
15
information is not required, the Company believes that it is important to provide
16
the Commission with this information because it demonstrates program benefits
17
in addition to those included in the TRC test.
Even though this
18
19
20
6.
Q.
WHY WERE 2012 DEMAND SAVINGS LOWER THAN TARGETED?
A.
First, demand savings for a program are directly tied to the installed measure mix.
21
The savings from the Commercial Retrofit Incentives and Energy Smart Schools
22
programs comprised greater than two thirds of the target demand savings. Both of
23
these programs assume a mix of measures for planning purposes but actual
24
measures installed reflect the choices made by customers participating in the
25
program. For both of these programs customers chose to do more lighting and
26
less heating ventilation and air conditioning (“HVAC”) than was assumed in the
27
28
Lindsay-DIRECT
3
3DJHRI
1
project plan. Lighting projects provide a lower level of demand savings due to
2
the fact that the HVAC loads peak in the summer months highly coincident with
3
system peaks but lighting loads are fairly level throughout the year and do not
4
necessarily align with system peak.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
5
6
Second, the projected demand savings for the 2012 program plans were
7
determined using energy savings curves that were available in 2010.
8
energy savings curves were based on an aggregate of a variety of national utilities
9
with weather and geographic factors that were not specific to the conditions
10
experienced at Sierra and were also based on generic compatible programs. In
11
2013 for the evaluation of the 2012 programs, Sierra’s M&V contractor provided
12
program specific energy savings curves that are based on the projects that were
13
actually completed as a part of Sierra’s program activity as well as local weather
14
and geographical data. The resulting demand savings are slightly lower but more
15
precise.
These
16
17
7.
Q.
HOW DID SIERRA LEVERAGE THE RESULTS AND THE LESSONS
18
LEARNED FROM THE 2012 PROGRAMS TO INFORM AND IMPROVE
19
THE DESIGN OF PROGRAMS FOR THE 2014-2016 ACTION PLAN
20
PERIOD?
21
A. The results from the 2012 programs that were evaluated in considering the
22
potential designs of programs for the 2014-2016 action plan period included the
23
following:
24
1.
Kilowatt hour savings
25
2.
Kilowatt savings
26
3.
Number of participants
27
28
Lindsay-DIRECT
4
3DJHRI
1
4.
Observations and analysis contained in M&V reports
2
5.
Freeridership study
3
6.
Feedback from implementation contractors
4
7.
Feedback from program contractors
5
8.
Feedback from customers
6
9.
Input from program managers
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
8
The program data sheet for each program provided in Exhibit A includes an
9
analysis of the 2012 results, a list of the lessons learned and conclusions regarding
10
changes based on the analysis of the data evaluated. A number of the program
11
enhancements identified in this process have been integrated in the delivery of the
12
2013 programs.
13
14
SECTION B: ANALYSIS AND PROPOSALS
15
8.
Q.
PLEASE
DESCRIBE
THE
PROCESS
USED
BY
SIERRA
TO
16
INVESTIGATE NEW PROGRAMS UNDER CONSIDERATION FOR
17
ADDITION TO THE EXISTING PORTFOLIO OF PROGRAMS.
18
A.
To keep in step with technology and market changes that yield new energy
19
savings opportunities, Sierra cast a wide net to obtain recommendations and
20
concept ideas for new programs to evaluate for addition to the DSM Portfolio.
21
Sierra asked members of the DSM Collaborative during multiple meetings in late
22
2012 and early 2013 to provide recommendations for new programs or program
23
additions.
24
contractors expressing interest in working with Sierra in the future to recommend
25
new programs. These recommendations often have the added benefit of the
26
experience of contractors who have performed a market assessment for a program
In addition, Sierra asked current implementation contractors and
27
28
Lindsay-DIRECT
5
3DJHRI
1
and thus can propose programs with good market potential for Sierra’s service
2
territory. DSM Planning Staff and Energy Efficiency and Conservation Program
3
Managers also talked with colleagues at other utilities to explore additional
4
programs offered in their territories for potential adoption by Sierra.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
5
6
Proposals for stand-alone programs, for niche additions to an existing program, or
7
for individual measures to be added to existing programs were considered. Where
8
warranted Sierra compiled the data required to run a cost-benefit analysis to
9
evaluate the recommendations. Programs, measures and niche segments with a
10
TRC greater than one were further considered for their potential in the local
11
market, and assessed for any freeridership and measurement and verification
12
concerns. A list of programs evaluated for inclusion in the DSM Plan is provided
13
in Table DSM-31 of the DSM Narrative.
14
15
9.
Q.
16
HAS SIERRA PROPOSED A COST-EFFECTIVE LOW INCOME
WEATHERIZATION PROGRAM?
17
A.
No. The Commission’s order accepting Sierra’s 2012 Natural Gas Conservation
18
and Energy Efficiency Plan Annual Report in Docket No. 12-06051,1 required
19
Sierra to issue a request for proposals (“RFP”) for a gas low income
20
weatherization program for delivery in 2014. To provide for a more cost effective
21
program based on economies of scale, Sierra issued a combined RFP for both gas
22
and electric programs.
23
Accordingly, Sierra decided that it would not propose a low income
24
weatherization program for Action Plan period.
There were no proposals in response to the RFP.
25
26
1
27
28
See Ordering paragraph 4 and paragraph 4, Sierras’ 2012 Natural Gas Conservation and Energy Efficiency Plan
Annual Report Docket No. 12-06051 order issued November 11, 2012.
Lindsay-DIRECT
6
3DJHRI
1
Q.
PLEASE DESCRIBE THE SCOPE AND SCALE OF THE ENERGY
2
SMART SCHOOLS PROGRAM THAT SIERRA INCLUDES IN THE
3
PREFERRED PLAN FOR THE 2014-2016 ACTION PLAN PERIOD.
4
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
10.
A.
The Energy Smart Schools program is designed to facilitate energy efficiency and
5
peak demand reduction for schools.
6
program components: incentives for energy efficient measures and extensive
7
technical assistance for the identification, development, bidding and managing of
8
energy efficiency projects. The customers served by this program have been
9
expanded from K-12 public schools to include private schools and schools of
10
This program is composed of two key
higher education.
11
12
The primary objective of the Energy Smart Schools Program remains to achieve
13
cost effective energy savings that ultimately result in energy and cost savings for
14
schools within Sierra’s service territory.
15
16
The technical assistance may include support to help school facility operators
17
identify qualifying projects, provide assessment of program viability, calculate
18
energy and cost savings, provide energy savings verification, assist with district
19
internal communications to management, retrofit specification design assistance,
20
along with oversight and assistance with retrofit project management activities.
21
22
Sierra recommends that the Energy Smart Schools program be adopted in the
23
2014-2016 Action Plan period as described in the Preferred Plan. The Preferred
24
Plan budget for the Action Plan period for this program is as follows: $400,000
25
per year for 2014 through 2016. The attendant expected energy savings are
26
27
28
Lindsay-DIRECT
7
3DJHRI
1
2,500,000 kWh per year for 2014 through 2016. The estimated aggregate demand
2
savings are 250 kW per year for 2014 through 2016.
3
4
Q.
PLEASE DESCRIBE THE SCOPE AND SCALE OF THE NON-PROFIT
5
AGENCY GRANTS PROGRAM THAT SIERRA INCLUDES IN THE
6
PREFERRED PLAN FOR THE 2014-2016 ACTION PLAN PERIOD.
7
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
11.
A.
The Non-Profit Agency Grants (“NPAG”) Program offers qualifying non-profit
8
organizations a financial means to implement energy efficiency measures. This
9
program provides financial assistance to non-profit organizations for the
10
installation of energy efficiency measures in new and existing buildings. To
11
qualify, an agency must be a 501(c)3 entity located within Sierra’s service area.
12
The grant money may be used for projects to fund energy efficient measures for
13
retrofits or energy efficiency upgrades for new buildings. Due to the reduced cost
14
to own or lease older buildings, non-profit agencies often occupy older buildings
15
that may have significant energy inefficiencies.
16
17
NPAG solicits participation from qualifying non-profit organizations by sending a
18
letter that invites grant submission requests and by promoting the program
19
through community partners such as the United Way.
20
recipients for the project grants, the kW and kWh savings are projected by the
21
contractor working with the non-profit agencies with input and screening
22
provided by Sierra based on the information submitted by the participating non­
23
profit organization. In order for the grant request to be accepted each project
24
request was required to generally support a TRC of 1.00 or greater. The project
25
selection process achieves the cost effective energy and demand savings within
26
the available program funding.
In determining the
27
28
Lindsay-DIRECT
8
3DJHRI
1
2
Sierra recommends that the NPAG Program be adopted in the 2014-2016 Action
3
Plan period as described in the Preferred Plan. The Preferred Plan budget for the
4
Action Plan period for this program is as follows: $110,000 per year for 2014
5
through 2016. The attendant expected energy savings are 324,000 kWh per year
6
for 2014 through 2016. The estimated aggregate demand savings are 74 kW per
7
year for 2014 through 2016.
8
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
9
12.
Q.
WHY HAS SIERRA COMBINED THE COMMERCIAL RETROFIT
10
INCENTIVES AND THE COMMERCIAL NEW CONSTRUCTION
11
PROGRAMS INTO A SINGLE PROGRAM NOW KNOWN AS THE
12
COMMERCIAL INCENTIVE PROGRAM?
13
A.
The Commercial Retrofit Incentives program and the Commercial New
14
Construction program have been combined in response to the relatively anemic
15
new construction activity in northern Nevada. Combining the programs will
16
provide opportunities for reducing the fixed costs of running the two programs
17
separately. In addition construction projects that are occurring tend to be major
18
tenant improvements instead of new “ground up” buildings. The Commercial
19
Retrofit Incentives program continues to experience highly cost-effective results
20
with customer demand that exceeds program resources. Within this combined
21
program, new construction measures will compete with retrofit measures for
22
program resources. New construction projects will be individually screened to
23
assure cost effectiveness reasonably comparable to retrofit projects prior to
24
project preapproval.
25
26
27
28
Lindsay-DIRECT
9
3DJHRI
1
Q.
PLEASE DESCRIBE THE SCOPE AND SCALE OF THE COMMERCIAL
2
INCENTIVES
3
PREFERRED PLAN FOR THE 2014-2016 ACTION PLAN PERIOD.
4
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
13.
A.
PROGRAM
THAT
SIERRA
INCLUDES
IN
THE
The Commercial Incentives Program facilitates the implementation of energy
5
efficient measures and building practices in commercial, industrial, and
6
institutional facilities through incentives and comprehensive technical services.
7
The Commercial Incentives Program offers per-unit prescriptive incentives for
8
energy efficient lighting, cooling, motors, commercial kitchens, refrigeration, and
9
miscellaneous energy conservation measures. In addition, custom incentives are
10
offered for most measures not covered under the prescriptive component that
11
result in verifiable energy savings.
12
13
For new construction projects, the program will work with the building
14
developers and their contractors or professionals to assess the amount of energy
15
savings prior to project approval. Incentives will be paid when a new building is
16
complete and ready for occupancy and the applicant can demonstrate that the
17
energy efficiency measures have met program requirements.
18
19
Sierra recommends that the Commercial Incentives Program be adopted in the
20
2014-2016 Action Plan period as described in the Preferred Plan. The Preferred
21
Plan budget for the Action Plan period for this program is as follows: $4,500,000
22
per year for 2014 through 2016. The expected attendant energy savings are
23
32,000,000 kWh per year for 2014 through 2016.
24
demand savings are 5,423 kW per year for 2014 through 2016.
The estimated aggregate
25
26
27
28
Lindsay-DIRECT
10
3DJHRI
1
Q.
PLEASE DESCRIBE THE SCOPE AND SCALE OF THE ENERGY
2
EDUCATION AND CONSULTATION PROGRAM THAT SIERRA
3
INCLUDES IN THE PREFERRED PLAN FOR THE 2014-2016 ACTION
4
PLAN PERIOD?
5
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
14.
A.
The Energy Education and Consultation Program is designed to educate and assist
6
customers, builders, developers, realtors, and energy professionals regarding the
7
efficient use of electricity and environmental benefits of conservation in their
8
homes and businesses. The program has been revised for the 2014-2016 Action
9
Plan period to include three components.
First, in Residential Customer
10
Education, Sierra will focus efforts on educating K-12 teachers and students and
11
providing presentations to adults on energy efficiency. This measure will put less
12
reliance on public events such as home shows as compared to previous years.
13
Second, the Commercial Customer Education component has been expanded from
14
facility operator training to include webinars and shorter seminars to educate
15
additional commercial customers.
16
Building Industry Support component has shifted resources from a near sole
17
emphasis on new home construction to a wider focus that incorporates the energy
18
retrofit industry, real estate industry and code compliance training. For each of
19
the three components, partnerships will be sought to increase the reach of
20
program funding.
Third, the Residential and Commercial
21
22
Sierra recommends that the Energy Education and Consultation program be
23
adopted in the 2014-2016 Action Plan period as described in the Preferred Plan.
24
The Preferred Plan budget for the Action Plan period for this program is $250,000
25
per year for 2014 through 2016.
26
27
28
Lindsay-DIRECT
11
3DJHRI
1
15.
2
Q.
ARE YOU SPONSORING ANY NEW PROGRAMS?
A. Yes, I am sponsoring the proposed residential Home Energy Reports Program in
3
Sierra’s DSM portfolio. The program is one of three programs at Sierra designed
4
to provide services to residential customers.
5
6
16.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
Q.
PLEASE DESCRIBE THE HOME ENERGY REPORTS PROGRAM.
A. The Home Energy Reports Program focuses on changing behaviors to conserve
8
energy and save money on utility bills. This program is information based and
9
provides benefits to a large number of residential customers in a cost-effective
10
manner.
11
12
The Home Energy Reports Program targets higher than average energy users by
13
employing a dynamically created comparison group for each residence that
14
compares the energy consumption for that customer to other similarly sized and
15
located households. Consumers change how they use energy when they receive
16
relevant insights about their energy use in a format that provokes their interest and
17
action.
18
comparisons are highly motivating ways to present information.2 This behavioral
19
science complements other residential energy efficiency approaches.
20
program will be delivered on an opt-out basis to households, with higher than
21
average energy use. The program is designed with the following elements:
Behavioral science research has demonstrated that peer-based
The
22
23
1. Delivery of reports: Targeted households will receive a welcome insert that
24
introduces them to the program and is followed by a series of home energy
25
26
2
27
Cialdini, Robert, and Wesley Schultz, 2004, “Understanding and Motivating Energy Conservation via Social Norms,”
Arizona State and California State Universities, available here:
http://opower.com/uploads/library/file/2/understanding_and_motivating_energy_conservation_via_social_norms.pdf
28
Lindsay-DIRECT
12
3DJHRI
1
reports delivered to participating households monthly or bi-monthly
2
throughout the program year. The reports provide updates on the energy
3
usage behavior of that household contrasted with that of the comparison
4
group, and offers tips for saving energy.
5
6
2. Delivery of Email Reports: Households that have provided email addresses
7
to Sierra may additionally receive email versions of home energy reports.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
8
9
3. Ability to opt-out: All participants will have an easy method for opting out
10
of the program if they no longer want to receive the home energy reports. The
11
opt-out rate for Home Energy Report program in other jurisdictions has
12
generally been less than one percent.3
13
14
At the Preferred Plan level, the program proposes to provide Home Energy
15
Reports to 65,000 residential customers in northern Nevada. A full description of
16
the Home Energy Reports program is provided in the Home Energy Reports
17
Program Data Sheet within Exhibit A.
18
19
17.
Q.
20
PLEASE DESCRIBE THE SCOPE AND SCALE OF THE HOME
ENERGY REPORTS PROGRAM.
21
A.
Sierra recommends that the Commission adopt the Home Energy Reports
22
Program in the 2014-2016 Action Plan period. The Preferred Plan budget for the
23
Action Plan period for this program is as follows: $600,000 for 2014; $520,000
24
for 2015; and $520,000 for 2016. The estimated energy savings are: 8,950,000
25
26
27
28
3
Allcott, Hunt, October 2011. “Social Norms and Energy Conservation.” Journal of Public Economics Vol 95 (9-10),
pp. 1082 – 1095; See Table 2 for opt-out results
Lindsay-DIRECT
13
3DJHRI
1
kWh for 2014; 13,270,000 kWh for 2015; and 14,050,000 kWh for 2016. The
2
estimated aggregate demand savings are: 2,281 kW for 2014; 3,381 kW for 2015;
3
and 3,579 kW for 2016.
4
5
6
18.
Q.
DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A.
Yes
7
8
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Lindsay-DIRECT
14
3DJHRI
Exhibit Lindsay-Direct-1
Page 1 of 2
Statement of Qualifications
Michelle A Lindsay
June 2012
Education
Bachelor of Arts in Communication, University of South Carolina 2001
Masters of Science in Construction Management, University of Nevada Las Vegas
2012 (Projected Completion)
Professional Experience
2011 To Date
Staff Consultant, DSM Planning
NV Energy
Responsibilities and accomplishments 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, associated reporting and
stakeholder collaborative.
2006 through 2011
Staff Consultant, Technology Development
NV Energy
Responsibilities and accomplishments included analysis, design and development of proposals,
requirements, testing materials, training materials, implementation and change management
plans for efficient, cost effective process and technology solutions; and training users on new
systems.
2005 through 2006
Six Sigma Black Belt
Bechtel Nevada
Responsibilities and accomplishments included leading process improvement teams through the
identify, measure, analyze, improve and control lifecycle of process improvement projects to
drive quantifiable business results and coaching junior process improvement practitioners and
business leaders in tool usage and business case development.
2002 through 2005
Procurement Specialist
Bechtel Nevada
Responsibilities and accomplishments included performing the bid, award, negotiate, and
administer process for material and service contracts; streamlining competitive purchases into
blanket purchasing agreements; and leading process improvement teams as a Six Sigma Yellow
Belt.
2001 through 2002
Project Controls Specialist
Bechtel Savannah River Site, Inc.
Planning and scheduling in a production operations facility.
Professional Certifications
Planning and Scheduling Professional; Association for the Advancement of Cost Engineering
3DJHRI
Exhibit Lindsay-Direct-1
Page 2 of 2
Boards and Honors
National Association of Women in Construction, past Board Member and member
US Green Building Council, member
Toastmasters International- Say Watt Club, Board Member
3DJHRI
3DJHRI
KELLY A. VAGIANOS
3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-_____
4
PREPARED DIRECT TESTIMONY OF
5
Kelly A. Vagianos
6
7
I. INTRODUCTION
8
1.
Q.
ADDRESS.
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
A.
10
My name is Kelly A. Vagianos. I am employed by Nevada Power
11
Company d/b/a NV Energy (“Nevada Power” or the “Company”) and
12
Sierra Pacific Power Company d/b/a NV Energy (“Sierra” and, together
13
with Nevada Power, the “Companies”) as Consultant Staff, DSM
14
Planning in the Customer Strategy and Programs Department.
15
business address is 6226 West Sahara Avenue in Las Vegas, Nevada. I
16
am filing testimony on behalf of Sierra.
My
17
18
2.
Q.
19
20
PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND
AND EXPERIENCE.
A. I have a Bachelor of Arts degree in Business Administration. I also have
21
a Certificate in Human Resources Management. Since starting at Sierra
22
in 2008, I have held two positions within the Customer Strategy and
23
Programs Department.
24
background and experience are set forth in my Statement of
25
Qualifications, included as Exhibit Vagianos-Direct-1.
More details regarding my professional
26
27
28
Vagianos-DIRECT
3DJHRI
1
3.
Q.
2
PROCEEDING?
3
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
A.
Together with witnesses Lawrence Holmes, Zelkjo Vukanovic, Michelle
4
Lindsay, and Michael Brown, I sponsor and present the Demand Side
5
Management Plan (“DSM Plan”) set forth in Sierra’s 2014 – 2033
6
Integrated Resource Plan (“IRP”). My testimony describes and provides
7
the basis for Sierra’s request for approval of the proposed DSM Plan, as
8
well as the actions the Company plans to take during the three-year
9
Action Plan period associated with this IRP DSM Plan, January 2014 to
10
December 2016.
11
12
In particular, I sponsor and present the Second Refrigerator Collection
13
and Refrigerator Recycling, Residential Energy Efficient Lighting, and
14
Market and Technology Trials programs proposed in the Preferred Plan
15
and Alternative Plans. I also sponsor and present segments of the DSM
16
Plan pertaining to the Measurement and Verification (“M&V”) Results
17
Integration, the Energy Efficiency Implementation Rate (“EEIR”)
18
revenue requirement, and the M&V Process.
19
20
4.
Q.
21
22
23
PLEASE PROVIDE AN OVERVIEW OF YOUR TESTIMONY
FOR THE COMMISSION.
A.
First, in Section II, I summarize the following three DSM programs
proposed in the Preferred Plan for the 2014-2016 Action Plan period:
24
Market and Technology Trials
25
Second Refrigerator Collection and Refrigerator Recycling
26
Residential Energy Efficient Lighting
27
28
Vagianos-DIRECT
3DJHRI
1
I also sponsor several additional items in Section II regarding the
2
integration of the M&V results and the impacts of new technologies.
3
4
In Section III of my testimony I provide a brief description of the
5
calculation of the EEIR revenue requirement that will be a result of the
6
Preferred Plan during the 2014-2016 Action Plan period.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
8
Finally, in Section IV of my testimony I provide a brief discussion on the
9
subject of the M&V process.
10
11
II.
A
NALYSIS AND PROPOSALS
12
5.
Q.
PLEASE DESCRIBE THE SCOPE AND SCALE OF THE
13
MARKET AND TECHNOLOGY TRIALS PROGRAM THAT
14
SIERRA INCLUDES IN THE PREFERRED PLAN FOR THE
15
2014-2016 ACTION PLAN PERIOD.
16
A. The Market and Technology Trials program focuses on the assessment
17
and testing of innovative and energy efficient technologies with
18
applications in the residential, small-commercial, and industrial markets
19
in Nevada. The trials allow small and moderate scale tests of products
20
that have potential energy and demand savings benefits. Where the
21
benefits are demonstrated to be of sufficient quantity and reliability, the
22
measure will be incorporated in one of Sierra’s energy efficiency or
23
demand response programs. This program strengthens Sierra’s ability to
24
help customers reduce their energy bills through the implementation of
25
new, advanced and cutting edge energy efficiency measures.
26
27
28
Vagianos-DIRECT
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
1
The screening process used to select the energy efficiency measures
2
evaluated by the program is required to show a reasonable level of
3
potential for viable and economical energy savings. Sierra may require
4
that applicants provide third-party reports demonstrating the potential
5
energy savings for the energy efficiency measures for review prior to
6
accepting the market trial.
7
development project.) The results of the trial are generally supported by
8
independent customer research or measurement and verification
9
evaluation.
(The program is not a research and
10
11
Sierra recommends that the Market and Technology Trials program be
12
adopted in the 2014-2016 Action Plan period as described in the
13
Preferred Plan. The Preferred Plan budget for the Action Plan period for
14
this program is $100,000 in each year of the Action Plan period.
15
16
6.
Q.
PLEASE DESCRIBE THE SCOPE AND SCALE OF THE
17
SECOND REFRIGERATOR COLLECTION AND RECYCLING
18
PROGRAM THAT SIERRA INCLUDES IN THE PREFERRED
19
PLAN FOR THE 2014-2016 ACTION PLAN PERIOD.
20
A.
The Second Refrigerator Recycling Program is designed to help
21
customers reduce their energy consumption by removing a functional
22
second refrigerator or freezer from their home and permanently
23
removing that unit from the market place.
24
program because the second refrigerator usually operates inefficiently as
25
it is an older, less efficient refrigerator, cools a small thermal load, and is
26
often located in an unconditioned air space such as a garage.
Sierra benefits from the
Any
27
28
Vagianos-DIRECT
3DJHRI
1
residential customer can take advantage of this program. The turned in
2
unit is dismantled and recycled, and thus permanently removed from the
3
electric system. The recycling process safely disposes of all potentially
4
environmentally harmful materials and prevents reusable materials from
5
being sent to area landfills.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
6
7
The implementation of this program in the 2014-2016 Action Plan period
8
incorporates the change implemented in late 2012 in which the retail
9
component of the program was discontinued. The retail component of
10
the program involved the delivery of a new refrigerator and the removal
11
of the customer’s old refrigerator. Sierra’s program implementer then
12
collected the old refrigerators from the retailer for recycling. A study of
13
freeridership that was completed by the Company in 2012,1 determined
14
that the retail component was driving up the freeridership of the program
15
as it was a major contributor of primary units which have a higher
16
freeridership rate. The retail component was therefore discontinued.
17
This action has not only reduced the freeridership rate but also increased
18
the cost effectiveness of the program going forward.
19
20
Sierra recommends that the Second Refrigerator Collection and
21
Recycling program be adopted in the 2014-2016 Action Plan period as
22
described in the Preferred Plan.
23
Action Plan period for this program is $500,000 for each year. The
The Preferred Plan budget for the
24
25
26
1
NV Energy: Sierra Pacific Power company, Volume I: Final Report, June 14, 2012 prepared by Tetra Tech.
27
28
Vagianos-DIRECT
3DJHRI
1
estimated attendant energy savings in megawatt-hours (“MWh”) for the
2
DSM Plan are: 2,900 MWh in year 2014; 2,907 in year 2015; and 2,909
3
MWh in year 2016.
4
(“MW”) for the DSM Plan are: 0.404 MW in year 2014; 0.409 MW in
5
year 2015; and 0.413 MW in year 2016.
The aggregate demand savings in megawatts
6
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
7.
Q.
PLEASE DESCRIBE THE SCOPE AND SCALE OF THE
8
RESIDENTIAL ENERGY EFFICIENT LIGHTING PROGRAM
9
THAT SIERRA INCLUDES IN THE PREFERRED PLAN FOR
10
11
THE 2014-2016 ACTION PLAN PERIOD.
A.
The Residential Energy Efficient Lighting Program is a market-based
12
residential DSM program that provides upstream incentives to
13
consumers for the retail purchases of energy efficient lighting products.
14
Incentives are typically delivered to Sierra’s customers through
15
discounted retail pricing for energy efficient light bulbs.
16
discounts and rebates are provided for specific lighting products that
17
have earned the national ENERGY STAR® rating and logo.
18
program includes only Light Emitting Diode (“LED”) lighting measures
19
in the 2014-2016 Action Plan period.
Product
This
20
21
Sierra recommends that the Residential Energy Efficient Lighting
22
Program be adopted in the 2014-2016 Action Plan period as described in
23
the Preferred Plan. The Preferred Plan budget for the Action Plan period
24
for this program is as follows: $800,000 in year 2014; $1,200,000 in
25
year 2015; and $1,400,000 in year 2016. The attendant estimated energy
26
savings in MWh for the DSM Plan are: 1,300 MWh in year 2014; 2,100
27
28
Vagianos-DIRECT
3DJHRI
1
MWh in year 2015; and 2,700 MWh in year 2016.
The estimated
2
demand savings in MW for the DSM Plan are: 0.120 MW in year 2014;
3
0.194 MW in year 2015; and 0.249 MW in year 2016.
4
5
8.
Q.
6
ARE
THE
BENEFITS
OF
CONDUCTING
A
COMPREHENSIVE M&V PROCESS?
7
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
WHAT
A.
The primary benefit of the M&V process is the validation of the energy
8
and demand savings achieved by a program.
The validated energy
9
savings not only quantify past results but also provide essential input for
10
the planning and design for future program years.
In addition, the
11
process generates comprehensive energy savings curves customized to
12
Sierra’s DSM programs.
13
14
Given that the M&V contractor is a third-party independent evaluator, it
15
is able to provide unbiased recommendations to improve the delivery and
16
results of the programs for future periods.
17
informed by its experience providing M&V analyses for several other
18
entities.
19
customer reaction to measures or programs, provide important
20
information that causes a change in the processes for determining ex ante
21
energy savings, or actions that will enhance the M&V process.
These suggestions are
These recommendations can be measure specific, address
22
23
9.
Q.
IN WHAT WAYS DOES SIERRA INCORPORATE THE DATA
24
PROVIDED IN THE M&V REPORTS IN THE DESIGN OF
25
FUTURE PROGRAMS?
26
27
28
Vagianos-DIRECT
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
1
A. The M&V reports provide extensive data regarding the energy savings
2
that have been achieved by a program in prior years. For some programs
3
the energy savings data is provided at both the measure level and at the
4
program level. This energy savings data is the most important input in
5
determining whether to continue a program and, if it is continued, the
6
scope and scale of a program for future years. Where measure level data
7
is provided, measures are removed or scaled up in future program
8
offerings based on these results. Programs that have performed better in
9
terms of the verified energy savings are given priority for budget dollars
10
and within the selection of programs for each of the alternative plans. In
11
addition, the energy savings curves developed as a part of the M&V
12
process are a key input for the determinant of the cost effectives of
13
program for future years.
14
15
10.
Q.
PLEASE
DESCRIBE
HOW
SIERRA
INTEGRATED
2012
16
PROGRAM YEAR M&V RESULTS IN THE PREFERRED PLAN
17
AND ALTERNATIVE PLANS.
18
A.
The M&V results for program year 2012 provided valuable lessons
19
learned and informed conclusions and recommendations that assisted in
20
customizing the design process for the Preferred Plan and Alternative
21
Plans. The lessons learned were used to revise the mix of measures,
22
adjust incentives, revise marketing strategies, and adjust program targets.
23
These lessons are an integral and important part of continuous feedback
24
and process improvement that was used to plan, evaluate, and improve
25
each of the programs.
26
27
28
Vagianos-DIRECT
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
1
An example of lessons learned and conclusions and recommendations is
2
provided by the Second Refrigerator Collection and Refrigerator
3
Recycling Program. For the 2014-2016 Action Plan period, the program
4
will be updating its per unit energy savings estimates at the beginning of
5
each program year to anticipate the various predictable changes in
6
refrigerator and freezer populations from year to year. According to the
7
2012 M&V results, the 2012 estimated energy savings estimates have
8
significantly exceeded the verified savings; thus it would be appropriate
9
for the implementer to analyze the three-year trend to develop new
10
estimates for future program years.
11
12
The lessons learned and conclusions and recommendations are included
13
in each program data sheet provided in Exhibit A to the DSM Plan
14
Narrative.
15
16
11.
Q.
HOW
HAS
SIERRA
INCORPORATED
THE
17
RECOMMENDATIONS CONTAINED IN THE M&V REPORTS
18
FOR PROGRAM ENHANCMENTS?
19
A.
Sierra reviews each of the recommendations for program enhancement
20
included in the M&V reports to determine the best manner to leverage
21
the recommendation for future program performance enhancement.
22
Where
23
implementation contractor in evaluating the most effective manner of
24
implementing the recommendations. The recommendations range from
25
simple changes to the data collection process to better facilitate the
applicable,
Sierra’s
Program
Managers
involve
the
26
27
28
Vagianos-DIRECT
3DJHRI
1
M&V process to changes that will increase the energy savings of the
2
program or potentially improve customer responses to the program.
3
4
Q.
PLEASE PROVIDE AN EXAMPLE OF RECOMMENDATIONS
5
MADE BY THE M&V CONTRACTOR THAT WILL PROVIDE
6
BENEFITS TO THE PROGRAM IMPLEMENTATION.
7
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
12.
A.
An example is included in 2012 M&V Report for the Commercial
8
Incentives program. The recommendations in that report observe that
9
the M&V process could be improved by earlier involvement of the M&V
10
contractor in the M&V process.
ADM makes almost an identical
11
recommendation in the M&V report for the 2012 Commercial New
12
Construction program. ADM makes these recommendation based on
13
two observations. The first is that some customers are confused about
14
their role in an M&V process after a project is completed.
15
recommends addressing this issue by providing clearer communication
16
with a customer prior to the start of the project. In addition, for larger or
17
more complex projects, ADM recommends that all of the parties meet
18
prior to the start of the project and that the M&V processes specific to
19
that project be clearly discussed.
ADM
20
21
The recommendations also address the need for early identification of
22
projects that might be difficult to evaluate after completion,
23
identification of projects that involve new products or technologies, and
24
recognition of the need to collect additional existing site data for the
25
project site report before the start of work. ADM recommended that the
26
M&V process could be significantly enhanced if a meeting is held prior
27
28
Vagianos-DIRECT
3DJHRI
1
to the start of the project that identifies the information and
2
instrumentation that would provide for the optimal M&V process for all
3
such projects.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
4
5
Sierra recognized that these recommendations provided important
6
opportunities to improve the M&V process. These types of issues have
7
arisen from time to time in the past but it became apparent that more
8
definitive action was needed with larger, more complex projects to
9
prevent or minimize their recurrence in the future.
It is Sierra’s
10
assessment that each of the issues that arose could have been avoided
11
with better coordination and communications by all parties prior to the
12
start of the project.
13
14
13.
Q.
WHAT ACTIONS HAS SIERRA TAKEN TO INCORPORATE
15
THE
16
CONTRACTOR IN THE EXAMPLE PROVIDED ABOVE?
17
A.
RECOMMENDATIONS
MADE
BY
THE
M&V
Sierra recognized that these recommendations provided important
18
opportunities to improve the M&V process.
19
implemented several changes to the process.
As a result, Sierra
20
21
First, Sierra implemented the scheduling of mandatory preconstruction
22
meetings for applicable projects.
23
mandatory preconstruction meeting for projects that exceed 500,000
24
kWh in annual savings, involve new technologies or applications of
25
technologies for which the most appropriate M&V methodologies are
26
not evident, and where there might be constraints or difficulties in
Specifically Sierra requires a
27
28
Vagianos-DIRECT
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
1
performing the M&V evaluation. The purpose of the preconstruction
2
meeting is to review the project in sufficient detail so that all participants
3
understand the scope and nature of the project, determine what
4
information and data will be required to support the M&V work, how the
5
data will be collected and who will collect the data. The process for
6
collecting the M&V data will be clearly explained to the customer and
7
the customer will be requested to advise if there are operational
8
constraints that must be accommodated in the collection of the M&V
9
data. The result of the meeting will be a clearly defined project specific
10
M&V plan including timing, responsibilities, and buyin from all parties.
11
The preconstruction meeting must include appropriate representatives for
12
the customer, the implementation contractor, the M&V contractor,
13
Sierra, and when warranted the installation contractor. The customer’s
14
feedback and buy-in during the M&V plan period will provide a better
15
customer experience and in turn improve their willingness to participate
16
in the improved efforts.
17
18
Another process change is to place additional emphasis in the project
19
documentation and applications on the customer requirement to
20
accommodate and assist in the M&V work as a condition of receiving a
21
rebate or incentive for a project. The project application will require an
22
acknowledgement of this requirement by the customer.
23
24
Sierra will continuously monitor the preconstruction meeting process and
25
make additional modifications as appropriate based on actual project
26
experience.
27
28
Vagianos-DIRECT
3DJHRI
1
14.
PLEASE DESCRIBE THE THREE PROJECTS THAT WERE
2
SPECIFICALLY LISTED IN ADM’S RECOMMENDATIONS IN
3
THE 2012 COMMERCIAL RETROFIT INCENTIVES AND THE
4
2012 COMMERCIAL NEW CONSTRUCTION M&V REPORTS.
5
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
Q.
A.
The recommendations in the 2012 Commercial Retrofit Incentives
6
program M&V report includes two projects identified as SB12-01837
7
and SB12-02647. Both of these projects involved the installation of
8
variable frequency drives (“VFD”) on large motors with pumping loads.
9
One VFD was installed on a 400HP precipitate filter press feed pump
10
and the other VFD was installed on an existing 250HP de-aerator feed
11
pump.
12
Construction program M&V report includes one project identified as
13
SB12-01894. This project also involved the installation of VFD on large
14
motor with a pumping load. The 1,250HP pump for this project pumps
15
the barren solution from the barren tank up to the leach pads. All three
16
of these projects were completed by the same customer.
The recommendations in the 2012 Commercial New
17
18
15.
Q.
PLEASE DESCRIBE THE SITUATION THAT LED TO ADM’S
19
RECOMMENDATIONS REGARDING THE INVOVLEMENT OF
20
THE CUSTOMER IN THE M&V PROCESS AND THAT THE
21
PERSISTENCE OF THE SAVINGS BE EVALUATED FOR THESE
22
THREE PROJECTS.2
23
24
25
2
26
See Section 5 page 1 of the 2012 Commercial Retrofit Incentives Program M&V Report and Section 5 of
the 2102 Commercial New Construction Program M&V Report.
27
28
Vagianos-DIRECT
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
1
A.
I t is Sierra’s assessment that ADM’s recommendations were a result of
2
there not being clarity on the part of customer regarding the M&V work
3
to verify the energy savings that would be required following the
4
completion of the project. If the customer had been aware of the specific
5
M&V requirements for these projects prior to ordering the VFDs, the
6
VFDs could have been ordered with the software that is needed to record
7
the operating data, referred to as trending data in the M&V reports, that
8
would have supported the M&V process. The trending data would have
9
provided ADM the best available data to for calculating the verified
10
energy savings.
11
12
16.
Q.
HOW WAS ADM ABLE TO MEASURE AND VERIFY THE
13
ENERGY SAVINGS IN THE ABSENCE OF THE TRENDING
14
DATA?
15
A.
ADM employed an engineering analysis based on operating data
16
provided by the implementation contractor, the operating data collected
17
during ADM’s onsite inspection and operating data collected through
18
interviews with the customer.
19
20
17.
Q.
21
22
WHAT IS REQUIRED TO OBTAIN THE TRENDING DATA
FROM THE VFDS?
A.
It is Sierra’s understanding that the VFD software will need to be
23
upgraded to enable the data to be stored and collected. The installation
24
of the software upgrade will require a shutdown of the customer’s
25
operations.
26
27
28
Vagianos-DIRECT
3DJHRI
1
18.
WHAT ACTION IS BEING TAKEN THAT WILL FACILITATE
2
AN ANALYSIS OF THE PERSISTENCE OF THE ENERGY
3
SAVINGS FOR EACH OF THESE THREE PROJECTS AS
4
RECOMMENDED BY ADM?
5
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
Q.
A.
Sierra is working with the customer to facilitate an analysis of the
6
persistence of the energy savings for each of the three projects. The
7
customer has stated that the acquisition of the needed software has been
8
budgeted and that the trending data should be available next year. If the
9
data is available, then ADM could analyze the persistence of the energy
10
savings for these three VFD projects as is recommended in the two
11
M&V reports.
12
13
19.
Q.
14
15
PLEASE DESCRIBE HOW SIERRA HAS COMPLIED WITH
NAC 704.934(3) IN CREATING ITS DEMAND SIDE PLAN.
A. In accordance with NAC 704.934(3), Sierra considered the impact of
16
applicable new technologies on current and future demand side options.
17
Examples of new technologies considered include Heating, Ventilation,
18
and Air Conditioning (“HVAC”) Optimization solutions, the leveraging
19
of smart grid opportunities, monitoring standard and code changes, and
20
the delivery of DSM programs through the web-based platform called
21
TrakSmart®.
22
23
HVAC Optimization solutions provide significant energy savings
24
opportunities for Demand Response program participants in addition to
25
more advanced demand response functions. These solutions introduce a
26
new concept for energy savings based upon strong analytics from a
27
28
Vagianos-DIRECT
3DJHRI
1
remote site using the internet to optimize the operation of the controlled
2
air conditioning systems.
3
provided in the Market and Technology Trials and Demand Response
4
Program Data Sheets.
More information on such solutions is
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
5
6
Technology also impacts the manner in which Sierra manages and
7
monitors DSM programs. Sierra has replaced the Data Store Web Portal
8
with TrakSmart® from Nexant, a new web-based platform for demand
9
side management business process automation. TrakSmart® is a central
10
system of record for program management, data tracking and reporting
11
that manages the complete DSM program lifecycle including;
12
implementation, program performance tracking, evaluation support, and
13
measurement and verification activities.
14
15
Once fully operational, TrakSmart®’s capabilities will enable the
16
Companies to provide log-on access to Staff and other authorized parties
17
to view all recorded program and project data.3 This will allow those
18
authorized to have access to program implementation data throughout
19
the entire program year as well as provide an additional level of visibility
20
and transparency.
21
22
23
24
25
26
3
Subject to appropriate confidential customer information controls and processes.
27
28
Vagianos-DIRECT
3DJHRI
1
CALCULATION OF THE ENERGY EFFICIENCY IMPLEMENTATION
2
RATE (“EEIR”) REVENUE REQUIREMENT THAT WILL BE CAUSED
3
BY THE PROPOSED 2014, 2015, AND 2016 PREFERRED PLAN.
4
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
III. 20.
Q.
THE
COMMISSION’S
DIRECTIVE
IN
ORDERING
5
PARAGRAPHS 10 AND 11 OF ITS ORDER IN DOCKET NOS. 10-
6
10024 AND 10-10025 DIRECTED THE COMPANIES TO
7
PROVIDE A CALCULATION OF EXPECTED LOST REVENUES
8
THAT WILL BE GENERATED FROM THE ENTIRE 2014, 2015,
9
AND 2016 PORTFOLIO, BROKEN DOWN BY INDIVIDUAL
10
PROGRAMS ON OR BEFORE THEIR NEXT RESPECTIVE
11
ANNUAL DEMAND SIDE MANAGEMENT UPDATE. HAS THE
12
COMPANY PROVIDED A CALCULATION OF EXPECTED
13
LOST REVENUES THAT WILL BE GENERATED FROM THE
14
ENTIRE 2014-2016 PORTFOLIO IN THIS FILING?
15
A.
Yes. The Commission has indicated that the impact of proposed DSM
16
programs on rates is one of the criteria used by the Commission in
17
evaluating the Company’s proposed DSM plans. Sierra has therefore
18
included a calculation of expected lost revenues for the entire 2014-2016
19
period in this filing. The expected lost revenues have been calculated
20
individually for each program in the Preferred Plan and tabulated to
21
show the expected lost revenues at the portfolio level. Expected lost
22
revenues have been estimated for the full year incremental lost revenue
23
that will be generated in the 2014, 2015, and 2016 program years as
24
proposed by the Company. The estimated cumulative lost revenue by
25
program and by portfolio for 2014 includes program measures installed
26
from June 1, 2012 through December 31, 2014.
The estimated
27
28
Vagianos-DIRECT
3DJHRI
1
cumulative lost revenue by program and by portfolio for 2015 for each
2
program includes program measures installed from June 1, 2012 through
3
December 31, 2015 and the cumulative lost revenue by program and by
4
portfolio for 2016 for each program includes program measures installed
5
from June 1, 2012 through December 31, 2016.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
6
7
The Company’s DSM group provided energy savings projections to the
8
Company’s Rates and Regulatory Department for the computation of the
9
revenue requirement. Mr. Bohrman, from the Rates and Regulatory
10
Department explains and supports in his Direct Testimony the
11
calculation of the EEIR revenue requirement.
12
13
21.
Q.
14
15
WHAT
CONTRIBUTES
TO
THE
CUMULATIVE
LOST
REVENUES IN 2014, 2015, AND 2016?
A. The cumulative lost revenues are caused by energy efficiency measures
16
that have been installed in a program year or in previous program years
17
that are not reflected in the billing determinates that were used to
18
determine the rates that are in effect during that program year. The
19
contribution for programs delivered in each year to lost revenues for
20
years 2014, 2015, and 2016 are listed in the following bullets.
2014
21
o 2012 Partial Year – Energy efficiency measures installed
22
between June 1, 2012 and December 31, 2012
23
24
o 2013 Partial Full Year - Energy efficiency measures
25
installed between January 1, 2013 and December 31, 2013
26
27
28
Vagianos-DIRECT
3DJHRI
1
o 2014 First Year Savings - Energy efficiency measures
2
installed between January 1, 2014 and December 31, 2014
3
2015
o 2012 Partial Year – Energy efficiency measures installed
4
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
5
between June 1, 2012 and December 31, 2012
6
o 2013 Partial Full Year - Energy efficiency measures
7
installed between January 1, 2013 and December 31, 2013
8
o 2014 Full Year Savings - Energy efficiency measures
9
installed between January 1, 2014 and December 31, 2014
10
o 2015 First Year Savings - Energy efficiency measures
11
installed between January 1, 2015 and December 31, 2015
20164
12
o 2012 Partial Year – Energy efficiency measures installed
13
between June 1, 2012 and December 31, 2012
14
15
o 2013 Partial Full Year - Energy efficiency measures
16
installed between January 1, 2013 and December 31, 2013
17
o 2014 Full Year Savings - Energy efficiency measures
18
installed between January 1, 2014 and December 31, 2014
19
o 2015 Full Year Savings - Energy efficiency measures
20
installed between January 1, 2015 and December 31, 2015
21
o 2016 First Year Savings - Energy efficiency measures
22
installed between January 1, 2016 and December 31, 2016
23
24
25
26
4
The computation of cumulative lost revenues for 2016 assumes Sierra files a general rate case on June 1,
2016.
27
28
Vagianos-DIRECT
3DJHRI
1
22.
Q.
2
ENERGY SAVINGS?
3
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
HOW DO THE COMPANIES DEFINE THE TERM FIRST YEAR
A.
The Companies define the term “first year savings” as those energy
4
savings that would be achieved by installed energy efficiency measures
5
during the program year in which the energy efficiency measures are
6
installed.
7
because measures installed as the year progresses are not in place for a
8
full year and do not achieve a full year of savings in that first year. This
9
is demonstrated by examining the installation of a MR-16 LED light
10
bulb with an estimated annual savings of 24 kWh. If the light bulb is
11
installed on January 1, 2014 it will be in place for all of 2014 and will
12
contribute savings each month of the year, for a first year savings of 24
13
kWh.
14
contribute only one half of the annual savings in 2014 for a first year
15
savings of 12 kWh. Similarly, if the same light bulb is installed on
16
December 1, 2014 it will contribute only approximately one twelfth of
17
the annual savings in 2014 for a first year savings of 2 kWh. The first
18
year savings accounts for the reduced savings experienced in the first
19
year as measures are installed throughout the year.
The first year savings are less than the full year savings
If the light bulb is instead installed on July 1, 2014, it will
20
21
23.
Q.
22
23
HOW DO THE COMPANIES DEFINE THE TERM FULL YEAR
ENERGY SAVINGS?
A.
The Companies define the term “full year energy savings” as those
24
energy savings that would be achieved by a program if all measures
25
installed in one program year were in operation for a full calendar year.
26
The full year energy savings is first achieved in the year following the
27
28
Vagianos-DIRECT
3DJHRI
1
program year in which the measures are installed. Full year savings
2
occur in the following year and all subsequent years until the final year
3
of the expected useful life of the installed energy efficiency measures.
4
5
24.
Q.
6
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
HOW DO THE COMPANIES DEFINE THE TERM PARTIAL
YEAR ENERGY SAVINGS?
A.
The Companies define the term “partial year energy savings” as the
8
portion of the full year savings that are accounted for by energy
9
efficiency measures installed in a year that is included in the certification
10
period for the most recent general rate case. The determination of partial
11
year savings is similar to that of first year savings but a different
12
timeframe is involved. The timeframe considered is the certification
13
period for the general rate case.
14
examining the installation of a MR-16 LED light bulb with an estimated
15
annual savings for 24 kWh, but over the certification period running
16
from June 1, 2012 through May 30, 2013 instead of a calendar year. If
17
the light bulb is installed on June 1, 2012 it will essentially be in place
18
for all of the certification period of June 1, 2012-May 30, 2013 and the
19
savings would be fully reflected in the billing determinates and therefore
20
would have virtually no contribution to lost revenues. If the light bulb is
21
installed instead on December 1, 2012, it will provide only one half of
22
the annual savings or 12 kWh during the certification period. The other
23
half would not be reflected in the billing determinates and would
24
contribute to lost revenues during the 2013 through 2016 period.
25
Similarly, if the same light bulb is installed in May 1, 2013, only
26
approximately one twelfth of the annual savings or 2 kWh, would occur
This is demonstrated by again
27
28
Vagianos-DIRECT
3DJHRI
1
during the certification period of June 1, 2012 through May 30, 2013.
2
The remaining 10 kWh of annual savings would occur after the
3
certification period and would cause lost revenues in 2013-2016 period.
4
The partial year savings accounts for the energy savings that occurs in a
5
year that includes a general rate case certification period that are not
6
included in the billing determinates derived from that certification
7
period.
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
25.
Q.
HOW DID THE COMPANY INCORPORATE THE FREE-
10
RIDERSHIP AND SPILLOVER RATES FOR EACH PROGRAM
11
IN
12
REVENUE VALUES?
13
A.
THE
DETERMINATION
OF
EEIR
REPLACEMENT
The Company calculated the net energy savings for each program by
14
applying the free-ridership factors determined in the NV Energy DSM
15
Free-ridership Spillover Study Results for NV Energy: Sierra Pacific
16
Power Company, Volume I: Final Report, June 14, 2012 prepared by
17
Tetra Tech. The results for 2011 are applied to 2012 and the results for
18
2013 are applied to each year in the 2013-2016 period. The net to gross
19
ratios in this study were approved by the Commission’s Order in Docket
20
Nos. 12-06052 and 12-060523.5 Integral in the presentation of the net to
21
gross ratios in the Tetra Tech report are the freeridership rates for each
22
program.
23
24
25
26
5
See Paragraph 234 of the Commission’s Order issued December 24, 2012 in Docket Nos. 12-06052 and 12­
06053
27
28
Vagianos-DIRECT
3DJHRI
1
IV
M&V PROCESS
2
26.
Q.
3
COMPANY TO MEASURE AND VERIFY ENERGY SAVINGS
4
THAT FOLLOW FROM THE IMPLEMENTATION OF ENERGY
5
EFFICIENCY AND CONSERVATION (“EE&C”) PROGRAMS.
6
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE DESCRIBE THE PROCESS EMPLOYED BY THE
A. To ensure that its M&V objectives are met, the Company employs a
7
measurement and verification process that is based on generally accepted
8
industry standards and procedures. This work is performed by a third
9
party M&V evaluation contractor with considerable experience. The
10
purpose of M&V activities is to collect and analyze data to calculate the
11
energy and demand savings that result from EE&C programs and
12
measures installed at sites that participate in the Company’s energy
13
efficiency program. Sierra has committed to using best practice M&V
14
for two key reasons. First, M&V provides systematic measurement of
15
the performance of energy efficiency programs and technologies.
16
Second, engineering methods and technical data provide valid and
17
reliable results.
18
As part of performing the M&V evaluation the M&V contractor selects a
19
random sample of projects which will allow the determination of savings
20
to be made with 10.0 percent precision at the 90 percent confidence
21
level.
22
23
A more in depth description of the M&V process is provided by the
24
Direct Testimony of Messrs. Dohrmann, Oliver, and Baroiant and in the
25
overview of the M&V process provide in Technical Appendix 17.
26
27
28
Vagianos-DIRECT
3DJHRI
1
The M&V Reports for the 2012 programs are provided in Technical
2
Appendices DSM-5 through DSM-14. The M&V Reports provide the
3
key input for determining the performance of Sierra’s portfolio of DSM
4
programs for the 2012 program year.
5
6
27.
Q.
7
8
DOES
THIS
CONCLUDE
YOUR
PRE-FILED
DIRECT
TESTIMONY?
A.
Yes.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Vagianos-DIRECT
3DJHRI
Exhibit Vagianos-Direct-1
Page 1 of 1
Statement of Qualifications
Kelly A. Vagianos
June 11, 2012
Education
Bachelor of Arts in Business Administration, Baldwin-Wallace College, 2003
Certificate in Human Resources Management, Baldwin-Wallace College, 2003
Professional Experience
2011 To Date
Consultant Staff, DSM Planning
NV Energy
Responsible for the implementation of the measurement and verification activities of the
Demand Side Management (DSM) programs, manage individual DSM program data tracking,
assist in the calculation of the revenue requirement as a result of implementing DSM programs,
program manager for the Time-of-Use rate implementation, assist in the preparation of the DSM
portion of regulatory filings, and assist in analyzing the results of the programs. Participate in
the development of community energy efficiency and conservation programs and the Nevada
Dynamic Pricing Trial.
2008-2010
Project Leader, Energy Efficiency and Conservation
NV Energy
Responsible for the implementation of the measurement and verification activities of the
Demand Side Management (DSM) programs and manage individual DSM program data
tracking. Participated in the development of community energy efficiency and conservation
programs.
2008
Independent Contractor
Nevada Child Abuse Prevention
Responsible for designing and implementing a public education and awareness campaign
regarding Shaken Baby Syndrome.
2003-2007
Operations Manager
SVA Communications, Inc.
Responsibilities included managing the communications for the Northeast Ohio Public Energy
Council (NOPEC) the largest public energy aggregation in the Country, providing consultation
services for a variety of political campaigns and public awareness issues, and responsible for the
internal day-to-day management of the Company.
Boards and Honors
HomeFree Nevada, Board Member, Vice President and Secretary, 2009-present
Green Chips, member, 2010-present
Association of Energy Service Professionals, member 2009-present
Treasurer to Ohio State Representative Thomas F. Patton, 2003-2005
3DJHRI
3DJHRI
ZELJKO VUKANOVIC
3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-_____
4
PREPARED DIRECT TESTIMONY OF
5
Zeljko Vukanovic
6
7
1.
Q.
8
ADDRESS.
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
A. My name is Zeljko Vukanovic. I am employed by Nevada Power Company d/b/a
10
NV Energy (“Nevada Power” or the “Company”) and Sierra Pacific Power
11
Company d/b/a NV Energy (“Sierra” and, together with Nevada Power, the
12
“Companies”) as Consultant Staff, DSM Planning in the Customer Strategy and
13
Programs Department. My business address is 6226 West Sahara Avenue in Las
14
Vegas, Nevada. I am filing testimony on behalf of Sierra.
15
16
2.
Q.
17
18
PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
EXPERIENCE.
A. I have a Bachelor of Science degree in Business Administration. I also have a
19
Master of Business Administration degree and Master of Science in Banking and
20
Financial Services Management degree. Since starting at Nevada Power in 2006,
21
I have held three positions within the Customer Strategy and Programs
22
Department, and one position within Financial Planning and Analysis and
23
Resource Planning. Additional details regarding my professional background and
24
experience are set forth in my Statement of Qualifications, provided in Exhibit
25
Vukanovic-Direct-1.
26
27
28
Vukanovic-DIRECT
1
3DJHRI
1
3.
Q.
2
IS
THE
PURPOSE
OF
YOUR
TESTIMONY
IN
THIS
PROCEEDING?
3
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
WHAT
A.
Together with witnesses Lawrence Holmes, Michael Brown, Kelly Vagianos, and
4
Michelle Lindsay, I sponsor the Demand Side Management Plan (“DSM Plan”)
5
set forth in Sierra Pacific Power’s 2014 – 2033 Integrated Resource Plan (“IRP”).
6
Specifically, I sponsor and support the following items: the development and
7
selection of the Preferred and two alternative plans, a description of the cost
8
effectiveness analysis performed by the Company, and the Solar Thermal Water
9
Heating Program.
10
11
4.
12
Q.
PLEASE PROVIDE AN OVERVIEW OF YOUR TESTIMONY.
A. The first section of my testimony, Section A, presents the development of the
13
Preferred Plan and two alternative plans as well as basis for selecting and
14
recommending the Preferred Plan.
15
alternative plans.Section B provides a description of the cost effectiveness process
16
used to evaluate proposed DSM programs. In Section C, I describe the Solar
17
Thermal Water Heating program.
In this section I also describe the two
18
19
SECTION A: THREE ALTERNATIVE PLANS
20
5.
Q.
WHAT DIRECTION DID THE COMMISSION PROVIDE REGARDING
21
THE DEVELOPMENT OF ALTERNATIVE DSM PLANS IN THIS
22
INTEGRATED RESOURCE PLAN FILING?
23
24
A. The Commission directed the Company to provide at least three portfolios, one
preferred and two alternatives.
The Commission further directed that the
25
26
27
28
Vukanovic-DIRECT
2
3DJHRI
1
Company provide the rationale for choosing the preferred plan over the two
2
alternative plans.1
3
4
6.
Q.
5
PROVIDE A PREFERRED PLAN AND TWO ALTERNATIVE PLANS?
6
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
HAS THE COMPANY COMPLIED WITH THE DIRECTIVE TO
A.
Yes. The DSM Plan developed by the Company includes a Preferred Plan and
7
two alternative plans, the Minimum Impact Alternative Plan and the Maximum
8
Net Benefits Alternative Plan. The three plans each address different strategic
9
load and policy objectives.
10
11
7.
Q.
PLEASE DESCRIBE THE MAXIMUM NET BENEFITS ALTERNATIVE
12
PLAN INCLUDING THE STRATEGIC LOAD OBJECTIVE OF THAT
13
PLAN.
14
A.
The Maximum Net Benefits Alternative Plan is a more aggressive DSM plan that
15
seeks to achieve the greatest level of energy savings and peak demand reductions,
16
with an emphasis on peak demand reduction. The objective for this plan is to
17
achieve immediate and sustained energy savings along with a reduction in the
18
system peak. The plan increases budgets and targets for most programs and adds
19
additional dimensions such as niche projects directed at target businesses or
20
industries. An element of this plan is a higher level of risk of not meeting the
21
plan’s targets. For some programs, it would be necessary to increase incentives
22
and marketing to achieve targeted savings. For example, to further encourage
23
peak demand reductions, the value for the incentives for on-peak kWh savings is
24
increased for this plan.
25
26
27
1
28
Vukanovic-DIRECT
See Paragraph 373 of the Commission’s Order in Docket Nos. 11-07026 and 11-07027 issued March 23, 2012.
3
3DJHRI
1
8.
Q.
2
PROPOSED BY THE COMPANY IN THIS IRP.
3
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
PLEASE SUMMARIZE THE MAXIMUM NET BENEFITS PLAN
A.
The Maximum Net Benefits Plan presented in the DSM Plan includes eleven
4
programs, two of which are new programs and nine of which are enhanced
5
designs of the programs from the approved 2010 IRP Demand Side Plan. Table
6
DS-19, Demand Side Action Plan Budget, in the DSM Narrative lists those
7
programs and provides the annual budgets for each program for the 2014-2016
8
Action Plan Period.
9
Maximum Net Benefits Plan are presented in Table ZV-1.
The budget, energy savings and demand savings for
10
Table ZV-1: Maximum Net Benefits Plan
11
12
Preferred Plan
13
2014
2015
2016
$14,770,000
$18,935,000
$24,435,000
Energy Savings (kWh)
75,018,000
90,317,000
101,924,000
Demand Savings (kW)
21,912
40,421
62,803
Budget ($)
14
15
16
17
18
9.
Q.
STRATEGIC LOAD OBJECTIVE OF THAT PLAN.
19
20
PLEASE DESCRIBE THE MINIMUM IMPACT PLAN INCLUDING THE
A.
The Minimum Impact Plan provides the least amount of energy savings and peak
21
demand reductions among the three plans provided. The objective of this plan is
22
a more gradual long-term and sustained reduction in energy consumption and
23
system peak reduction. This plan would have the least impact on avoiding the
24
costs for the construction of new generation and T&D facilities. On the other
25
hand, this plan would also have the least impact on short-term rates.
26
challenge in designing this plan was to scale down programs to a level that
27
remains cost effective and retains the partnerships, relationships, networks and the
28
Vukanovic-DIRECT
The
4
3DJHRI
1
basic DSM infrastructure for the continued economic delivery of DSM programs.
2
Less cost effective programs that are included in the Preferred and Maximum Net
3
Benefit plans are not present in the Minimum Impact plan to enable the
4
concentration of resources in the more cost effective programs.
5
6
10.
Q.
7
SUMMARIZE
THE
DSM
MINIMUM
IMPACT
PLAN
PROPOSED BY THE COMPANY IN THIS IRP.
8
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
PLEASE
A.
The Minimum Impact Plan presented in the DSM Plan includes six programs, one
9
of which is a new program and five of which are enhanced designs of the
10
programs from the approved 2010 IRP Demand Side Plan. Table DS-25, Demand
11
Side Action Plan Budget, in the DSM Narrative lists those programs and provides
12
the annual budgets for each program for the 2014-2016 Action Plan Period. The
13
budget, energy savings and demand savings for Minimum Impact Plan are
14
presented in Table ZV-2 below.
15
Table ZV-2: Minimum Impact Plan
16
17
Minimum Impact Plan
18
2014
2015
2016
Budget ($)
$7,100,000
$7,600,000
$8,300,000
Energy Savings (kWh)
29,340,000
30,140,000
30,640,000
Demand Savings (kW)
9,662
15,662
18,662
19
20
21
22
23
11.
Q.
STRATEGIC LOAD OBJECTIVE OF THAT PLAN.
24
25
PLEASE DESCRIBE THE PREFERRED PLAN INCLUDING THE
A.
The Preferred Plan is designed to reflect the increasing magnitude of the open
26
position as shown in Table ZV-3. The alternative plans, Maximum Net Benefits
27
and Minimum Impact, act as bookends, providing two distinctly different
28
Vukanovic-DIRECT
5
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
1
approaches to DSM planning for the 2014-2016 Action Plan period. One seeks
2
maximum benefits and one is focusing on moderating short term rate impacts. To
3
find an optimal balance the Company evaluated future open positions and costs of
4
meeting the needs of the system via alternative DSM Plans and designed a plan
5
that pulls from the best features of each of the bookend plans. The Preferred Plan
6
takes an alternate approach as compared to the two alternative plans as it is
7
designed to be responsive to the growing open position reflected in the Loads and
8
Resources Table (“L&R Table”). The Preferred Plan begins in 2014 with a
9
modestly aggressive portfolio of programs and then expands in each of the
10
following two years. The shape of the Preferred Plan matches the growing open
11
position as shown on Table ZV-3.2
12
position that is forecasted for the period of 2014-2023 without any new supply
13
side resources and assuming that no DSM is accomplished after 2013. The open
14
position grows steadily from 126 MW in 2014 to 904 MW in 2023. The load
15
objective of the Preferred Plan is to grow the scope and scale of the contribution
16
made by DSM in a pattern that reflects the Company’s growing open position.
17
The DSM Preferred Plan provides 15.6 MW of demand reduction in 2014, 24.7
18
MW in 2015 and 33.0 MW of demand reduction in 2016.
This table shows the Company’s open
19
Table ZV-3: Open Position Without New Supply Additions or DSM After 2013
20
21
Year
22
Megawatt
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
126
296
355
410
449
464
490
516
675
904
23
24
25
26
27
2
28
Vukanovic-DIRECT
Table ZV-3 replicates the first line of Table DS-8 in the DSM Narrative
6
3DJHRI
1
12.
Q.
2
THE COMPANY IN THIS IRP.
3
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
PLEASE SUMMARIZE THE DSM PREFERRED PLAN PROPOSED BY
A.
The DSM Preferred Plan presented in the DSM Plan includes ten programs, one
4
of which is a new program and nine of which are enhanced designs of the
5
programs from the approved 2010 IRP Demand Side Plan. Table DS-10, Demand
6
Side Action Plan Budget, in the DSM Narrative lists those programs and provides
7
the annual budgets for each program for the 2014-2016 Action Plan Period. The
8
budget, energy savings and demand savings for Preferred Plan are presented in
9
Table ZV-4 below.
10
Table ZV-4: Preferred Plan
11
12
Preferred Plan
2014
2015
2016
13
Budget ($)
$10,410,000
$11,730,000
$13,580,000
14
Energy Savings (kWh)
49,062,000
55,355,000
57,900,000
15
Demand Savings (kW)
15,560
24,739
32,996
16
17
18
13.
Q.
WHAT FACTORS DID SIERRA CONSIDER IN THE DESIGNING THE
19
DSM PORTFOLIOS INCLUDED IN EACH PLAN AND THE SELECTION
20
OF THE PLAN OF THE PREFERRED PLAN TO RECOMMEND FOR
21
COMMISSION APPROVAL?
22
23
A. Sierra considered the following eight strategic load objective criteria in selecting
the Preferred Plan.
24
1. Meeting energy and demand needs of customers
25
2. Impact on short term rates
26
3. Impact on long term rates
27
28
Vukanovic-DIRECT
7
3DJHRI
1
4. The net benefits provided for the communities served
2
5. Providing tools to help customers manage their bills
3
6. Contributing portfolio credits for complying with the Renewable
4
Portfolio Standard
5
7. Reducing greenhouse gasses
6
8. Facilitating the integration of renewable resources
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
8
Each of these criteria provides a measure of the benefits that are provided by a
9
well-designed portfolio of DSM programs. In evaluating each of these criteria
10
Sierra determined that the magnitude of the growing open position as
11
demonstrated by the excerpt from the L&R table provided in my Q&A 12 made
12
the first criteria, meeting the energy and demand needs of customers the dominant
13
criteria. In addition, Sierra determined that the rate impacts, both short term and
14
long term provide a good counter balance to the costs involved in meeting the
15
energy and demand needs of customers. Sierra therefore based its evaluation of
16
which of the three alternative plans to recommend for Commissions approval
17
based on these three criteria. The other five criteria informed the portfolio design
18
and evaluation process but did not form the basis of the Company’s selection
19
process and recommendation.
20
21
14.
Q.
22
23
PLEASE EXPLAIN THE BASIS FOR SELECTING THE PREFERRED
PLAN OVER THE ALTERNATIVE PLANS.
A. The evaluation of which plan to recommend to the Commission for approval
24
centered on the resource needs that are depicted in Table ZV-3. Based on the
25
steady growth of the open position through 2023, and the magnitude of the open
26
position in 2023 of 904 MW as shown in Table ZV-3, it is clear that the
27
28
Vukanovic-DIRECT
8
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
1
forecasted open position is not addressed adequately with the Minimum Rate
2
Impact Plan, which takes a slower approach in terms of energy savings and
3
demand reduction. The Minimum Rate Impact Plan therefore falls too short in
4
terms of the resources provided. To assess the full cost of delivering Alternative
5
Plans to all ratepayers the Company has looked more closely at the results of the
6
rate impact analysis.
7
Alternative plans are presented in the Narrative in the tables for each alternative
8
plan. Results of the analysis reveal that all three alternative plans cause an
9
increase in rates in a short term (1-4 years) but, due to decreased consumption, in
10
aggregate bills are reduced. The Maximum Net Benefits Alternative Plan has an
11
aggressive ramp up which leads to the largest short term increase in rates of all
12
three plans. The Preferred Plan is tailored to provide strong energy and peak
13
demand savings with a reasonable and sustainable impact on rates by presenting a
14
portfolio of programs that are designed to help meet system resource requirements
15
in the Action Plan Period and the forecasted growing short position in future
16
years. The Company therefore recommends that the Preferred Plan be approved.
The detailed results of impact on rates for all three
17
18
15.
Q.
WILL THE PROPOSED DSM PLAN BE ABLE TO PROVIDE THE
19
MAXIMUM CONTRIBUTION TO THE RENEWABLE PORTFOLIO
20
STANDARD THAT IS ALLOWED FROM ENERGY EFFICIENCY
21
THROUGHOUT THE 2014-2016 PERIOD?
22
A.
Pursuant to NRS 704.7821(2)(b) Sierra can use portfolio credits generated by
23
energy efficiency measures to meet up to 25 percent of the annual RPS
24
requirement. Half of the 25 percent must come from residential sources unless
25
the Commission finds otherwise. Including projected energy savings for 2013,
26
the Company estimates that it has in place adequate savings from energy
27
28
Vukanovic-DIRECT
9
3DJHRI
1
efficiency measures installed or to be installed prior to 2014 to provide the full 25
2
percent allowed through the 2014 compliance year.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
3
4
Legislation recently enacted by the Nevada Legislature during its 2013 session
5
has changed the amount of portfolio credits generated by energy efficiency
6
measures that can be used to comply with the RPS starting in 2015.3 In 2015 the
7
Company can use portfolio credits generated by energy efficiency measures to
8
meet up to 20 percent of the annual RPS requirement. Figure DS-6 in the DSM
9
Narrative illustrates that regardless of the proposed DSM portfolio in 2015, Sierra
10
will fall short of providing maximum allowable DSM contributing to the
11
Renewable Portfolio Standard.
12
13
16.
Q.
WHY DIDN’T THE COMPANY GIVE MORE WEIGHT TO THE
14
CRITERIA
15
COMPLYING WITH THE RENEWABLE PORTFOLIO STANDARD IN
16
DETERMINING WHICH PLAN TO RECOMMEND?
17
A.
OF
CONTRIBUTING
PORTFOLIO
CREDITS
FOR
Even without DSM making the maximum allowable contribution to the
18
Renewable Portfolio Standard, Sierra is still well positioned to meet RPS
19
requirements in the next ten years and therefore meeting the RPS requirements
20
was not afforded more weight in the DSM Plan selection process.
21
22
23
24
25
26
27
3
28
Vukanovic-DIRECT
SB 252, 2013 Session of the Nevada Legislature.
10
3DJHRI
1
SECTION B: COST-EFFECTIVENESS ANALYSIS 2
17.
WHAT METHODOLOGY HAS THE COMPANY EMPLOYED TO
3
DETERMINE THE COST EFFECTIVENESS OF EACH OF THE
4
PROGRAMS EVALUATED IN THIS DSM UPDATE REPORT?
5
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
Q.
A.
The Company utilized the PortfolioPro model to determine the cost effectiveness
6
of each program evaluated in this DSM plan. The PortfolioPro model, which
7
follows generally accepted industry practices for evaluating the cost effectiveness
8
of Energy Efficiency and Conservation (“EE&C”) programs, was developed for
9
the Company by The Cadmus Group. This model has been employed by the
10
Company for determining the cost effectiveness of EE&C programs since 2006.
11
The model has benefited from a number of enhancements in the last six years.
12
The model provides six tests to evaluate cost effectiveness. These six tests are as
13
follows:
14
Total Resource Cost (“TRC”)
15
Adjusted Total Resource Cost (“ATRC”)
16
Rate Impact Measure (“RIM”)
17
Utility-Cost Test (“UCT”)
18
Participant Cost Test (“PCT”)
19
Societal Cost Test (“SCT”)
20
21
18.
Q.
HAS SIERRA MADE ANY CHANGES TO THE MODEL SINCE THE
22
FILING OF SIERRA’S 2012 ANNUAL DSM UPDATE REPORT LAST
23
YEAR?
24
A.
Yes, the PortfolioPro model is reviewed every year to identify opportunities for
25
improvement including ease of use and clarity of the outputs of the model.
26
Making the model easier to use and improving the clarity of the outputs helps
27
28
Vukanovic-DIRECT
11
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
1
facilitate the analysis performed by third parties such as Staff or BCP who wish to
2
independently analyze the programs. For this filing no changes were made to the
3
calculations integral to the model, however enhanced accuracy was achieved by
4
replacing the energy savings curves in the model that were generic in nature with
5
energy savings curves that were developed based on the programs that were
6
delivered by Sierra in 2012. The clarity of the output of the model was improved
7
as the output sheet was reorganized and simplified with uniform labeling to make
8
the data presented more accessible to third party users. The model was made
9
easier to use by simplifying the naming and labeling in the model as well as
10
making the labeling more uniform.
11
PortfolioPro made subsequent to Sierra’s 2012 Annual DSM Update Report are
12
provided in Technical Appendix DSM-2.
A detailed list of the improvements to
13
14
19.
Q.
15
16
DID SIERRA INCLUDE ANY NON-ENERGY BENEFITS IN THE
DETERMINATION OF THE TRC?
A.
Sierra did not include any non-energy benefits in the determination of the TRC.
17
The result is that both the TRC and the net benefits for all the plans presented
18
understate the value of the Preferred Plan. The net benefits are computed by
19
subtracting the costs calculated for the TRC from the benefits computed for the
20
TRC.
21
programs.
The TRC and the net benefits present a conservative analysis of the
22
23
24
25
26
27
28
Vukanovic-DIRECT
12
3DJHRI
1
20.
Q.
2
THAT ARE NOT ACCOUNTED FOR IN THE TRC ANALYSIS. 3
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE PROVIDE SOME EXAMPLES OF NON-ENERGY BENEFITS A. Non-energy benefits break down into three broad categories, participant, society
4
and utility. A typical list of non-energy benefits for each category is provided in
5
the following breakout:
6
1. Participant
7
a. Increased property values
8
b. Operations and maintenance savings
9
c. Increased comfort
10
d. Improved health
11
e. Increased productively
12
2. Society
13
a. Water savings
14
b. Environmental benefits
15
c. Economic benefits/ job creation
16
3. Utility
17
a. Reduced arrearages and late payments
18
b. Reduced uncollectables and bad debt write-off
19
c. Reduce bill related customer calls
20
d. Reduced bill collection process costs
21
22
Although these non-energy benefits are hard to quantify they are real and
23
identifiable.4
24
25
26
4
27
28
Addressing Non-Energy Benefits in the Cost Effectiveness Framework, CPUC Energy Division Staff and Ed Vine,
http://www.cpuc.ca.gov/NR/rdonlyres/BA1A54CF-AA89-4B80-BD90-0A4D32D11238/0/AddressingNEBsFinal.pdf
Vukanovic-DIRECT
13
3DJHRI
1
21.
Q.
2
CALCULATION OF THE TRC?
3
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
WHY DID SIERRA NOT INCLUDE NON-ENERGY BENEFITS IN THE
A.
The Company has not included non-energy benefits in the calculation of the TRC
4
primarily because the Company does include non-energy benefits in the SCT. In
5
addition to questions regarding the appropriateness of including non-energy
6
benefits in the TRC, it is difficult and costly to accurately quantify non-energy
7
benefits.5 In calculating the SCT results the Company uses an adder of ten
8
percent to approximate the value of the non-energy benefits. The ten percent
9
adder recognizes that the non-energy benefits have real value but avoids a time
10
consuming and potentially expensive effort to quantify those results. Moreover,
11
the Commission has sufficient information to consider the probative value of non-
12
energy benefits because the Company provides the results of the SCT to the
13
Commission.
14
15
22.
Q.
16
PLEASE SUMMARIZE YOUR TESTIMONY REGARDING NONENERGY BENEFITS?
17
A.
Sierra is not requesting approval from the Commission to include non-energy
18
benefits in the calculation of the TRC. We do note, however, that the TRC is, in
19
our view, conservative due to their absence. Thus, the approval of the Preferred
20
Plan proposed by the Company will accrue to the communities served by the
21
company benefits over and above the $31,754,221 net benefits calculated by the
22
Company.
23
24
25
26
27
5
28
Vukanovic-DIRECT
Id.
14
3DJHRI
1
23.
Q.
2
THE FINANCIAL ANALYSIS OF DSM PROGRAMS?
3
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
DOES SIERRA USE CONSERVATIVE INPUTS AND ASSUMPTIONS IN
A.
Yes, the financial analysis employed by the Company includes several other
4
assumptions and inputs that use conservative values. One of the inputs to the
5
financial analysis of DSM programs is the avoided Transmission and Distribution
6
(T&D) costs. It is challenging to directly relate the savings achieved with energy
7
efficiency measures that are disbursed throughout Sierra’s electric system with
8
specific avoided investments in T&D infrastructure. As a result the adopted
9
methodology, as explained in Section 3 of the DSM Narrative, is based on the
10
marginal cost study value for T&D costs from the most recent general rate case.
11
The values used are conservative because they include only 25 percent of the
12
marginal costs for transmission and distribution, and the distribution costs used
13
only include distribution substations. In evaluating the avoided cost practices for
14
other jurisdictions for T&D, the Company has determined that that the avoided
15
T&D costs, as currently employed in the financial modeling process, are about
16
50-75 percent lower than are used in other jurisdictions.6
17
18
In addition, the current financial modeling process does not include any value for
19
the contribution made by the DSM programs to comply with the RPS
20
requirements. DSM programs help reduce sales and consequently the amount of
21
required Portfolio Credits (PCs), as well as contributing directly to the number of
22
credits required for compliance. Another example of conservative input is that
23
24
6
25
26
Best Practices in Energy Efficiency Program Screening (July 2012), pg. 26. http://www.synapse­
energy.com/Downloads/SynapseReport.2012-07.NHPC.EE-Program-Screening.12-040. T&D Avoided costs in
California Utilities https://www.pge.com/regulation/DemandResponseOIR/Other­
Docs/E3/2010/DemandResponseOIR_Other-Doc_E3_20101105-01Atch01.doc
27
28
Vukanovic-DIRECT
15
3DJHRI
1
the cost effectiveness analysis for Demand Response does not include the value
2
the Demand Response System provides in emergencies. The avoided costs used
3
in the financial model do not take into account the cost of capacity during
4
emergencies.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
5
6
Obtaining more precise figures for these factors can be both time consuming and
7
costly and therefore Sierra is not requesting any change to these factors in this
8
filing. Sierra has called attention to these factors and the non-energy benefits to
9
provide a better context for the Commission as it considers Sierra’s
10
recommendations regarding the 2014-2016 DSM Plan.
11
12
SECTION C: SOLAR THERMAL WATER HEATING PROGRAM
13
24.
Q
PLEASE DESCRIBE THE SCOPE AND SCALE OF THE RESIDENTIAL
14
SOLAR THERMAL WATER HEATING PROGRAM THAT SIERRA
15
INCLUDES IN THE PREFERRED PLAN FOR THE ACTION PLAN
16
PERIOD.
17
A.
The Residential Solar Thermal Water Heating Program provides incentives to
18
residential customers with electric water heaters who install qualifying solar
19
thermal water heating systems. The Residential Solar Thermal Water Heating
20
program is included in this DSM Update Report in compliance with NRS
21
704.741(3)(a) and NAC 704.934(4).
22
23
The program encourages the installation of solar thermal water heating systems
24
by providing financial incentives to customers to assist with installation costs and
25
by providing training for contractors, building inspectors, and other state and local
26
27
28
Vukanovic-DIRECT
16
3DJHRI
1
building officials. The program targets the approximate 15 percent of single-
2
family homes with electric water heaters.
3
4
This program will be delivered to customers as a part of the Renewable
5
Generations bundle of programs. Bundling this program with other renewable
6
incentive programs provides cost savings in administration, marketing, and
7
education as materials and support systems can generally be deployed for the
8
benefit of multiple programs.
Nevada Power Company
and Sierra Pacific Power Company d/b/a NV Energy
9
10
Sierra recommends that the Solar Thermal Water Heating Program be adopted in
11
the 2014-2016 Action Plan period as described in the Preferred Plan.
12
Preferred Plan budget for the Action Plan period for this program is $200,000 in
13
each year of the Action Plan period. The estimated attendant energy savings in
14
MWh for the DSM Plan are 108 MWh for each year in the Action Plan period.
15
The estimated aggregate demand savings in MW for the DSM Plan are 9 kW for
16
each year in the Action Plan period.
The
17
18
19
25.
Q.
DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A.
Yes, this concludes my prepared direct testimony.
20
21
22
23
24
25
26
27
28
Vukanovic-DIRECT
17
3DJHRI
Exhibit Vukanovic-Direct-1
Page 1 of 1
Statement of Qualifications
Zeljko G. Vukanovic
June 21, 2012
Education
Master of Science in Banking and Financial Services Management at the Boston University,2011
Master of Business Administration at the University of Nevada at Las Vegas, 2008
Bachelor of Science in Business Administration, Megatrend University in Belgrade, Serbia, 2003
Professional Experience
2012 To Date
Staff Consultant, DSM Planning
NV Energy
As Project Manager for the NV Energy DSM IRP coordinate, schedule and track all aspects of
the filing. Provide and defend testimony. Lead the IRP and other projects through regulatory
approval.
2010-2012
Senior Consultant, DSM Planning
NV Energy
Leading financial and economic modeling of Energy Efficiency, Demand Response, and Gas
DSM programs. Preparing DSM part of Integrated Resource Plans, Annual Electric and Gas
DSM Report Updates, Renewable Portfolio Standard Annual Report, and other regulatory
filings.
2006-2010
Consultant, DSM Planning
NV Energy
Participated in preparing DSM part of Integrated Resource Plans, Annual Electric and Gas DSM
Report Updates, Renewable Portfolio Standard Annual Report, and other regulatory filings.
Financial and economic modeling of Energy Efficiency, Demand Response, and Gas DSM
programs.
2006
Intern, Resource Planning, and Financial Planning and Analysis
NV Energy
Responsibilities included: Anaysis of NV Energy and comparable utitlites financial metrics, gas
hedging modeling, electric and gas forecasting.
Boards and Honors
International Association for Energy Economics, member
Association of Energy Service Professionals, member
3DJHRI
3DJHRI
MICHAEL O. BROWN
3DJHRI
1
3
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-_____
4
PREPARED DIRECT TESTIMONY OF
5
Michael O. Brown
2
6
7
1.
Q.
ADDRESS.
8
A.
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
My name is Michael O. Brown. I am the Manager of Demand Response
10
(“DR”) Programs for Nevada Power Company d/b/a/ NV Energy
11
(“Nevada Power”) and Sierra Pacific Power Company d/b/a NV Energy
12
(“Sierra” and, together with Nevada Power, the “Companies”).
13
business address is 6226 West Sahara Avenue in Las Vegas, Nevada. I
14
am filing testimony on behalf of Sierra.
My
15
16
2.
Q.
AND EXPERIENCE.
17
18
PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND
A. My professional experience includes over fifteen years in the energy
19
sector focusing on demand response, energy efficiency, and renewable
20
energy in both deregulated and regulated electricity markets. Prior to
21
joining the Companies in September of 2005, I held a variety of
22
positions at consulting and energy service firms, including the following
23
roles: energy systems analysis; energy efficiency project development
24
and project management; key account management for energy and
25
commodity (gas and electricity) services; product development; and
26
strategy development.
27
design and implementation of demand side management (“DSM”)
28
Brown-DIRECT
My roles with the Companies have included
1
3DJHRI
1
programs. I have a Masters of Business Administration and a Bachelors
2
of Science in Chemistry and International Relations.
3
regarding my professional background and experience are set forth in my
4
Statement of Qualifications, which is Exhibit Brown-Direct-1.
More details
5
6
3.
Q.
7
PROCEEDING?
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
A.
I sponsor and present the Demand Response (“DR”) Program set forth in
9
the Demand Side Management Plan (“DSM Plan”) of Sierra’s 2014 –
10
2033 Integrated Resource Plan (“IRP”). My testimony describes Sierra’s
11
request for approval of the proposed DR Program and the goals
12
recommended during the three-year Action Plan period associated with
13
this IRP (January 2014 to December 2016).
14
15
4.
Q.
PLEASE DESCRIBE THE SCOPE AND SCALE OF THE DR
16
PROGRAM THAT SIERRA INCLUDES IN THE PREFERRED
17
DSM PLAN.
18
A.
The DR Program, as more fully described in the DR Program Data Sheet
19
in Exhibit A of the DSM Narrative, develops dispatchable resources to
20
help the Company manage peak demand in a similar fashion to supply-
21
side peaking combustion turbines or combined-cycle plants.
22
development of dispatchable demand-side resources represents an
23
attractive and cost effective investment opportunity to supplement existing
24
and future supply-side resources. The addition of these resources to the
25
energy supply portfolio increases the Companies’ capability to manage
26
and reduce energy price and volumetric risk. The DR resources can be
27
used to fulfill operating reserve requirements and, under emergency
28
Brown-DIRECT
The
2
3DJHRI
1
conditions, can be used to help prevent brownouts or blackouts. The
2
infrastructure developed to deliver the DR Program can accommodate tens
3
of thousands of distributed resources. This provides distribution grid
4
location-based benefits and also allows the Companies to adapt to and
5
manage increasing amounts of new distributed resources over time (e.g.
6
photovoltaic systems, electric cars). The infrastructure also allows the
7
Companies at a future time to implement and deploy dynamic pricing
8
based programs for peak demand management.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
The Preferred DSM Plan proposes a controlled level of growth in new DR
11
resources, which would ramp up resources to 45 MW of installed capacity
12
by the end of 2016. This goal would be accomplished by continuing to
13
build out the residential program offerings and introducing new offerings
14
in the commercial and industrial (“C&I”), and agricultural sectors. The
15
three year Action Plan budget for DR resources is $12,500,000.
16
17
A common theme across the Preferred DSM Plan design and customer
18
offerings is to provide tangible and meaningful customer benefits through
19
enabling technology and ongoing energy savings that deliver a more
20
powerful value proposition to the customer than financial incentives
21
(rebates) alone. The DR Program designs are centered on a set of enabling
22
technologies that allow customers to realize significant year round energy
23
savings while minimizing the impact to customers of participating in
24
demand response events. In this regard, the core DR Program offerings
25
present integrated energy efficiency and demand response program
26
options to the major customer segments.
27
28
Brown-DIRECT
3
3DJHRI
1
Q.
PLEASE
DESCRIBE
HOW
THE
NEW
ENABLING
2
TECHNOLOGIES PROVIDE FOR A MORE ROBUST AND
3
EFFECTIVE DR SYSTEM.
4
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
5.
A.
The proposed enabling technology architectures seek to address an issue
5
that has plagued direct load control programs for decades—the problem
6
of asymmetric information between the utility and the customer/premise.
7
Despite some attempts at “advanced” cycling logic in load control
8
devices, classic utility command and control systems cannot know the
9
conditions that exist at the customer premise and have tended toward one
10
size fits all methodologies, most particularly in the residential sector.
11
This often leads to suboptimal results and negative customer comfort or
12
operational impacts. The proposed DR Programs take advantage of the
13
data provided by smart meters and the functionality provided by new
14
sophisticated DR infrastructure and enabling technology platforms
15
deployed over the 2010-2012 Action Plan period.
16
architecture and programs focus on deploying networked technologies
17
with premise-based “intelligence” toward the goal of achieving more
18
efficient results with less customer impact utilizing and analyzing data
19
collected from each individual premise. The premise-based systems that
20
will be deployed will have the capability to analyze large amounts of
21
data and translate that into optimized HVAC performance specific to
22
each premise. The technologies will also have the capability to identify
23
equipment in need of service and repair leading to additional energy and
24
cost savings for the customers. On the utility side of the architecture, the
25
back office systems are focused on utilizing smart meter data to forecast
26
the load impact of the various types of premises more precisely. The
27
systems then use the forecasts to create optimized dispatch strategies
28
Brown-DIRECT
The Company
4
3DJHRI
1
working in tandem with supply-side unit commitment models for more
2
efficient and cost effective energy supply and risk management
3
operations.
4
5
Q.
PLEASE DESCRIBE KEY DIFFERENCES BETWEEN THE DR
6
PROGRAM OFFERINGS AT NEVADA POWER AND THE
7
PROPOSED PROGRAM AT SIERRA.
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
6.
A.
With the exception of the proposed agricultural pilot—which is a new
9
proposal—Sierra is proposing to implement the same types of
10
technology and program designs that the Company has implemented at
11
Nevada Power. However, one of the major differences between the two
12
operating entities is the maturity level of the residential component of the
13
portfolio. The Nevada Power residential programs benefit from many
14
years of technology testing and at scale program performance.
15
Considering currently deployed technologies at Nevada Power, one-way
16
receiver switch and programmable communicating thermostat (PCT)
17
testing began in 2002 and two-way PCT testing began in 2005. The
18
program was slowly ramped up from 2002-2006 and then significantly
19
grown at scale between 2007 and 2010 based upon a more solid set of
20
performance and cost data.
21
similar ramp up strategy. Testing of residential DR technology in the
22
Sierra climate started over the past few years. The Preferred DSM Plan
23
uses the 2014 program year to ramp up the size of the residential pilots
24
and the commercial pilot started in 2013 in order to gain another year of
25
technology and program performance testing before starting to scale up
26
at a more rapid pace in 2015 and 2016. The scale up of the program in
Sierra’s Preferred DSM Plan follows a
27
28
Brown-DIRECT
5
3DJHRI
1
2015 and 2016 is contingent on the results of the pilots that will be
2
completed in 2014.
3
4
7.
Q.
5
PROGRAM AT SIERRA.
6
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE DESCRIBE THE PROPOSED AGRICULTURAL PILOT
A.
The proposed agricultural pilot will introduce a new opportunity for
7
irrigators that use central pivot irrigation.
The processes and
8
technologies utilized were designed to allow dispatchable peak load
9
reduction as well as improved energy and water efficiency, and enhanced
10
crop yields. Sierra would trial the concept in 2014 and then expand the
11
offering in 2015 and 2016 as shown in the program plan if warranted by
12
the program performance.
13
14
8. Q.
HOW IS THE PROPOSED AGRICULTURAL SECTOR PILOT
15
OFFERING DIFFERENT FROM THE EXISTING IRRIGATION
16
LOAD CONTROL SYSTEM ASSOCIATED WITH THE IS-2
17
TARIFF?
18
A. Customers on the IS-2 tariff are required to shut off irrigation pumps
19
during emergency conditions as specified in the IS-2 tariff. There are a
20
number of different irrigation methods employed by customers on the IS­
21
2 tariff, and a very small portion of the IS-2 customers use pivot type
22
irrigation. Current IS-2 records indicate that 38 customers on the tariff
23
are using some form of a pivot system, and that 14 of those systems can
24
already be remotely shut off since they were compatible with the paging
25
based receiver switch technology that was deployed by Sierra in the
26
2008/2009 timeframe.
27
28
Brown-DIRECT
6
3DJHRI
1
The proposed agricultural pilot only targets center pivot irrigation
2
systems, and the market research indicates that the vast majority of those
3
center pivots are not on the IS-2 rate. However, if there is customer on
4
the IS-2 rate with a compatible center pivot system not yet under any
5
form of remote control, Sierra recommends that they be eligible to
6
participate in the new agricultural pilot with the caveat that participation
7
in emergency events remains mandatory per the IS-2 tariff while
8
participation in economic DR events beyond a minimum participation
9
commitment be optional.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
9.
Q.
PLEASE DESCRIBE KEY RISKS IN PROGRAM EXECUTION
12
ALONG WITH TECHNIQUES FOR HOW THOSE RISKS CAN
13
BE MANAGED.
14
A.
Program execution risk includes some important categories to call out:
15
customer adoption; technology; and vendor risk. Customer adoption risk
16
relates to how well the program is received by customers and the overall
17
levels of program adoption which can impact program success.
18
Customer adoption risk can be managed by implementing programs that
19
have value propositions effectively targeted to appropriate customer
20
segments. It can also be managed by ensuring a portfolio of program
21
offerings.
22
materials are less than expected, deployment of C&I offerings could be
23
ramped up to compensate. Additionally, if there is only one type of C&I
24
offering many customers may simply not be able to or willing to
25
participate.
26
mitigation fully applies to DR Program execution to manage customer
27
adoption risk.
28
Brown-DIRECT
For example, if residential response rates to recruitment
Hence, the concept of portfolio management for risk
7
3DJHRI
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
1
2
This concept also applies to managing technology risk. The technology
3
strategy is based upon multiple communication pathways and multiple
4
types of premise based equipment that will appeal to various types of
5
customer segments. If the program is designed around deploying only
6
one type of technology and that technology turns out to have security,
7
safety, or other operational issues, there could be catastrophic
8
consequences to the program.
9
recommending full reliance on one contractor or vendor to deliver the
10
program. A portfolio of vendors reduces execution risk and promotes
11
healthy vendor competition.
12
performance based contract structures with appropriate alignment of
13
utility and vendor performance incentives.
Likewise, the Company is not
Vendor risk is also managed by
14
15
10.
Q.
16
17
DOES
THIS
CONCLUDE
YOUR
PREPARED
DIRECT
TESTIMONY?
A.
Yes, this concludes my prepared direct testimony.
18
19
20
21
22
23
24
25
26
27
28
Brown-DIRECT
8
3DJHRI
Exhibit Brown–Direct-1
Page 1 of 3
STATEMENT OF QUALIFICATIONS
MICHAEL O. BROWN MANAGER, DEMAND RESPONSE
NV ENERGY
6226 West Sahara Avenue
Las Vegas, Nevada 89146
(702) 402-5421
[email protected]
Summary of Qualifications
Fourteen years of experience in the energy sector focused on demand response, energy
efficiency, and renewable energy in both deregulated and regulated electricity markets.
Particularly relevant experience to Demand Response and Smart Grid efforts include the design
and implementation of the largest two-way communicating programmable thermostat program in
the country—Cool Share. Cool Share program incentives have characteristics very similar to
Peak Time Rebate programs. Additional relevant experience includes: managing NV Energy’s
participation in a Federal Grant program with partners UNLV and Pulte Homes to demonstrate
65% peak demand reduction in a residential community utilizing demand response, advanced
consumer gateways, advanced building techniques, distributed energy, and smart meter
technology; and, pilot program and product development efforts and implementation
management for commercial and industrial customers participating in NYISO demand response
markets.
Relevant Employment History
™ NV Energy, Manager
December 2010 – Present
Manages team responsible for delivering demand response programs including
residential and small commercial (Cool Share) demand response, IS-2 irrigation
pump direct load control, Nevada Dynamic Pricing Trial delivery oversight, large
commercial and industrial demand response development and delivery, and
distributed energy resources integration and optimization.
Work includes program design and implementation, contract structuring and
execution, business process improvement, stakeholder management, analysis of
new products and services, business case development, and integration of demand
side resources with smart grid infrastructure (NVEnergize).
™ NV Energy, Sr. Program Manager
May 2006 – December 2010
Key program management responsibilities included residential and small
commercial direct load control and a Federal grant program for consumer
information gateway development and integration to enable price-responsive and
direct load control.
3DJHRI
Exhibit Brown–Direct-1
Page 2 of 3
Experience also included taking lead role in bidding out and awarding online energy information, billing information, and energy audit software tool for
customers.
Managed NPC portfolio of residential and commercial energy efficiency programs with primary role for air conditioning programs and supporting role for lighting, education,
and commercial programs.
™ Nevada Power Company, Strategist
September 2005 – May 2006
Worked in the DSM planning department to design and develop energy efficiency
programs.
Developed zero energy homes and energy information pilot programs.
™ Energis Pax, Consultant
January 2004 – September 2005
Continued distributed generation strategy development work from business school
project for BOC (British Oxygen).
Evaluated and pursued Clean Development Mechanism (CDM) opportunities in
India.
™ Luthin Consulting, Contractor
June 2002 – September 2002
Short term contract for energy and commodity management services for health
care facilities in New York.
™ Enron Energy Services (EES), Account Manager
June 2000 to December 2001
Managed the operations of energy outsource and large commodity contracts
valued in excess of $300 million.
Identified additional energy efficiency and demand response opportunities for
clients.
Worked with product structuring group to develop demand response products.
Launched a demand response product for customers in New York and
Massachusetts, and provided leadership and training to fellow account managers
in evolving demand response markets in the NYISO and New England ISO.
™ Enron Energy Services (EES), Project Developer
March 1999 to June 2000
Identified and developed energy efficiency projects in industrial and commercial
buildings.
Evaluated energy efficiency technologies and the impact of deregulation on
project economics.
™ ICRC Energy Inc., Project Manager, Energy Services
January 1998 to March 1999
Managed a contract with the National Renewable Energy Laboratory (NREL) and
3DJHRI
Exhibit Brown–Direct-1
Page 3 of 3
the Federal Energy Management Program (FEMP) to provide technical assistance
to Federal facilities.
Performed energy efficiency and renewable energy feasibility studies and energy
systems design aid.
™ McNeil Technologies, Inc. and Good Consulting Co., Energy Analyst
June 1995 to January 1998
Supported two U.S. Department of Energy clients: FEMP and The Office of
Photovoltaic Technologies. Work included supporting the ESPC program, FEMP analytical tools, and the Million Solar Roofs Initiative. For Good Consulting, performed energy consumption analysis for EPA laboratories with recommendations for energy efficiency measures. Education
The College of William and Mary
Bachelor of Science, Double Major, Chemistry and International Relations, May 1994
The Cranfield School of Management
Master of Business Administration, September 2003
Industry Specific Training
NYISO Market Training
PJM Market Training
Electric Market Dynamics
Gas Markets Training
Derivatives Training/Swaps and Options
Cost of Service and Rate Design Training
Communications Systems to Support Smart Grid Efforts
Advanced Meter Infrastructure Planning
General Training
Executive Sales Presentations
Miller Heiman Strategic Selling
Karrass Negotiating
Memberships
Advanced Load Control Alliance (ALCA)
Association of Energy Service Professionals (AESP)
3DJHRI
3DJHRI
DONALD R. DOHRMANN
3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-_____
4
PREPARED DIRECT TESTIMONY OF
5
Donald R. Dohrmann
6
7
A.
INTRODUCTION
8
1.
Q.
A.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
9
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Donald R. Dohrmann. My business address is 5470 Kietzke
10
Lane, Suite 220, in Reno, Nevada. I am providing testimony on behalf of
11
Sierra Pacific Power Company d/b/a NV Energy (“Sierra” or the
12
“Company”).
13
14
2.
15
Q.
BY WHOM AND IN WHAT CAPACITY YOU ARE EMPLOYED.
A. I am employed by ADM Associates, Inc., (“ADM”) as a Principal and
16
Director of Economics. In that capacity, I am responsible for directing the
17
work of ADM’s staff on M&V projects involving economic and statistical
18
analyses.
19
20
3.
Q.
BRIEFLY
SUMMARIZE
YOUR
EDUCATIONAL
BACKGROUND AND EMPLOYMENT EXPERIENCE.
21
22
PLEASE
A. I have a M.A. and Ph.D. in economics from Yale University. I have been
23
employed at ADM Associates since 1979. Additional detail about my
24
educational and employment history is provided in Exhibit Dohrmann-
25
Direct-1.
26
27
28
Dohrmann - Direct
1
3DJHRI
1
4.
Q.
2
HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA?
3
A. 4
Yes.
I previously testified before the Commission in the following
dockets.
5
1. Sierra Pacific Power Company’s (“Sierra”)and Nevada Power
6
Company’s (“Nevada Power”) 2011 Annual DSM Update
7
Reports – Docket Nos. 11-07026 and 11-07027
2. Sierra’s and Nevada Power’s
8
Adjustment – Docket Nos. 12-03004, 12-03005 and 12-03006
9
3. Nevada Power’s 2012 IRP and Sierra’s 2012 Annual DSM
10
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
Deferred Energy Accounting
Update Report – Docket Nos. 12-06052 and 12-06053
11
12
13
5.
14
Q. ARE YOU SPONSORING ANY TECHNICAL APPENDIX ITEMS?
A. Yes. Together with Sasha Baroiant, Robert Oliver and Kelly Vagianos, I
15
sponsor the reports contained in Technical Appendices DSM-5 through
16
DSM-13 (the “M&V Reports”).
17
18
6.
Q.
19
20
PLEASE
SUMMARIZE
YOUR
TESTIMONY
IN
THIS
PROCEEDING.
A. My testimony addresses the following topics:
21
1. Standards for M&V work
22
2. Energy savings calculations
23
3. Models
24
4. Statistics
25
5. Sampling Plans for M&V reports
26
6. Engineering and modeling support of gross savings
27
28
Dohrmann - Direct
2
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
In Section B, I address the relationship between ADM and the Company.
2
Section C generally describes the standards that govern measurement and
3
verification work, the work that ADM performed to measure and verify
4
savings for Sierra’s 2012 DSM portfolio, and explains that ADM
5
complied with applicable standards.
6
process that ADM used to verify savings for select programs. Section E
7
addresses statistical sampling and background information, and explains
8
that ADM sought to provide M&V results at a 90 percent confidence level
9
and 10 percent precision level. Section F describes the sampling approach
Section D discusses the M&V
10
that ADM used for specific programs.
11
engineering calculations and modeling that ADM employed to verify
12
savings for specific programs. Section H of this testimony contains my
13
conclusions.
Section G describes the
14
15
7.
Q.
PLEASE EXPLAIN WHY YOU ARE SPONSORING THE M&V
16
REPORTS JOINTLY WITH SASHA BAROIANT, ROBERT
17
OLIVER AND KELLY VAGIANOS.
18
A.
The M&V process is a cross-discipline effort. ADM assembles a cross-
19
discipline team to complete M&V projects.
20
economists, statisticians, engineers and other professionals. Accordingly,
21
we are jointly sponsoring the M&V Reports so that we can provide
22
information to the Commission in an efficient and clear manner.
23
addition, the M&V effort relies in part on information that is in the control
24
of Sierra.
25
support of the M&V reports.
These teams include
In
For this reason, Ms. Vagianos also provides testimony in
26
27
28
Dohrmann - Direct
3
3DJHRI
1
B.
2
3
ADM OPERATES INDEPENDENTLY
VERIFYING KWH SAVINGS
8.
Q.
4
PLEASE BRIEFLY DESCRIBE ADM ASSOCIATES INC AND
THE SERVICES THEY PROVIDE.
5
A.
ADM, which began business in 1979, provides research, analysis,
6
evaluation, and consulting services on energy efficiency and demand
7
response.
8
economists, statisticians, psychologists, and architects. Although ADM’s
9
headquarters are in California, ADM provides its services to utilities and
10
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
WHEN MEASURING AND
ADM’s staff is multi-disciplinary, including engineers,
government agencies throughout the United States and Canada.
11
12
13
9.
Q.
PLEASE
DESCRIBE
ADM’S
RELATIONSHIP
WITH
THE
COMPANY.
14
A. The Company contracted with ADM to provide an independent
15
assessment of the energy savings and demand reductions for the
16
Company’s DSM programs. At the start of each year, ADM prepares
17
M&V plans for all of the Sierra programs to be assessed for that year.
18
These M&V plans are reviewed with the Company and its implementation
19
contractors, but final decisions on approaches and procedures are made by
20
ADM acting as an independent agent. ADM then performs the M&V
21
work for the programs according to these plans.
22
23
ADM’s relationship with Sierra for the M&V work is in accord with the
24
M&V processes followed for utility energy efficiency programs in other
25
states.
26
27
28
Dohrmann - Direct
4
3DJHRI
1
10.
Q.
2
WITH RESPECT TO THIS FILING, WHAT SPECIFIC SERVICE
DID THE COMPANY ASK ADM TO PROVIDE?
3
A.
The Company requested that ADM perform the M&V analyses described
4
below, utilizing best practices while complying with the Commission’s
5
regulations and industry standards and practices.
6
7
11.
Q.
8
WHAT ROLE DID ADM FULFILL IN CREATING THESE M&V
REPORTS?
9
A. ADM prepared all of the M&V reports.
Q.
PLEASE
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
11
12.
12
13
DESCRIBE
WHAT
WORK
IS
COMPLETED
IN
CREATING THE M&V REPORTS.
A. ADM collected and analyzed data to independently determine energy
14
savings and demand reductions for the Company’s energy efficiency and
15
conservation (“EE&C”) programs.
16
17
Data collection begins with inspection of data entered by program
18
implementers into TrakSmart® the data management system used by NV
19
Energy for its EE&C programs. Primary data collection includes due-
20
diligence on-site audit visits, telephone interviews, and inspections of a
21
sample of project documentation and sites to verify that measures claimed
22
to be installed through a program have been properly installed and are
23
being utilized. Data are also collected that are needed to analyze and
24
calculate energy savings and demand reductions.
25
activities are guided by appropriate statistical sampling procedures.
All data collection
26
27
28
Dohrmann - Direct
5
3DJHRI
1
Using the data we collect, we calculate and validate annual and monthly
2
kWh savings and peak kW reductions for each Company EE&C program
3
implemented during a given year.
4
engineering calculations and statistical analysis, as appropriate.
This analysis is performed using
5
6
We provide annual reports on the results of our M&V work that the
7
Company uses to evaluate programs and make budget decisions, and
8
submits to the Commission for review and acceptance.
9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
13.
Q.
PLEASE DESCRIBE IN MORE DETAIL THE GENERAL
11
INDUSTRY
12
GOVERN THE MEASUREMENT AND VERIFICATION OF
13
ENERGY AND DEMAND SAVINGS.
14
A.
STANDARDS
AND
SPECIFICATIONS
THAT
The industry standards and specifications that guide ADM’s M&V work
15
for the Company’s EE&C programs is set out in several guidebook
16
documents that have been published over the past several years. These
17
include the following:
18
American Society of Heating, Refrigeration and Air Conditioning
19
Engineers (ASHRAE). Measurement of Energy and Demand Savings,
20
Guideline 14. June 2002.
21
California Public Utilities Commission. The California Evaluation
22
Framework. June 2004.
23
Federal Energy Management Program (FEMP). Federal Energy
24
Management
25
Verification for Federal Energy Projects. September 2000.
Program
M&V
Guidelines:
Measurement
and
26
27
28
Dohrmann - Direct
6
3DJHRI
1
International Performance Measurement and Verification Protocol.
2
IPMVP Volume I: Concepts and Options for Determining Energy and
3
Water Savings. April 2007.
4
National Action Plan for Energy Efficiency. Model Energy Efficiency
5
Program Impact Evaluation Guide. Prepared by Steven R. Schiller,
6
Schiller Consulting, Inc., December 2007.
7
8
14.
Q.
9
CONDUCTED TO CREATE THEM COMPLY WITH THE
10
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
DO THE M&V REPORTS AND THE METHODOLOGIES
INDUSTRY STANDARDS YOU JUST DESCRIBED?
11
A.
12
Yes, all of the M&V work that we performed regarding the Company’s
programs is done in compliance with industry standards.
13
14
C.
15
16
GENERAL
APPROACHES
TO
THE
MEASUREMENT
AND
VERIFICATION OF KWH SAVINGS
15.
Q.
PLEASE SUMMARIZE THE APPROACHES THAT ADM USED
17
TO MEASURE AND VERIFY SAVINGS FOR SIERRA’S 2012
18
PROGRAMS.
19
A. A taxonomy presented in the Model Energy Efficiency Program Impact
20
Evaluation Guide identifies three major approaches for calculating
21
estimates of energy savings and demand reductions.
22
A deemed savings approach involves using stipulated savings for
23
energy conservation measures for which savings values are well-
24
known and documented.
25
acceptable for lighting retrofits for customers’ spaces (e.g., offices)
26
where there is general agreement on the hours of use for such spaces.
For example, this approach may be
27
28
Dohrmann - Direct
7
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
A site-specific M&V approach involves (1) selecting a representative
2
sample of customers or sites that participated in a project; (2)
3
determining the savings for each customer or site in the sample,
4
usually by using one or more of the M&V Options defined in the
5
International Performance Measurement and Verification Protocol
6
(“IPMVP”); and (3) applying the results of determining the savings for
7
the sample to the entire population in the project.
8
A large-scale data analysis approach involves determining energy
9
savings and demand reductions by applying one or more statistical
10
methods to measured energy consumption, utility meter billing data
11
and independent variable data. This approach usually (1) involves
12
analysis of a census of project sites versus a sample, and (2) does not
13
involve on-site data collection for model calibration.
14
sample of customers or sites may be selected and visited to confirm
15
that the energy conservation measures were properly installed and are
16
still operating.
However, a
17
18
In performing the M&V work for the Company’s EE&C programs, we
19
examined documentation for the programs to identify 1) the types of
20
energy efficiency measures from which savings are expected to be
21
realized, and 2) which of these three types of analyses is most appropriate
22
for determining savings for a particular program. We take account of
23
several factors.
24
The magnitude of expected savings from program measures affects the
25
choice of savings estimation approach.
In particular, analysis of
26
27
28
Dohrmann - Direct
8
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
billing data may not be sufficient to detect savings of small magnitude
2
for some measures.
3
The number and complexity of the measures and technologies being
4
promoted through a project is a factor in determining the savings
5
estimation approach.
6
installed at a single customer site, there may be overlapping and/or
7
interactive effects among the measures.
8
individual measures therefore requires using a savings estimation
9
approach that can account for the impact of interrelated measures.
For example, if multiple measures can be
Identifying the effects of
10
Costs associated with the approaches differ and therefore are also
11
considered in choosing the savings estimation approach.
12
13
16.
Q.
PLEASE DESCRIBE THE DEEMED SAVINGS APPROACH AS IT
WAS APPLIED TO SIERRA’S PROGRAMS.
14
15
A.
The deemed savings approach was not used for the Company’s programs.
16
The programs were evaluated using either site-specific approach or large
17
scale data analysis approach.
18
19
17.
Q. PLEASE DESCRIBE THE SITE-SPECIFIC M&V APPROACH
20
AND THE LARGE SCALE DATA ANALYSIS APPROACH AS
21
THEY WERE APPLIED TO SIERRA’S PROGRAMS.
22
A. A major consideration in choosing which approach to use in determining
23
savings for a program is whether the program targets residential customers
24
versus commercial/industrial customers. There are differences between
25
residential and commercial/industrial programs in terms of numbers and
26
characteristics of participants. Programs for residential customers usually
27
28
Dohrmann - Direct
9
3DJHRI
1
have larger numbers of participants who can be expected to show a fair
2
degree of homogeneity. For such programs, the large scale data analysis
3
approach is often feasible and appropriate.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
4
5
On the other hand, programs for commercial/industrial customers usually
6
have smaller numbers of participants, and some of the customers who do
7
participate can be relatively large with unique operations, making it
8
difficult to perform meaningful statistical comparisons across participating
9
customers.
The site-specific M&V approach is therefore often more
10
appropriate for commercial/industrial programs, with more reliance placed
11
on using site-specific engineering analysis and end-use metering as
12
methods to determine savings.
13
14
D. M&V EFFORTS FOR THE COMMERCIAL RETROFIT INCENTIVES
15
PROGRAM
16
PROGRAM
17
18.
Q.
AND
THE
COMMERCIAL
NEW
CONSTRUCTION
PLEASE DESCRIBE THE M&V PROCESS FOR DETERMINING
18
THE VERIFIED ENERGY SAVINGS FOR THE COMMERCIAL
19
RETROFIT INCENTIVES PROGRAM.
20
A.
The overall objective for the impact evaluation of the Commercial Retrofit
21
Incentives Program was to determine the gross energy savings and the
22
corresponding peak kW reductions resulting from program during 2012.
23
24
The approach for the impact evaluation had the following main features.
25
Available documentation (e.g., audit reports, savings calculation work
26
papers, etc.) was reviewed for a sample of projects, with particular
27
28
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attention given to the calculation procedures and documentation for
2
savings calculations.
3
4
On-site data collection was conducted for a sample of projects to provide
5
the information needed for calculating savings and demand reductions.
6
Monitoring was also conducted at some sites to obtain more accurate
7
information on measure operating characteristics.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
8
9
Gross savings were determined using industry standard and proven
10
techniques. For lighting measures, savings were determined using an
11
evaluation model that used information on operating parameters collected
12
on site and, if appropriate, industry standards. For HVAC measures, the
13
original analyses used to calculate the expected savings were reviewed and
14
the operating and structural parameters of the analysis were verified. For
15
custom measures or relatively more complex measures, simulations with
16
the DOE2 (eQuest) energy analysis model were used to develop energy
17
use values and savings from the installed measures.
18
19
19.
Q.
PLEASE DESCRIBE THE M&V PROCESS FOR DETERMINING
20
THE VERIFIED ENERGY SAVINGS FOR THE COMMERCIAL
21
NEW CONSTRUCTION PROGRAM.
22
A.
The M&V procedures to determine verified savings for the Commercial
23
New Construction program were based upon standard technical
24
references, such as the IPMVP and the National Action Plan Model
25
Energy Efficiency Program Impact Evaluation Guide. The procedures
26
were refined using the program implementation plan and information
27
28
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collected during discussions with staff from the Company and the
2
implementation contractor.
3
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
4
The major steps in the M&V approach were as follows:
5
Select a representative sample of program participants.
6
Review program data and a sample of participant project
7
documentation.
8
Verify installation of claimed measures and collect data for analysis
9
purposes through on-site visits to sample sites.
10
Develop and/or verify energy use and savings with computerized
11
whole building energy use simulation model. Building simulations
12
were calibrated when billing data were available.
13
Calculate gross savings using proven techniques.
14
measures, savings were determined through analysis with ADM’s
15
custom-designed Lighting Evaluation Model, with system parameters
16
(fixture wattage, etc.) based on information on operating parameters
17
collected on site and, if appropriate, industry standards and code
18
requirements.
19
calculate the expected savings were reviewed, and the building
20
characteristics, operating schedules, and algorithm parameters of the
21
analysis were verified.
22
complex measures, simulations with the DOE2 (eQuest) energy
23
analysis model were used to develop energy use values and savings
24
from the installed and verified measures.
For lighting
For HVAC measures, the ex ante analyses used to
For custom measures or relatively more
25
26
27
28
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E. STATISTICAL SAMPLING AND EXTRAPOLATION
2
20.
Q.
PLEASE DESCRIBE STATISTICAL SAMPLING.
A. Statistical sampling allows a population to be studied by gathering and
3
4
analyzing information for a sample (i.e., subset) of the population.
5
Statistical sampling differs from a census approach, which involves
6
measuring variables for every element of the population being studied.
7
Statistical sampling requires collecting and analyzing data only for a
8
selected set of elements in the population. Results from the analysis of the
9
sample are generalized to the population according to established
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
procedures. Generally, the larger the sample size, the better the results.
11
12
A statistical sampling process begins with a definition of the population to
13
be studied and of the variables that need to be measured.
14
population variables being measured and methods of measurement have
15
been defined, statistical sampling techniques are applied to accurately
16
sample elements from the population so that the data collected for these
17
sample elements is representative of a larger group.
Once the
18
19
There are various approaches to statistical sampling, examples of which
20
include simple random sampling, stratified random sampling and cluster
21
sampling. The choice of which statistical sampling approach to use for
22
M&V work depends on the characteristics of the energy savings for
23
customers participating in the program, the uncertainty about these
24
savings, and the variability on energy savings estimates.
25
26
27
28
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21.
Q.
2
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
3
DR. DOHRMANN, WHY IS STATISTICAL SAMPLING APPLIED
IN M&V WORK?
A.
Statistical sampling is conducted in M&V work to assess the savings
4
impacts of energy efficiency projects within a given budget to create a
5
trade-off between measurement accuracy and statistical precision. That is,
6
within a given budget, collecting more – or more detailed – data to give
7
greater accuracy of measurement for individual sites, may mean collecting
8
data for fewer sites, thus decreasing the statistical precision of the results.
9
Accordingly, in considering the sampling requirements for each project,
10
the M&V contractor considers sampling approaches that balance these
11
measurement and statistical considerations.
12
13
For some programs, particularly those that are targeted at commercial and
14
industrial customers and facilities, it is often found that a small number of
15
sites account for a large percentage of total program savings. In such
16
cases, stratified random sampling can be more appropriate. For example,
17
one effective sampling plan is to select sites with large savings with
18
certainty and to take a probability (i.e., simple random) sample of the
19
other sites that participated in the project.
20
21
Sampling also takes into consideration that the M&V effort is occurring in
22
real time, while projects are being implemented. Sites participating in a
23
program accumulate over time as a project is implemented. The sampling
24
is therefore designed to have a predetermined sample size requirement for
25
achieving certain analytical goals but with adjustments made over time as
26
data for additional participants become available.
27
28
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1
22.
PLEASE IDENTIFY INDUSTRY STANDARDS, GUIDELINES, OR
2
PRACTICES THAT APPLY TO STATISTICAL SAMPLING FOR
3
M&V EVALUATIONS.
4
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
Q.
A.
Industry standards, guidelines and/or standard practices that apply to
5
statistical sampling for M&V and evaluations are provided in the
6
following documents.
7
California Public Utilities Commission. The California Evaluation
8
Framework. June 2004.
9
California Public Utilities Commission, California Energy Efficiency
10
Evaluation Protocols: Technical, Methodological, and Reporting
11
Requirements for Evaluation Professionals. April 2006.
12
National Action Plan for Energy Efficiency. Model Energy Efficiency
13
Program Impact Evaluation Guide. Prepared by Steven R. Schiller,
14
Schiller Consulting, Inc. December 2007.
15
16
23.
Q.
PLEASE DESCRIBE HOW THE M&V WORK PROVIDED BY
17
ADM COMPLIES WITH INDUSTRY STANDARDS, GUIDELINES,
18
OR INDUSTRY STANDARD PRACTICES.
19
A. Besides the M&V work that ADM is performing for the Company, ADM
20
is also performing EM&V work for utilities in several states across the
21
United States, including California, New Mexico, Idaho, Oklahoma,
22
Arkansas, Missouri, Illinois, Indiana, Ohio, Pennsylvania, and West
23
Virginia. Thus, we are completely familiar with industry standards and
24
guidelines and with standard industry practices. All of the M&V work
25
that ADM provides for the Company is in accordance with industry
26
standards, guidelines, and practices.
27
28
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Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
2
24.
Q.
PLEASE EXPLAIN “CONFIDENCE INTERVAL.”
A.
A confidence interval is a range of values around a measurement value
3
that conveys the precision of the measurement value. The purpose of
4
taking a sample from a population and computing a statistic from the data,
5
such as the mean value of a variable, is to approximate the value of the
6
mean of the population. How well the sample statistic estimates the
7
underlying population value is always an issue. A confidence interval
8
addresses this issue because it provides a range of values that is likely to
9
contain the population parameter of interest.
Confidence intervals
10
essentially have two elements: the confidence level and the precision
11
level.
12
13
Confidence intervals are constructed at a confidence level selected by the
14
user. Confidence level is essentially a level of significance, which is a
15
statistical term for how willing you are to be wrong. For example, with a
16
90 percent confidence interval, you have a 10 percent chance of being
17
wrong. With a 95 percent confidence interval, you have a 5 percent
18
chance of being wrong.
19
20
A confidence level of 90 percent thus means that if the same population is
21
sampled on numerous occasions and interval estimates are made on each
22
occasion, the resulting intervals would bracket the true population
23
parameter in approximately 90 percent of the cases.
24
25
In technical terms, confidence intervals are calculated based on the
26
standard error of a measurement. Generally, the larger the number of
27
28
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1
measurements made (i.e., the larger the sample), the smaller the standard
2
error and narrower the resulting confidence intervals.
3
4
25.
5
Q.
PLEASE EXPLAIN “PRECISION LEVEL.”
A.
In statistics, precision level refers to how closely a set of values cluster
6
about a given value (e.g., the mean). Precision refers to the dispersion of
7
the observations about the mean, whether or not the mean value around
8
which the dispersion is measured approximates the “true” value.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
9
10
Note that precision is not the same as accuracy, which is the property of
11
being close to some target or true value. Target shooting can be used to
12
illustrate the difference between precision and accuracy. Suppose arrows
13
are fired at a target and measurements are taken. For a number of arrows
14
being fired, precision would be the size of the arrow cluster. When all
15
arrows are grouped tightly together, the cluster is considered precise since
16
they all struck close to the same spot, even if not necessarily near the
17
bullseye at the target center. Accuracy describes the closeness of the
18
arrows to the bullseye; arrows that strike closer to the bullseye are
19
considered more accurate. The closer a system's measurements to the
20
accepted value, the more accurate the system is considered to be.
21
22
26.
Q.
WHAT
WAS
THE
MINIMUM
PRECISION
LEVEL
AND
23
CONFIDENCE LEVEL THAT WAS EMPLOYED IN THE M&V
24
REPORTS PROVIDED TO THE COMPANY?
25
26
A. Statistical sampling for the M&V work performed on 2012 programs by
ADM for the Company was based on achieving at least 10 percent
27
28
Dohrmann - Direct
17
3DJHRI
1
precision at a 90 percent confidence level. To illustrate the role of these
2
factors, consider the simple random sampling approach.
3
approach, the following equations are used to determine the sample size:
4
n0
For this
z 2cv(y) 2
p2
5
6
n
7
n0
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
8
1
n0
1
N
9
where n is required sample size; z is the abscissa of the standard normal
10
curve for a specified level of confidence (e.g., 1.645 for 90 percent
11
confidence level); p is required precision level (e.g., 10 percent), and cv(y)
12
is coefficient of variation for the variable to be estimated (e.g., hours of
13
use). The second equation applies a finite population correction factor to
14
determine final sample size when no/N is greater than 10 percent.
15
16
Inspection of these formula shows that required sample sizes increase as
17
the variability of the variable to be measured increases. Prior information
18
about the expected variability of savings for sites in a program is therefore
19
needed to determine the required sample size; this information can be
20
obtained from the M&V activities performed for previous years.
21
22
27.
Q.
PLEASE
DESCRIBE
THE
BASIC
CONCEPT
OF
23
EXTRAPOLATION TO A LARGER POPULATION BASED UPON
24
RANDOM SAMPLING.
25
26
A. The basic idea in sampling is extrapolation from the part to the whole –
from “the sample” to “the population.” However, the sample must be
27
28
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1
chosen to fairly represent the population. Good sampling involves the use
2
of probability methods in order to minimize subjective judgment in the
3
choice of units to select for the sample.
4
probability methods to minimize bias.
Samples are drawn using
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
5
6
If a sample is properly chosen and representative of the population, then
7
results calculated for the sample units can be extrapolated to represent the
8
results expected for the population. For example, for simple random
9
sampling, mean kWh savings calculated for a sample can be used to
10
determine total program savings by multiplying the mean savings
11
determined for sample units by the total number of units in the population.
12
More complicated calculation procedures (e.g., applying weights) are
13
needed for stratified or other sampling approaches, but the general
14
principle still applies that the results for a properly chosen sample can be
15
applied to represent population values.
16
17
F.
SAMPLING APPROACHES USED FOR SPECIFIC PROGRAMS
18
28.
Q.
PLEASE
DESCRIBE
THE
SAMPLING
APPROACH
AND
19
SAMPLING PLAN THAT WAS USED FOR DETERMINING THE
20
SAMPLE
21
INCENTIVES PROGRAM.
22
A. SIZE
FOR
THE
COMMERCIAL
RETROFIT
Data provided by the implementation contractor for the Commercial
23
Retrofit Incentives Program showed the total number of projects
24
implemented through the program for the year and the expected kWh
25
savings for those projects.
26
individual projects provided by the implementation contractor indicated
Inspection of data on kWh savings for
27
28
Dohrmann - Direct
19
3DJHRI
1
that the distribution of savings was generally positively skewed, with a
2
relatively small number of projects accounting for a high percentage of the
3
savings. A sample design for selecting projects using stratified random
4
sampling was used that took such skewness into account and allowed ex
5
post verified savings to be determined with a 10 percent precision at the
6
90 percent confidence level.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
7
8
Sampling for the collection of program M&V data accounted for the
9
M&V effort occurring in real time during program implementation.
10
Completed projects accumulate over time as the program is implemented,
11
and sample selection was thus spread over the entire program year. ADM
12
used a near real-time process whereby a portion of the sample was
13
selected periodically as projects in the program were completed. The
14
timing of sample selection was contingent upon the timing of the
15
completion of projects during the program year.
16
17
29.
Q.
PLEASE
DESCRIBE
THE
SAMPLING
APPROACH
AND
18
SAMPLING PLAN THAT WAS USED FOR DETERMINING THE
19
SAMPLE
20
CONSTRUCTION PROGRAM.
21
A.
SIZE
FOR
THE
COMMERCIAL
NEW
ADM staff developed a final sample design for the evaluation of the New
22
Construction program in January 2013. The project ex ante kWh savings
23
was the design variable used to develop the sampling plan. Sample strata
24
were defined by applying the Dalenius-Hodges stratification procedure to
25
the data on ex ante kWh savings and based upon prior year participation.
26
The sampling plan was designed to involve quarterly sampling of the
27
28
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20
3DJHRI
1
completed projects.
2
extracted quarterly from the KEMA pipeline database and the tracking
3
system TrakSmart® maintained by the Company to track the progress of
4
the program. Initial site data collection activities were performed for some
5
of the projects, but the majority of program savings was not confirmed for
6
the program until very late in the year. Therefore, ADM conducted most
7
field work in the beginning of 2013.
Accordingly, available project information was
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
8
9
The efficacy of different allocations of sample points across strata were
10
examined by considering the precision with which total kWh savings
11
could be estimated at the 90 percent confidence level, with ±10 percent
12
precision being the target.
13
14
30.
Q.
PLEASE
DESCRIBE
THE
SAMPLING
APPROACH
AND
15
SAMPLING PLAN THAT WAS USED FOR DETERMINING THE
16
SAMPLE
17
COLLECTION AND RECYCLING PROGRAM.
18
A.
SIZE
FOR
THE
SECOND
REFRIGERATOR
To determine the percentage of refrigerators or freezers that were still
19
operable when picked up by the recyclers, ADM conducted telephone
20
interviews with a sample of participants. Participants were stratified by
21
appliance type (refrigerator or freezer), and a random sample was selected
22
such that 10 percent relative precision with 90 percent confidence was
23
achieved. Assuming a coefficient of variation of 0.5,1 sample sizes of 68
24
participants were required for each type of appliance.
25
26
1
27
28
The coefficient of variation, cv(y), is a measure of variation for the variable to be estimated. As set out in
the Model Energy Efficiency Program Impact Evaluation Guide:
Dohrmann - Direct
21
3DJHRI
1
Q.
PLEASE
DESCRIBE
THE
SAMPLING
APPROACH
AND
2
SAMPLING PLAN THAT WAS USED FOR DETERMINING THE
3
SAMPLE SIZE FOR THE CONSUMER ELECTRONICS AND
4
PLUG LOADS PROGRAM.
5
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
31.
A.
ADM’s sampling approach for the Consumer Electronics and Plug Loads
6
program was to select a sample of transactions from the Company’s
7
TrakSmart® that would ensure that the audit trail would be inspected for
8
at least three transactions per participating retail chain, including for each
9
retail chain at least one small, one medium and one large transaction. In
10
this context of Data Store transactions, the adjectives “small” – “medium”
11
– “large” refer to a particular retail chain’s ex ante kWh savings per
12
transaction relative to that particular retail chain’s mean ex ante kWh
13
savings per transaction.
14
15
Given that the 2012 program included six participating retail chains, and
16
given the skewness of the population of transactions reported through the
17
TrakSmart®, the Dalenius-Hodges stratification methodology was
18
employed to enable ADM to achieve relative precision requirements for
19
this sampling exercise.
20
21
ADM’s sampling for surveying customers in the 2012 program was
22
conducted using Random Digit Dialing. Using this methodology, survey
23
respondents were contacted who indicated that they had purchased a
24
25
26
Until the actual mean and standard deviation of the population can be estimated from actual
samples, 0.5 is often accepted as an initial estimate for cv. The more homogenous the
population, the smaller the cv.
27
Using a cv = 0.5 is also in accordance with California Evaluation Protocols for homogenous measures.
28
Dohrmann - Direct
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3DJHRI
1
television, a monitor, or both during 2012. The telephone interviews with
2
these customers were focused on determining the residential rate class
3
distribution of Sierra customers who had purchased televisions and/or
4
monitors during the 2012 program year.
5
6
G.
7
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
8
ENGINEERING
CALCULATIONS
AND
MODELING
USED
FOR
SPECIFIC PROGRAMS
32.
Q.
PLEASE DESCRIBE THE BASIC ELEMENTS OF ENGINEERING
9
CALCULATIONS AND MODELING THAT WERE EMPLOYED
10
TO DETERMINE THE ENERGY AND DEMAND SAVINGS FOR
11
THE COMMERCIAL RETROFIT INCENTIVES PROGRAM.
12
A.
For each project, the available documentation (e.g., audit reports, savings
13
calculation work papers, etc.) for each rebated measure was reviewed,
14
with particular attention given to the calculation procedures and
15
documentation for savings estimates.
16
17
On-site visits were used to collect data on which the analysis of savings
18
impacts was based. Site visits of the sampled projects were used to collect
19
primary data on the measures implemented at those facilities. Estimates of
20
energy use and savings for energy efficiency measures depend
21
significantly on having accurate data for such factors as operating hours
22
and usage patterns. At some sites, monitoring was conducted to gather
23
such information (e.g., on the operating hours of the installed measures).
24
Monitoring was conducted at sites where it was judged that the monitored
25
data would be useful for further refinement and higher accuracy of savings
26
calculations.
27
28
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3DJHRI
1
Monitoring was not considered necessary for some sites. This included
2
facilities where project documentation allowed for sufficiently detailed
3
calculations or where this type of information was available from an
4
energy management control system.
5
could be obtained through relatively simple monitoring using loggers.
For other facilities, information
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
6
7
The method used to determine gross savings impacts depended on the type
8
of measure being analyzed. The energy savings achieved with different
9
types of measures were determined using a site-specific M&V approach.
10
This involved determining the savings for the measures installed through a
11
project by using one or more of the M&V options defined in the IPMVP.
12
For process measures that did not involve space conditioning, the
13
specificity of the process generally precluded using an energy analysis
14
model for simulation analysis. Therefore savings from these types of
15
process improvement measures were analyzed through engineering
16
analysis of the process affected by the improvements, with monitoring
17
used to supply information for important variables.
18
Savings for lighting measures were assessed using IPMVP Option B,
19
Retrofit Isolation.
20
using short term or continuous measurement, and savings are
21
determined by field post-measurements of the system(s) to which the
22
measure(s) have been applied, separate from the energy use of the rest
23
of the facility.
24
during the post-retrofit period. In fact only a small number of the
25
projects for high tech facilities involved lighting measures (either
26
retrofits or controls).
With IPMVP Option B, savings are calculated
Short-term or continuous measurements are taken
27
28
Dohrmann - Direct
24
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
Savings from compressed air measures were evaluated through
2
engineering analysis of compressor performance curves, supported by
3
data collected through short-term metering. Nameplate information
4
for the pre-retrofit equipment was obtained either from the project file
5
or during the on-site survey. Performance curve data was obtained
6
from manufacturers. Engineering staff then conducted an engineering
7
analysis of the performance characteristics of the pre-retrofit
8
equipment. Where appropriate, savings calculations were made using
9
AirMaster+2.
10
HVAC measures were analyzed using IPMVP Option D, which
11
involves calibrated simulation of energy use. For this analysis, the
12
eQuest energy analysis model was used to prepare computer
13
simulations of energy use before and after the HVAC measures were
14
installed at a facility.
15
16
33.
Q.
PLEASE DESCRIBE THE BASIC ELEMENTS OF ENGINEERING
17
CALCULATIONS AND MODELING THAT WERE EMPLOYED
18
TO DETERMINE ENERGY AND DEMAND SAVINGS FOR THE
19
COMMERCIAL NEW CONSTRUCTION PROGRAM.
20
A. The engineering calculations and modeling that were employed to
21
determine energy and demand savings for the Commercial New
22
Construction Program were the same as those used for the Commercial
23
Retrofit Program.
24
25
2
27
AIRMaster+ provides a systematic approach to assessing the supply-side performance of compressed air
systems. Using plant-specific data, the software effectively evaluates supply-side operational costs for various
equipment configurations and system profiles. It provides useful estimates of the potential savings that could
be gained from selected energy efficiency measures and calculates the associated simple payback periods. See
http://www1.eere.energy.gov/manufacturing/tech_assistance/pdfs/airmaster_fs.pdf
28
Dohrmann - Direct
26
25
3DJHRI
1
34.
IF A GIVEN SITE (OR PARTICIPANT) IN THE COMMERCIAL
2
NEW CONSTRUCTION PROGRAM HAD OCCUPANCY OF LESS
3
THAN 100 PERCENT WHEN INITIAL M&V WORK WAS
4
COMPLETED, SHOULD FUTURE OCCUPANCY RATES BE
5
ASSUMED, OR SHOULD FUTURE OCCUPANCY RATES BE
6
RECHECKED?
7
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
Q.
A.
ADM will directly address the occupancy concern for any New
8
Construction project for which occupancy was less than 100 percent at the
9
time of ADM’s initial site visits by revisiting each site during each future
10
calendar year for which there is a potential impact on the calculation of the
11
Company’s foregone sales revenue claims. ADM will report the updated
12
occupancy data via addenda to the original M&V report.
13
14
35.
Q.
IF FOR A GIVEN COMMERCIAL NEW CONSTRUCTION SITE,
15
INITIAL M&V RESULTS WERE DEVELOPED USING ONLY
16
ONE MONTH OF MONITORED DATA AND/OR BILLING DATA
17
TO CALIBRATE A SIMULATION MODEL, SHOULD M&V
18
RESULTS BE UPDATED AFTER ADDITIONAL BILLING DATA
19
BECOMES AVAILABLE?
20
A.
ADM has extensive experience using one month’s data to calibrate DOE-2
21
simulations.
22
Edison, ADM has addressed the question of how much data are required
23
to arrive at reasonable results from simulation analysis. Results of these
24
studies are summarized in Alereza and Faramarzi.3 The results of these
In previous studies with staff from Southern California
25
26
3
27
Alereza, T., and R. Faramarzi. 1994. “More Data Is Better, But How Much Is Enough for Impact
Evaluations?” In Proceedings of the ACEEE 1994 Summer Study on Energy Efficiency in Buildings, 2:11-19.
Washington, D.C.: American Council for an Energy-Efficient Economy (ACEEE).
28
Dohrmann - Direct
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3DJHRI
1
analyses indicated that a combination of detailed audit data with monthly
2
utility bills can be used together in a simulation analysis to provide
3
reasonable accuracy for determination of annual energy consumption for a
4
building.
5
regarding the operation of systems within a building, although data for
6
more months is preferable.
Even one month of data can provide useful information
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
7
8
Given the implications related to potential recovery of foregone sales
9
revenue for the Company’s 2013 and future programs, ADM’s
10
recommendation is to use data for one month (or more) to develop initial,
11
interim M&V results for each new construction site, then subsequently
12
update the results after nine months (or more) of billing data – including
13
summer and winter months – become available.
14
15
36.
Q.
PLEASE DESCRIBE THE BASIC ELEMENTS OF ENGINEERING
16
CALCULATIONS AND MODELING THAT WERE EMPLOYED
17
TO DETERMINE THE ENERGY AND DEMAND SAVINGS FOR
18
THE
19
RECYCLING PROGRAM.
20
A.
SECOND
REFRIGERATOR
COLLECTION
AND
The implementer for the Company’s Second Refrigerator Collection and
21
Recycling Program estimated ex ante savings for recycled units by taking
22
the manufacture’s estimate of annual kWh usage for a recycled unit and
23
increasing that to reflect at-death energy usage, based on an assumed
24
equipment degradation factor. For the M&V effort, this procedure was
25
examined with respect to (1) the assumed degradation factor and (2) the
26
accuracy of energy use as estimated through the DOE test procedure.
27
28
Dohrmann - Direct
27
3DJHRI
1
ADM’s review of available literature and data showed that that the
2
degradation coefficients applied by the implementer were at the upper end
3
of the range of coefficients observed in other similar studies. Based on the
4
large amount of metered data analyzed and its comprehensive nature,
5
ADM determined that a more appropriate equipment-degradation factor
6
could be developed using data and analysis prepared for a 2009 study on
7
refrigerator degradation for the California Public Utilities Commission.
8
That study (conducted by The Cadmus Group or “Cadmus”) used data on
9
refrigerator / freezer energy use obtained through two in situ monitoring
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
efforts:
11
A dual monitoring study that ADM conducted in support of the
12
evaluation of the (California) 2004-2005 Statewide Residential
13
Appliance Recycling Program; and
14
Additional in situ monitoring that Cadmus conducted as part of its
15
study.
16
17
The product of these efforts was a database that contained energy use
18
obtained through both DOE testing and in situ monitoring for a sample of
19
321 units, 184 of which were from the 2004-2005 evaluation and 137 from
20
the 2006-2008 evaluation.
21
monitoring sample to develop regression models that relate in situ energy
22
use to energy use as determined from the DOE test procedure and
23
modification factors based on weather and household size.
Cadmus used the data from this dual
24
25
26
27
28
Dohrmann - Direct
28
3DJHRI
1
H.
CONCLUSION
2
37.
Q.
3
SUMMARIZE
YOUR
TESTIMONY
IN
THIS
PROCEEDING.
4
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
PLEASE
A. I, jointly with Robert Oliver and Sasha Baroiant and Kelly Vagianos, am
5
sponsoring and presenting the M&V Reports.
6
prepared in compliance with the Commission’s regulations and industry
7
standard and practices. The reports provide measured and verified energy
8
and demand savings realized by the Company’s customers. Accordingly,
9
the reports can serve as a basis of assessing the effect of the Company’s
10
EE&C programs on sales, and the attendant financial impact of such
11
programs on the Company.
These reports were
12
13
38.
Q.
14
15
DOES
THIS
CONCLUDE
YOUR
PRE-FILED
DIRECT
TESTIMONY?
A. Yes, it does.
16
17
18
19
20
21
22
23
24
25
26
27
28
Dohrmann - Direct
29
3DJHRI
Exhibit Dohrmann-Direct-1
Page 1 of 2
STATEMENT OF QUALIFICATIONS
DONALD R. DOHRMANN
PRINCIPAL
ADM ASSOCIATES, INC.
4755 Caughlin Parkway
Reno, Nevada 89519
(775) 825-7076
Mr. Dohrmann is a Principal and Director of Economic Studies at ADM Associates,
Inc. He has been at ADM since April 1979. Dr. Dohrmann’s technical expertise is in
economics, survey design, and statistical analysis. On ADM’s evaluation projects, Dr.
Dohrmann is responsible for developing evaluation plans, preparing statistical sampling plans,
directing development of databases, and reporting. He has developed and applied analytical
methodologies for evaluating DSM programs, including evaluations of commercial and
industrial custom retrofit programs, refrigerator recycling programs, commercial new
construction programs, high efficiency motors and adjustable speed drives programs, and
commercial lighting programs. He has been responsible for designing the statistical sampling
plans for surveys of residential, commercial and industrial firms that ADM has conducted for
various companies, including Pacific Gas and Electric Company, Southern California Edison
Company, the Bonneville Power Administration, Florida Power and Light, B.C. Hydro, Kansas
City Power and Light, El Paso Electric, Southern California Edison Co., the Sacramento
Municipal Utility District, San Diego Gas and Electric Co., and other utilities. He has also been
responsible for preparing and conducting the analysis of the data collected in these surveys,
which has included statistical analysis of customer billing data. He has also developed and
applied methods for performing net-to-gross analyses for DSM programs, such as residential
appliance recycling programs and commercial and industrial custom programs.
Employment History
ADM Associates, Inc.
April 1979 to Present
Principal
April 1979 to Present
Developing and applying methods for evaluation of utility DSM programs.
Directing ADM staff in evaluating DSM programs. Current clients for which
evaluations are being performed include:
- NV Energy
- New Mexico investor-owned utilities
- Ameren Missouri
- First Energy Companies (Ohio, Pennsylvania)
- SMUD
- Idaho Power
3DJHRI
Exhibit Dohrmann-Direct-1
Page 2 of 2
Hittman Associates, Inc.
July 1977 to March 1979
Senior Economist
Responsible for economic and statistical analysis on studies of commercial
sector energy efficiency for California Energy Commission, EPRI, U. S.
Department of Energy.
United Technologies Research Center
June 1973 to June 1977
Economist
Responsible for evaluation of economic and market potential for new energy
technologies, such as repowering of combustion turbines, compressed air
storage.
University of Connecticut
September 1969 to August 1972
Instructor, Economics
Taught undergraduates in courses including principles of economics and
economic history of the United States
Education
Iowa State University
Bachelor of Science in Economics, August 1964
Yale University
Master of Arts in Economics, May 1965
Ph. D. in Economics, December 1976
3DJHRI
3DJHRI
ROBERT R. OLIVER
3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-_____
4
PREPARED DIRECT TESTIMONY OF
5
Robert R. Oliver
6
7
A.
INTRODUCTION
8
1.
Q.
EMPLOYER AND BUSINESS ADDRESS.
9
A.
10
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
MR. OLIVER, PLEASE STATE YOUR NAME, JOB TITLE,
My name is Robert R. Oliver. I am employed by ADM Associates, Inc.
11
(“ADM”) as a Director/Project Manager. My business address is 5470
12
Kietzke Lane, Suite 220 in Reno, Nevada. I provide testimony on behalf
13
of Sierra Pacific Power Company d/b/a NV Energy (“Sierra” or the
14
“Company”). I am filing testimony on behalf of Sierra.
15
16
2.
Q.
AND EXPERIENCE.
17
18
PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND
A. I have a Bachelor of Science in agricultural economics and business
19
management from Cornell University. I have been employed by ADM
20
since January of 2010.
21
various capacities since 2005, and provided consulting services for the
22
Nevada Task Force for Renewable Energy and Energy Conservation
23
during 2004 and 2005.
24
background and experience are set forth in Exhibit Oliver-Direct-1.
Previously I consulted with the Company in
More details regarding my professional
25
26
27
28
Oliver - Direct
1
3DJHRI
1
3.
2
Q.
ARE YOU SPONSORING ANY EXHIBITS?
A. Yes.
Together with Sasha Baroiant, Donald Dohrmann and Kelly
3
Vagianos, I sponsor the measurement and verification reports contained in
4
Technical Appendices DSM-5 through DSM-13 (the “M&V Reports”).
5
6
4.
Q.
UTILITIES COMMISSION OF NEVADA?
7
A. 8
Yes.
I previously testified before the Commission in the following
dockets.
9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
10
1. Sierra Pacific Power Company’s (“Sierra”)and Nevada Power
11
Company’s (“Nevada Power”) 2011 Annual DSM Update
12
Reports – Docket Nos. 11-07026 and 11-07027
2. Sierra’s and Nevada Power’s
13
Deferred Energy Accounting
Adjustment – Docket Nos. 12-03004, 12-03005 and 12-03006
14
3. Nevada Power’s 2012 IRP and Sierra’s 2012 Annual DSM
15
Update Report – Docket Nos. 12-06052 and 12-06053
16
17
18
5.
Q.
SUMMARIZE
YOUR
TESTIMONY
IN
THIS
PROCEEDING.
19
20
PLEASE
A. In Section B, I discuss the “Energy Savings Curves” that ADM provided
21
to the Company to enable the Company to analyze hourly demand (kW)
22
impacts per rate class to forecast hourly demand impacts per rate class for
23
prospective 2014-2016 programs. I also discuss the per-month, per-rate
24
class kW and kWh spreadsheets that ADM provided the Company.
25
Section C of this testimony contains my conclusions.
26
27
28
Oliver - Direct
2
3DJHRI
1
6.
Q.
PLEASE EXPLAIN WHY YOU ARE SPONSORING THE M&V
2
REPORTSJOINTLY WITH DONALD DOHRMANN, SASHA
3
BAROIANT AND KELLY VAGIANOS.
A.
4
As Dr. Dohrmann explains, the measurement and verification process is a
5
cross-discipline effort. Accordingly, we jointly sponsor the M&V Reports
6
for the purpose of providing information to the Commission in an efficient
7
and clear manner.
8
information that is in the control of the Company. For this reason, Ms.
9
Vagianos also provides testimony in support of the M&V Reports.
In addition, the M&V effort relies in part on
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
11
B.
KW AND KWH SAVINGS
12
13
“ENERGY SAVINGS CURVES” AND PER MONTH, PER RATE CLASS
7.
Q.
MR. OLIVER, WHAT DATA DID ADM PROVIDE THE
14
COMPANY TO ENABLE THE COMPANY TO UPDATE ITS
15
“PORTFOLIO PRO” LOAD SHAPES?
16
A. For the following programs, ADM provided the Company a spreadsheet
17
containing program-level “Energy Savings Curves” that were used in – or
18
derived from – ADM’s M&V analyses of the Company’s programs for the
19
most recent program year in which each program was implemented. For
20
each of the following programs, ADM provided a program-level “Energy
21
Savings Curve” comprised of 8,760 hourly values listed in a column in an
22
Excel file. For each of these programs, its 8,760 hourly values summed to
23
one, i.e., each “Energy Savings Curve” was normalized to sum to unity.
24
As such, each hourly value in a given, normalized “Energy Savings
25
Curve” represents the fraction of annual energy savings that occurs in that
26
hour as the result of the implementation of Sierra’s program.
27
28
Oliver - Direct
3
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
Residential Lighting
2
Refrigerator Recycling
3
Consumer Electronics
4
Solar Thermal Water Heating
5
Non-Profit Agency Grants
6
Energy Smart Schools
7
Commercial New Construction
8
Commercial Retrofit
9
Commercial Incentives
10
Home Energy Reports
11
DR Residential
12
DR Commercial
13
DR Agricultural
14
15
8.
Q.
WERE THE PROGRAM-LEVEL, HOURLY “ENERGY SAVINGS
16
CURVES” THAT ADM PROVIDED TO THE COMPANY THE
17
SAME AS THE DATA ANALYZED AND REPORTED BY ADM IN
18
THE RESPECTIVE M&V REPORTS FOR THE COMPANY’S 2012
19
PROGRAMS?
20
A.
Yes, for most programs. However, certain exceptions were necessary, as
described below for the following programs.
21
22
Residential Lighting: ADM provided the program-level “Energy
23
Savings Curve” for program year 2011 (“PY2011”) instead of program
24
year 2012 (“PY2012”) because the Residential Lighting program was
25
not implemented in PY2012.
26
27
28
Oliver - Direct
4
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
Commercial Incentives: This program is a combination of the
2
Commercial Retrofit incentives program and the Commercial New
3
Construction program delivered separately in prior years, so ADM
4
provided an estimated program-level “Energy Savings Curve” for
5
2014-2016 which was derived from Sierra’s PY2012 Commercial
6
programs.
7
Home Energy Reports: This is a new program, therefore ADM
8
provided an estimated program-level “Energy Savings Curve” for
9
2014-2016 for which the derivation is described in Dr. Baroiant’s
10
testimony.
11
DR Residential: This is a new program, therefore ADM provided an
12
estimated program-level “Energy Savings Curve” for 2014-2016 for
13
which the derivation is described in Dr. Baroiant’s testimony.
14
DR Commercial: This is a new program, therefore ADM provided an
15
estimated program-level “Energy Savings Curve” for 2014-2016 for
16
which the derivation is described in Dr. Baroiant’s testimony.
17
DR Agricultural: This is a new program, therefore ADM provided an
18
estimated program-level “Energy Savings Curve” for 2014-2016 for
19
which the derivation is described in Dr. Baroiant’s testimony.
20
21
9.
Q.
PLEASE PROVIDE A DESCRIPTION OF THE kw guru™ FILES
22
THAT ARE THE SOURCE OF THE PER MONTH PER RATE
23
CLASS KW AND KWH SAVINGS, AND THE SPREADSHEETS,
24
MODEL OUTPUTS AND OTHER SOURCES THAT PROVIDE
25
INPUTS TO THE kw guru™ FILES.
26
27
28
Oliver - Direct
5
3DJHRI
1
T
he KW GURU™ files are expansive Excel based spreadsheets that ADM
2
has created to calculate the ex post energy savings for DSM programs.
3
For programs with relatively straightforward computations, the entire ex
4
post savings calculation is contained in the kw guru™ file. For programs
5
such as the Commercial Retrofit Incentives program that include a variety
6
of measures that require differing calculations, specialized calculations
7
from software modeling tools or more complex calculations, the kw
8
guru™ file becomes the assembly point for each of these diverse sources
9
to create the unified results reported as ex post savings and the per-month
10
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
A.
per-rate class kW and kWh savings tables provided in the M&V Reports.
11
12
The determination of whether all of the computations are included in the
13
kw guru™ files or some of the calculations are performed separately is
14
based on both the complexity of the computations and the required
15
computing time. For those programs with less complex computations, all
16
of the inputs are entered directly into the kw guru™ file. Sources can
17
include TrakSmart® project data, measurement and verification data
18
collected by ADM, data from resources such as California’s DEER
19
database, energy savings curves from multiple sources, technical reference
20
manuals, DOE data or industry recognized white papers and surveys
21
conducted by ADM that are specific to the program being evaluated. The
22
time required to execute the computations in the file may dictate that they
23
be done in steps, and that the results from one step be manually copied and
24
pasted as inputs to the next step before the next step is executed.
25
26
Projects that are more complex include multiple model runs and separate
27
spreadsheet computations. The results from each of these other sources
28
Oliver - Direct
6
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
are then copied and pasted into the kw guru™ file to be summarized and
2
to obtain the measured and verified result for the program as a whole.
3
M&V analyses for certain DSM programs require dozens of DOE-2
4
analysis files, which feed output values to Excel files that must (for
5
efficiency of human resources as well as electronic-computation
6
resources) be kept separate from the kW and kWh savings per month per
7
rate class spreadsheets.
8
statistical programs that are far more robust than Excel; results from those
9
statistical programs must then be imported into the kW and kWh savings
10
per month per rate class spreadsheets. These examples are mentioned to
11
explain why the data contained in the kW and kWh savings per month per
12
rate class spreadsheets is typically a small fraction of the data that that was
13
analyzed to achieve those final results for ex post verified energy savings.
14
Sources also include TrakSmart® project data, measurement and
15
verification data collected by ADM, data from resources such as
16
California’s DEER database, energy savings curves from multiple sources,
17
technical reference manuals, DOE data or industry recognized white
18
papers and surveys conducted by ADM that are specific to the program
19
being evaluated.
1
Certain DSM programs require the use of
20
21
10.
Q.
WHAT ISSUES DOES THIS PROCESS PRESENT FOR THE
REVIEW OF THE CALCULATIONS OF EX POST SAVINGS?
22
A.
23
As a result of performing the calculations in steps and copying the results
from one step to the next step within the kw guru™ file – as well as
24
25
26
1
27
ADM uses the DOE2 EQuest Model for calculating energy savings, demand savings and developing energy
savings curves. A description of the EQuest model is provided in Exhibit Oliver-Direct-2.
28
Oliver - Direct
7
3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
pasting results into the kw guru™ file from multiple calculations
2
performed in separate models or spreadsheets – it can be difficult to follow
3
the computations from one step to the next, as the figures that have been
4
brought in from other sources are not linked back to those sources. In
5
recent years, ADM has met with Sierra and the Commission’s Regulatory
6
Operation Staff (“Staff”) to demonstrate the derivation of the calculated ex
7
post verified energy savings values for which hard coded values were
8
copied and pasted into the kw guru™ file for the computation of ex post
9
savings and the kW and kWh savings per month per rate class
10
spreadsheets. At those sessions ADM also discussed and demonstrated its
11
utilization of energy savings curves in the kw guru™ files for determining
12
the kW and kWh savings per month per rate class. ADM recommends
13
ongoing collaboration with Sierra, Staff and other stakeholders to
14
determine the most effective ways we can provide access to and explain
15
the usage of the many kinds of analysis files that feed into the
16
determination of the ex post savings and the kW and kWh savings per
17
month per rate class.
18
19
11.
Q.
DO THE PER MONTH PER RATE CLASS CALCULATIONS AND
20
KWH AND KW SAVINGS ALLOCATIONS MATCH THE
21
AGGREGATE
22
PROVIDED IN THE M&V REPORTS?
23
A.
KWH
AND
KW
SAVINGS
THAT
WERE
Yes.
24
25
26
27
28
Oliver - Direct
8
3DJHRI
1
C.
C
ONCLUSION
2
12.
Q.
PLEASE
SUMMARIZE
YOUR
TESTIMONY
IN
THIS
PROCEEDING.
3
A. 4
Jointly with Donald Dohrmann, Sasha Baroiant and Kelly Vagianos, I am
5
sponsoring and presenting Sierra’s M&V Reports for program year 2012.
6
The M&V Reports provide measured and verified energy and demand
7
savings for the Company’s energy efficiency and conservation programs
8
in a manner that is consistent with industry practices.
9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
13.
Q.
THIS
CONCLUDE
YOUR
PREPARED
DIRECT
TESTIMONY?
11
12
DOES
A. Yes, it does.
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Oliver - Direct
9
3DJHRI
Exhibit Oliver Direct-1
Page 1 of 2
STATEMENT OF QUALIFICATIONS
ROBERT OLIVER DIRECTOR
ADM ASSOCIATES, INC.
4755 Caughlin Parkway
Reno, Nevada 89519
(775) 825-7076
Education
Bachelor of Science, Business Management and Finance, Cornell University
Areas of Expertise
Energy Use Analysis
Field Work Experience
Analysis of Metered Data
Regulatory Support
Organizational Structure Review
Financial Management
Years of Professional Practice
Mr. Oliver is an energy industry professional with 25 years of contract and program
management experience, including extensive work with electric and gas utility demandside management (DSM) programs. Mr. Oliver’s focus is process and impact evaluation
and reporting for residential, commercial, agricultural and solar DSM programs,
including current oversight responsibility for DSM program evaluations for Nevada and
Ohio utilities. He also serves as lead analyst for various program-level evaluations, and
has served as lead writer or editor for scores of evaluation reports and related technical
documents. Mr. Oliver’s skills include DSM program design and implementation. He
developed and executed residential energy conservation initiatives such as Energy Star
programs for various utilities, and led implementation teams that consistently exceeded
energy targets.
Mr. Oliver has counseled numerous governmental and private industry clients, delivering
recommendations related to strategic issue management, public policy initiatives and
communications with key constituents or stakeholders. His Bachelor of Science in
Business Management and Finance was awarded by Cornell University.
3DJHRI
Exhibit Oliver Direct-1
Page 2 of 2
Energy Use Analysis/Analysis of Metered Data
Mr. Oliver has analyzed energy usage for numerous residential, commercial and
agricultural programs, including analyses of measures such as lighting, consumer
electronics, pool pumps, refrigeration, traffic signals, space cooling and heating, motors
and agricultural water pumping. His analysis methodologies utilize engineering
calculations and simple regression analyses for which data inputs include primary data
sources such as measured energy usage and customer survey results, and secondary data
sources such as published engineering data and energy efficiency reports. His analysis
skills include the use of 8760 load shapes to identify energy savings occurring during any
selected timeframe during a typical year, and to quantify critical peak demand savings per
load shape.
Field Work Experience
Mr. Oliver has developed sampling plans that employ statistical protocols such as
Dalenius-Hodges stratification techniques. He has managed field resources, supervised
field measurement and verification projects, provided staff training and oversight of
logistics and scheduling, developed field data collection forms and verified installation
for measures installed within various energy conservation programs.
Regulatory Support
Mr. Oliver has significant expertise in the realm of state statutes and regulations
governing the implementation and evaluation of energy efficiency and renewable energy
projects. He currently serves as an advisor, and provides data analysis and reports related
to utilities’ revenue losses associated with the implementation of energy efficiency
projects.
Organizational Structure Review
Mr. Oliver has 25 years of experience reviewing organizational structures of whole
enterprises and subsets (e.g., one or more departments within the whole enterprise) in a
diverse range of industries. In recent years he has applied this skill set on behalf of utility
clients and within process evaluations for energy efficiency programs.
Financial Management
Mr. Oliver has 25 years of financial management, contract management and project
management experience in a diverse range of industries, with specific expertise
developing budgets and fulfilling whatever specific scope of work or client requirements
need to be accomplished with relatively limited resources. He is currently managing
ADM’s long-term contracts with Nevada and Ohio utilities.
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3DJHRI
SASHA S. BAROIANT
3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-_____
4
PREPARED DIRECT TESTIMONY OF
5
Sasha S. Baroiant
6
7
1.
Q.
8
EMPLOYER AND BUSINESS ADDRESS.
9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
DR. BAROIANT, PLEASE STATE YOUR NAME, JOB TITLE,
A.
My name is Sasha S. Baroiant. I am employed by ADM Associates, Inc.
10
(“ADM”) as a Director/Project Manager. My business address is 3239
11
Ramos Circle in Sacramento, California. I am filing this testimony on
12
behalf of Sierra Pacific Power Company d/b/a NV Energy and Nevada
13
Power Company d/b/a NV Energy.
14
15
2.
Q.
16
PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND
AND EXPERIENCE.
17
A. I have a Bachelor of Science in Physics and a Ph.D. in Experimental High
18
Energy Physics from the University of California, Davis. I have been
19
employed at ADM Associates since 2007. More details regarding my
20
professional background and experience are set forth in my Statement of
21
Qualifications, included as Exhibit Baroiant-Direct-1.
22
23
24
3.
Q. WHAT IS THE PURPOSE OF YOUR PREPARED TESTIMONY?
A. My testimony demonstrates that the energy savings curves, an integral
25
component of the measurement and verification reports (“M&V Reports”)
26
for the 2012 DSM programs delivered by NV Energy, are reasonable and
27
28
Baroiant - Direct
1
3DJHRI
1
appropriate for the allocation of energy savings for each program
2
throughout each of the 8,760 hours of the year. I discuss updates to
3
savings curves for the 2012 programs and new savings curves developed
4
for programs expected to be implemented in the next program cycle.
5
6
4.
Q.
7
UTILITIES COMMISSION OF NEVADA?
8
A. 9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
Yes.
I previously testified before the Commission in the following
dockets.
10
1. Sierra Pacific Power Company’s (“Sierra”)and Nevada Power
11
Company’s (“Nevada Power”) 2011 Annual DSM Update
12
Reports – Docket Nos. 11-07026 and 11-07027
2. Sierra’s and Nevada Power’s
13
Deferred Energy Accounting
Adjustment – Docket Nos. 12-03004, 12-03005 and 12-03006
14
3. Nevada Power’s 2012 IRP and Sierra’s 2012 Annual DSM
15
Update Report – Docket Nos. 12-06052 and 12-06053
16
4. Sierra’s and Nevada Power’s
17
Deferred Energy Accounting
Adjustment – Docket Nos. 13-03003, 12-03004 and 12-03005
18
19
20
5.
21
Q. ARE YOU SPONSORING ANY EXHIBITS?
A. Yes. I am sponsoring the following Exhibits:
22
Exhibit Baroiant-Direct-1
Statement of Qualifications 23
24
25
26
6.
Q.
PLEASE SUMMARIZE YOUR TESTIMONY?
A. In my testimony I discuss the process that I employed to determine that
the energy savings curves employed in the development of the M&V
27
28
Baroiant - Direct
2
3DJHRI
1
Reports are reasonable and appropriate for the distribution of program
2
energy savings throughout the year. I discuss updates and improvements
3
made to savings curves for residential programs, and an update in
4
methodology and data sources for the commercial and industrial programs.
5
6
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
7
7.
Q.
WHY HAVE YOU UPDATED THE SAVINGS CURVES FOR 2012?
A.
Our goal is to provide the best possible representation of the program and
8
portfolio level impacts each year.
9
programs change from year to year through inclusion of new measures,
10
changes in measure distributions, or even changes in code or market
11
baselines, updated curves may be necessary. In addition, our experience
12
in prior proceedings before the Commission has reinforced our belief in
13
the need for a rigorous approach to developing energy savings curves as a
14
part of the M&V process. The added rigor does not mean that the energy
15
savings curves that ADM provided for Sierra’s Deferred Energy
16
Proceeding, Docket No.13-03004, are deficient in any way, but rather that
17
the energy savings curves provided for this filing benefit from our ongoing
18
commitment to improving the quality and precision of the M&V results.
As the demand side management
19
20
Updates related to savings curves can be put into two broad categories:
21
data updates and methodology updates.
22
reasons for updates in these categories. Opportunities for data updates
23
include the availability of new reputable sources of secondary data (e.g., a
24
new end use metering study) or the availability of program-specific
25
primary data.
26
collection for a large fraction of the projects, as weighted by impacts, the
There are opportunities and
Given that ADM samples and conducts on-site data
27
28
Baroiant - Direct
3
3DJHRI
1
latter opportunity is ever present. Reasons for data updates may include
2
new programs, new measures, or even a significant change in the
3
relevance of a measure within a program. For example, street lighting was
4
a major measure for Southern Nevada in 2012; though CEUS has several
5
exterior lighting curves, none are exclusively derived from streetlights.
6
Opportunities for methodology updates include innovations that result in
7
cost effective, material improvements in curve accuracy or specificity.
8
9
8.
Q.
SIGNIFICANT METHODOLOGY
UPDATES THAT APPLY TO THE 2012 SAVINGS CURVES.
10
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
PLEASE DESCRIBE THE
11
A.
There are two significant methodology updates and both pertain to the
12
nonresidential programs. The first methodology update includes heating
13
and cooling interactive factors (HCIF) for commercial lighting and
14
refrigeration/motors measures.
15
sector are updated to reflect the secondary HCIF impacts that are
16
determined in the EM&V effort.
17
methodology and data sources. Prior to 2012 the nonresidential savings
18
curves relied almost exclusively on data from the California Commercial
19
End Use Survey (CEUS). The 2012 nonresidential curves still draw from
20
the CEUS study, but the curves also utilize data collected during the 2012
21
impact evaluations.
The 2012 curves in the nonresidential
The second update includes both
22
23
9.
Q.
IF HCIF FACTORS ARE ALREADY INCLUDED IN THE M&V
24
PROCESS, WOULD THEIR INCLUSION IN THE SAVINGS
25
CURVES DOUBLE-COUNT THESE FACTORS?
26
27
28
Baroiant - Direct
4
3DJHRI
1
A. No, all savings curves are normalized to equal 1.0 in any non-leap year.
2
Therefore, the curves do not increase or decrease the energy savings that
3
have been determined by the impact evaluations.
4
5
Q.
IF THE INCLUSION OF HCIF IN THE SAVINGS CURVES DOES
6
NOT INCREASE OR DECREASE THE SAVINGS, THEN WHY IS
7
IT IMPORTANT TO UPDATE THE CURVES IN THIS RESPECT?
8
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10.
A.
ADM’s responsibility is to provide information with regards to how much
9
savings result from Sierra’s demand side management programs, and also
10
with regards to when those savings occur. Both aspects are necessary to
11
quantify the DSM programs’ impacts on the time-dependent demand for
12
electric energy.
13
importance of having unbiased information regarding the valuation of
14
potential measure impacts. The example below does not necessarily apply
15
to Sierra’s portfolio, but makes the point that in a resource-limited
16
allocation, an overly conservative estimation of a measure’s impacts
17
would lead to under-allocation of that measure and vice versa.
Below I provide an example to demonstrate the
18
19
Portfolio designers must weigh the valuation of a measure (measured in
20
terms of the ability to reduce energy usage and to reduce electric demand
21
in a given time period) with the costs associated with the measure
22
implementation. Just as investment vehicles in a financial portfolio have
23
estimated risk in the expected rates of return, DSM measures may also
24
have a certain amount of “M&V uncertainty” defined as the risk that the
25
realized savings are different than the planned or estimated savings.
26
Without full consideration of HCIF, the savings curves would
27
28
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1
underestimate the peak-reducing potential of lighting upgrades. This may
2
lead a portfolio designer to specify a greater amount of other measures to
3
achieve a targeted peak load reduction. EM&V experience has shown
4
that, compared to most other significant measures in DSM portfolios,
5
lighting upgrades are often more cost effective and have less M&V risk. It
6
follows, then, that without full consideration of HCIF factors in
7
commercial lighting (and residential lighting), the portfolios would be
8
weighted more heavily toward measures that are peak targeting, but may
9
be less cost effective and may have greater M&V risk.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
11
11.
Q.
WHY
HAS
ADM
STARTED
TO
INCORPORATE
DATA
12
COLLECTED THROUGH M&V INTO THE SAVINGS CURVES,
13
RATHER THAN RELYING WHOLLY ON CEUS DATA?
14
A. There are several reasons for inclusion of site-specific data. One reason is
15
that concerns have been raised of the potential that CEUS-derived data
16
may not be fully representative of Sierra’s or Nevada Power’s service
17
territories.
18
territory-specific information in the savings curves. For example, the
19
savings curves for Washoe County schools are now modified to match the
20
school district instructional calendar. As shown in Figure 1 below, the
21
ADM-modified curve tends to have a more pronounced “dip” in the
22
summer season.
To address this concern ADM has incorporated service
23
24
25
26
27
28
Baroiant - Direct
6
3DJHRI
Figure 1 – Comparison of original CEUS curve to ADM-modified CEUS curve for
interior lighting in Washoe County Schools.
1
2
3
4
5
6
7
8
9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
11
In my previous testimony I investigated and confirmed that the curves for
12
the 2011 programs were appropriate.1 In preparation for that testimony I
13
constructed reasonable alternate savings curves from data collected
14
through project level M&V to cross-check the CEUS-based curves.
15
Because I concluded that both the CEUS-derived and the project-derived
16
sets of curves were generally in good agreement, it follows that both
17
methods of curve generation or specification should be considered as
18
potential sources for savings curves.
19
20
12.
Q.
DO
PROJECT-LEVEL
SAVINGS
CURVES
REQUIRE
ADDITIONAL DATA COLLECTION?
21
22
A.
We typically gather sufficient data to construct savings curves through our
23
normal impact evaluation activities.
24
always cast into hourly resolution. We developed spreadsheet-based tools
25
that construct site-specific savings curves for lighting and for simpler
However, the information is not
26
1
27
Sierra’s and Nevada Power’s Deferred Energy Accounting Adjustment – Docket Nos. 13-03003, 12-03004
and 12-03005
28
Baroiant - Direct
7
3DJHRI
1
refrigeration or motors projects. These tools increase M&V transparency
2
and also serve to catalog savings curves. It is hoped that continued use of
3
these tools will eventually generate Nevada-specific savings curves that
4
rival the CEUS project in sample size – at least for the commercial
5
lighting and simple refrigeration measures.
6
7
More complicated measures typically require regression or simulation
8
analyses. In most cases, these analysis tools generate savings estimates
9
with hourly resolution, so it is possible to cast the outputs into savings
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
curves.
11
12
13.
Q.
HOW DOES ONE DECIDE WHETHER TO USE A CEUS-BASED
13
CURVE OR A PROJECT-SPECIFIC CURVE FOR A GIVEN
14
MEASURE OR END-USE?
15
A.
In my review of the curves I have noticed that CEUS-derived curves are
16
most applicable when describing measures that are implemented on a large
17
number of facilities. As the participation increases for a given measure,
18
most attributes of interest tend to approximate the overall market and are
19
quite compatible with CEUS. If a measure is implemented only once or
20
twice, or is dominated by a very high savings project, then a project-
21
specific curve would better capture peculiarities associated with the one or
22
dominant installation of a measure. In particular, we specified the savings
23
curves for Sierra’s Sure Bet New Construction program entirely from data
24
gathered during project level M&V. This is possible for the 2012 Sure Bet
25
New Construction program because ADM sampled a very high fraction of
26
the projects, as weighted by energy savings.
27
28
Baroiant - Direct
8
3DJHRI
1
PLEASE DESCRIBE THE PROCESS ADM EMPLOYED TO
2
DEVELOP AN ENERGY SAVINGS CURVE FOR A GIVEN
3
MEASURE OR END-USE.
4
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
14. Q.
A.
The process that was used to specify energy savings curves is as follows:
5
1. Categorize all projects in the program by facility type and end-use.
6
2. For each combination of facility type and end-use, calculate the
7
fraction of projects (weighted by energy savings) that fell into ADM’s
8
evaluation sample.
9
3. Construct a blended curve that has project-specific curves for each
10
sampled project under a given facility type and measure combination,
11
and has CEUS-based curves for the remaining projects, again weighted
12
by project level savings.
13
14
For example, if ADM sampled 14 of 77 projects that had interior lighting
15
in retail establishments, and that the 14 sampled projects accounted for
16
50% of the savings in the group of 77, then the savings curve would be
17
constructed using 15 curves. The CEUS curve for interior lighting in
18
retail establishments – modified with HCIF – would have a weight of
19
50%, while the remaining curves would be weighted in accordance to their
20
savings and sample weights and would represent the remaining 50% of the
21
savings.
22
23
I have listed all the savings curves used to describe Sierra’s 2012
24
nonresidential programs in Table 1 below. Some of the curves are named
25
after rebate numbers because they represent specific projects. This is
26
often the case with the New Construction program. In general, curves that
27
28
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3DJHRI
1
are focused on industrial motors and large new construction projects are
2
heavily weighted toward project-specific curves.
3
4
5
6
7
8
9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Table 1: List of savings curves used to describe SPPC’s 2012
nonresidential DSM programs.
Rank (by annual
MWh)
3,568,825
3,479,658
Flat (often mining related)
IntLight (Warehouse)
0%
63%
100%
37%
3,100,833
3,097,251
2,689,617
2,516,445
2,206,237
2,145,809
1,072,560
1,010,927
823,053
IntLight Washoe County
Schools
IntLight (Misc)
SB12-01894 VFD
ExtLight (Lodging)
IntLight (Lodging)
IntLight (Retail)
Misc (Misc)
SB12-01667 Whole Building
Misc (Lodging)
70%
78%
0%
0%
59%
55%
99%
0%
100%
30%
22%
100%
100%
41%
45%
1%
100%
0%
602,528
569,050
518,744
512,126
445,647
393,542
366,494
282,689
250,998
228,182
223,717
219,831
202,980
192,367
167,811
167,616
165,060
140,016
140,016
105,843
New Construction Program
Level
IntLight (Small Office)
ExtLight (Misc)
IntLight (Health)
Motors (Lodging)
SB12-01664 Whole Building
IntLight (Restaurant)
Motors (Misc)
GREM (Lodging)
Motors (University)
SB12-01666 HVAC
IntLight (SB1851)
Ventilation (Restaurant)
Misc (Small Office)
ExtLight (Retail)
Vending
Misc (Retail)
SB12-02544 VSD
SB12-02546 VSD
NonProfitAgencyGrants
0%
92%
80%
87%
100%
0%
98%
100%
12%
100%
0%
0%
100%
100%
70%
80%
100%
0%
0%
0%
100%
8%
20%
13%
0%
100%
2%
0%
88%
0%
100%
100%
0%
0%
30%
20%
0%
100%
100%
100%
91,508
Cool - Washoe County
Schools
80%
20%
33,007
30,876
15,448
School - ExtLight
SB12-01946 HVAC Lighting
SB12-01911 HVAC
80%
0%
0%
20%
100%
100%
Savings Curve
% CEUS
% ADM
26
27
28
Baroiant - Direct
10
3DJHRI
1
15.
CAN YOU DESCRIBE UPDATES THAT APPLY TO THE 2012
Q.
RESIDENTIAL SAVINGS CURVES?
2
3
A.
I would not describe any update to residential sector curves as
4
“significant”. The energy savings curves for second refrigerator recycling
5
have been updated to have hourly resolution, as shown by Figure 2. The
6
energy savings curve for the Consumer Electronics Program has been
7
updated to correct a transcription error that led to a 1% rise in monthly
8
utilization for the month of May as shown by Figure 3.
9
11
Figure 2 - Comparison of 2011 (solid black profile) and
2012 (dashed profile) hourly savings curves for refrigerators
in the Second Refrigerator Removal and Recycling Program.
12
SPPC Refrigerator
13
14
15
16
17
18
19
20
21
22
Hourly kW per MWh Annual Savings
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
SPPC Refrigerator 2012 Curve
0.16
0.14
0.12
0.10
0.08
0.06
0.04
0.02
0.00
1
23
24
3
5
7
9 11 13 15 17 19 21 23
Hour on Average Day in July
25
26
27
28
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3DJHRI
Figure 3 – Comparison of 2011 (solid black profile) and 2012 (dashed profile) savings curves for the Home Entertainment program (NPC and SPPC use the same curve).
1
2
3
NPC - Consumer Electronics
4
12%
Percent of Annual Savings
5
6
7
8
9
10
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
Home Entertainment 2012
11
12
10%
8%
6%
4%
2%
0%
13
1
14
2
3
4
5
6
7
Month
15
8
9
10
11
12
16
17
18
16.
Q.
PLEASE DESCRIBE THE ENERGY SAVINGS CURVES THAT
19
ADM
20
PORTFOLIOPRO FINANCIAL MODELING.
21
22
A. PROVIDED
FOR
SIERRA
TO
USE
IN
THE
ADM has provided thirteen curves to Sierra for use the PortfolioPro
financial modeling. The curves are listed in Table 2 below.
23
24
25
26
27
28
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Table 2: List of Savings Curves Used for Soerra’s IRP.
1
2
3
Savings Curve
Source
Residential Lighting
Refrigerator Recycling
2011 Program Shape
2012 Program Shape
Consumer Electronics
Solar Thermal
Home Energy Reports
Non-Profit AgencyGrant
Energy Smart Schools
Commercial New Const.
Commercial Retrofit
Commercial ALL (2014)
DR Residential + Savings - Ecofactor
DR Commercial + Savings - Building IQ
DR Agricultural - Normalized
2012 Program Shape
2012 Program Shape
SPPC Load Research Data
2012 Program Shape
2012 Program Shape
2012 Program Shape
2012 ProgramShape
Combined from 2012 Program Shapes
M&V Reports + Engineering Calculations
ADM Simulations
SPPC Load Research Data
4
5
6
7
8
9
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
11
For programs that will be administered in a similar manner as in 2012,
12
such as Second Refrigerator Removal and Recycling, Consumer
13
Electronic, Solar Thermal Water Heaters, Energy Smart Schools, and
14
Non-Profit Agency Grants, the weighted program level savings curve from
15
2012 were used as the savings curves for future years. The Commercial
16
New Construction and Retrofit programs will be combined in the future.
17
To represent the future program, ADM created an average savings curve,
18
weighted by the total savings achieved by each of the two programs in
19
2012. The residential lighting program to be implemented in future years
20
derives its shape from the 2011 residential lighting program. Though the
21
future program will focus on LED lighting, the curve from the CFL-driven
22
2011 program is appropriate because the underlying lighting utilization
23
patterns are expected to be relatively insensitive to lighting technology.
24
The curves from Residential Lighting, Refrigerator Recycling, and
25
Consumer Electronics would likely be improved upon with the inclusion
26
of HCIF. These three curves presently do not account for heating and
27
28
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3DJHRI
1
cooling interactive effects. The curve from the Home Energy Reports
2
program is developed from Sierra’s load research data. The Home Energy
3
Reports program is a behavioral based program. The savings curve for
4
this program is a scaled down (to unity) version of the hourly usages for
5
the Residential Single-Family and Residential Multi-Family rate classes.
6
The inherent assumption is that the energy savings from this program are
7
expected to be proportional to energy usage, in real time. This is likely to
8
be a conservative assumption. Implementers of similar programs have
9
reported disproportionate savings during peak times such as summer
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
weekday afternoons.
11
12
17.
Q.
PLEASE DESCRIBE THE ENERGY SAVINGS CURVES THAT
13
ADM
14
PORTFOLIOPRO FINANCIAL MODELING OF THE DEMAND
15
RESPONSE MEASURES.
16
A.
PROVIDED
FOR
SIERRA
TO
USE
IN
THE
Sierra Pacific proposes three demand response measures for the 2014­
17
2034 IRP. Demand response in the residential sector will be achieved
18
through the direct load control and energy management thermostats that
19
employ a software based optimization to reduce energy usage. Demand
20
response for the commercial sector will also focus on the heating, cooling
21
and ventilation (HVAC) end use and will utilize software based energy
22
usage optimization technology that provides a remote interface to
23
participating customers’ energy management systems. The third segment
24
of demand response focuses on agricultural pivots.
25
deployed for the agricultural pivots will enable more efficient irrigation
26
through feedback based on remote sensing, as well as traditional direct
The technology
27
28
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3DJHRI
1
load interruption capability for demand response events. Each of the three
2
measures combine direct load control mechanisms with energy efficiency
3
gains through data monitoring, optimization algorithms, and feedback
4
controls. As such, the programs are expected to achieve energy impacts
5
on both “event” and “non-event” days. ADM developed hourly savings
6
curves for these programs through a combination of methods including
7
energy simulation, analysis of load research data, and M&V of pilot
8
programs. The development of the savings curves are discussed below.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
9
10
Residential HVAC
11
The residential demand response and energy optimizing thermostat is the
12
basis for the future residential demand response program. The demand
13
response performance capacity of this device has been evaluated in pilot
14
studies in 2011 and 2012. The device can also achieve energy savings
15
through several mechanisms: In the cooling season, the device saves
16
energy by running the air handler for several minutes after the traditional,
17
compressive cooling cycle has ended.
18
handler into a direct evaporative cooler and achieves an ultra-efficient
19
cooling “boost” after each air conditioning cycle. ADM is familiar with
20
this technology and has evaluated a similar proportional time delay relay
21
for residential HVAC in Nevada Power’s service territory in 2011 and
22
2012. This thermostat can also save energy by altering the thermostat set
23
points.
24
setback may result in approximately 5% savings in the cooling season and
25
3% savings in the heating season.
This effectively turns the air
The potential gains are significant in that even a one-degree
26
27
28
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3DJHRI
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
1
ADM modeled the demand response performance by reviewing results
2
from pilot events conducted for M&V purposes.
3
experimentation in 2012, it was determined that optimization thermostats
4
can achieve approximately a 1.2 kWh reduction per controlled AC unit
5
during the first hour of deployment, provided that the hour is in the
6
afternoon, where AC usage is highest. The impact evaluation also found
7
that the second-hour savings are significantly lower, at 0.7 kWh. This is
8
typical for devices that curtail air conditioner (AC) load through
9
controlling space temperature rather than by sending a direct interrupt
10
signal to the AC unit for the entire duration of the event. ADM also
11
modeled “snapback”, or the additional AC energy usage associated with
12
restoring the indoor temperatures to their normal set points after the event
13
period. The snapback on hot days is modeled at 0.5 kWh additional usage
14
per point the first hour after the event, and 0.25 kWh additional usage per
15
point the second hour after the event.
After some
16
17
ADM modeled the energy impacts as a percentage of the (electric) heating
18
or cooling energy usage for a typical customer. To model the baseline
19
heating and cooling loads, ADM obtained load research data from SPPC.
20
The data consisted of hourly loads from April 2009 to March 2010 for
21
residential single-family and residential multi-family homes. The portion
22
of loads associated with heating and cooling were isolated by subtracting
23
the hourly usages from the month of May from the corresponding hours
24
for other months. The month of May was selected as the best month to
25
represent non-HVAC usage through comparison of energy usage to
26
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1
cooling and heating degree days. It appears that, in Northern Nevada,
2
there is little electric energy usage associated cooling or heating in May.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
3
4
Having isolated the hourly energy usage associated with heating and
5
cooling, ADM developed a savings curve by multiplying the hourly
6
usages by 24% in the summer season and 16% in the winter season. The
7
savings percentages have been constructed to match the lower end of
8
ADM’s estimate of 300 kWh to 450 kWh savings per home from the
9
M&V of the 2012 EcoFactor Pilot Study2. The 24% savings in estimate in
10
the summer time is significantly larger than the savings estimate for the
11
same device in Nevada Power territory.
12
device in Sierra territory is motivated by the engineering principle that the
13
relative savings for air handler time delays increase as the compressor
14
cycle times decrease, and by the observation that AC run times are
15
significantly shorter in SPPC service territory than in NPC service
16
territory. The savings estimation for the winter period is lower because
17
optimization thermostats have the additional savings mode associated with
18
the time delay relay that is available in the summer only.
The higher estimate for the
19
20
Finally, the energy savings and demand reduction impacts are combined
21
through simple addition, with the energy savings curves both normalized
22
to represent the typical customer3. A total of 18 events are simulated with
23
24
25
26
2
See Demand Response M&V Report - Evaluation of 2012 Residential Demand Response Pilot provided in
Technical Appendix DSM-6
3
That is, both the demand response and energy savings impacts have as the unit, one home. Usage of load
research data implies that the relative fractions of multi-family and single-family homes, and gas-heated vs.
electrically heated homes, are consistent with the corresponding SPPC service territory averages.
27
28
Baroiant - Direct
17
3DJHRI
1
the distribution of dates (one day in June, 11 days in July, and six days in
2
August) informed by the same long-term weather forecasts that Sierra uses
3
to develop peak demand estimates
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
4
5
Commercial HVAC
6
The commercial HVAC demand response program also combines
7
elements of energy efficiency through optimization with direct load
8
control. ADM used eQuest simulations to model the event-day impacts
9
and to generate hourly energy usage curves that could be converted to
10
energy savings curves through normalization.
11
program’s customer agreement form to identify programmatically
12
determined limitations on space temperature ranges and event-durations in
13
order to simulate demand response events. Per program design, the space
14
temperature range is to remain between 68°F and 76°F with a maximum
15
one-hour temperature rise of 4°F. The expected strategy will involve “pre­
16
cooling” prior to the demand response event followed by a temporary
17
thermostat setback to achieve the desired usage reduction. ADM used
18
eight separate eQuest models to estimate the impacts. Four models (two
19
building types and two methods of regulating outside air flows to meet
20
indoor air quality requirements) were used to estimate baseline operation
21
characteristics, and four corresponding models had the thermostats altered
22
to simulate pre-cooling and setbacks for event days.
ADM reviewed the
23
24
The energy impacts were simulated by applying a relative savings to the
25
HVAC usages as determined by eQuest.
26
necessary because the specific energy savings opportunities and
Extrinsic calculations are
27
28
Baroiant - Direct
18
3DJHRI
1
optimization steps are not known at this time. However, ADM did vary
2
the relative savings as a function of total HVAC load, with the premise
3
that the savings opportunities are smaller on the hottest days. This reflects
4
ADM’s experience that much of the savings opportunities associated with
5
controls mechanisms ranging from variable frequency drives to simple
6
throttling or staging, occur at part-load conditions.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
7
8
Agricultural Irrigation Pivots
9
As with the HVAC-based demand response programs, the agricultural
10
pivot demand response program includes energy savings and demand
11
response components. Unlike the other two programs, space temperature
12
ranges and occupant comfort considerations do not pose limitations on
13
demand reduction potential. A pivot that is running can be turned off
14
remotely, so long as an equal amount of “makeup” irrigation occurs within
15
a reasonable amount of time.
16
impacts in excel by starting with hourly load research date from the IS-2
17
rate class, and zeroing out usages during event hours, but requiring that the
18
foregone pumping is fully compensated for within 24 hours, but during
19
off-peak times. Modeled in this fashion, the demand response events do
20
not achieve a net energy savings because overall pumped volume is the
21
same as before demand response.
ADM modeled the demand response
22
23
In addition to demand response capacity, energy savings are expected
24
through automated and optimized irrigation based on feedback from soil
25
monitoring and sensing technologies.
26
evaluation results are not available for the energy savings portion of this
At the present time, impact
27
28
Baroiant - Direct
19
3DJHRI
1
measure as implemented in Sierra service territory. However, there are
2
many studies available that focus on the water savings associated with
3
efficient irrigation practices. ADM estimated the potential energy savings
4
to be proportional to the potential water savings associated with improved
5
irrigation scheduling.
6
7
ADM modeled the energy savings to be proportional to (with a
8
proportionality constant of 10%4), and synchronous with, the pumping
9
energy usage.
Nevada Power Company
And Sierra Pacific Power Company
d/b/a NV Energy
10
11
18.
Q.
12
DOES
THIS
CONCLUDE
YOUR
PREPARED
DIRECT
TESTIMONY?
13
A.
Yes.
14
15
16
17
18
19
20
21
22
23
24
25
4
27
The 10% estimate is based on Figure 21 in the report “Sustaining California Agriculture in an Uncertain
Future”,
available
online
from
the
Pacific
Institute
(http://www.pacinst.org/wp­
content/uploads/2013/02/final6.pdf). In that figure it is estimated that irrigation scheduling can save 3.4
million acre-feet of irrigation water in CA, which amounts to about 10% water savings. The associated electric
energy savings would also be approximately 10%.
28
Baroiant - Direct
26
20
3DJHRI
Exhibit Baroiant-Direct-1
Page 1 of 1
STATEMENT OF QUALIFICATIONS
SASHA BAROIANT ADM ASSOCIATES, INC 3239 Ramos Circle
Sacramento, CA 95826
(916) 363-8383
Education
Bachelor of Science in Physics, University of California, Davis 1999
Ph.D. in Experimental High Energy Physics, University of California, Davis 2006
Professional Experience
2007 To Date
Director
ADM Associates, Inc.
Responsible for measurement, verification, and evaluation of Demand Side Management (DSM)
programs and DSM portfolios. Responsible for DSM portfolio development and modeling
including technical, market, and financial analyses. Responsible for modeling and simulation
services – particularly associated with development of energy savings profiles. Responsible for
evaluations of emerging technologies and evaluations that require advanced measurement
techniques and associated uncertainty analysis.
1999 through 2000
Post Graduate Researcher
Physics, Dept. UC Davis
Responsibilities in detector hardware development included prototyping, characterization, and
optimization of silicon detectors used to track relativistic charged particles in a high radiation
environment. Responsibilities in detector software development included development of data
acquisition software to parse hexadecimal output of silicon readout chips used in the CDF SVXII
silicon tracking detector at Fermi National Accelerator Laboratory.
Awards and Honors
Research Fellowship, UCD Physics Dept., 2005
UC Davis Regents Scholarship 1995-1999
3DJHRI
3DJHRI
HOSSEIN HAERI
3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
3
Sierra Pacific Power Company d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13-_____
4
PREPARED DIRECT TESTIMONY OF
5
Hossein Haeri
6
7
1.
Q.
BUSINESS ADDRESS.
8
A.
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
PLEASE STATE YOUR NAME, JOB TITLE, EMPLOYER AND
My Name is Hossein Haeri. I am an Executive Director at The Cadmus
10
Group, Inc. (Cadmus), an energy and environmental consulting firm. My
11
business address is 720 SW Washington Street, Suite 400, Portland,
12
Oregon 97205. I am filing testimony on behalf of Sierra Pacific Power
13
Company d/b/a NV Energy (“Sierra” or the “Company”) and Nevada
14
Power Company d/b/a NV Energy (“Nevada Power” and, together with
15
Sierra, the “Companies”).
16
17
2.
Q.
AND EXPERIENCE.
18
19
PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND
A.
I have worked in the energy utility industry for 25 years, in various
20
capacities including as a researcher, consultant, teacher, and utility
21
manager. I have provided technical advice and planning consultation to
22
energy utilities on matters related to resource planning, load forecasting,
23
load research, market assessment, energy efficiency, demand response,
24
portfolio assessment, performance measurement, and cost-effectiveness
25
analysis. I supervised the design and development of Cadmus’ Portfolio
26
Pro model, the tool currently used by the Companies to calculate and
27
28
Haeri – Direct
1
3DJHRI
1
report cost-effectiveness of their energy-efficiency and conservation
2
programs.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
3
4
Before joining Cadmus in 2003, I was vice president for consulting at
5
KEMA Consulting.
6
Systems, responsible for measurement and verification at Chevron Energy
7
Solutions (formerly PG&E Energy Services) from 1997 to 2000. Prior to
8
that, I served as a principal in the consulting firm of Barakat &
9
Chamberlin, where I led the firm’s impact evaluation and assessment
10
practice area. I also worked for four years as Manager of Planning and
11
Assessment for Central Maine Power Company, where I was responsible
12
for planning and evaluation of the company’s demand-side management
13
(“DSM”) programs and co-chaired the Maine Collaborative, representing
14
the state’s investor-owned utilities. I was also the manager of Western
15
Operations for ERC International, where I was responsible for utility DSM
16
program evaluations. I was also an adjunct assistant professor at Portland
17
State University from 2000 to 2005, where I co-founded the graduate
18
program in Applied Energy Economics and taught courses in energy
19
planning and regulation.
I served as the director of Energy Information
20
21
I hold a doctorate degree in regional science. The results of my research
22
have been published in various conference proceedings and refereed
23
journals, including Policy Studies Journal, The Energy Journal and Public
24
Utilities Fortnightly.
25
26
27
28
Haeri – Direct
2
3DJHRI
1
3.
Q.
YOU
PREVIOUSLY
TESTIFIED
BEFORE
THIS
COMMISSION?
2
A.
3
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
HAVE
I have.
I provided testimony in the Companies’ 2011 Annual DSM
4
Update Reports, Docket Nos. 11-07026 and 11-07027, regarding an
5
approach and methodology for calculating the impact on rates of utility
6
investments in energy efficiency and conservation including a recommend
7
a process for applying the methodology to estimate the potential rate
8
impacts likely to result from the implementation of energy efficiency and
9
conservation programs.
In Sierra’s 2012 Annual Demand Side
10
Management Update Report and Nevada Power’s 2012 Integrated
11
Resource Plan, Docket Nos. 12-06052 and 12-06053, I applied this
12
method to estimate the rate and customer bill impacts of the proposed
13
plans.
14
15
4.
Q.
WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
PROCEEDING?
16
A. 17
The purpose of my testimony is to provide the results of Cadmus’
18
assessment of the likely effect on rates and customer bills from Sierra’s
19
implementation of its 2014-2016 Demand Side Plan (“DSM Plan”). In
20
addition, my testimony supplements the direct testimony of Ms. Anita
21
Hart and to provide additional information on and to answer questions
22
regarding NV Energy’s assessment of fuel diversity and related risks of
23
alternative electric resource portfolios.
24
25
5.
Q.
ARE YOU PRESENTING ANY EXHIBITS AS PART OF YOUR
TESTIMONY?
26
27
28
Haeri – Direct
3
3DJHRI
A. 1
Yes, my testimony is accompanied two exhibits:
2
Exhibit Haeri-Direct-1: Statement of Qualifications
3
Exhibit Haeri-Direct-2: Description of the rate and bill impact assessment
4
tool (“the tool”).
5
6
6.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
Q.
HOW IS YOUR TESTIMONY ORGANIZED?
A.
My testimony is organized in two parts as follows: (1) overview of the
8
methods and assumptions for analyzing the rate and bill impacts of
9
Sierra’s Plan; and (2) the report of the results of that analysis.
The
10
conceptual foundations and methodologies for calculating the rate and bill
11
impacts were described in detail in my previous testimony in these
12
proceedings (Hossein Haeri, Direct, Docket No. 12-06053, pp. 4-7). A
13
description of the software tool used in the analysis is provided in Exhibit
14
Haeri-Direct-2.
15
16
7.
Q.
OF SIERRA’S 2014-2016 PLAN WERE CALCULATED.
17
18
PLEASE DESCRIBE HOW THE POTENTIAL RATE IMPACTS
A.
The annual rate impacts of Sierra’s planned 2014-2016 demand-side
19
programs were assessed over 10 years from 2014 through 2023. The
20
analysis involved four steps as described below.
21
1- Base Year was set to 2013, which roughly corresponds with the test
22
year used in Sierra’s 2013 general rate case application. Base-year
23
revenue requirement for each customer class (residential and
24
nonresidential) was then calculated by dividing actual revenues by
25
retail sales to that class. Consistent with basic rate calculations, the
26
27
28
Haeri – Direct
4
3DJHRI
1
average revenue requirement for each class consisted of the following
2
components:
3
a. Base Tariff General Rate (“BTGR”) – The fixed component of
4
the rate, representing the cost of utility operation less energy
5
production, per kWh.
6
b. Base Tariff Energy Rate (“BTER”) – The cost of energy
7
production per kWh, representing the variable rate component,
8
inclusive of capacity costs.
c. Energy Efficiency Program Rate (“EEPR”), reflecting demand-
9
side expenditures.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
d. Energy Efficiency Implementation Rate (“EEIR”), the lost
11
revenue recovery component of the rate for each class.
12
13
Both BTER and BTGR are assumed constant over the course of the
14
planning period.1
15
Energy Development Charge (“TRED”), Renewable Energy Program
16
Rate (“REPR”), and Universal Energy Credit (“UEC”) are assumed to
17
be unaffected by demand-side activity.
Other rate components, Temporary Renewable
2- Demand-Side Expenditures: Planned 2014-2016 expenditures on
18
energy efficiency, reported in Sierra’s Plan.2
19
20
3- Demand-Side Savings: Projected net energy (kWh) and peak demand
21
(kW) savings for energy efficiency and demand response programs,
22
reported in the Plan.
23
implementation of the Plan are expected to persist for a period equal to
The energy and demand savings from
24
25
26
1
27
Please note that applying an escalation factor to these rate components would offset the relative impact of
demand-side activity, particularly energy efficiency.
2
See DSM Plan Narrative
28
Haeri – Direct
5
3DJHRI
1
the expected life of the measures offered by the Plan - or the weighted
2
average measure life for programs that consist of multiple measures.
3
4- Avoided Power Supply Costs: Projected total monetary value of
4
energy
and
capacity
savings
5
implementation of the Plan.
expected
to
result
from
the
6
7
8.
Q.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
DESCRIBE
HOW
THE
BILL
IMPACTS
ARE
CALCULATED.
8
9
PLEASE
A.
Demand-side programs affect customers in particular rate classes
10
differently, depending on whether they participate in a demand-side
11
program. For nonparticipants, bill impacts arise as a direct result of the
12
impacts of demand-side programs on rates. Depending on the trend in
13
rates after the implementation of demand-side programs, nonparticipants’
14
bills may be higher or lower than they would have been in the absence of
15
demand-side programs. If demand-side programs lead to an increase in
16
rates, then nonparticipants will experience a proportional increase in their
17
bills for the same level of consumption.
18
19
The change in average rate will also affect participants’ bills. Participants,
20
however, will experience a change in their bills from the lower
21
consumption caused by the adoption of energy-efficiency measures
22
offered through a demand-side program. As a result of these savings,
23
participants’ bills will almost always be lower, even in circumstances
24
where demand-side programs lead to an increase in the average rate.
25
26
27
28
Haeri – Direct
6
3DJHRI
1
9.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
2
Q.
PLEASE EXPLAIN HOW THIS METHOD WAS IMPLEMENTED.
A.
Cadmus developed a spreadsheet tool based on MS Excel for making the
3
necessary calculations to implement the approach, and customized it to
4
appropriately represent the unique rate and lost revenue recovery
5
calculations used by Sierra.
6
underlying methods to the Commission’s Regulatory Operations Staff
7
(“Staff”) and Bureau of Consumer Protection (“BCP”) on September 30,
8
2011 and solicited their feedback.
9
application of the approach were reviewed with the Staff and BCP on
10
April 5, 2012 and again on April 30, 2012. A description of the tool is
11
provided in Exhibit Haeri-Direct-2.
Cadmus demonstrated the tool and its
The preliminary results from the
12
13
10.
Q.
WHAT WERE THE RESULTS OF YOUR ANALYSIS WITH
14
RESPECT TO THE RATE IMPACTS OF THE 2014-2016 DSM
15
PROGRAMS PLANNED BY SIERRA?
16
A.
Sierra’s Plan includes three plans, a Preferred Plan and, the Minimum
17
Impact Plan and the Maximum Net Benefits Plan. Each plan is designed
18
to address Sierra’s different load objective as described by the Demand-
19
Side Plan Narrative and by witness Lawrence Holmes.
20
21
The three plans are distinguished primarily in terms of the planned
22
investment in demand side, as shown in Table 1.
23
24
25
26
27
28
Haeri – Direct
7
3DJHRI
Table 1 Planned Demand Side Expenditures by Year and Customer Class
(2014-2016)
1
2
Plan
Year
Residential
Nonresidential
Preferred
2014
$2,845,394
$7,264,606
Plan
2015
$3,685,394
$7,744,606
2016
$4,485,394
$8,794,606
3
4
5
6
7
Maximum
2014
$3,662,875
$10,807,125
8
Net Benefit
2015
$5,857,875
$12,777,125
2016
$8,457,875
$15,677,125
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
Minimum
2014
$703,740
$6,096,260
11
Impact
2015
$753,740
$6,546,260
2016
$803,740
$7,196,260
12
13
14
15
11.
Q.
16
WHAT WERE THE RESULTS OF YOUR ANALYSIS WITH
RESPECT TO THE RATE IMPACTS OF THE PLAN?
17
A. Under the Preferred Plan, Sierra proposes to invest $34.82 million in
18
energy efficiency programs over the 2014-2016 planning period as shown
19
in Table 1.3
20
expenditures, which will be recovered through rates within three years
21
after the implementation of the Plan. $11.6 million accounts for demand
22
response expenditures. The remainder $1.05 million will be spent on
Energy efficiency accounts for $22.17 million of the
23
24
25
3
27
The $34.82 million differs from the Preferred DSM Plan budget shown in Table DS-1 of the DSM Narrative
because it excludes the Legacy costs for the Demand Response Program. The Legacy costs are the
maintenance costs and the incentives for the demand response devices installed prior to 2014. The Legacy
costs were included in the rate impact assessments that were performed for prior program year.
28
Haeri – Direct
26
8
3DJHRI
1
Energy Education and Market and Technology trials that will not be
2
claiming energy savings
3
4
The planned demand side investments are projected to produce nearly
5
966,171 MWh of cumulative savings over the life of installed measures
6
and an average 32.24 MW of annual demand savings. The cumulative
7
avoided energy and capacity benefits of the planned programs under the
8
Preferred Plan are estimated in at nearly $50.25 million between 2013 and
9
2030 (Table 2).4
Table 2
Cumulative Capacity and Energy Benefits (NPV) 2014-2023
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
Plan
12
Preferred Plan
Energy
Capacity
$ 10,900,358
$ 50,244,800
13
Minimum Impact
$ 1,720,177
$ 39,847,472
14
Maximum Benefit
$ 20,287,421
$ 86,664,361
15
16
The results of Cadmus’s analysis indicate that implementation of the
17
Preferred Plan will likely raise the average rate for Sierra’s residential
18
customers by 0.497 percent and increase nonresidential rates by 0.405
19
percent per year on average over the 10-year analysis period. Rates for
20
both residential and nonresidential customers are also projected to be
21
higher under the Maximum Net Benefits Plan. The Minimum Impact Plan
22
residential rates are expected to be slightly lower and nonresidential rates
23
will increase (Table 3).
24
25
4
27
The avoided capacity cost benefits of the Plan include estimated transmission and distribution benefits of
under $12 per kW. This figure is significantly lower than the $31 per kW to as much as $132 per kW reported
by other national utilities. (See Best Practices in Energy Efficiency Program Screening, Synapse Energy
Economic, Inc., July 23, 2012, p.26.) An upward adjustment to transmission and distribution costs will
increase the benefits of the Plan proportionately.
28
Haeri – Direct
26
9
3DJHRI
1
2
Table 3 Projected Average Rate Impacts by Customer Class and Scenario
(2014-2023)
3
Plan
Residential
Nonresidential
Preferred Plan
0.497%
0.405%
6
Minimum Impact
-0.030%
0.357%
7
Maximum Net
8
Benefits
0.593%
0.716%
4
5
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
In the residential sector, rates will rise after the implementation of each of
11
the plans to allow Sierra to recover the 2014-2016 expenditures on energy
12
efficiency during through the EEPR mechanism. Similarly, there will be
13
an increase in the EEIR component of the rate, reflecting the recovery of
14
lost revenues. Other rate components, namely BTGR and BTER, are
15
expected to be lower after 2019. Changes in various components of the
16
rate for Sierra’s residential sector for the Preferred Plan are shown in
17
Figure 1 for demonstration.
18
19
20
21
22
23
24
25
26
27
28
Haeri – Direct
10
3DJHRI
Figure 1
Projected Change in Residential Rate Components
Preferred Plan (2014-2023) 1
2
3
4
5
6
7
8
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
12
13
14
15
It is important to note that this analysis has assumed both BTGR and
16
BTER remain constant at the nominal 2014 value.
17
18
12.
Q.
DEMAND-SIDE PLAN ON CUSTOMERS BILLS?
19
20
WHAT ARE THE PROJECTED IMPACTS OF THE 2014
A.
The bill impacts resulting from the implementation of the Preferred Plan
21
are expected to lower the aggregate annual bills for Sierra’s residential and
22
nonresidential customers by nearly $634,325 and $4,979,519 respectively
23
on average (Table 4). Both the Maximum Benefits plan and the Minimum
24
Impact plan also are expected to lower aggregate annual bills. Under the
25
Maximum Net Benefits Plan bills will be reduced by $1,262,285 for the
26
residential class and $9,129,843 for the nonresidential class.
The
27
28
Haeri – Direct
11
3DJHRI
1
Minimum Rate Impact Plan average annual bill savings will be $179,780
2
for the residential class and $3,865,472 for the nonresidential class (Table
3
4). The distribution of average annual bill impacts between participants
4
and nonparticipants are reported in Table 5 and Table 6 respectively.
5
6
7
Table 4 Projected Average Annual Change in Aggregate Bill by Customer Class For All Customers 8
Plan
9
Residential
Nonresidential
Preferred Plan
$
(634,325)
$ (4,979,519)
11
Maximum Net Benefits
$ (1,262,285)
$ (9,129,843)
12
Minimum Impact
$
$ (3,865,472)
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
(179,780)
13
14
15
Table 5 Projected Average Annual Change in Aggregate Bill by Customer Class For Participants for the Preferred Plan
16
Scenario
17
Residential
Nonresidential
18
Preferred Plan
$ (2,036,547)
$ (7,746,484)
19
Maximum Net Benefit
$ (2,899,726)
$ (14,023,623)
20
Minimum Impact
$
$
(78,239)
(6,344,922)
21
22
23
24
25
26
27
28
Haeri – Direct
12
3DJHRI
1
Table 6 Projected Average Annual Change in Aggregate Bill by Customer Class For Nonparticipants for the Preferred Plan
2
3
Scenario
4
5
Residential
Nonresidential
Preferred Plan
$ 1,402,222
$ 2,766,966
Maximum Net Benefit
$ 1,637,441
$ 4,893,780
6
7
8
Minimum Impact
$
(101,541)
$ 2,479,451
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
13.
Q.
THE 2013 PLAN ON CUSTOMERS BILLS?
12
13
WHAT ARE THE PROJECTED CUMMULATIVE IMPACTS OF
A.
The net present value of the cumulative bill impacts for participants
14
resulting from implementation of Sierra’s Preferred Plan are estimated at
15
approximately $54.5 million, $126.4 million for the Maximum Net
16
Benefits Plan and $44.7 million for the for the Minimum Impact Plan
17
over the planning period (Table 7). The annual bills are expected to be
18
higher for nonparticipants on average, as shown in Table 6, and in net
19
present value under all three plan scenarios (Table 7). The reason for this
20
is that nonparticipants would pay higher rates in the first few years of the
21
Plan’s as implementation and lost-revenue expenses are recovered.
22
23
24
25
26
27
28
Haeri – Direct
13
3DJHRI
Table 7 Cumulative Bill Impacts (NPV) by Program Plan for Participant and Nonparticipants
2014-2023 1
2
3
4
Scenario
5
Preferred Plan
6
7
Participants
Nonparticipants
$ (54,504,105)
$ 36,798,909
Maximum Net Benefit
$ (126,428,321)
$ 58,280,686
Minimum Rate Impact
$ (44,669,567)
$ 21,706,521
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
Bill impacts will be different for participants, depending on characteristics
11
of the measures such as cost, savings, and life.
12
13
14.
Q.
WHAT ARE THE LIMITATIONS OF THE METHOD YOU HAVE
DESCRIBED AND HOW SHOULD THE TOOL BE USED?
14
A.
15
The rate and bill impacts reported here are based on a number of specific
16
assumptions about Nevada Energy’s future load, avoided costs, level of
17
demand-side activity, expected participation rates, and trends in the fixed
18
cost-rate components. Clearly, changes in these assumptions will alter the
19
results of this analysis. The Cadmus tool provides a robust and flexible
20
means of evaluating alternative investment scenarios and program options,
21
rather than calculating actual future rates and bills.
22
23
15.
Q.
PLEASE PROVIDE AN OVERVIEW OF THE FUEL DIVERSITY
CADMUS CONDUCTED FOR NV ENERGY?
24
25
A. Cadmus conducted a thorough review of financial literature and
26
interviewed planning staff at other utilities to explore alternative methods
27
and current practices in electric resource portfolio screening and risk.
28
Haeri – Direct
14
3DJHRI
1
Based on this information, Cadmus developed a methodology for
2
evaluating the benefits, costs and risks of alternative fuel mixes within a
3
resource portfolio and tested this methodology on several future scenarios
4
concerning NV Energy energy’s current generation mix and future load
5
requirements.
6
7
16.
8
Q.
WHAT WAS YOUR ROLE IN THIS ASSESSMENT?
A.
I supervised the technical assessment and preparation of the final report,
by Cadmus’ staff.
9
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
10
11
12
17.
Q.
DOES THIS CONCLUDE YOUR TESTIMONY?
A.
Yes, it does.
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Haeri – Direct
15
3DJHRI
Exhibit Haeri Direct-1
Page 1 of 2
Hossein Haeri, Ph.D., Executive Director
Education and Certifications
Ph.D., Regional Science, Portland State University
B.A., Quantitative Social Research, University of Oregon
Professional Experience and Qualifications
Hossein Haeri, an Executive Director at The Cadmus Group, Inc., has more than 25 years of experience in
research, consulting, utility management and teaching in the energy utility industry. Working in Cadmus’
Energy Services team, Dr. Haeri specializes in utility strategic planning, integrated resource assessment and
portfolio analysis, demand response planning and market assessment, and performance measurement.
Before joining Cadmus, Dr. Haeri was the director of Energy Information Systems at Chevron Energy
Solutions (formerly PG&E Energy Services), where he led a team of engineers and IT professionals to
design and develop the remote monitoring and control systems to support the company’s performance
contracts. He was a principal at the consulting firm of Barakat and Chamberlin and managed demand-side
planning and assessment at Central Maine Power.
Examples of Relevant Experience
Demand Side Management (DSM) Resource Assessment
Dr. Haeri is a nationally recognized expert in energy efficiency and load management resource assessment,
planning and impact evaluation. . His work has encompassed all aspects of assessing technical, economic
and achievable potentials, including innovative approaches to determining market potentials. He has led, or
been the key technical advisor on, numerous market studies of electric and natural gas efficiency, demand
response, distributed generation (including renewable energy), and fuel conversion for investor-owned and
public utilities throughout the United States, including Bonneville Power Administration, Black Hills
Energy, Mid American Energy, Alliant Energy, Puget Sound Energy, Portland General Electric, Great Rive
Energy, Rocky Mountain Power, Pacific Power, Seattle City Light, and Snohomish County PUD
Integrated Resource Planning and Forecasting
Dr. Haeri’s work has addressed both theoretical and practical aspects of modeling demand-side management
potentials in the IRP process. He is familiar with the various IRP models used by utilities, such as portfoliobased and capacity expansion models. Dr. Haeri typically works with utility clients to develop overall
strategies for resource planning and on the mechanics of incorporating DSM resources in the IRP process.
Resource Portfolio Planning and Assessment
Dr. Haeri has worked closely with utilities in various jurisdictions having energy-efficiency resource
standards (EERS), helping them formulate effective strategies to meet their targets. Numerous energy
utilities have engaged him to translate the results of DSM market studies into effective and successful
programs, and to develop portfolios of DSM products and services with associated targets, budgets and
The Cadmus Group, Inc.: Energy Services
Portland Office: 720 Washington Street, Suite 400, Portland, OR 97205 / 503-228-2992
3DJHRI
Exhibit Haeri Direct-1
Page 2 of 2
Hossein Haeri, Ph.D.
implementation, evaluation plans. His efforts include providing the necessary public process and regulatory
support to gain approval for these plans.
Dr. Haeri has also worked with stakeholder groups to create optimal outcomes for his clients in a number of
states, and he has worked with regulators on behalf of utilities in several jurisdictions including Maine, Iowa,
New York, Nevada, Oregon, Utah, and Washington.
In addition, Dr. Haeri has worked extensively on the development of cost-effective tools for program
planning and portfolio assessment. He was the architect and lead developer of DSM Portfolio Pro,
Cadmus’s tool for DSM portfolio planning and risk assessment; DR Pro, an analytic tool for assessing the
market potentials and costs for demand response strategies; and the DSM Planner, an Excel-based model
for long-term planning and budgeting of DSM portfolios.
Evaluation, Measurement and Verification
Dr. Haeri brings more than 20 years of experience to projects involving measurement, verification, and
quantitative methods for determining the gross and net impacts of energy efficiency and demand response
programs. He has led impact evaluation projects involving sample design, primary data collection and
engineering and statistical assessment of load impacts.
Dr. Haeri is currently leading the evaluations of the Industrial Sector Initiative for the Northwest Energy
Efficiency Alliance, BC Hydro’s Power Smart Partners Program, and Southern California Edison’s Peak
Plus demand response initiative.
Recent Publications and Presentations
Dr. Haeri has authored many technical reports and papers published in refereed journals such as The
Energy Journal, Public Policy Journal and the Utilities Fortnightly. His recent presentations, conference
papers, and publications include:
x
“Extreme Efficiency: Performance Standards are a Valid Idea if Targets are Achievable,” Public
Utility Fortnightly, September 2010.
x
“Energy efficiency in New York: Balancing the Risks and Opportunities,” Public Utilities
Fortnightly, January 2010.
x
“Using Experimental Design to Assess the Impacts of Education and Rate Design: The PEAK Plus
Pilot Project,” Proceedings, International Energy Program Evaluation Conference, Portland, August
2009.
x
“Technical and Economic Feasibility of Direct Irrigation Load Control in the Northwest,” Peak
Load Management Alliance Conference, Austin, Texas, October 2008.
x
“Do Stock Prices Reflect Operational Efficiency?” With Matei Perussi and M. Sami Khawaja, Public
Utilities Fortnightly, February 1999.
x
“The Fortnightly 100, Which Utility Ranks the Highest?” With Janice Forrester and Michael Carter,
Public Utilities Fortnightly, September 1997.
The Cadmus Group, Inc.: Energy Services Division
Portland Office: 720 Washington Street, Suite 400, Portland, OR 97205 / 503-228-2992
3DJHRI
Exhibit Haeri-Direct-2
Page 1 of 2
Description of the Rate Impact Model
The Rate Impact Model (the Model) is structured as an MS Excel workbook. The workbook
contains ten separate worksheets (tabs). All formulas and calculations are clearly defined in
each worksheet. The function and content of each of the 10 worksheets is described below.
1. Index
- This tab outlines the contents of all other worksheets.
2. Assumptions tab:
- Lists financial assumptions used in the calculation of rate impacts by utility and
sector. This tab also allows for allocation of avoided costs in terms of market
purchase or capacity construction. For the purpose of current calculations, all
marginal load requirements are assumed to be met through market purchases. This
tab also allows changing the utility and sector for calculations.
3. Rate Impact Analysis tab:
- Baseline rate calculations table uses the forecast kWh sales from the consumption
data tab and multiplies the average rate per kWh (the sum of BTGR, BTER, and
other rate components) to get the base revenue requirement and baseline average rate
per kWh.
- DSM outcomes table calculates net cumulative savings, avoided energy costs and
capacity costs, DSM expenditures, and the new forecast sales from the Portfolio Pro
output tab by utility by sector.
- The DSM rate calculations table calculates the new BTGR, BTER, avoided capacity,
and other rate components per kWh using the new forecast sales from the DSM
outcomes table, all of which are based on the three-year rate cases.
- The DSM rate calculations table also calculates the following:
a. The EEPR is the DSM expenditures per kWh from the new sales forecast
and the EEIR is the lost revenue per kWh from the new sales forecast.
b. The average rate per kWh is the sum of the new BTGR, BTER, avoided
capacity, other rate components, EEIR, and EEPR.
c. Percent change from the baseline is the percent change from the baseline
average rate per kWh and the new, after taking DSM into account.
- This tab also graphs the change in EEPR, EEIR, total rate change, average rate
change, and the combined change in BTGR, BTER, and capacity.
3DJHRI
Exhibit Haeri-Direct-2
Page 2 of 2
4. Lost Revenue tab:
- Shows the calculation of annual lost revenue
- Shows allocation of annual lost revenue to monthly recovery figures and allows for
the application of a carrying charge (currently set to zero).
5. Bill Impact Analysis tab:
- Calculates impacts to bills showing the baseline scenario and the adjustments for lost
revenue recovery. For the residential sector, bill impacts may be calculated in terms
of average residential customer (column I).
6. Portfolio Pro Output tab:
- Portfolio Pro outputs consistent with 2012 plan EEP filing period. It lists forecast
EE expenditures, savings, and energy and demand benefits by utility by sector.
7. Common Costs tab:
- Shows costs by utility that are not attributable to either residential or nonresidential
rate classes. The common costs are allocated based on the G&E allocator in the
Rates Component tab.
8. Customer Data tab:
- The forecast number of customers by utility by class.
9. Consumption Data (kWh) tab:
- Consumption data is kWh forecast provided by Nevada Power by class.
10. Rate Components tab calculates the following:
- The sum of 2012 savings forecast by utility by class
- BTGR (per kWh BTGR energy and demand revenue requirement by customer class).
- EEIR (net of demand implementation rate and non-recoverable operation and
maintenance (VOM)).
- BTER (per unit energy revenue requirement by class)
- Other rate components (customer charge and specific facilities over kWh by class)
- Total revenues is the sum of rate components multiplied by kWh sales
- Monthly distribution of revenue recovery funds by utility and sector.
3DJHRI
3DJHRI
JEFFREY R. BOHRMAN 3DJHRI
1
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2
Sierra Pacific Power Company
d/b/a NV Energy
2014 – 2033 Integrated Resource Plan
Docket No. 13­
3
4
PREPARED DIRECT TESTIMONY OF
5
Jeffrey R. Bohrman
6
7
1.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
8
Q.
PLEASE STATE YOUR NAME, TITLE, AND BUSINESS ADDRESS.
A. My name is Jeffrey R. Bohrman. I am a Staff Analyst in the Regulatory Pricing
9
and Economic Analysis section of the Rates and Regulatory Affairs Department
10
for Sierra Pacific Power Company (“SPPC”, "Sierra” or the “Company”) and
11
Nevada Power Company (“NPC” or “Nevada Power”) d/b/a NV Energy (“NV
12
Energy”). My primary business address is 6100 Neil Road, Reno, Nevada. I am
13
filing testimony on behalf of Sierra.
14
15
2.
Q.
DOES EXHIBIT BOHRMAN DIRECT-1 ACCURATELY DESCRIBE
16
YOUR
17
EXPERIENCE?
18
EDUCATIONAL
A. Yes, it does.
Q.
WHAT
BACKGROUND
AND
PROFESSIONAL
19
20
3.
21
22
IS
THE
PURPOSE
OF
YOUR
TESTIMONY
IN
THIS
PROCEEDING?
A.
I am sponsoring the technical aspects of the Energy Efficiency and Conservation
23
(“EE&C”) lost revenue requirement calculations presented in this docket. My
24
testimony both relies on and supports the testimony of other witnesses. Kelly
25
Vagianos is sponsoring the net energy savings resulting from the Company’s
26
EE&C programs that I relied upon for the calculation of lost revenues.
27
28
Bohrman-DIRECT
1
3DJHRI
1
4.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
2
Q.
PLEASE PROVIDE AN OVERVIEW OF YOUR TESTIMONY.
A. My testimony encompasses the calculation of lost revenue resulting from the
3
Company’s EE&C programs for the three year period covered in this docket,
4
2014 through 2016. For each program, and then in summary for all programs
5
offered by the Company that result in lost sales, I present the lost revenue
6
resulting from each program’s full year and cumulative savings.
7
calculations are based on the EE&C savings discussed in detail in the direct filed
8
testimony of Ms. Vagianos.
9
calculations are reflected in the exhibits attached to this testimony and embedded
10
These
Program-specific lost revenue requirement
in tables DS-17 and DS-18 of the DSM narrative.
11
12
13
5.
Q.
PLEASE DESCRIBE YOUR TESTIMONY EXHIBITS.
A. I sponsor the following exhibits to my testimony:
14
�
Exhibit Bohrman Direct-1, the qualifications of the witness;
15
�
Exhibit Bohrman Direct-2, the program-specific cumulative lost revenue
16
17
requirement for the years 2014 - 2016;
�
18
19
Exhibit Bohrman Direct-3, the program-specific full year lost revenue
requirement for the years 2014 - 2016; and
�
Exhibit Bohrman Direct-4, the summary of cumulative and full year
20
program-specific minimum lost demand revenue for the years 2014 ­
21
2016.
22
23
The filing includes workpapers used to develop the numbers shown in Exhibits
24
Bohrman Direct-2, 3 and 4 in Technical Appendix DSM-3.
25
26
27
28
Bohrman-DIRECT
2
3DJHRI
1
6.
Q.
PLEASE PROVIDE AN OVERVIEW AS TO WHY LOST REVENUE IS
2
BEING PRESENTED IN THIS INTEGRATED RESOURCE PLAN
3
FILING.
4
A.
In the order in Docket No. 10-10024, (page 69, paragraph 10), the Commission
5
directed the Companies to prepare and file a calculation of expected lost revenue
6
for the 2012 portfolio in both of the Companies’ Annual DSM Update filings:
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
7
8
Nevada Power Company d/b/a NV Energy and Sierra Pacific Power
9
Company d/b/a NV Energy shall provide a calculation of expected lost
10
revenues that will be generated from the entire 2012 portfolio, broken
11
down by individual programs on or before in their next respective
12
Annual Demand Side Management Update.
13
14
The Company provided the requested calculations, which the Commission
15
recognized complied with its prior order (Paragraph 10, page 6, Docket No. 11­
16
07027). For the purpose of providing the Commission with a basis for evaluating
17
the preferred suite of EE&C programs, the Companies have continued to provide
18
estimates of expected lost revenue that will be generated by the proposed EE&C
19
program portfolio, broken down to the individual program level. Thus we are
20
providing calculations of lost revenue resulting from the Company’s EE&C
21
programs for the three year period covered in this docket, 2014 through 2016.
22
Exhibit Bohrman Direct-2 summarizes the estimated lost revenue, by class and
23
year, based on the cumulative savings found in Technical Appendix DSM-3,
24
while Exhibit Bohrman Direct-3 shows the same information based upon the
25
Full Year savings.
26
27
28
Bohrman-DIRECT
3
3DJHRI
1
7.
Q.
2
HAVE THERE BEEN ANY CHANGES IN THE LOST REVENUE
CALCULATIONS FROM THE PREVIOUSLY FILED METHODOLOGY?
3
A.
No, the same methodology for calculating lost revenue resulting from energy and
4
demand savings which was proposed in the Annual DEAA and Energy Efficiency
5
base and amortization rate filings in March 2013 (Docket Nos. 13-03003 and 13­
6
03004 for NPC and Sierra, respectively) was utilized in these calculations.
7
8
8.
Q.
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
HOW ARE THE DEMAND SAVINGS AND RESULTING LOST
REVENUE CALCULATED?
A.
As stated above, the methodology used in determining lost demand sales and the
11
resulting lost demand revenue is consistent with the proposal in the March 2013
12
filing.
13
Associates, Inc. (“ADM”), the Measurement and Verification (“M&V”)
14
contractor, on an annual basis. To be consistent with the March 2013 filing, we
15
used the 2011 program year savings shapes provided by ADM, which reflect the
16
most current year previously provided to the Commission for review. These 2011
17
program savings shapes were then adjusted for the approved net-to-gross rates.
18
The net savings are summarized by class and time-of-use (“TOU”) period and
19
applied on an annual basis to the forecast savings for the years in question, in this
20
case 2014 through 2016.
An hourly program-specific savings shape is developed by ADM
21
22
As it is not possible to determine the exact amount of lost demand sales during
23
each TOU period during the year, our analysis is based on the minimum demand
24
savings which is the currently approved methodology. This minimum demand
25
savings is then applied to the approved applicable demand charge for that TOU
26
period and timeframe consistent with the savings, resulting in the lost revenue
27
28
Bohrman-DIRECT
4
3DJHRI
1
requirement related to lost demand sales. Exhibit Bohrman Direct-4 shows the
2
resulting lost demand revenue amounts by program and TOU period.
3
4
9.
Q.
5
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
6
ARE THERE ANY EXCEPTIONS TO THE LOST DEMAND REVENUE
CALCULATION METHODOLOGY?
A.
Yes, there are two instances where the basic ratio methodology described above is
7
not sufficient. First, the Non-Profit Grant program is expected to result in a
8
relatively small amount of savings (20,430, 38,698, and 56,966 cumulative kWh
9
in 2014, 2015 and 2016, respectively) in the GS-3 class according to the
10
workpapers provided in Technical Appendix DSM-3. This program did not have
11
any GS-3 participants in 2011, and as a result no kWh savings in the measured
12
and verified 2011 program year. From a commercial class perspective this is a
13
small program, and the measures are not expected to differ significantly, if at all,
14
between the GS-2 and GS-3 classes. Therefore, the GS-2 savings shape was
15
applied to the GS-3 class.
16
17
Second, the Commercial Retrofit program had minimal M&V kWh savings for
18
the OGS-2-TOU class in the 2011 M&V report. The program forecast shows
19
savings of 558,578, 685,607, and 812,635 cumulative kWh in 2014, 2015 and
20
2016, respectively, according to the DSM-3 savings workpapers. Unlike the Non-
21
Profit Grant program discussed above, the Commercial Retrofit program provides
22
multiple customer class options for use as a proxy savings shape. In this case,
23
after reviewing the class load factors and relative characteristics of the options, I
24
determined that the best fit was the GS-2 class which is the otherwise applicable
25
class for participants who do not opt for the TOU rate structure alternative.
26
27
28
Bohrman-DIRECT
5
3DJHRI
1
Therefore, the 2011 GS-2 class savings shape was used to shape the 2014 through
2
2016 OGS-2-TOU savings.
3
4
The net result of the calculations described above provides a sound and
5
reasonable estimate of recoverable lost revenue resulting in both lost energy and
6
demand sales caused by the Company’s EE&C programs for the plan years of
7
2014 through 2016.
8
Nevada Power Company
and Sierra Pacific Power Company
d/b/a NV Energy
9
10
10.
Q.
DOES THIS COMPLETE YOUR TESTIMONY?
A.
Yes, it does.
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Bohrman-DIRECT
6
3DJHRI
Exhibit Bohrman Direct-1
Page 1 of 2
JEFF BOHRMAN
STAFF ANALYST
RATES & REGULATORY AFFAIRS
NV Energy
6100 Neil Road Reno, Nevada 89511-1137 (775) 834-3772
Mr. Bohrman has been an employee of Sierra Pacific Resources for eight years and his time at the
company is split between his previous position as a Senior Accountant in the Corporate Accounting
department and his current position within the Regulatory Pricing & Economic Analysis section of the
Rates & Regulatory Affairs department. His current responsibilities are focused upon electric cost of
service and rate design issues and supplementary studies in support of the Rate & Regulatory Affairs
department’s responsibilities.
Prior to joining the Company, Mr. Bohrman had experience primarily in the accounting field and was
most recently employed at Harmonic Inc, a technology company that designs and manufactures video
products and system solutions for broadcast and on-demand services, as a Senior Accountant.
Employment History
NV Energy
May 2005 to Present
Staff Analyst, Regulatory Pricing & Economic Analysis
Senior Analyst, Regulatory Pricing & Economic Analysis
September 2008 to Present
Conduct research and prepare studies for internal and external presentations
Compute bill comparisons and minimum bills for large customers of Sierra Pacific
and Nevada Power companies
Analyze data for filings in Nevada and California, Gas and Electric
Prepare or update Marginal Cost of Service and Customer Weighting Factor Studies
Coordinate with numerous departments to gather data for Marginal Cost of Service
and Customer Weighting Factor Cost Studies
Develop and update models for calculating lost revenue
Research and prepare responses to internal and external data requests
Ancillary support for Company filings and other Rate & Regulatory Affairs
department responsibilities
3DJHRI
Exhibit Bohrman Direct-1
Page 2 of 2
Senior Accountant, Corporate Accounting
May 2005 to September 2008
Primarily was responsible for the analysis of Operations and Maintenance expenses, as well as the analysis of the Company’s financial reports on a monthly, quarterly,
and annual basis
Prepared the quarterly and annual Earnings per Share calculation and footnote to the Company’s financial report
Prepared and analyzed multiple schedules and deliverables for the Company’s rate
case filings
Non-Sierra Employment
Harmonic Inc.
January 2000 to May 2005
Senior Accountant
General Ledger Accountant, responsible for the analysis and reconciliation of the
ledger along with the quarterly and annual external audit process
Fixed Asset Accountant, managed the tracking and accounting for the company’s
assets
Royalty Accountant, maintained and coordinated the company’s royalty agreements
Also was responsible for a number of other activities within the accounting and
finance departments
Prior Testimony before Public Utilities Commissions
PUCN Docket Nos.: 10-06001, 11-03003, 11-06006, 12-06052, 12-06053, 13-03003, 13-03004
Education
Santa Clara University
Master of Business Administration, December 2003
Humboldt State University
Bachelor of Science in Business Administration, June 1999
Continuing Education
NARUC Utility Rate School
NERA Estimation of Electricity Marginal Costs and Application to Pricing
Member of the Marginal Cost Working Group
Utility Finance and Accounting for Financial Professionals
3DJHRI
3DJHRI
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
$
$
Non-Profit Agency Grants
Residential Energy Efficient Lighting Program
Second Refrigerator Collection and Recycling
Commercial New Construction
Energy Smart Schools Program
Commercial Retrofit Incentives Program
Solar Thermal Water Heating
Demand Response
Home Energy Reports
Total Lost Revenue Requirement
Program
2,416,395 $
19,959 $
26,661
185,863
108,129
124,324
1,425,095
6,112
3,204
517,048
2014
3,936,888 $
35,536 $
107,189
309,367
108,129
242,274
2,340,653
12,584
14,537
766,617
2015
5,295,586
51,108
223,075
434,156
108,129
360,225
3,256,323
19,057
31,833
811,678
2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
Page 1 of 1
Exhibit Bohrman Direct-2
2013 Sierra Pacific IRP
Summary Lost Revenue
Based on Cumulative Savings Forecasts
3DJHRI
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
$
$
Non-Profit Agency Grants
Residential Energy Efficient Lighting Program
Second Refrigerator Collection and Recycling
Commercial New Construction
Energy Smart Schools Program
Commercial Retrofit Incentives Program
Solar Thermal Water Heating
Demand Response
Home Energy Reports
Total Lost Revenue Requirement
Program
1,771,937 $
15,647 $
64,121
122,579
117,951
920,998
6,473
7,120
517,048
2014
2,088,052 $
15,647 $
103,581
124,482
117,951
920,998
6,473
32,304
766,617
2015
2,201,777
15,647
133,175
125,116
117,951
920,998
6,473
70,740
811,678
2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
Exhibit Bohrman Direct-3
2013 Sierra Pacific IRP
Summary Lost Revenue
Based on Full Year Savings Forecasts
Page 1 of 1
3DJHRI
Commercial Retrofit
Total
4
5
6
7
8
9
10
11
12
13
14
4
3
2
1
Workpaper Bohrman Direct-4 Retrofit Lost Revenue
Workpaper Bohrman Direct-4 Schools Lost Revenue
Workpaper Bohrman Direct-4 CNC Lost Revenue
Workpaper Bohrman Direct-4 NPG Lost Revenue
Program Details:
Schools3
3
4
Commercial New Construction
2
2
Non-Profit Grants1
Program
1
Line
No.
(a)
$
$
117 $
(d)
(e)
13,748
15,444 $
651
994
51 $
32,469
37,008 $
2,057
2,332
150 $
36,962
42,071 $
2,313
2,464
332 $
Demand Lost Revenue - Minimum Savings
Summer
Winter
Winter
Mid-peak
On-peak
Mid-peak
(c)
2014 Cumulative Summary
28,443
31,714 $
857
2,297
Summer
On-peak
(b)
650
111,622
126,236
5,878
8,086
Total
(f)
Page 1 of 6
4
5
6
7
8
9
10
11
12
13
14
3
2
1
Line
No.
Exhibit Bohrman Direct-4
2013 Sierra Pacific IRP
Summary Lost Demand Revenue
2014 Cumulative Savings
3DJHRI
Commercial Retrofit
Total
4
5
6
7
8
9
10
11
12
13
14
4
4
2
1
Workpaper Bohrman Direct-4 Retrofit Lost Revenue
Workpaper Bohrman Direct-4 Schools Lost Revenue
Workpaper Bohrman Direct-4 CNC Lost Revenue
Workpaper Bohrman Direct-4 NPG Lost Revenue
Program Details:
Schools3
3
4
Commercial New Construction
2
2
Non-Profit Grants1
Program
1
Line
No.
(a)
$
$
195 $
(d)
(e)
22,525
24,879 $
1,272
994
89 $
53,123
59,716 $
4,003
2,332
258 $
60,467
68,001 $
4,496
2,464
573 $
Demand Lost Revenue - Minimum Savings
Summer
Winter
Winter
Mid-peak
On-peak
Mid-peak
(c)
2015 Cumulative Summary
46,478
50,662 $
1,692
2,297
Summer
On-peak
(b)
182,593
203,258
11,463
8,086
1,115
Total
(f)
Page 2 of 6
4
5
6
7
8
9
10
11
12
13
14
3
2
1
Line
No.
Exhibit Bohrman Direct-4
2013 Sierra Pacific IRP
Summary Lost Demand Revenue
2015 Cumulative Savings
3DJHRI
Commercial Retrofit
Total
4
5
6
7
8
9
10
11
12
13
14
4
4
2
1
Workpaper Bohrman Direct-4 Retrofit Lost Revenue
Workpaper Bohrman Direct-4 Schools Lost Revenue
Workpaper Bohrman Direct-4 CNC Lost Revenue
Workpaper Bohrman Direct-4 NPG Lost Revenue
Program Details:
Schools3
3
4
Commercial New Construction
2
2
Non-Profit Grants1
Program
1
Line
No.
(a)
$
$
270 $
(d)
(e)
31,312
34,324 $
1,893
994
125 $
73,811
82,459 $
5,950
2,332
366 $
84,009
93,966 $
6,680
2,464
814 $
Demand Lost Revenue - Minimum Savings
Summer
Winter
Winter
Mid-peak
On-peak
Mid-peak
(c)
2016 Cumulative Summary
64,545
69,638 $
2,526
2,297
Summer
On-peak
(b)
253,677
280,387
17,049
8,086
1,575
Total
(f)
Page 3 of 6
4
5
6
7
8
9
10
11
12
13
14
3
2
1
Line
No.
Exhibit Bohrman Direct-4
2013 Sierra Pacific IRP
Summary Lost Demand Revenue
2016 Cumulative Savings
3DJHRI
Schools3
Commercial Retrofit4
Total
3
4
5
6
7
8
9
10
11
12
13
14
4
4
2
1
Workpaper Bohrman Direct-4 Retrofit Lost Revenue
Workpaper Bohrman Direct-4 Schools Lost Revenue
Workpaper Bohrman Direct-4 CNC Lost Revenue
Workpaper Bohrman Direct-4 NPG Lost Revenue
Program Details:
Commercial New Construction
2
2
Non-Profit Grants1
Program
1
Line
No.
(a)
$
$
834
-
111 $
(d)
(e)
8,831
9,496 $
621
44 $
20,908
22,973 $
1,947
-
118 $
23,810
26,255 $
2,184
-
262 $
Demand Lost Revenue - Minimum Savings
Summer
Winter
Winter
Mid-peak
On-peak
Mid-peak
(c)
2014 Full Year Summary
18,065
19,010 $
Summer
On-peak
(b)
-
535
71,614
77,734
5,586
Total
(f)
Page 4 of 6
4
5
6
7
8
9
10
11
12
13
14
3
2
1
Line
No.
Exhibit Bohrman Direct-4
2013 Sierra Pacific IRP
Summary Lost Demand Revenue
2014 Full Year Savings
3DJHRI
Schools3
Commercial Retrofit4
Total
3
4
5
6
7
8
9
10
11
12
13
14
4
4
2
1
Workpaper Bohrman Direct-4 Retrofit Lost Revenue
Workpaper Bohrman Direct-4 Schools Lost Revenue
Workpaper Bohrman Direct-4 CNC Lost Revenue
Workpaper Bohrman Direct-4 NPG Lost Revenue
Program Details:
Commercial New Construction
2
2
Non-Profit Grants1
Program
1
Line
No.
(a)
$
$
834
-
111 $
(d)
(e)
8,831
9,496 $
621
44 $
20,908
22,973 $
1,947
-
118 $
23,810
26,255 $
2,184
-
262 $
Demand Lost Revenue - Minimum Savings
Summer
Winter
Winter
Mid-peak
On-peak
Mid-peak
(c)
2015 Full Year Summary
18,065
19,010 $
Summer
On-peak
(b)
-
535
71,614
77,734
5,586
Total
(f)
Page 5 of 6
4
5
6
7
8
9
10
11
12
13
14
3
2
1
Line
No.
Exhibit Bohrman Direct-4
2013 Sierra Pacific IRP
Summary Lost Demand Revenue
2015 Full Year Savings
3DJHRI
Schools3
Commercial Retrofit4
Total
3
4
5
6
7
8
9
10
11
12
13
14
4
4
2
1
Workpaper Bohrman Direct-4 Retrofit Lost Revenue
Workpaper Bohrman Direct-4 Schools Lost Revenue
Workpaper Bohrman Direct-4 CNC Lost Revenue
Workpaper Bohrman Direct-4 NPG Lost Revenue
Program Details:
Commercial New Construction
2
2
Non-Profit Grants1
Program
1
Line
No.
(a)
$
$
834
-
111 $
(d)
(e)
8,831
9,496 $
621
44 $
20,908
22,973 $
1,947
-
118 $
23,810
26,255 $
2,184
-
262 $
Demand Lost Revenue - Minimum Savings
Summer
Winter
Winter
Mid-peak
On-peak
Mid-peak
(c)
2016 Full Year Summary
18,065
19,010 $
Summer
On-peak
(b)
-
535
71,614
77,734
5,586
Total
(f)
Page 6 of 6
4
5
6
7
8
9
10
11
12
13
14
3
2
1
Line
No.
Exhibit Bohrman Direct-4
2013 Sierra Pacific IRP
Summary Lost Demand Revenue
2016 Full Year Savings
3DJHRI

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