NEVADA POWER COMPANY d/b/a NV Energy BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA IN THE MATTER of the Application of NEVADA ) POWER COMPANY, d/b/a NV Energy, filed ) pursuant to NRS 704.110 (3) and (4), addressing its ) annual revenue requirement for general rates ) charged to all classes of customers. ) __________________________________________ ) Docket No. 20- 06____ VOLUME 9 of 25 Prepared Direct Testimony of: OMAG Expense Lisa Holder Danielle Lewis Deborah J. Florence Revenue Requirements Harold Walker III Bill Trigero Terry A. Baxter Eric Fox Mariya Recorded Test Year ended December 31, 2019 Certification Period ended May 31, 2020 Expected Change in Circumstance Period ending December 31, 2020
Transcript
NEVADA POWER COMPANY d/b/a NV Energy
BEFORE THE
PUBLIC UTILITIES COMMISSION OF NEVADA
IN THE MATTER of the Application of NEVADA ) POWER COMPANY, d/b/a NV Energy, filed ) pursuant to NRS 704.110 (3) and (4), addressing its ) annual revenue requirement for general rates ) charged to all classes of customers. ) __________________________________________ ) Docket No. 20- 06____
VOLUME 9 of 25
Prepared Direct Testimony of:
OMAG Expense
Lisa Holder Danielle Lewis
Deborah J. Florence
Revenue Requirements
Harold Walker III Bill Trigero
Terry A. Baxter Eric Fox Mariya
Recorded Test Year ended December 31, 2019 Certification Period ended May 31, 2020
Expected Change in Circumstance Period ending December 31, 2020
Index
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Nevada Power Companyd/b/a NV Energy
Volume 9 of 25 Testimony
Index Page 1 of 1
Description Page No. Prepared Direct Testimony Of:
OMAG Expense:
Lisa Holder 5 Danielle Lewis 82 Deborah J. Florence 98
Revenue Requirements:
Harold Walker III 108 Bill Trigero 160 Terry A. Baxter 199 Eric Fox 212 Mariya Coleman 241
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LISA HOLDER
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV EnergyDocket No. 20-06___
2020 General Rate Case
Prepared Direct Testimony of
Lisa Holder
Revenue Requirement
I. INTRODUCTION, BACKGROUND, AND PURPOSE OF TESTIMONY
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
ADDRESS.
A. My name is Lisa Holder. I am Director, Compensation, Benefits and Human
Resources Records for NV Energy, Inc., and its two operating subsidiaries,
Nevada Power Company d/b/a NV Energy (“Nevada Power” or “Company”)
and Sierra Pacific Power Company d/b/a NV Energy (“Sierra” and together
with Nevada Power the “Companies”). My primary business address is 6226
West Sahara Avenue in Las Vegas, Nevada. I am filing testimony in this
proceeding on behalf of Nevada Power.
2. Q. WHAT ARE YOUR PRIMARY RESPONSIBILITIES AS DIRECTOR,
COMPENSATION, BENEFITS AND HUMAN RESOURCES
RECORDS FOR NEVADA POWER AND SIERRA?
A. I manage the administration of the Companies’ employee compensation and
benefit programs. I also have responsibilities related to the maintenance of
human resources systems and records.
Holder-DIRECT 1
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3. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
EXPERIENCE.
A. I hold a Bachelor of Science Degree in Human and Family Resources and a
Master of Science Degree in Education. For the past 22 years I have worked
in human resources or have been in positions supporting the human resource
function. I spent five of these years as a consultant working with compensation
and benefits departments across the country implementing technology tools to
support their business needs. For the past 12 years I have been employed by
Sierra and Nevada Power in a variety of roles supporting the compensation
and benefits functions.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. Yes. Most recently, I filed testimony with the Commission in Sierra’s last
general rate case, Docket No. 19-06002.
5. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT
TESTIMONY?
A. I address the reasonableness of test and certification period costs of the
Company’s employee cash compensation programs.
6. Q. ARE YOU SPONSORING ANY EXHIBITS WITH YOUR
TESTIMONY?
A. Yes. I have prepared and am sponsoring the following exhibits as part of my
testimony:
Exhibit Holder-Direct-1 Statement of Qualifications
Holder-DIRECT 2
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Exhibit Holder-Direct-2A Local 396 Wage Scales
Exhibit Holder-Direct-2B Executed Letter of Agreement – Contract
7. Q. HOW IS THE REMAINDER OF YOUR TESTIMONY ORGANIZED?
A. In parts II, III and IV of my testimony, I support the reasonableness of test and
certification period costs associated with Sierra’s compensation programs for
represented employees, non-represented employees, and officers,
respectively.
II. BASE PAY FOR BARGAINING UNIT EMPLOYEES
8. Q. PLEASE DESCRIBE THE COMPENSATION STRUCTURE FOR
BARGAINING UNIT EMPLOYEES.
A. Wages for represented employees are established through collective
bargaining in accordance with federal law. Exhibit Holder-Direct-2A shows
wage scales for the International Brotherhood of Electrical Workers, Local
396 (“Local 396”) employees.
Holder-DIRECT 3
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9. Q. IS NEVADA POWER CURRENTLY ENGAGED IN COLLECTIVE
BARGAINING WITH LOCAL 396?
A. No. The collective bargaining agreement with Local 396, was executed on
September 24, 2013 (“CBA”) and was originally set to expire September 22,
2017. However, Nevada Power and Local 396 agreed to extend the CBA
through June 30, 2021. Exhibit Holder-Direct-2B is a copy of the executed
extension agreement. The payroll expense levels reflected in Schedule H-
CERT-17 for bargaining unit employees are based on the CBA and the
estimated workforce level in January 2020. This provides an annualized
amount from which to estimate costs at the end of May 31, 2020.
10. Q. HAS THE COMMISSION PREVIOUSLY REVIEWED THE CBA,
WHICH WAS USED TO CALCULATE ANNUALIZED PAYROLL OF
BARGAINING UNIT EMPLOYEES AS OF MAY 31, 2020?
A. Yes. The CBA was in place during the test period for Nevada Power’s last
general rate case, Docket No. 17-06003.
11. Q. IS THE BASE PAY FOR LOCAL 396 EMPLOYEES UNDER THE CBA
REASONABLE?
A. Yes. The benchmarking analysis described below demonstrates that the
compensation levels negotiated under the CBA are in fact reasonable and
consistent with regional industry standards. It is also important to recognize
that the Company negotiates a total wage, benefit and work rule package with
the Local 396. As a result, in some instances, wage increases may be granted
if savings are captured from other areas (e.g. changes to work rules, changes
to pension funding, etc.).
Holder-DIRECT 4
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12. Q. PLEASE EXPLAIN NEVADA POWER’S BENCHMARKING OF
LOCAL 396 WAGES.
A. The Company utilized benchmarking data from the EAP Data Information
Solutions (“EAPDIS”) 2018 Energy Technical Craft Clerical Survey to
validate current Local 396 wage rates. The data from the survey is effective as
of April 1, 2018, and was aged 2.5 percent, to December 31, 2019, using an
independent on-line market pricing system.
The Company’s market analysis compares Nevada Power’s average hourly
wages for benchmarked positions and the median hourly wages as reported
within 1) All Companies; 2) the Mountain/Plains Region; 3) the Western
Region; and 4) the average between the Mountain and Western scopes. The
analysis revealed that the average hourly wage for Nevada Power’s
benchmarked positions is 3.9 percent greater than All Companies, 7.0 percent
greater than the Mountain/Plains Region average, 10.6 percent lower than the
Western Region average, and 1.8 percent lower than the average composite of
these two regions.1
13. Q. WHAT IS THE IMPORTANCE OF COMPARING WAGE RATES TO
REGIONAL WAGE LEVELS?
A. This is an important comparison because electric utilities in the western United
States and some mountain states compete directly with Nevada Power for
skilled craft employees. In evaluating the reasonableness of Nevada Power’s
compensation costs, the Company considers the labor markets in which it must
compete for skilled labor to perform the work to serve customers. Although
1 To protect the integrity of the salary survey results, as only one survey source was used, the benchmarking analysis cannot be published and is considered proprietary information; however, the analysis can be reviewed on-site upon request.
Holder-DIRECT 5
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higher wage levels are commanded by skilled utility workers in the Western
Region, the hourly wages for Local 396 are positioned between the Western
Region and the Mountain/Plains Region.
III. BASE PAY FOR NON-REPRESENTED EMPLOYEES
14. Q. PLEASE DESCRIBE THE CASH COMPENSATION COMPONENTS
FOR NON-REPRESENTED EMPLOYEES.
A. The components of the cash compensation program for non-represented
employees reflected in the revenue requirement calculated in this case include:
• Base pay, which is provided to all employees;
• Short Term Incentive Plan (“STIP”), which provides a financial
incentive for meeting or exceeding Nevada Power’s short-term
strategic goals and meeting or exceeding personal performance goals
which contribute to the achievement of company goals.
• Other cash compensation, including signing bonuses, retention
bonuses, severance and relocation costs.
15. Q. HOW IS BASE PAY DETERMINED?
A. Our goal is to provide competitive compensation at the median level of what
an employee would receive at another company. We evaluate internal equity,
which is the relative worth of each job within the Companies when comparing
the jobs’ responsibilities and accountabilities, and the required level of
competencies, training, and experience needed by an employee to fulfill the
jobs’ duties. We also continuously evaluate the current market value of jobs
based on the knowledge, skills, and talents required of a fully competent
incumbent. Based on the internal value and external market, jobs are assigned
Holder-DIRECT 6
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to a salary grade. The salary range, which includes a minimum, midpoint and
maximum rate, varies by salary grade. Employee’s salaries are then managed
within the grade using the midpoint as a reference.
16. Q. WHAT ARE THE RANGES OF BASE SALARIES FOR NON-
REPRESENTED EMPLOYEES?
A. Exhibit Holder-Direct-3A shows the 2019 non-represented salary structure.
17. Q. HOW IS EXTERNAL MARKET VALUE DETERMINED?
A. While Nevada Power uses several compensation surveys to benchmark non-
represented jobs, results from Willis Towers Watson CDB Energy Services
Mid-Management, Professional & Support continues to be the primary source
of benchmark data. For each benchmarked non-represented job, the market
median of the benchmark job is pulled along with the target bonus incentive.
Data is pulled utilizing the total sample. Surveys utilized in 2019 are listed in
Table-Holder-Direct-1 below.
Table-Holder-Direct-1
Survey Name Survey Data
Effective Date
Aon High Demand IT Compensation & Practices, 2018 3/1/2018 Aon IEHRA Energy Industry, 2018 5/1/2018 Aon Renewable Energy, 2018 4/1/2018 Aon TCM Broad-Based Mgmt Total Comp by Industry, 2018 3/1/2018 Energy Technical Craft Clerical, 2018 4/1/2018 Willis Towers Watson American Gas Association, 2019 3/1/2019 Willis Towers Watson Energy Services Executive, 2019 4/1/2019 Willis Towers Watson Energy Services Mid-Mgmt, Prof &
Support, 2019 4/1/2019
Holder-DIRECT 7
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18. Q. WHAT OTHER COMPANIES PARTICIPATE IN THESE SURVEYS
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THAT WOULD BE INCLUDED IN THE TOTAL SAMPLE?
A. Exhibit Holder-Direct-3C provides a listing of participants in each of the
salary surveys used.
19. Q. THE SURVEY DATA EFFECTIVE DATE IS PRIOR TO
DECEMBER 31, 2019. THE MARKET DATA PROVIDED IN
HOLDER-DIRECT-3C IS AS OF DECEMBER 31, 2019. HOW WAS
THE MARKET DATA AGED?
A. The vendor who provides on-line market pricing system loads the electronic
survey results obtained from the survey providers into the market pricing
database, called MarketPay, and ages the data for the Companies. The vendor
ages the survey data within MarketPay off of the number of days between a
survey’s effective date and the system’s established “Age-to-Date.” Survey
results have been aged by 2.5 percent to December 31, 2019. Using months to
simplify the calculation, the formulas for the aging based on the survey data
effective date are provided below in Table Holder-Direct 2.
Distribution 4019 Operator Start, Distribution 2 Year $49.90 $51.15 $52.43 4020 Operator, Distribution 2 Year $52.06 $53.36 $54.69 4021 Senior Operator, Distribution Vacancy** $55.05 $56.43 $57.84
Training 4006 Trainer, System Operator $56.82 $58.24 $59.70
* Step is defined as time required at each classification level ** Vacancy in the next higher classification is required for progression *** NERC Certification is required for progression to Transmission Operator
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Exhibit Holder-Direct-2A
NV Energy – IBEW L396 COLLECTIVE BARGAINING AGREEMENT
Aon High Demand IT Compensation & Practices, 2018 Abercrombie & Fitch Co. Adventist Health System AIPSO Allegis Group, Inc. Alliant Credit Union Ally Financial, Inc. Ameren Corporation American Family Mutual Insurance Co., Inc. AmerisourceBergen Atmos Energy Corporation AT&T Aurora Health Care, Inc. Autozone Inc. Availity, L.L.C. Aviall BAE Systems Battelle Energy Alliance LLC Blackboard Blue Cross and Blue Shield of Florida, Inc. Blue Cross & Blue Shield of North Carolina BNSF Railway Company Board of Governors of the Federal Reserve System Briggs & Stratton Corporation Brown Forman Caesars Acquisition Company CareFirst of Maryland Cargill Incorporated CDW CenterPoint Energy, Inc. Chewy, Inc. Choice Hotels International, Inc. Chubb Group Citizens Financial Group, Inc. City Public Service of San Antonio Clean Harbors CoBham plc Cognosante Colonial Pipeline Company Comcast Corporation Cornell University Cox Enterprises, Inc. Darden Restaurants, Inc. Dart Container Corporation Deere & Company Deloitte & Touche L.L.P.
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Deluxe Corporation Dick's Sporting Goods, Inc. Discover Financial Services Domino's Pizza, Inc. DSW, Inc. EAB Edward D. Jones & Co., L.P Emory University Empowered Benefits, LLC Energy Transfer Partners Ernst & Young Farm Credit Bank of Texas Federal Reserve Bank of Dallas Federal Reserve Bank of Minneapolis Federal Reserve Information Technology Fermi National Laboratory Fifth Third Bancorp First Data Corporation Fiserv, Inc. General Mills, Inc. Genuine Parts Company Graco, Inc. Hanesbrands, Inc. HD Supply Helmerich & Payne, Inc. Hilton Grand Vacations Company LLC Hyatt Hotels Corporation IDEXX Ilitch Holdings, Inc. Jackson National Life Insurance JEA JetBlue Airways J. J. Keller & Associates, Inc. JM Family Kellogg Company Kforce Inc. Laureate Education, Inc. Littelfuse, Inc. Mapfre U.S.A. Corp. Mazda Motor Corporation Methode Electronics MIT Lincoln Laboratory Molex Incorporated National Futures Association National Renewable Energy Lab Navy Federal Credit Union
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
NCI, Inc. Nestle Purina PetCare Company Northern Arizona University NRG Energy, Inc. Nustar Energy L.P NV Energy, Inc. One America Financial Partners, Inc. Onemain Financial PACCAR Inc. Parsons Corporation Petco Animal Supplies, Inc. Pilot Flying J, Inc. Public Broadcasting Service Quintiles Reinsurance Group of America, Incorporated Retail Business Services Ricoh Americas Corporation Robert Half International Ropes & Gray LLP RSM US LLP Sentry Insurance State Farm Mutual Automobile Insurance Company Stericycle, Inc. TDS Telecommunications Texas Children's Hospital Texas Health Resources The Allstate Corporation The Capital Group, Inc. The Dow Chemical Company The Progressive Corporation The University Of Texas M D Anderson Cancer Center Thomas Jefferson National Accelerator Facility TJX Companies, Inc. T-Mobile Tractor Supply Company Trinity Health Corporation United Air Lines United States Steel Corp. Universal Studios U.S. Cellular Valero Energy Corporation Voya Financial Washington Gas Light Company Wawa, Inc. Weil, Gotshal & Manges LLP Western & Southern Financial Group, Inc.
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Wolters Kluwer U.S. W.W. Grainger, Inc. Yum! Brands, Inc. Zurich American Insurance
Aon IEHRA Energy Industry, 2018 ALLETE, Inc. Alliant Energy Corporation Alyeska Pipeline Service Company Ameren Corporation American Electric Power Company, Inc. Arizona Public Service Company Arkansas Electric Cooperatives Corporation Associated Electric Cooperative Inc. Atlantic Power Services LLC Avangrid Renewables Avant Energy, Inc. Berkshire Hathaway Energy Company Buckeye Partners, L.P. Calpine Corporation Capital Power Corporation CenterPoint Energy, Inc. Chevron Global Power Company City Utilities of Springfield, MO Cleco Corporation CMS Energy Corporation Colorado Springs Utilities Consolidated Edison, Inc. Covanta Energy CPS Energy Dairyland Power Cooperative Diamond Generating Corporation Direct Energy Services Inc. Dominion Energy, Inc. DTE Energy Company Duke Energy Corporation EDF Renewables EDF Trading Limited Edison International EDP Renewables North America LLC Emera Energy Inc. Energy Transfer Partners, L.P. Entrust Energy, Inc. EthosEnergy Group Exelon Corporation Ferrellgas Partners, L.P. FirstEnergy Corp.
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
First Solar, Inc. Gas South, LLC Great River Energy Greystone Power Corporation Heorot Power Management LLC IHI Power Services Corporation JEA Kamo Electric Cooperative, Inc. Midwest AgEnergy Group LLC Nebraska Public Power District New Jersey Resources Corp New York Power Authority NextEra Energy Resources, LLC NiSource Inc. North American Energy Services Corporation NRG Energy, Inc. Nustar Energy L.P. OCI Solar Power OGE Energy Corp. Oglethorpe Power Corporation Old Dominion Electric Cooperative Ormat Technologies, Inc. Pedernales Electric Cooperative, Inc. PG&E Corporation PJM Interconnection LLC Portland General Electric Company Power Plant Management Services LLC Prairie State Generating Company, LLC Public Utility District 1 of Chelan County Sacramento Municipal Utility District SCANA Corporation Seminole Electric Cooperative, Inc. Sempra Energy Southern Company Southwest Gas Corporation Southwest Generation Operating Company, LLC Spire Energy Suncoke Energy, Inc. Tenaska, Inc. Tennessee Valley Authority Vistra Energy WEC Energy Group, Inc. Xcel Energy, Inc.
Aon Renewable Energy, 2018 Acciona Energy USA Global LLC ALLETE, Inc.
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Alliant Energy Avangrid, Inc. BayWa r.e. Solar Projects, LLC BP p.l.c. City Utilities of Springfield, MO Con Edison Competitive Covanta Energy Dairyland Power Cooperative Duke Energy Corporation EDF Renewable Energy EDP Renewables North America LLC Enel Green Power North America, Inc. Energy Businesses Ethos Energy Group Exelon Corporation First Solar GDF Suez North America MidAmerican Energy Holdings (Berkshire Hathaway Energy) NAES Corporation (North American Energy Services) Nebraska Public Power District NextEra Energy Resources, LLC Ormat Technologies Inc. Portland General Electric Company Seminole Electric Cooperative, Inc. Sempra Energy Sunrun Inc Tenaska, Inc. The Southern Company Tradewind energy Inc. Underwriters Laboratories Vestas America Vivint Solar, Inc.
Aon TCM Broad-Based Mgmt Total Comp by Industry, 2018 3M Company 7-Eleven, Inc. Abbott Laboratories Academy Sports & Outdoors, Ltd. ACCO Brands Corporation Acushnet Company ADT Corp Aegion Corp. A&E Television Networks Aetna Inc. Aflac Incorporated AGCO Corporation Air Methods Corporation
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Albertsons Inc. Alight Solutions Allegion S&S US Holding Company Inc Allegis Group Allete, Inc. Alliant Energy Corporation Allianz Life Insurance Company of North America Ally Financial Inc. Altria Group, Inc. Ameren Corporation American Airlines American Axle & Manufacturing Holdings, Inc. American Electric Power Company, Inc. American Express Company American Family Mutual Insurance Co Inc American Greetings Corporation American Hotel Register Company American International Group, Inc. Analog Devices, Inc. Andeavor Aon Corporation Aptim Aptiv Arby's Restaurant Group, Inc. Arch Coal, Inc. Argo Group Us, Inc. Arkansas Blue Cross & Blue Shield, A Mutual Insurance Company Arkema Inc. Armstrong World Industries, Inc. Asbury Automotive Group, Inc. AT&T Inc. Auria Solutions USA Inc. Avangrid, Inc. Avanos BAE Systems, Inc. Bain & Company, Inc. Ball Corporation Ballentine Partners Barnes Group Inc. Barry-Wehmiller Companies, Inc. Battelle Memorial Institute Inc Baxter Credit Union BB&T Corporation Beachbody Beam Suntory Inc. Belden Inc.
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Belk, Inc. Berkshire Hathaway Energy Company BJ's Restaurants, Inc. Bloomin Brands Blue Cross Blue Shield Association Blue Diamond Growers BMW of North America BNSF Railway Company Boddie Noell Enterprises Inc Borg Warner Breakthru Beverage Group Briggs & Stratton Corporation Brighthouse Financial Brown-Forman Corporation Brunswick Corporation Buckeye Partners, L.P. Builders FirstSource, Inc. Bush Brothers & Company Caesars Entertainment, Inc Ca, Inc. Cajun operating Company Calgon Carbon Corporation Calpine Corporation Campbell Soup Company Capital Power Corporation Cardinal Health, Inc. Cardtronics, Inc. Career Education Corporation Cargill, Incorporated Carter's, Inc. Case New Holland Caterpillar Inc. CDK Global, Inc. CenterPoint Energy, Inc. Century Aluminum Company CF Industries Holdings, Inc. Checkers Drive-In Restaurants, Inc. Cheniere Energy, Inc. Chewy, Inc. Chico's FAS, Inc. Children's Medical Center of Dallas Cincinnati Financial Corporation City & County Of Denver City Utilities of Springfield Clearwater Paper Corporation Cleco Corporation
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
CNA Financial Corporation Coca-Cola Bottling Co. Consolidated Coca-Cola Refreshments Colfax Corporation Colgate-Palmolive Company Colorado Energy Management Colorado Springs Utilities Colson Associates, Inc. Comcast Corporation ConAgra Foods, Inc. Consolidated Edison Cooper-Standard Holdings Inc. CoreLogic, Inc. Coriant Coty Inc. Covance Covanta Energy Cox Enterprises, Inc. Credit Acceptance Corporation Curtiss-Wright Corporation CVS Health Danaher Corporation Darden Restaurants, Inc. Dart Container Corporation Deere & Company Deloitte & Touche L.L.P. Deluxe Corporation Denny's Corporation Denso International America, Inc. Diageo North America, Inc. Diamond Generating Corporation Dick's Sporting Goods, Inc. Dine Brands Direct Energy Services Inc Discover Financial Services Dole Food Company, Inc. Dominion Energy, Inc. Domino's Pizza, Inc. Donaldson Company, Inc. Donatos Pizzeria Corp. Drew Marine USA Inc Duke Energy Corporation Dunkin' Brands, Inc. Duracell International Inc. EAB Eaton Corporation
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Ecolab Inc. EDF Renewable Energy EDP Renewables E. & J. Gallo Winery Elkay Manufacturing Company Inc Elo Touch Solutions, Inc. Emerson Electric Co. Encore Capital Group, Inc. Erie Indemnity Company Essendant Inc. Essex Property Trust, Inc. Essilor of America, Inc. Ethos Energy Group Evraz Inc. NA Exide Technologies Express Express Scripts, Inc. Fairfax County Public Schools Federal Home Loan Bank of Atlanta Federal Home Loan Mortgage Corporation Federal Reserve Bank of Cleveland Federal Reserve Bank of Dallas Federal Reserve Bank of Kansas City Federal Reserve Bank of Minneapolis Federal Reserve Information Technology FedEx Corporation FedEx Services Fermi National Laboratory Ferrara Candy Company First Data Corporation FirstEnergy Corp. First Solar, Inc. Fitbit Flowserve Corporation Focus Brands Ford Motor Company Foresters Fortune Brands Home & Security Fossil, Inc. Franklin Electric Co., Inc. Freeport-McMoRan Inc. Fresenius Medical Care Frost & Sullivan GAF Gardner Denver, Inc. GATX Corporation
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Gemological Institute of America General Dynamics Corporation General Dynamics Land Systems General Mills, Inc. General Motors Company Genuine Parts Company Genworth Financial, Inc. Gilbane Inc. Gilead Sciences Glanbia Performance Nutrition, Inc. GNC Corporation Gordon Food Service Gorton's Inc. Graphic Packaging Holding Company Great River Energy Greystone Power Corporation Gypsum Management and Supply, Inc. Hallmark Cards, Inc. Hanesbrands Inc. Harley-Davidson Motor Company, Inc. Harris Corporation Haworth, Inc. H.B. Fuller Company HCC Insurance Holdings, Inc. HD Supply H. E. Butt Grocery Company Helen of Troy Limited Helzberg Diamonds Hendrickson USA, LLC Herbalife International Herman Miller, Inc. Hi-Crush Partners LP Hilti Of America Inc Hilton Grand Vacations Company, LLC Hilton Worldwide, Inc. HMSHost HNTB Corporation Hollister Incorporated Hollyfrontier Corporation Holman Enterprises, Inc. Honda North America, Inc Hormel Foods Corporation Houghton Mifflin Company H&R Block Hubbell Incorporated Hudson Advisors
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Humana Inc. Huron Consulting Group Inc. Hyatt Hotels Corporation ICF International, Inc. Ideal Industries, Inc. IKEA North America Services, LLC Illinois Tool Works Inc. Information Resources, Inc. Ingersoll-Rand Company Ingevity Corporation Ingredion Incorporated International Automotive Components Group North America, Inc. International Dairy Queen, Inc. International Paper Company Iron Mountain Incorporated ITG Brands, LLC Itochu International Inc. ITU AbsorbTech, Inc Jack in the Box Inc. James Hardie Industries SE JBS USA Holdings, Inc. JEA Johns Manville Corporation Johnson Controls International Johnson & Johnson Johnson Outdoors Inc. John Wiley & Sons, Inc. J. Paul Getty Trust J. R. Simplot Company Kaman Corporation Kamo Electric Cooperative Inc. Kellogg Company Kenco Group Keystone Foods LLC Kforce Inc. Kimberly-Clark Corporation Kinder Morgan Inc Kings Hawaiian Bakery Kinross Gold U.S.A., Inc. Knowles Corporation Kohler Co. Komatsu Mining Corporation L-3 Communications Holdings, Inc. Lamb Weston Legal & General America, Inc. Liberty Tire Recycling
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Little Rapids Corporation L.L. Bean, Inc. Lockheed Martin Corporation LPL Financial Corporation Lsg Sky Chefs Usa, Inc. Luxottica Retail Lydall, Inc. Magna International Inc. Magnolia Realty Inc. ManpowerGroup Marriott International, Inc. Marriott Vacation Worldwide Mars Incorporated Martin Marietta Materials, Inc. Masco Corporation Maximus Inc. Mazda Motor Corporation McDonald's Corporation McLane Company, Inc. Mercedes-Benz Financial Services USA LLC Mercedes Benz USA LLC Mercury Insurance Meritor, Inc. Merrill Corporation Micron Technology Mid-America Apartment Communities, Inc. Midwest AgEnergy Group Mitsui & Co. (u.s.a.) Inc. Mohawk Industries, Inc. Momentive Specialty Chemicals Inc. Mondelez International, Inc. Mortgage Guaranty Insurance Corporation Motorsport Aftermarket Group MRC Global Inc. Mr. Cooper Mueller Water Products, Inc. Navy Federal Credit Union NCI Building Systems, Inc. NCR Corporation Nestle Purina Petcare Company Nestle USA, Inc. Netapp, Inc. New Jersey Manufacturers Insurance Company New York Power Authority New York University Nextera Energy Resources, LLC
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Nintendo of America, Inc. Nippon Express U.S.A., Inc. NiSource Inc. Nordstrom, Inc. Northern Trust Corporation Northshore University Healthsystem Novartis Pharmaceuticals Corporation NRG Energy, Inc. NSK Corporation NuStar Energy LP NV Energy, Inc. nVent Oak Ridge Associated Universities Inc. Olympus America Inc. ONEOK, Inc. Oriental Trading Company Owens-Illinois, Inc. Pacific Bells, Inc. Pacific Life Insurance Company Packaging Corporation of America Panasonic Corp of North America Panduit Corp. Papa John's International, Inc. Parker-Hannifin Corporation Patagonia Paychex, Inc. Pedernales Electric Cooperative, Inc. Penske Corporation Pentair, Inc. People's United Financial, Inc. PepsiCo, Inc. Performance Food Group Company Pernod Ricard Usa, LLC Perrigo Company Petco Animal Supplies, Inc. PetSmart, Inc. P.F. Chang's China Bistro,Inc. PG&E Corporation Pjm Interconnection, LLC PolyOne Corporation Prairie State Generating Company, LLC Praxair, Inc. Pricewaterhousecoopers LLP Prologis, Inc. Public Company Accounting Oversight Board Publix Super Markets, Inc.
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
PVH Corp. Qorvo Quad-Graphics, Inc. Qualcomm Inc. Quest Diagnostics Incorporated Radisson Hotels International Raising Cane's Resturants Randstad North America L.P. Raytheon Company RECARO Aircraft Seating Americas, Inc. Redbox Regal Beloit Corporation Republic Services, Inc. Reynolds American Inc. Rich Products Corporation Ricoh Americas Corporation Risk Administration Service Ritchie Bros. Auctioneers Incorporated Robert Bosch LLC Robert Half International Inc. Ryder System, Inc. Sacramento Municipal Utility District Sally Beauty Holdings, Inc. Sargento Foods Inc. SCANA Corporation S & C Electric Company Scholle Corporation Schreiber Foods, Inc. S. C. Johnson & Son, Inc. Seminole Electric Cooperative, Inc. Sempra Energy Sharecare ShopKo Stores, Inc. Siemens Corporation Simpson Manufacturing Co., Inc. Sodexo, Inc. Sonic Corp. Sonoco Products Company Sotera Health Southeastern Freight Lines, Inc. Southern Methodist University Inc Southwest Generation Operating Company LLC Spartan Light Metal Products, Inc. SpartanNash Company Spire Inc Stage Stores, Inc.
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Standard Motor Products, Inc. Staples, Inc. St. Jude Children's Research Hospital, Inc. Stryker Corporation Subway Restaurants, Inc Summit Polymers, Inc. SuperValu Inc. Sutter Home Winery, Inc. Taco John's International, Inc. Target Corporation TDS Telecommunications Corporation Tecumseh Products Company Tellurian Inc Tenaska Energy Inc. Tennant Company Tennessee Valley Authority Terex Corporation Texas Children's Hospital Textron Inc. The Allstate Corporation The Bama Companies, Inc The Chamberlain Group, Inc The Chemours Company The Clorox Company The Coca-Cola Company The Dow Chemical Company The Estee Lauder Companies Inc The Goodyear Tire & Rubber Company The Guardian Life Insurance Company of America The Hartford Financial Services Group Inc The Hershey Company The Marcus Corporation The New York Times Company The Privatebank and Trust Company The Progressive Corporation The Scotts Miracle-Gro Company The ServiceMaster Company LLC The Sherwin-Williams Company The Timken Company The TJX Companies Inc Thirty-One Gifts LLC Tivity Health TMEIC Corporation Toms Shoes Inc. Topbuild Corp Tory Burch LLC
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Toyota Boshoku TPI Composites Transamerica TransUnion LLC TreeHouse Foods, Inc Trinity Industries, Inc. True Value Company TS Tech Americas, Inc. TTX Company Tuesday Morning Corporation Tyson Foods, Inc. Uline, Inc. Unilever United States Inc. United Continental Holdings, Inc. UnitedHealth Group Incorporated United Parcel Service United States Cellular Corporation United Technologies Corporation Universal Health Services, Inc. Universal Studios Orlando Restaurants U.S. Bancorp US Foods, Inc. Vail Resorts, Inc. Valero Energy Corporation Valmont Industries, Inc. Venator Veritiv Corporation Verizon Communications Inc. Verso corporation VetSource V.F. Corporation Viad Corp Visa Inc. Vision Service Plan Vista Outdoor Inc. Vistra Energy Vitamix Corporation Walgreens Boots Alliance, Inc. Waste Management, Inc. Weathernews Inc. Wegmans Food Markets, Inc. WellCare Health Plans, Inc Wells Enterprises, Inc. WestRock Company WEX Inc. Whirlpool Corporation
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
White Castle System, Inc. Whole Foods Market, Inc. Williams-Sonoma, Inc. Wolters Kluwer U.S. Woodward Inc. World Bank Xcel Energy Inc. Xerox Corporation Yazaki North America, Inc. YUM Brands, Inc. Zappos ZF Friedrichshafen AG
Energy Technical Craft Clerical, 2018 AES US Services, LLC Ameren Corporation American Electric Power Arizona Public Service/Pinnacle West Avista Utilities CenterPoint Energy Cleco Corporate Holdings, LLC Colorado Springs Utilities Consumers Energy Dominion DTE Energy Company Duke Energy Corporation East Kentucky Power Cooperative ElectriCities of North Carolina, Inc Energy Northwest Entergy Corp. Eversource Energy Exelon Corp. FirstEnergy Corp. Idaho Power Company JEA Kansas City Power and Light Lower Colorado River Authority MidAmerican Energy Company Montana-Dakota Utilities Co Nebraska Public Power District Newmont Mining Corporation New York Power Authority NextEra Energy, Inc. NorthWestern Energy NRG Energy, Inc. Omaha Public Power District Oncor Electric Delivery
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Otter Tail Power Company Pacific Gas & Electric Company Platte River Power Authority PPL Corporation Puget Sound Energy San Diego Gas and Electric Santee Cooper SCANA Corporation Southern California Edison Southern California Gas Co. Southern Company - Ga. Power Southern Company - MS Power Southern Company- Nuc. Operating Tampa Electric Tucson Electric Power Company We Energies Westar Energy, Inc Wolf Creek Nuclear Operating Corp. Xcel Energy
WTW American Gas Association, 2019 Atmos Energy Corporation Avista Corporation Berkshire Hathaway Energy Black Hills Corporation CenterPoint Energy Chesapeake Utilities Corporation Citizens Energy Group City of Gainesville Colorado Springs Utilities CPS Energy Dominion Energy Southeast Energy Group Enstar Natural Gas Company Equitrans Midstream Corporation Eversource Energy Greenville Utilities Hawaii Gas Knoxville Utilities Board LG&E and KU Energy Memphis Light, Gas & Water Metropolitan Utilities District Montana-Dakota Utilities Company Mountaineer Gas Company National Fuel Gas Company National Gas & Oil Cooperative New Jersey Resources
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
NiSource NorthWestern Energy NW Natural ONE Gas Peoples Natural Gas Philadelphia Gas Works Puget Sound Energy San Diego Gas & Electric Company SEMCO Energy Southern Company Gas Southern Star Central Gas Pipeline South Jersey Industries Southwest Gas Corporation Spire TC Energy (TECO Energy ) Washington Gas Xcel Energy
WTW Energy Services Executive, 2019 AES Corporation ALLETE Alliant Energy Ameren American Electric Power Aqua America Atmos Energy AVANGRID Avista Baker Hughes, a GE company Berkshire Hathaway Energy Black Hills Boardwalk Pipeline Partners BWX Technologies California Independent System Calpine Canadian Solar CenterPoint Energy Cheniere Energy Chesapeake Utilities Citizens Energy Group CLEAResult Cleco CMS Energy Colorado Springs Utilities Consolidated Edison Cooperative Core Laboratories
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
CPS Energy Dairyland Power Cooperative DCP Midstream Dominion Energy Dominion Energy Southeast Energy DTE Energy Duke Energy Duquesne Light EDF Renewable Energy Edison International El Paso Electric Enable Midstream Partners Energy Northwest Energy Transfer Partners ENGIE Energy North America ENI US Operating Company EnLink Midstream Entergy E.ON - Climate and Renewables EQT Corporation ERCOT Evergy Eversource Energy Exelon FirstEnergy First Solar Framatome Genesis Energy GE Power GE Renewable Energy Great River Energy Group Hawaiian Electric Industries Helmerich & Payne ICF International Idaho Power Institute of Nuclear Power Operations ISO New England ITC Holdings JEA Kinder Morgan Knoxville Utilities Board LG&E and KU Energy Lower Colorado River Authority Midwest Independent Transmission Monroe Energy
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Montana-Dakota Utilities MRC Global Inc National Grid USA Nebraska Public Power District New Jersey Resources NextEra Energy Inc. NiSource NorthWestern Energy NOVA Chemicals NuStar Energy NW Natural OGE ENnergy Oglethorpe Power Old Dominion Electric Omaha Public Power Oncor Electric Delivery ONE Gas ONEOK Operator Orano Orlando Utilities Commission Otter Tail Pacific Gas & Electric Pedernales Electric Cooperative Pinnacle West Capital PJM Interconnection PNM Resources Portland General Electric PPL Precision Drilling Public Service Enterprise Group Puget Sound Energy Salt River Project Santee Cooper SEMCO Energy Sempra Energy Silicon Ranch Corporation Southern Company Services Southern Maryland Electric South Jersey Industries Southwest Gas Spire STP Nuclear Operating System Operator TC Energy TECO Energy
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Tennessee Valley Authority UGI Unitil UNS Energy URENCO Vistra Energy WEC Energy Group Williams Companies Xcel Energy
WTW Energy Services Mid-Mgmt, Prof & Support, 2019 AES Corporation Algonquin Power & Utilities ALLETE Alliant Energy Alyeska Pipeline Service Ameren American Electric Power Aqua America Associated Electric Cooperative ATC Management Atmos Energy AVANGRID Avista Berkshire Hathaway Energy Black Hills Blattner Energy Boardwalk Pipeline Partners BWX Technologies California Independent System Operator Calpine Canadian Solar Capital Power CenterPoint Energy Centrica Chelan County Public Utility District Cheniere Energy Chesapeake Utilities CLEAResult Cleco CMS Energy Colorado Springs Utilities Consolidated Edison Core Laboratories CPS Energy Dairyland Power Cooperative DCP Midstream
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Delek US Holdings DNV GL Dominion Energy Dominion Energy Southeast Energy Group DTE Energy Duke Energy Duquesne Light EDF Renewable Energy EDF Trading Edison International Electric Boat Corporation ElectriCities of North Carolina El Paso Electric Enable Midstream Partners Enbridge Energy Northwest Energy Transfer Partners ENGIE Energy North America ENI US Operating Company EnLink Midstream Entergy E.ON - Climate and Renewables EPCOR Utilities EQT Corporation ERCOT Evergy Eversource Energy Exelon Fieldcore FirstEnergy First Solar Fluor Marine Propulsion Framatome GE Power GE Renewable Energy Gibson Energy Great River Energy Hawaiian Electric Industries Helmerich & Payne ICF International Idaho Power Institute of Nuclear Power Operations ISO New England ITC Holdings JEA Kinder Morgan
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Knoxville Utilities Board LG&E and KU Energy Lightsource BP Lower Colorado River Authority MDU Resources MGE Energy Midwest Independent Transmission System Operator Monroe Energy NAES National Fuel Gas National Grid USA Nebraska Public Power District NextEra Energy Inc. NiSource North America NorthWestern Energy NOVA Chemicals Nuscale Power NuStar Energy NW Natural Oak Ridge National Laboratory OGE Energy Oglethorpe Power Old Dominion Electric Omaha Public Power Oncor Electric Delivery ONE Gas ONEOK Orano Orlando Utilities Commission Pacific Gas & Electric Pedernales Electric Cooperative Pembina Pipeline PetroChina International (America) Pinnacle West Capital PJM Interconnection Platte River Power Authority PNM Resources Portland General Electric PPL Precision Drilling Public Service Enterprise Group Puget Sound Energy Salt River Project Santee Cooper Sempra Energy
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Exhibit Holder-Direct-3C
Survey Report Title Survey Participant
Southern Company Services Southern Maryland Electric Cooperative South Jersey Industries Southwest Gas Spire STP Nuclear Operating Talen Energy Targa Resources TC Energy T.D. Williamson TECO Energy Tennessee Valley Authority Transocean Tri-State Generation & Transmission Unitil UNS Energy URENCO Veolia Environmental Services Washington Gas Williams Companies Xcel Energy
Nevada Power Company d/b/a NV EnergyDocket No. 20-06___
2020 General Rate Case
Prepared Direct Testimony of
Danielle Lewis
Revenue Requirement
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
ADDRESS.
A. My name is Danielle Lewis. I am a Finance Project Manager for Sierra Pacific
Power Company d/b/a NV Energy (“Sierra” ) and Nevada Power Company
d/b/a NV Energy (“Nevada Power” or the “Company” and, together with
Sierra, the “Companies”). I work primarily out of Sierra’s offices at 6100 Neil
Road in Reno, Nevada. I am filing testimony on behalf of Nevada Power.
2. Q. PLEASE SUMMARIZE YOUR EDUCATION AND PROFESSIONAL
EXPERIENCE.
A. I have been employed by the Companies for 5 years. A complete statement of
my qualifications is set forth as Exhibit Lewis-Direct-1, attached to my
testimony.
3. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. Yes. I filed prepared direct testimony in support of Sierra’s 2019 General Rate
Case, Docket No. 19-06002.
Lewis-DIRECT 1
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4. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
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A. The purpose of my testimony is to sponsor Schedule H-CERT-17: Payroll,
Benefits and Pension Expense for the Test Period ended December 31, 2019,
and for the Certification Period ended May 31, 2020.
5. Q. PLEASE DESCRIBE SCHEDULE H-CERT-17.
A. In this and prior general rate review proceedings, Schedule H-CERT-17 shows
the calculation of annualized payroll, benefits and pension expense. The
annualizations that are calculated through Schedule H-CERT-17 are intended
to insure that revenue requirement reflects the ongoing costs of payroll,
benefits and pension expense.
Pages 1 through 4 of the Annualized Payroll reflect Nevada Power’s recorded
operations and maintenance (“O&M”) labor costs for the test year, as well as
the estimated change in annualized payroll costs attributable to Nevada
Power’s O&M activities as of May 31, 2020, the end of the certification
period. Annualized payroll costs reflect staffing and salary changes, overtime
estimates and other changes in compensation for regular and temporary
employees effective as of May 31, 2020.
Pages 1 and 5 of the Annualized Payroll reflect Nevada Power’s recorded
O&M benefit and pension expenses for the test year, as well as the estimated
change in annualized benefit and pension expenses attributable to Nevada
Power’s O&M activities in 2020. Annualized benefit and pension expenses
reflect anticipated increases in 401(k) contributions, health insurance cost
changes, and known and measurable 2020 pension costs effective as of
May 31, 2020.
Lewis-DIRECT 2
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6. Q. PLEASE DESCRIBE CHANGES THAT HAVE BEEN MADE TO H-
CERT-17, ALSO KNOWN AS THE “PAYROLL ANNUALIZATION,”
SINCE NEVADA POWER’S LAST GENERAL RATE REVIEW
FILING.
A. There was a change in accounting methodology related to non-service pension
costs, in compliance with ASC-715-20. Non-service pension costs can no
longer be capitalized, resulting in a decrease in O&M expenses of $1.736
million, as described in Statement P, and using the actuarial report amounts
from Willis Towers Watson. This change in accounting methodology was
presented in Sierra’s 2019 General Rate Case, Docket No. 19-06002, and
approved by the Commission.
In his testimony, Michael Behrens explains how pension costs are determined
from the Company’s actuary, Willis Towers Watson.
7. Q. PLEASE PROVIDE AN OVERVIEW OF THE RESULTS AND
DEVELOPMENT OF THE PAYROLL ANNUALIZATION.
A. The payroll annualization results in an increase in payroll expense of
$6.395 million as of the end of the certification period for the aggregate of
Nevada Power, Sierra, and the parent company, NV Energy, Inc., as compared
to test period results (see, H-CERT-17, page 3, line 17 through 31). The overall
increase between test period and certification period results was largely
generated at Sierra and Nevada Power, with a combined increase of
$7.668 million, which was offset by a $1.273 million decrease at the parent
company. The $6.395 million overall increase was allocated to Sierra, Nevada
Power, and the parent company using each entity’s test-year payroll
distribution percentages (i.e., by company and by accounts). The jurisdictional
Lewis-DIRECT 3
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allocated increase at Nevada Power was $2.429 million (see H-CERT-17, page
1, line 22).
8. Q. PLEASE EXPLAIN HOW COMMON FUNCTIONS OR
INTERCOMPANY PAYROLL CHARGES IMPACT NEVADA
POWER IN THIS SCHEDULE.
A. The payroll annualization schedule takes into account the following practices:
• Due to the utility holding company structure, Nevada Power
employees provide services that are either directly charged or allocated
to Nevada Power, its sister operating utility, Sierra, and/or its parent
company, NV Energy, Inc.; and
• Nevada Power also may receive direct or allocated charges from
employees of its sister operating utility and/or parent company as a
result of services their employees performed on behalf of Nevada
Power.
9. Q. PLEASE EXPLAIN THE CALCULATION OF THE THREE
INDIVIDUAL COMPANIES’ ANNUALIZED PAYROLL EXPENSE
ADJUSTMENTS.
A. The calculation of each individual Companies annualized payroll expense was
performed by determining the annualized payroll amount and subtracting the
recorded payroll.
Annualized Payroll: The annualized payroll calculation is composed of three-
parts:
1. The base pay salaries of regular employees were identified by company
as of January 1, 2020. Staffing levels were assumed to remain at the
January 1, 2020, level for purposes of the estimate as of May 31, 2020.
Lewis-DIRECT 4
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2. Overtime percentages for regular employees were calculated for non-
represented and represented employees based on test year data. The
analysis assumes that the same historic rates of overtime will continue
by each of the two Companies’ two employee classes going forward.1
These four overtime percentages are applied to regular employees’
base pay salaries by company and employee class to estimate the
respective overtime payroll.
3. Estimates of “Other” compensation, not included in base salaries, used
the test year data of each company. Again, the underlying assumption
is that historical occurrences or level of “Other” compensation will
continue by each of the three companies’ employees in the future.
“Other” compensation includes the actual cost of the Short-Term
Incentive Pay (“STIP”) payout in 2019 relating to the calendar year
2019 performance, with an adjustment to the December 2019 metrics
and reduction for the financial strength metric of the Berkshire
Hathaway Energy Company (“BHE”) scorecard. Various bonuses and
performance awards were removed from the case. Long-Term
Incentive Pay is included in the payroll annualization and removed in
total in a separate proforma, H-CERT-16. Please refer to the prepared
direct testimony of Jennifer Oswald for more information regarding the
overall compensation and benefits programs provided to the
companies’ employees.
1 Employees of NV Energy, Inc. do not receive overtime.
Lewis-DIRECT 5
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These components – base pay, overtime and revised historic “Other”
compensation – were summarized to arrive at the total annualized payroll by
company.
Recorded Payroll: The recorded payroll calculation is composed of two-parts:
1. The general ledger costs, identified as payroll through a unique
resource type (“RT”) coding, were compiled by individual company.
2. Certain payroll costs that were recorded without a unique RT coding
were identified by individual company as well.
The sum of the parts as described above makes up the recorded and adjusted
payroll for the test period.
Calculation: The calculation of each individual company’s annualized Payroll
Expense adjustment was performed by reducing each company’s annualized
payroll by its recorded and adjusted payroll. The “Grand Total” Payroll
increase in the aggregate amount of $6.395 million and the individual
company’s annualized Payroll adjustments are shown in H-CERT-17, page 3,
line 31.
10. Q. HOW WERE RECENT CHANGES IN THE COMPOSITION OF THE
EXECUTIVE TEAM REFLECTED IN THE PAYROLL
ANNUALIZATION?
A. At the time the payroll animalization was completed, there were no changes at
the executive level anticipated from January 1, 2020, to May 31, 2020.
Therefore, an adjustment was not made to annualized payroll for executives.
However, late in the preparation of the filing (May 14, 2020), Kevin Geraghty,
Lewis-DIRECT 6
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SVP, Operations, departed from the Company. This departure will be
addressed and adjustment proposed in the certification period filing.
An adjustment was made to remove certain items of other compensation paid
to any executives, such as signing bonuses, retention bonuses, performance
bonuses and severance payments. These reductions result in a lower amount
for “Other” compensation shown at H-CERT-17, page 3, line 11.
11. Q. PLEASE EXPLAIN THE REDUCTION TO STIP EXPENSES
A. In December of 2013, Sierra, Nevada Power and their parent company were
purchased by MidAmerican Energy Holding Company, now BHE. As such,
the companies have adopted the STIP corporate scorecard based on the six
core principals of business operation. In 2017, the corporate scorecard
financial strength metric had a weight of 16.70 percent. This metric was
eliminated within Statement N.
In Docket No. 17-06003, there was an additional decrease accepted for the
customer service metric to December 2017. This additional decrease was also
taken into account in Statement N.
In Docket No. 19-06002, Sierra’s 2019 general rate case, further STIP
adjustments were made to account for the difference between the amount paid
using the Q3 scorecard results and the end of year scorecard results. In order
to properly account for STIP in this case, STIP was reduced in H-CERT-17,
page 3, to the Q4 2019 scorecard of 65.28 percent and was further reduced for
the related financial strength metric of 8.33 percent for a total allowed STIP
of 56.95 percent compared to the amount funded of 90 percent. Therefore, the
Lewis-DIRECT 7
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entire STIP reduction is accounted for in H-CERT-17, page 3, to properly
allocate based on 2019 payroll.
As discussed above, Statement N also included adjustments for STIP using
2017 allocations. In order to account for adjustments one time, H-CERT-17,
page 2, accounted for the entire STIP reduction on page 3 and added back STIP
reductions from Statement N. This results in the cumulative impact of
Statement N and H-CERT-17 STIP requested in revenue requirement at 56.95
percent (December 2019 Scorecard of 65.28 percent less Financial Strength of
8.33 percent).
12. Q. PLEASE EXPLAIN THE ALLOCATION OF EACH INDIVIDUAL
COMPANY’S PAYROLL EXPENSE TO NEVADA POWER’S O&M.
A. The allocation of each individual company’s Payroll Expense was performed
by determining factors based on the historical payroll charging patterns of each
company by functional grouping. In other words, the companies (operating
utilities and parent) provide services to one another and directly charge and/or
allocate the associated payroll costs to each other as appropriate. Therefore,
just as payroll is not restricted to the originating or “home” company, the
Payroll Expense adjustments are not restricted to the home company. Thus,
Payroll Expense adjustments are allocated to each of the companies based on
the historical charging patterns of each company.
Lewis-DIRECT 8
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13. Q. WHAT IS THE TOTAL ADJUSTMENT TO NEVADA POWER’S
COST OF SERVICE THAT RESULTED FROM THE PAYROLL
EXPENSE CERTIFICATION ADJUSTMENTS?
A. The total cost of service increase is $2.277 million, as shown on H-CERT-17,
page 1, line 18. The aggregate of the three individual companies’ Payroll
Expense adjustment allocations to the Nevada jurisdiction’s portion of Nevada
Power’s O&M is an increase of $2.228 million as shown in H-CERT-17, page
1, line 18. A payroll tax adjustment of $0.201 million, as shown on H-CERT-
17, page 1, line 20, is added to the $2.228 million to arrive at a total increase
of $2.429 million.2
14. Q. PLEASE DESCRIBE THE BENEFITS PORTION OF THE
SCHEDULE.
A. Schedule H-CERT-17 on page 5 of 5 adjusts the cost of benefits expense. The
schedule aggregates the adjustments for the estimated net change in
medical/dental/vision costs (“Medical Costs”) and the 401(k) Company
matching costs as compared to the recorded costs during the test period. This
schedule reflects an aggregate decrease of $0.647 million, with a Nevada
jurisdictional cost of service decrease amount of $0.635 million as shown on
H-CERT-17, page 1, line 29. Please refer to Ms. Oswald’s pre-filed direct
testimony for more information concerning the companies’ overall
compensation and benefit plans.
2 Nevada Power expects to update this schedule at the end of the certification period.
Lewis-DIRECT 9
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15. Q. PLEASE DESCRIBE HOW ESTIMATED MEDICAL COSTS OR
HEALTH INSURANCE COSTS WERE DETERMINED FOR THE
PAYROLL PROFORMA.
A. For purposes of the schedule, Medical Costs were estimated by multiplying
the January 2020 accrual amount, adjusted for a one-time payment, by five
and adding the result to the amount booked for the last seven months of 2019.
Medical costs were then reduced by the test year recorded medical costs to
determine the decrease amount of $0.601 million, as shown on H-CERT-17,
page 5, line 3. This amount was then combined with the 401(k) Company
match and allocated to expense as shown on H-CERT-17, page 5, line 9. The
combined decrease of $0.647 million was brought forward to page 1 where it
was then allocated to the Nevada jurisdiction for a net adjustment decrease of
$0.635 million.
16. Q. PLEASE EXPLAIN THE 401(k) COMPANY MATCH ADJUSTMENT.
A. The adjustment for 401(k) Company match is based on the annualized cost of
Company matching contributions as compared to the recorded costs during the
test period. The total decrease amount of $0.522 million is shown on H-CERT-
17, page 5, line 5. This amount was then combined with the health insurance
increase and allocated to expense as shown on H-CERT-17, page 5, line 9. The
combined decrease of $0.647 million was brought forward to page 1, where it
was then allocated to the Nevada jurisdiction for a net decrease adjustment of
$0.635 million.3
3 The Company expects to update this portion of the adjustment at the end of the certification period.
Lewis-DIRECT 10
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17. Q. PLEASE DESCRIBE THE PENSION PORTION OF THE SCHEDULE.
A. This schedule includes the cost of retirement benefits for both active and
retired employees. Specifically, this schedule adjusts recorded test year costs
for Pension Service Costs and Pension Non-Service Costs, as accounted for
under ASC 715-20 and ASC 715-30. Within each pension cost classification,
there are pension costs, supplemental executive retirement program (“SERP”),
and Other Post-Employment Benefits (“OPEB”) as accounted for in ASC 715-
60. This schedule shows an aggregate decrease to the Nevada jurisdictional
cost of service in the amount of $3.961 million as shown on H-Cert 17, page
1, line 35.
18. Q. PLEASE EXPLAIN THE PENSION COST ADJUSTMENT.
A. The Pension Cost adjustment represents the difference between the annualized
costs of the Company’s retirement plan as compared to the recorded costs
during the test period—in this case a decrease in cost. The annualized cost, as
provided by the consulting actuaries, Willis Towers Watson, is Nevada
Power’s allocated share of the NV Energy’s Retirement Plan based on the
actuarial estimates for 2020.
The Pension Service Cost increase is $0.207 million, shown on H-CERT-17,
page 5, line 14. This amount was then combined with pension service costs for
the restoration and the post retirement adjustments, and allocated to O&M and
Nevada Power’s electric department. The result is an increase of
$0.142 million as shown on H-CERT-17, page 5, line 22.
The Pension Non-service Cost decreased $4.076 million, shown on H-CERT-
17, page 5, line 26. This amount was then combined with pension non-service
Lewis-DIRECT 11
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costs for the restoration and the post retirement adjustments. The entire
pension non-service cost expense is classified as O&M expense, in compliance
with ASC 715-20. See, Statement P for further details. The result is a decrease
of $4.178 million as shown on H-CERT-17, page 5, line 32.
The total pension service costs and total non-service pension costs adjustments
are summed to calculate a total pension cost decrease of $4.036 million as
shown on H-CERT-17, page 5, line 34. This amount is brought forward to
page 1, line 35, where it was then allocated to the Nevada jurisdiction for a net
decrease of $3.961 million.
In his testimony, Mr. Behrens explains how pension costs are determined from
the Company’s actuary, Willis Towers Watson.
19. Q. PLEASE EXPLAIN THE RESTORATION ADJUSTMENT.
A. Consistent with prior dockets, the restoration component of SERP has been
included in the calculation of annualized pension costs. The recorded
restoration costs exceed the annualized costs by $0.016 million, reflecting a
decrease of $0.015 million to pension service costs as shown on H-CERT-17,
page 5, line 16, and a decrease of pension non-service costs of $0.001 million
as shown on H-CERT-17, page 5, line 28. These amounts were then combined
with the pension and post retirement adjustments. The pension service costs
were allocated to O&M, however, non-service costs were all classified as
O&M expense in compliance with ASC 715-20. Nevada Power is not
requesting recovery of non-restoration SERP costs in compliance with past
Commission orders.
Lewis-DIRECT 12
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20. Q. PLEASE EXPLAIN THE ADJUSTMENT INCLUDED IN THIS
SCHEDULE REFERRED TO AS OPEB.
A. The OPEB adjustment represents an increase in OPEB costs as a result of the
difference between the annualized OPEB costs as compared to the recorded
costs during the test period. The annualized cost, as provided by the consulting
actuaries, Willis Towers Watson, is Nevada Power’s portion of the NV Energy
Post-Retirement Welfare Plan based on the actuarial estimates for fiscal year
2020.
The recorded OPEB costs exceed the annualized costs by $0.046 million,
reflecting an increase of $0.055 million to pension service costs as shown on
H-CERT-17, page 5, line 18, and a decrease of pension non-service costs of
$0.101 million as shown on H-CERT-17, page 5, line 30. These amounts were
then combined with restoration and pension adjustments. The pension service
costs were allocated to O&M, however, non-service costs were all classified
as O&M expense in compliance with ASC 715-20.
In his testimony, Mr. Behrens explains how pension costs are determined from
the Company’s actuary, Willis Towers Watson.
21. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A. Yes, it does.
Lewis-DIRECT 13
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Exhibit Lewis-Direct-1 Page 1 of 1
QUALIFICATIONS OF WITNESS Danielle Lewis
Project Manager – Finance NV Energy
6100 Neil Rd. Reno, NV 89511
Danielle Lewis has over 5 years of experience in various capacities at NV Energy, primarily focused on SEC financial reporting and accounting research. Mrs. Lewis has extensive knowledge of the application of Generally Accepted Accounting Principles and Federal Energy Regulatory Commission (“FERC”) accounting compliance. Mrs. Lewis has prepared and/or directed the preparation of various reports, analyses, and financial statements submitted to state jurisdictions, FERC and the Securities and Exchange Commission. Mrs. Lewis has previously testified in Sierra Pacific Power’s 2019 general rate case and has previously assisted in supporting testimony and data requests in prior filings before the Public Utilities Commission of Nevada.
EMPLOYMENT HISTORY
2018 to Present NV Energy Project Manager – Finance Prepared and reviewed financial data and testimony before the PUCN. Coordinate and execute special projects, including the implementation of lease accounting software.
2017 to 2018 NV Energy Manager, External Financial Reporting Responsibilities include compliance with the FERC Uniform System of Accounts, the SEC requirements and the requirements of other federal and state regulatory agencies. Reviewed and analyzed financial data for SEC and FERC reporting. Trained and supervised external reporting accounting staff.
2016 to 2017 NV Energy Manager, Financial and Regulatory Strategy
2014 to 2016 NV Energy Senior Technical Accountant
2010 to 2014 Grant Thornton, LLP Senior Audit Associate
2009 NV Energy Accounting Intern
EDUCATION
University of Nevada, Reno BS in Business Administration, Accounting major, Economics minor – 2009 Masters of Accountancy – 2010
CERTIFICATION
Certified Public Accountant Nevada CPA-5322 – Issued 2012, active status
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AFFIRMATION
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Pursuant to the requirements of NRS 53.045 and NAC 703.710, DANIELLE
LEWIS, states that she is the person identified in the foregoing prepared testimony and/or
exhibits; that such testimony and/or exhibits were prepared by or under the direction of
said person; that the answers and/or information appearing therein are true to the best of
his knowledge and belief; and that if asked the questions appearing therein, his answers
thereto would, under oath, be the same.
I declare under penalty of perjury that the foregoing is true and correct.
5/26/2020Date: ___________________________ ____________________________ DANIELLE LEWIS
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DEBORAH J. FLORENCE
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV Energy Docket No. 20-06___
2020 General Rate Case
Prepared Direct Testimony of
Deborah J. Florence
Revenue Requirement
I. INTRODUCTION BACKGROUND AND PURPOSE OF TESTIMONY
1. Q. PLEASE STATE YOUR NAME, TITLE AND ADDRESS.
A. My name is Deborah J. Florence. I am the Director of Corporate Taxes for NV
Energy Inc. (“NV Energy”), Nevada Power Company d/b/a NV Energy (“Nevada
Power” or the “Company”), and Sierra Pacific Power Company d/b/a NV Energy
(“Sierra” and together with Nevada Power the “Companies”). I am responsible for
all areas of taxation for Nevada Power and Sierra. I work primarily out of Sierra’s
corporate offices in Reno, which are located at 6100 Neil Road. I am filing testimony
on behalf of Nevada Power.
2. Q. PLEASE DESCRIBE YOUR HISTORY WITH NEVADA POWER.
A. With the merger of Nevada Power and Sierra as wholly owned subsidiaries of NV
Energy, I was promoted from a Senior Tax Analyst with Sierra to the Corporate Tax
Manager for the merged companies. On January 2, 2005, I was promoted to the
Director of Corporate Taxes.
Florence – DIRECT 1
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3. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE
INDUSTRY.
A. Before coming to Sierra in 1997, I worked for seven years in the Certified Public
Accounting firm of Deloitte & Touche, LLP. As tax manager there I was responsible
for all areas of tax compliance, research and planning for several large corporate
clients.
4. Q. PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND
PROFESSIONAL QUALIFICATIONS.
A. I have a Bachelor of Science Degree in Accounting and a Master of Science Degree
majoring in taxation, both from Weber State University. I am a Certified Public
Accountant in Nevada. I have included as Exhibit Florence-Direct-1 a complete
statement of my qualifications.
5. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. Yes. I have testified before the Commission in many proceedings, most recently in
Sierra’s 2019 general rate case (Docket No. 19-06002), Nevada Power’s 2017
general rate case (Docket No. 17-06003) and the hearing on the Company’s Tax
Rate Rider (Docket No. 18-02010).
6. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT TESTIMONY?
A. I am sponsoring the calculations of income taxes and taxes other than income taxes
in this general rate case filing. I have provided testimony on the calculation of
excess deferred taxes and the related Average Rate Assumption Method (“ARAM”)
adjustments.
Florence – DIRECT 2
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Specifically, I am sponsoring the following Statements and Schedules:
• Statement M, Calculation of Federal Income Tax for the Test Period Ended
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December 31, 2019.
• Schedule M-1, Reconciliation of Book Income to Taxable Income for the
Tax Year 2018 and the Three Preceding Years.
• Schedule M-2, Comparison of Tax Depreciation to Book. Depreciation for
the Tax Year 2018 and the Three Preceding Years.
• Schedule M-3, Consolidated Income and Deductions Summary for the Tax
Year Ended December 31, 2018.
• Schedule M-4, Monthly Book Balance of Accumulated Deferred Income
Taxes from January 2019 to December 2019.
• Schedule M-5, Taxes Other Than Income.
• Schedule H-CERT-08, Taxes Other Than Income for the Test Period. Ended
December 31, 2019, and for the Certification Period Ended May 31, 2020.
• Schedule H-CERT-09, Income Tax M-1 Items for the Test Period Ended
December 31, 2019, and for the Certification Period Ended May 31, 2020.
• Schedule H-CERT-10, Deferred Income Tax Expense for the Test Period
Ended December 31, 2019, and for the Certification Period Ended May 31,
2020.
• Schedule H-CERT-11, Income Tax Ratebase Adjustments for the Test
Period Ended December 31, 2019, and for the Certification Period Ended
May 31, 2020.
• Schedule H-CERT-15, Amortization of ITC and JDIC for the Test Period
Ended December 31, 2019, and for the Certification Period Ended May 31,
2020.
Florence – DIRECT 3
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• Schedule H-CERT-44 Excess ADIT Protected and Unprotected Regulatory
Liability.
• Schedule H-EC-9, Income Tax M-1 Items for the ECIC Period Ended
December 31, 2020.
• Schedule H-EC-10, Deferred Income Tax Expense for the ECIC Period
ended December 31, 2020.
• Schedule H-EC-11, Income Tax Ratebase Adjustments for the ECIC Ended
December 31, 2020.
• Statement P, Item 7. Presentation changes for ARAM.
7. Q ARE YOU SPONSORING ANY EXHIBITS?
A. Yes, I am sponsoring the following exhibits:
• Exhibit Florence-Direct-1 Statement of Qualifications
II. STATEMENTS AND SCHEDULES
8. Q. PLEASE DESCRIBE STATEMENT M AND SCHEDULES M-1 THROUGH
M-5.
A. Statement M has been prepared in accordance with sections 703.2411 through
703.2435 of the Nevada Administrative Code (“NAC”). Statement M shows the
computation of allowances for federal income tax for the 12 months ended May 31,
2020 along with related schedules that:
• Reconcile book and tax income for the last four filed tax returns (M-1).
• Detail the difference between tax and book depreciation for the last four filed
tax returns (M-2).
• Provide details of the last filed consolidated tax return (M-3).
Florence – DIRECT 4
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• Provide monthly balances by deferred income tax account for each month of
the test period (M-4).
• Provide details of taxes other than income taxes for the test period and the
projected period (M-5).
9. Q. PLEASE DESCRIBE SCHEDULE H-CERT-08.
A. H-CERT-08 shows the adjustment relating to taxes other than income for the change
between the test period ended December 31, 2019, and the certification period
ending May 31, 2020.
10. Q. PLEASE DESCRIBE SCHEDULE H-CERT-09.
A. Schedule H–CERT-09 reflects the tax adjustments for cost of service items for the
test and certification periods. The cost of service tax adjustments are divided into
two categories: permanent/flow-through and normalized. Permanent/flow-through
items are those which increase or decrease taxes based on the actual amount due to
the Internal Revenue Service (“IRS”). Adjustments for normalized items do not
increase or decrease total tax expense since offsetting deferred taxes are provided as
shown on Schedule H-CERT-10, which I describe below. The certification
adjustments shown on Schedule H-CERT-09 result from the annualization of certain
tax items and from the tax effect of other adjustments included in the test period.
11. Q. PLEASE DESCRIBE SCHEDULE H-CERT- 10.
A. Schedule H-CERT-10 reflects adjustments for deferred income taxes associated
with liberalized depreciation and various other normalized items as shown on
Schedule H-CERT-09. The certification adjustments shown on Schedule H-CERT-
Florence – DIRECT 5
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10 result from the annualization of certain tax items and from the tax effect of other
adjustments included in the test period.
12. Q. PLEASE DESCRIBE SCHEDULE H-CERT-11.
A. Schedule H-CERT-11 reflects the adjustment to rate base resulting from income
taxes generated by items included in rate base, such as deferred taxes on the
differences between book and tax depreciation.
13. Q. PLEASE DESCRIBE SCHEDULE H-CERT-15.
A. Schedule H-CERT-15 reflects the adjustments to the amortization of Investment Tax
Credit resulting from annualization.
14. Q. PLEASE DESCRIBE SCHEDULE H-CERT-44.
A. Schedule H-CERT-44 reflects the adjustment necessary to include the amortization
of unprotected excess deferred taxes over three years and the inclusion of ARAM
amortization on the protected balances of excess deferred income taxes.
15. Q. WHERE ARE THESE REPRESENTED IN STATEMENT H?
A. Both the current year ARAM amount and one year of the three year amortization for
the regulatory liability established by the order in Docket No. 18-02010 are included
on line 20, column (c) of Statement H page 2 of 6.
16. Q. PLEASE DESCRIBE THE PRESENTATIONS CHANGES IN STATEMENT
P ITEM 7.
A. Total flow through tax expense including all ARAM is now shown on line 11 of H-
Cert-09. The amount recaptured as required by the order in Docket No. 18-02010
Florence – DIRECT 6
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is shown on line 12 of H-Cert-09. The difference between the total flow through
and the amount recaptured is due to flow through not related to the 2017 Tax Cuts
and Jobs Act.
17. Q. HOW WAS THIS PRESENTED IN PRIOR RATE PROCEEDINGS?
A. Total flow through was included as part of liberalized tax depreciation and the
related deferred income taxes. This presentation is merely a reclassification to
provide easy reference.
18. Q. PLEASE DESCRIBE SCHEDULE H-EC-09.
A. Schedule H–EC-09 reflects the tax adjustments for cost of service items for the as
updated for the ECIC period.
19. Q. PLEASE DESCRIBE SCHEDULE H-EC-10.
A. Schedule H-EC-10 reflects adjustments for deferred income taxes associated with
liberalized depreciation and various other normalized items as shown on Schedule
H-EC-09 updated for the ECIC period.
20. Q. PLEASE DESCRIBE SCHEDULE H-EC-11.
A. Schedule H-EC-11 reflects the adjustment to rate base resulting from income taxes
generated by items included in rate base, such as deferred taxes on the differences
between book and tax depreciation as updated for the ECIC period.
21. Q. DOES THIS COMPLETE YOUR PREPARED DIRECT TESTIMONY?
A. Yes, it does.
Florence – DIRECT 7
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Exhibit-Florence-Direct-1 Page 1 of 1
STATEMENT OF QUALIFICATIONS
DEBORAH J. FLORENCE
My name is Deborah J. Florence. I am the Director of Corporate Taxes for NV Energy Inc.
(formerly Sierra Pacific Resources), Nevada Power Company and Sierra Pacific Power
Company. My business address is 6100 Neil Road, Reno, Nevada.
I graduated from the Weber State University in 1990 with a Masters of Science Degree majoring
in taxation and a Bachelor’s of Science Degree majoring in accounting. I am a Certified Public
Accountant in the state of Nevada.
From August of 1990 until April of 1997, I was employed by the Certified Public Accounting
firm of Deloitte & Touche LLP. As a tax manager, I was responsible for all areas of tax
compliance, research, and planning for several large corporate clients. I supervised up to 10 staff
members.
In April of 1997, I was employed by Sierra Pacific Power Company as a Senior Tax Analyst in
the Corporate Tax Department. In December of 2000, I was promoted to Corporate Tax Manager
for Sierra Pacific Resources. In January of 2005, I was promoted to Corporate Tax Director. I
supervise 7 people and I am responsible for all areas of taxation for Nevada Power Company,
Sierra Pacific Power Company and multiple subsidiaries.
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17
AFFIRMATION1
2
3 Pursuant to the requirements of NRS 53.045 and NAC 703.710,
4 DEBORAH FLORENCE, states that she is the person identified in the foregoing prepared
testimony and/or exhibits; that such testimony and/or exhibits were prepared by or under the
6 direction of said person; that the answers and/or information appearing therein are true
7 to the best of his knowledge and belief; and that if asked the questions appearing therein,
8 his answers thereto would, under oath, be the same.
=
I declare under penalty of perjury that the foregoing is true and correct. ..... Ei ; Qc.U .., 11
NEVADA POWER COMPANY D/B/A NV ENERGY LAS VEGAS, NEVADA
DIRECT TESTIMONY OF
HAROLD WALKER, III
CONCERNING LEAD-LAG STUDY
FOR DETERMINATION OF CASH WORKING CAPITAL
APRIL 2020
Prepared by: GANNETT FLEMING
VALUATION AND RATE CONSULTANTS, LLC
Valley Forge, Pennsylvania
Page 108 of 247
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA Nevada Power Company d/b/a NV Energy
2020 General Rate Case Docket No. 20-06___
Revenue Requirement
PREPARED DIRECT TESTIMONY OF
Harold Walker III
TABLE OF CONTENTS I. INTRODUCTION ......................................................................................................................... 1
II. SCOPE OF TESTIMONY............................................................................................................. 1
III. PRINCIPLES OF WORKING CAPITAL..................................................................................... 2
IV. SUMMARY OF WORKING CAPITAL ...................................................................................... 3
V. LEAD-LAG STUDY..................................................................................................................... 3
VI. RESULTS OF THE LEAD-LAG STUDY.................................................................................... 6
VII. CONCLUSION............................................................................................................................ 10
i
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I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME, AND BUSINESS ADDRESS AND THE
PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is Harold Walker, III. My business mailing address is 1010 Adams
Avenue, Audubon, Pennsylvania, 19403. I am filing testimony on behalf of Nevada
Power Company d/b/a NV Energy (“Nevada Power” or the “Company”).
2. Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?
A. I am employed by Gannett Fleming Valuation and Rate Consultants, LLC as
Manager, Financial Studies.
3. Q. WHAT IS YOUR EDUCATIONAL BACKGROUND AND EMPLOYMENT
EXPERIENCE?
A. My educational background, business experience and qualifications are provided
in Exhibit Walker-Direct-1.
II. SCOPE OF TESTIMONY
4. Q. WHAT IS THE SCOPE OF YOUR TESTIMONY
A. The purpose of my testimony is to recommend the appropriate electric revenue lag
days and expense lead days for the determination of the cash working capital
allowance, on which Nevada Power should be afforded an opportunity to earn as
part of its rate base for its Nevada jurisdictional electric service operations.1
1 The Company’s expense lead days include lead days for operations and maintenance expenses, taxes and interest expense.
Walker-DIRECT 1
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My recommendation is based upon the results of a lead-lag analysis conducted for
Nevada Power’s electric service operations. My testimony is supported by Exhibit
Walker-Direct-2.
III. PRINCIPLES OF WORKING CAPITAL
5. Q. WOULD YOU PLEASE EXPLAIN THE RATEMAKING PRINCIPLES
CONCERNING THE INCLUSION OF WORKING CAPITAL AS AN
ELEMENT OF RATE BASE?
A. Yes. The working capital allowance is a component of rate base. A utility’s need
to recover the cost of working capital was first recognized in the noted U.S.
Supreme Court case, Smyth v. Ames.2 Among the many benchmarks established
in the case was the “property devoted to public use doctrine” as a basis for fixing
rates. The case recognized that among the matters to be considered in determining
the value of property used was “the sum required to meet operating expenses.”3
Since that time, working capital required to meet operating expenses has generally
been recognized as a proper item to be included in the rate base on which a utility
is entitled to earn a return.
The rationale for the inclusion of operating working capital in rate base is to
compensate investors for the use of that amount of their funds over and above their
investment in plant. Operating working capital bridges the gap between the time
funds are provided by investors to meet operating expenses incurred to provide
service to customers, and the time the revenue is received from those customers as
reimbursement for the costs of these services.
2 Smyth v. Ames, 169 U.S. 466 (1898). 3 Id. at 547.
Walker-DIRECT 2
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IV. SUMMARY OF WORKING CAPITAL
6. Q. WHAT ARE THE COMPONENTS OF THE COMPANY’S WORKING
CAPITAL?
A. Nevada Power’s working capital is comprised of materials and supplies,
prepayments and “other” elements. My testimony presents the revenue lag days and
expense lead days used to determine the cash working capital component of the
Company’s total working capital. The materials and supplies, prepayments and
“other” elements of Nevada Power’s working capital are included in the direct
testimony of various Company witnesses. My recommended revenue lag days and
expense lead days are based upon the results of a lead-lag analysis conducted for
Nevada Power’s electric service operations. A summary of Nevada Power’s
revenue lag days and expense lead days is shown on page 2 of Exhibit Walker-
Direct-2.
V. LEAD-LAG STUDY
7. Q. WHAT DOES A LEAD-LAG STUDY MEASURE AND HOW IS IT
MEASURED?
A. The lead-lag study in this testimony measures the level of funding required to
operate on a day-to-day basis in providing for the cost of operations and
maintenance (“O&M”) expenses, taxes and interest expense. This is measured by
calculating the net lag between the amount of time elapsed between when a
company provides a service to its customers and when the company receives
payments from its customers, and the amount of time elapsed between when a
company receives goods and services and when the company pays its suppliers for
those goods and services. The difference between these two elapsed periods of time
is known as the “net lag.”
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The net lag is multiplied by the average daily cost of O&M expenses, taxes and
interest expense items to determine the cash working capital. Cash working capital
for O&M expenses, taxes and interest expense is included in rate base to
compensate investors for the use of their funds over and above their investment in
plant, and to provide investors with a return on the funds required by a company
for daily operations.
8. Q. WHAT ARE THE COMPONENTS OF A LEAD-LAG STUDY?
A. There are two primary elements of a lead-lag analysis: revenue lags and expense
leads. The revenue lag is the sum of two distinct components: the service period
lag and the payment lag.4 The revenue lag is the elapsed time between the delivery
of a company’s product to its customers and when a company receives payment for
the delivery of the product. Investor-provided funds are required to keep a
company running during the revenue lag time period, when the revenue stream is
temporarily insufficient to finance daily operational needs.
The expense lead is the sum of two distinct factors: the service lead and the payment
lead. The expense lead is the elapsed time between when a good or service is
provided to a company and when a company pays its supplier for the good or
service. During the expense lead time period, cash received from customers may
temporarily exceed a company’s payments to its suppliers for goods or services,
and the excess may be used to repay investor-provided funds. The net difference
between the revenue lag and expense lead denotes a company’s cash working
capital requirement.
4 The payment lag includes the billing lag and the collection lag.
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9. Q. WHAT TIME PERIOD DOES YOUR LEAD-LAG STUDY ENCOMPASS?
A. The lead-lag study in this case analyzed the revenues and the associated cost of
O&M expenses, taxes and interest expense during the 12 months ended December
31, 2019, (“Test Year”) to derive the appropriate lag (lead) days. While the lead
and lag days were calculated from Test Year results, the expenses that they are
applied to are for the Company’s certification period ended May 31, 2020.
10. Q. WAS THE LEAD-LAG STUDY THAT YOU CONDUCTED FOR THE
COMPANY PREPARED USING SIMILAR METHODS AND
TECHNIQUES IN PRIOR FILINGS?
A. Yes. The methodology used in the lead-lag study is fundamentally the same as that
used in the Company’s prior lead-lag studies filed with the Public Utilities
Commission of Nevada (the “Commission”). Although the same general
methodology has been utilized in prior lead-lag studies, over time, certain parts of
the approach have been adapted to reflect either changes in expense payment
practices by the Company, recommendations by the Commission’s Regulatory
Operations Staff, the Bureau of Consumer Protection and/or determinations by the
Commission.
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11. Q. WHAT DATA SET DID YOU UTILIZE IN YOUR LEAD-LAG STUDY?
A. The lead-lag study reflects information provided by the Company. Once the data
had been provided, data validation was performed by comparing an actual invoice
or a bill with data from Nevada Power’s systems to ensure accuracy.
The revenue lag data set was developed from each rate schedule. For rate schedules
with the largest customer counts, such as residential and general service, a statistical
sample was taken of random accounts selected using a computer model that queried
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the database containing customer billing information for each month of the test
year. The revenue lags for all other rate schedules were determined by analyzing
the individual lag days for all customers served under each rate schedule during the
test year.
The expense lead data sets were developed in a similar method and reflect the
service beginning and ending dates, the amount purchased, and the date of payment.
For the largest expense item (goods and services), a statistical sample was taken of
random accounts selected using a computer model that queried the database
containing vendor billing information for each month of the test year. The expense
leads for all other expense items were determined by analyzing the individual lead
days for all vendors in the account during the test year to reflect the service
beginning and ending dates, the amount purchased and the date of payment.
VI. RESULTS OF THE LEAD-LAG STUDY
12. Q. WHAT ARE THE RESULTS OF THE LEAD-LAG STUDY?
A. Page 2 of Exhibit Walker-Direct-2 sets forth the results of the lead-lag study and
summarizes the revenue lag days and the expense lead days. The revenue lag days
were determined to be 37.47 days and the various expense lead days, determined
by line item, range from 10.45 days to 372.33 days.
13. Q. PLEASE EXPLAIN THE PROCEDURES USED TO DETERMINE THE
REVENUE LAG.
A. Page 3 of Exhibit Walker-Direct-2 (Schedule I) summarizes the development of the
37.47 revenue lag days. The lag days for revenue is comprised of the service period
lag and the payment lag.
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14. Q. PLEASE EXPLAIN THE PROCEDURES USED TO DETERMINE THE
SERVICE PERIOD LAG DAYS FOR REVENUE.
A. The service period lag is the average time between actual meter readings of 30.42
days based on monthly billing (365 days ÷ 12 months). The average time between
meter readings, 30.42 days, is divided by two to produce a midpoint, or service
period lag of 15.21 days. A mid-point is used because it is assumed service is
provided evenly over the service period.
15. Q. PLEASE DESCRIBE THE PROCEDURE USED TO CALCULATE THE
PAYMENT LAG PORTION OF THE REVENUE LAG.
A. The payment lag is the average number of days from the meter read date and the
date customers’ payments are received. This was determined for each customer or
each customer sampled and produced in an average payment lag of 22.26 days for
the Company.
16. Q. PLEASE SUMMARIZE THE TOTAL REVENUE LAG.
A. The total revenue lag of 37.47 lag days for Nevada Power is shown on page 3 of
Exhibit Walker-Direct-2 (Schedule I). It includes a 15.21-day service period lag
and a payment lag of 22.26 days.
17. Q. PLEASE EXPLAIN THE CALCULATION OF EXPENSE LEAD DAYS
SHOWN ON PAGE 2 OF EXHIBIT WALKER-DIRECT-2.
A. The expense lead days shown on page 2 are comprised of three major sub-accounts:
O&M expenses, taxes, and interest expense. For the expense items shown, the lead
days were generally calculated for each invoice or account based on the midpoints
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of the service periods to the dates the Company paid the invoices or accounts.5
18. Q. HOW WERE THE LEAD DAYS DETERMINED FOR THE OTHER O&M
EXPENSES SHOWN ON PAGE 2 OF EXHIBIT WALKER-DIRECT-2?
A. For the other O&M expenses shown, the lead days were determined for each
invoice or account sampled based on the midpoints of the service periods to the
dates the Company paid the invoices or accounts based on the actual data or a
sampling of data.6
For example, the weighted average lead days for natural gas and natural gas
transportation expense equal 40.00 days and is developed on page 7 (Exhibit
Walker-Direct-2). The lead days for natural gas and natural gas transportation
expense were calculated for each invoice examined based on the midpoints of the
service periods to the dates the Company paid the invoices.
Similar analyses were conducted for other expense items: purchased power lead
days of 38.36 days are developed on page 8; goods and services (Nevada) lead days
of 35.85 days are developed on pages 9-14; labor lead days of 10.45 days are
developed on page 15; and leases expense lead days of 12.11 days are developed
on pages 29-30.
5 As was the case with the revenue service period, a midpoint was generally used for the service lead because it is assumed service is provided evenly over the service period. 6 For goods and services expenses, a statistical sample was taken of random accounts selected using a computer model that queried the database containing vendor billing information for each month of the test year.
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19. Q. PLEASE EXPLAIN HOW THE LEAD DAYS WERE DETERMINED FOR
THE GOODS AND SERVICES EXPENSE SHOWN ON PAGE 2 OF
EXHIBIT WALKER-DIRECT-2.
A. The goods and services expense line item lead days include a sampling of Nevada
Power invoices that were not included in the other O&M expense line items. The
supporting information used to determine the 35.85 lead days is shown on pages 9-
14 and reflects the sampling process described previously. The lead days for goods
and services were calculated as the difference between the payment date and the
actual beginning and ending service date for each voucher analyzed in order to
calculate lead days in accordance with Commission’s Order in Docket No. 08-
12002.
20. Q. HOW WERE THE LEAD DAYS DETERMINED FOR THE TAX
EXPENSES SHOWN ON PAGE 2 OF EXHIBIT WALKER-DIRECT-2?
A. For most of the taxes, the lead days were calculated based on the midpoint of the
tax liability period to the payment date, weighted by the actual amount paid. The
exception to this was income taxes, where the lead days were calculated based on
the midpoint of the tax period to the payment date, weighted by the percent of the
payment required. The taxes line items shown on page 2 include: mill tax expense
lead days of 145.58 (developed on page 16); possessory interest tax (Moapa)
expense lead days of 45.32 (developed on page 17); possessory interest tax
(Navajo) expense lead days of 214.33 (developed on page 18); Nevada use tax on
Purchasing Card (P Card) expense lead days of 15.27 (developed on page 19);
property tax (Arizona) expense lead days of 214.33 (developed on page 20);
unemployment tax expense lead days of 76.38 (developed on page 21); Nevada
modified business tax (MBT) expense lead days of 76.18 (developed on page 22);
FICA expense lead days of 11.00 (developed on page 23); franchise tax Nevada
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counties expense lead days of 372.33 (developed on page 24); federal income tax
(current) expense lead days of 37.00 (developed on page 25); and Nevada
commerce tax expense lead days of 225.61 (developed on page 28).
21. Q. HOW WERE THE LEAD DAYS DETERMINED FOR THE INTEREST
EXPENSES SHOWN ON PAGE 2 OF EXHIBIT WALKER-DIRECT-2?
A. For the interest expense line items shown, the lead days were calculated based on
the midpoint of the interest liability period to the payment date. The interest
expense line items shown on page 2 include: long-term debt expense lead days of
90.00 (developed on page 26) and deposits expense lead days of 105.00 (developed
on page 27).
VII. CONCLUSION
22. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A. Yes, it does.
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Professional Qualifications of
Harold Walker, III
Manager, Financial Studies
Gannett Fleming Valuation and Rate Consultants, LLC.
Exhibit Walker-Direct-1 Page 1 of 6
EDUCATION
Mr. Walker graduated from Pennsylvania State University in 1984 with a Bachelor of Science Degree in
Finance. His studies concentrated on securities analysis and portfolio management with an emphasis on
economics and quantitative business analysis. He has also completed the regulation and the rate-making
process courses presented by the College of Business Administration and Economics Center for Public
Utilities at New Mexico State University. Additionally, he has attended programs presented by The
Institute of Chartered Financial Analysts (CFA).
Mr. Walker was awarded the professional designation "Certified Rate of Return Analyst" (CRRA) by the
Society of Utility and Regulatory Financial Analysts. This designation is based upon education, experience
and the successful completion of a comprehensive examination. He is also a member of the Society of
Utility and Regulatory Financial Analysts (SURFA) and has attended numerous financial forums sponsored
by the Society. The SURFA forums are recognized by the Association for Investment Management and
Research (AIMR) and the National Association of State Boards of Accountancy for continuing education
credits.
Mr. Walker is also a licensed Municipal Advisor Representative (Series 50) by Municipal Securities
Rulemaking Board (MSRB) and Financial Industry Regulatory Authority (FINRA).
BUSINESS EXPERIENCE
Prior to joining Gannett Fleming Valuation and Rate Consultants, LLC., Mr. Walker was employed by
AUS Consultants - Utility Services. He held various positions during his eleven years with AUS,
concluding his employment there as a Vice President. His duties included providing and supervising
financial and economic studies on behalf of investor owned and municipally owned water, waste water,
electric, natural gas distribution and transmission, oil pipeline and telephone utilities as well as resource
recovery companies.
In 1996, Mr. Walker joined Gannett Fleming Valuation and Rate Consultants, LLC. In his capacity as
Manager, Financial Studies and for the past twenty years, he has continuously studied rates of return
requirements for regulated firms. In this regard, he supervised the preparation of rate of return studies in
connection with his testimony and in the past, for other individuals. He also assisted and/or developed
Nevada Use Tax on P Card 15.27 X Property Tax - AZ 214.33 Xl
Unemployment Tax 76.38 XII Nevada Modified Business Tax 76.18 Xlll
FICA 11.00 XlV Franchise Tax Nevada Counties 372.33 XV
Federal Income Tax 37.00 XVl Long-term Debt 90.00 XVll
Deposits 105.00 XVlll Nevada Commerce Tax 225.61 XIX
Leases 12.11 XX
Average 85.84
Count 21
(1) Coal and Diesel Oil historical costs are included but no Lag is calculated as there are no costs going forward.
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Exhibit Walker-Direct-2 Page 3 of 30
Nevada Power Company d/b/a NV Energy Schedule I Revenue Lag Days Lead Lag Study January 1, 2019 - December 31,2019
Total Recorded Rev Total Dollar Days Grand Total
R/S Count: 104
Total Lag Days: 37.47 Activity Total Total Midpoint Total Bill Payment Recorded Code Rate Schedule Dollar Days ARAPPL Calculation Lag Days Lag Lag Revenues Dollar Days
A. For the test period, Schedule H-CERT-06 recognizes the impact of changes in
rate base and capital structure on the level of interest charges included in the
calculation of FIT for the test period and the certification period. This schedule
also reflects the impact of the additional certification revenue requirement and
1 Revenues collected pursuant to the BTGR, BTER, R-BTER, Deferred Energy Accounting Adjustment (“DEAA”), special-purpose Renewable Energy Program Rate (“REPR”), Temporary Renewable Energy Development Rate (“TRED”), Energy Efficiency Program Rate (“EEPR”), and Energy Efficiency Implementation Rate (“EEIR”).
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incentive revenue requirement, which impact Cash Working Capital. Cash
Working Capital impacts rate base and rate base impacts interest expense.
Consistent with the Commission’s treatment in prior dockets, the sum of the
weighted debt components of the proposed rate of return (long- and short-term
debt, customer deposits and, where applicable, preferred stock) have been
applied to the appropriate rate base to arrive at the interest levels used for the
calculation of federal income tax liability in Statement H, page two.
A. Schedule H-2 allocates the total Nevada jurisdictional revenue requirement
from Statement H, page 1, column (k), to the three basic utility functions –
generation, transmission and distribution. The unbundled revenue requirement
serves as the basis for rate design. Schedule H-2 starts with the recorded results
of operations for the 12 months ended December 31, 2019, as allocated in
Statement N and summarized on Statement H, page 1, column (b). Based on
the detail provided in Schedules H-CERT-01 and H-EC-01, the certification
and ECIC adjustments are added to the recorded numbers. Finally, the
additional revenue requirement and the associated adjustments to mill tax,
uncollectible accounts expense, interest expense, federal income tax liability,
and cash working capital are added. The resulting values shown in column (g)
are allocated or unbundled into the three basic functions – generation,
transmission and distribution.
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30. Q. HOW WAS THE UNBUNDLED COST OF SERVICE CALCULATED
BY FUNCTION?
Most capital and a significant portion of the operation and maintenance
expenses are directly assigned to a specific function (generation, transmission
or distribution), based on FERC system of accounts classifications. Other
components, such as general and intangible plant and administrative and
general expense, are allocated using one of the ten allocators shown on page
19 of Schedule H-2. Similar to Statement N, the allocators for each component
are indicated next to the component.
31. Q. WHAT IS THE PURPOSE OF STATEMENT I?
A. Statement I is required by NAC § 703.2351 if the utility’s Statement H
contains estimated changes beyond the year of testing. Consistent with the
Commission’s rules, the certification filing will be made within 120 days of
the end of the Certification Period, May 31, 2020.
32. Q. PLEASE DESCRIBE STATEMENT J.
A. There are two Statements J included in this filing and are constructed in the
same fashion. The first is Statement J ECIC per NRS reflecting a $95.5
decrease in revenue requirement. Statement J Proposed reflects a revenue
requirement decrease of $120 million. The $95.5 million decrease Statement J
is prepared in accordance with NAC § 703.2355. Both Statements J provide
the comparison of recorded revenues, revenues at present rates and revenues
at proposed rates. Present and proposed rates revenues were developed by
applying the appropriate rates to annualized and weather-normalized billing
determinants for each customer class in the test period ending December 31,
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2019. The present rates use the rates in effect at April 1, 2020. Company
witness, Mr. Tim Pollard, addresses the proposed rates in Statement O that
result from Statement J.
As noted in Statement P, a presentation change was made since Docket No.
17-06003 with the elimination of Schedule J-3 that included the present and
proposed rate revenue for Merrill Lynch. The Merrill Lynch surcharge ended
effective June 30, 2019, in accordance with Docket Nos. 06-11035 and 17-
01014. Previous schedules J-4 through J-12 are now identified as Schedules J-
3 through J-11 with J-11 serving as the Typical Bill Calculation. In addition,
a new workpaper format presents the data in Excel tables instead of multiple
tabs per rate schedule which referenced external data sources. The underlying
calculations have remained the same.
Load forecasting provides the weather normalization data that consists of
monthly adjustment factors by major rate class. The weather adjustment
factors are based on a 20-year rolling average of heating and cooling degree
days consistent with the weather normalization methodology accepted for
integrated resource planning purposes. Statement J also addresses the level and
treatment of other Nevada jurisdictional revenues addressed below. The
present rates revenue from these calculations was the starting point for the
revenue requirements calculations. Finally, Statement J provides a separate
verification that the proposed rates calculated in Statement O generate the
requested revenue requirements.
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Statement J ECIC per NRS reflects that the impact of the proposed rates on all
residential customers is a decrease of 3.1 percent over present rates. For non-
residential customers, the decrease is 7.5 percent, and, for DOS customers, the
decrease is 3.6 percent. ECIC Statement J per NRS displays the percentage
and dollar changes in revenue by rate schedule within customer classes
reflecting a revenue requirement decrease of $95.5 million.
Statement J Proposed reflects that the impact of the proposed rates on all
residential customers is a 4.4 percent decrease over present rates. For non-
residential customers, the decrease is 8.7 percent and, for DOS customers,
the decrease is 4.8 percent. Statement J Proposed displays the percentage and
dollar changes in revenue by rate schedule within customer classes for the
Company’s request for a revenue requirement decrease of $120.0 million.
The Company will update both Statements J and related schedules at the end
of the certification period.
33. Q. BRIEFLY DESCRIBE SCHEDULES J-1 THROUGH J-12.
A. Schedule J-1 reflects present and proposed BTGR and BTER revenues.
Schedule J-2 compares present and proposed BTGR revenue for only the
BTGR component calculated from the annualized billing determinants shown
in column (b). In addition to BTGR per kWh, BTGR revenue includes basic
service, demand, facility and power factor charges and any other charges
shown in the statement of rates other than Universal Energy Charge (“UEC”)
and TRED. The UEC is remitted directly to the Commission and TRED
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collections are remitted directly to the TRED Trust, and so do not constitute
Company revenues.
Schedule J-3 shows the revenue resulting from the current BTER and the
DEAA rate when applied to the annualized billing determinants. The
annualized BTER revenue is included in the total revenue used to design rates.
Schedule J-4 shows the revenue resulting from the current REPR when applied
to the annualized billing determinants.
Schedule J-5 reflects the recorded revenues by rate schedule for the test period
ended December 31, 2019. The revenues were separated into BTGR, BTER,
DEAA, REPR, EEIR and EEPR.
Schedule J-6 reflects recorded customers, sales and revenues by month for the
test period. Included in this schedule are adjustments for unbilled sales and
other special items that occurred during the test period. Other Revenues –
Nevada are shown along with revenue credits and adjustments from Statement
N Nevada jurisdiction. The revenues from this table appear in Statement H and
Statement N Nevada jurisdiction as recorded revenues.
Schedule J-7 reflects changes in recorded kWh due to adjustments,
annualization and weather normalization. Annualization increased test period
volumetric consumption by 40,011 MWh and weather normalization increased
test period volumetric consumption by 167,789 MWh for a net increase to test
period volumetric consumption of 207,800 MWh or 0.94 percent.
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Schedule J-8 reflects the impact on total revenue of non-weather adjustments
and annualizations such as out-of-period adjustments, as well as the
incremental impact of weather normalization.
Schedule J-9 summarizes the recorded and annualized sales and bills for the
test period for each existing rate classification. The table portrays the effects
of annualization with respect to recorded sales. As shown in the table,
annualized sales for the test period total 22,334,668 MWh, an increase of 0.94
percent over recorded sales of 22,126,868 MWh. Average annualized
customers total 11,561,592, an increase of 0.92 percent over the test period
customers of 11,456,516. The annualized customer count of 11,561,592,
which includes Street and Outdoor Lighting, translates to 963,466 customers.
Schedule J-10 provides the present and proposed rate revenue for Energy
Efficiency Program and Implementation rates (excluding EEIR amortization
amounts that are reclassified to a balance sheet account).
Schedule J-11 reflects the typical bill calculation for residential single and
multi-family rates using the updated average usage.
34. Q. PLEASE DESCRIBE THE PRIMARY STEPS INVOLVED IN
DEVELOPING THE ANNUALIZED BILLING DETERMINANTS.
A. There are generally four steps involved in developing the annualized billing
determinants for all classes other than Street and Outdoor Lighting:
1. Recorded billing determinants are summarized by existing customer
classes. These billing determinants are generally comprised of the
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number of customers, kWh sales, kilowatt (“kW”) demand, facility
demand (kW), and billed kilovolt ampere-reactive hours (kVarh),
which pertain to power factor charges. For classes with time-of-use
(“TOU”) billing, the kWh and kW determinants are also detailed by
TOU period. Some classes also have contract demand determinants
and customer-specific facility charges.
2. The recorded billing determinants are adjusted, as necessary. Reasons
for adjustments to recorded amounts include:
i. Placing out-of-period adjustments reflected in the recorded
data into the correct month or seasonal period; and
ii. Correcting recorded entries that were the result of manual
input errors, misclassification of customers in the Company’s customer
information system, or bill corrections made after the recorded entries.
Also, any special adjustments or changes, usually for larger customers,
were individually reviewed to ensure the most representative monthly
sales level.
3. The resulting adjusted monthly kWh sales by class are then weather
normalized based upon the monthly weather-related adjustments to
recorded sales estimated by Resource Planning. Only the kWh billing
determinants are adjusted for weather. The kWh sales for certain
classes such as street lighting, outdoor lighting, standby energy use,
water pumping, and applicable distribution-only are not weather
adjusted because their loads are deemed to be insensitive to weather.
4. The adjusted determinants (and in the case of kWh sales, the adjusted
and weather normalized billing determinants) are then annualized. For
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example, kWh sales for each class other than street and outdoor
lighting are annualized by using the following methodology:
i. The average kWh sales per customer is calculated for
each month during the test period and by TOU period as applicable;
ii. The monthly average kWh sales per month are
multiplied by the customer count at the end of the test period; and,
iii. The revised kWh for each month is then summed
together to obtain the annual sales for the test period.
This same annualization methodology is used for the kW demand (by TOU
period as applicable), the non-customer specific facilities kW, and billed
kVarh (power factor) determinants. As indicated, the annualized customer
count is the number of customers in the class in the last month of the test
period.
35. Q. WHAT SPECIAL ADJUSTMENTS OR CHANGES IN ANNUALIZED
SALES WERE PERFORMED FOR LARGER CUSTOMERS?
A. Two NRS Chapter 704B customers will use alternative energy provider(s) post
test period. An adjustment included the removal of these customers from their
respective retail rate schedules, annualizing their usage and re-classifying
them to their appropriate DOS schedule.
Adjustments were performed for two prospective large customers expected to
connect post test period. Estimated loads were calculated, annualized, and
added to the appropriate rate schedules.
Trigero-DIRECT 26
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36. Q. PLEASE EXPLAIN HOW LIGHTING REVENUES WERE
ANNUALIZED.
A. The General Service (“GS”) and Residential Service (“RS”) and Private Area
Lights (“PAL”) are flat-rate lighting services. The kWh sales to flat-rate
lighting customers were derived in two steps:
i) For each class, the test period ending lamp (or bulb) count is multiplied
by 12 to get the annualized number of lamps in the class and;
ii) The “rated” monthly kWh consumption for each class for the type of
lamp is multiplied by the annualized number of lamps.
The sum of kWh sales calculated for each class is the total annualized kWh for
the respective RS and GS PAL classes. The present rate BTER annualized
revenues for the RS-PAL and GS-PAL classes were then computed as the
product of the annualized kWh determinants and the present BTER. Similarly,
present rate BTGR revenues were calculated for each lighting class as the
product of the annualized number of lamps and the present BTGR monthly
rate per lamp.
Flat-rate Street Lighting Services were annualized in the same manner as the
PAL lighting services.
37. Q. PLEASE DESCRIBE HOW YOU DEVELOPED THE “OTHER
REVENUES” USED IN THE PRESENT AND PROPOSED RATE
CALCULATIONS.
A. The following annualized adjustments have been made to “Other Revenues”:
• Account 450000, Forfeited Discounts, contains the revenue from late
charges on overdue bills.
Trigero-DIRECT 27
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• Account 451000, Miscellaneous Service Revenues, consists largely of
connection service fees.
• Accounts 451020/030 reflect return check charges and miscellaneous
damage charges.
• Accounts 451080/085 reflects an annualized figure for the initial and
monthly fees for non-standard meter option.
• Account 451091, Flexpay Monthly Fee, consists of fees associated with
the Flexpay program.
• Account 456001, Other Elec Rev–Policy Adjust, has a debit balance for
the test period and has been removed from revenue requirement. It
represents miscellaneous billing adjustments.
• Account 456002, Other Electric Rev–Misc., has been annualized to
remove all test period revenue, which related to expiring amortizations and
contracts, and to include amortizations calculated on H-CERT-37, H-
CERT-38.
• Account 456003, Retail Open Access Impact Fees, represents the impact
fees calculated on H-CERT-47 and H-CERT-48.
• Account 456006, Other Elec Rev-Rate Correction, has a debit balance for
the test period and has been removed from revenue requirement. It
represents miscellaneous billing corrections.
38. Q. PLEASE DESCRIBE STATEMENT K, OPERATIONS AND
MAINTENANCE EXPENSE.
A. This statement is co-sponsored with Mr. Behrens. Statement K is a seven-page
statement, the first page of which depicts the Company’s total recorded
operations and maintenance expense for the test year, by functional
Trigero-DIRECT 28
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classifications of primary accounts. The first page also reflects a summary of
Statement N adjustments and the additions of certification adjustments. Pages
two, four and six were comprised of monthly recorded expenses by primary
accounts, grouped into their functional classifications. Pages three, five and
seven show the operating and maintenance amounts starting with recorded
data, Statement N regulatory adjustments, and conclude with the addition of
certification adjustments and ECIC adjustments.
39. Q. PLEASE DESCRIBE SCHEDULE K-1, ANALYSIS OF LABOR
COSTS.
A. This statement is co-sponsored with Mr. Behrens. Schedule K-1 categorizes
the recorded operations and maintenance expenses reported in Statement K
into labor expense and other expenses. Page one begins with recorded data,
adds in Statement N regulatory adjustments, and concludes with the addition
of certification adjustments and ECIC adjustments. Page two shows the
recorded test period expenses by month by functional classifications.
40. Q. PLEASE DESCRIBE STATEMENT L.
A. Statement L provides a summary of Nevada Power’s plant depreciation and
amortization expense by functional classifications through the test period
ended December 31, 2019, and the certification period ending May 31, 2020,
and the ECIC Period ending December 31, 2020.
Trigero-DIRECT 29
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41. Q. PLEASE DESCRIBE THE INFORMATION CONTAINED IN
STATEMENT N.
A. Statement N contains a summary of the Company’s adjusted results of
operations for the twelve months ended December 31, 2019, and is the starting
point and source for most of the statements and schedules from which annual
revenue requirement is calculated. Each page includes:
• The recorded values from the books and records of the utility;
• Adjustments to reflect regulatory treatment that is not otherwise recorded
on the books; and
• The allocation of the amounts between Nevada Power’s FERC
jurisdictional and Nevada jurisdictional customers.
As noted in Statement P, there was a presentation change made to schedules
with data labeled as Amortization of ITC. Excess Accumulated Depreciation
Income Taxes (“ADIT”) will be added where appropriate as Excess ADIT is
being introduced in this general rate case. Additionally noted in Statement P,
page 17 of Statement N has been updated to segregate leases into two
categories labeled as Lease – General Office and Lease Transmission. This
assigned an expense lead for leases of 12.11. The impact of this change
resulted in a rate base deduction of $11.6 million compared to a reduction of
$14.7 million using the current treatment. The expense lead day calculation is
by Company witness Mr. Walker III.
Trigero-DIRECT 30
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42. Q. PLEASE DESCRIBE THE NEVADA JURISDICTIONAL PORTION
OF STATEMENT N.
A. The results of operations and rate of return calculations for Nevada Power’s
Nevada and Federal electric jurisdictions are shown on Statement N. The
adjustment to rate base for the cash working capital allowance and the interest
synchronization for FIT calculations also are included. The allocation
methodology used in this schedule follows the methodology recommended by
the National Association of Regulatory Utility Commissioners in their Cost
Allocation Manual and is more fully set forth in Exhibit Trigero-Direct-2.
43. Q. HAVE ANY ADJUSTMENTS BEEN MADE TO THE ALLOCATORS
USED IN STATEMENT N?
A. No.
44. Q. PLEASE DESCRIBE SCHEDULE M-5, TAXES OTHER THAN
INCOME.
A. Schedule M-5 lists taxes other than income recorded and allocated at
December 31, 2019, certification adjustments estimated at May 31, 2020, and
adjustment for the ECIC Period ending December 31, 2020.
45. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A. Yes, it does.
Trigero-DIRECT 31
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Exhibit Trigero-Direct-1 Page 1 of 2
QUALIFICATIONS OF WITNESS
BILL TRIGERO
I graduated from University of Nevada, Reno with a Bachelor of Science Degree
in Accounting. Prior to coming to Sierra Pacific I held positions at Nevada National
Bank and International Game Technology.
I began working at Sierra Pacific Power Company, now known as NV Energy, in
1985. During the course of my employment at Sierra, I have held muliple positions.
Accountant in Regulatory Accounting – 1985 to 1986
Accountant/Senior Accountant in Accounting Systems and Development –
1986 to 1990
Financial Planning Analyst/Team Leader in Finance – 1990 to 1995
Pipeline Accounting Analyst working for Tuscarora Gas Transmission
Company - 1995 to 1996
Transmission Group Controller – 1996 to 1998
Distribution Group Controller – 1998 to 1999
Financials Team Lead overseeing the implementation of Nevada Power
and Sierra’s accounting system (PeopleSoft) – 1999 to 2000
Accounting Manager for Sierra Pacific Communications – 2000 to 2001
Staff Analyst in Rates and Regulatory Affairs – September 2001 to March
2008
Supervisor, Regulatory Accounting – March 2008 to January 2015
Project Manager, Transmission Project Delivery – January 2015 to
December 2015
Director, FERC Compliance – December 2015 to March 2020
Director, Regulatory Accounting, Revenue Requirements and FERC -
April 2020 to present
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Exhibit Trigero-Direct-1 Page 2 of 2
I have sponsored and/or prepared testimony and exhibits for proceedings held
before the Nevada Public Service Commission, California Public Utilities Commission,
and the Federal Energy Regulatory Commission.
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EXHIBIT TRIGERO-DIRECT- 2
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Exhibit Trigero-Direct-2 Page 1 of 3
NEVADA POWER COMPANY d/b/a NV Energy
COST ALLOCATION METHODOLOGY
1. Nevada Power Company (“Nevada Power”) is a regulated public utility engaged primarily in the generation, purchase, transmission, distribution and sales of electricity in Nevada. The electric utility department operates under the jurisdiction of the Public Utilities Commission of Nevada (“PUCN”) and the Federal Energy Regulatory Commission (“FERC”).
2. Nevada Power maintains its accounting records in accordance with the uniform system of accounts for such utilities as prescribed by Code of Federal Regulations (“CFR”).
3. In its "Preface" to the 1973 National Association of Regulatory Utility Commissioners (“NARUC”) Electric Utility Cost Allocation Manual, the Subcommittee on cost allocation states:
A uniform method of cost allocation for electric utilities operating under the jurisdiction of more than one regulatory agency is required if neither the public or the utility is to suffer by reason of inconsistent or incompatible action. A reasonable method should be agreed upon by the several regulatory jurisdictions and implemented by the utility in each area. The sum of the jurisdictional pieces allocated by a reasonable method should equal the jurisdictional total -no more and no less.
The allocation methodology described herein has been submitted to and accepted by the PUCN and closely follows the methodology recommended by NARUC.
4. Under the allocation methodology described herein, costs are classified into the basic components demand, energy, customer, or some composite thereof, for allocation purposes. Demand-related costs are those costs which relate to peak usage of electricity. These costs are generally referred to as fixed costs because they remain constant regardless of the amount of energy delivered by the system. Energy-related costs are those which vary directly with the quantity of energy produced and delivered. Customer-related costs are those which vary with the number of customers served.
5. These three dimensions, demand, energy and customers, provide the basis for the jurisdictional allocation of the majority of the Electric Department costs, both capital and operating. The jurisdictional responsibility for demand-related costs is based on the contribution to twelve monthly peaks. Transmission Demand is the sum of twelve monthly transmission system loads and Production demand is the sum of the twelve monthly system peaks. The jurisdictional responsibility for energy-related costs is determined by the sum of twelve months recorded sales and their relationship to output to lines for the same period. Because Nevada
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Exhibit Trigero-Direct-2 Page 2 of 3
Power is a retail energy provider solely within the State of Nevada, customer-related costs are directly assigned to the Nevada Retail jurisdiction. These ratios are primary allocation ratios and the combination of two or more of these primary ratios are a composite ratio.
6. All costs do not fall neatly into the three classifications listed above. Generally, such costs are allocated only after all basic costs have been apportioned to the appropriate jurisdiction. These costs fall into a category which follows proportionately the direct initial allocation of functional costs. Allocation ratios calculated as the sum of specific previously allocated accounts are secondary ratios.
7. Net Production Plant and related operating expense for steam and other power production, with the exception of fuel, is classified as demand-related. Other power supply expenses, excluding energy costs for purchased power, are also demand- related. The Production Demand allocator is contribution to system peak. Fuel, energy costs for purchased power and all production maintenance expense are energy-related.
8. Net Transmission Plant, its associated operation and maintenance expense (with the exception of Account No. 565), and depreciation expense are classified as demand-related. The Transmission allocation is based on the Transmission System Load as described in the NV Energy Operating Companies Open Access Transmission Tariff (“OATT”). Transmission System Load is the sum of the contribution to peak of all Network Customers (including Nevada Power’s native load) plus the contract demands of all long-term firm point-to-point customers. The four coincident peaks of June, July, August, and September (“4CP”) are used to calculate the transmission demand allocator. Patricia Franklin addresses the use of the 4CP in her direct testimony. Short-term and non-firm transmission transactions are treated as revenue credits. Account No. 565, Transmission by others, is associated with Account No. 555, Purchased Power, and is recovered in Deferred Energy Accounting.
9. Net Distribution Plant and its associated operation and maintenance expense and depreciation expense are Nevada jurisdictional.
10. Net General Plant and depreciation expense are allocated jurisdictionally on a ratio based on functionalize labor expense.
11. Net Intangible Plant and depreciation expense are allocated jurisdictionally on a ratio based on functionalized labor expense.
12. Other additions and deductions to rate base are allocated based on the items that give rise to them. For example, Materials and Supplies-Fuel is allocated on energy, as is Fuel Expense.
13. Customer Accounts Expense and Customer Service and Information Expense are assigned to the Nevada jurisdiction.
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Exhibit Trigero-Direct-2 Page 3 of 3
14. Administrative and General Expenses are allocated to jurisdictions using secondary allocation ratios based on Plant and/or Expenses. Regulatory Commission Expense and Resource Planning Expenses are directly assigned.
15. Allocation of Taxes other than Income Taxes, Deferred Income Taxes, Investment Tax Credits, and Schedule M Tax Adjustments are based on the item which gives rise to the tax or tax adjustment.
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Page 197 of 247
TERRY A. BAXTER
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV EnergyDocket No. 20-06___
2020 General Rate Case
Prepared Direct Testimony Of
Terry A. Baxter
Revenue Requirement
1. Q. PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
ADDRESS.
A. My name is Terry A. Baxter. I was Manager of Load Forecasting at Nevada
Power d/b/a NV Energy (“Nevada Power” or the “Company”) and Sierra
Pacific Power Company d/b/a NV Energy (“Sierra,” and together with Nevada
Power, the “Companies”) from July 9, 2007, through May 8, 2019. I have since
retired from Nevada Power, but I consult for Yoh, a Day and Zimmerman
Company. I am supporting the load forecast function for the Company. More
details regarding my professional background and qualifications are set forth
in Exhibit Baxter-Direct-1. I am filing testimony on behalf of Nevada Power.
2. Q. WHY ARE YOU STILL WORKING FOR THE COMPANIES?
A. Due to the timing of my retirement, and my involvement in developing the
weather normalized sales for this filing as well as the load forecast for
upcoming filings, I was retained by the Company to support the load forecast
for 2020.
Baxter-DIRECT 1
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3. Q. WHAT WERE YOUR RESPONSIBILITIES AS MANAGER OF LOAD
FORECASTING?
A. As the Manager of Load Forecasting for Nevada Power, my primary
responsibilities included forecasting sales volume, customer counts and peak
demand for use in development of financial budgets, sales weather
normalization for general rate cases (“GRC”), Energy Supply Plans (“ESP”)
and Integrated Resource Plans (“IRP”).
4. Q. PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND
AND EMPLOYMENT EXPERIENCE IN THE UTILITY INDUSTRY.
A. I hold a Master of Arts in Economics from the University of Arkansas located
in Fayetteville, Arkansas, and a Bachelor of Science in Economics from the
University of Missouri at Rolla (now Missouri University of Science and
Technology) located in Rolla, Missouri. Prior to my time at NV Energy, I
served as the Manager of Forecasting and Economic Analysis at Alliant
Energy in Cedar Rapids, Iowa, for nine years, where I was responsible for load
and revenue forecasting and load research. Prior to that, I was a Group
Manager for seven years with Aspen Systems Corporation (now a division of
Lockheed-Martin) overseeing analytical consulting projects for utilities and
the U.S. government. I also have served as Manager of Load Research at
Midwest Resources (now MidAmerican Energy Company) and as the Load
Research Analyst at Missouri Public Service Company (now a part of Kansas
City Power and Light Co., a division of Great Plains Energy). I have submitted
reports and testimony regarding load forecasting and load research before the
Iowa Utilities Board, the Wisconsin Public Service Commission, the Illinois
Commerce Commission, the Minnesota Department of Commerce, the
Baxter-DIRECT 2
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California Energy Commission, the California Public Utilities Commission
and the Public Utilities Commission of Nevada (“Commission”).
5. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA?
A. Yes, I have testified in numerous proceedings before the Commission, most
recently in the Companies’ 2018 Joint IRP, Docket No. 18-06003, the Second
Amendment to the 2018 Joint IRP, Docket No. 19-05002 and the Sierra’s 2019
GRC, Docket No. 19-06002.
6. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. The purpose of my testimony is to sponsor the weather normalization of test
period sales included in Statement J, Schedule J-7 – Annualized kWh with
Weather Normalization Contribution for the Test Period Ended December 31,
2019. The remainder of Statement J will be sponsored by Nevada Power
witness William Trigero.
I also sponsor the following exhibit that is attached to my testimony:
• Exhibit Baxter-Direct-1 – Statement of Qualifications.
7. Q. ARE ANY OF THE MATERIALS YOU ARE SPONSORING
CONFIDENTIAL?
A. No.
Baxter-DIRECT 3
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8. Q. PLEASE EXPLAIN THE WEATHER NORMALIZATION OF
REVENUES PERFORMED IN THIS CASE.
A. Weather normalization of historic consumption and revenue data is an
accepted practice at Nevada Power. Peak demand and energy consumption
must be weather normalized when preparing a forecast to be used in preparing
an IRP. The Commission has also accepted the use of weather normalized sales
in preparing projections or estimates of sales for use in Statement J in Nevada
Power’s last general rate case (“GRC”), Docket No. 17-06003. Similarly, the
same weather normalization techniques used to prepare peak demand and
energy consumption forecasts in an IRP were used to prepare projections or
estimates of sales under normal weather conditions.1
9. Q. BRIEFLY EXPLAIN HOW SALES WERE WEATHER
NORMALIZED FOR THIS CASE.
A. As in IRP filings, a rolling 20-year period was used to calculate normal degree
days, cooling degree days (“CDD”) and heating degree days (“HDD”). For the
purposes of this proceeding, the 20-year normal period was January 2000
through December 2019. To normalize residential load, the Company used
CDD with base 70 and 80.2 This test year was slightly cooler than the normal
weather. Table Baxter-Direct-1 below shows the difference between the
recorded and normal temperature.
1 For example, refer to Technical Appendix LF-1, Volume 5 of 18 pages 54-55, in the 2018 Joint IRP, Docket No. 18-06003. 2 CDD is measured by taking the difference of the recorded temperature with the CDD base temperature. If the difference results in a negative value, then it is replaced with 0. For example, if the recorded temperature is 90, then the CDD70 is 20, and, if the recorded temperature is 65, then the CDD70 is 0. It should be noted that, for the residential class, the Company used CDD70 and CDD80 in the weather normalization model (vs. CDD75 in the 2018 GRC) to capture the nonlinear relationship between cooling weather and electricity consumption. Additionally, the Company utilized HDD60 (vs. HDD55 in the 2017 GRC) to normalize for heating weather as that model had slightly better model statistics than the HDD65 used in the 2017 GRC model.
Baxter-DIRECT 4
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Table Baxter-Direct-1
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CDDs and HDDs for Test Period Ending December 31 , 2019
Recorded Normal Difference =
Recorded –
Normal
CDD 70 2,729 2,854 -125
CDD 80 1,312 1,316 -4
HDD 60 1,130 1,078 52
Nevada Power’s load forecasting department ran multiple regression models
using monthly billed sales data for the 10-year historical period 2010 through
2019 for the residential single family, residential multi-family, GS, LGS-1,
and LGS-2 and LGS-3 (combined – designated “LGS2/3”) rate classes. In
each model, billing cycle CDDs and HDDs were independent variables used
to explain the variation in monthly sales caused by the weather. The
coefficients of these variables measure the estimated change in sales per
customer (or total sales for the LGS 2/3 class) for a one unit change in degree
days. Certain classes that are not sensitive to weather were not weather
normalized, e.g. street lighting, outdoor lighting, and public authority. Where
applicable, distribution-only service sales were included in the appropriate
weather normalization model.
Nevada Power’s load forecasting department uses a standard process to
develop weather normalized sales. The steps included:
• Derive the difference between the actual and normal degree days for
each month;
Baxter-DIRECT 5
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• Multiply the difference obtained above by the estimated weather
coefficient(s) for that month (the slope estimate); and
• Add the value from the step above to the monthly sales per customer
(or total sales). Multiply the monthly sales per customer times the
monthly customer count to obtain the monthly class weather
normalized sales.
This process was applied to the monthly sales by rate class for 2019 and a
monthly factor measuring the ratio of weather normalized to actual billed sales
was developed. This factor was then applied to the monthly billing
determinants to obtain the sales used in preparing Statement J.
10. Q. WHAT ARE THE IMPACTS OF WEATHER NORMALIZATION ON
TEST PERIOD SALES?
A. Schedule J-7 shows changes in recorded kilowatt-hours (“kWh”) due to
weather normalization. Weather normalization increased test period sales by
167,789,133 kWh, or less than one percent.
11. Q. IN SIERRA’S 2019 GRC, THE COMMISSION ORDERED SIERRA TO
USE A 20-YEAR TREND ANALYSIS TO ACCOUNT FOR THE
WARMING TREND IN TEMPERATURES IN SIERRA’S SERVICE
TERRITORY. HAVE YOU PERFORMED ANY SIMILAR ANALYSES
FOR NEVADA POWER?
A. In Sierra’s GRC, the Commission found that a 20-year trend methodology
captured a warming trend in Sierra’s service territory that was different than
Sierra’s 20-year weather normalization average. To determine the potential
differences in this case, Nevada Power contracted Itron, Inc. (“Itron”), a
Baxter-DIRECT 6
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consulting firm it has used in the past to assist in forecasting and weather
normalization tasks, to examine the temperature history at McCarran Airport
in Clark County using a method it developed to study long term temperature
trends and the impact on system loads. Itron’s analysis shows a strong
warming trend for the average daily temperature from 1970 to 2019, indicating
an increase of 0.11 degrees per year, or 1.1 degrees per decade. In addition, its
analysis shows the annual maximum temperature has been increasing 0.19
degrees per decade, although that trend does not exhibit strong statistical
significance. Further, the analysis shows the annual minimum temperature is
experiencing a strong statistical temperature increase trend of 2.74 degrees per
decade. Itron’s conclusion is that average temperature is rising mainly because
the minimum temperature is increasing, not the maximum temperature. The
Prepared Direct Testimony of Mr. Eric Fox provides a description of the
analysis on weather trends and how to employ the results in developing
weather normalization.
12. Q. GIVEN THE ANALYSES DESCRIBED ABOVE, WHY DID NEVADA
POWER CONTINUE USING THE ROLLING 20 YEAR AVERAGE IN
ITS WEATHER NORMALIZATION ANALYSIS?
A. Nevada Power decided to use rolling 20 year average as a reasonable method
to define normal weather consistent with previous IRP filings as well as
general rate review proceedings since 2000 while research and analysis by
Itron was in progress. The use of weather normalization impacts the
adjustment to billing determinants as well as the forecast, both are inputs into
the general rate case (“GRC”). The forecast and the weather normalization
adjustments were delivered in late February for input to the GRC. The forecast
went to Resource Planning to support development of the probability of peak
Baxter-DIRECT 7
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and loss of load probability inputs to Marginal Cost of Service study (“MCS”).
The weather normalization factors delivered to the Regulatory Accounting
team completing Statement J.
Discussions with Itron regarding research and analysis of average weather in
Nevada began at the end of January. In early February, Itron completed an
initial review of historical weather and then provided a list of data inputs they
needed to complete a full analysis, which the Company provided by mid-
February. Using those inputs, Itron has been developing trended normal degree
days for various bases for Nevada Power using a detailed analysis of the
historical temperature data. However, a complete analysis of the weather
normalization adjustment factors and a revised forecast using the trended
normal degree days could not be complete before input were due by the end
of February. The methodology and results of the trended normal degree days
is described in the testimony of Mr. Fox of Itron. These normal degree days in
addition to the forecast reflecting trended normal degree days will be
employed as inputs in the Certification filing,
13. Q. WHAT IS YOUR RECOMMENDATION REGARDING THE USE OF
THE ITRON TRENDED NORMAL WEATHER FOR USE IN
WEATHER NORMALIZATION OF TEST YEAR SALES?
A. The previously approved rolling 20 year average definition of normal weather
provided in the direct filing is a reasonable methodology the Commission
could utilize. However, after reviewing the work performed by Itron, the
Company recommends adopting the use of the trended normal weather as
discussed in the testimony of Mr. Fox to weather normalize test year sales as
a more appropriate methodology. A full comparison of the results of both
Baxter-DIRECT 8
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methodologies and the respective impact on billing determinants will be
included in the certification filing.
14. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A. Yes, it does.
Baxter-DIRECT 9
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STATEMENT OF QUALIFICATIONS OF
TERRY A. BAXTER
Education Master of Arts University of Arkansas, Fayetteville, AR, 1979, Economics Bachelor of Science University of Missouri-Rolla, Rolla, MO, 1976 Economics
Related Professional Experience
Exhibit Baxter-Direct-1 Page 1 of 2
5/20 to present Team Lead – Forecasting. Yoh, a Zimmerman and Day Company. In this position, I support the load forecasting activities of NV Energy.
7/07 to 5/20 Manager of Load Forecasting, Nevada Power Company d/b/a NV Energy My primary duties are the forecasting of customers, sales, peak demand, gas therms and gas design day therms, for use in supply planning, rate cases and budgeting. Additional responsibilities include production of forecast variance reports actual to budget, weather adjustment of peaks and sales, and participation in local population forecasting working groups. I have filed testimony and supporting documents and testified on numerous occasions before the Public Utility Commission of Nevada.
2003 to 2007 Manager, Forecasting and Economic Analysis, Alliant Energy Responsible for the direction and technical work in the areas of statistical sample design and evaluation of load research samples, peak and energy forecasting, for both the gas and electric utilities, and associated regulatory filings, including Integrated Resource Plan filings in Iowa, Illinois, Minnesota and Wisconsin. In this position, I was also responsible for the monthly sales and revenue forecast and explanations of the monthly variance analysis, including actual to budget, year-over-year, and outlook for both operating companies: Wisconsin Power and Light Company and Iowa Power and Light Company. Also responsible for rate case sales and demand forecasts in Wisconsin and Minnesota. Filed direct testimony before the Minnesota Department of Commerce.
2001 to 2003 Private Consultant Assisted utility companies in sample design and analysis of load research programs.
1998 to 2003 Team Leader, Forecasting and Economic Analysis, Alliant Energy Responsible for the direction and technical work in the areas of statistical sample design and evaluation of load research samples, peak and energy forecasting, for both the gas and electric utilities, and associated regulatory filings for IES Utilities and Interstate Power Company and its successor company, Iowa Power and Light.
1991 to 1998 Group Manager, Aspen Systems Corporation Responsible for the technical direction of utility consulting projects in the areas of sample design, DSM performance evaluation, market and survey research.
1985 to 1991 Rate Engineer and Manager of Load Research, and Forecasting, Iowa Power, Inc. /Midwest Energy Responsible for all facets of the load research program, including sample design, analysis and equipment selection, as well as sales forecasting. Filed testimony before the Iowa Utilities Board.
1980 to 1995 Load Research Analyst, Missouri Public Service Company Responsible for all facets of the load research program as well as class cost of service and marginal cost studies.
1979 to 1980 Economic Analyst, Illinois Commerce Commission Responsible for examination of utility rate and regulatory filings.
1
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Other
2007 to 2020 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.
2
Exhibit Baxter-Direct-1 Page 2 of 2
Page 209 of 247
Page 210 of 247
ERIC FOX
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV Energy Docket No. 20-06___
2020 General Rate Case
Prepared Direct Testimony of
Eric Fox
Revenue Requirement
I. INTRODUCTION
1. Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
A. My name is Eric Fox. My business address is 20 Park Plaza, Suite 428, Boston,
Massachusetts, 02116.
2. Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?
A. I am employed by Itron, Inc. (“Itron”) as Director, Forecast Solutions.
3. Q. PLEASE BRIEFLY DESCRIBE ITRON.
A. Itron is a leading technology provider and critical source of knowledge to the global
energy and water industries. More than 3,000 utilities worldwide rely on Itron
technology to deliver the knowledge they require to optimize the delivery and use
of energy and water. Itron provides industry-leading solutions for electricity
metering; meter data collection; energy information management; demand
response; load forecasting, analysis and consulting services; distribution system
design and optimization; web-based workforce automation; and enterprise and
residential energy management.
Fox-DIRECT 1
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4. Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
A. I am testifying on behalf of Nevada Power Company d/b/a/ NV Energy (“Nevada
Power” or the “Company”).
5. Q. PLEASE DESCRIBE YOUR EDUCATIONAL AND PROFESSIONAL
BACKGROUND.
A. I received my Master of Arts in Economics from San Diego State University in
1984 and my Bachelor of Arts in Economics from San Diego State University in
1981. While attending graduate school, I worked for Regional Economic Research,
Inc. (“RER”) as a SAS programmer. After graduating, I worked as an Analyst in
the Forecasting Department of San Diego Gas & Electric. I was later promoted to
Senior Analyst in the Rate Department. I also taught statistics in the Economics
Department of San Diego State University on a part-time basis.
In 1986, I was employed by RER as a Senior Analyst. I worked at RER for three
years before moving to Boston and taking a position with New England Electric as
a Senior Analyst in the Forecasting Group. I was later promoted to Manager of
Load Research. In 1994, I left New England Electric to open the Boston office for
RER, which was acquired by Itron in 2002.
Over the last 25 years, I have provided support for a wide range of utility operations
and planning requirements, including forecasting, load research, weather
normalization, rate design, financial analysis, and conservation and load
management program evaluation. Clients include traditional integrated utilities,
distribution companies, independent system operators, generation and power
trading companies, and energy retailers. I have presented various forecasting and
Fox-DIRECT 2
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energy analysis topics at numerous forecasting conferences and forums. I also
direct electric and gas forecasting workshops that focus on estimating econometric
models and using statistical-based models for monthly sales and customer
forecasting, weather normalization, and calculation of billed and unbilled sales.
Over the last twenty years, I have provided forecast training to several hundred
utility analysts and analysts in other businesses.
In the area of energy and load weather normalization, I have implemented and
directed numerous weather normalization studies and applications used for utility
sales and revenue variance analysis and reporting and estimating booked and
unbilled sales and revenue. Recent studies include developing weather normalized
class profiles for cost allocation and rate design, estimating rate class hourly profile
models to support retail settlement activity, weather normalizing historical billing
sales for analyzing historical sales trends, developing customer class and weather
normalized end-use profiles as part of a utility integrated resource plan, and
developing normal daily and monthly weather data to support sales and system
hourly load forecasting. The most recent study I directed was an evaluation of
climate impact on long-term energy and demand for the New York independent
system operator (“ISO”). My resume is included in Exhibit Fox-Direct-1.
6. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”) OR ANY
OTHER REGULATORY AGENCY?
A. Yes. I have provided testimony to support the long-term forecasts as part of
regulatory filings for Sierra Pacific Power Company d/b/a NV Energy (“Sierra”)
Energy Supply Plan Update (Docket No. 12-08010), Sierra’s 8th Amendment to its
Fox-DIRECT 3
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2008 Integrated Resource Plan (Docket 10-03023) and Nevada Power’s 2010
Triennial Integrated Resource Plan and Energy Supply Plan (Docket 10-02009). I
have also provided testimony related to forecasting and weather normalization in
other state jurisdictions including Indiana, Florida, Arkansas, Kansas, Oklahoma,
and most recently Missouri. My regulatory experience is included in Exhibit Fox-
Direct-1.
7. Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY IN THIS
PROCEEDING?
A. As part of our forecast support contract, Itron was asked to assess the
reasonableness of using 20-year normal heating degree-days (“HDD”) and cooling
degree days (“CDD”) for weather normalizing test-year sales and constructing
budget sales and long-term energy and demand forecasts. Using a temperature
trend analysis approach developed as part of our recent climate impact study for the
New York ISO, we found a positive and statistically significant temperature trend
in Las Vegas. Translating the temperature trend into degree-rates results in trended-
normal CDD that are higher than the traditional 20-year normal CDD and trended-
normal HDD that are lower than 20-year normal HDD. Our analysis shows that
the trended-normal CDD and trended-normal HDD more accurately reflects current
weather conditions. The purpose of this testimony is to describe our analysis, show
results, and summarize our recommendations.
Fox-DIRECT 4
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II. TEMPERATURE TRENDS
8. Q. PLEASE DESCRIBE RECENT WORK IN ASSESSING TEMPERATURE
TRENDS AND IMPLICATIONS FOR ELECTRICITY LOADS.
A. Itron recently completed a study that I directed to evaluate long-term temperature
trends and impact on system load (New York ISO Climate Change Impact Study,
Phase I Long-Term Load Impact, December 2019); the study can be downloaded
from the New York ISO’s website.1 The core finding is that there is a statistically
measurable temperature increase across New York. We evaluated temperature
trends for 21 weather stations across New York. Daily temperature data was
available going back to 1950. Temperature trends varied significantly across
regions averaging for 0.5 degrees to 1.1 degrees per decade; the average trend for
the state of New York is 0.7 degrees per decade. Results were consistent with
recent state climate impact studies based on several Global Circulation Models
(“GCM”). GCM models are used to evaluate the impact of increasing greenhouse
gases on weather conditions, sea temperatures, tide-levels, severe weather events,
and other physical changes tied to an increase in greenhouse gases (primarily CO2).
A recent study by the San Francisco Federal Reserve Board and University of
Pennsylvania evaluated annual average temperature trends for 15 weather stations
across the United States (“PIERS Study”).2 The PIERS Study found similar
temperature trends with temperature increase averaging from 0.36 degrees per
decade (Boston) to 1.06 degrees per decade (Las Vegas).
One of our findings from the New York study is that temperatures on the coldest
days are increasing faster than the average temperature. While temperatures on the
1 https://www.nyiso.com/documents/20142/10773574/NYISO-Climate-Impact-Study-Phase1-Report.pdfAdd link to New York ISO website
2 Available at https://economics.sas.upenn.edu/pier/working-paper/2019/evolution-us-temperature-dynamics
New England Electric Service Power Company, 1990 – 1994 Positions Held: ─ Principal Rate Analyst, Rates ─ Coordinator, Load Research ─ Senior Analyst, Forecasting
San Diego Gas & Electric, 1984 – 1987 Positions Held: ─ Senior Analyst, Rate Department ─ Analyst, Forecasting and Evaluation Department
Instructor, Economics Department, San Diego State University, 1985 – 1986
Page 228 of 247
Exhibit Fox-Direct-1 Page 2 of 11
Experience Mr. Eric Fox is Director, Forecasting Solutions with Itron where he directs electric and gas analytics and forecasting projects and manages Itron’s Boston office. Mr. Fox has over 30 years of forecasting experience with expertise in financial forecasting and analysis, long-term energy and demand forecasting, and load research.
Mr. Fox and his team focus on developing and implementing forecast applications to streamline and support utility business operations. This work includes directing development and implementation of Itron’s integrated sales and revenue forecasting application (ForecastManager.net) and load research system (LRS). He also engages in forecast support work, which includes developing energy and demand forecasts for financial and long-term planning, billed and unbilled sales and revenue analysis, weather normalization for monthly sales variance analysis and rate case support, and analyzing technology and economic trends and their impact on long-term energy usage.
Mr. Fox has provided expert testimony and support in rate and regulatory related issues. This support has included developing forecasts for IRP and rate filings, weather normalizing sales and demand for rate filing cost of service studies, providing rate case support and direct testimony and conducting forecast workshops with regulatory staff. He is one of Itron’s primary forecast instructors. He provides forecast training through workshops sponsored by Itron, utility on-site training programs, and workshops held by other utility organizations.
Prior to joining RER/Itron, Mr. Fox supervised the load research group at New England Electric where he oversaw systems development, directed load research programs, and customer load analysis. He also worked in the Rate Department as a Principal Analyst where he was responsible for DSM rate and incentive filings, and related cost studies. The position required providing testimony in regulatory proceedings.
Long-Term Data Center Load Demand Forecast, Dominion Energy, April 2020
Long-Term Model Review, Dominion Energy, April 2020
Sales and Revenue Forecast for 2020 Rate Case, with Mike Russo, Hydro Ottawa, March 2020
New York ISO Climate Impact Study: Phase 1 Long-Term Load Impact, New York ISO, December 2019, with Rich Simons, Oleg Moskatov, and Mike Russo
Cold Climate Heat Pump Study, Sample Design, December 2019, with Rich Simons, Nova Scotia Power
Long-Term Energy and Demand Forecast, 2020 IRP, October 2019, with Mike Russo, Vectren (A CenterPoint Energy Company)
Fundamentals of Forecasting Workshop, October 2019, Washington DC
Development of Energy Efficiency Conservation Curves for Long-Term System Load Model, ISO New England, September 2019 with Mike Russo
Test-Year Weather Normalization and Filed Testimony, July 2019, with Oleg Moskotov, Liberty Utilities
Advanced Forecast Topics Workshop, Energy Forecasting Group 2019 Annual Meeting, April 2, 2019, Boston NA
Long-Term Forecast Development and Modeling Workshop. Salt River Project, Tempe Arizona, March 26-27, 2019
Sales and Revenue Forecast for 2019 Rate Filing, with Oleg Moskatov and Mike Russo, Green Mountain Power Company, March 2019
Modeling Long-Term Peak Demand - Forecasting Workshop. ISO New England, December 19, 2018
Testimony and Supporting Sales Weather-Normalization for the 2018 Kansas Rate Case. Empire District Electric/Liberty Utilities, November 2018.
Load Research Training – Methods, Design, and LRS Applications. Colorado Springs Utilities. November 29-30, 2018
2018 Benchmark Survey – Energy Trends, Projections, and Methods. Electric Utility Forecaster Forum, November 13-14, 2018. Orlando, Florida
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Exhibit Fox-Direct-1 Page 4 of 11
Forecasting Methods, Model Development, and Training. WEC Energy Group, Milwaukee WI, September 20 -21, 2018.
Development of Budget Sales and Customer Forecast Models, Report, and Forecast Training. Alectra Utilities, July 2018
Electricity Forecasting in a Dynamic Market. Presentation and Panel Participant, Organization of MISO States, Forecast Workshop & Spring Seminar, Des Moines Iowa, March 21 -23, 2018.
Load Research Methods and Results, IPL and Indiana Office of Utility Consumer Counselor (OUCC), March 12, 2018
Sales Weather Normalization to Support the IPL 2018 Rate Case, with Richard Simons, Indianapolis Power & Light, December 2017
Dominion Long-Term Electricity Demand Forecast Review. Dominion Energy Virginia, September 15, 2017.
Dominion Long-Term Electricity Demand Forecast Review. Dominion Energy Virginia, September 15, 2017.
Vermont Long-Term Energy and Demand Forecast, with Mike Russo and Oleg Moskatov, Presented to the Vermont State Forecast Committee, August 1, 2017
Utility Forecasting Trends and Approaches, with Rich Simons and Mike Russo, Presented to the Energy Information Administration, July 27, 2017
Sales and Revenue Forecast Delivery and Presentation, with Mike Russo, Indianapolis Power & Light, July 13, 2017
Forecasting Gas Demand When GDP No Longer Works, Southern Gas Association Gas Forecasters Forum, June13 to 17, Ft Lauderdale, Florida
Behind the Meter Solar Forecasting, with Rudy Bombien, Duke Energy, Electric Utility Forecaster Forum, May 3 to 5, 2017, Orlando, Florida
Advanced Forecast Training Workshop, with Mike Russo, EFG Meeting, Chicago Illinois, April 25th, 2017
Budget-Year Electric Sales, Customer, and Revenue Forecast, with Oleg Moskatov and Mike Russo, Green Mountain Power Company, March 2017
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Exhibit Fox-Direct-1 Page 5 of 11
Solar Load Modeling, Statistic Analysis, and Software Training, Duke Energy, March 1 to 3, 2017
Development of a Multi-Jurisdictional Electric Sales and Demand Forecast Application, with Mike Russo and Rich Simons, Wabash Valley Power Cooperative, January, 2017,
Net Energy Metered Customer Sample Design and Training, Nevada Energy, December 1 – 2, 2016
Development of Long-Term Regional Energy and Demand Forecast Models, Tennessee Valley Authority, November 14, 2016
New York Energy Trends and Long-Term Energy Outlook, New York ISO Forecasting Conference, Albany New York, October 28, 2016
Fundamentals of Forecasting Workshop, with Mark Quan, Chicago, Illinois, September 26th – 28th, 2016
Building Long-Term Solar Capacity and Generation Model, Duke Energy, September 8 and 9th, Charlotte North Carolina
When GDP No Longer Works - Capturing End-Use Efficiency Trends in the Long-Term Forecast, EEI Forecast Conference, August 21 – 23rd, 2016, Boston Massachusetts
2016 Long-Term Electric Energy and Demand Forecast, Vectren Corporation, August 4, 2016
Forecasting Behind the Meter Solar Adoption and Load Impacts, with Mike Russo, Itron Brown Bag, July 12, 2016
2016 Long-Term Electric Energy and Demand Forecast, IPL, July 19, 2016
Long-Term Forecast Methodology, IPL Integrated Resource Plan Forecast, Presented to the Indiana Utility Regulatory Commission Staff, June 15, 2016
Long-Term Energy and Demand Forecast, Burlington Electric Vermont, May 2016
Statistical Mumbo Jumbo: It’s Not Really, Understanding Basic Forecast Model Statistics, Electric Utility Forecasting Forum, Chattanooga, Tennessee, April 7 to 8, 2016
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Exhibit Fox-Direct-1 Page 6 of 11
Solar Load Modeling and Forecast Review, NV Energy, Nevada Public Utilities Commission Staff, and Bureau of Consumer Protection, Reno Nevada, January 29, 2016
Statistically Adjusted End-Use Modeling Workshop, New York ISO, December 10, 2015
Long-Term Energy and Load Modeling Workshop, Chicago Illinois, October 29th – 30th
Integrating Energy Efficiency Program Impacts into the Forecast, Indiana Utility Regulatory Commission, Contemporary Issues Conference, September 1, 2015
Residential and Commercial End-Use Energy Trends (SAE Update), Itron Webinar for EFG Members, with Oleg Moskatov and Michael Russo, July 22, 2015
Capturing End-Use Efficiency Improvements through the SAE Model, 3rd CLD Meeting, Vaughan, Ontario, June 24 2015
Modeling New Technologies – When Regression Models Don’t Work, Itron Webinar Brown Bag Series, with Oleg Moskatov and Michael Russo, June 9, 2015
Long-Term Demand Forecasting Overview and Training, KCP&L, April 2015
Budget Year 2016, Sales, Revenue, and Load Forecast, Green Mountain Power Company, March 2015
Forecast Review and Training for 2015 Rate Filing, PowerStream, January 2015
Rate Class Customer and Sales Forecast: 2015 Rate Filing, Hydro Ottawa, January 2015
Forecast Systems Implementation and Training, Entergy, January 2015
Long-Term Energy and Demand Forecasting, Ontario Ministry of Energy, January 2015
Load Research Sample Design, Nova Scotia Power, November 2014
Vermont Long-Term Energy and Demand Forecast, VELCO, November 2014
Energy Trends and Utility Survey Results, EUFF Meeting, October 2014
Fundamentals of Forecasting Workshop, Boston, MA, October 2014
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Gas Forecasting Workshop with Minnesota PUC Staff, Integrys, September 2014
Load Research System Implementation and Training, NVEnergy, June 2014
Forecasting and Modeling Issues Workshop, Ontario, CA, July 2014
Unbilled Sales Analysis and System Implementation, KCP&L March 2014
Gas Sales and Revenue Forecast Model Development, TECo, December 2013
Forecast Model Development and Training, Duke Energy, October 2013
Sales and Revenue Forecast, GMP, August 2013
Forecast Support and Testimony, TECo, June 2013
Long-Term Energy and Demand Forecast, IRP Filing, GMP, May 2013
Long-Term Energy and Demand Forecast, IRP Filing, Vectren, March 2013
Statistical End-Use Model Implementation, Nova Scotia Power, December 2012
Fundamentals of Forecasting, Workshop, Boston, MA, November 2012
Rate Class Profile Development for Settlement Support, NYSEG and RGE (Iberdrola), September 2012
Budget Forecasting System Implementation, and Training, Horizon Utilities, August 2012
Commercial Sales Forecasting: Getting it Right, Itron Brownbag Web Presentation, June 2012
Long-Term Energy Trends and Budget Forecast Assessment, Tampa Electric Company, June 2012
Budget-Year 2013 Sales and Revenue Forecast, Green Mountain Power, April 2012
Long-Term Residential and Commercial Energy Trends and Forecast, Electric Utility Forecasting Week, Las Vegas, May 2012
NV Energy Forecast Workshop, with Terry Baxter, NV Energy, March 2012
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Exhibit Fox-Direct-1 Page 8 of 11
Commercial Sales Forecasting, the Neglected Sector, Electric Utility Forecasting Forum, Orlando, November 2011
Vermont Long-Term Energy and Demand Forecast, Vermont Electric Transmission Company, November 2011
Fundamentals of Forecasting Workshop, Boston, September 2011
Forecasting Top 100 PPL Load-Hours, with David Woodruff, AEIC Summer Load Research Conference, Alexandra, VA, August 2011
Budget and Long-Term Energy and Demand Forecast Model Development, Central Electric Power Cooperative, April 2011
Development of an Integrated Revenue Forecasting Application, TVA, March 2011 Integrating Energy Efficiency Into Utility Load Forecasts, with Shawn Enterline, 2010
ACEE Summer Study on Energy Efficiency in Buildings, August 2010
Using Load Research Data to Develop Peak Demand Forecasts, AEIC Load Research Conference, Sandestin, FL, August 2010
Development of a Long-term Energy and Demand Forecasting Framework, Consumer Energy, October 2009
Review of Entergy Arkansas Weather Normalization Methodology for the 2009 Rate Case, Entergy Arkansas Inc., September 2009
Green Mountain Power Budget Year and Rate Case Sales and Revenue Forecast, Green Mountain Power, May 2009
Vectren Gas Peak-Day Design Day Load Forecast and Analysis, Vectren Energy, April 2009
Nevada Power, Long-Term Energy and Demand Forecast, NV Energy, March 2009
Estimating End-Use Load Profiles, Leveraging Off of Load Research Data, Western Load Research Conference, Atlanta, March 2009
Fundamentals of Load Forecasting Workshop, Orlando, March 2009
DPL Long-Term Energy and Demand Forecast, 2009 IRP Filing, Dayton Power & Light, February 2009
Development and Application of Long-Term End-Use Hourly Load Forecasting Model, AEP, October 2008
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Exhibit Fox-Direct-1 Page 9 of 11
Load Research from the User’s Perspective, AEIC Annual Load Research Conference, Oklahoma City, August 2008
OGE Weather Normalized Sales Study, Estimation of Weather Normalized Sales for 2007 Rate Case, July 2008
Vermont Long-Term and Zonal Demand Forecast, Vermont Power Company, July 2008
Budget Forecast System Implementation, Entergy June 2008
Approaches for Analyzing Electric Sales Trends, Electric Forecasting Group, Las Vegas, May 2008
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Regulatory Experience
July 2019: Provided testimony and supporting sales and weather-normalization for the 2020 Missouri rate case. Empire District Electric/Liberty Utilities.
November 2018: Provided testimony and supporting sales weather-normalization for the 2018 Kansas rate case. Empire District Electric/Liberty Utilities.
December 2017: Provided testimony and support related to sales weather-normalization for the 2018 rate case. Indianapolis Power & Light.
October 2017: Provided testimony and support for the Dominion Energy Virginia 2017 Integrated Resource Plan
Jan 2015 – Dec 2016: Assisted Power Stream with developing and supporting the 2015 rate case sales and customer forecast before the Ontario Energy Board
Jan 2015 – Dec 2016: Assisted Hydro Ottawa with developing and supporting the 2015 rate case sales and customer forecast before the Ontario Energy Board
September 2015: Provided testimony and support related to sales weather-normalization for the 2015 rate case. Indianapolis Power & Light
October 2014 – July 2015: Assisted Entergy Arkansas with developing and supporting weather adjusted sales and demand estimates for the 2015 rate case.
September 2014: Assisted with developing the budget sales and revenue forecast and provided regulatory support related Horizon Utilities 2014 rate filing before the Ontario Energy Board
August 2013: Reviewed and provided testimony supporting Sierra Pacific Power Company’s forecast for the 2013 Energy Supply Plan before the Nevada Public Utilities Commission
July 2013: Reviewed and provided testimony supporting Tampa Electric’s forecast for the 2013 rate case before the Florida Public Service Commission
March 2013: Reviewed and provided testimony supporting Entergy Arkansas sales weather normalization for the 2013 rate filing before the Arkansas Public Service Commission
June 2012: Reviewed and provided testimony supporting Nevada Power Company’s 2012 Long-Term Energy and Demand Forecast before the Nevada Public Utilities Commission
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Exhibit Fox-Direct-1 Page 11 of 11
May 2010: Provided testimony supporting Sierra Pacific Power’s Company’s 2010 Long-Term Energy and Demand Forecast before the Nevada Public Utilities Commission
March 2010: Assisted with development of the IRP forecast and provided testimony supporting Nevada Power Company’s 2010 Long-Term Energy and Demand Forecast before the Nevada Public Utilities Commission
August 2009: Reviewed Entergy Arkansas weather normalization and provided supporting testimony before the Arkansas Public Service Commission
February 2006: Developed long-term forecast and provided testimony to support Orlando Utilities Commission Need for PowerApplication before the Florida Public Service Commission
July 2005: Developed sales and customer forecast and provided testimony to support Central Hudson’s electric rate filing before the New York Public Service Commission
April 2004: Held Weather Normalization Workshop with the Missouri Public Service Commission Staff
July 2001: Conducted workshop on long-term forecasting with the Colorado Public Utilities Commission Staff
October 1993: Submitted testimony in support of DSM earned incentives and related rate design before the Massachusetts Department Public Utilities, and Rhode Island Public Utilities Commission. Position: Principal Analyst, Rate Department, New England Power Service Company. Supervisor: Mr. Larry Reilly.
June 1993: Testified in matters related to the annual Energy Conservation Services Charge before Massachusetts Department Public Utilities. Position: Principal Analyst, Rate Department, New England Power Service Company. Supervisor: Mr. Larry Reilly.
June 1990: Submitted testimony in Nevada Power’s behalf in matters related to gas transportation rates proposed by Southwest Gas in Southwest Gas rate proceedings before Nevada Public Utilities Commission. Position: Sr. Analyst, Regional Economic Research, Inc.
October 1988: Testified to development and application of a Gas Marginal Cost of Service Study for unbundling natural gas rates as part of a generic hearing to restructure the natural gas industry in California before the California Public Utilities Commission. Position: Sr. Analyst, Rate Department, San Diego Gas & Electric. Supervisor: Mr. Douglas Hansen
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Page 239 of 247
MARIYA COLEMAN
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV EnergyDocket No. 20-06___
2020 General Rate Case
Prepared Direct Testimony of
Mariya Coleman
Revenue Requirement
1. Q. PLEASE STATE YOUR NAME, JOB TITLE, EMPLOYER AND BUSINESS
ADDRESS.
A. My name is Mariya Coleman. I am the Director of Corporate Insurance for Nevada
Power Company d/b/a NV Energy (“Nevada Power” or the “Company”) and Sierra
Pacific Power Company d/b/a NV Energy (“Sierra,” and together with Nevada
Power, the “Companies”). My work address is 6226 West Sahara Avenue, Las
Vegas, Nevada, 89146. I am filing testimony on behalf of Nevada Power.
2. Q. WHAT ARE YOUR PRIMARY RESPONSIBILITIES AS DIRECTOR OF
COPORATE INSURANCE FOR THE COMPANIES?
A. As Director of Corporate Insurance, I am responsible for the acquisition and
management of all corporate insurance programs, excluding benefits-related plans
and for monitoring the operations of the Companies to ensure compliance with
policies and procedures for reducing their risk profile and exposure.
3. Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND
EMPLOYMENT EXPERIENCE.
A. I joined the Companies as a Risk Analyst in 2010 and worked in Corporate
Insurance through 2014. From 2014 through 2017, I was the Manager of Corporate
Insurance. In 2017, I was named the Director of Corporate Insurance. I have a
Coleman-DIRECT 1
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Bachelor of Science in Finance from University of Nevada, Las Vegas, and a
Master’s in Business Administration from University of Nevada, Las Vegas. I
completed the Master’s in Renewable Engineering Certificate program from
University of Nevada, Reno, in 2014. A complete statement of my qualifications
is set forth in Exhibit Coleman-Direct-1.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. Yes, I have testified previously before the Commission. My most recent appearance
in a general rate case was in Nevada Power’s 2017 general rate case, Docket No.
17-06003.
5. Q. ARE YOU SPONSORING ANY EXHIBITS WITH YOUR TESTIMONY
OTHER THAN YOUR STATEMENT OF QUALIFICATIONS?
A. No.
6. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
PROCEEDING?
A. I support and explain the reasonableness of the changes to four categories of the
annual insurance costs reflected on Schedule H-CERT-22. Schedule H-CERT-22
shows that Nevada Power’s annualized cost of property insurance has decreased
from $915,000 (as recorded on December 31, 2019) to $890,000 (estimated as of
May 31, 2020). Schedule H-CERT-22 also reflects the removal of the directors’
and officers’ liability insurance which expired on December 19, 2019. There will
be no future allocations for this insurance. The annual cost of excess liability
Coleman-DIRECT 2
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insurance has increased from $2,237,000 (as recorded on December 31, 2019) to
$2,420,000 (estimated as of May 31, 2020).
7. Q. PLEASE EXPLAIN THE DECREASE IN THE ANNUALIZED COST OF
PROPERTY INSURANCE.
A. The decrease in the annualized cost of property insurance was achieved by a
decrease in the property insurance rate, and the reimbursement of some premiums
for not having any claims during the policy period.
8. Q. PLEASE EXPLAIN THE INCREASE IN THE ANNUALIZED COST OF
LIABILITY INSURANCE.
A. The increase in the annualized cost of excess liability insurance is primarily due to
a midterm premium adjustment for the general liability policy. The annual audit of
the Companies’ losses was performed and determined that additional general
liability premium was required due to high claims costs which cannot be sustained
at a lower premium. Excess liability also had a small increase due to market
conditions.
9. Q. ARE WILDFIRE INSURANCE COSTS INCLUDED IN THE COSTS
REFLECTED IN H-CERT-22?
A. Yes, they are.
Coleman-DIRECT 3
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10. Q. ARE THE ANNUAL COSTS OF INSURANCE SHOWN ON SCHEDULE
H-CERT-22 REFLECTIVE OF NEVADA POWER’S ONGOING ANNUAL
INSURANCE COSTS?
A. Yes, they are.
11. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
A. Yes, it does.
Coleman-DIRECT 4
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Exhibit Coleman-Direct-1 Page 1 of 2
QUALIFICATIONS OF WITNESS Mariya Coleman
Director, Corporate Insurance NV Energy
6226 W. Sahara Ave Las Vegas, NV 89146
EDUCATION University of Nevada-Las Vegas, Lee Business School
M.B.A., Finance – 2010 University of Nevada-Las Vegas
B.S.B.A., Finance – 2008
PROFESSIONAL EXPERIENCE NV Energy, Las Vegas, Nevada Director, Corporate Insurance, July 2017 – present Manager, Corporate Insurance, January 2015 – July 2017
• Direct the Corporate Insurance function for Berkshire Hathaway Energy Co. (“BHE”) reporting directly to the Senior Vice President and General Counsel of BHE
• Responsible for $30 million global insurance program covering $100 billion in assets, $19.8 billion in revenue, 17,000 miles of natural gas pipelines and 23,000 employees world wide
• Manage NV Energy captive insurance subsidiary and BHE captive subsidiary • Coordinate with multiple business units at the operating platforms to develop risk and
insurance cost forecasts as well as allocation strategy • Provide insurance related expertise for all major merger and acquisition activities
NV Energy, Las Vegas, Nevada Senior Analyst, September 2011-December 2015 Analyst, August 2010-September 2011
• Supported the restructuring of coverage terms, limits and risk retention levels generating annual premium spend savings in excess of $5 million vs. 2010 levels
• Participated in the (BHE) acquisition integration team • Principal analyst on renewals of liability, property, worker’s compensation and
environmental insurance programs • Provided expertise on contractual risk transfer to multiple (BHE) businesses and created a
central standard for contractual terms • Optimized risk reduction efforts within Power Generation team by recreating monthly
reporting format for Risk Performance Metric • Led 2011, 2013 and 2014 General Rate Case submission and testimony development for
Corporate Insurance • Provided industry accepted language improvements to insurance and indemnity provisions
in major and minor agreements with counterparties
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Exhibit Coleman-Direct-1 Page 2 of 2
RELEVANT INDUSTRY/PROFESSIONAL INFORMATION Graduate Certificate in Renewable Energy, University of Nevada, Reno, 2014; Leadership Henderson Graduate, 2013; NV Chapter of Risk and Insurance Management Society Board, 2013-2015; AEGIS Loss Control Task Force, 2015-present; Associate in Claims (AIC), The Institutes, 2015; Associate in Risk Management (ARM), The Institutes, 2013; Chartered Property Casualty Underwriter (CPCU), The Institutes, 2013
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AFFIRMATION1
2
Pursuant to the requirements of NRS 53.045 and NAC 703.710, MARIYA3
COLEMAN, states that she is the person identified in the foregoing prepared testimony and/ 4
or exhibits; that such testimony and/or exhibits were prepared by or under the direction of
6 said person; that the answers and/or information appearing therein are true to the best
7 of his knowledge and belief; and that if asked the questions appearing therein, his answers
8 thereto would, under oath, be the same.
5
= c,s 10 I declare under penalty of perjury that the foregoing is true and correct.
