Eversource Energy : NSTAR Gas Rate Order (October 30)

November 03, 2020 at 03:10 am EST

The Commonwealth of Massachusetts

DEPARTMENT OF PUBLIC UTILITIES

D.P.U. 19-120October 30, 2020

Petition of NSTAR Gas Company doing business as Eversource Energy, pursuant to G.L. c. 164, § 94 and 220 CMR 5.00, for Approval of a General Increase in Base Distribution Rates for Gas Service and a Performance Based Ratemaking Mechanism.

____________________________________________________________________________

APPEARANCES: Cheryl M. Kimball, Esq.

Danielle C. Winter, Esq.

Kerri A. Mahoney, Esq.

Jameson Calitri, Esq.

Jessica Buno Ralston, Esq.

Keegan Werlin LLP

99 High Street, Ste 2900

Boston, Massachusetts 02110

FOR: NSTAR GAS COMPANY

Petitioner

Maura Healey, Attorney General

Commonwealth of Massachusetts

By:Joseph W. Rogers

John J. Geary

Matthew E. Saunders

Donald Boecke

Ashley Gagnon

Shannon Beale

Jo Ann Bodemer

Assistant Attorneys General

Office of Ratepayer Advocacy

One Ashburton Place

Boston, Massachusetts 02108

Intervenor

D.P.U. 19-120

Page ii

Department of Energy Resources

Commonwealth of Massachusetts

By:Rachael Graham Evans, Esq.

Robert H. Hoaglund II, Esq.

Ben Dobbs, Esq.

Colin P. Carroll, Esq.

100 Cambridge Street, Suite 1020

Boston, Massachusetts 02114

Intervenor

Charles Harak, Esq.

National Consumer Law Center

7 Winthrop Square, 4th Floor

Boston, Massachusetts 02110

-and-

Jerrold Oppenheim, Esq.

57 Middle Street

Gloucester, Massachusetts 01930

FOR: THE LOW-INCOME WEATHERIZATION AND FUEL ASSISTANCE PROGRAM NETWORK AND THE MASSACHUSETTS ENERGY DIRECTORS ASSOCIATION

Intervenor

Nicole Horberg Decter, Esq.

Jasper Groner, Esq.

Segal, Roitman, LLP

33 Harrison Avenue, 7th Floor Boston, Massachusetts 02111

FOR:	UNITED STEELWORKERS OF AMERICA,
	LOCAL 12004
	Intervenor

D.P.U. 19-120

Page iii

John J. McNutt

General Attorney

U.S. Army Legal Services Agency

Regulatory Law Division

Office of the Judge Advocate General

9275 Gunston Road, Suite 1300

Fort Belvoir, Virginia 22060

FOR: THE UNITED STATES DEPARTMENT OF

DEFENSE AND ALL OTHER FEDERAL

EXECUTIVE AGENCIES

Intervenor

Joey Lee Miranda, Esq.

Robinson & Cole LLP

280 Trumbull Street

Hartford, Connecticut 06103

FOR: DIRECT ENERGY SERVICES, LLC; DIRECT

ENERGY BUSINESS, LLC; AND DIRECT

ENERGY BUSINESS MARKETING, LLC

Limited Intervenors

Courtney Feeley Karp, Esq.

Jonathan S. Klavens, Esq.

Klavens Law Group, P.C.

420 Boylston Street, Suite 610

Boston, Massachusetts 02116

FOR: HOME ENERGY EFFICIENCY TEAM, INC.

Limited Intervenor

James M. Avery, Esq.

Pierce Atwood LLP

100 Summer Street, Suite 2250

Boston, Massachusetts 02110

FOR: THE BERKSHIRE GAS COMPANY

Limited Participant

Laura S. Olton, Esq.

LSO Energy Advisors, LLC

38 Thackeray Road

Wellesley, Massachusetts 02481

FOR: POWEROPTIONS, INC.

Limited Participant

D.P.U. 19-120

Page iv

Robert Ruddock, Esq.

Locke Lord Public Policy Group

111 Huntington Avenue

Boston, Massachusetts 02199

FOR: THE ENERGY CONSORTIUM

Limited Participant

Paul A. Scoff, Esq.

Sprague Operating Resources, LLC

185 International Drive

Portsmouth, New Hampshire 03801

FOR: SPRAGUE OPERATING RESOURCES, LLC

Limited Participant

D.P.U. 19-120		Page v
			TABLE OF CONTENTS
I.	INTRODUCTION ...................................................................................	1
II.	PROCEDURAL HISTORY .......................................................................	3
III.	ATTORNEY GENERAL'S MOTION TO STRIKE..........................................	8
	A.	Introduction ..................................................................................	8
	B.	Positions of the Parties ....................................................................	9
		1.	Attorney General ..................................................................	9
		2.	Company ...........................................................................	11
	C.	Analysis and Findings ....................................................................	11
IV.	STIPULATED ADJUSTMENTS................................................................	15
	A.	Introduction .................................................................................	15
	B.	Standard of Review........................................................................	17
	C.	Analysis and Findings ....................................................................	18
V.	PERFORMANCE-BASED RATEMAKING PROPOSAL .................................	20
	A.	Introduction .................................................................................	20
	B.	PBRM Proposal ............................................................................	21
		1.	Introduction ........................................................................	21
		2.	Formula Elements ................................................................	22
		3.	Positions of the Parties ..........................................................	31
		4.	Analysis and Findings ...........................................................	56
	C.	Scorecard Metrics .........................................................................	98
		1.	Introduction ........................................................................	98
		2.	Company Proposal ...............................................................	98
		3.	Positions of the Parties ........................................................	100
		4.	Analysis and Findings .........................................................	106
VI.	DEMONSTRATION PROJECTS .............................................................	113
	A.	Gas Demand Response Demonstration Project.....................................	113
		1.	Introduction ......................................................................	113
		2.	Positions of the Parties ........................................................	116
		3.	Analysis and Findings .........................................................	125
	B.	Geothermal Demonstration Project ...................................................	128
		1.	Company Proposal .............................................................	128
		2.	Positions of the Parties ........................................................	131
		3.	Analysis and Findings .........................................................	138
		4.	Conclusion .......................................................................	155

D.P.U. 19-120		Page vi
VII.	RATE BASE	.......................................................................................	156
	A.	Introduction ...............................................................................	156
	B.	Test-Year-End Plant Additions........................................................	158
		1.	Introduction ......................................................................	158
		2.	Positions of the Parties ........................................................	160
		3.	Standard of Review ............................................................	161
		4.	Analysis and Findings .........................................................	163
	C.	Post-Test-Year Plant Additions .......................................................	166
		1.	Introduction ......................................................................	166
		2.	Positions of the Parties ........................................................	167
		3.	Standard of Review ............................................................	168
		4.	Analysis and Findings .........................................................	169
	D.	Prior Disallowances .....................................................................	170
		1.	Introduction ......................................................................	170
		2.	Positions of the Parties ........................................................	172
		3.	Analysis and Findings .........................................................	174
	E.	Cash Working Capital Allowance ....................................................	183
		1.	Introduction ......................................................................	183
		2.	Company's Lead-Lag Study ..................................................	184
		3.	Positions of the Parties ........................................................	186
		4.	Analysis and Findings .........................................................	186
	F.	Contributions in Aid of Construction ................................................	188
		1.	Introduction ......................................................................	188
		2.	Analysis and Findings .........................................................	190
		3.	Conclusion .......................................................................	196
	G.	Conclusion ................................................................................	197
VIII.	OPERATIONS AND MAINTENANCE EXPENSES.....................................	201
	A.	Employee Compensation and Benefits ...............................................	201
		1.	Introduction ......................................................................	201
		2.	Non-Union Wages ..............................................................	202
		3.	Union Wages ....................................................................	208
		4.	Incentive Compensation .......................................................	211
		5.	Supplemental Executive Retirement Plan ..................................	221
		6.	Employee Benefits..............................................................	225
		7.	Post-Test Year Full-Time Employees ......................................	232
		8.	Payroll Taxes ....................................................................	245
	B.	Enterprise Information Technology Projects Expense ............................	246
		1.	Introduction ......................................................................	246
		2.	Positions of the Parties ........................................................	247
		3.	Standard of Review ............................................................	251
		4.	Analysis and Findings .........................................................	252

D.P.U. 19-120

Page vii

C.	Lease Expense............................................................................	257
	1.	Introduction ......................................................................	257
	2.	Positions of the Parties ........................................................	260
	3.	Analysis and Findings .........................................................	263
D.	Service Company Expense .............................................................	269
	1.	Introduction ......................................................................	269
	2.	Positions of the Parties ........................................................	270
	3.	Analysis and Findings .........................................................	272
	4.	Conclusion .......................................................................	276
E.	Insurance Expense and Injuries and Damages Expense ..........................	277
	1.	Introduction ......................................................................	277
	2.	Positions of the Parties ........................................................	278
	3.	Analysis and Findings .........................................................	280
F.	Regulatory Assessment .................................................................	282
	1.	Introduction ......................................................................	282
	2.	Positions of the Parties ........................................................	283
	3.	Analysis and Findings .........................................................	285
G.	Rate Case Expense ......................................................................	291
	1.	Introduction ......................................................................	291
	2.	Position of the Company ......................................................	292
	3.	Analysis and Findings .........................................................	292
	4.	Conclusion .......................................................................	303
H.	Depreciation ..............................................................................	303
	1.	Introduction ......................................................................	303
	2.	Positions of the Parties ........................................................	305
	3.	Analysis and Findings .........................................................	305
I.	Uncollectible Expense ..................................................................	310
	1.	Introduction ......................................................................	310
	2.	Positions of the Parties ........................................................	311
	3.	Analysis and Findings .........................................................	312
J.	Inflation Allowance......................................................................	314
	1.	Introduction ......................................................................	314
	2.	Positions of the Parties ........................................................	315
	3.	Analysis and Findings .........................................................	316

D.P.U. 19-120		Page viii
IX.	AMORTIZATION OF GOODWILL .........................................................	320
	A.	Introduction ...............................................................................	320
	B.	Company Proposal.......................................................................	323
	C.	Analysis and Findings ..................................................................	324
X.	EXOGENOUS COST PROPERTY TAX PROPOSAL ...................................	325
	A.	Introduction ...............................................................................	325
	B.	Company Proposal.......................................................................	326
	C.	Positions of the Parties .................................................................	328
		1.	Attorney General ...............................................................	328
		2.	TEC ...............................................................................	329
		3.	Company .........................................................................	329
	D.	Analysis and Findings ..................................................................	332
XI.	CAPITAL STRUCTURE AND RATE OF RETURN ....................................	338
	A.	Introduction ...............................................................................	338
	B.	Capital Structure .........................................................................	339
		1.	Company's Proposal ...........................................................	339
		2.	Attorney General Proposal....................................................	340
		3.	Positions of the Parties ........................................................	340
		4.	Analysis and Findings .........................................................	343
	C.	Cost of Debt ..............................................................................	346
		1.	Company's Proposal ...........................................................	346
		2.	Positions of the Parties ........................................................	347
		3.	Analysis and Findings .........................................................	348
	D.	Proxy Groups.............................................................................	349
		1.	Company's Proxy Group......................................................	349
		2.	Attorney General's Proxy Group ............................................	350
		3.	Positions of the Parties ........................................................	351
		4.	Analysis and Findings .........................................................	352
	E.	Return on Equity.........................................................................	353
		1.	Company's Proposal ...........................................................	353
		2.	Attorney General's Proposal .................................................	355
		3.	DOD-FEA's Proposal..........................................................	356
		4.	Capital Market Conditions ....................................................	357
		5.	Discounted Cash Flow.........................................................	363
		6.	Capital Asset Pricing Model..................................................	375
		7.	Risk Premium Model ..........................................................	385
		8.	Flotation Costs ..................................................................	393
		9.	Cost of Equity Impact of Revenue Decoupling and PBRM ............	395
		10.	Conclusion .......................................................................	399

D.P.U. 19-120		Page ix
XII.	RATE STRUCTURE ............................................................................	409
	A.	Rate Structure Goals ....................................................................	409
	B.	Allocated Cost of Service Study ......................................................	413
		1.	Company Proposal .............................................................	413
		2.	Positions of the Parties ........................................................	414
		3.	Analysis and Findings .........................................................	420
	C.	Marginal Cost Study ....................................................................	423
		1.	Introduction ......................................................................	423
		2.	Positions of the Parties ........................................................	425
		3.	Analysis and Findings .........................................................	426
	D.	Class Revenue Allocation ..............................................................	427
		1.	Introduction ......................................................................	427
		2.	Positions of the Parties ........................................................	429
		3.	Analysis and Findings .........................................................	430
	E.	Low-Income Discount ..................................................................	433
		1.	Introduction ......................................................................	433
		2.	Positions of the Parties ........................................................	433
		3.	Analysis and Findings .........................................................	435
	F.	Rate by Rate Analysis ..................................................................	437
		1.	Introduction ......................................................................	437
		2.	Rates R-1 (Residential Non-Heating) and R-2(Low-Income
			Non-Heating) ....................................................................	438
		3.	Rates R-3 (Residential Heating) and R-4(Low-Income Heating) .....	439
		4.	Rate G-41 (Low Load Factor General Service - Small) ................	440
		5.	Rate G-42 (Low Load Factor General Service - Medium) .............	441
		6.	Rate G-43 (Low Load Factor General Service - Large) ................	442
		7.	Rate G-51 (High Load Factor General Service - Small) ................	443
		8.	Rate G-52 (High Load Factor General Service - Medium).............	444
		9.	Rate G-53 (High Load Factor General Service - Large)................	445
XIII.	CUSTOMER CONNECTION SURCHARGE ..............................................	446
	A.	Company's Proposal ....................................................................	446
	B.	Positions of the Parties .................................................................	449
		1.	Attorney General ...............................................................	449
		2.	Company .........................................................................	451
	C.	Analysis and Findings ..................................................................	455
		1.	Introduction ......................................................................	455
		2.	NSTAR Gas's Main Extension and CIAC Policies ......................	456
		3.	Proposed Surcharges ...........................................................	460
		4.	Energy Policy ...................................................................	464
		5.	Use of Surcharge Revenues...................................................	464
		6.	Accounting .......................................................................	465

D.P.U. 19-120		Page x
		7.	Conclusion .......................................................................	465
XIV. ENVIRONMENTALLY RESPONSIBLE GAS ............................................	467
	A.	Company's Proposal ....................................................................	467
	B.	Positions of the Companies ............................................................	468
		1.	Standard of Review ............................................................	469
		2.	Analysis and Findings .........................................................	470
XV.	TERMS AND CONDITIONS TARIFF ......................................................	473
	A.	Introduction ...............................................................................	473
	B.	Positions of the Parties .................................................................	474
		1.	Direct Energy ...................................................................	474
		2.	The Energy Consortium .......................................................	474
	C.	Analysis and Findings ..................................................................	475
XVI.	SCHEDULES	.....................................................................................	478
	A.	Schedule 1 - Revenue Requirements and Calculation of Revenue Increase.. 478
	B.	Schedule 2 - Operations and Maintenance Expenses .............................	479
	C.	Schedule 3 - Depreciation and Amortization Expenses ..........................	480
	D.	Schedule 4 - Rate Base and Return on Rate Base.................................	481
	E.	Schedule 5 - Cost of Capital ..........................................................	482
	F.	Schedule 6 - Cash Working Capital .................................................	483
	G.	Schedule 7 - Taxes Other Than Income Taxes ....................................	484
	H.	Schedule 8 - Income Taxes............................................................	485
	I.	Schedule 9 - Revenues .................................................................	486
	J.	Schedule 10 - Allocation to Rate Classes...........................................	487
XVII. ORDER .............................................................................................	488

D.P.U. 19-120

Page 1

INTRODUCTION
On November 8, 2019, NSTAR Gas Company doing business as Eversource Energy

("NSTAR Gas" or "Company") filed a petition with the Department of Public Utilities ("Department") seeking approval of an increase to base distribution rates for gas service pursuant to G.L. c. 164, § 94, as well as other proposals. NSTAR Gas's last increase in base distribution rates went into effect on January 1, 2016. NSTAR Gas Company, D.P.U. 14-150, at 434 (2015).

NSTAR Gas operates as a wholly owned subsidiary of Yankee Energy System, Inc., a holding company that is a wholly owned subsidiary of Eversource Energy ("Eversource") (Exh. ES-WJA/DPH-1, at 17). The Company is engaged in the retail distribution and sale of natural gas to approximately 296,000 customers in 51 communities in central and eastern Massachusetts, covering 1,067 square miles (Exh. ES-WJA/DPH-1, at 17).

In the instant case, NSTAR Gas seeks to increase base distribution rates to generate $34,970,916 in additional revenues, an approximate 17-percent increase over current

operating revenues (Exh. ES-DPH/ANB-2 (Rev. 3), Sch. 1, at 1).1 The Company based its proposed base distribution rate increase on a test year of January 1, 2018, through December 31, 2018 (Exh. ES-WJA/DPH-1, at 9).

1 In its initial filing, NSTAR Gas sought to increase base distribution rates to generate $38,034,254, an approximate 19-percent increase over current operating revenues (Exh. ES-DPH/ANB-2, Sch. 1, at 1). The Company revised the proposed increase during the course of this proceeding.

D.P.U. 19-120

Page 2

The Company's requested rate increase includes the recovery of merger-related costs

and exogenous costs associated with the settlements approved by the Department in BEC

Energy/Commonwealth Energy System, D.T.E. 99-19 (1999) and NSTAR/Northeast Utilities

Merger, D.P.U. 10-170 (2012) (Exh. ES-DPH/ANB-1, at 90-92,105-106). Additionally,

the Company proposes to implement a five-yearperformance-based ratemaking plan ("PBR

Plan") that includes a mechanism ("PBRM") that would allow NSTAR Gas to adjust its

distribution rates on an annual basis through the application of a revenue-cap formula and a

set of metrics to evaluate the Company's performance (Exh. ES-WJA/DPH-1, at 8). Within

the PBR Plan, the Company proposes to undertake two clean energy demonstration projects

over the next five years: a gas demand response program and a geothermal network, with

estimated costs of $2,305,729 and $12,810,645, respectively (Exhs. ES-WJA/DPH-1, at 8-9;

ES-PMC/MRG-1, at 26, 41, 52).

Finally, NSTAR Gas proposes a number of tariff changes. The Company proposes

changes to its distribution service terms and conditions tariff,2 including updates to its current

fees and a new sales tax abatement fee; a new PBR adjustment tariff to implement the

PBRM; revisions to the local distribution adjustment clause ("LDAC"), default service, and

2 Initially, the Company proposed several changes to its terms and conditions tariff in proposed tariff M.D.P.U. No. 400E that addressed the responsibilities and rights of gas suppliers (Exhs. ES-RDC/LMC-2, at 1-75;ES-RDC/LMC-3, at 1-89). On June 29, 2020, the Company moved to withdraw those revisions. D.P.U. 19-120, Motion to Withdraw Certain Proposed Tariff Revisions (June 29, 2020). On

July 1, 2020, the Department approved the Company's motion to withdraw on the record (Tr. 12, at 1536-1537).

D.P.U. 19-120

Page 3

retail rate tariffs; and a customer connection rider tariff to implement a surcharge of

30 percent of a customer's base distribution charges for a period of 20 years on customer

meters connected to the system on or after November 1, 2021 (Exh. ES-RDC/LMC-1;

proposed M.D.P.U. Nos. 400E, 401G, 402S, 403D, 404C, 409D, 411, 420D, 421G, 422D,

423G, 430D through 435D, 450C, 451C, 452C, and 453).3

The Department docketed the instant petition as D.P.U. 19-120 and suspended the

effective date of the proposed rate increase until October 1, 2020, to investigate the propriety

of the Company's request. The Department further suspended the effective date of the

Company's proposed tariffs until November 1, 2020, as a result of subsequent filings.

D.P.U. 19-120, Suspension Order (April 22, 2020) (seeSection II, below).

PROCEDURAL HISTORY
On November 12, 2019, the Attorney General of the Commonwealth of Massachusetts

("Attorney General") filed a notice of intervention pursuant to G.L. c. 12, § 11E)4

In the intervening period, NSTAR Gas filed, and the Department approved, M.D.P.U. No. 402S in its gas system enhancement plan proceeding. NSTAR Gas Company, D.P.U. 19-GSEP-06, at 29 (April 30, 2020). For clarity, we cite to the proposed M.D.P.U. No. 402S as originally submitted in this docket. In its compliance filing, NSTAR Gas shall refile the LDAC tariff consistent with the directives in D.P.U. 19-GSEP-06 and the directives contained herein using the next available M.D.P.U. number.

On January 3, 2020, the Department approved the Attorney General's retention of experts and consultants, filed pursuant to G.L. c. 12, § 11E(b), to assist her in representing consumer interests in this case at a cost not to exceed $550,000. D.P.U. 19-120, Order on Attorney General's Notice of Retention of Experts and Consultants (January 3, 2020). The costs incurred by the Attorney General in this proceeding are reimbursed to her by NSTAR Gas, and the Company recovers these costs from its ratepayers.

D.P.U. 19-120

Page 4

Additionally, the following entities were granted full party intervenor status: (1) the

Massachusetts Department of Energy Resources ("DOER"); (2) the Department of Defense

and all other Federal Executive Agencies ("DOD-FEA"); (3) United Steelworkers,

Local 12004 ("United Steelworkers"); and (4) the Low-Income Weatherization and Fuel

Assistance Program Network and the Massachusetts Energy Directors Association

("Low-Income Network"). The Department granted limited intervenor status to Direct

Energy Services LLC, Direct Energy Business LLC, and Direct Energy Business Marketing

LLC (together, "Direct Energy") and the Home Energy Efficiency Team, Inc. ("HEET").

The Department granted limited participant status to The Berkshire Gas Company; Power

Options, Inc.; The Energy Consortium ("TEC"); and Sprague Operating Resources LLC.5

Pursuant to notice duly issued on November 26, 2019, the Department held four

public hearings in NSTAR Gas's service area: (1) in Boston on February 24, 2020; (2) in

Worcester on February 25, 2020; (3) in New Bedford on February 27, 2020; and (4) in

Dedham on March 3, 2020.6 The Department also received written comments from NSTAR

Gas ratepayers and others.

For the Hearing Officer's Rulings regarding intervention, limited intervention, and limited participant status, refer to D.P.U. 19-120,Stamp-Granted Petitions for Intervention (December 18, 2019); D.P.U. 19-120, Procedural Conference Transcript at 5-9 (January 7, 2020); D.P.U. 19-120, Hearing Officer Ruling on Petition for Intervention at 5 (January 28, 2020).

A fifth public hearing was scheduled on March 5, 2020, in Plymouth at Plymouth North High School. On March 5, 2020, the Plymouth Public Schools announced that all schools in Plymouth would be closed on March 6, 2020, due to possible COVID-19 contamination. Based on this announcement, the Department cancelled the public hearing in the interest of public health and safety.

D.P.U. 19-120Page 5

On March 17, 2020, the Company moved to amend the procedural schedule to allow

Eversource and the Attorney General to engage in settlement discussions regarding Eversource's acquisition of Bay State Gas Company doing business as Columbia Gas of

Massachusetts ("Bay State").7 United Steelworkers also filed a motion on March 18, 2020, seeking an extension of the deadline to issue discovery due to office closures and logistical challenges arising out of the COVID-19 pandemic. On April 2, 2020, the Department granted both motions and established an amended procedural schedule pursuant to

220 CMR 1.02(5) subject to the Company filing proposed tariffs effective May 1, 2020, to replace in their entirety the proposed tariffs submitted on November 9, 2019.

D.P.U. 19-120, Hearing Officer Ruling on Motions to Amend the Procedural Schedule and Procedural Directive at 2, 4 (April 2, 2020). On April 16, 2020, the Company filed replacement tariffs, which the Department suspended until November 1, 2020.

D.P.U. 19-120, Suspension Order (April 22, 2020).

In accordance with the amended procedural schedule, evidentiary hearings were scheduled to occur in the month of June 2020. Pursuant to Executive Order No. 591, Declaration of a State of Emergency to Respond to COVID-19, on June 6, 2020, Governor Baker issued COVID-19 Order No. 38. Effective June 8, 2020, gatherings that brought together more than ten persons into close physical proximity in any confined indoor or

7 On October 7, 2020, the Department approved this asset purchase and sale transaction. Eversource Energy, NiSource Inc., Eversource Gas Company of Massachusetts, and Bay State Gas Company d/b/a Columbia Gas of Massachusetts, D.P.U. 20-59/19-140/19-141 (October 7, 2020).

D.P.U. 19-120Page 6

outdoor space remained prohibited throughout the Commonwealth. After due consideration of the ongoing assemblage prohibition, the statutory deadline for order issuance, and the interests of the parties to this proceeding, the Department found that it was necessary to facilitate the evidentiary hearings via videoconference. D.P.U. 19-120, Hearing Officer Memorandum and Ground Rules for Virtual Evidentiary Hearings (June 9, 2020).

The Department held twelve days of virtual evidentiary hearings from June 16, 2020, to July 1, 2020. In support of the Company's filing, NSTAR Gas sponsored the testimony of 18 witnesses: (1) William J. Akley, president, gas distribution business, Eversource;

(2) Douglas P. Horton, vice president, distribution rates and regulatory requirements, Eversource Energy Service Company ("ESC"); (3) Penelope M. Conner, chief customer officer and senior vice president, ESC; (4) Michael Goldman, director, regulatory, evaluation and support, energy efficiency, ESC; (5) Julia Frayer, managing director, London Economics International LLC ("LEI"); (6) Dr. Marie N. Fagan, managing consultant and lead economist, LEI; (7) Ashley N. Botelho, manager of revenue requirements, ESC;

Robert B. Hevert, managing partner, ScottMadden, Inc.; (9) Sasha Lazor, director of compensation, ESC; (10) Michal P. Synan, director of benefits strategy and human resources shared services, ESC; (11) John J. Spanos, senior vice president, Gannett Fleming Valuation and Rate Consultants; (12) David A. Heintz, vice president, Concentric Energy Advisors;

Melissa F. Bartos, assistant vice president, Concentric Energy Advisors;
Richard D. Chin, manager of rates, ESC; (15) Lisa Cullen, manager of gas supply
operations, ESC; (16) Leanne M. Landry, director of budget and investment planning, ESC;

D.P.U. 19-120

Page 7

Thomas C. Desroisers, manager of budget and investment planning, ESC; and (18) Eric Soderman, manager of gas procurement and market analytics, ESC.8
The Attorney General sponsored the testimony of ten witnesses: (1) David J. Effron, consultant; (2) John Defever, consultant, Larkin & Associates, PLLC; (3) Dr. Mark N. Lowry, president, Pacific Economics Group Research LLC; (4) Scott Rubin, consultant;

Dr. J. Randall Woolridge, professor of finance at Pennsylvania State University;
David J. Garrett, managing member of Resolve Utility Consulting, PLLC; (7) Dwight Etheridge, vice president, Exeter Associates, Inc.; (8) Frank Radigan, principal in the Hudson River Energy Group; (9) Timothy Newhart, financial analyst, Office of Ratepayer Advocacy of the Massachusetts Office of the Attorney General; and (10) Jerome D. Mierzwa, principal and president of Exeter Associates, Inc. DOD-FEA sponsored the testimony of Michael P. Gorman, managing principal, and Christopher C. Walters, associate, Brubaker and Associates, Inc. Direct Energy sponsored the testimony of Keira Sanders, manager of retail natural gas operations and Marc Hanks, senior manager, corporate and regulatory affairs, Direct Energy.
On July 24, 2020, the Attorney General, DOER, DOD-FEA,Low-Income Network, HEET, and TEC submitted initial briefs. Direct Energy and PowerOptions, Inc. each submitted a letter in lieu of initial briefs. On August 10, 2020, the Company submitted its

8 During evidentiary hearings, the Company made the following witnesses, who had not submitted written testimony, available for cross examination: Kelly Dimeo, director of information technology project management and enterprise architecture, ESC; and Sean Noonan, director of information technology business solutions, ESC.

D.P.U. 19-120

Page 8

initial brief.9 On August 25, 2020, the Attorney General, DOER, DOD-FEA, HEET, and

TEC submitted reply briefs. On August 31, 2020, NSTAR Gas submitted its reply brief, and

on September 1, 2020, NSTAR Gas filed its final revenue requirement schedules and updates

to certain discovery requests. The evidentiary record consists of approximately 1800 exhibits

and 62 responses to record requests.

ATTORNEY GENERAL'S MOTION TO STRIKE

Introduction

At the conclusion of evidentiary hearings, NSTAR Gas was directed to file its reply

brief and final revenue requirement schedules by August 28, 2020 (Tr. 12, at 1611). In

addition, the Hearing Officer stated that he would be "keeping the record open for the limited

purposes of receiving responses to record requests and updates to certain information

requests, for example related to rate-case expense" (Tr. 12, at 1611). On August 28, 2020,

NSTAR Gas filed a motion for a one-business day extension to file its final revenue

requirement schedules, which the Department granted. D.P.U. 19-120, Hearing Officer

Stamp-Granted Motion for an Extension of Time (August 31, 2020).

9 On August 5, 2020, NSTAR Gas filed a motion for a one-business day extension to file its initial brief, which the Department granted. D.P.U. 19-120, Hearing Officer Stamp-Granted Motion for an Extension of Time (August 6, 2020). As a result, the Friday, August 7, 2020 deadline was extended to Monday, August 10, 2020. All subsequent reply brief deadlines were also extended such that intervenor reply briefs were due Tuesday, August 25, 2020, instead of Friday, August 21, 2020, and the

Company's reply brief was due Monday, August 31, 2020 instead of Friday, August 28, 2020. D.P.U. 19-120,Stamp-Granted Motion for an Extension of Time at 2 (August 6, 2020).

D.P.U. 19-120	Page 9
On September 1, 2020, NSTAR Gas submitted a supplemental response to the

Department's eighth record request ("RR-DPU-8 (Supp.)") and other exhibits.10 The supplemental response contained information regarding the status of Eversource's new area work center located in Auburn, Massachusetts ("Auburn AWC") and an attached copy of a

lease agreement between ESC and Rocky River Realty Company ("Rocky River").11 On September 10, 2020, the Attorney General filed a motion to strike pursuant to

220 CMR 1.04(5), 1.11(8) ("Motion to Strike"). The Attorney General specifically seeks to strike RR-DPU-8 (Supp.), including the attachment, and the corresponding citations to that response in the Company's reply brief (Motion to Strike at 1, 5, citingCompany Reply Brief at 56-57;RR-DPU-8 (Supp.) & Att.). On September 17, 2020, NSTAR Gas filed an opposition to the Motion to Strike ("Company Response").

Positions of the Parties

1. Attorney General

The Attorney General contends that the Hearing Officer did not leave the record open for the Company to submit RR-DPU-8 (Supp.) (Motion to Strike at 4-5,citingTr. 2,

at 348-349; Tr. 12, at 1611-1612). The Attorney General maintains that 220 CMR 1.11(8) prohibits any party from presenting additional evidence after the hearing has been closed

NSTAR Gas's filing also included the third revisions to Exhibits ES-DPH/ANB-2 and ES-DPH/ANB-3, the fourth supplemental response to Exhibit DPU-ES10-15, and the second supplemental response to Exhibit DPU-ES4-44.

Rocky River is a real estate holding company and wholly-owned subsidiary of Eversource (Exh. AG 1-98, Att.; Tr. 8, at 1050-1051).

D.P.U. 19-120Page 10

unless the party files a motion and demonstrates good cause (Motion to Strike at 3-4). The Attorney General argues that the Department should strike RR-DPU-8 (Supp.) and the corresponding citations in the Company's reply brief because NSTAR Gas neither moved to reopen the record nor demonstrated good cause (Motion to Strike at 3).

The Attorney General asserts that allowing the response into the record would prejudice the intervenors because they had no opportunity to cross-examine Company witnesses regarding the new information (Motion to Strike at 5). The Attorney General avers that neither the Department nor the intervenors had an opportunity to ascertain the veracity of the Company's self-serving claims (Motion to Strike at 5).

Further, the Attorney General contends that the response is ineligible for consideration by the Department because it is not supported by an affidavit (Motion to Strike at 5, citing220 CMR 1.01(1)). The Attorney General maintains that the Department must strike RR-DPU-8 (Supp.) and all citations thereof in the Company's reply brief from the evidentiary record in this proceeding based on the Company's failure to file a motion to reopen the record showing good cause coupled with its failure to submit an affidavit (Motion to Strike at 5). Finally, the Attorney General insists that if the Department allows RR-DPU-8 (Supp.) into the record it must strike the paragraph therein regarding the construction status and occupancy date, because the information is unresponsive to the record request, which asked for copies of all lease agreements related to the Auburn AWC (Motion to Strike at 6).

D.P.U. 19-120

Page 11

2. Company

The Company asserts that it properly filed RR-DPU-8 (Supp.) and that the

Department should reject the Motion to Strike (Company Response at 2). The Company contends that the Hearing Officer expressly left the record open for the Company to submit pertinent information about the Auburn AWC, including a copy of a lease agreement and an update on the relocation of employees to the facility (Company Response at 3-6,citingTr. 2, at 346-348,350-351; Tr. 8, at 1041, 1049-1050; Tr. 12, at 1611). NSTAR Gas maintains that RR-DPU-8 (Supp.) was an update required by the Department and not extra-record evidence (Company Response at 3, 6). The Company also argues that it was not required to file an affidavit in support of RR-DPU-8 (Supp.) because record requests are written substitutes to oral testimony and are automatically part of the evidentiary record (Company Response at 7-8,citingD.P.U. 19-120, Procedural Notice and Ground Rules at 13 (January 28, 2020); Tr. 12, at 1609).

Analysis and Findings

It is axiomatic that a party's post-hearing brief may not serve the purpose of

presenting facts or other evidence that are not in the record. Aquarion Water Company of Massachusetts, Inc., D.P.U. 17-90, at 15; New England Gas Company, D.P.U. 10-114, at 7-8 (2011); New England Gas Company, D.P.U. 08-35, at 15 (2009). Argument and comment filed on brief are not evidence in a case, as there is no opportunity for cross-examination or rebuttal testimony and evidence. D.P.U. 17-90 at 15-16; D.P.U.

10-114, at 8. A party's presentation of extra-record evidence to the fact-finder after the record has closed is an unacceptable tactic that is potentially prejudicial to the rights of other

D.P.U. 19-120Page 12

parties even when the evidence is excluded. D.P.U. 17-90 at 16; D.P.U. 10-114, at 8;

Boston Gas Company, D.P.U. 88-67 (Phase II) at 7 (1989). Nonetheless, the Department routinely permits the record to remain open after the end of hearings for receipt of updated information on certain non-controversial cost of service items such as rate case expense and property tax. D.P.U. 17-90 at 16, citingD.P.U. 10-114, at 8; Fitchburg Gas and Electric Light Company, D.T.E. 02-24/25, at 11 (2002). The filing of updated information may also be permissible in extraordinary or compelling circumstances. D.P.U. 10-114, at 8, citing Bay State Gas Company, D.P.U. 89-81, at 45 (1989).

The Attorney General contends that RR-DPU-8 (Supp.) is not admissible because it constitutes unsworn testimony unsupported by an affidavit (Motion to Strike at 5). We disagree and will not grant the Attorney General's Motion to Strike on that basis. Record requests are written substitutes to oral answers given at evidentiary hearings under oath and as such they are automatically part of the evidentiary record unless a motion to strike is made and granted. D.P.U. 19-120, Procedural Notice and Ground Rules, § III.G (January 28, 2020);12 D.P.U. 88-67, at 4. Accordingly, RR-DPU-8 (Supp.) does not constitute unsworn testimony.

12 Pursuant to 220 CMR 1.06(5)(c)2:

[T]he presiding officer shall establish discovery procedures in each case that take into account the legitimate rights of the parties in the context of the case at issue. In establishing discovery procedures, the presiding officer must exercise his or her discretion to balance the interests of the parties and ensure that the information necessary to complete the record is produced without unproductive delays.

D.P.U. 19-120Page 13

NSTAR Gas did not file a motion to reopen the record upon a showing of good cause.

Therefore, our decision on the Motion to Strike turns on whether, as the Company asserts, the Hearing Officer held the record open to accept RR-DPU-8 (Supp.) or, as the Attorney General asserts, the record was not held open for that purpose.

On June 17, 2020, just after the Hearing Officer issued the Department's record request for copies of all lease agreements related to the Auburn AWC, the Company's witness stated that NSTAR Gas intended to move its employees into the Auburn AWC by August 31, 2020, and committed to providing verification that the move had occurred (Tr. 2, at 350-351). In response to the Company's offer to provide said verification, the Hearing Officer responded, "Okay, thank you" (Tr. 2, at 351). On June 25, 2020, the Hearing Officer conducted further cross-examination of the witness regarding the anticipated in-service date of the Auburn AWC and the initial response to the Department's eighth record request, which provided that ESC had not executed a lease for the Auburn AWC at that time but anticipated that a lease would be executed by August 31, 2020 (RR-DPU-8). The witness testified that the Auburn AWC would be in-service when its employees were moved into the facility and that the Company's plan to complete the move in June 2020 had been delayed due to the COVID-19 pandemic (Tr. 8, at 1039-1043). In response to further examination about ESC's anticipated lease for the facility, the witness stated: "I think last week we did commit to providing verification that the move occurred on August 31, 2020, to the Department following the close of the hearings on this proceeding. I do think it would be reasonable if we also provided the lease agreement as well" (Tr. 8, at 1049-1050). Based on

D.P.U. 19-120Page 14

the examination by the Department's staff and the Company's responses, it was the clear

intent of the Hearing Officer and understanding of the Company that the record was to be held open for the Company to submit verification that the NSTAR Gas employees had moved to the Auburn AWC and a copy of the lease for the facility, which the Company provided in RR-DPU-8 (Supp.) (Tr. 2, at 348-351; Tr. 8, at 1049-1050; Tr. 12, at 1611).

We acknowledge that the in-service date of the Auburn AWC was a contested issue in this proceeding, and because of that the information provided in RR-DPU-8 (Supp.) is not akin to the non-controversial updates such as property tax bills and rate case expense invoices typically provided after the conclusion of evidentiary hearings. Nevertheless, the Company testified at hearing that the move-in date and coinciding in-service date for the Auburn AWC had been delayed due to the COVID-19 pandemic (Tr. 8, at 1039-1043). The ongoing pandemic and state of emergency's unprecedented effects on the availability and predictability of acquiring goods and services in the Commonwealth constitute extraordinary circumstances. Therefore, the Hearing Officer did not abuse his discretion in holding the record open to receive the information contained in RR-DPU-8 (Supp.). D.P.U. 10-114, at 8;

D.P.U. 89-81, at 45.

Lastly, the Attorney General asserts that if the Department does not strike RR-DPU-8 (Supp.) from the record in its entirety, then the Department should strike the paragraph in RR-DPU-8 (Supp.) regarding the Auburn AWC construction status and expected occupancy date because it is not responsive to the request. We disagree. The original response to RR-DPU-8 provided that the lease would be executed by August 31, 2020, i.e., the

D.P.U. 19-120

Page 15

occupancy date (RR-DPU-8). The information contained in the paragraph of RR-DPU-8

(Supp.) is relevant to the original response, to the verification that the move has occurred,

and to the information sought by the Hearing Officer during cross-examination. The

Attorney General's claim that the paragraph is not responsive and should be stricken is

without merit.

Based on the forgoing discussion, we conclude that (1) the Hearing Officer held the

record open until September 1, 2020, for the purpose of receiving the information contained

in RR-DPU-8 (Supp.); (2) the Company was not required to file a motion to reopen the

record for good cause shown; (3) the Hearing Officer did not abuse his discretion; (4) the

Company was not required to submit an affidavit; and (5) the paragraph in RR-DPU-8

(Supp.) regarding the Auburn AWC construction status and expected occupancy date contains

information relevant to the Department's record request. Accordingly, the Attorney

General's Motion to Strike is denied.

IV. STIPULATED ADJUSTMENTS

Introduction

On June 3, 2020, NSTAR Gas and the Attorney General submitted a joint motion

pursuant to 220 CMR 1.02(5) requesting that the Department approve their stipulations

regarding certain contested issues ("ES-AG Stipulations").13 The Company and the Attorney

13 Generally, a stipulation is a statement of facts agreed to by parties. This stipulation also includes issue of law (e.g., allowable costs and revenues, just and reasonable result, consistent with the public interest). The courts review stipulations of fact and stipulations of law differently. Goddard v. Goucher, 89 Mass. App. Ct. 41, 43

(2016). Importantly, a "court cannot be controlled by agreement of counsel on a subsidiary question of law." Goddard, 89 Mass. App. Ct. 41, 43 quoting Swift and

D.P.U. 19-120

Page 16

General proposed the stipulated adjustments to narrow the scope of evidentiary hearings and

briefing (ES-AG Stipulations at 1). No other parties submitted a response to the motion.

NSTAR Gas and the Attorney General proposed adjustments to the following

operations and maintenance ("O&M") expenses, which were incorporated into the

Company's final revenue requirement schedules submitted on September 1, 2020:

decrease 401(k) expense by $212,480; (2) decrease employee awards expense by $10,956;

decrease severance expense by $59,537; and (4) decrease the inflation adjustment by
$134,037 (ES-AG Stipulations at 2-3). In addition, the moving parties proposed to increase unbilled revenues by $295,098 and reduce rate base by $100,000 for customer advances (ES-AG Stipulations at 2-3). NSTAR Gas also agreed to credit customers for the remaining gains on sales of property and gains on the sale of the home heating protection business balance of $217,708 amortized over five years (ES-AG Stipulations at 3).14 Lastly, the Company agreed to reduce its proposed depreciation accrual for Accounts 336, 367, and 369, in accordance with the modified accrual rates shown in Table 1 to the ES-AG Stipulations, and decrease depreciation expense by $1,459,659 (ES-AG Stipulations at 3).

Company v. Hocking Valley Railway Company, 243 U.S. 282,289 (1917). See also Texas Instruments Federal Credit Union v. DelBonis, 72 F.3d 921, 928 (1st Cir 1995) ("Parties may not stipulate to the legal conclusions to be reached by the court"), quoting Saviano v. Commissioner of Internal Revenue, 765 F.2d 643, 645 (7th Cir. 1985).

14 NSTAR Gas will include the $43,542 credit ($217,708/5) in the Company's Local Distribution Adjustment Factor ("LDAF") (ES-AG Stipulations at 3).

D.P.U. 19-120	Page 17
Further, NSTAR Gas agreed to the following rate structure stipulations. The

Company will adhere to a distribution rate increase cap of 175 percent of the system-average percentage increase, use the residential average cost to allocate service pipe costs for the residential classes, use the actual embedded cost of each type of meter to allocate meter and meter installation costs, and allocate house regulator costs only to customers who are not located on the low-pressure system (ES-AG Stipulations at 3).

On July 24, 2020, NSTAR Gas and the Low-Income Network submitted a joint motion pursuant to 220 CMR 1.02(5) requesting that the Department approve their stipulated adjustment to the low-income discount ("ES-LI Stipulation").15 No other parties submitted a response to the motion.

Standard of Review

In assessing the reasonableness of an offer of settlement,16 the Department reviews all available information to ensure that the settlement is consistent with Department precedent and the public interest. Fall River Gas Company, D.P.U. 96-60 (1996); Essex County Gas Company, D.P.U. 96-70 (1996); Boston Edison Company, D.P.U. 92-130-D at 5 (1996); Bay State Gas Company, D.P.U. 95-104, at 14-15 (1995); Boston Edison Company, D.P.U. 88-28/88-48/89-100, at 9 (1989). A settlement among the parties does not relieve the Department of its statutory obligation to conclude its investigation with a finding that a

This stipulation also involves an issue of law - rate design. The stipulations are in the nature of offers of settlement.

D.P.U. 19-120

Page 18

just and reasonable outcome will result. D.P.U. 95-104, at 15; D.P.U. 88-28/88-48/89-100,

at 9.

It is well established that the Department's goals for utility rate structure are

efficiency, simplicity, continuity, fairness, and earnings stability. D.P.U. 95-104, at 15; Bay

State Gas Company, D.P.U. 92-111, at 283 (1992); see also Massachusetts Electric

Company, D.P.U. 95-40, at 144-145 (1995). The Department has previously accepted

settlements which include cost allocation and/or rate design when such settlements were

consistent with the Department's goals. D.P.U. 96-60; D.P.U. 96-70; D.P.U. 95-104, at 15;

Massachusetts Electric Company, D.P.U. 91-52 (1991).

Analysis and Findings

The Department has reviewed the stipulated adjustments to the O&M expenses listed

above, unbilled revenues, rate base, and depreciation in light of the evidence, including the

Company's initial filing and responses to information requests and the Attorney General's

testimony and responses to information requests submitted in this proceeding.17 Together,

these stipulated adjustments provide for significant ratepayer savings and are consistent with

findings that might reasonably have been made by the Department. Thus, the Department

concludes that the proposed cost of service adjustments are consistent with both applicable

17 The Department appreciates the efforts of the parties to potentially narrow contested issues, especially for this proceeding in which the Department first conducted extensive remote evidentiary hearings. See Boston Edison Company, Cambridge Electric Light Company, Commonwealth Electric Company, Fitchburg Gas and Electric Light Company, and Western Massachusetts Electric Company,

D.P.U 94-162, at 18 (Department encourages settlement).

D.P.U. 19-120Page 19

law and the public interest and approval of these adjustments results in a just and reasonable outcome of the specific issues raised therein. Accordingly, the Company and Attorney General's stipulated adjustments to NSTAR Gas's proposed cost of service are approved.

The Department has also reviewed the proposed adjustments to the Company's rate structure and the proposed adjustment to the Company's low-income discount. The Department has historically been reluctant to accept settlements that involve rate design issues. Massachusetts Electric Company, D.P.U. 84-240/85-146, at 3-4 (1985). Our reluctance to approve settlements that resolve rate structure issues, even if parties in the case can reach agreement, is based on the complicated nature of implementing the Department's rate structure goals. Cambridge Electric Light Company, D.P.U. 89-109, Interlocutory Order on Offer of Settlement at 3-4 (1989). The balancing of oft-competing goals involves the allocation of costs among classes and the design of rates within classes, in a way that moves rates toward costs consistent with continuity considerations. D.P.U. 89-109, Interlocutory Order on Offer of Settlement at 4. While parties representing limited constituencies in a rate case may come to some agreement on rate structure issues, this agreement might be to the detriment of other customers or be at odds with the Department's policy goals and objectives. D.P.U. 89-109, Interlocutory Order on Offer of Settlement at 4. Based on the findings in Section XII, below, the Department is unable to accept the Company and Attorney General's proposed rate structure adjustments or the Company and Low-Income Network's proposed adjustment to the low-income discount.

D.P.U. 19-120Page 20

Accordingly, we grant in part, and deny in part, the joint motion of NSTAR Gas and

the Attorney General, and we deny the joint motion of NSTAR Gas and the Low-Income Network. The Department's partial approval of the proposed stipulations does not constitute a determination as to the merits of any allegations or contentions made in this proceeding. In addition, the Department's acceptance does not establish a precedent for future filings, whether ultimately settled or adjudicated.

PERFORMANCE-BASEDRATEMAKING PROPOSAL

Introduction

NSTAR Gas's proposed PBR Plan has three components: (1) a PBRM to adjust rates annually and provide revenue support for operations and capital investment; (2) cost recovery for two demonstration projects, one to test the feasibility of natural gas demand-response initiatives, and one to assess the viability of geothermal distribution; and (3) a set of scorecard metrics to measure the success of PBR Plan implementation

(Exh. ES-WJA/DPH-1, at 5-6). The Company stated that it foresees changes in the operating environment for local distribution companies ("LDCs"), including increased capital investment outside of the GSEP and increased safety requirements (Exh. ES-WJA/DPH-1, at 11-12). The Company believes that the proposed PBR Plan is a better fit than traditional cost-of-service ratemaking, providing the revenue support necessary to address changes in the operating environment without diverting resources from the operation of the system

(Exh. ES-WJA/DPH-1, at 12-13).

D.P.U. 19-120

Page 21

PBRM Proposal

1. Introduction

NSTAR Gas's proposed PBRM uses a revenue cap formula to adjust base distribution rates annually through an adjustment to the Company's revenue decoupling mechanism (Exh. ES-WJA/DPH-1, at 79-80). The PBRM would adjust the base revenue requirement approved in this proceeding, which serves as the revenue target for the revenue decoupling mechanism, according to the following formula:

PBRAFT = (GDPPIT-1 - X) + (ZREV / Base RevenueT-1), where

PBRAFT is the percentage change to be applied to the Prior Year PBR

Revenue;

GDPPIT-1 is a price inflation index;18

X is a productivity offset;

Z is an adjustment for exogenous costs (positive or negative);

Base Revenue is the base distribution revenue requirement.

(Exh. ES-RDC/LMC-2, Proposed M.D.P.U. No. 411, § 6.0).

Two additional elements in the Company's proposed PBRM are not shown in the above formula. First, the Company proposed an earnings sharing mechanism ("ESM") that would provide either a credit or an additional charge to customers if earnings are higher or

18 GDPPI (also GDP-PI) refers to the gross domestic product price index, which measures changes in the prices of goods and services produced in the United States, including those exported to other countries. https://www.bea.gov/data/prices-inflation/gdp-price-index.

D.P.U. 19-120

Page 22

lower than the return on equity ("ROE") approved in this proceeding by more than 100 basis

points (proposed M.D.P.U. No. 411, §§ 4.0, 9.0). Second, the annual revenue requirement

associated with the investments for the two proposed demonstration projects would be

recovered through a Y Factor (proposed M.D.P.U. No. 411, § 10.0). Each element of the

Company's proposed revenue cap formula and PBRM is described in detail below.

2. Formula Elements

PBR Term

NSTAR Gas proposed an initial term of five years for the PBR Plan, with a

provisional five-year extension (Exh. ES-WJA/DPH-1, at 79, 93-95).19 The initial five-year

PBR term would commence on November 1, 2020 and expire on October 31, 2025

(Exh. WJA/DPH-1, at 94). Within the five-year term, there would be four annual PBRM

adjustments taking effect November 1, 2021, November 1, 2022, November 1, 2023, and

November 1, 2024 (Exh. WJA/DPH-1, at 94). In conjunction with the PBR term, the

Company proposed a stay-out provision whereby the Company may not file a base

distribution rate case during the PBR term (Exh. ES-WJA/DPH-1, at 94). Under the

19 The five-year extension is conditioned on the Department's approval of the following:

the two-part exogenous cost mechanism as proposed; (2) the proposed symmetrical ESM with a 100 basis point deadband; (3) the proposed cost of capital (ROE and capital structure); (4) the proposal to incorporate capital additions completed in 2019 and 2020 into rate base; and (5) a provision that would allow the Company to incorporate capital additions completed through December 31, 2024 into rate base in Year 5 of the PBR Plan term (Exh. ES-WJA/DPH-1, at 94-95).

D.P.U. 19-120Page 23

stay-out, the Company would be eligible to file rate schedules to put new base distribution

rates into effect no earlier than November 1, 2025 (Exh. ES-WJA/DPH-1, at 94).20

Post Test Year Capital Additions

NSTAR Gas proposed to recover the revenue requirement associated with non-GSEP capital additions completed through December 31, 2019, in base distribution rates effective with this Order; and capital additions completed through December 31, 2020, in base distribution rates effective on November 1, 2021 in the first PBRM adjustment

(Exhs. ES-WJA/DPH-1, at 95; ES-DPH/ANB-1, at 9-10,20-21;DPU-ES7-3; AG 10-1). In addition, the Company conditions its proposed five-year PBR term extension in part on allowing the revenue requirement associated with the capital additions completed through December 31, 2024, into base distribution rates in year five of the PBR Plan term

(Exh. ES-WJA/DPH-1, at 94-95). NSTAR Gas would include a determination in its September 15, 2024 PBRM adjustment filing of whether it has opted to stay out with a roll-in of capital additions in lieu of filing a base distribution rate case or other proposal for effect November 1, 2025 (Exh. ES-WJA/DPH-1, at 99). If the Company indicates in the September 15, 2024 PBRM adjustment filing that it has opted to roll in capital additions (and extended the PBR Plan term), NSTAR Gas would present capital project documentation through December 31, 2024, to the Department on or before April 1, 2025 for review and for roll-in to rates effective November 1, 2025 (Exh. ES-WJA/DPH-1, at 99).

20 In addition, the Company makes the stay-out contingent upon the Department's approval of the Company's proposed PBRM adjustment formula

(Exh. ES-WJA/DPH-1, at 97-98; Tr. 3, at 393-397).

D.P.U. 19-120

Page 24

X Factor

NSTAR Gas proposed a productivity offset ("X factor")21 to be calculated as:

X = TFPTGDI-US + IPTGDI-US, where

TFPTGDI-US is the total productivity trend differential between the electric22 distribution industry in the Northeast region and the overall United States economy,

IPTGDI-US is the total input price trend differential between the electric distribution industry and the overall United States economy.

(Exh. ES-RDC/LMC-2 (Rev.), Proposed M.D.P.U. No. 411, § 6.0).

When a PBRM utilizes an inflation factor that is a measure of economy-wide

inflation, the X factor consists of the differential in expected productivity growth between the

LDC industry and the overall economy, and the differential in expected input price growth

between the overall economy and the LDC industry (Exhs. ES-JF/MF-1, at 45; ES-JF/MF-2,

at 46). To determine the proposed X factor, NSTAR Gas conducted a productivity study of

nationwide LDCs' distribution TFP and input price growth over the period 2003 through

2017 (Exh. ES-JF/MF-2, at 11). The Company used two different samples for this

productivity study: (1) a sample of 83 U.S. LDCs intended to represent the overall

nationwide LDC industry; and (2) a sample of 29 LDCs intended to represent the LDC

The X factor, also referred to as a productivity target by the parties, consists of a total factor productivity ("TFP") differential, as measured by the difference of industry productivity growth and economy wide productivity growth, and an input price differential (Exhs. ES-JF/MF-1, at 45; ES-JF/MF-2, at 46).

The Department notes that the Company's proposed tariffs erroneously reference the electric distribution industry. The Department directs the Company to correct such references as part of its compliance filing.

D.P.U. 19-120

Page 25

industry in the Northeast (Exh. ES-JF/MF-1, at 21). For the industry TFP study and

calculation of the X factor, the Company used several official U.S. government sources.23

TFP is defined as the ratio of quantity of outputs produced to quantity of inputs used

in production (Exh. ES-JF/MF-2, at 15). Inputs and outputs should be those that most

accurately represent the physical process behind the distribution of gas (Exh. ES-JF/MF-2,

at 25). For the input measure, NSTAR Gas used capital expenditures and non-capital

expenditures (operations, maintenance, and administration ("OM&A")) (Exh. ES-JF/MF-2,

at 25). The Company then constructed quantity and price indices of total input for each firm

and each year (Exh. ES-JF/MF-2, at 27-37). NSTAR Gas used number of customers as the

sole productivity study output measure (Exh. ES-JF/MF-2, at 25).

The Company utilized a capital cost specification method referred to as the one hoss

shay method (Exh. ES-JF/MF-2, at 31). The basic assumption of this method is that an asset

provides a constant level of services over the service life of the asset (Exh. ES-JF/MF-2,

at 31). The one hoss shay method also requires an average service life of all assets in order

to estimate the quantity of capital retirements (Exh. ES-JF/MF-2, at 31-33).24

The Company used firm-level data for sample LDCs from Federal Energy Regulatory Commission ("FERC") Form 2 and the U.S. Energy Information Administration ("EIA") (Exh. ES-JF/MF-2, at 25).23 The Company used economy-wide data from:

U.S. Bureau of Labor Statistics ("BLS") Employer Cost Index ("ECI"); (2) U.S. Bureau of Economic Analysis ("BEA") Price Index for Gross Domestic Product ("GDP-PI"); (3) BLS Multifactor Productivity; (4) Federal Reserve Bank of St. Louis, Corporate Bond Yields; and (5) U.S. Treasury, U.S. Treasury Bonds and Inflation-Protected Securities (Exh. ES-JF/MF-1, at 25, 37).

In contrast, in the Attorney General's proposed TFP studies, she deployed the geometric decay and Kahn methods for capital cost specification (Exh. AG-MNL-2,

D.P.U. 19-120Page 26

The initial results of the Company's study indicated that, for the period 2003-2017, the average growth in productivity for the national LDC industry sample was equal to

percent, while the economy-wide productivity growth was equal to 0.60 percent, which generated a productivity differential of -0.51 percent for the study period (0.09 percent less

percent = -0.51 percent) (Exh. ES-JF/MF-2, at 47). For the same period, the average input price growth for the national LDC industry sample was equal to 2.79 percent, while the economy-wide input price growth was equal to 2.51 percent, which generated an input price differential of -0.28 percent (2.51 percent less 2.79 percent = -0.28 percent)
(Exh. ES-JF/MF-2, at 47). The sum of the national productivity differential and the national input price differential in the Company's initial results generated a -0.79 percent X factor (-0.51 percent plus -0.28 percent) (Exh. ES-JF/MF-2, at 47). When the Company initially conducted the TFP study using its regional LDC industry sample, the average growth in productivity was -0.39 percent, which generated a productivity differential of -0.98 percent (Exh. ES-JF/MF-2, at 47). The regional sample also produced an industry input price growth average of 2.83 percent, which generated an input price differential of -0.32 percent (Exh. ES-JF/MF-2, at 47). The sum of the regional productivity differential and the regional

input price differential in the Company's initial study generated a -1.30 percent X factor (Exh. ES-JF/MF-2, at 47). During the course of the proceeding, the Company

at 2). Regarding geometric decay, the flow of services from investments in a given year declines at a constant rate over time (Exh. AG-MNL-2, at 13). The Kahn method decomposes capital cost into a price and quantity index using a simplified version of cost of service accounting (Exh. AG-MNL-2, at 15, 39).

D.P.U. 19-120

Page 27

acknowledged that energy efficiency program costs for three Massachusetts LDCs were

inadvertently included in the initial TFP study results25 (RR-DPU-21, at 1). After removing

the energy efficiency program costs and rerunning the study, the TFP increased by three

basis points and 12 basis points in the national and regional samples, respectively

(RR-DPU-21, at 1). Accordingly, the national and regional X factors resulting from the

update are -0.76 percent and -1.18 percent, respectively (RR-DPU-21, at 2).

The Company proposed that the updated X factor of -1.18 percent be incorporated in

the PBRM, which observes the productivity average of the regional sample (Company Brief

at 26, citingRR-DPU-21, at 2). The Company stated that this X factor is most appropriate

because there are factors that may impact productivity growth in the LDC sector that vary

between the Northeast Region and the rest of the U.S., specifically economies of scale,

technology, and output growth (Exh. ES-JF/MF-1, at 29-31).

Consumer Dividend

NSTAR Gas proposed not to include a consumer dividend component to its PBRM

(Exh. WJA/DPH-1, at 84). In theory, a consumer dividend reflects an expectation that

efficiency gains not captured in the rates approved at the beginning of the PBR Plan term,

will be realized as a result of the PBR Plan over the course of the PBR Plan term

25 The Company's consultant represented that it excluded energy efficiency program costs associated with all Massachusetts LDCs included in the study sample, but discovered that for Boston Gas Company, Colonial Gas Company, and Bay State, such costs were reported in Account 905, rather than Account 815 (RR-DPU-21,

at 1). The Company reran the TFP and benchmarking studies removing Account 905 for the three identified companies (RR-DPU-21, at 1).

D.P.U. 19-120Page 28

(Exh. ES-WJA/DPH-1, at 83). A consumer dividend is designed to share those efficiency gains with customers. The proposal to exclude a consumer dividend was the result of a cost benchmarking study that compared the Company's cost performance to its peers, finding that NSTAR Gas was relatively efficient compared to its peers (Exh. ES-WJA/DPH-1, at 84).

Exogenous Cost Factor (Z Factor)

The Company proposed to include an exogenous cost provision ("Z factor"), which it defines as positive or negative changes to its costs that are beyond NSTAR Gas's control and are not reflected in the GDP-PI (Exh. ES-WJA/DPH-1, at 85). The Company further defined the criteria for any costs that would be eligible for recovery through the Z factor as those that are due to changes in tax laws, accounting requirements, or regulatory, judicial, or legislative acts, each of which uniquely affect the natural gas distribution industry

(Exh. ES-WJA/DPH-1, at 85). More specifically, the Company proposed a two-part exogenous cost mechanism: (1) includes events that meet the Department's established criteria for an exogenous event (described above); and (2) a more targeted definition specific to exogenous events arising due to pipeline safety requirements imposed after November 8, 2019, with demonstrated cost impacts after the date of the PBRM, November 1, 2020 (Exh. ES-WJA/DPH-1, at 85-86). The Company stated that it would be necessary to include the two-part definition of exogenous event in order to commit to the five-year stay out (Exhs. ES-WJA/DPH-1, at 85; DPU-ES12-9).

In addition, the exogenous cost for either proposed part would be required to meet a significance threshold of $700,000, which was determined by multiplying the Company's

D.P.U. 19-120

Page 29

total operating revenues for calendar year 2018 of $499,895,237 by 0.00125326 and then

rounding upwards (Exhs. ES-WJA/DPH-1, at 86-87;DPU-ES12-2).27 The Company

proposed two slightly different treatments of the threshold for the two proposed parts of the

definition of an exogenous cost: (1) the significance threshold for the first part, the

traditional exogenous factor, would include O&M cost changes in a single year, and (2) the

significance threshold for the second part, specific to pipeline safety requirements, would

allow for both capital and O&M cost changes, applied separately to capital and O&M

(Exh. WJA/DPH-1, at 87). Further, the significance threshold for each part would be

subject to annual adjustments based on changes in GDP-PI (Exh. WJA/DPH-1, at 87).

Y Factor

Initially, the Company proposed to recover the costs associated with the

implementation of two demonstration projects through the Y factor component of the PBRM

by amortizing the costs of the projects over the five-year term as actual costs are incurred

(Exh. ES-WJA/DPH-1, at 90). The two demonstration projects include a gas demand

response project and a geothermal distribution demonstration project (Exh. ES-WJA/DPH-1,

at 90). These projects are discussed in more detail in Section VI. During the proceedings,

The Company states that the Department has previously approved a factor of 0.001253 for use in deriving the threshold for exogenous cost recovery (Exh. ES-WJA/DPH-1, n. 14, citing NSTAR Electric Company/Western Massachusetts Electric Company, D.P.U. 17-05, at 397 (2017)).

The Company further explained that when considering the threshold for the Company's second part of the definition, the impact of a change in capital costs would be determined as the revenue requirement impact of the cost change attributed to the exogenous event (Exh. DPU-ES12-5).

D.P.U. 19-120

Page 30

NSTAR Gas proposed that the Y factor be collected as a component of the local distribution

adjustment factor ("LDAF") to work in tandem with the PBRM, but not as an explicit

component of the PBR formula (Exh. ES-RDC/LMC-2 (Rev.) at 126; Tr. 7, at 366-367).

Earnings Sharing Mechanism

As part of the PBRM, the Company proposed to adopt an ESM with a symmetrical

deadband of 100 basis points (Exh. WJA/DPH-1, at 91). The proposed ESM would trigger a

sharing of earnings or losses with customers on a 75 (customers)/25 (shareholders) basis

when the actual distribution ROE exceeds 100 basis points above or below the ROE

authorized by the Department (Exh. ES-WJA/DPH-1, at 91).28 NSTAR Gas indicated that

its proposed ESM is necessary for the Company to commit to the five-year stay out

(Exhs. ES-WJA/DPH-1, at 94; DPU-ES12-9). Calendar year 2021 would be the first year

for which the Company would evaluate whether an ESM adjustment were appropriate, for

effect November 1, 2022 (Exh. ES-WJA/DPH-1, at 93).

28 The Company proposed that the distribution ROE be calculated using earnings available for common equity and the capital structure approved by the Department in this proceeding (Exh. ES-WJA/DPH-1, at 92; proposed M.D.P.U. No. 411, § 9.0). The Company proposed that the calculation of utility net income used in the calculation of ROE will exclude incentive payments such as energy efficiency incentives, service-quality penalties, and any settlements or decisions related to prior periods (Exh. WJA/DPH-1, at 92; proposed M.D.P.U. No. 411, § 9.0).

D.P.U. 19-120			Page 31
3.	Positions of the Parties
	a.	Attorney General
		i.	Introduction

The Attorney General argues that the Department should reject the proposed PBRM or, in the alternative, adopt the PBRM with certain changes and terminate the Company's GSEP (Attorney General Brief at 117, 137; Attorney General Reply Brief at 40, 54). The Attorney General claims that: (1) the PBR term of five years is inconsistent with Department precedent and not long enough to achieve the efficiency promised to ratepayers and shareholders; (2) the PBRM will result in the double recovery of capital addition costs; and

(3) the Company's proposed X factor, ESM, and lack of consumer dividend render the proposal flawed, resulting in unjust and unreasonable rates that are not cost-based (Attorney General Brief at 114-116, 118, 134, 137; Attorney General Reply Brief at 37-39,45-50). The Attorney General also criticizes the Company's threats to abandon the PBR Plan if the Department does not authorize all components as proposed (Attorney General Reply Brief

at 53, citingCompany Brief at 47). While the Attorney General makes specific arguments as to why the PBR Plan should be rejected, she also offers recommended modifications, should the Department approve a PBRM for NSTAR Gas (Attorney General Brief at 114-137; Attorney General Reply Brief at 37-54).

PBR Term

The Attorney General argues that the Department has previously found that five-year terms are not long enough to achieve the efficiencies and benefits that a PBR Plan is expected to provide (Attorney General Brief at 114-115; Attorney General Reply Brief at 37-38). The

D.P.U. 19-120Page 32

Attorney General references the Department's rejection of Boston Gas's proposed five-year term in D.P.U. 03-40 and the rejection of Bay State Gas's five-year term in D.P.U. 05-27, both in favor of ten-year terms, while also noting that both PBR plans were terminated early when found to not be working as intended (Attorney General Brief at 114-116; Attorney General Reply Brief at 37-38, 54). The Attorney General claims that the Company's reliance on recently approved electric distribution company PBR plans in D.P.U. 17-05 and D.P.U. 18-150 with five-year terms is tenuous and inapplicable, as NSTAR Gas is not an electric distribution company, and PBR plans for the two industries are wholly disparate (Attorney General Reply Brief at 37).

Post Test Year Capital Additions

The Attorney General maintains that NSTAR Gas has failed to provide a legitimate basis for the Department to depart from its longstanding precedent (Attorney General Brief at 19). The Attorney General contends that, even if the Department approves the Company's proposed PBRM, an exception to the post-test-year standard on rate base additions is not appropriate (Attorney General Brief at 14, citingD.P.U. 96-50-C (Phase I) at 16-17; D.P.U. 96-50 (Phase I) at 15).

According to the Attorney General, the Company's 2019 plant investments compared to its history from 2015 through 2018 undermines the argument that the carrying cost of these post-test-year investments would amount to a significant burden (Attorney General Brief at 16-17). The Attorney General also dismisses the Company's concern that the ESM in its proposed PBRM will be triggered if the Department does not allow the inclusion of 2019 and

D.P.U. 19-120Page 33

2020 capital additions in rate base (Attorney General Brief at 16, citingCompany Brief at 73; Tr. 6, at 711-715). According to the Attorney General, even if the Department were to approve the Company's proposed PBRM, there should be no concern about triggering the ESM because of: (1) the revenue growth from growth-related capital additions; (2) the reduction in NSTAR Gas's costs associated with the acquisition of Bay State's operations;

the expected zero growth in operations and maintenance expenses; and (4) basic prudent budget management (Attorney General Brief at 16, 23-24,61-63).
Additionally, the Attorney General rejects the Company's claim that post-test-year investments should be included in rate base because "increasing investment is projected to continue" (Attorney General Reply Brief at 6, citingCompany Brief at 50, 70, 72). In particular, she notes that the Company did not provide project proposals, budgets, or approvals to support the necessity, the prudence, or the dollar amount associated with the claimed spending for the years 2020 through 2025 (Attorney General Reply Brief at 6).

Further, the Attorney General points out that the Company's list of projects anticipated to be in service in 2020 was $25.17 million, $10 million short of the Company's predicted amount of $35.9 million (Attorney General Reply Brief at 6, citingExh. DPU-ES33-18). She claims that the same shortfall of anticipated in-service projects exists for 2021, as evidenced by a comparison between the estimated spend of $26.3 million and projected spend of $50.1 million (Attorney General Reply Brief at 6-7,citingExh. DPU-ES33-18).

Moreover, the Attorney General argues that the Company's reliance on the Department's decision in D.P.U. 18-150 to justify the departure from precedent ignores the

D.P.U. 19-120Page 34

basis for that decision, which she claims was National Grid's transitioning from traditional cost of service ratemaking with a capital tracker to a PBRM (Attorney General Brief at 16; Attorney General Reply Brief at 4). The Attorney General argues that NSTAR Gas, unlike National Grid, is not transitioning from a capital tracker to a PBRM, but simply is seeking to roll into rate base investments made since its last base distribution rate case (Attorney General Brief at 16).

Regarding the Company's proposed roll-in of 2020 non-GSEP capital additions in its first PBR adjustment, the Attorney General asserts that the Company also fails to meet the Department's post-test year adjustment standard (Attorney General Brief at 19). Moreover, the Attorney General argues that the Company has not provided any documentation regarding the 2020 additions and concludes that they are neither known and measurable nor shown to be significant (Attorney General Brief at 19).

X Factor

Introduction

The Attorney General claims that the Company's proposed X factor is unreasonable, and she calculates her own using various alternatives to the Company's TFP study parameters and methodology (Attorney General Brief at 118, 125; Attorney General Reply Brief

at 39-40). With respect to the Company's TFP study, the Attorney General raises specific concerns regarding: (1) the treatment of Customer Service and Information ("CS&I") expense; (2) the chosen sample/peer group; (3) the use of allegedly flawed data; and (4) the benchmark year selection (Attorney General Brief at 120-125; Attorney General Reply Brief

D.P.U. 19-120	Page 35
at 41-45). The Attorney General proposed an X factor of -0.69 percent based on her
alternative methodology (Attorney General Brief at 126).29
(B)	Treatment of CS&I Expenses

The Attorney General alleges that the Company's inclusion of CS&I expenses is inappropriate and biases the X factor in favor of NSTAR Gas (Attorney General Brief

at 120-121; Attorney General Reply Brief at 41-42). The Attorney General notes that some, but not all, LDCs include demand-side management ("DSM") expenses under the CS&I expense category, and that DSM expenses are not itemized or easily identifiable (Attorney General Brief at 120, citingExhs. ES-JF/MF-Rebuttal-1, at 25-27;AG-MNL-Surrebuttal

at 4; AG 9-10; Tr. 7, at 912-915; Attorney General Reply Brief at 41-42). While the Company excluded its own DSM expenses from its TFP study, the Attorney General contends that the inclusion of CS&I expenses for other companies likely includes DSM expenses, which have grown rapidly for many LDCs during the 15-year study timeframe (Attorney General Brief at 121; Attorney General Reply Brief at 41-42). Based on the divergent reporting and potential magnitude of DSM expenses, the Attorney General maintains that CS&I expenses should be excluded from TFP studies, as they were in the productivity studies sponsored by electric distribution companies in their recent PBR proposals (Attorney General Brief at 121, citingExhs. AG-MNL-1, at 13; AG-MNL-Surrebuttal at 4).

29 The X factor computed by the Attorney General uses a national industry sample/peer group, which was adjusted to exclude CS&I expenses and alleged problematic data (Attorney General Brief at 126).

D.P.U. 19-120Page 36

To support her claim that inclusion of CS&I expense has a material effect on the X

factor, the Attorney General points to the Company's updated X factor after removing DSM expenses for three additional Massachusetts LDCs, which increased by 12 basis points (Attorney General Reply Brief at 41-42). The Attorney General contends that DSM expenses are still included for other LDCs in the regional sample in the instances where they are included under CS&I expense, and, as such, they skew the X factor results to be more

negative (Attorney General Reply Brief at 42).30

Peer Group Selection (national vs. regional)

The Attorney General argues that the regional sample group is not an appropriate peer group for the Company and that the national sample should be used to set the X factor (Attorney General Brief at 122; Attorney General Reply Brief at 43). The Attorney General notes that in recent PBR proceedings before the Department, X factors were determined based on a national peer group, but that here the Company shifts to the sample group that provides a more favorable X factor to NSTAR Gas (Attorney General Brief at 123; Attorney General Reply Brief at 43).

While the Company defends the use of a regional group because of differences in economies of scale and output growth between the regional and national group, the Attorney General claims that NSTAR Gas's customer growth is more aligned with the national group and that empirical evidence related to the effects of LDC size and economies of scale were

30 The Attorney General maintains that increased energy savings resulting from increased

DSM and CS&I expenses are not captured in the study's output metric, which causes skewed TFP results (Attorney General Brief at 121).

D.P.U. 19-120Page 37

not provided (Attorney General Brief at 122; Attorney General Reply Brief at 43-44). The Attorney General also challenges the Company's assertion that a regional group is more appropriate based on the higher composition of leak-prone mains in the Northeast, noting that the cost to replace these mains are addressed and recovered through the Company's GSEP (Attorney General Brief at 122; Attorney General Reply Brief at 44). Moreover, the Attorney General contends that the TFP growth of the Northeast region is likely slowed by the replacement of cast iron and bare steel mains and that this further supports the use of a national peer group (Attorney General Brief at 123, citingExh. AG-MNL-Surrebuttal, at 17; Attorney General Reply Brief at 44-45).

Use of Allegedly Flawed Data

The Attorney General maintains that some of the data used in the Company's TFP study is problematic and ran her own TFP study which, among other changes, removed the alleged problematic data (Attorney General Brief 123-124; Attorney General Reply Brief at 42). Specifically, the Attorney General asserts that the Company's study included LDCs with data that was compromised by merger, acquisition, and divestiture problems (Attorney General Brief at 123, citingExh. ES-JF/MF-Rebuttal-1, at 35-36). The Attorney General claims that NSTAR Gas has not adequately defended the use of such data, and that the Company's suggestion that aggregating data would obviate any potential issues is incorrect (Attorney General Brief at 123; Attorney General Reply Brief at 42-43).

TFP Study Benchmark Year

The Attorney General argues that the use of a recent benchmark year is suboptimal, as the accuracy of the capital quantity index is improved when the benchmark year is as early

D.P.U. 19-120Page 38

as possible (Attorney General Brief at 124, citingExhs. AG-MNL-1, at 8-9;AG-MNL-3,

at 31). The Attorney General notes that the Company's benchmark year of 1998 is only five years before the start of the study sample period, whereas the benchmark year in the recent National Grid PBR proposal was 1964 (Attorney General Brief at 124; Attorney General Reply Brief at 43). The Attorney General contends that by assuming the same system age for all LDCs as part of its TFP study despite the Northeast having older systems, estimated productivity growth is slowed, and that the use of a recent benchmark year only exacerbates this problem (Attorney General Brief at 124-125; Attorney General Reply Brief at 43).

Consumer Dividend

Introduction

The Attorney General states that the Company's exclusion of a consumer dividend is based on NSTAR Gas's econometric benchmarking study, which purports to show that the Company is a relatively efficient cost performer compared to its peers (Attorney General Brief at 127; Attorney General Reply Brief at 49). The Attorney General raises several concerns regarding the Company's benchmarking study, including: (1) the benchmark year selection and timeframe; (2) the inclusion of CS&I expenses; (3) the study sample timeframe;

the manner in which prices are levelized; and (5) the complexity of the benchmarking study (Attorney General Brief at 127-131). Based on her own benchmarking analysis that

attempts to address her concerns, the Attorney General argues that NSTAR Gas's cost performance was merely average amongst its peers (Attorney General Brief at 132, citingExh. AG-MNL-3, at 53). The Attorney General contends that average cost performance is commensurate with a consumer dividend of 0.3 to 0.4 percent, and that it is both improper

D.P.U. 19-120Page 39

and unusual to claim that no consumer dividend is warranted unless a company is a markedly superior cost performer (Attorney General Brief at 132; Attorney General Reply Brief at 49). The Company, the Attorney General argues, is simply not a superior cost performer (Attorney General Reply Brief at 49).

Benchmark Year and Timeframe

With respect to the chosen benchmark year, the Attorney General voices the same concerns for the benchmarking study as the TFP study regarding the recency of the benchmark year and the potential for it to skew the accuracy of results (Attorney General Brief at 127; Attorney General Reply Brief at 40-41, 43). Regarding the benchmarking timeframe, the Attorney General contends that the latest benchmarking year of 2017 is only three years before the first year of the proposed PBR Plan, and she takes issue with the exclusion of the Company's 2018 test-year costs from the study (Attorney General Brief

at 129).

Treatment of CS&I Expenses

As in the case of the TFP study, the Attorney General disagrees with the inclusion of CS&I costs in the Company's benchmarking study, claiming that the inclusion throws into question the entire LDC ranking since the Company is unable to determine how many of the LDCs in the sample had DSM program expenses (Attorney General Brief at 128, citingExh. AG 9-10). The Attorney General further indicates that, if CS&I costs are removed, the Company's cost performance ranking drops from the first quartile to the second quartile (Attorney General Brief at 129, citingRR-DPU-21, at 3; Attorney General Reply Brief,

at 49, citingRR-DPU-21, at 3).

D.P.U. 19-120

Page 40

Sample Timeframe

The Attorney General asserts that the Company's benchmarking study needlessly restricted the sample period for its econometric work, and that a longer sample period would have improved the precision of the model estimates and predictions (Attorney General Brief at 129, citingExh. AG-MNL-3, at 44). In response to the Company's claim that a shorter time series was examined to measure current efficiency of each firm relative to its peers, the Attorney General indicates that a longer period could have been used if a trend variable were added to the cost model (Attorney General Brief at 129). The Attorney General claims that the restricted timeframe is not standard practice in econometric cost benchmarking studies (Attorney General Brief at 129, citingExh. AG-MNL-3, at 44).

Price Levelization

The Attorney General contends that the Company improperly levelized input prices, such that differences in price levels faced by LDCs were poorly measured (Attorney General Brief at 129). As an example, the Attorney General contends that for certain years labor and construction prices were assumed to be the same for all utilities, whereas in other years prices differed slightly if regional price trends differed (Attorney General Brief at 129). The Attorney General claims that this treatment of prices is unusual in econometric utility cost research (Attorney General Brief at 129).

Complexity of Benchmarking Model

The Attorney General insists that the Company's benchmarking model is unnecessarily complex, utilizing a multi-equation model with a cost share equation and cost function, as well as quadratic and interaction terms for certain variables (Attorney General Brief at 130,

D.P.U. 19-120Page 41

citingExhs. ES-JF/MF-3, at 20-21; AG 37-1, (Supp.) Att. at 28). The Attorney General argues that the complexity, along with the short sample period, results in variables with few statistically significant parameter estimates (Attorney General Brief at 130-131).

Earnings Sharing Mechanism

The Attorney General opposes the Company's symmetrical ESM, stating that it

punishes ratepayers by sharing the costs if productivity gains are lackluster (Attorney General Brief at 133). Additionally, the Attorney General insists that the ESM will not prevent NSTAR Gas from overearning, but simply will limit the amount of overearning and double recovery (Attorney General Reply Brief at 50). Because any sharing with ratepayers would not occur until earnings surpassed the 100-basis point deadband, the Attorney General alleges that the Company could over earn by approximately six to eight million dollars a year before needing to return some of the over earnings to customers (Attorney General Reply Brief

at 50). If the Department is to approve the Company's PBR Plan, the Attorney General recommends that the Department adopt an asymmetrical ESM where sharing only occurs if the Company's ROE is 100-basis points above the allowed ROE (Attorney General Brief

at 134). In support of her recommendation, the Attorney General refers to the asymmetrical ESMs approved by the Department in recent PBR proposals (Attorney General Brief at 134, citingD.P.U. 18-150, at 70; D.P.U. 17-05, at 401).

Double Recovery of Capital Costs

The Attorney General alleges that the Company's PBR Plan allows for double recovery of certain capital addition costs, namely those associated with leak-prone pipe replacement recovered through the GSEP (Attorney General Brief at 135-136; Attorney

D.P.U. 19-120Page 42

General Reply Brief at 45). The Attorney General states that a comprehensive PBR proposal includes the recovery of all capital and, therefore, a PBR proposal with a capital tracker like the GSEP will inevitably lead to double recovery (Attorney General Brief at 135-136; Attorney General Reply Brief at 46). The Attorney General notes that the Company's affiliate, NSTAR Electric Company ("NSTAR Electric"), recognized in its their proposal in D.P.U. 17-05 that a utility should have a capital tracker or a PBR plan, but not both (Attorney General Brief at 137).

Moreover, the Attorney General rejects the Company's claims that without the GSEP the Company would not replace, nor would base rates provide recovery for, any leak-prone mains or services (Attorney General Brief at 135; Attorney General Reply Brief at 47). She avers that the Company has been replacing leak-prone pipe since its inception and certainly before the GSEP was put in place (Attorney General Brief at 135; Attorney General Reply Brief at 47).

DOER

DOER acknowledges the Department's precedent approving PBRMs in the past for distribution companies, and notes that approval of such a mechanism should rest on a finding that it will result in just and reasonable rates (DOER Brief at 2). DOER does not comment on the individual elements of the Company's proposed PBRM on brief, but defers to the Department in evaluating the reasonableness of the proposal (DOER Brief at 13-14).

DOD-FEA

DOD-FEA argues that the Company's proposed PBRM should be rejected in its entirety (DOD-FEA Brief at 28, 31). DOD-FEA contends that the PBR proposal will erode

D.P.U. 19-120Page 43

customer protections as rates will increase without any formal cost of service reviews and that customers will not have an opportunity to contest the reasonableness of rates (DOD-FEA Brief at 28-29). Further, DOD-FEA asserts that PBR is not designed to work in conjunction with the Company's LDAC and GSEP (DOD-FEA Brief at 29). According to DOD-FEA, the proposed PBRM accomplishes nothing more than create a simple administrative means to adjust rates between rate cases, and administrative ease should not come at the expense of customer protections and reasonable rates (DOD-FEA Brief at 30). DOD-FEA stresses that rates should be based on known and measurable cost changes (DOD-FEA Brief at 31).

DOD-FEA contends that traditional ratemaking creates stronger incentives than PBR to manage and contain costs, as the Company would need to reduce operating expenses below the test year level of costs in order to enhance profits (DOD-FEA Brief at 31-32). In contrast, under the PBRM, DOD-FEA states that rates would adjust annually based on forecasts that have no direct relationship to the Company's actual costs, allowing the Company to earn more than the Department's authorized return (DOD-FEA Brief at 31-32).

TEC argues that the Company's proposed PBRM is flawed and should be rejected (TEC Brief at 6). TEC indicates that the flaws include, but are not limited to: (1) an overly broad exogenous cost factor; (2) potential capital additions without customer safeguards; (3) an ESM that heavily favors NSTAR Gas; and (4) the potential for overlap with the GSEP (TEC Brief at 6).

D.P.U. 19-120Page 44

Regarding the exogenous cost factor, TEC takes issue with the recovery of costs

relating to future standards or practices for gas pipeline safety directives, arguing that such expenses should not trigger an exogenous cost event, as safety is a core function of running a gas utility (TEC Brief at 6-7). TEC also asserts that an exogenous cost factor should only recover costs that are truly unforeseeable and beyond the Company's control, and should not incentivize the Company to be indifferent to changes where it may have some degree of control or legal recourse (TEC Brief at 7).

TEC also raises concerns with the Company's proposal to roll in capital additions since the start of the PBR term if the five-year term is extended to a ten-year term (TEC Brief at 7; TEC Reply Brief at 9, 11). TEC argues that the Department has a responsibility to ratepayers to ensure that capital additions are prudent and that any future roll-in should occur only through a base distribution rate proceeding (TEC Brief at 7). TEC contends that a base distribution rate proceeding after five years would give the Department an opportunity to evaluate the PBRM and that any capital addition roll-in with limited oversight would set bad precedent (TEC Brief at 7-8; TEC Reply Brief at 10).

TEC echoes the Attorney General's concerns regarding the ESM, noting that as proposed it functions as a form of ROE insurance for NSTAR Gas (TEC Brief at 8). TEC suggests that if an ESM is approved, it should be asymmetric with over earnings refunded to ratepayers (TEC Brief at 8). TEC also echoes the Attorney General's concerns regarding the potential for the PBRM to overlap with reconciling mechanisms, and suggests that the Department examine any potential effect on the X factor (TEC Brief at 7). TEC argues that

D.P.U. 19-120

Page 45

the X factor approved must be high enough to protect ratepayers and incentivize efficient

operation by the Company (TEC Brief at 8-9).

Company

Introduction

NSTAR Gas argues that its proposed PBR Plan will create a strong economic

incentive for the Company to manage its costs, provide the flexibility and predictability

necessary to face the near-term uncertainties facing the natural gas industry, and maintain

safe and reliable service (Company Brief at 17-18,21-23; Company Reply Brief at 2-3). The

Company rejects claims made by intervenors that the PBR Plan erodes customer protections

and avers that Department oversight will increase with annual compliance filings (Company

Brief at 76-77). The Company argues that its proposal is consistent with Department

precedent that has previously found that PBR is appropriate as an alternative to traditional

ratemaking to address a changing operating environment and higher customer expectations

(Company Brief at 16, 23, citingD.P.U. 18-150, at 53; Company Reply Brief at 29). The

Company identifies a variety of challenges, including the changing operating environment for

LDCs, the need to address environmental impacts, and the step-up in safety requirements

resulting from the Merrimack Valley incident,31 and claims that the PBR will best support the

Company in addressing these challenges (Company Brief at 23).

31 On September 13, 2018, Bay State experienced an overpressurization of its low-pressure distribution system serving the City of Lawrence and the towns of Andover and North Andover in the Merrimack Valley. National Transportation Safety Board Pipeline Accident Report, NTSB/PAR-19/02 (NTIS

No. PB2019-101365), adopted September 24, 2019 ("NTSB Report") at 1. The overpressurization allowed gas from a high-pressure distribution system to enter the

D.P.U. 19-120Page 46

The Company asserts that the PBR formula is derived through economic analysis of

utility cost trends and that the revenue-per-customer cap is designed to work in tandem with the revenue decoupling mechanism approved in D.P.U. 14-150 (Company Brief at 18, 24). NSTAR Gas contends that the benefits of the proposed PBR Plan include the reduction in regulatory costs and burden, lower customer costs in the long term, and enhanced operations and safety (Company Brief at 22-23). NSTAR Gas maintains that the proposed PBR Plan will provide benefits for both customers and the Company and that it should be approved as proposed (Company Brief at 21-23; Company Reply Brief at 23-24).

PBR Term

The Company argues that the proposed five-year PBR term and potential five-year extension will reduce regulatory burden and associated customer costs, indicating that, without a PBR plan, the Company anticipates needing to file a base distribution rate proceeding every other year (Company Brief at 46-47; Company Reply Brief at 10, 26). With a five-year term beginning November 1, 2020 and ending October 31, 2025, the Company insists that the PBR Plan would avoid at least two rate cases (Company Brief at 47, citingExh. ES-WJA/DPH-1, at 93, 94). NSTAR Gas contends that the five-year term provides the appropriate incentives for cost savings and operational efficiencies (Company Brief at 47, 55; Company Reply Brief at 4-5). The Company asserts that its proposal is consistent with the Department's decision in D.T.E. 03-40 to impose a ten-year PBR plan

low-pressure distribution system. NTSB Report at 1. This lack of proper system regulation resulted in the damage or destruction of 131 homes and businesses, the hospitalization of 22 individuals, and the death of one person. NTSB Report at 1.

D.P.U. 19-120Page 47

with a mid-point review to determine if the plan should continue or be terminated (Company Reply Brief at 4). Moreover, the Company contends that the Attorney General's reliance on Department precedent from almost ten years prior to suggest that a five-year term is too short is inapposite, as the current challenges facing the natural gas industry are different (Company Reply Brief at 5). The Company also indicates that any extension of a second five-year term would be subject to Department oversight (Company Reply Brief at 26).

Post Test Year Capital Additions

NSTAR Gas argues that the rate base roll-ins associated with 2019 and 2020 plant are appropriate and critical to the proposed PBR Plan (Company Brief at 67, 72). As an initial matter, the Company rejects the Attorney General's assertions that she was not afforded due process with respect to the 2019 non-GSEP capital additions, arguing there was ample time to review and respond to the Company's proposed 2019 capital additions prior to evidentiary hearings (Company Brief at 68-69). The Company further argues that the Attorney General retained, at customers' expense, an expert consultant whose sole purpose in the proceeding was to assist in the review of the Company's capital additions, including the 2019 non-GSEP investments (Company Brief at 69). NSTAR Gas maintains that the Attorney General had ample time to review the 2019 non-GSEP investment documentation and, as such, there has been no infringement of her rights under G.L. c. 30A, § 11 (Company Brief at 69-70).

NSTAR Gas contends that, contrary to the Attorney General's argument, even when combined with the potential PBR revenues, the cost of carrying the non-GSEP investment is insufficient to offset the potential PBR revenues, even when coupled with customer growth

D.P.U. 19-120	Page 48
revenues (Company Reply Brief at 31, citingTr. 6, at 807; RR-DPU-3;RR-DPU-4;

RR-DPU-16). In addition, the Company states that the opportunity to earn revenues from new business is in decline and expected to further diminish due the increasing cost of connecting customers (Company Reply Brief at 32). In particular, the Company notes that between 2015 and 2019 there were 2,300 customers requesting gas service that were not connected due to required contributions in aid of construction ("CIACs") (Company Reply Brief at 32).

The Company insists that the main driver for its PBR Plan is the unprecedented level of capital investments that it has made and will continue to make (Company Brief at 70). NSTAR Gas claims that rate base increased by nearly 90 percent since the Company's last base distribution rate proceeding and that the PBR Plan was designed to address the most significant cost pressures facing the Company (i.e., capital investments) (Company Brief

at 70, 72). By incorporating the 2019 non-GSEP capital additions into base distribution rates for effect November 1, 2020, and the 2020 non-GSEP capital additions on November 1, 2021, the Company claims that it will be able to potentially avoid a base distribution rate proceeding for a period of longer than five years (Company Brief at 70, 72, citing

Exh. ES-DPH/ANB-1, at 10). Moreover, the Company argues that excluding the capital additions would dilute, if not entirely defeat, the purpose of a shift from traditional cost of service regulation to incentive regulation and insists that the revenue support provided by the PBR adjustments, as well as any potential growth in customer revenues, would be insufficient

D.P.U. 19-120Page 49

to support necessary capital investments during the PBR term (Company Brief at 73, citingRR-DPU-15;RR-DPU-16).

Regarding the 2020 non-GSEP capital roll-ins, NSTAR Gas contends that it will file the necessary project documentation with the Department on April 1, 2021, prior to the first annual PBR rate adjustment filing on August 1, 2021, for rates effective November 1, 2021, to provide ample time for review (Company Brief at 75, citingExh. DPU-ES7-3). The Company maintains that it is not seeking pre-approval of cost recovery associated with these projects prior to the Department's conducting a prudence review and, as such, the

2020 non-GSEP capital additions will undergo a proper review prior to inclusion in rates (Company Brief at 76).

Moreover, the Company argues that in order for the PBRM to continue for a second five-year term, it is essential to include the revenue requirement associated with the 2021 through 2024 investments in base distribution rates in year five of the PBR term (Company Brief at 79). Accordingly, NSTAR Gas maintains that it would notify the Department in the September 15, 2024 compliance filing whether it intends to continue the PBRM for a second five-year term or file for a base distribution rate increase for effect November 1, 2025 (Company Brief at 54, citingExh. ES-WJA/DPH-1, at 99).

X Factor

Introduction

NSTAR Gas argues that the proposed X factor of -1.18 percent is reasonable and adequately supported by the record (Company Brief at 36, 55; Company Reply Brief at 12). According to the Company, the X factor is the productivity offset based on an industry TFP

D.P.U. 19-120Page 50

study, where the resulting factor represents a rate of growth for efficiency that the Company must achieve in order to earn its allowed rate of return (Company Brief at 26-27,citingExh. DPU-ES22-11). The Company avers that it appropriately adjusted the TFP study to ensure that energy efficiency program costs for all Massachusetts LDCs were removed and that there is no valid reason to reject the proposed PBR Plan or X factor (Company Brief at 26, n.8, 56). The Company argues that none of the Attorney General's critiques of its TFP study are persuasive and that the Department should reject her recommended X factor of - 0.69 (Company Brief at 55, 60; Company Reply Brief at 12-16).

Treatment of CS&I Expenses

The Company argues that the Attorney General's proposal to exclude CS&I expenses from the TFP study is inappropriate and, moreover, fails to solve the alleged concerns surrounding DSM programs (Company Reply Brief at 18). NSTAR Gas contends that while the Attorney General's witness did not observe trends in DSM expenses over time, data published in the American Council for an Energy-Efficient Economy reports demonstrate DSM expenses have been declining over time (Company Reply Brief at 19, citingTr. 11, at 1446-1450,1452-1453). The Company asserts that CS&I expenses as a whole have been rising over time, which invalidates the Attorney General's claim that DSM expenses are a majority of the costs included in CS&I expense (Company Reply Brief at 19, citing

Exh. AG 44-6). Further, the Company argues that this evidence supports the fact that CS&I expense contains legitimate costs that should be included in the TFP study (Company Reply Brief at 19).

D.P.U. 19-120

Page 51

Peer Group Selection (national vs. regional)
NSTAR Gas argues that the regional peer group is most appropriate for determining

the X factor and that the Attorney General's recommendation of a national peer group is simply results driven and not based on methodological principles (Company Reply Brief

at 14). NSTAR Gas insists that trends experienced by the Northeast regional peer group are most similar to the actual experiences of the Company and, therefore, will result in the most accurate X factor (Company Reply Brief at 15). The Company argues that differences between the regional and national TFP trends are due to regional drivers such as the presence of cast iron and bare steel mains, economies of scale, technology, and output growth (Company Reply Brief at 15-16). NSTAR Gas maintains that TFP trends for the Northeast region are slower overall due to capital input trends, OM&A input trends, and output trends overall (Company Reply Brief at 16, citingTr. 6, at 930-932). Moreover, the Company contends that use of a regional peer group is consistent with Department precedent for determining LDC X factors (Company Brief at 35, citingD.T.E. 03-40, at 475; Company Reply Brief at 15).

Use of Allegedly Flawed Data

The Company rejects the Attorney General's allegations that the TFP study relies on flawed data, stating that her assertions are wrong and should be disregarded (Company Brief at 59; Company Reply Brief at 14). In response to claims that data was compromised by mergers, acquisitions, and divestiture problems, NSTAR Gas contends that the Attorney General's witness failed to educate himself on the timing and implications of such events and that the Attorney General did not properly evaluate whether the associated data was

D.P.U. 19-120Page 52

appropriate to include in the TFP study (Company Brief at 59, citingTr. 11, at 1464-1467; Company Reply Brief at 14). NSTAR Gas claims that the Attorney General arbitrarily excluded additional data associated with certain companies due to company size, and companies with perceived anomalies without fully understanding the data or properly supporting the exclusions (Company Brief at 59, citingTr. 11, at 1460).

TFP Study Benchmark Year

NSTAR Gas asserts that the proposed benchmark year was chosen to include a greater cross-section of quality, reliable utility data, as well as to account for the change in focus to replacement of leak-prone pipe (Company Brief at 60; Company Reply Brief at 17, citingExh. AG 9-1). The Company contends that the Attorney General's proposal to use an earlier benchmark would result in a sizable loss of companies in the study due to unreliable or incomplete data (Company Brief at 59-60). Moreover, the Company asserts that the Attorney General's claim that a more recent benchmark compromises the accuracy of the study results is not supported by record evidence (Company Reply Brief at 16).

The Company also contends that quantitative analysis demonstrates that an earlier benchmark year would not have a material impact on the TFP growth rate of NSTAR Gas (Company Reply Brief at 17, citingExh. ES-JF/MF-Rebuttal-1, at 21-23). Moreover, the Company avers that the Attorney General's witness recently used a similar period of time between the benchmark and start year for another client's LDC TFP study (Company Reply Brief at 17, citingTr. 11, at 1479).

D.P.U. 19-120

Page 53

Consumer Dividend

NSTAR Gas argues that, because it is already a relatively efficient cost performer, a consumer dividend, or any additional stretch factor, is unwarranted (Company Brief at 36-37, 60; Company Reply Brief at 20). In response to the Attorney General's recommendation of a consumer dividend between 0.3 and 0.4 percent, the Company claims that these figures are not supported by record evidence (Company Brief at 63; Company Reply Brief at 20). The Company maintains that record evidence is required to approve such a quantification or finding (Company Brief at 63; Company Reply Brief at 20).

The Company rejects the Attorney General's critiques of the Company's benchmarking model and insists that the analysis presented by the Attorney General has its own issues (Company Brief at 61). NSTAR Gas contends, for example, that the Attorney General relied on more granular labor price inputs that required additional unsupported assumptions that raise doubts regarding the reliability of the inputs and outputs (Company Brief at 61, citingExh. ES-JF/MF-Rebuttal-1, at 42-44). NSTAR Gas claims that the Attorney General confuses granularity for accuracy and asserts that the Company opted to focus on data that was as accurate as possible (Company Brief at 61).

NSTAR Gas acknowledges that the Attorney General's reference to the econometric total cost benchmarking and resulting stretch factor assignment relied upon in Ontario (Company Reply Brief at 21-22,citingExh. AG-MNL-1, at 17). Examining its performance, which it argues was 13 percent more efficient than average for the years 2014 through 2017, NSTAR Gas contends that if the Ontario criteria were applied, the Company's

D.P.U. 19-120Page 54

performance would align with a stretch factor of 0.15 percent, rather than the 0.3 to 0.4 percent suggested by the Attorney General (Company Reply Brief at 21-22).

Earnings Sharing Mechanism

NSTAR Gas argues that the proposed ESM is not only reasonable, but appropriately balances shareholder and ratepayer risk during the PBR term (Company Brief at 64, 80; Company Reply Brief at 22). The Company indicates that the symmetrical ESM allows for a correction if actual costs fall out of alignment during the PBR term and provides customers with a near-term benefit if earnings reach a level above the deadband (Company Brief at 45, 65; Company Reply Brief at 22, 24-25). NSTAR Gas contends that the ESM preserves the incentives of the PBR Plan and provides a level of assurance during a time of great uncertainty for the gas industry in Massachusetts (Company Brief at 45).

NSTAR Gas dismisses the intervenors' assertion that the ESM erodes customer protections and maintains that the ESM will protect customers against inaccurate cost projections (Company Reply Brief at 24-25). The Company insists that benefits will inure largely to customers as the proposed sharing is on a 75-percent and 25-percent basis for ratepayers and shareholders, respectively (Company Brief at 46, 65). Moreover, the Company claims that, prior to D.P.U. 17-05, every PBR approved by the Department included a symmetrical deadband (Company Brief at 64).

Exogenous Cost Factor (Z Factor)

The Company maintains that the Z factor is a necessary component of the PBRM as it accounts for operating cost changes that arise from factors beyond the Company's control (Company Brief at 40). NSTAR Gas observes that the Department has consistently

D.P.U. 19-120	Page 55
established exogenous cost provisions within approved PBR plans and maintains that

exogenous events can cause positive or negative cost changes that are not otherwise reflected in GDP-PI (Company Brief at 40). The Company avers that the significance threshold of $700,000 is consistent with Department precedent (Company Brief at 41).

Regarding the second set of criteria for exogenous cost changes, NSTAR Gas argues that the two-part Z factor is necessary to address uncertainty in the industry, including increases in future pipeline safety requirements (Company Brief at 42-43). In response to TEC's assertion that the Z factor qualification criteria are overly broad, the Company insists that such an argument stems from a misunderstanding of the costs for which the Company has any control (Company Brief at 77-78).

Double Recovery of Capital Costs

NSTAR Gas maintains that there will be no double recovery of GSEP-eligible costs, as the X factor in the PBR formula and the cost recovery associated with the GSEP represent two distinct aspects of the utility regulatory paradigm (Company Brief at 65; Company Reply Brief at 8, citingExh. ES-JF/MF-1, at 46). The GSEP, the Company argues, is only designed to provide for the accelerated replacement of leak-prone pipe to achieve safety and policy goals and is not a comprehensive capital recovery mechanism (Company Brief at 65). The Company states that the PBR formula will be applied annually to a revenue requirement that accounts for all capital additions made to date, regardless of past treatment, and that such treatment assures there is no possibility of double recovery of past GSEP projects (Company Brief at 39, 66, citingExh. DPU-ES32-14). Additionally, the Company argues that the

D.P.U. 19-120	Page 56
PBRM does not recover specific costs but, instead, provides revenue adjustments in

accordance with the PBR formula on a forward basis (Company Brief at 66).

According to the Company, there is no risk of double recovery only the potential for a revenue stream that is greater than the Company's costs (Company Brief at 66). NSTAR Gas asserts that such concerns are unwarranted because the level of capital funding provided by the PBR formula will still be less than the revenue requirement needed to support its capital investment based on its projected level of future capital spending and funding (Company Brief at 39, 66, citingExh. DPU-ES32-14; Company Reply Brief at 8). Moreover, the Company argues that if the combination of the PBR and GSEP result in a revenue stream greater than the Company's overall costs, the proposed ESM will return a portion of those overearnings to customers (Company Brief at 39-40, 58; Company Reply Brief at 8).

4. Analysis and Findings

Introduction

In the sections below, we review our ratemaking authority and reaffirm that, pursuant to G.L. c. 164, § 94, the Department may implement PBR as an alternative to cost of service/rate of return regulation. Further, we discuss the factors that the Department has used to review incentive regulation proposals. Finally, we review the Company's PBR Plan to determine whether it is in the public interest and will result in just and reasonable rates.

Department Ratemaking Authority

Pursuant to G.L. c. 164, § 94, the Legislature has granted the Department extensive ratemaking authority over electric and gas distribution companies. The Supreme Judicial

D.P.U. 19-120Page 57

Court has consistently found that the Department's authority to design and set rates is broad and substantial. See, e.g., Boston Real Estate Board v. Department of Public Utilities, 334 Mass. 477, 485 (1956). Because G.L. c. 164, § 94, authorizes the Department to regulate the rates, prices, and charges that electric and gas distribution companies may collect, this authority includes the power to implement revenue adjustment mechanisms such as a PBR. Boston Gas Company v. Department of Telecommunications and Energy,

436 Mass. 233, 234-235 (2002).

The Department is not compelled to use any particular method to establish rates, provided that the end result is not confiscatory (i.e., deprives a distribution company of the opportunity to realize a fair and reasonable return on its investment). 375 Mass. 1, 19. The Supreme Judicial Court has held that a basic principle of ratemaking is that "the department is free to select or reject a particular method as long as its choice does not have a confiscatory effect or is not otherwise illegal." American Hoechest Corporation v. Department of Public Utilities, 379 Mass. 408, 413 (1980), citing376 Mass. 294, 302.

In addition, G.L. c. 164, § 76, grants the Department broad supervision over electric and gas distribution companies. Under G.L. c. 164, § 76, the Department has the authority to establish reasonable rules and regulations consistent with G.L. c. 164, as needed, to carry out its administration of jurisdictional companies in the public interest. D.P.U. 07-50-B

at 26-27.See also Cambridge Electric Light Company v. Department of Public Utilities, 363 Mass. 474, 494-496 (1973).

D.P.U. 19-120Page 58

Although the Department traditionally has relied on cost of service/rate of return

regulation to establish just and reasonable rates, there are many variations and adjustments in the specific application of this model to individual utilities as circumstances differed across companies and across time. D.P.U. 07-50, at 8. Over the years, electric and gas distribution companies subject to the Department's jurisdiction have operated under PBR or PBR-like plans. See, e.g., D.P.U. 18-150, at 47; D.P.U. 17-05, at 371-372; D.T.E. 05-27, at 382; D.T.E. 03-40, at 471; The Berkshire Gas Company, D.T.E. 01-56, at 10 (2002); Massachusetts Electric Company/Eastern Edison Company, D.T.E. 99-47, at 4-14 (2000).

Consistent with the discussion above, the Department reaffirms that we may implement PBR as an alternative to cost of service/rate of return regulation under the broad

ratemaking authority granted to us by the Legislature under G.L. c. 164, § 94.32 The Department reviews the Company's specific PBR proposal under the standards set forth below.

Evaluation Criteria for PBR

The Department must approach the setting of rates and charges in a manner that:

meets our statutory obligations under G.L. c. 164, § 94, to ensure rates that are just and reasonable, not unjustly discriminatory, or unduly preferential; and (2) is consistent with long-standing ratemaking principles, including fairness, equity, and continuity.
D.P.U. 07-50, at 10-11. Further, the Department must establish rates in a manner that

32 In addition, pursuant to G.L. c. 164, § 1E(a), the Department is authorized to promulgate rules and regulations to establish and require performance-based rates for gas and electric distribution companies.

D.P.U. 19-120Page 59

balances a number of these key principles to reflect and address the practical circumstances attendant to any individual company's base distribution rate case. D.P.U. 07-50-A at 28. The Department has implemented PBRs or PBR-like mechanisms on a finding that such regulatory methods would better satisfy our public policy goals and statutory obligations. See, e.g., D.P.U. 96-50 (Phase I) at 261; D.P.U. 94-158, at 42-43; D.P.U. 94-50, at 139.

As part of our generic investigation of incentive ratemaking in D.P.U. 94-158,

at 52-66, the Department examined the criteria by which PBR proposals for electric and gas distribution companies would be evaluated. The Department found that, because incentive regulation acts as an alternative to traditional cost of service regulation, incentive proposals would be subject to the standard of review established by G.L. c. 164, § 94, which requires that rates be just and reasonable. D.P.U. 94-158, at 52. Further, the Department determined that a petitioner seeking approval of an incentive regulation proposal like PBR is required to demonstrate that its approach is more likely than current regulation to advance the Department's traditional goals of safe, reliable, and least-cost energy service and to promote the objectives of economic efficiency, cost control, lower rates, and reduced administrative burden in regulation. D.P.U. 94-158, at 57. Finally, a well-designed incentive mechanism should provide utilities with greater incentives to reduce costs than currently exist under traditional cost of service regulation and should result in benefits to customers that are greater than would be present under current regulation. D.P.U. 94-158, at 57.

In addition to these criteria, the Department established a number of additional factors it would weigh in evaluating incentive proposals. D.P.U. 94-158, at 57. These factors

D.P.U. 19-120	Page 60
provide that a well-designed incentive proposal should: (1) comply with Department

regulations, unless accompanied by a request for a specific waiver; (2) be designed to serve as a vehicle to a more competitive environment and to improve the provision of monopoly services; (3) not result in reductions of safety, service reliability, or existing standards of customer service; (4) not focus excessively on cost recovery issues; (5) focus on comprehensive results; (6) be designed to achieve specific, measurable results; and

provide a more efficient regulatory approach, thus reducing regulatory and administrative costs. D.P.U. 94-158, at 58-64. The Department discusses these criteria and factors in the

context of our evaluation of NSTAR Gas's PBR proposal in the subsections below.

Rationale for PBR

There is a fundamental evolution taking place in the natural gas local distribution industry in Massachusetts. This evolution has been driven, in large part, by two primary factors. First, the Commonwealth has instituted a number of legislative and administrative policy initiatives designed to address climate change and to foster a clean energy economy. An Act Relative To Green Communities, St. 2008, c. 169; An Act Establishing the Global Warming Solutions Act, St. 2008, c. 298 ("GWSA"); Green Communities Expansion Act,

83A; Executive Order No. 569: Establishing an Integrated Climate Change Strategy for the Commonwealth (September 16, 2016). Second, the Merrimack Valley incident has prompted the industry and its regulators to reevaluate safety standards, practices, protocols, and procedures, to enhance safety and reliability of the natural gas distribution system
(Exh. ES-WJA/DPH-1, at 34). An Act Further Providing for the Safety of the

D.P.U. 19-120Page 61

Commonwealth's Natural Gas Infrastructure, St. 2018, c. 269. To varying degrees, this

evolution is changing the operating environment for LDCs in Massachusetts.33

As described above, NSTAR Gas proposes to implement a PBRM that would adjust rates annually in accordance with a revenue cap formula (Exh. ES-WJA/DPH-1, at 8). The Company claims that a PBRM is a better fit than cost of service ratemaking for providing the Company with the revenue support it needs to address these changing industry dynamics (Exh. ES-WJA/DPH-1, at 14). Specifically, the cost control incentives and greater flexibility in relation to cost planning inherent in the PBR Plan will be beneficial in light of the Company's forecasted increase in both non-GSEP capital expenses and operating expenses to address changes in the industry operating environment (Exhs. ES-WJA/DPH-1, at 14, 23-29, 57; DPU-ES3-5). Further, the Company claims that the PBR Plan is more administratively efficient and will, therefore, reduce administrative burden compared to cost of service ratemaking (Exhs. ES-WJA/DPH-1, at 13-14,93-94;DPU-ES3-5). For the reasons discussed below, the Department finds that NSTAR Gas has demonstrated that an alternative to traditional cost of service/rate of return ratemaking is warranted.

NSTAR Gas demonstrated that its system needs are changing and that its capital and operating costs are increasing in ways that it has not experienced in the past. The Company

33 The Department notes that it has instituted an investigation to examine the role of LDCs in helping the Commonwealth to achieve its 2050 climate goals. Specifically, we will explore strategies to enable the Commonwealth to move into its net-zero emissions energy future while simultaneously safeguarding ratepayer interests; ensuring safe, reliable, and cost-effective natural gas service; and potentially recasting the role of LDCs in the Commonwealth. D.P.U. 20-80, at 1.

D.P.U. 19-120Page 62

argues that there are two dynamics shaping the future of the natural gas industry across the United States: (1) the need to achieve the utmost level of public safety; and (2) the need to

reduce methane emissions (Exh. ES-WJA/DPH-1, at 4-5).34 The Company expects for these industry-wide changes to require substantial increases in capital investment and operating costs compared to prior periods, beyond what is already planned for GSEP-related activities (Exh. ES-WJA/DPH-1, at 24-35, 69). NSTAR Gas expects to see substantial increases in costs in four non-GSEP project categories: (1) pressure regulation modernization; (2) a low-pressure protection program; (3) system resiliency; and (4) system reliability investments (Exhs. ES-WJA/DPH-1, at 26-29;DPU-ES3-12;DPU-ES12-21;DPU-ES33-13;DPU-ES33-14;DPU-ES33-15). This increased capital expense will impose significant financial pressure on the Company, and, the Company argues, the PBR Plan will provide a means of maintaining financial integrity for the PBR term (Exh. ES-WJA/DPH-1, at 95-96). Further, unlike a capital cost recovery mechanism, NSTAR Gas maintains that the proposed PBRM is designed to provide it with strong incentives to control costs

(Exh. ES-WJA/DPH-1, at 13-14;DPU-ES3-5).

The Department has allowed companies to adopt various capital cost recovery mechanisms in cases where a company has adequately demonstrated its need to recover incremental costs associated with capital expenditure programs between base distribution rate

34 The Company also mentions infrastructure constraints as a third concern for the Company and the industry, particularly in the Northeast region (Exhs. DPU-ES3-5;DPU-ES12-18).

D.P.U. 19-120	Page 63
cases. D.P.U. 15-155, at 40, 51-54;Fitchburg Gas and Electric Light Company,

D.P.U. 15-80/D.P.U.15-81, at 50 (2016); Boston Gas Company/Colonial Gas Company/Essex Gas Company, D.P.U. 10-55, at 121-122,132-133 (2010); D.P.U. 09-39, at 79-80, 82; D.P.U. 09-30, at 133-134. The Department finds that a PBRM provides the Company more flexibility to address a changing operating environment

(Exhs. ES-WJA/DPH-1, at 12-14;ES-WJA/DPH-1, at 21, 24-26,34-35;DPU-ES3-5). The approach we adopt addresses the need for increased non-GSEP capital investment and allows NSTAR Gas to best meet its public service obligations for providing safe, reliable, and least-cost service to customers as well as to ensure that the Commonwealth's emission reduction and pipeline safety goals are met. D.P.U. 94-158, at 57.

As part of the PBR Plan, the Company has committed to refraining from filing rate schedules to put new base distribution rates into effect during the PBR term

(Exh. ES-WJA/DPH-1, at 93-94,97-98; Tr. 3, at 381). The Department accepts that this stay-out provision will generate diminished administrative burden and will result in future efficiencies (Exhs. DPU-ES3-5;DPU-ES12-14;DPU-ES12-15;DPU-ES22-13). For instance, NSTAR Gas estimates that, without the PBRM, the Company would need to pursue a base distribution rate case every two years (Exhs. ES-WJA/DPH-1, at 93; DPU-ES3-7; Tr. 3, at 380-382). Accordingly, the Department finds that the PBRM will result in a reduced administrative burden and is in the public interest as compared to other ratemaking and cost recovery mechanisms (Exhs. ES-JF/MF-1, at 17; ES-WJA/DPH-1, at 93-94).

D.P.U. 19-120Page 64

Below, the Department addresses the PBRM formula elements and whether the proposed formula appropriately balances ratepayer and shareholder risk, is in the public interest, and will result in just and reasonable rates.

PBR Term

NSTAR Gas included an initial term of five years for the PBR Plan, with a provisional five-year extension (Exh. ES-WJA/DPH-1, at 79, 93-95). The initial five-year PBR term would commence on November 1, 2020, and expire on October 31, 2025

(Exh. ES-WJA/DPH-1, at 94). Within the five-year term, there would be four annual PBRM adjustments taking effect November 1, 2021, November 1, 2022, November 1, 2023, and November 1, 2024 (Exh. ES-WJA/DPH-1, at 94). In conjunction with the PBR term, NSTAR Gas proposed a stay-out provision during which the Company commits to file rate schedules to put new base distribution rates into effect no earlier than November 1, 2025 (Exh. ES-WJA/DPH-1, at 94).

The Department has found that a well-designed PBR Plan should be of sufficient duration to give the plan enough time to achieve its goals and to provide utilities with the appropriate economic incentives and certainty to follow through with medium- and long-term strategic business decisions. D.P.U. 96-50 (Phase I) at 320; D.P.U. 94-158, at 66; D.P.U. 94-50, at 272. In addition, the Department has stated that one benefit of incentive regulation is a reduction in regulatory and administrative costs. D.P.U. 18-150, at 53; D.P.U. 17-05, at 402; D.P.U. 96-50 (Phase I) at 320; D.P.U. 94-158, at 64.

D.P.U. 19-120Page 65

Previous PBR plans approved by the Department have had terms of five and ten

years. See, e.g., D.P.U. 18-150, at 56 (five years); D.P.U. 17-05, at 404 (five years); D.T.E 05-27, at 399 (ten years); D.T.E. 03-40, at 495-496 (ten years); D.T.E. 01-56, at 10 (ten years); D.P.U. 96-50 (Phase I) at 320 (five years). With the exception of the PBR plan approved in D.P.U. 96-50 (Phase I), the Department has historically found that five-year terms are not long enough for gas distribution companies to achieve the efficiencies and benefits that a PBR plan is expected to provide to shareholders and ratepayers.

D.T.E. 03-40, at 495. Accordingly, the Department rejects the Company's proposed five-year term.

The Department finds that a ten-year term will give the plan sufficient time to achieve its goals and to evaluate administrative efficiencies, and will provide the Company with the appropriate economic incentives for cost containment and long-term planning. A ten-year term is consistent with previous Department approved gas distribution company PBR plans and G.L. c. 164. By extending the PBR term, the Company will have a better opportunity to achieve efficiencies crucial to the success of incentive regulation, which should provide benefits to ratepayers and shareholders alike. As discussed in more detail in Section V.B.4.f.ii, after review, the Department will determine whether capital additions through 2024 may be rolled into base distribution rates on November 1, 2025.

Furthermore, a stay-out provision provides an important benefit to ratepayers as it will ensure that there are strong incentives for cost containment under the PBR. D.P.U. 18-150, at 55; D.P.U. 17-05, at 403. Accordingly, the Department adopts a stay-out provision in

D.P.U. 19-120

Page 66

conjunction with the ten-year term. For the reasons discussed above, the Department finds

that the Company's PBR shall operate for a ten-year term starting November 1, 2020.35

Additionally, the Company shall commit to not file a petition under G.L. c. 164, § 94 that

seeks to put increased base distribution rates into effect prior to November 1, 2030.36 In the

event that the Company elects to file a petition for a change in base distribution rates for

effect prior to November 1, 2030, the PBRM and all associated factors shall terminate when

that case is filed.

Rate Base Proposals
i. 2019-2020Capital Additions

Introduction

NSTAR Gas seeks to roll in its 2019 and 2020 non-GSEP plant additions into rate

base. NSTAR Gas does not seek to roll in its 2019 and 2020 non-GSEP plant additions into

rate base, however, on the basis that they represent a significant investment that has a

The Company proposed to amortize its new balance of active protected receivables over five years, resulting in an annual amortization expense of $602,516

(Exhs. ES-DPH/ANB-1, at 99; ES-DPH/ANB-2, at Sch. 23). Because the Department adjusted the proposed PBR term to ten years, a corresponding adjustment must be made to the Company's proposed annual amortization of active protected receivables. Accordingly, the Department directs NSTAR Gas to amortize its hardship receivable balance over ten years, resulting in an allowed annual amortization expense of $301,258 (seeDepartment Schedule 3 in Section XVI, below).

If the NSTAR Gas ends its PBRM prior to the end of the ten-year term, then, in its next base distribution rate case, the Department will consider the effects in setting the ROE unless the Department denies the base distribution rate adjustment for the 2021 through 2024 investments (seeSection V.B.4.f.ii, below).

D.P.U. 19-120Page 67

substantial effect on the Company's rate base. Rather, NSTAR Gas ties its request to include the post-test-year plant additions in rate base to the recent and expected-to-continue increase in capital investment, a decline in new customer revenues, and the long-term effectiveness of the PBRM (Company Brief at 50-53; Company Reply Brief at 31-33). The Attorney General argues that the Company's proposal to include post-test-year plant additions in rate base is inconsistent with Department precedent, and, even if the Department were to allow the PBR Plan, an exception to the post-test-year standard on rate base additions still is not appropriate (Attorney General Brief at 14-17; Attorney General Reply Brief at 4-7). The Department has carefully considered the arguments of the parties and the record supporting their positions. As discussed below, we conclude that there are substantial circumstances present that persuade us to consider the Company's post-test-year plant additions without regard to the size of the additions in relation to rate base.

Increase in Non-GSEP Safety and Reliability Investment

The Company's strategic plan anticipates that capital investment costs will continue to increase through 2023 with budgeted, non-GSEP plant additions in 2023 being nearly double the amount in 2015 (Exhs. WJA/DPH/ANB-1, at 26; DPU-ES12-20, Att. (a); AG 1-18, Att. (b); AG 5-3). The Company expects to invest between $85 million and $100 million annually in non-GSEP capital over the first five years of the PBR Plan

(Exhs. WJA/DPH/ANB-1, at 95; DPU-ES3-12). The Company states that the increase in capital spending is driven by the response to the Merrimack Valley incident and, specifically, the Company's investments in the following categories: (1) $15.3 million in pressure

D.P.U. 19-120

Page 68

regulation modernization37; (2) $21.5 million in the low-pressure protection program38;

$49.5 million in system resiliency investments; and (4) $189.7 million in system reliability investments39 (Exhs. DPU-ES33-13;DPU-ES33-14;DPU-ES33-15;DPU-ES33-16; AG 5-3; Tr. 6, at 756). The estimated spending on these four project categories for the period 2019 to 2023 totals $272 million (Exh. AG 5-3).
The Attorney General argues, however, that the Company's capital spending

projections are unreliable and lack specific project proposals with budgets and approvals

(Attorney General Reply Brief at 6). For example, she asserts that the actual amount of plant

placed in service in 2020 is expected to be approximately 30 percent short of the amount

budgeted (Attorney General Reply Brief at 6). We disagree. The record demonstrates that

the Attorney General's argument is premised on comparing the Company's capital budgeting

and strategic planning processes, which are dissimilar.

Pressure regulation modernization improves system awareness and control of the gas distribution system, increasing safety and reliability (Exh. DPU-ES33-13). Specific projects include emergency shut-down devices, remote monitoring and control devices, and telemetry (Exh. ES-WJA/DPH-1, at 27). The Company did not invest in pressure regulation modernization between 2015 and 2019 (Exh. AG 5-3).

Investments into the low-pressure protection program are intended to provide a third level of pressure protection for low-pressure systems, eliminate single incident failures at all low-pressure district regulators, and convert approximately 17 low-pressure district regulators to intermediate pressure (Exh. ES-WJA/DPH-1, at 28). Between 2015 and 2019, the Company did not make investments in the low-pressure protection program (Exh. AG 5-3).

System reliability investments include upgrades to gate and regulator stations, projects to maintain pressure during peak conditions, reinforcements for reliability as well as projects for leak and corrosion remediation, service valve replacement, and system telemetry (Exh. ES-WJA/DPH-1, at 29).

D.P.U. 19-120Page 69

NSTAR Gas develops a capital plan annually as a collaborative effort between the

engineering and operations departments to identify specific needs in each area

(Exh. ES-LML/TCD-1, at 15). An extensive budget review process is then conducted at year-end by senior management in which the portfolio of projects is considered along with multi-year funding for major projects (Exh. ES-LML/TCD-1, at 15). This annual budget process is distinct from the Company's strategic plan, which is developed by the "Planning Group" to review potential capital spending over the upcoming five-year period

(Exh. ES-LML/TCD-1, at 13). The strategic plan is approved by senior management and is then used as the basis for annual capital budget plans (Exh. ES-LML/TCD-1, at 13). While the strategic plan includes capital expenditures and operating cost projections, the focus is the long-term capital investment needs for each functional area (Exh. DPU-ES11-5). The Department finds that, by its nature, the variance between actual spending and the five-year strategic plan will be inherently greater than the variance between actual spending and the annual capital budget plan due to the greater likelihood of unforeseen contingencies, over a longer time period.

The Company's 2019 capital budget was created in December 2018 based on the 2018 strategic plan (Exh. ES-LML/TCD-1, at 13-14). The 2019 strategic plan, however, is dated April 15, 2019, seven months after the Merrimack Valley incident (Exh. DPU-ES33-12, Att. (b)). There are significant increases in the budgeted amounts of the 2018 and 2019 strategic plans specific to system resiliency, system reinforcement, gate and regulator stations, and low-pressure protection system and reliability projects (Exh. DPU-ES33-12,

D.P.U. 19-120Page 70

Atts.). It is reasonable to expect that, given the Merrimack Valley incident's profound

impact on the industry, NSTAR Gas's strategic planning, post-Merrimack Valley incident, would contain significant budget increases as the Company plans its future spending in response to lessons learned from the Merrimack Valley incident (Exhs. ES-WJA/DPH-1, at 11, 34, 37; DPU-ES23-15 & Atts.; Tr. 6, at 806). And, while the actual 2019 investment did not rise to the level expected in the strategic plan (Exh. DPU-ES33-21), we are persuaded by the record evidence that the Company will remain committed to making the necessary investments in order to ensure system safety and reliability in the wake of the Merrimack Valley incident (Exhs. ES-WJA/DPH-1, at 11, 34, 37; DPU-ES23-15 & Atts.; Tr. 6, at 847-848).

Accordingly, the Department finds that the heightened level of investment discussed above will result in significant carrying costs to the Company over the ten-year term of the PBR plan (Exhs. ES-WJA/DPH-1, at 25; DPU-ES3-9;DPU-ES3-10;DPU-ES7-3;DPU-ES12-14; AG 9-24;RR-DPU-16, Att.). The ten-year PBR term and stay-out provision approved above would preclude the Company from seeking a base distribution rate increase to begin recovering the costs of those investments; therefore, the Department finds that it is appropriate to consider the significant carrying costs in light of the Company's proposed capital additions.

Offsets to Capital Carrying Costs

The Attorney General argues that a significant portion of the Company's non-GSEP projects are revenue producing, and, therefore, under revenue decoupling, the revenues are

D.P.U. 19-120

Page 71

retained by the Company and will partially offset the carrying costs of non-revenue producing

plant investments (Attorney General Brief at 17). We disagree. During the proceeding, the

Department solicited testimony and detailed calculations from NSTAR Gas demonstrating

how projected PBR revenues, projected new customer revenues, and depreciation accounting

would offset the capital carrying costs discussed above (Exhs. DPU-ES12-10 & Atts.;

DPU-ES28-1 & Atts.; DPU-ES28-2 & Atts.; Tr. 2, at 283-326; Tr. 3, at 380-390; Tr. 6,

at 778-793;RR-DPU-16). The Company estimates that, under the PBR Plan, annual

increases in revenue should be approximately $8 million (Exh. ES-WJA/DPH-1, at 95; Tr. 3,

at 381). Further, incremental revenues from customer growth range from $1.6 million to

$1.9 million40 each year, accounting for customers leaving the system and assuming the level

of revenues from new customer additions stays flat (Exh. DPU-ES-28-1; Tr. 2, at 298;

Tr. 6 at 812; RR-DPU-3). Based on conservative estimates of PBR revenues, revenues from

customer growth and capital additions, and accounting for depreciation, the Company

forecasts revenue requirement deficits ranging from $12.6 million to $26.8 million each year

for the first five years of the PBR term (RR-DPU-16, Att., at 1). Therefore, we find that

40 Forecasted new customer revenue is derived at the rate level by multiplying the latest approved tariffs from July 1, 2018 by the Company's unit forecast of distribution (sales), customer count and demand. Gas sales and customer counts are forecasted econometrically utilizing four years of historical data and incorporate changes in energy prices and economic conditions. Demand is forecasted by analyzing the trends over the most recent three-year period. The line item entitled "Expected Decoupled Customer Reduction" reflects the fact that the decoupled revenues are not "fixed" and the decoupled customer population is expected to decline slightly each year resulting in lower decoupled revenues (RR-DPU-3).

D.P.U. 19-120Page 72

there is substantial record evidence to demonstrate that the projected PBRM revenues, new customer revenues, and adjustment for depreciation are most likely insufficient compared with the revenue requirement associated with NSTAR Gas's increased capital spending requirements to prevent the Company from the necessity of filing for rate relief prior to the end of the PBR term.

Conclusion

Above, the Department approved a ten-year PBR term and stay-out provision in order to maximize the benefits achieved for NSTAR Gas's customers and shareholders under the PBR Plan. NSTAR Gas has demonstrated its commitment to a significant increase in its non-GSEP investments to improve the safety and reliability of its distribution system, representing about 50 percent of its overall capital spending, and the Department has found that the PBRM affords the Company needed flexibility to address a changing and uncertain operating environment. In light of these circumstances, the Department finds that NSTAR Gas has made a convincing showing that the proposed roll-in of 2019 and 2020 non-GSEP capital investments is necessary to cover the expected increase in costs associated with necessary capital investments, particularly those undertaken in response to the Merrimack Valley incident, and to ensure the potential benefits of the PBRM to customers are realized (Exhs. ES-WJA/DPH-1, at 26, 95-96;DPU-ES12-20, Att. (a); DPU-ES33-12;

DPU-ES33-13;DPU-ES33-14;DPU-ES33-15;DPU-ES33-16; AG 1-18, Att. (b);

AG 5-3; Tr. 3, at 381; Tr. 6, at 807; RR-DPU-16). In making these findings, however, we seek to strike a balance between establishing an appropriate foundation upon which PBR

D.P.U. 19-120

Page 73

revenues can grow and support the Company's ambitious strategic plan spending and

mitigating bill impacts on ratepayers by maintaining an appropriate level of annual rate

increases during the PBR term.

Thus, in base distribution rates effective November 1, 2020, the Company's rate base

will be determined by the test-year net plant, as determined above, and consistent with

traditional cost of service ratemaking.41 In the Company's initial PBR filing, effective

November 1, 2021, rate base will be updated to incorporate the 2019 non-GSEP plant

additions along with the associated accumulated depreciation. The Company shall adjust the

base distribution rates for depreciation expense, return on rate base, associated federal and

state income taxes, property taxes, and revenues for all existing non-GSEP assets ending

December 31, 2019. During the instant proceeding, the Company provided project

documentation to support its proposed 2019 capital additions (Exhs. ES-LML/TCD-1 (Supp.)

at 3; ES-LML/TCD-3;ES-LML/TCD-13). The parties were afforded an extended

opportunity to conduct discovery on the project documentation and to cross-examine the

Company's witnesses during the evidentiary phase of the proceedings (see, e.g.,

Exhs. AG 36-1; AG 40-1 through AG 40-9; AG 46-1 through AG 46-14; Tr. 6, at 861-889).

41 As part of NSTAR Gas's proposal to update rate base for actual 2019 plant balances, the Company also proposed a $3,150,999 decrease to operating revenues (Exh.ES-DPH/ANB-1, at 11-12;ES-DPH/ANB-2, Sch. 6; ES-DPH/ANB-2 (Rev.) at Summary of Cost of Service Changes, Sch. 1, at 1, 9; Sch. 6). Consistent with our decision to determine rate base using the test-year-end plant balance in base distribution rates effective November 1, 2020, the Company's operating revenues will be based on the test-year-end amount. This adjustment is shown on Department Schedules 1 and 9 in Section XVI, below.

D.P.U. 19-120Page 74

Therefore, the Department finds no due process concerns associated with the review of the Company's 2019 capital additions.

The Company may seek to update its rate base to incorporate the 2020 non-GSEP plant additions along with associated accumulated depreciation as part of its second annual PBRM filing effective November 1, 2022. The Company shall file no later than May 1, 2022, all relevant project documentation and supporting testimony to demonstrate that the costs associated with the 2020 investments were prudently incurred and that the plant is used and useful in service to customers. The Company shall adjust the base distribution rates for depreciation expense, return on rate base, associated federal and state income taxes, and property taxes for all existing non-GSEP assets ending December 31, 2020. The Department will establish an appropriate procedural schedule to provide interested parties an opportunity to review the project documentation and supporting testimony.

In light of our findings above, we need not address whether the Company's proposal is consistent with the Department's decision in D.P.U. 18-150, or any of the Company's other discrete arguments. These findings above provide a sufficient basis upon which to allow the Company to incorporate post-test-year plant additions in rate base. We stress, however, that we do not intend for our decision today to represent a wholesale shift in the Department's standard of review for post-test-year plant additions and the required showing of significance. Rather, it is a recognition of the unique circumstances present in this case.

D.P.U. 19-120

Page 75

2021-2024Capital Additions

NSTAR Gas conditioned its proposed five-year PBR term extension in part on allowing the revenue requirement associated with the capital additions completed through December 31, 2024 into base rates in year five of the PBR Plan term (i.e., for rates effective on November 1, 2025) (Exh. ES-WJA/DPH-1, at 94-95). The Company argued that the expected cost of the investments during the first five years of the PBR would not allow it to continue the PBR for another five years without incorporating these capital costs (Company Brief at 79). TEC, on the other hand, argues that the Department has a responsibility to ratepayers to ensure that capital additions are prudent, and that any future approval of capital costs in base distribution rates should only occur through a base distribution rate proceeding (TEC Brief at 7).

The Department finds that too many uncertainties exist at this time to determine whether the revenue requirement associated with the 2021 through 2024 investments should be allowed to be included in rate base in year five of the PBR term for rates effective on November 1, 2025. As such, we find that we would consider allowing these investments into base rates in year five of the PBR term on November 1, 2025, if the Company can demonstrate in its 2024 annual PBR filing (i.e., filed September 15, 2024) that the Company has met the following conditions: (1) achieved all of its scorecard metrics within the first four years of the PBR term with reasonable variance shown to be outside the Company's control; (2) invested in capital in accordance with its five-year capital plan

(Exhs. DPU-ES12-10 & Att. (b), AG-1-18 & Att. (b); AG-5-3); and (3) filed with the

D.P.U. 19-120

Page 76

Department its most recent five-year capital spending plan.42, 43 Additionally, the Department

directs the Company to file with its September 15, 2023 annual PBR filing a progress report

on its five-year capital plan reconciled with its capital budget forecast.44 If the Department

allows the base distribution rate adjustment adjustment for the 2021 through 2024

investments, then the Company shall maintain its commitment to forgo a base distribution

rate proceeding and continue with its PBRM through November 1, 2030.

PBR Formula Elements

X Factor
1. Introduction

In the context of a revenue cap formula that uses an economy-wide measure of

inflation, a productivity offset (or X factor) consists of the (1) differential in expected

productivity growth between the natural gas local distribution industry and the overall

economy and (2) the differential in expected input price growth between the overall economy

If the Department allows these investments to be included in base distribution rates on November 1, 2025, subject to a prudence review, then NSTAR Gas shall file with the Department capital project documentation for projects completed January 1, 2021 through December 31, 2024 on or before April 1, 2025 for Department review (Exh. ES-WJA/DPH-1, at 99).

The Department expects the Company to demonstrate capital investment in accordance with the total five-year capital plan as provided in Exhibit DPU-ES12-10 & Att. (b), as well as at the program level (i.e., Exhibit AG-5-3), and at the business unit level (i.e., Exhibit AG-1-18 & Att. (b)).

The Department expects the Company to provide a progress report with the total five-year capital plan as provided in Exhibit DPU-ES12-10 & Att. (b), as well as at the program level (i.e., Exhibit AG-5-3), and at the business unit level

(i.e., Exhibit AG-1-18 & Att. (b)).

D.P.U. 19-120Page 77

and the LDC industry (Exhs. ES-JF/MF-1, at 45; ES-JF/MF-2, at 46). In combination with the inflation factor, the X factor is designed to represent the expected unit cost performance of an average performing company in the industry (Exh. ES-WJA/DPH-1, at 81). As described above, NSTAR Gas conducted multiple TFP analyses and ultimately proposed an

X factor in the instant case equal to -1.18 percent45 (Company Brief at 26). The Attorney General also conducted multiple TFP analyses that produced a range of X factor results from -1.07 percent to -0.69 percent (Exh. AG-MNL-1 at 15). As noted above, the Attorney General proposed an X factor of -0.69 percent (Attorney General Brief at 126). The

X factors produced by the Attorney General's TFP analysis differ from the Company's TFP study in several ways, which the Department reviews in the sections below. In the subsequent sections, the Department details its decision to accept the Company's proposed X factor of -1.18 percent to be used in the PBRM.

Treatment of CS&I Expenses

One of the inputs into the Company's TFP and benchmarking studies is total OM&A expenses (Exhs. ES-JF/MF-2, at 27; ES-JF/MF-3, at 12). The Company included categories of costs, as reported in FERC Form 2 and LDC State Filings, associated with physical productivity of distribution for LDCs, including expenses associated with storage, distribution customer service account, sales, and administrative and general expenses, including labor

45 The Company initially proposed an X factor of -1.30 percent, but during the proceeding updated the proposal to -1.18 percent based on a correction to the Company's TFP study (Exhs. ES-JF/MF-1, at 29-31;ES-JF/MF-2, at 47; RR-DPU-21, at 1-2).

D.P.U. 19-120	Page 78
(Exhs. ES-JF/MF-2, at 27-28;ES-JF/MF-3, at 12).	For the same reason, the Company

excluded costs in the categories of transmission and fuel procurement (Exh. ES-JF/MF-2, at 27). According to the Company, OM&A costs included CS&I expenses for all sampled

LDCs (Exh. AG 9-10).46

The Attorney General argues that it is inappropriate to include CS&I expenses in the TFP and benchmarking cost calculations. The Attorney General specifies that CS&I expenses oftentimes include DSM expenses and that DSM expenses can account for a large portion of total CS&I expense (Exh. AG-MNL-Surrebuttal, at 3). The Attorney General explains that the Company excludes DSM expenses of NSTAR Gas and other Massachusetts LDCs because they are not reported in CS&I expenses, but includes DSM expenses for other LDCs, resulting in a bias in favor of NSTAR Gas (Exhs. AG-MNL-Surrebuttal, at 4;

AG 9-10). Conversely, the Company holds that the Attorney General inaccurately characterizes the type of costs included in the CS&I category (Exh. ES-JF/MR-Rebuttal-1, at 25-27). The Company argues that excluding the entire CS&I expense category excludes and underestimates other expenses, and it is therefore incorrect to exclude CS&I expenses for the purpose of eliminating DSM (Exh. ES-JF/MR-Rebuttal-1, at 28). The record in the instant proceeding demonstrates that DSM expenses have been declining over time while CS&I expenses have been increasing, which would indicate that CS&I trends have not been

46 CS&I expenses are defined as "the cost of labor, materials used, and expenses incurred in providing instructions or assistance to customers, the object of which is to encourage safe, efficient, and economical use of the associated utility company's service." (Exh. AG 9-10)

D.P.U. 19-120	Page 79
driven by DSM expenses, but rather by other legitimate costs that are relevant to the

determination of TFP trends (Exh. AG 44-6; Tr. 11, at 1452-1453;RR-DPU-21, at 1). Therefore, the Department finds that the exclusion of CS&I expenses is not appropriate and would likely ignore important costs that affect LDC productivity trends.

Peer Group Selection (National vs. Regional)
The Company calculated TFP and corresponding X factors using two different

samples for its productivity study: (1) a sample of 83 U.S. LDCs intended to represent the overall nationwide LDC industry and (2) a sample of 29 LDCs intended to represent the LDC industry in the Northeast Region (Exhs. ES-JF/MF-1, at 21; ES-JF/MF-2, at 5-7). The TFP study for the national sample results in an X factor of -0.76 percent, and the TFP study for the Northeast sample results in an X factor of -1.18 percent (RR-DPU-21, at 2). The Company proposed that the X factor corresponding to the Northeast peer group sample

of -1.18 percent be used for the PBRM, stating that this X factor is the most appropriate due namely to three differences between the Northeast Region and the rest of the United States that may impact productivity growth in the LDC sector: (1) lack of economies of scale (i.e., smaller pipeline systems in the Northeast); (2) technology (i.e., a greater proportion of older, cast or wrought iron mains in the Northeast); and (3) output growth (i.e., a slower rate of growth in number of customers in the Northeast) (Exhs. ES-JF/MF-1, at 9-10;29-31;ES-JF/MF-2, at 42-43;ES-JF/MF-Rebuttal-1, at 49-52;RR-DPU-21, at 2). For these reasons, the Company asserts that Northeast Region LDCs are closer peers to NSTAR Gas than the National LDC sample (Exh. ES-JF/MF-Rebuttal-1, at 49).

D.P.U. 19-120Page 80

Alternatively, the Attorney General argues that it is more appropriate to use the

national peer group to calculate the X factor for two reasons (Exhs. AG-MNL-1, at 9-10, 15; AG-MNL-2, at 41, 50). First, the Attorney General explains that NSTAR Gas does not have the same slower customer growth that is exhibited in the Northeast Region, which gives the Company more opportunity to realize economies of scale (Exhs. AG-MNL-1, at 9-10;AG-MNL-2, at 41, 50). Second, the Attorney General points out that, since the Company proposes to track GSEP costs outside of the PBRM, the impact of having a relatively higher proportion of older, cast iron mains would be accounted for outside of the X factor

(Exhs. AG-MNL-1, at 9-10;AG-MNL-2, at 41, 50).

The Department recognizes that TFP growth differs between the national and regional group for a variety of reasons. Differences in economies of scale, technology, input and output growth, population density, system size, and system composition influence trends in TFP over time, and the Company has demonstrated that the LDCs in the Northeast have characteristics that differ from LDCs in the rest of the United States, such that the regional peer group is more appropriate for the purpose of setting an X factor (Exhs. ES-JF/MF-1, at 28-31;ES-JF/MF-3 (Rev.) at 21; ES-JF/MF-Rebuttal-1, at 50-52; Tr. 7, at 922-925,930-931). With respect to inclusion of GSEP costs in the TFP study, both parties acknowledge that there is no practical or straightforward way to exclude GSEP costs from the X factor calculation due to data limitations (Exh. ES-JF/MF-Rebuttal-1, at 60; Tr. 11,

at 1516-1518). While the inclusion of GSEP costs may have some effect on TFP growth,

D.P.U. 19-120	Page 81
NSTAR Gas determined that the impact would not be significant or material

(Exh. DPU-ES32-1, at 4).

In recently approved PBR proposals for electric distribution companies, the Department has accepted the use of national peer groups for purposes of setting an X factor. D.P.U. 18-150, at 58, 60; D.P.U. 17-05, at 383-384. In those proceedings, one of the concerns regarding the regional peer group was the potential for sample endogeneity, but here such concerns are non-existent. D.P.U. 17-05, at 384, 386. Additionally, while electric distribution companies have relied on national peer groups, the Department has historically found that regional peer groups are more appropriate for setting X factors for LDCs. D.T.E. 05-27, at 363; D.T.E. 03-40, at 475; D.P.U. 96-50 (Phase I), at 275-276. The evidence provided in the instant proceeding is consistent with the Department's past findings. We find that the use of a regional peer group is consistent with Department precedent and that conditions in the Northeast are unique enough to determine that the Northeast region LDCs are closer peers to NSTAR Gas than the national LDC sample. Moreover, the regional peer group accounted for 94 percent of gas customers in the Northeast region and 81 percent of the total volume of gas sales as of 2017, which the Department finds is sufficiently robust, providing a reliable basis to establish TFP

(Exh. ES-JF/MF-1, at 21). Accordingly, the Department accepts the Company's reliance on the regional peer group for establishing an appropriate X factor.

D.P.U. 19-120

Page 82

Use of Allegedly Flawed Data

The Attorney General argues that the Company's TFP study uses flawed data, as it

includes companies whose data were compromised by acquisitions, mergers, and divestitures

(Attorney General Brief at 123). NSTAR Gas insists the Attorney General's argument should

be disregarded, as her exclusions of data were arbitrary and improperly informed (Company

Brief at 59). The Department is not persuaded that the Attorney General's concerns are

warranted, as it is unclear how the inclusion of companies that underwent acquisitions,

mergers, and divestitures is inherently flawed. The Attorney General's assertions that the

TFP study relied on flawed data is not sufficiently supported, and, therefore, the Department

agrees with the Company's contention that such exclusions are arbitrary.

TFP Study Benchmark Year

In order to calculate the quantity of capital stock over time, an input into the

calculation of TFP, the Company first had to choose an initial "benchmark year" as a starting

point of the capital stock calculation (Exhs. ES-JF/MF-2, at 34; AG-MNL-3, at 31). The

Company describes that the capital quantity in the benchmark year is calculated from the

gross book value of all capital assets for each company in the sample, a value which is

comprised of assets of many different vintages (Exh. ES-JF/MF-2, at 34).47 For this reason,

the measure of capital stock is sensitive to the age of the different components captured in the

47 Capital stock in the benchmark year is calculated by dividing the estimated gross book value of a company's gas distribution asset base in 1998 by a 51-year average of an inflation index for 1998 and the previous 51 years (Exh. ES-JF/MF-2, at 31, 34-35;DPU-ES12-22 & Att.). Fifty-one years is the average service life calculated for the studies (Exh. ES-JF/MF-2, at 31).

D.P.U. 19-120Page 83

gross book value (Exh. ES-JF/MF-2, at 34). The Company used 1998 as a benchmark year, explaining that while a year well before the study period begins in 2003 is preferable for accuracy, this must be balanced by a consideration of data availability (Exh. ES-JF/MF-2, at 34).

The Attorney General is concerned that 1998 is too close in time to the study period, reducing the accuracy of the benchmarking and X factor study results (Exhs. AG-MNL-1,

at 9, 18; AG-MNL-3, at 40, 43). Both the Company and the Attorney General agree that the calculation is likely to be more accurate if the benchmark year is earlier in time and that the choice of a benchmark year will depend on data availability (Exhs. ES-JF/MF-2, at 34; AG-MNL-3, at 31, 43; AG-MNL-Surrebuttal at 5). The Company contends that 1998 is an appropriate year given the availability of data, as estimating the benchmark capital stock in an earlier year would have limited the number of peer companies in the sample due to data

availability (Exh. ES-JF/MF-Rebuttal-1, at 19-20).48 Further, the Company argues that, counter to the Attorney General's assertion, the use of a later benchmarking year does not universally lead to underestimation of the TFP trend because deviations in real capital stock can be in either direction, depending on each firm's investment cycle

(Exh. ES-JF/MF-Rebuttal-1, at 20-21). The Company demonstrates, using NSTAR Gas as

48 If the Company were to use 1994 instead, the sample would lose representation for 15 to 20 percent of total customers served in 2017, depending on the sample (national or regional, respectively) (Exh. ES-JF/MF-Rebuttal-1, at 19-20). This would result in around 80 percent representation for the regional sample, and 55 percent for the national sample (Exh. ES-JF/MF-2, at 5, 7).

D.P.U. 19-120Page 84

an example, that using 1984 as a benchmark year, in fact, leads to a lower estimate of capital stock and a negligible impact on TFP growth rate (i.e., that it was not understated using the later benchmark year) (Exh. ES-JF/MF-Rebuttal-1, at 21-24). The Department recognizes that an earlier benchmark year provides more accurate results in some instances

(Exh. ES-JF/MF-1, at 22). Nonetheless, the Department also acknowledges that sample size is an important consideration for the purposes of conducting a robust study and there are limitations to the financial and operating data available for LDCs (Exh. ES-JF/MF-1, at 22). Accordingly, the Department is unpersuaded by the record evidence that the use of an earlier benchmark year is appropriate in this case.

Conclusion

In the sections above, the Department has reviewed the Company's proposed TFP study, which generates an X factor of -1.18 percent that was used in the benchmarking study to measure the NSTAR Gas's cost performance. The Department recognizes that all studies rely on various assumptions, as well as matters of judgement based on expertise

(Exh. ES-JF/MF-Rebuttal-1, at 44; Tr. 11, at 1527-1528). While the Attorney General raises concerns about certain assumptions and parameters used in the Company's TFP study, the Department finds that NSTAR Gas's study is reasonable. Accordingly, the Department approves the Company's proposed X factor of -1.18 percent based on a regional sample.

Consumer Dividend

The consumer dividend is intended to reflect expected future gains in productivity because of the move from cost of service regulation to incentive regulation. D.P.U. 96-50 (Phase I) at 165-166, 280. As a deduction to the PBR adjustment, the consumer dividend is

D.P.U. 19-120	Page 85
designed to allow ratepayers to share in these aforementioned gains (Exh. ES-JF/MF-1,
at 18). NSTAR Gas proposes not to apply a consumer dividend as part of the PBRM
(Exhs. ES-WJA/DPH-1, at 84; AG 37-1 Att. (b), at 45).

The Company conducted a total cost benchmarking study and determines that the results of the study indicate that NSTAR Gas is already relatively efficient, is an above-average performer, and therefore there is no need to include a stretch factor in the revenue cap per customer proposal (Exhs. AG- 7-1, Att. (b) at 45; DPU-ES12-8). Further, the Company claims, that even absent a consumer dividend, the I-X formula in the PBRM incentivizes the Company to maintain productivity over time that is in line with the industry trend, otherwise, it will not realize its allowed ROE (Exh. DPU-ES12-8). The Company asserts that, based on its already high level of efficiency, its performance goal during the PBR term should be to maintain its efficiency over a period where it may experience increasing costs, as opposed to eradicating existing inefficiencies which is what a consumer dividend is designed to incentivize (Exhs. DPU-ES3-4;DPU-ES22-15).

The Attorney General argues that there are several methodological concerns with how the Company conducted the benchmarking study and she conducted a revised benchmarking analysis to account for some of these concerns. The Attorney General concludes that, contrary to the Company's assertion, NSTAR Gas is an average cost performer

(Exh. AG-MNL-3, at 53). The Attorney General also argues that the Company's proposed consumer dividend of zero is not supported by the benchmarking results (Exh. AG-MNL-1, at 21-22).

D.P.U. 19-120	Page 86
As with the Attorney General's critiques of the Company's TFP study, the

Department finds that the critiques associated with the Company's benchmarking study are similarly unfounded. The Department also acknowledges that experts rely on various assumptions that are often based in professional judgment and do not necessarily render a study faulty.

The Department has previously found that a consumer dividend represents an explicit, tangible ratepayer benefit. D.P.U. 18-150, at 60-61; D.P.U. 17-05, at 395. The Department is concerned that without a consumer dividend, ratepayer benefits will be realized only at the end of the PBR term when rates are reset, rather than throughout its operation. Therefore, the Department is not persuaded that a consumer dividend of zero is appropriate.

While NSTAR Gas proposes no consumer dividend, the Company acknowledges that in the context of a PBR formula set on the basis of a regional peer group, it could operate with a consumer dividend between 10 and 15 basis points (Exh. DPU-ES22-15, at 1). Moreover, on reply brief the Company notes that its cost performance would align with a stretch factor of 0.15 percent under the criteria established for assigning stretch factors in Ontario (Company Reply Brief at 21-22). As such, the Department finds that the record supports that a consumer dividend of 0.15 percent is necessary to provide an immediate ratepayer benefit, consistent with Department precedent. Accordingly, the Department directs the Company to incorporate a consumer dividend of 0.15 percent in its PBR formula.

D.P.U. 19-120

Page 87

Earnings Sharing Mechanism

The Department has found that ESMs may be integral components of incentive regulation plans. D.P.U. 94-50, at 197 n.116. Specifically, the Department has found that ESMs provide an important backstop to the uncertainty associated with setting the productivity factor. D.P.U. 18-150, at D.P.U. 17-05, at 400; D.P.U. 96-50 (Phase I)

at 325; D.P.U. 94-50, at 197.

The Company proposes to implement a symmetrical ESM with a deadband of 100 basis points (Exh. WJA/DPH-1, at 91). Under the Company's proposal, earnings or losses would be shared with ratepayers and shareholders on a 75/25 percent basis (i.e., 75 percent to ratepayers and 25 percent to shareholders) when the calculated distribution ROE either exceeds or falls short of the ROE authorized in this proceeding by 100 basis points (Exh. WJA/DPH-1, at 91).

The Attorney General, as well as TEC, argue that a symmetrical ESM punishes ratepayers and acts primarily to protect the Company's shareholders. Both intervenors argue that the Department should approve an asymmetrical ESM, with sharing only occurring in the instance of earnings above the proposed deadband (Attorney General Brief at 134; TEC Brief at 8).

An ESM offers an important protection for ratepayers in the event that expenses increase at a rate much lower than the revenue increases generated by the PBR. D.P.U. 18-150, at 70; D.P.U. 17-05, at 400; D.P.U. 10-70, at 8 n.3; D.T.E. 05-27, at 404-405. For this reason, the Department finds that there is a significant benefit to

D.P.U. 19-120Page 88

implementing an ESM as part of the PBRM adopted in this case. As discussed below, the Department finds that certain modifications to the Company's proposed earnings sharing mechanism are necessary to appropriately balance the risks to shareholders and ratepayers under the PBR.

Regarding a symmetrical or asymmetrical deadband, the Department finds that an asymmetrical deadband, as proposed by the Attorney General and TEC, appropriately protects ratepayers, is consistent with recent Department precedent, and further increases the Company's incentives to pursue savings, as a greater share of under-earnings will be borne by the Company. D.P.U. 18-150, at 71-72; D.P.U. 17-05 at 401. In contrast, a symmetrical deadband inappropriately shifts losses to ratepayers.

As noted above, the Company proposed to adopt a deadband of 100 basis points (Exh. WJA/DPH-1, at 91). The Department has recently, and historically, approved ESMs with deadbands of 200 basis points or greater. D.P.U. 18-150, at 71-72; D.P.U. 17-05, at 401; D.T.E. 05-27, at 405; D.T.E. 03-40, at 500; D.P.U. 96-50 (Phase I) at 326. NSTAR Gas acknowledges that the 100-basis point deadband is narrower than would typically apply in an ESM but argues that it is appropriate due to the future uncertainty plaguing the gas distribution industry (Exh. ES-WJA/DPH-1, at 91). Here, the Department is not persuaded that a 100-basis point deadband below the authorized ROE is appropriate.

The Department has concerns regarding a narrow deadband because increased administrative efficiency and reduced administrative costs are both considered benefits of incentive regulation. D.P.U. 96-50 (Phase I) at 320; D.P.U. 94-158, at 64. When the

D.P.U. 19-120Page 89

Department inquired as to how the Company would have fared with its proposed ESM if it had been in place during the period of 2008 through 2018, the Company demonstrated that the ESM would have been triggered for an ROE below the authorized level in 2008, 2012, and 2016 under an ESM with a 100-basis point deadband, but not at all if it had a deadband of 200-basis points (Exhs. DPU-ES3-2 & Att. (a); DPU-ES3-3 & Att.). Further, the Company testified that with a 100-basis point deadband, any modifications to the PBR Plan would likely trigger the ESM for earnings below the authorized ROE as soon as the first year of the PBR term (Tr. 3, at 388-390; Tr. 6, at 712; RR-DPU-15). While the Company argues that this circumstance would indicate that the PBRM is not operating as intended, the Department finds that this result is more indicative that the deadband below the ROE is too narrow and, therefore, that the ESM is too sensitive to downside risk (Company Reply Brief at 41).

The Department finds that an asymmetrical deadband of 100 basis points above and 150 basis points below the authorized ROE is appropriately sensitive to variations in ROE, administratively efficient, consistent with Department precedent, and will provide the Company with a strong incentive to pursue savings. To appropriately balance shareholder and ratepayer risk under the PBRM as designed, the Department finds that the benefits of any earnings above the deadband must inure largely to ratepayers. Accordingly, we find that a mechanism that shares earnings with ratepayers and shareholders on a 75/25 percent basis (i.e., 75 percent to ratepayers and 25 percent to shareholders) for earnings more than 100 basis points above the authorized ROE and losses with ratepayers and shareholders on a

D.P.U. 19-120	Page 90
50/50 percent basis	(i.e., 50 percent to ratepayers and 50 percent to shareholders) for losses

between 150 and 200 basis points below the authorized ROE, and on a 75/25 percent basis

(i.e., 75 percent to ratepayers and 25 percent to shareholders) for losses more than 200 basis points below the authorized ROE is appropriate in this case. These ratios will provide NSTAR Gas an adequate incentive to pursue savings while protecting ratepayers from any unforeseen financial windfall or underearning for the Company.

In conclusion, the Department finds that the Company's PBRM shall include an asymmetrical ESM that sets a deadband of 100 basis points above and 150 basis points below the Company's authorized ROE. If NSTAR Gas's earned distribution ROE falls within the deadband, there will be no sharing. If the Company's earned distribution ROE exceeds the authorized ROE by more than 100 basis points, the earnings above the deadband will be shared 75 percent with ratepayers and 25 percent with shareholders. If the Company's earned distribution ROE is between 150 and 200 basis points below the authorized ROE, the shortfall below the deadband will be shared 50 percent with ratepayers and 50 percent with shareholders, and if the Company's earned distribution ROE is more than 200 basis points

below the authorized ROE, the shortfall below the 150 basis point deadband49 will be shared 75 percent to ratepayers and 25 percent to shareholders.

49 The Department will fully review the Company's ESM filing and may make a financial adjustment if it determines that the Company underearned as a result of inappropriate spending or accounting to trigger an ESM. The ESM is not designed to create a perverse incentive but rather to balance risk under a multi-year PBR plan.

Attachments

Original document
Permalink

Disclaimer

Eversource Energy published this content on 30 October 2020 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 03 November 2020 08:09:02 UTC

Market Closed - Nyse Other stock markets 04:00:02 2024-05-07 pm EDT			5-day change	1st Jan Change
61.17 ^USD	+2.45%		+0.91%	-0.89%

May. 03	BMO Capital Adjusts Price Target on Eversource Energy to $66 From $65	MT
May. 03	Wells Fargo Adjusts Price Target on Eversource Energy to $72 From $69	MT

BMO Capital Adjusts Price Target on Eversource Energy to $66 From $65	May. 03	MT
Wells Fargo Adjusts Price Target on Eversource Energy to $72 From $69	May. 03	MT
Google Objects to Epic Games' Proposed Changes in Play Store	May. 03	MT
Eversource Energy Q1 Earnings Climb, Revenue Declines	May. 02	MT
Transcript : Eversource Energy, Q1 2024 Earnings Call, May 02, 2024	May. 02
Declared voting Results by Eversource Energy	May. 01	CI
Earnings Flash (ES) EVERSOURCE ENERGY Reports Q1 EPS $1.49	May. 01	MT
Eversource Energy Reaffirms Earnings Guidance for the Year 2024	May. 01	CI
Eversource Energy Approves Common Dividend, Payable June 28, 2024	May. 01	CI
Eversource Energy Reports Earnings Results for the First Quarter Ended March 31, 2024	May. 01	CI
Morning Bid: Mayday for bonds as 2024 Fed cut hopes dwindle	May. 01	RE
Installed offshore wind capacity in U.S. sees nearly six-fold jump in first-quarter, report says	Apr. 23	RE
Barclays Adjusts Price Target on Eversource Energy to $65 From $62	Apr. 22	MT
BMO Capital Raises Eversource Energy's Price Target to $65 From $64	Apr. 22	MT
Scotiabank Adjusts Eversource Energy's Price Target to $57 From $61	Apr. 22	MT
Utility Stocks Climb; Eversource Energy Finalizes Deal -- Utilities Roundup	Apr. 19	DJ
Eversource Energy Says It Executed Definitive Agreement to Sell Stake in Sunrise Wind Project	Apr. 19	MT
China Industrial Securities Sells Bonds Issued by Eversource, Electricite De France	Apr. 17	MT
Meta Platforms Wants FTC Lawsuit Over Instagram, WhatsApp Buyouts Thrown Out	Apr. 05	MT
North American Morning Briefing : Investors on -2-	Apr. 05	DJ
UBS Upgrades Eversource Energy to Buy From Neutral, Adjusts Price Target to $67 From $62	Apr. 04	MT
US approves Orsted's Sunrise Wind offshore wind farm to power New York homes	Mar. 26	RE
Argus Adjusts Price Target on Eversource Energy to $68 From $85, Maintains Buy Rating	Mar. 25	MT
John Chevedden Submits a Shareholder Proposal to Eversource Energy	Mar. 22	CI
Equinor, Ørsted/Eversource Get Conditional Awards for New York Offshore Wind Projects	Feb. 29	DJ

	1st Jan change	Capi.
EVERSOURCE ENERGY	-0.89%	21.55B
NEXTERA ENERGY	+18.46%	148B
SOUTHERN COMPANY	+9.74%	84.14B
IBERDROLA, S.A.	-0.08%	80.67B
DUKE ENERGY CORPORATION	+5.38%	78.89B
ENEL S.P.A.	-4.28%	69.89B
CONSTELLATION ENERGY CORPORATION	+71.58%	63.2B
AMERICAN ELECTRIC POWER COMPANY, INC.	+10.65%	47.37B
GE VERNOVA INC.	0.00%	45.87B
DOMINION ENERGY, INC.	+10.89%	43.69B

Eversource Energy

Equities

ES

US30040W1080

Electric Utilities

Eversource Energy : NSTAR Gas Rate Order (October 30)

Latest news about Eversource Energy

Chart Eversource Energy

Company Profile

Income Statement Evolution

Ratings for Eversource Energy

Analysts' Consensus

EPS Revisions

Quarterly earnings - Rate of surprise

Sector Other Electric Utilities