Ratemaking and Regulation
for Massachusetts Electric
Utilities
Jeff Hall and Ben Davis
MA DPU
Grid Modernization Steering
Committee
February 5, 2013
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Disclaimer
This presentation is not intended to represent official views
of the Massachusetts Department of Public Utilities or the
Commission.
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Purpose of Presentation
• Provide a high level introduction to ratemaking and
regulation to help the Working Group consider the question:
“What policies might we recommend to the DPU to advance
grid modernization goals?”
• Present (1) a snapshot of basic principles of “traditional”
ratemaking and (2) alternative regulatory approaches used in
Massachusetts.
• Not intended to be exhaustive; does not address
complexities, nuances, or debates about various elements.
• Goal: provide a “baseline” of understanding to foster
useful discussion.
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Outline
• Basic principles of “traditional” ratemaking
• Regulatory developments in Massachusetts
• Performance Based Ratemaking
• Service Quality Regulation
• Decoupling
• Cost Recovery Mechanisms outside of “traditional”
ratemaking
• Energy Efficiency
•Time-varying pricing?
• How does this discussion inform the Working Group?
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Traditional Method for Setting Distribution
Rates
RR = O&M + D + T + r(RB)
 RR = Revenue Requirement
 O&M = Operating and Maintenance Expense
 D = Depreciation and Amortization
 T = Taxes
 r = Rate of Return
(both debt service and shareholders)
 RB = Rate Base
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Traditional Method for Setting Rates
• Decisions are based on extensive Department precedent.
• Distribution rates are non-reconciling and are frozen between
rate cases.
• Utility bears risk of change in revenue as well as costs.
• Utility will file for a rate change because revenues are too
low or costs are too high.
• DPU may order a utility to make a rate filing if over earning
(G.L. c. 164, sec. 93).
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Performance Based Ratemaking (“PBR”)
• PBR is an example of an innovation to traditional ratemaking
to increase the incentive for companies to reduce costs.
• Price cap model used in Massachusetts, but there are other
models for PBR, such as a revenue cap.
• Utility operates under a term during which it will not file for a
rate case in exchange for annual, formulaic rate increases
(typically 10 years).
• Increases the utility’s incentive to reduce expenses while
providing ratepayer with certainty of future rate increases.
• To ensure that the utility’s efforts to reduce costs do not result
in a reduction in service quality, service quality (“SQ”) standards
were introduced.
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Service Quality
 Originally part of Restructuring Act, updated several times since.
 Companies file annual SQ reports, which include many metrics, e.g.:
 System and Circuit Outage Duration and Frequency

SAIDI & SAIFI: Average minutes or durations per customer.
 Customer Service – telephone answering, service appointments
 Safety – Lost work time due to accidents
 Penalties associated with certain metrics, up to a total of 2.5% of
annual transmission and distribution revenue.
 Current NOI “tees up” several aspects (e.g., alternative metrics (DG),
methods of benchmarking, penalty framework) and seeks input.
 Attorney General filed detailed report on strengthening SQ standards.
 Purpose of SQ is to measure day to day service; therefore, major events
(such as large storms) are excluded.
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Regulatory Framework For Storms
 Major events such as large storms are excluded from
SQ metrics and are evaluated outside of SQ.
 In recent years, the regulatory framework for storms
has evolved:
 Legislation – e.g., Emergency Response Plans, Penalty
Authority
 D.P.U. Regulations
 D.P.U. Investigations
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Decoupling
• Docket D.P.U. 07-50 (Generic)
• Purpose – To eliminate potential barriers to distribution
companies’ aggressive pursuit of energy efficiency and
demand resources.
• Main principle:
• To sever revenue recovery from sales volumes while
adhering to the Department’s ratemaking principles
(fairness, equity, continuity, etc.).
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Mechanics of Revenue Decoupling - Electric
• The annual base rate adjustment equal to the difference
between actual billed distribution revenues and annual
target revenues divided by forecasted sales.
• Annual rate adjustment capped at 3% of total revenues so
as to maintain rate continuity (utility can defer any
unrecovered balance for recovery in the subsequent year).
• NSTAR is only electric company that has not decoupled.
• NSTAR collects Lost Base Revenue (“LBR”) associated with its
energy efficiency programs (Merger Settlement,
D.P.U. 10-170).
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Tracking & Recovering Costs Outside Base Rates
• Mechanisms track actual costs & utilities file for DPU
approval of recovery.
• Simply a pass through of costs.
• Utilities have had reconciling cost recovery mechanisms for
decades (e.g., fuel charge).
• Creation of these mechanisms based on several factors:
legislation (utility ownership of solar facilities; long term
contracts for renewable energy); public policy objectives
(low-income discount); volatile costs outside of a utility’s
control (pension costs).
• Many examples: Pension Adjustment Factor (PAF),
Residential Assistance Adjustment Factor (RAAF), Smart
Grid Adjustment Factor (SGAF), Solar Cost Adjustment
Factor (SCAF), Energy Efficiency Surcharge (EES), etc.
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Tracker Mechanisms for Capital Investments
• Essentially allows a company to recover certain capital
investments in a manner similar to rate base, on an annual
basis outside of base rates, subject to review & DPU
approval.
•
Earn a “return of” and “return on” investment
• Reduces regulatory lag
•
Including value of depreciation
• Examples: National Grid’s CapEx, Bay State Gas’ TIRF
• Use of these mechanisms is topic of ongoing discussion.
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Energy Efficiency
 Long history of energy efficiency programs in MA
 Green Communities Act - statewide, three-year approach
to achieve “all available cost-effective.”
 Mechanism to recover projected costs; later reconciled to
actual, approved costs.
 Includes performance incentive.
 Based on achievement of benefits, net benefits, and
meeting “performance metrics” (designed to encourage
specific activities).
 Company must achieve at least 75% of “design” level
incentive to begin earning incentive; cap at 125%.
 2013-2015 Three-Year Plans, approved January, 2013.
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Time-varying Pricing?
 Presentation – mostly distribution rate portion of the bill
 Current form – Not “time-varying.”
 Should time-varying rate be considered? Reflect costs?
 Supply portion of the bill
 Most small customers on basic service (DPU policy
governs); most large customers on competitive supply.
 Basic service – currently not “time-varying.”

Should it be? What would the impacts be? Who benefits?
 Question - capabilities of meter, communications,
data management, and billing systems?
 What would be needed? Benefits vs. costs?
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Recap
 The purpose of this presentation? To help the WG consider
questions like:
 To what degree is ‘traditional’ regulatory framework sufficient/





insufficient to achieve certain GM goals?
To what degree are current SQ or storm regulations sufficient/
insufficient to achieve certain GM goals? Should SQ metrics be
updated to achieve certain GM goals?
Should modification or additional cost-recovery mechanisms be
considered/ or not?
Is a broader change needed, akin to PBRs or decoupling?
Does an alternative framework, such as what is used for energy
efficiency, provide ideas?
In other words…
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In which box (or boxes)
do Grid Modernization
activities fit? Do we
need a new box?
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