Targeting Attrition: Some Familiar Ratemaking Tools

Kenneth Gordon is a Special Consultant at NERAand specializes in utility regulation and related

issues. He was previously Chairman of theMassachusetts Department of Public Utilities. Hecame to the Massachusetts Commission from the

Maine Public Utilities Commission, where he alsoheld the office of Chairman. Prior to that, he was anIndustry Economist at the Federal Communications

Commission’s Office of Plans and Policies. Dr.Gordon was an active member of the National

Association of Regulatory Utility Commissioners(NARUC) and served as President of that

organization in 1992. He was also a member ofNARUC’s Executive Committee and Committee on

Communications. In addition, he has served asChairman of the New England Conference of Public

Utilities Commissioners TelecommunicationsCommittee and is a former Chairman of the Power

Planning Committee of the New EnglandGovernors’ Conference.

Wayne P. Olson is a Senior Consultant at NERAand focuses on economic, finance, accounting, and

public policy issues in the electric utility, gasdistribution, oil and gas pipeline, and

telecommunications industries. Prior to joiningNERA, he was Director of Finance of the Maine Public

Utilities Commission, where he was involved inelectric restructuring and telecommunications

activities as well as the full gamut of rate case and otherregulatory issues. He has also served as a Manager at

Palmer Bellevue Corporation, an InternationalBanking Officer at Westpac Banking Corporation, and

a Financial Analyst in the Economics and RatesDepartment of the Illinois Commerce Commission.

Kurt G. Strunk is a Senior Consultant at NERA andhas extensive experience working on strategic,

regulatory, and corporate financial issues in theenergy industry. In the U.S., he has advised utilities on

sector restructuring, contract and asset valuation,origination, hedging and risk management,

regulatory strategy, prudence, cost of capital, affiliatetransactions, and retail market issues. He has been akey member of the NERA team implementing auctions

for the provision of default electric service in NewJersey and Illinois. Mr. Strunk has also advised

governments, regulators, and energy companies onissues relating to industry structure, regulation, and

sector reform in Latin America and Europe. Hecoauthored the white paper outlining structural

reform and partial privatization of the Mexican powersector, which was developed for Mexico’s NationalCongress in 2000. In 2002 and 2003, Mr. Strunkadvised the Commission for Energy Regulation inIreland on the development of a solicitation for the

construction of a 400 MW power generation facilityand associated offtake contract. He has also advised

Mexico’s Comision Federal de Electricidad on thedevelopment of its independent power program and, in1996, was part of the NERA team working on power

sector restructuring in Spain.

10
1040-6190/$–see front matter # 2011 Else
Targeting Attrition:Some Familiar RatemakingTools

Because of their investment in long-lived assets withlittle value in alternative uses, special attention to meetingthe terms of the regulatory compact is appropriate.This need not always take the form of full-blown ratecases—there are more targeted tools as well. Targetedand formula-based approaches can play a role in settingjust and reasonable rates, based on prudently incurredcosts.

Kenneth Gordon, Wayne P. Olson and Kurt G. Strunk

I. Introduction

Public utilities invest in long-

lived, specialized assets. This

‘‘infrastructure’’ supports

economic growth and, as such,

helps to explain why public

utilities are regulated.1 Public

policymakers—at the federal level

and in many states—have made

modernization of the nation’s

electric transmission and

distribution infrastructure a

priority.2 There are a variety of

vier Inc. All rights reserved., doi:/10.1016/j.

policies and practices that can be

considered ‘‘standard’’ public

utility regulatory methods and

that can support investment in

infrastructure.

S tate utility commissions use a

variety of regulatory policies

and practices—variations on a

theme but distinctive enough to

suit the needs of the state. For

utility investors, it is not the tiny

details that matter, but rather

whether there is a credible

commitment to treat both utility

tej.2011.07.005 The Electricity Journal

http://dx.doi.org/10.1016/j.tej.2011.07.005

With any application ofthese regulatorybuilding blocks, thereneeds to be an assurancethat each ratemakingtool can work correctlyand not simply end-runthe regulator.

A

customers and utility investors

fairly, over the short and long

runs. Public utilities are regulated

to protect utility customers from

the consequences of the unfair

exercise of market power.

W hat purpose would

targeted and formula-

based regulatory approaches

serve? The answer to that

question would vary from state to

state and from case to case, but, in

the current economic climate, we

would suggest that there are three

major challenges that many

electric utilities are now facing: (1)

attrition, which is a persistent

inability to recover the real costs

of providing utility services; (2)

the need to invest capital to build

utility infrastructure, some of

which is mandated by the makers

of public policymakers, which can

exacerbate the attrition problem;

and (3) credit ratings that are

above investment grade, but that

remain weak by historical

standards. A utility’s persistent

inability to recover the real costs

of providing utility service would

harm customers. Direct solutions

to the attrition problem may be

difficult to achieve, so the focus of

this article is on investigating new

applications of traditional

regulatory tools, aiming to

provide commissions and utilities

with examples of approaches that

could meet current challenges.

In this article, we review key

regulatory building blocks that

could accommodate regulatory

approaches that result in more

timely recovery of costs.

Examples of regulatory

approaches that are increasingly

ug./Sept. 2011, Vol. 24, Issue 7 1040-6190/$–

being used by state commissions

when setting utility rates include:

� Asset ‘‘trackers’’ for defined

categories of capital expenditures

(‘‘cap ex’’) as they enter rate base.

� Construction work in

progress (CWIP) in rate base with

a cash return.

� Indexing procedures of

various sorts.

� Alternative forms of

regulation, such as broad-based,

formula-rate plans.

� Some form of ‘‘pre-

approval’’ of the regulatory

policies and practices to be used

for a major capital addition, often

generation- or transmission-

related, but that could also apply

to major distribution investments.

Next, we survey and review

specific examples of these

approaches. This article identifies

regulatory building blocks that

are squarely part of standard

regulatory methods, but that,

given the challenges currently

facing the electric utility industry,

may have a greater role to play.

In conclusion, we review some

of the crucial public policy

considerations, e.g., economic

see front matter# 2011 Elsevier Inc. All rights

efficiency and consumer benefits,

which state commissions should

consider. With any application of

these regulatory building blocks,

there needs to be an assurance

that each ratemaking tool can

work correctly and not simply

end-run the regulator. The

approaches described in this

article have the potential to

provide benefits to utility

customers.

II. Industry Challenges

Each state and region has its

own infrastructure needs and

would focus its attention on how

to best meet those needs. Utility

ratepayers would be well served

by a regulatory framework and

company policies that serve the

public interest by minimizing the

overall cost of capital, while

facilitating investments in needed

infrastructure by the regulated

utility industry. There are a

variety of ways to accomplish this

goal.

I n the current economic

climate, we would suggest

that there are three major

challenges that many electric

utilities are now facing:

� Attrition dilemma. Rates that

are adequate for a given ‘‘test

year’’ can fall short in succeeding

periods given growth in rate base

and increasing operating costs,

leading to ‘‘attrition,’’ which is the

erosion of earnings ‘‘caused by

cost of services increasing more

rapidly than revenues.’’3 Figure 1

provides evidence that some

electric utilities have not earned

reserved., doi:/10.1016/j.tej.2011.07.005 11


[(Figure_2)TD$FIG]

32

37

47

55

6360 59

70 6868

0

10

20

30

40

50

60

70

80

2013E2012E2011E2010200920082007200620052004Year

Tot

al C

apita

l ($

Bill

ions

)

Source: Regulatory Research Associates (SNL Energy), Financial Focus Special Report, Capital Expenditures, May 6, 2011

Figure 2: Total Capital Expenditures for 44 Companies (Historical and Forecast-$ Billions)

[(Figure_1)TD$FIG]

8.00

8.50

9.00

9.50

10.00

10.50

11.00

2006 2007 2008 2009 2010

Ret

urn

on E

quity

(%)

Year

Earned ROE Allowed ROE

Figure 1: Allowed ROE vs. Earned ROE (2006–2010)

12

their allowed ROE in recent years.

With few exceptions, all of a

utility’s activities are aimed at

meeting its obligation to serve

customers and, therefore, the

legitimate costs incurred by a

utility as part of its efforts to meet

the needs of its customers would

be recoverable in rates. With

appropriate incentives in place,

there is a strong presumption that

all of a utility’s costs will be

incurred to meet the utility’s

obligation to serve. While there is

no guarantee that a utility will

actually be able to earn its cost of

capital once rates have been set, if

rates are set such that the utility

does not have a realistic

opportunity to recover its costs,

harm to customers will likely

result in the longer run, if not

sooner.

� Capital expenditure challenge.

Infrastructure investment in

generation, transmission, and

distribution plant would be

needed to meet the ambitious


goals and major challenges that

face the electric utility industry—

and extensive cap ex construction

programs can exacerbate a

utility’s attrition problem.

Figure 2 shows that the cap ex

plans of utilities are ambitious,

requiring the raising of significant

new capital over the next few


years. The ability of utilities to

fund capital investment is directly

dependent on their ability to raise

debt and equity in the capital

markets. Moreover, most states

now have renewable portfolio

standards (RPS) or state mandates

in place,4 as shown in Figure 3. To

meet RPS type mandates, many

utilities will need to invest in the

infrastructure needed to make use

of that renewable energy. Given

the nature of these infrastructure

investments, some degree of

regulatory pre-commitment

would likely be appropriate,

along with other regulatory

building blocks, such as asset

trackers and CWIP in rate base

with a cash return.

� Credit quality constraint.

Electric utility credit ratings are

generally above investment

grade, but remain weak by

historical standards. Figure 4

shows the S&P bond ratings for

electric utilities.5 The sharp



[(Figure_3)TD$FIG]

VA

PA

NC

MI

WVKY

LA

AR

MN

OK

NV

CA

ID

AL

AZ

CO

FL

GA

IA

IL IN

KS MO

MS

MT ND

NE

NM

NY

OH

OR

SC

SD

TN

TX

UT

WA

WIWY

AK

HI

DC

NJ

MD

RI

VT

ME

DE

NHMACT

VA

PA

NC

MI

WVKY

LA

AR

MN

OK

NV

CA

ID

AL

AZ

CO

FL

GA

IA

IL IN

KS MO

MS

MT ND

NE

NM

NY

OH

OR

SC

SD

TN

TX

UT

WA

WIWY

AK

HI

DC

NJ

MD

RI

VT

ME

DE

NHMACT

Source: Energy Information Administration, Renewable Energy Trends in Consumption and Electricity 2008.

Figure 3: States with Renewable Portfolio Standards, 2008

A

decline in electric utility credit

quality (relative to 2001 levels)

begs the question of whether the

industry and its regulators will

together be able to find ways to

implement the nation’s grid

modernization, energy

independence, and

environmental goals in a timely

and efficient manner. Timely rate

[(Figure_4)TD$FIG]

Electric Util196

0%10%20%30%40%50%60%70%80%90%

100%

198519831980197519701965

A- or higher

Sources: Leonard Hyman and EEI.

Figure 4: Electric Utility Bond Ratings (1965–

ug./Sept. 2011, Vol. 24, Issue 7 1040-6190/$–

recovery methods would be a

necessary part of that balanced

approach. The ability of utilities to

fund capital investment is directly

dependent on their ability to raise

debt and equity in the capital

markets. Under current market

conditions, it would be relatively

more difficult for utilities to raise

funds in the debt market, and

ity Bond Ratings5-2009

200920082007200119921990

BBB Below BBB-

2011)


when they do so, it would be at a

higher cost than it would have

been with a bond rating of ‘‘A-/

A300 or higher.

U tility ratemaking should

not prevent a utility from

earning an adequate return on its

investment in serving the public.

Attrition, which is typically

discussed in the context of the

combined effects of inflation and

large-scale construction programs

on a utility’s opportunity to

actually earn its allowed ROE,

should not lead to a public utility

being prevented from having a

reasonable opportunity to recover

its prudently incurred costs,

including the forward-looking

cost of capital.

Leonard Saul Goodman points

out that‘‘[i]f attrition is an

economic factor truly beyond the

company’s control, and if it is a

proper cost in a transitional

inflationary period, there is



An importantelement in

this demonstrationis being

able to pointto a supportive

regulatoryenvironment.

14

unfairness in placing the entire

burden of the cost on

shareholders.’’6 A close reading of

this comment suggests that:

� Economic factor truly beyond

the company’s control.

Infrastructure costs aimed at

achieving ‘‘energy

independence’’ can be considered

to be a type of mandated cost,

with the initial decision to

construct beyond the control of

the utility. To meet RPS mandates,

utilities will need to invest in

infrastructure and some degree of

‘‘preapproval’’ of the initial

decision to construct can be

justified.

� A proper cost. Note that the

utility would continue to have

control of its execution of the

project and therefore would face

prudence scrutiny with respect to

the mandated investment.

� Unfairness in placing the

burden entirely on shareholders.

With respect to the traditional

regulatory ‘‘balancing act,’’

efforts to ameliorate the economic

effects of attrition by providing

more timely cost recovery can be

beneficial to both utility

customers and investors. This is

because utility customers’ rates

will reflect the weighted cost of

the utility’s debt, preferred stock,

and common equity—and use of

the regulatory building blocks can

potentially reduce these capital

costs.

T he traditional standard to

justify the suitability of a

fuel adjustment mechanism is

whether the cost of the purchased

item is beyond the control of the

utility, large, and volatile.7


Applying an analogous

ratemaking approach to

mandated infrastructure

investments can potentially make

sense from a public policy

perspective. After all, the

cumulative effect of numerous

ratemaking adjustments should

not prevent a utility from having

the opportunity to earn a

compensatory return on capital.

Absent imprudence, a public

utility should not face a persistent

inability to recoup its costs of

providing utility service. Put

more positively, a utility should

be given a reasonable opportunity

to realize an adequate rate of

return and thereby be assured of

access to the capital markets at a

reasonable cost—because

customers would benefit.

III. Regulatory BuildingBlocks

The focus of utility regulation

should always be on consumers,

with regulation ensuring that the

rates paid by utility customers are

just and reasonable, based on


prudently incurred costs. Given

that regulated electric utilities

must be able to raise substantial

amounts of both debt and equity

capital in order to fund

investment in long-lived,

specialized assets, utilities must

be able to demonstrate that they

have the financial standing and

resources needed to raise capital

at a reasonable cost, in good

markets and bad, in both the short

and long terms. An important

element in this demonstration is

being able to point to a supportive

regulatory environment.

T he purpose of this section is

to review key regulatory

building blocks that can

accommodate regulatory

approaches that result in more

timely recovery of costs. These

building blocks include such

regulatory practices as:

� FERC Form 1 accounting

statements. Effective regulation of

any form requires that regulators

define the consistent, durable, and

transparent accounting

procedures to be used by

regulated utilities. The early

history of regulation in the U.S.

was characterized by notorious

accounting abuses, including

overstated expenses, unverifiable

investments in plant and

equipment, a lack of separation

between utility and non-utility

businesses, and

overcapitalization. Such abuses

were ended with the adoption, in

1938, of the Uniform System of

Accounts by the federal

government.8 The goals of good

regulation are frustrated when the

lack of detailed and reliable



A

accounting data obstructs the

regulator’s ability to periodically

assess the cost of service.9 For

example, the Uniform System of

Accounts rarely leaves U.S. energy

utilities and their regulators in

dispute over basic financial issues

such as profitability, depreciation

expenses, customer contributions,

incurred operating costs, or the

treatment of unregulated affiliates.

Rate cases instead focus on how

these costs should be recovered for

ratemaking purposes.

� Adjustment mechanisms.

Infrastructure recovery

mechanisms, also known as ‘‘asset

trackers’’ or ‘‘riders,’’ are roughly

analogous to the adjustment

mechanisms that are used to pass

through the costs of fuel and

purchased power. Regulatory

Research Associates (RRA)

explains that ‘‘from an investor

standpoint, this is the preferred

treatment, as adjustment clauses

can allow for more timely rate

recognition of incremental

CWIP.’’10 Asset trackers or similar

adjustment mechanisms allow for

more-timely recovery of rate base

additions than would be the case

with traditional rate cases.

Operating and maintenance

expense (O&M) riders or trackers

of various sorts, such as bad debt

riders or regional cost riders, could

also be used. Adjustment

mechanisms have been used by

regulators since the early days of

the industry.11

� CWIP in rate base with a cash

return. As commissions and

utilities grapple with questions of

how best to invest in the utility

infrastructure needed to

ug./Sept. 2011, Vol. 24, Issue 7 1040-6190/$–

accommodate public policy goals,

allowing CWIP in rate base with a

cash return has once again

become a standard part of the

regulatory toolkit. As the industry

proceeds with the ongoing

construction cycle, legislatures

and regulators have begun to

allow CWIP in rate base for a cash

return, sometimes restricted to

only certain designated types of

plant, i.e., transmission or certain

types of generation.12 RRA

reports that 16 states have

permitted a cash return on CWIP

in recent years and that eight of

the states that allow CWIP in rate

base with a cash return also allow

asset trackers to be used.13 Given

that an allowance for funds used

during construction (AFUDC)

need not be recovered in rates,

using this approach reduces the

total cost to customers.

� Inflation adjustments. Attrition

is the persistent inability to recover

the real costs of providing utility

services. To mitigate the impact of

attrition, regulators use inflation

adjustments in a variety of ways

including attrition allowances,

fully forecasted test years,


projections of cost items, true-up

of projected and actual costs, and

formal price cap plans (inflation

minus an x-factor). Generally,

inflation adjustments can help

maintain rates at levels that

provide a utility with a reasonable

opportunity to recover its costs,

including the cost of capital.

� Cap ex budgeting. All investor-

owned public utilities have some

type of capital expenditure

budgeting process in place to

prioritize the many alternative

infrastructure investments that

could be made. In a few states,

ex ante cap ex budgeting

information is formally provided

to the utility regulator, while, in

other cases, less formal

procedures are used to keep the

regulatory agency informed.

Either way, the cap ex budgeting

process can build a foundation for

recovering utility costs in a timely

manner.

T hese building blocks can aid

in the establishment of

regulatory practices that support

investment in utility

infrastructure, which can, in turn,

aid in meeting RPS requirements

and other state goals.14 The

regulatory process has safeguards

(e.g., prudence reviews) to assure

that tariffed rates remain at a just

and reasonable level. Consistent

with the regulatory compact,

which provides a means of

balancing the competing interests

of utility customers and the

investor–owners of public

utilities, these tools can be used to

respond and adapt to changes in

customer, industry, and market

conditions.



16

IV. Some Solutions tothe Attrition Problem

Utility ratemaking is conducted

on a case-by-case, fact-specific

basis. While the details vary

somewhat from state to state, the

basics of the ratemaking process

are largely the same. For any

given jurisdiction, the

overarching framework of utility

regulation—the ‘‘end result’’15—

is likely what is most important to

investors.16 Under the Hope

standard, ‘‘[i]t is not theory but

the impact of the rate order which

counts.’’17

U tility commissions

necessarily have

discretion, consistent with their

statutory authorization, to revise

regulatory policies and

procedures. Thus, for example,

commissions can typically decide

whether to use a fully forecasted

test year, a partially forecasted

test year, or a fully historic one; a

test year can be adjusted for

attrition and/or known and

measurable changes in costs. The

comprehensive state-level

regulation of electric utilities is

based on a regulatory compact

that provides an economic

framework that supports major

capital investments in assets with

very long useful lives. If utility

price signals are more efficient

when a more cost-reflective test

year is used, for example,

regulatory policies can be

adjusted to accomplish this,

consistent with the commission’s

statutory authority. The purpose

of this section is to review several

regulatory approaches that can be


considered ‘‘standard’’ public

utility regulatory methods

and that may be especially well

suited to meeting current

challenges.

A. FERC formula-rate

transmission ratemaking

Formula-based approaches—

and other regulatory building

blocks—can be used to set just

and reasonable rates, based on

prudently incurred costs. The

FERC’s formula rate approach is a

useful example of how to achieve

timely rate recovery, while

maintaining traditional

regulatory oversight of utility rate

levels. The FERC’s approach

relies crucially on applying FERC

Form 1 data in a formula-based

ratemaking approach. Some of

these formula-rate plans use

prior-year FERC Form 1 data to

calculate rates for the upcoming

year, while other plans use

projected rates, which are then

trued up when actual costs are

known, with over-collections

returned to customers with

interest.18


FERC’s approach has a number

of advantages including:

� Keeping rates at levels that are

close to the cost of service. This

largely avoids the possibility of

‘‘overearning’’ by the utility.

Rates are maintained at cost-

based levels, without the need for

frequent full-blown rate cases.

This is a sharp contrast to the

FERC ratemaking approach for

gas pipelines, where gas pipelines

can ‘‘over-earn’’ for extended

periods of time (paid for by

electric utilities and gas local

distribution company customers,

among others), with the FERC

staff only investigating if the

earned ROE is over 20 percent.19

� Accommodating various types

of incentives. Various types of

incentives can be accommodated

within the FERC’s framework.

Orders 679 and 679-A established

the procedures by which electric

transmission owners can receive

incentive-based rate treatment.20

Under FERC Order 679,

incentives available to

jurisdictional public utilities

include ROE incentives, CWIP in

rate base with a cash return,

hypothetical capital structure,

accelerated depreciation,

recovery of costs of abandoned

facilities, and deferred cost

recovery. FERC’s various

incentive measures typically

garner more attention than does

its formula rate approach.

� Credit quality. Credit quality

is a statutorily required criterion

in FERC’s determination of a

formula-rate plan.21 FERC has,

example, considered Westar’s

‘‘BBB-’’ credit rating when



A

approving formula rates,22 an

example of a regulatory

commission using its discretion to

support a utility whose credit

rating was on the verge of

dropping below investment

grade.23 The FERC’s formula rate

approach can incorporate

accelerated depreciation for

ratemaking purposes, CWIP in

rate base with a cash return, and

an asset tracker approach, all of

which can support a utility’s

credit standing.

� Inflation adjustments.

Standard ratemaking practice

makes use, in a variety of ways, of

inflation adjustments to actual

costs. Whether it is an attrition

adjustment, use of a fully

forecasted test year, projections of

variable costs, a formal price-cap

(inflation minus an x-factor) plan,

or some other regulatory use of an

inflation adjustment, standard

practice accommodates

ratemaking adjustments based on

anticipated inflation. Adjustment

mechanisms, such as FERC’s

formula-rate approach, can build

in true-ups of projected and actual

costs.

� Administrative efficiency.

FERC has a large and diligent

accounting and auditing staff and

thus can be assured that the FERC

Form 1 data is accurate and

reliable. Thus, FERC’s formula-

rate approach can be

implemented in an

administratively efficient way.

FERC regulates a large number

of transmission entities, and, to

prevent a logjam, needs to have

administratively workable

ratemaking procedures in place.

ug./Sept. 2011, Vol. 24, Issue 7 1040-6190/$–

Nevertheless, the timing and

procedural protocols provide

enough time for interested parties

to review the data filed by the

transmission entity and to submit

information requests.24

S tate commissions regulate a

smaller number of

companies, but the rate-case-

every-few-years paradigm may

currently not work well in all

instances. Among other things,

state commission administrative

resources are constrained in an

era of tight budgets. Most states

commissions have ‘‘annual

report’’ filing requirements, akin

to the FERC Form 1, which would

accommodate the use of a

formula-rate approach.

B. Con Ed distribution rate

settlement

Rate settlements or stipulations

are a standard part of the

procedural repertoire used to

conduct public utility rate

regulation. Settlements are a way

to forge consensus on issues that

would otherwise have to be

decided by the regulator, based


on a divided record. Thus,

settlements have a useful role to

play.25

Con Ed has, in recent years,

borne a cap ex budget of well over

$1 billion dollars per year, which

is aimed at investing in

distribution infrastructure

needed to meet its obligation to

serve. The Con Ed settlement

‘‘hardwires’’ a three-year cap ex

program of roughly $1.4 billion

per year into a three-year rate

plan, with rate increases of

$540.8 million, $306.5 million, and

$280.2 million, respectively.26 The

New York commission has an ex

ante cap ex review process in

place, which may accommodate

more timely ratemaking

treatment of infrastructure

investment.

W ith settlements, one does

not necessarily know all of

the tradeoffs involved, only the

end result. In some contexts,

settlements can make the

ratemaking process less

transparent because the

commission may not rule, for

example, on what it believes to be a

reasonable capital structure and

cost of equity and thus a

stipulation can become opaque, a

black box. That need not be the

case however and, indeed, is not

the case with Con Ed. Integrating a

three-year cap ex program into the

setting of rates for those years

provides an opportunity to raise

rates in a stable and predictable

way, rather than rely on one-time

adjustments via occasional full-

blown rate cases. Con Ed’s three-

year cap ex rate plan provides a

good ratemaking model, as does



18

the settlement process used to

achieve that outcome.

C. Peoples Gas pipe

replacement tracker

A well-designed and

implemented asset tracker for

qualified infrastructure

investments benefits customers.

The basic idea would be to

recover the costs of ‘‘qualified’’

infrastructure investments

incurred between rate cases

through an asset tracker. The

definition of qualified

investments varies. For example,

the definition for The Peoples Gas

Light and Coke Company

(‘‘Peoples Gas’’) infrastructure

cost recovery charge (ICR charge)

focuses on qualified additions

associated with replacing aged

facilities that have not previously

been included in rate base.27

Under an alternative approach

used in New Jersey,28 job creation

and economic impact are the main

criteria used to target cost

recovery on an expedited basis.29

A definition of ‘‘qualified’’

infrastructure investments might

include capital expenditures that

benefit many customers, are

relatively large in size, and that go

beyond the ordinary expansion of

distribution facilities.

T he Peoples Gas ICR charge

was implemented in the

context of a desire to ensure

timely replacement of aging and

possibly unsafe gas

infrastructure. Further, the tariff

notes that there is a savings of

$6,000 per mile from abandoning

aged cast iron pipe.30 Actual


savings are reconciled to this

estimate every three years. Hence,

the program was implemented as

an incentive for what was

considered to be a desirable

investment from safety,

reliability, and economic

perspectives.

An infrastructure recovery

mechanism, or asset tracker, is

attractive from a public policy

perspective for numerous

reasons.

� Accommodate more timely

recovery of new plant costs. By

ensuring timely recovery, a

tracker may make timely

investment in facilities more

feasible. Rates would ordinarily

go up in conjunction with

capital expenditure completion

and commercial operation

but that would be accomplished

in a relatively stable and

predictable fashion given the cap

ex review process. An asset

tracker can be implemented in

conjunction with CWIP in rate

base with a cash return, which

would further accelerate and

smooth rate impacts. In terms of

rate stability, if some AFUDC


accruals can be avoided or

minimized, that would help keep

rates low.

� Support financial integrity. An

asset tracker can support a public

utility’s ability to raise new

capital, thereby easing the

financing of capital expenditures.

Over time, this would tend to

improve credit quality and benefit

customers via a lower cost of

capital.

� Administrative safeguards.

Procedures could be put in place

to ensure that the commission has

the timely opportunity—and

necessary information—to ensure

that the asset tracker is working as

intended, thereby benefiting

customers. For example, Peoples’

internal auditors must certify

each year that the ICR has been

properly implemented, and there

must be an independent external

review every five years.31

The Peoples asset tracker

mechanism, which places assets

into rates in a timely matter, but

leaves most of the review process

to the reconciliation stage of the

case, provides a reasonable

ratemaking model. Other

approaches can, of course, be

used as well. The Peoples Gas

Rider ICR mitigates regulatory

lag for qualified capital

expenditures. Rather than

spending and then waiting for

commission approval to recover

the costs, the utility is afforded the

opportunity to spend, recover,

and then wait for a retrospective

prudence review.

From a credit quality

standpoint, however, the

regulatory implementation of the



[(Figure_5)TD$FIG]

0

10

20

30

40

50

60

70

80

20102009200820072006200520042003200220012000Year

Num

ber

of R

ate

Cas

es F

iled

Source: Regulatory Research Associates

Figure 5: Number of Rate Cases Filed, 2000–2010

A

Peoples Gas ICR has a major

drawback. The mechanics of the

Peoples Gas infrastructure tracker

are sound, but the ‘‘quasi-debt’’

rate allowed for Rider ICR assets

may effectively prevent Peoples

Gas from improving its credit

quality, at a time when it must

raise new capital to fund cap ex

programs. Providing only a quasi-

debt return implies that the

‘‘tracked’’ assets require a lower

allowed ROE than non-tracked

assets, but the cost of capital is a

function of the use to which it is

put and is not a function of the

specific rate treatment provided

those assets.32

P roviding only a quasi-debt

return makes it more

difficult for the company to

maintain the coverage ratios

needed to maintain or improve its

credit rating. Peoples Gas had lost

it’s ‘‘A-’’ credit rating from S&P (it

has an ‘‘A3’’ rating from

Moody’s) following its previous

rate case, with those lower ratings

affirmed subsequent to the

February 2010 rate case decision.

In explaining its downgrade, S&P

noted that its assessment was

based, in part, on its ‘‘assessment

of the Illinois regulatory

environment which we place in

the least credit supportive

category.’’33 This rate case did not

put Peoples Gas back on the road

to meriting an ‘‘A-’’ credit rating.

It is a mistake to view an asset

tracker in isolation—credit rating

agencies generally focus on the

regulatory compact in the state

not on relatively narrow aspects

of ratemaking procedure—and

thus this aspect of the February

ug./Sept. 2011, Vol. 24, Issue 7 1040-6190/$–

2010 Peoples Gas rate case order

represents a missed opportunity

to enhance the utility’s ability to

raise debt at a low cost.

V. Traditional RateCases and the RegulatoryBuilding Blocks

While ratemaking procedures

will vary on a state by state, case

by case basis, regulators’ primary

regulatory ‘‘tool’’ for overseeing a

utility’s tariffed rates is the

traditional rate-of-return/cost-of-

service rate case, which provides

the regulator with a forum for

investigating and determining the

justness and reasonableness of the

utility’s rates and the prudence of

its capital and operating costs.

Figure 5 shows that rate case

activity surged during the

middle- to late-2000s following a

period of relative inactivity

during the late 1990s and early

2000s.34 Through June 30, 2011, 39

rate cases have been filed

compared to a total of 60 for

2010.35 Using a ‘‘test year’’


revenue requirement, the

regulatory agency examines the

reasonableness of the utility’s

sales growth projections, rate

base, operating expenses, cost of

capital, and other cost

components, and then sets rates

that provide the utility a

reasonable opportunity to recover

its prudently incurred costs—this

is the core of the traditional public

utility ratemaking regulatory

bargain.

A regulator’s ability to

disallow imprudently

incurred costs provides crucial

regulatory oversight over the

utility’s management of its

operations. A utility’s costs are

held to a ‘‘reasonableness’’

standard, not an ‘‘ideal’’ standard

of perfection or optimization. In

setting rates that are just and

reasonable, the required

ratemaking approach is to

provide the utility with an

opportunity to recover the

prudently incurred costs

(including a fair rate of return on

capital) of providing utility

services to customers. In



20

examining the prudence of a

utility’s costs, the regulator

considers the costs in relation to a

‘‘reasonable man’’ standard—the

costs must be reasonable in

comparison to the costs that

would result from reasonable

utility practice. Any prudence

determination should be based on

whether the decisions at the time

they were made were reasonable

under the then existing

circumstances. For a utility,

prudence is reflected in the

decision a reasonable utility

management would make at the

time the decision is required, and

must remain free of any

hindsight. If a prudent decision

turns out badly, the bad outcome

does not by itself demonstrate a

lack of prudence.36 Fairness

requires that any imprudence be

demonstrated objectively so that

there will not be uncertainty

about the regulatory decision.

Evidence of failure to act

prudently must be well grounded

in law, economics, and public

policy.

S ome prudently incurred

costs (e.g., charitable

contributions,37 executive

incentive compensation, and

advertising expenses) are

frequently excluded from a

utility’s revenue requirement,

even if they are legitimately

incurred costs. Prof. Alfred E.

Kahn, when he was chairman of

the New York State Public Service

Commission, expressed the view

that ‘‘heated discussions’’ about

advertising ratemaking policy

were a ‘‘tempest in a teapot,’’ both

because the dollars were small


and because disallowing

advertising expenditures under

the ‘‘glib assumption that these

costs will then be borne by

stockholders rather than

ratepayers, is something of a

sham.’’38 Prof. Kahn went on to

explain that the:

[E]ssential fraudulence of our

purporting to exclude from rates

expenditures for advertising that

company managements will con-

tinue to feel it necessary to make:

since we made every effort to set

the allowable return on equity at

the minimum cost of capital, and

most of the companies we regulate

are not earning even that, in

principle putting any advertising

expenditures ‘below the line’ can

only mean, if we are honest,

increasing the allowed return on

equity, in order to enable these

companies to raise the capital they

need on reasonable terms.39

This problem could be

addressed directly, by revisiting

commission policies and

precedent on the ratemaking

treatment of these costs.

Unfortunately, however, this

rarely occurs, which makes a

direct solution to the problem


difficult to achieve. The

regulatory approaches described

in this paper do not solve this

problem, but would provide an

indirect way to deal with the

attrition problem, large cap ex

programs, and bond ratings that

are weak by historical standards.

VI. Conclusion

The standard approaches

described in this article can be

used to meet the challenges that

the electric utility industry

currently faces. While the details

of utility regulation in the state are

no doubt important, there are a

variety of regulatory policies and

mechanisms that can be used to

set utility rates. Regulatory

approaches which might not be

viewed as quite as favorable to

investors, might, in practice, be

well-suited to the specific

situation in a given state and

therefore be considered to be

acceptable. It is the end result that

matters when regulatory

institutions apply the regulatory

compact.

Utilities must have incentives

that lead them to maximize

customer benefits—so that

customers receive efficient, safe,

adequate, and reliable service

both now and in the future. A

utility’s economic incentives will

be better when rates to customers

reflect the utility’s true cost of

providing service.

� Allocative efficiency refers to

the prices that customers face.

Allocatively efficient utility rates

would give customers the



A

economically correct price signals

to use electricity or gas or not,

depending on the customer’s

choice. Failure to allow

appropriate costs to be included

in the utility revenue requirement

distorts this efficiency, since

customers are receiving an

inaccurate price signal.

� Productive (or technical)

efficiency refers to the incentives

that the utility faces as it decides

how to provide its services. The

utility should have the incentives

to operate in an efficient manner,

while also continuing to provide

safe, adequate, and reliable

service. With appropriate

incentives in place, few if any

costs should be excluded from the

utility’s tariffed rates—the utility

will be focused on fulfilling its

obligations to its customers.

� Investment incentives are the

dynamic aspect of productive

efficiency. The utility must have

the incentive to efficiently invest

in infrastructure. An inability to

recover its costs could distort the

utility’s investment incentives.

Where credit quality concerns

remain a significant deterrent to

utility investment in

infrastructure on behalf of

customers, ratemaking treatments

that provide more timely and

regular recovery of costs may

prove useful.&

Endnotes:

1. Utility regulation may, in part, be a‘‘method of promoting the expansionof infrastructure services.’’ Richard A.Posner, Taxation by Regulation, BELL J.ECON., Spring 1971, at 39–41.

ug./Sept. 2011, Vol. 24, Issue 7 1040-6190/$–

2. Title XIII of the EnergyIndependence and Security Act of2007 (‘‘EISA07’’) declares that ‘‘it is thepolicy of the United States to supportthe modernization of the Nation’selectricity transmission anddistribution system to maintain areliable and secure electricityinfrastructure that can meet futuredemand growth’’ and ‘‘achieve [the 10items], which together characterize aSmart Grid.’’ At 292–293.

3. Robert L. Hahne and Gregory E.Aliff, ACCOUNTING FOR PUBLIC UTILITIES

(Newark, NJ: Matthew Bender, 2001),at 8–3.

4. U.S. Energy InformationAdministration, Renewable PortfolioStandards and State Mandates byState, 2008, Aug. 2010, at http://www.eia.gov/cneaf/solar.renewables/page/trends/table28.html.

5. See Leonard Hyman, AMERICA’S

ELECTRIC UTILITIES: PAST PRESENT AND

FUTURE, 2nd Ed. (Arlington, VA: PUR,1985), at 263. See also Leonard Hyman,A.S. Hyman, and R.C. Hyman,AMERICA’S ELECTRIC UTILITIES: PAST

PRESENT AND FUTURE, 8th Ed. (Vienna,VA: PUR, 2005), at 432. For recent data,see Edison Electric Institute, QuarterlyFinancial Updates, various dates.

6. Leonard Saul Goodman, THE

PROCESS OF RATEMAKING, Vol. I (Vienna,VA: PUR, 1998), at 638.

7. Robert Burns, Mark Eifert and PeterNagler, Current PGA and FAC Practices:Implications for Ratemaking in


Competitive Markets, NationalRegulatory Research Institute, Nov.1991, at 9.

8. These accounts are firmlyembedded within the practices of theaccounting profession in the U.S. andare not capable of being amended orchanged, as a practical matter, withoutthe scrutiny and approval of the U.S.accounting profession’s standardsboard.

9. Outside the U.S., many regulatoryjurisdictions still lack access to reliableand useful accounting data.

10. RRA, Construction Work inProgress: A State-by-State PolicyOverview, April 7, 2009, at 1–2.

11. Adjustment mechanisms mayhave been unusual in 1918, when thePennsylvania Public ServiceCommission characterized them assuch, but they are not unusual today.See R.S. Trigg, Escalator Clauses inPublic Utility Rate Schedules, UNIV. OF

PENN. LAW REV., May 1958, at 964.

12. RRA goes on to summarize thepolicy rationale for including CWIP inrate base, explaining that: ‘‘[i]nclusionof CWIP in rate base is generallyviewed favorably by investors. Suchtreatment allows the utility to collect acash rate of return on the asset while itis under development. The associatedcash flow may reduce the amount ofutility financing necessary during theconstruction program and enable autility to receive more favorableconsideration from the credit-ratingagencies, thus reducing the utilitiescost-of-capital going forward.Additionally, since including CWIP inrate base effectively ‘phases in’ therelated investment, such treatmentwill reduce the ‘rate shock’ that mightotherwise be experienced by theratepayer when the plant or project iscompleted and placed into service andthen reflected in rates in one step.’’RRA, supra note 10, at 1.

13. Id., at 1–2.

14. For a 50-state survey of RPSstandards, see American BarAssociation, Report of the RenewableEnergy Committee, Section of PublicUtility, Communications andTransportation Law, Spring 2011.


http://www.eia.gov/cneaf/solar.renewables/page/trends/table28.html





22

15. Per Hope, under the ‘‘just andreasonable’’ standard, ‘‘it is the resultreached not the method employedwhich is controlling.’’ 320 U.S. 591(1944).

16. See Wayne P. Olson, At aCrossroads: Modernizing UtilityInfrastructure in a Tough CreditEnvironment, ELEC. J., Aug./Sept. 2009,at 6–26.

17. Hope, supra note 15.

18. Public Service Electric and GasCompany (PSEG), 123 FERC P 61303,2008 WL 4416764 (FERC), Sept. 30,2008.

19. Of the five most recent FERC rateinvestigations, the lowest earned ROEwas 20.83 percent for Great LakesTransmission. This leads to theconclusion that the effective thresholdto warrant investigation by the FERCwas about 20 percent.

20. Promoting Transmission Investmentthrough Pricing Reform, Order No. 679,FERC Stats. & Regs. � 31,222 (2006)(‘‘Order No. 679’’); order on reh’g,Order No. 679-A, FERC Stats. & Regs.� 31,236 (2006) (‘‘Order No. 679-A’’);order denying reh’g, 119 FERC � 61.062(2007).

21. 16 U.S.C. 824s (2006). Section 219of The Energy Policy Act of 2005, 119Stat. § 594 1241 (2005), amended theFPA. Specifically, § 824s specifies,among other things, that the FERCtransmission infrastructureinvestment rule shall promotereliable transmission and generationby ‘‘promoting capital investment’’in transmission infrastructureand provide an allowed returnon equity that ‘‘attracts newinvestment in transmission facilities.’’See http://www.law.cornell.edu/uscode/16/usc_sec_16_00000824—s000-.html.

22. Westar Energy, Inc., 122 FERC �61,268 (2008), Para. 47.

23. Olson found that ‘‘there isconsiderable evidence that the rateorders for ‘‘BBB-’’ utilities pay carefulattention to credit quality when settingrates.’’ Olson, supra note 16, at 17.

24. PSEG, supra note 18.


25. Zhongmin Wang, Settling UtilityRate Cases: An Alternative RatemakingProcedure, J. REGULATORY ECON., 26:2,2004, at 141–163.

26. Before the New York PublicService Commission, Proceeding onthe Motion of the Commission as tothe Rates, Charges, Rules andRegulation of Consolidated EdisonCompany of New York, Inc. forElectric Service, Order EstablishingThree-Year Electric Rate Plan, Case09-E-0428, Mar. 26, 2010, at 3,10–15.

27. Peoples Gas, Rider ICR,Infrastructure Cost Recovery, Ill.C.C.No 28, Fifth Revised Sheet No. 130,Feb. 17, 2010.

28. Before the New Jersey Board ofPublic Utilities, In the Matter of theProceeding for InfrastructureInvestment and a Cost RecoveryMechanism for all Gas andElectric Utilities, Decision and OrderApproving Stipulation, Docket No.EO09010049, April 28, 2009, at 3,10–15.

29. New Jersey’s economic stimulusplan, which sought to moderate theeffects on New Jersey of the worldeconomic downturn that followed the2008 financial crisis, continues inoperation, with companies required tofile quarterly compliance reports. See,for example, South Jersey Gas, CapitalInvestment Recovery TrackerQuarterly Report in Compliance withthe Board’s Order in Docket No.GO09010051, May 2, 2011.


30. Peoples Gas, supra note 27, at 8.

31. Peoples Gas, supra note 27, at 9.

32. Richard Brealey and StewartMyers, PRINCIPLES OF CORPORATE

FINANCE, 1st Ed. (New York: McGraw-Hill, 1981), at 158.

33. S&P, ‘‘Peoples Gas Light & CokeCo.,’’ Mar. 18, 2009, at 2.

34. During the 1990s, rates werefrozen in a number of jurisdictionsbecause of settlements and litigatedproceedings related to mergers,alternative rate plans, and theintroduction of retail competition. SeeHethie Parmesano and Jeff D.Makholm, The Thaw: The End ofthe Ice Age for American Utility RateCases—Are You Ready? ELEC. J., July2004, at 69.

35. Regulatory Research Associates, athttp://www.snl.com/InteractiveX/RateCaseHistory.aspx.

36. When challenging the prudence ofmanagement on the basis of a badresult, care is needed because theregulatory agency already has onepiece of information that utilitymanagement did not, and couldnot, have at the time the decisionwas made. The evaluation ofprudence must be based on what areasonable utility would have knownat the time the costs were beingincurred, not based on 20/20hindsight, long after the costs wereincurred.

37. The Economist, in a specialsupplement on precisely this issue,points out that ‘‘for strictly selfishreasons, well-run companies willstrive for friendly long-term relationswith employees, suppliers andcustomers. There is no need for selflesssacrifice when it comes tostakeholders. It goes with theterritory.’’ The Good Company,ECONOMIST, Jan. 22–28, 2005, at 11.

38. Prof. Alfred Kahn as quoted inRichard Pierce, Jr., Gary Allison andPatrick Martin et al., ECONOMIC

REGULATION: ENERGY, TRANSPORTATION

AND UTILITIES (New York: Bobbs-Merrill, 1980), at 142.

39. Id.


http://www.law.cornell.edu/uscode/16/usc_sec_16_00000824---s000-.html



http://www.snl.com/InteractiveX/RateCaseHistory.aspx

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Targeting Attrition: Some Familiar Ratemaking Tools

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