DCOS Perspectives: The Future of Electric

Distribution Cost of Service
(DCOS) Perspectives—The
Future of Electric Distribution
Darryl Tietjen
Public Utility Commission of Texas
Southwest Electric Distribution Exchange Conference
April 27, 2011
Purpose of this presentation is to:
Provide a quick and general overview of
traditional rate regulation and the ratemaking
Discuss recent and emerging regulatory and
legislative developments in the recovery of
distribution-related costs and investments
Provide a quick and general overview of
traditional rate regulation and the ratemaking
Discuss recent and emerging regulatory and
legislative developments in the recovery of
distribution-related costs and investments
Traditional Cost Recovery for Regulated
Investor-Owned Utilities
In Texas, Sec. 36.051 of the Public Utility Regulatory
Act (PURA) states that:
“In establishing an electric utility’s rates, the regulatory
authority shall establish the utility’s overall revenues at
an amount that will permit the utility a reasonable
opportunity to earn a reasonable return on the utility’s
invested capital used and useful in providing service to
the public in excess of the utility’s reasonable and
necessary operating expenses.”
 PURA provides a reasonable opportunity for a utility to
earn its authorized return but does not provide a
guaranteed level or rate of return.
What Triggers A Utility Rate Case?
Earned return is too low
The utility company initiates a rate case
Earned return is too high
PUCT Staff reviews annual PUC Earnings Monitoring
Reports and makes recommendation to the
Commission to require a company to file a rate case
 Intervenor group files petition to initiate a rate case
What is “Cost of Service”
In Cost-of-Service regulation, the regulator determines the Revenue
Requirement—i.e., the “cost of service”—that reflects the total
amount that must be collected by the utility so that it can recover its
costs and earn a reasonable return.
Basic ratemaking formula:
Rate Base
x Allowed Rate of Return
= Required Return $$
+ Operating Expenses
= Cost of Service (Revenue Requirement)
Basic Issues in Rate Proceedings
Regulated Rates are essentially made up of the
following basic components:
 Return on investment through rate of return on
invested capital
 Return of investment through recovery of
depreciation expense
 Recovery of reasonable and necessary expenses
 Recovery of taxes
 Recovery of reasonable fuel expenditures (for
vertically integrated companies)
Overall Objectives of the
Ratemaking Process
Develop the utility’s revenue requirement (i.e., the
utility’s reasonable cost of service)
Design rates to recover cost of service
Cost of Service study is developed to allocate the utility’s
revenue requirement to various customer classes (e.g.,
residential, commercial, industrial)
Rates are designed to recover the utility’s revenue
requirement from the various customer classes
 These steps constitute a conceptually simple process, but
in practice, a comprehensive rate case is typically a massive
undertaking with regard to the effort and volume of
information necessary to complete the process.
The Rate Filing Package
Prepared Testimony
A Rate Filing Package (RFP) must be
accompanied by the applicant’s prepared
Topical and relevant issues related to the electric and
energy industry
 Economic issues
 Accounting and Finance
 Legal and regulatory issues and analysis
 Engineering issues
The Parties
Utility (applicant)
Involved parties may be friends or foes of the utility
 Could include customer groups, rate/consumer
advocates, other utilities, competitors
Commission Staff
Basic COS Component: Rate Base
The Rate Base is the net amount of investment, funded by
investors, in utility plant and other assets devoted to the
rendering of utility service upon which a reasonable rate of
return may be earned.
Plant in Service is the largest component of a company’s rate base
 Generally, it is one of the least controversial aspects of a rate
proceeding unless the prudence of construction is an issue or
excess capacity is at issue
Materials and supplies
Cash Working Capital
For vertically integrated utilities, Rate Base includes fuel
inventories consisting of gas in storage, coal, and nuclear fuel
Criteria for Inclusion of Cost
in Rate Base
“Used and useful” concept – only plant currently
providing or capable of providing utility service to
customers is included in rate base
“Prudent investment” concept – only plant prudently
purchased or constructed is includable in rate base
Construction of nuclear generation plants in 1980s led to
state commission prudence reviews of construction
management and costs associated with construction of
nuclear facilities. In some cases, these prudence reviews led
to disallowance of plant costs for ratemaking purposes
Prudence disallowance of transmission and distribution
investment rarely, if ever, occurs.
Basic COS Component: Rate of Return
The Rate of Return is the percentage rate that the PUC finds should
be earned on the rate base in order to cover the costs related to the
financing provided by the company’s capital investors.
What is meant by the phrase “allowed rate of return”?
In the utility industry, the phrase “allowed rate of return” is
generally synonymous with “the cost of capital.” It refers to the
rate of return on rate base required to recover the utility’s:
 Costs of common stock, long-term debt, and preferred stock
The total dollar amount of return, which includes earnings, is
calculated by multiplying the allowed rate of return by the utility’s
total dollar amount of rate base.
The Commission-authorized Rate of Return can be considered as
the rate of return that is permitted, but not guaranteed.
Basic COS Component: Operating
Allowable Operating Expenses include operation and
maintenance costs (O&M), depreciation, and all taxes,
including income taxes.
O&M expense includes:
Power production expenses
Transmission expenses
Distribution expenses
Customer accounts expenses
Customer service and informational expenses
Sales expenses
Administrative and general expenses
Operating Revenues and Expenses
Requirements for inclusion of costs in revenue
Costs must be just and reasonable
 Costs must be prudently incurred
 Cost adjustments must be known and measurable
Test-Year Concepts
Identification of test year
Historical test year – generally based on financial
data for the most current 12 months for which
information is available during the preparation of the
rate application
In some circumstances, forecasted test years may be
used—for example, the new CREZ utilities in Texas will
likely use forecasted test years
The use of historical test years is far more common
than the use of forecasted or prospective test years.
To summarize the “cost of service”
one more time…
In Cost-of-Service regulation, the regulator determines the Revenue
Requirement—i.e., the “cost of service”—that reflects the total
amount that must be collected by the utility so that it can recover its
costs and earn a reasonable return.
Basic ratemaking formula:
Rate Base
x Allowed Rate of Return
= Required Return
+ Operating Expenses
= Cost of Service (Revenue Requirement)
Quick Overview of Allocation of Costs
After the utility’s revenue requirement is
established, the next steps are to:
 Allocate revenue requirements to customer
 Structure and design rates to recover revenue
Rate = Cost/Billing Determinants
Develop supporting schedules and file final
Rulemaking Activities at the PUC
PUC Subst. R. 25.192—(the “Interim TCOS” rule)
This rule allows transmission service providers to update
their transmission rates twice per year to reflect the return
on and of new transmission investment (along with
related taxes); it does not include any adjustments to
 PURA 35.004(d) provides specific statutory authorization
for recovery mechanisms for transmission investment:
“…the commission may approve wholesale rates that may be
periodically adjusted to ensure timely recovery of transmission
Streamlined Recovery of Distribution
Utility companies have for many years been
seeking a similar type of streamlined recovery
mechanism for distribution investment.
For transmission and distribution utilities, about
2/3 of their rate base, on average, is related to
For the state’s two largest utilities—Oncor and
CenterPoint—that translates to over $5 billion and
about $2.5 billion, respectively.
Streamlined Recovery of Distribution
The critical question is:
Does PURA authorize the type of recovery for
distribution investment that it does for
transmission investment?
Therein lies the proverbial rub….
PUC Rulemaking on Distribution
Cost Recovery Factor (DCRF)
In May 2010, Commission Staff opened a
rulemaking project to develop a DCRF mechanism
that would be similar to the existing interim TCOS
recovery mechanism.
While parties in the rulemaking contested many
issues relating to such a mechanism, the central
point of controversy was:
Is a mechanism for streamlined recovery of distribution
costs legal?
PUC Rulemaking on Distribution
Cost Recovery Factor (DCRF)
In December 2010, based on comments from
parties in the rulemaking, Staff submitted to the
Commissioners a Proposal for Adoption.
Under Staff’s proposal, the basic operation of the
DCRF would have been similar to that of the
interim TCOS rule—it would have allowed utilities
to make streamlined filings requesting updated rates
reflecting a return on and of distribution investment.
After considering Staff’s Proposal for Adoption, the
PUC Rulemaking on Distribution
Cost Recovery Factor (DCRF)
….declined to adopt the rule.
One commissioner (Chairman Smitherman) stated that
he did not believe that the mechanism contemplated in
the proposed rule was legal under existing statute.
Two commissioners (Commissioners Nelson and
Anderson) stated that they believe the PUC already has
the statutory authority to adopt such a rule, but opted
to give the Legislature an opportunity to address the
issue and pass a bill if deemed necessary or for statutory
clarification purposes.
PUC Rulemaking on Distribution
Cost Recovery Factor (DCRF)
At the present time, the Commission still does
not have a rule or mechanism that provides for
streamlined recovery of distribution-related
Is there really a need for a streamlined
mechanism for distribution costs?
Not surprisingly, the answer to this question is in
the eye of the beholder…..
Is there really a need for a streamlined
mechanism for distribution costs?
Utility companies say:
the current regulatory ratemaking paradigm is outdated and stale,
and does not reflect current market and industry conditions.
Providing for streamlined recovery of investment in distribution
infrastructure reduces uncertainty about cost recovery and
enhances economic incentives for additional distribution
The existing ratesetting process is bloated, inefficient, and costly.
For example, in CenterPoint’s recent base-rate proceeding, parties
submitted over 2,000 requests for information (in addition to the
info in the nearly 7,000 pages included in CNP’s initial filing).
Is there really a need for a streamlined
mechanism for distribution costs?
Intervenor/ratepayer groups say:
Utility companies are attempting to circumvent appropriate
regulatory scrutiny and push through rate increases quickly without
allowing affected parties a reasonable opportunity for review.
Limited-issue rate adjustments constitute “piecemeal” ratemaking.
Even though some regulatory lag may exist with regard to recovery
of distribution investment, that is not necessarily a bad thing, as
regulatory lag is a natural (and in fact desirable) part of regulation.
The utilities’ goal is to create a regulatory system in which
comprehensive rate cases became a thing of the past and the
traditional checks and balances (such as regulatory lag) in the
ratesetting process are no longer meaningful.
Adventures in Legislation—Current
Legislative Bills
Senate Bill (SB) 1693 and House Bill (HB) 3610:
these bills are referred to as the “PRA” bills (Periodic
Rate Adjustments); they were originally filed as
identical companion bills, and they provide explicit
statutory authority for the implementation of a
streamlined distribution-related cost-recovery
 Passage of either of these bills would definitively
eliminate the intervenors’ principal argument against
implementation of such a mechanism—that it is illegal.
SB 1693 and HB 3610
These legislative bills:
 Provide for streamlined PUC proceedings that would
authorize recovery of and on new distribution investment,
along with related taxes.
 Do not provide for recovery of expenses (same as interim
TCOS rule), but latest version of SB 1693 does provide that
rates may be adjusted based on changes in distributionrelated “intangible plant” (e.g., software for outage
management systems) and “communication equipment and
networks” (e.g., smart grid infrastructure).
 SB 1693 provides that the PUC may determine in either the
PRA filing or the utility’s next full rate proceeding that the
investments were prudent, reasonable, and necessary.
SB 1693 and HB 3610
These bills also:
 Would apply to both ERCOT and non-ERCOT (still
vertically integrated) utilities.
 Provide for municipalities’ continued original jurisdiction
over a utility’s rates (with PUC having appellate jurisdiction,
as it has currently).
 Provide for rate updates on an annual basis (SB 1693 limits
utilities to four PRA increases between full rate cases).
SB 1693 and HB 3610
These bills also:
 Provide that new rates resulting from the PRA should
reflect the effects of any increases in base-rate revenue
resulting from load growth.
 SB 1693 provides that PUC rules shall require utilities
to file earnings reports that allow the PUC or regulatory
authorities to determine whether the utility is overearning.
 SB 1693 has a six-year sunset provision (the law would
expire August 31, 2017).
PUC Rulemaking—Subsequent to
Passage of Legislative Bill
Many legislative bills (such as the PRA bills)
specifically require the PUC to adopt rules that
establish the specific procedures and details
pursuant to implementing the provisions of the new
 Once a law is passed, the arguments about some
issues may still not be over, as stakeholders can be
expected in the ensuing rulemaking process to
continue to advocate their interests and argue about
the appropriate interpretation of the new law.
Expectations for the PRA bill(s)….
After all is said and done, the most likely outcome
with regard to the possibility of a PRA type of
mechanism is that a bill will be passed and a rule
will then be adopted, after which the utilities will
have available for their distribution investment a
recovery mechanism that is essentially the same as
that for transmission investment.
 Specifically, utilities in Texas will be able to more
efficiently and timely recover and earn a return on
distribution-related investment.
Darryl Tietjen
Director, Rate Regulation Division
Public Utility Commission of Texas