Oversight and Safety Division
Gas Services
September 2017
Natural Gas
Rate Review
Handbook
Railroad Commission of Texas
Christi Craddick, Chairman
Wayne Christian, Commissioner
Jim Wright, Commissioner
Table of Contents
INTRODUCTION ...................................................................................................................... 1
A. Purpose of Regulation ........................................................................................................ 1
B. Explanation of Packet Layout ............................................................................................ 2
C. Frequently Asked Questions .............................................................................................. 2
Chapter I. JURISDICTION AND PROCEDURES ....................................................... 7
Section 1 - Jurisdiction ...................................................................................................... 7
Section 2 - Procedures at the City Level ............................................................................ 7
A. Statement of Intent ................................................................................................ 8
B. Notice ..................................................................................................................... 8
C. Disposition ............................................................................................................. 9
D. Hearing ................................................................................................................. 10
E. Environs Rates ..................................................................................................... 10
F. Jurisdiction over Gas Utility Rate Cases.............................................................. 12
Chapter II. OVERVIEW OF RATE REGULATION ................................................... 13
Section 1 - Rate Regulation - A Summary ....................................................................... 13
A. Rate Base ............................................................................................................. 13
B. Cost of Capital ..................................................................................................... 13
C. Operating Costs .................................................................................................... 14
D. Rate Design .......................................................................................................... 15
Chapter III. RATESETTING ......................................................................................... 16
Section 1 - Rate Base ....................................................................................................... 16
A. Test Year .............................................................................................................. 16
B. Invested Capital.................................................................................................... 16
C. Allocation of System-Wide Assets to a Distribution System .............................. 16
D. Current Cost (Reproduction Cost New) ............................................................... 17
E. Other Rate Base Items .......................................................................................... 17
F. Rate Base Summary ............................................................................................. 21
Section 2 - Cost of Capital ............................................................................................... 23
A. Capital Structure .................................................................................................. 23
B. Debt and Preferred Stock ..................................................................................... 24
C. Equity ................................................................................................................... 25
D. Small Utilities ...................................................................................................... 29
E. Attrition and Erosion............................................................................................ 30
F. Additional Sources of Capital .............................................................................. 30
ii
G. Weighted Average (or Composite) Cost of Capital ............................................. 30
Section 3 - Return on Rate Base ...................................................................................... 31
Section 4 - Revenue and Expenses .................................................................................. 32
A. Allocation Among Classes of Consumers ........................................................... 32
B. Revenue ............................................................................................................... 33
C. Expenses .............................................................................................................. 35
Section 5 - Rates .............................................................................................................. 40
A. Revenue Requirement .......................................................................................... 40
B. Rate Design .......................................................................................................... 41
C. Tariffs ................................................................................................................... 41
D. Sample Calculations for Revenue Adjustments ................................................... 43
Chapter IV. BEFORE THE COMMISSION .................................................................. 57
Section 1- Procedures on Appeal from City .................................................................... 57
A. Representation ...................................................................................................... 57
B. Filing of Documents ............................................................................................ 57
C. Motions ................................................................................................................ 59
D. Computation of Time ........................................................................................... 59
E. Postponements, Continuances and Extensions of Deadlines ............................... 59
F. Ex Parte Consultation .......................................................................................... 60
G. Interventions and Prefiled Testimony .................................................................. 60
H. Discovery ............................................................................................................. 60
I. Alignment of Parties ............................................................................................ 60
J. Consolidation ....................................................................................................... 61
K. Stipulations .......................................................................................................... 61
L. Objections to Prefiled Testimony ........................................................................ 61
M. Prehearing Conference ........................................................................................ 61
N. Court Reporter and Transcripts ............................................................................ 61
O. Order of Procedure at Hearing ............................................................................. 61
P. Evidence ............................................................................................................... 62
Q. Objections Made at Hearing ................................................................................ 62
R. Documentary Evidence ........................................................................................ 62
S. Official Notice ..................................................................................................... 62
T. Expert Testimony ................................................................................................. 63
U. Preservation of Excluded Evidence ..................................................................... 63
V. Briefs, Closing Statements, and Reply Briefs ...................................................... 63
W. Late-Filed Exhibits ............................................................................................... 63
X. Proposal for Decision, Exceptions and Replies ................................................... 63
Y. Notification of Open Meeting .............................................................................. 64
Z. Oral Argument ..................................................................................................... 64
AA.Effective Date ..................................................................................................... 64
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BB.Motions for Rehearing ......................................................................................... 64
Chapter V. INTERIM RATE ADJUSTMENT ............................................................. 65
Chapter VI. COST OF SERVICE ADJUSTMENT ....................................................... 68
Chapter VII. GLOSSARY OF GAS UTILITY TERMS ................................................ 71
BIBLIOGRAPHY ...................................................................................... 77
1
INTRODUCTION
This handbook is intended to assist municipalities, consultants, gas utilities and other interested
persons in understanding the principles and procedures involved in natural gas utility rate
regulation. Exercise of judgment is required in resolving the issues surrounding utility rate
requests, and the methodologies set out herein are presented only as possible methods for
resolving the issues identified. The methodologies and suggestions in this handbook by no means
represent Railroad Commission of Texas policy, precedent or a mandate. This handbook is
intended to only provide broad guidance to those that have questions about rate making. Also,
the handbook is not intended as a substitute for advice from your attorney or qualified rate
consultant. Titles 3 and 4 of the current Texas Utilities Code (T
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), and the
Railroad Commission of Texas’ (Commission) Special Rules of Practice and Procedure,
Substantive Rules, and General Rules of Practice and Procedure should be followed if there are
any conflicts between the statutes, the rules and this handbook.
A. PURPOSE OF REGULATION
Regulation of public utilities is intended to operate in lieu of the competitive forces that are
believed to control prices for goods and services provided by most business organizations.
Utilities invest large sums of money at the outset to build the facilities required to serve their
customers. Since a utility's initial capital investment is so high, the existence of competing
utilities would be wasteful and inefficient. That is why utilities are referred to as “natural
monopolies.” Normally, utilities operate most efficiently as monopolies, but with the potential
market abuses of a monopoly.
The Gas Utility Regulatory Act, The Cox Act, and other miscellaneous statutory provisions have
been revised and combined, along with the statutes governing the regulation of electric and
telephone utilities, into a statute referred to as the T
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(T
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Title 3 of the T
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replaces the Gas Utility Regulatory Act and the Cox Act, while
Title 4 replaces the other miscellaneous provisions.
The bill that codified the statutes was drafted by the Texas Legislative Council in 1997. The
process involved reclassifying and rearranging the statutes in a more logical order to make the
statutes more accessible, understandable, and usable. The 75
th
Legislature enacted the bill,
Governor Bush signed it, and it became effective September 1, 1997.
These statutes provide comprehensive regulation of gas utilities in lieu of competition. Each
regulatory authority is empowered by the T
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to enact rules and regulations as
necessary to adequately perform its statutory duty. Commission rules cited in this manual are not
binding upon a municipality when it is exercising its original jurisdiction, but they are applicable
when a case is appealed to the Commission and the municipality is a party to the appeal.
On December 24, 2004, the Commission created a rule (§ 7.7101 of 16 T
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) to
implement T
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, § 104.301 (sometimes referred to as the Gas Reliability
Infrastructure Program or GRIP), which was enacted by the 78th Legislature. These statutory
2
and rule provisions promote investment in infrastructure that will improve the reliability and
safety of the Texas natural gas system. Previously, the only way for a utility to increase its rates
was to file with the regulatory authorities a formal Statement of Intent rate package, including a
comprehensive cost of service rate case. This is sometimes referenced as “traditional” rate
making. The Interim Rate Adjustment (IRA) statute and rule allow a gas utility to apply with the
regulatory authority for an interim adjustment to its base rates to recover the cost of new
infrastructure investment made by a utility since its last comprehensive rate case. When a utility
applies for an interim rate adjustment, it is not required to submit a comprehensive rate package
demonstrating the reasonableness of its cost of service. More details of the IRA requirements are
discussed in a following chapter in this handbook.
B. EXPLANATION OF PACKET LAYOUT
This handbook contains seven Chapters following the Introduction. The first Chapter explains
the legal authority under which a city may act to set natural gas rates, and explains procedural
steps that are appropriate at the city level. The second Chapter provides a broad overview of
ratemaking methodology. The third Chapter also deals with the substance of rate calculation, but
in much greater detail. The fourth Chapter sets out procedures to be followed before the Railroad
Commission in the event that the city's rate setting action is appealed. The fifth Chapter
discusses the specific requirements and particulars of the Interim Rate Adjustment filing that is
an option to the utility. The sixth chapter discusses the use and applicability of Cost of Service
Adjustments (COSA) approved by the Commission. Finally, the seventh Chapter contains a
glossary of terms and a bibliography.
C. TEXAS NATURAL GAS RATES -- FREQUENTLY ASKED QUESTIONS
Q: How many Texas customers obtain gas through natural gas distribution systems?
A: Texas natural gas distribution systems include 30 investor owned utilities and 84
municipally owned systems through 2010. These natural gas distribution systems serve
4.5 million customers, which comprise domestic households, small commercial, and large
industrial customers.
Q: How many Texas cities are served by natural gas distribution systems?
A: Over 1,100 Texas cities are served by natural gas distribution systems. 85 of these cities
are served by municipally owned distribution systems. The rest of these cities are served
by investor owned utilities.
Q: How much gas is purchased through natural gas distribution systems in Texas?
A: 392 billion cubic feet of gas was purchased through natural gas distribution systems
in2010. This was 16% of all gas consumed in Texas (2,367 billion cubic feet). Gas sales
through natural gas distribution systems (municipal and investor owned) totaled over
$115 billion in 2010.
Q: Who has jurisdiction over natural gas rates in most Texas municipalities?
3
A: The majority of Texas municipalities are served by investor owned utilities. In these
municipalities, the municipality grants a franchise to a utility company, and the
municipality has original jurisdiction (and the Railroad Commission has exclusive
appellate authority) over the rates, operations, and services of the natural gas utility
within the municipality. The Railroad Commission has no authority over the rates,
operations, and services of a municipally owned gas utility within the municipality’s
boundaries.
Q: If I live in a municipality which is served by an investor owned natural gas utility
and I have a concern about my natural gas rates or bill, to whom do I complain?
A: Since the municipality has original jurisdiction over the rates, operations, and services of
the natural gas utility within the municipality, customer complaints should be addressed
to the municipal department which is responsible for the administration of this contract.
Q: Does the Railroad Commission of Texas have jurisdiction over a city’s natural gas
rates?
A: By statute, the city, as the regulatory authority, has a legal obligation to set rates that are
just and reasonable. If the utility or any other party to the proceeding at the city is not
satisfied with the rates set by the city, that aggrieved party may appeal the city’s rate
ordinance to the Commission, where rates will be determined through a formal
evidentiary rate case proceeding. The city has standing to participate in this appeal as a
party. An appeal by any party of the rates set by Commission order would go to Travis
County District Court.
The Commission monitors the overall quality of service and rates provided to a city by an
investor owned utility. Through regular audits, the Commission assures, among other
service issues, that the utility charges its customers the rates which have been formally
authorized, and orders refunds if customers have been overcharged.
Q: Does the Railroad Commission of Texas have jurisdiction over any other natural gas
rates?
A: Yes, the Commission has exclusive original jurisdiction over natural gas utility rates in
areas outside of municipalities, such as “environs”, “unincorporated areas” and “special
rate areas.” Areas adjacent to a municipality and served by the same distribution system
serving the municipality are referred to as “environs.” Areas outside and not adjacent to
an incorporated municipality are referred to as “unincorporated areas” or can be “special
rate areas.” Unincorporated areas are areas that are not adjacent to a municipality but
have rates the same as a nearby municipality served by the same utility. Special rates by
definition are rates applicable only to service by a given utility within a specified area
and not specifically keyed to the rates charged in an incorporated area. Also, the
Commission has exclusive original jurisdiction over the rates and services of a utility,
such as a natural gas pipeline, that delivers gas to a distribution utility, or “city gate
rates”. And, in the case of Interim Rate Adjustments (IRA), both the Cities and the
Commission have the authority to approve an IRA within their jurisdictions. A municipal
denial of a proposed IRA may be appealed by the utility to the Commission.
4
Q: Can the Railroad Commission of Texas provide assistance to municipalities which
are faced with a proposed natural gas rate increase?
A: A municipality may request the Railroad Commission of Texas to advise and assist the
municipality on a natural gas utility matter pending before the Commission, a court, or
the municipality’s governing body. Cities should be aware, however, that budget
constraints imposed by the Legislature limit the resources that the Commission has
available for providing assistance to municipalities. This Rate Review Handbook can
provide a general guidance and the Commission has placed many Proposals for Decision,
Orders and schedules on its web site for review. The handbook contains a comprehensive
review of the ratemaking process. Information regarding these publications is available
by phone at (512) 463-7167 or in the Gas Services section of the agency’s web site:
www.rrc.state.tx.us.
Q: What other sources of assistance regarding evaluation of proposed rate increases
are available to a city?
A: City staff may have the expertise required to evaluate a proposed rate increase. If
necessary, many consultants, attorneys, and associations are available to provide
assistance, usually on a fee basis.
Q Can a utility change my city’s natural gas rates?
A: A utility can propose to raise or lower the rates it charges to provide natural gas
distribution service within a city. Proposals to increase rates are most common. A utility
must follow a specific, formal process to propose and implement a rate increase. But, a
rate decrease can be implemented simply through the filing of a new tariff.
Q: What is the process a utility must follow to propose a rate increase?
A: A utility must file a written statement of intent to increase rates with the city it serves and
publish notice in a local newspaper for four successive weeks, and may not put the
increased rates into effect until at least 35 days after filing the statement of intent. Upon
the filing of a statement of intent, the city may take one of several actions:
1. The city may take no action at all, in which case the proposed rate increase will
automatically take effect after day 35.
2. Unless the increase is a “a major change” (i.e., one that would increase the
aggregate revenues of the utility more than the greater of $100,000 or 2.5
percent), the city, for good cause shown and under any conditions the city may
prescribe, may allow a rate increase to take effect before the end of the 35 day
period.
3. The city may suspend the proposed rate increase for an additional 90 days beyond
the 35
th
day (a total of 125 days from the date that the initial rate increase was
filed). If, after 90 days from the date that the statement of intent of proposed rate
increase was filed, the city has not established final rates, the utility may put into
effect a rate less than or equal to the proposed rate upon filing a bond payable to
the city. If, by the 125
th
day from the date the statement of intent was filed, the
city has not adopted a rate ordinance setting final rates, then the city is considered
5
to have approved the rates proposed by the utility, and they go into effect after the
125
th
day.
4. The city may expressly deny any rate increase, in which case the utility may:
a) maintain the existing rate schedule;
b) appeal to the Commission the city’s rate ordinance denying the requested
increase in rates; or,
c) file with the city a statement of intent proposing a different rate increase.
5. The city may expressly grant a lower than requested rate increase, in which case
the utility may:
a) appeal to the Commission the city’s rate ordinance denying the requested
increase in rates and setting rates at a lower level than requested;
b) put the new rates into effect (even though they are lower than the utility
originally requested), and file with the city a new statement of intent
proposing another rate increase; or,
c) simply put the new rates into effect (even though they are lower than the
utility originally requested).
6. The city may expressly approve the requested rate increase as filed.
Q: How often can a utility propose a rate increase to a city?
A: A utility can propose a rate increase to a city as often as the utility desires. In practice,
proposals to increase rates rarely occur more frequently than once per year. Often many
years pass before a utility seeks a rate increase. Within the requirements of the IRA, once
invoked a utility must file for an adjustment annually and file a Statement of Intent
within 5 years of the initial IRA filing for a full rate review.
Q: If a city denies a proposed rate increase and it is appealed to the Commission or
district court, what expenses will the city and its ratepayers face?
A: The governing body of any municipality participating in or conducting ratemaking
proceedings may select and engage rate consultants, accountants, auditors, attorneys,
and/or engineers to advise and represent the municipality with litigation or natural gas
utility ratemaking proceedings before any regulatory authority or in court. The natural
gas utility engaged in those proceedings is required to reimburse the governing body for
the costs of those services only to the extent that the costs are found reasonable by the
applicable regulatory authority. The natural gas utility commonly recoups these costs
along with its own reasonable rate case expenses by applying a surcharge, which is
determined by the regulatory authority, to its utility rates for that particular municipality.
This surcharge usually is applied on a per customer or per Mcf basis and is typically
spread out over a period of time to reduce its impact on ratepayers. The regulatory
authority typically monitors the amount of money collected under the surcharge to ensure
that the utility does not over collect.
Q: What percentage increase is being proposed in the statement of intent?
A: Most statements of intent propose a percentage rate increase. The percentage increase is
most frequently stated as the increase in total revenues, including the portion of revenues
which covers the cost of natural gas purchases. Since the cost of natural gas is simply
6
passed through to the customer without a profit, some prefer to exclude from the
calculation of a rate increase revenues which cover the cost of natural gas purchases. The
following example illustrates the difference between including and excluding cost of
natural gas pass-through revenue when calculating a percentage rate increase.
Present
Rates
Proposed
Rates
% Rate
Increase
Total Operating Revenue
(Including Cost of Gas)
$300,000
$315,000
5%
Cost of Gas
$220,000
$225,000
Total Operating Revenue
(Excluding Cost of Gas)
$80,000
$90,000
12.5%
Q: Where can I get further information regarding the topics discussed in this section?
A: Call the Gas Services at (512) 463-7167 or visit the Commission’s web site at
www.rrc.state.tx.us.
7
CHAPTER I.
JURISDICTION AND PROCEDURES
SECTION
1
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J
URISDICTION
City jurisdiction over natural gas distribution rates and services was implied under the Cox Act
and was specifically granted in the Gas Utility Regulatory Act. A municipality has original
jurisdiction over the rates, operations and services provided by any gas utility distributing natural
gas within the city or town limits pursuant to T
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§ 103.001. In contrast, T
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§ 102.001 gives the Commission original jurisdiction over utility distribution rates and
services outside the city limits and in other unincorporated areas and over city gate sales, and
appellate jurisdiction to review the rate ordinances or orders of municipalities.
As a regulatory authority, as defined in T
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§ 101.003(13), the city has the
authority:
• To make reasonable inspections of the papers, books, accounts, documents, or other
business records of the utility. T
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§ 102.203
• To require the filing of rates, rules, and regulations. T
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§ 102.151
• To fix just and reasonable standards of service to be followed by the utility.
T
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§ 104.252
• To provide for the examination and testing of equipment. T
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§ 102.205
• To engage rate consultants, accountants, auditors, attorneys and engineers to assist in
ratemaking proceedings. T
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§ 103.022.
• To establish rates. T
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§ 103.001.
T
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§ 103.022 gives cities the right to hire rate consultants, auditors, attorneys, and
engineers to assist with the ratemaking proceedings upon request by the city; the public utility is
required to reimburse the governing body for the reasonable costs of such services, which are
passed on to the ratepayers. A city may, of course, elect to pay for such services from tax-
generated revenue. The city should plan expenditures not only on a basis of reasonableness but
also on a basis of cost effectiveness.
Under T
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§ 102.005, the Commission may advise and assist municipalities upon
request in connection with questions and proceedings under the statute. Cities should be aware,
however, that budgetary constraints imposed by the Legislature limit the resources that the
Commission has available for providing such assistance.
8
SECTION
2
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P
ROCEDURES AT THE
C
ITY
L
EVEL
The procedures and legal standards for ratemaking proceedings are generally contained in T
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Chapters 102 and 104. Ratemaking proceedings are typically initiated by a utility by
filing a statement of intent to increase rates under T
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§ 104.102. The utility must
provide notice in accordance with T
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§ 104.103. The city, however, may initiate a
rate proceeding on its own motion or on the complaint of any affected person, and if, after notice
and hearing, it finds that existing rates are unreasonable or in violation of the law, it may adopt
new rates. T
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§ 104.151.
A. S
TATEMENT
O
F
I
NTENT
Under the terms of T
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§ 104.102, a utility may not increase its rates without filing,
at least 35 days prior to the effective date of the proposed increase, a statement of intent with the
regulatory authority having original jurisdiction. T
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§ 104.102 sets out
requirements for the content of the statement of intent, which must:
• specify a proposed effective date which is at least 35 days after the filing date, except
upon a showing of good cause;
• state the proposed revisions of tariffs and schedules and specify in detail each
proposed increase;
• state the effect of the proposed increase on company revenue;
• state the classes and numbers of utility customers affected; and,
• contain such other information as may be required by the regulatory authority’s rules
and regulations.
B. N
OTICE
A copy of the statement of intent must be mailed or delivered to the appropriate officer of each
affected municipality. T
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§ 104.102(b). If a proper statement of intent has been
filed, the city may proceed with its rate determination. If the statement of intent is defective, the
city may allow the filing of a proper or amended statement of intent. The statute does not require
that statements of intent include data to support the rate request. However, because the city must
evaluate the basis of the request in order to determine its reasonableness, the city shall require
the utility to submit supporting information to the city during the course of the city's
investigation of the merits of the rate request. T
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§ 103.021.
In addition to filing the statement of intent with the city, the utility must publish notice for four
successive weeks in a newspaper having general circulation in each county with territory
affected by the proposed change. The time limits and publication requirements set out in T
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§ 104.103 do not apply to a complaint proceeding under T
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§ 104.151.
9
Instead of publishing newspaper notice, a gas utility may provide notice to the public in an area
outside the affected municipality or in a municipality with a population of less than 2,500 by
either mailing the notice to each customer or including the notice in each customer’s bill. T
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§ 104.103(b).
C. D
ISPOSITION
Rate proceedings before the city may generally be processed according to any applicable
provisions of the city charter. However, T
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§ 103.021(b) requires that the city
make its rate determination using the procedures and requirements of Title 3, Subtitle A (the Gas
Utility Regulatory Act) of the Texas Utilities Code.
Once the proper statement of intent is filed and notice is given, the city council may on its own
motion or upon the complaint of any affected person hold a hearing or hearings to determine the
propriety of the change. This decision may be made at any time within 30 days from the date
when the change would or has become effective, upon reasonable notice to all affected parties.
T
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§ 104.105. The city council is required to provide an opportunity for hearing in
each case where the change would constitute a major change as defined in T
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§
104.101. T
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§ 104.104 prohibits a major change to take effect prior to the end of
the 35-day period prescribed by T
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§ 104.102. An informal proceeding may satisfy
the requirement if no complaint is received before the expiration of 45 days after notice of the
change has been filed.
Once the statement of intent has been filed, the city has several options for handling the rate
request. It may take no action and allow the proposed rate increase to take effect automatically at
least 35 days after the date of filing. Or the city, depending on what its investigation reveals,
may:
1) expressly deny any rate increase;
2) expressly grant the proposed rate increase in full;
3) expressly grant a rate increase less than that requested;
4) expressly set rates that are lower than the rates the utility is charging.
The city council should maintain a formal record of its decision, whether through ordinance or
minutes. Whatever the city's decision, the utility should be advised promptly in writing.
If the city finds that it cannot make an informed decision before the proposed effective date, it
may suspend the proposed rate pursuant to T
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§ 104.107. Upon delivery to the
affected utility of a written statement of its reasons, the city may suspend the operation of the
rate schedule for a period of 90 days beyond the date on which the schedule would otherwise
have gone into effect giving the city a total of 125 days to review the proposed rate increase.
10
If the city has not made a final determination within 125 days after the proposed effective date,
T
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§ 104.107(b) provides that the regulatory authority is considered to have
approved the rate schedule. This approval, however, is subject to the city's authority thereafter to
continue a hearing in progress.
If the city chooses to suspend the rates, it may consider establishing temporary rates for the
period of suspension. T
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§ 104.108. Temporary rates may be subject to credit or
refund upon setting the final rate. Bonded rates do not apply to cities, because they have to make
a decision by the 125
th
day (which is 90 days from the date the rates would otherwise have gone
into effect). T
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§ 104.109.
D. H
EARING
T
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§ 102.251 requires that a record be kept of the proceeding before the city. T
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§ 102.252 provides that all parties to the proceeding are entitled to be heard in
person or by an attorney. Although the T
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does not define the term “party,” T
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§ 105.051 refers to complaints made by any “affected person.” Presumably, any
“affected person” may be permitted to become a party to the proceeding. An “affected person” is
defined in T
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§ 101.003(1) as a gas utility affected by an action of a regulatory
authority, a person whose utility service or rates are affected by a proceeding before a regulatory
authority, or a person who is a competitor of a gas utility with respect to a service performed by
the utility or wants to enter into competition with a gas utility. Mere participation in the
proceeding does not confer party status on a person. Party status is conferred only when the city
names or admits the person as a party to the proceeding. A party to the proceeding may appeal
the city's action to the Railroad Commission. See TEX. ATT'Y GEN. OP. NO. MW-355 (1981).
A city has several options available concerning the scope of the data it will consider in
connection with applications for rate increases. The city may consider data covering the utility's
cost of providing service in just the municipality, or it may consider system-wide data. T
EX
.
U
TIL
.
C
ODE
§ 103.021. In appropriate situations, the city may limit the scope of the hearing to
consider an identifiable rate factor that can be easily segregated. See Railroad Comm’n v. City of
Fort Worth, 576 S.W.2d 899 (Tex. Civ. App.--Austin 1979, writ. ref'd n. r. e.).
E. E
NVIRONS
R
ATES
The Railroad Commission of Texas has original jurisdiction over gas rates outside of city limits.
T
EX
.
U
TIL
.
C
ODE
§ 102.001. If a gas utility operates a system that serves both within and outside
the city limits and the utility desires a uniform rate covering both areas, it must file two separate
statements of intent, one with the city to increase rates in the city and one with the Commission
to increase rates in the service area outside the city limits, known as the “environs.” Commission
special rule § 7.220(b) (16 T
EX
.
A
DMIN
.
C
ODE
§ 7.220(b)) provides that the utility may generally
implement the same rate in the environs as has been approved by the city council for the
incorporated areas. If the utility files simultaneously with the city and the Commission, it is
likely that the Commission would suspend any proposed environs rate until the city has had an
opportunity to make an independent decision concerning a proposed rate change in the city. In
11
the past, a utility would typically file a statement of intent to increase rates for an environs area
to match the rates already approved by the adjacent city. Once the city has taken action on the
statement of intent and has established a new city rate, the Commission may allow the utility to
charge the same rate in the environs. Commission substantive rule § 7.45, governing quality of
service, applies to the environs areas and becomes part of the environs rates notwithstanding
whether the same rules are in effect in the related incorporated area. When a city has granted
rates which reflect a late charge, such rates may be approved for the environs. Further, the
Commission has required that adjustment clauses included as part of an environs rate conform
with Commission substantive rule§ 7.5525, regarding lost and unaccounted for gas, and has
precluded establishing certain rate designs and indexing procedures in areas of Commission
original jurisdiction.
In recent years, utilities and municipal representatives have preferred having the Commission
concurrently hear both the environs statement of intent to increase rates and the appeal by the
utility of a denial by the municipality. The two docketed rate cases are consolidated and heard
together for time and economic efficiency. Since 2005, the vast majority of the utility’s
municipal and environs rate cases are heard together. Additionally, utilities are expected to file
schedules and workpapers sufficient to support the requested increase. Failure to file supporting
schedules and workpapers has resulted in filings being considered deficient. It is important that
utilities adequately support their request.
12
F. JURISDICTION OVER GAS UTILITY RATE CASES
Railroad Commission has original jurisdiction over:
A City has original jurisdiction over
gas rates and services of a gas utility
distributing natural gas in an
incorporated area.
Railroad Commission of Texas
(Appellate Jurisdiction)
Appeal
Appeal
District Court of
Travis County
Third Court of Appeals
Austin, Texas
Supreme Court of Texas
Austin, Texas
Texas Courts
Appeal
Appeal
Appeal
1) gas rates and services of a gas utility distributing
natural gas in an unincorporated area; and
2) sales for resale at the city gate.
13
CHAPTER II.
OVERVIEW OF RATE REGULATION
S
ECTION
1
-
R
ATE
R
EGULATION
:
A
S
UMMARY
Cost is the basis of utility ratemaking. A utility is entitled to rates which generate revenue
equal to its costs. These costs fall into two categories: capital costs and operating costs. A
utility’s operating costs are its reasonable and necessary expenses. For purposes of rate
regulation, a utility’s capital costs are considered to be its required return on investment
or its weighted average cost of money multiplied by the total amount of its investment in
the utility system, frequently referred to as the rate base. The regulator must identify the
appropriate rate base, the cost to the utility of the money invested in the rate base, and the
cost of operations. The task then is to design rates that fairly generate revenue equal to
the costs incurred. T
EX
.
U
TIL
.
C
ODE
§ 104.051.
Utilities are required to adopt the Federal Energy Regulatory Commission’s (FERC)
Uniform System of Accounts (USOA). T
EX
.
U
TIL
.
C
ODE
§ 102.101 and 16 T
EX
.
A
DMIN
.
C
ODE
§ 7.310. The FERC USOA provides specific instructions for account record
keeping and the manner in which the utility must treat certain items, including gas plant.
All statement of intent filings should attest to the utility’s adoption and use of the FERC
USOA for all operating and reporting purposes.
A. R
ATE
B
ASE
Rate base is the utility’s investment in the system. A utility's rate base may be calculated
as: 1) original cost less book depreciation (net invested capital); 2) reproduction cost
new less adjustment for age and condition (net current cost); or 3) some combination of
net invested capital and net current cost. T
EX
.
U
TIL
.
C
ODE
§ 104.053(b) provides that
these methods may be reasonably balanced using a weighting of 60 percent to 75 percent
net invested capital and 40 percent to 25 percent net current cost, to calculate the adjusted
value of invested capital.
Other components of the rate base are working capital, customer deposits, deferred
taxes, construction work in progress (CWIP), and retirement work in progress.
When evaluating the utility's rate base information, the regulator should be alert to
allocation issues, which, if not carefully scrutinized, could result in improper rates. For a
discussion of allocation of system wide assets to a distribution system, see Chapter III,
Section 1.C.
B. C
OST OF
C
APITAL
The cost of capital (the cost of borrowing money) can be used to adjust the rate base.
The statute offers only a general standard, i.e., “a fair return on the adjusted value of the
invested capital used and useful in providing service to the public.” T
EX
.
U
TIL
.
C
ODE
§
104.052.
14
To calculate the cost of capital, a rate must be assigned to each component of the capital
structure. Normally, the rates applied to debt and preferred stock are embedded; that is,
they may be simply taken from the utility's books. The regulator should be aware that
debt is sometimes listed at current interest rates when it was incurred at older, lower
interest rates. Interest rates applied to each issue of debt should be studied.
The cost of equity is an area in which there is potential for a cost overstatement, because
it can only be estimated. A utility's justification for cost of equity should be studied
carefully and checked against other cost formulas.
To determine the utility's weighted average cost of capital, the cost of each component
should be multiplied by the weight of each component, and these weighted costs should
then simply be added. The product of this weighted average cost of capital and net
invested capital is the utility's required monetary return.
The utility's cost of capital includes several components, of which debt, preferred stock,
and equity are the most common. In addition, if the utility chooses to make no rate base
adjustment for customer deposits and deferred taxes, these should be included in the
utility's capital structure. To avoid overstatement of the higher cost equity component,
capital costs can be assigned to the various components of the rate base. Close attention
should be paid to companies which are either subsidiaries or operating divisions of larger
companies. In this case, the utility may use a capital structure with a higher equity ratio.
C. O
PERATING
C
OSTS
Operating costs must be reimbursed from the rates, so the rate base is adjusted for
operating costs. The starting point for calculating a utility's operating costs is book
revenue and expenses. Revenue and expenses associated with the sale of goods and
services other than utility services should be excluded; e.g., sale of gas ranges,
installation, etc. Certain expenses associated with advertising and charitable contributions
may be excluded. Political contributions and lobbying expenses must be excluded under
T
EX
.
U
TIL
.
C
ODE
§ 104.057. All payments made to affiliated suppliers, defined in T
EX
.
U
TIL
.
C
ODE
§ 101.003(2) require careful scrutiny to be certain that prices have not been
inflated. All payments made to affiliates must meet the standards of T
EX
.
U
TIL
.
C
ODE
§
104.055. Failure to properly document affiliate transactions and provide the
documentation required in T
EX
.
U
TIL
.
C
ODE
§ 104.055 could result in a filing being
considered deficient or a denial of affiliate expenses.
If allocations are necessary, the utility should consider using a Cost Allocation Model (or
Manual) (“CAM”), to support its allocation methodology. Methods used to allocate
revenue and expenses should be scrutinized. Allocation issues fall into several categories.
First, the utility may allocate among classes of consumers, i.e., industrial vs. residential
and commercial. Second, the utility may allocate particular facilities and expenses to a
particular distribution system. Third, the utility may allocate portions of its general plant
and management salaries to each distribution system. Facilities and expenses should not
be charged to more than one distribution system.
15
After allocated book revenue and expenses are determined, the utility may attempt to
justify adjustments to these revenue and expenses. The most frequently proposed
adjustment is to account for variances in gas consumption due to abnormal weather. In
addition to weather, the utility may justify other known and measurable changes, such as
changes in tax rates, postage rates, salaries, etc. If these adjustments are, in fact, known
and measurable, they should be allowed. Just because a change is known and measurable,
its reasonableness must also be determined, such as a known and measurable salary
increase. However, the utility may also attempt to justify other adjustments for attrition,
erosion, price elasticity and inflation. Since these adjustments may be speculative in
nature, they should be studied closely. Further discussion of these adjustments follows in
Chapter III, Section 2.
The difference between adjusted revenue and expenses is adjusted gross income.
Application of the appropriate federal income tax rate to this gross income results in the
adjusted net income. The difference between the adjusted net income and the required
monetary return is the required net income increase. By dividing the net income
deficiency by the tax reciprocal, one derives the gross revenue deficiency. This, added to
the adjusted revenue, results in the total required revenue.
D. R
ATE
D
ESIGN
Rate Design is the manner in which the utility bills its customers. The utility’s rate
design should charge customers a fair amount for the type and amount of gas use, while
allowing the utility to recover enough revenue to cover its costs and make a reasonable
rate of return, or profit. The choice among the various rate designs is primarily a matter
of policy. Usually, the policy involves a choice between multi-block rates and single-
block rates. In the case of multi-block rates, the utility is allowed to charge a differing
rate for higher volume purchases. A single-block rate is a fixed charge per unit of gas
consumption. A utility may also include a customer charge to be paid regardless of
consumption.
Other rate schedule issues deal with the allowance of purchased gas and other adjustment
clauses. A purchased gas adjustment clause is a valuable tool to allow a utility's rates to
fluctuate according to a utility's cost of gas. Normally, this cost of gas will fluctuate more
frequently than the utility is able to seek and obtain rate changes. The regulator should
also study the utility's need for a factor to recover costs of lost and unaccounted for gas.
16
CHAPTER III.
RATESETTING
SECTION
1
-
R
ATE
B
ASE
Under T
EX
.
U
TIL
.
C
ODE
§ 104.053, the adjusted value of invested capital is the rate base.
See Southwestern Bell Telephone Company v. Public Utility Comm’n, 517 S.W.2d 503
(Tex. 1978). Invested capital has been defined as original cost less depreciation. The
rate base is comprised of a reasonable balance between original cost less depreciation and
current cost less an adjustment for present age and condition.
A. T
EST
Y
EAR
T
EX
.
U
TIL
.
C
ODE
§ 101.003(16) defines test year as the most recent 12 months for which
operating data for a gas utility are available. A test year shall commence with a calendar
quarter or fiscal year quarter.
The present practice of the Commission is to use asset balances as of the test year end
adjusted for known changes, as opposed to the average balance for the test year, because
year end data more accurately represents existing conditions on which to base rates for
the future.
B. I
NVESTED
C
APITAL
This includes all items used to provide utility service at the actual cost of the property at
the time it was dedicated to utility service, whether by the present owner or his
predecessor, less accumulated depreciation. T
EX
.
U
TIL
.
C
ODE
§ 104.053. The FERC
USOA provides specific instructions for gas plant accounting.
The Commission requires the straight-line method of depreciation for determining test
year depreciation and amortization expense. T
EX
.
U
TIL
.
C
ODE
§§ 102.152 and 104.054
and Commission substantive rule § 7.5252(a).
If the utility engages in both utility and non-utility activities, the investment must be
fairly and justly allocated between utility and non-utility activities. Commission
substantive rule § 7.5252(c).
C. A
LLOCATION OF
S
YSTEM
-W
IDE
A
SSETS TO A
D
ISTRIBUTION
S
YSTEM
Frequently, the utility will allocate its general plant or other assets to the distribution
system under consideration. Normally, the utility should not need to allocate the
distribution plant accounts, if separate accounts have been maintained for each
distribution system. If the utility needs to allocate distribution plant accounts, however,
one accepted method for doing so is on the basis of linear feet of pipe. Such an allocation
can raise problems if the utility allocates newer facilities in its system to an older
distribution system where the pipe has been depreciated.
17
In the case of a general plant, the most frequent allocation method seen is on the basis of
number of customers. This allocation is acceptable, since most general plant expenses are
customer-based (e.g., billing, accounting, etc.). In addition, general plant must frequently
be allocated among different business enterprises. This is particularly true in the case of
diversified energy corporations which include utility divisions. For this purpose, a multi-
factor formula is generally used. Such a formula may include: 1) sales revenue; 2) plant
in service; 3) operating expenses excluding overhead; 4) number of labor dollars for
personnel; and 5) number of operating units. The allocation factors should be chosen to
best reflect actual cost correlation. The weighting is usually equal unless some unusual
circumstance dictates otherwise.
D.
C
URRENT
C
OST
(R
EPRODUCTION
C
OST
N
EW
)
Current Cost or Reproduction Cost New involves the application of current prices to
existing assets. The objective is to determine the cost required to reproduce those assets
presently in use. Replacement cost, on the other hand, represents the application of
present prices to similar assets, some of which may be technologically superior to assets
actually in use. Since Commission practice involves the strict duplication of existing
utility property, replacement cost is not considered. See Webb, Utility Rate Base
Valuation in an Inflationary economy, Public Utility Regulation in Texas - A Symposium,
28 Baylor L. Rev. 823 (1976).
An alternative approach to determining current cost involves the application of trend
indices to the original cost of various assets. For example, the Handy-Whitman Index, the
Engineering News Record Building Construction Index, and the Wholesale Price Index
(developed by the U.S. Department of Labor) have been used.
The adjustment for age and condition represents the difference in value between the
present plant and what it would be if new. The Commission presently uses an adjustment
for age and condition equal to the ratio of accumulated depreciation to original cost.
It is important to note that the Commission prefers the use of original cost, less
accumulated depreciation, to determine rate base. Other methods, if necessary and
adequately supported, may be approved.
E. O
THER
R
ATE
B
ASE
I
TEMS
1. Construction Work In Progress
Many utilities urge the inclusion of an account for construction work in progress (CWIP)
in the rate base. It should be included as a component of the rate base only where
necessary to the financial integrity of the utility, at cost as recorded on the books of the
utility, T
EX
.
U
TIL
.
C
ODE
§ 104.053. The Commission allows CWIP only when convinced
that without it, the utility cannot meet its capital obligations, raise needed capital, or that
there will be an impairment of the utility's service. Commission substantive rule§ 7.5212.
18
16 T
EX
.
A
DMIN
.
C
ODE
§ 7.5212.
An allowance for funds used during construction (AFUDC) may be capitalized at a
reasonable rate at the time the item goes on line in those instances where CWIP is not
included in the rate base. Commission substantive rule § 7.5212. 16 T
EX
.
A
DMIN
.
C
ODE
§
7.5212.
2. Working Capital
The Commission prefers the use of a lead-lag study to determine working capital. If a
utility does not have the means to perform or to hire a consultant to perform a lead-lag
study, Commission practice is to provide for 45 days or 12.5 percent of operating
expense, excluding cost of gas purchased, depreciation and taxes, plus the 13-month
average amount of materials and supplies and the average prepayments.
3. Contributions in Aid of Construction and Customer Advances
Donations or contributions of cash, services, or property from individuals, companies,
states, municipalities or other governmental agencies, and others for construction
purposes, and advances by customers which are to be refunded either wholly or in part,
are accorded two optional treatments. Such funds are deducted from the rate base and not
included in the company's capital structure, or they are left in the company's rate base and
are included in the company's capital structure at the company's cost, if any.
Note: The Texas Supreme Court held in Sunbelt Utilities v. the Public Utility
Commission, 589 S.W. 2d 392 (Tex. 1979) that, where the developer of property
and the utility have common ownership, the developer's cost of installing the
utility system was recovered from the utility's customers through sale of the lots,
and was therefore a customer contribution in aid of construction and was properly
excluded from rate base.
4. Customer Deposits
Two optional treatments are accorded customer deposits: 1) The deposits are deducted
from the rate base and the interest paid to the customer on these funds pursuant to T
EX
.
U
TIL
.
C
ODE
Chapter 183 is included as an expense item; or 2) the deposits are left in the
company's rate base, and they are included as a part of the company's capital structure.
5. Investment Tax Credit
Pursuant to T
EX
.
U
TIL
.
C
ODE
§ 104.056, the tax savings derived from the investment tax
credits taken by the company are to be divided between present and future customers to
the extent allowed by the Internal Revenue Code.
It has been Commission practice not to reduce the rate base for pre-1971 investment tax
credits. Commission substantive rule § 7.501(3). 16 T
EX
.
A
DMIN
.
C
ODE
§ 7.501(3).
19
The treatment accorded post 1970 investment tax credits depends upon the election made
by the company under Section 46 of the Internal Revenue Code. If the company has made
no election, it is deemed that a rate base reduction election has been made. Under this
election, the Internal Revenue Code allows a rate base reduction in the amount of any
investment tax credit taken. However, the reduction must be restored to the rate base in
equal installments over the life of the assets on which the credit is taken.
Therefore, a utility must take either the Section 46 reduction or a rate base reduction. If
the company has made a cost of service reduction election under Section 46 of the
Internal Revenue Code, a rate base reduction is prohibited. Any rate base reduction, even
if it is achieved in an indirect manner, will cause the company to lose its eligibility to
claim the credit. The treatment to be accorded a cost of service reduction is discussed in
Chapter III, Section 4, Revenue and Expenses. Table III - 1 presents an example
calculation of the impact of the investment tax credit based on a 2004 test year. In this
example, the rate base would be reduced by $8,850.
T
ABLE
III
–
1
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Year
Credit
Taken
Amount
of
Credit
Servic
e
Life
Annual
Credit
(b) /(c)
Multiplier
(Test Yr. -
(a)
Restoratio
n
(d) x (e)
Net
Reductio
n
(b) - (f)
2000
$2,500
10
yrs.
$250
3
$750
$1,750
2001
$4,000
20
yrs.
$200
3
$600
$3,400
2002
$2,000
20
yrs.
$100
2
$200
$1,800
2003
$2,000
20
yrs.
$100
1
$100
$1,900
Total
$8,850
6. Deferred Income Taxes
Deferred taxes arise because of timing differences between the recognition of certain
items for book (i.e., liberalized depreciation for tax purposes and straight line
depreciation for book purposes). Further, the company may expense interest and real
property taxes accruing during construction projects for tax purposes, but it may
capitalize these items and write them off over the life of the asset for book purposes.
20
Two approaches, flow-through and normalization, have been developed for the treatment
of a utility's federal income tax liabilities. The flow-through method attempts to
recognize as tax expense for regulatory purposes the actual tax shown on the return. T
EX
.
U
TIL
.
C
ODE
§ 104.056 has been interpreted by the Commission to prohibit the
flow-through method because of the mandate in T
EX
.
U
TIL
.
C
ODE
§ 104.056(a)(1) that the
benefits of tax savings be balanced equitably between present and future customers.
Under the normalization approach, the company accumulates in its deferred tax accounts
the difference between the amount of income tax it pays and the amount it shows for
book purposes. One normalization method is to reduce the rate base by the amount of
deferred taxes attributable to a particular system. An alternative method is to make no
rate base reduction for deferred taxes, but to include all of the company's deferred taxes
as a part of its capital structure at zero cost. The normalization approach meets the
statutory intent of sharing the benefits of tax savings between present and future
customers, because this approach spreads the tax savings over the life of the asset.
Note: Commission substantive rule 16 T
EX
.
A
DMIN
.
C
ODE
§ 7.501(2) requires a gas
utility to report the amount of any income tax savings or deferrals derived from
the application of such methods as liberalized depreciation or amortization.
7. Insurance Reserve
Some utilities are self-insured and have a reserve account for use in the event of losses.
Some cities urge that the insurance reserve should reduce the rate base, even though the
insurance reserve is not included in the rate base. The reserve is not a rate base reduction
under present Commission practice.
8. Retirement of Plant Assets
The retirement of a plant asset from service is accounted for by crediting the book cost to
the utility plant account in which it is included. At the same time, accumulated
depreciation is debited with the original cost and the cost of removal and credited with
the salvage value and any other amounts recovered, such as insurance.
9. Acquisition Adjustment
When a company pays a purchase price above the net original cost for a utility operating
unit or system, it often requests an acquisition adjustment as a rate base addition. The
acquisition adjustment is equal to the difference between the price paid and the net
original cost. Similarly, when a company pays a purchase price that is below the net
original cost for a utility operating unit or system, an acquisition adjustment is used by
the Commission to reflect the actual investment for the purpose of calculating a return on
rate base. Such an item may be a proper expense to be amortized.
10. Summary of the Impact of the above Rate base Items
21
Each of the above rate base items can be included as a rate base deduction or included in
capital structure, but not both, because the utility should only be allowed to recover for
each item once. Table III - 2 presents the impact of each of the above rate base items if
they are included as a rate base deduction or included in capital structure.
T
ABLE
III
–
2
Other Rate Base Items
Treatment I
Contributions and
Advances,
Customer Deposits and
Deferred Income Taxes
Used
as Rate Base Reduction
Treatment II
Contributions and
Advances,
Customer Deposits and
Deferred
Income Taxes Included in
Capital Structure
Construction Work in
Progress
$0
$0
Working Capital
$508,850
$508,850
Contributions & Advances
$(20,000)
$0
Customer Deposits
$(120,000)
$0
Investment Tax Credit
$(8,850)
$(8,850)
Deferred Income Taxes
$(200,000)
$0
Insurance Reserves
$0
$0
Retirement of Plant Assets
$0
$0
Acquisition Adjustments
$0
$0
Totals
$160,000
$500,000
F. R
ATE
B
ASE
S
UMMARY
T
EX
.
U
TIL
.
C
ODE
§ 104.053 requires gas utility rates to be based on the adjusted value of
invested capital used and useful to the utility in providing service, and that the adjusted
value shall be computed on the basis of a reasonable balance between the original cost
(less depreciation) and the current cost (less an adjustment for age and condition).
Commission practice, if necessary, is to weigh net original cost at 60 percent and net
current cost at 40 percent. Under T
EX
.
U
TIL
.
C
ODE
§ 104.053, the weighting to be applied
to each of the components is discretionary with the regulatory authority so long as net
original cost is weighed no less than 60 percent nor more than 75 percent and net current
cost is weighed no more than 40 percent or less than 25 percent.
The regulatory authority has the discretion to set the percentages of each element in the
rate base within the limits T
EX
.
U
TIL
.
C
ODE
§ 104.053 on a case-by-case basis, in order
22
to adjust the monetary return to the proper level. See Southwestern Bell Telephone
Company v. Public Utility Commission, 571 S.W. 2d 503 (Tex. 1978).
Table III - 3 summarizes the calculation of total rate base as discussed in Chapter 3,
Section 1 and illustrates an example of the 60/40 weighting of original/current plant cost.
T
ABLE
III
–
3
Invested Capital
$1,000,000
Less Accumulated Depreciation
$ 200,000
Net Original Cost
$ 800,000
Other Rate Base Items (Net)
$ 500,000
Total Invested Capital
(a) $1,300,000
Current Cost
$2,000,000
Less Adjustment for Age and Condition
$ 400,000
Net Current Cost
$1,600,000
Rate Base
Net Original Cost = 800,000 x 60% =
$ 480,000
Net Current Cost = 1,600,000 x 40% =
$ 640,000
Other Rate Base Items (added since original plant was constructed)
$ 500,000
Total Rate Base (Adjusted Value Rate Base)
(b) $1,620,000
(a) The composite cost of capital may be applied to this figure to determine the required
monetary return
(b) The require monetary return is then divided by this figure to determine the rate of
return on the adjusted value of invested capital rate base.
23
SECTION
2
-
C
OST OF
C
APITAL
Utilities acquire capital primarily by borrowing (debt) or selling stock (equity). Like pipe
or stationery, money has a “cost”. That cost is determined by the return the lender or
investor requires. Financial theory postulates that returns must be commensurate with the
investment risk. That is, the higher the risk, the higher the return. This Section will
examine issues relating to capital structure and the cost of debt, preferred stock, equity,
and other sources of funds, in order to develop an estimate of the utilities’ cost of capital,
alternatively referred to as its rate of return. Once a company’s capital structure and
actual or estimated costs of debt and equity have been identified, the company’s overall
rate of return can be estimated by determining its weighted average cost of capital
(WACC). This is described in greater detail in section G.
A. C
APITAL
S
TRUCTURE
In order to determine a utility's cost of capital, it is necessary to determine the types of
investment in the company. The ratios of the various sources of capital to total permanent
capital is called the utility's capital structure. Because some sources of money are more
costly than others, the utility's capital structure can have a significant impact on the
overall cost of capital.
The first step in arriving at a proper capital structure is to determine the amount and types
of total permanent capital invested in the company. Short-term debt is often used by
corporations as a form of interim financing until long-term financing is available.
Company records will show if short-term debt has been relied on in recent years. If
short-term debt is part of the permanent capital structure, adjustments will be needed. The
ratio of short-term debt to total capital commonly fluctuates broadly over time. In this
case, a trending or averaging technique, tempered by judgment, will provide an
acceptable ratio of short-term debt to total capital.
Trends in corporate capital structures should be examined before automatically assigning
the end of the test year's capital component weighting. Company activity in the capital
markets, or lack of it, may skew its capital structure when compared to its historical
norm. It is important to realize that capital structures evolve as a company's scope of
activities and risks changes.
Companies maintain a capital structure that management deems to be optimal given the
mix and risk of corporate activities. Gas distribution companies typically have high debt
to equity ratios when compared to other industries. Problems arise in rate cases where the
gas utility is part of a diversified corporation. In these cases, the Commission generally
looks at the parent corporation's consolidated capital structure, weights the individual
components, and assigns them to the investment in the utility. If the consolidated capital
structure is far out of line with the industry average, as shown in Moody’s Utility
24
Manual, a typical industry capital structure may be considered.
Another consideration is the capital structure of small utilities. Some small utilities are
heavily equity financed. A company can reasonably be expected to lower the overall cost
to its ratepayers by using debt financing, but this determination should be made only after
very careful consideration. Often a small utility may not have the financial capacity to
borrow long-term fixed rate funds. They might even lack the financial strength to support
or even qualify for short-term borrowing. If a determination is made that the company
could have issued debt at reasonable cost and security, a reasonable capital structure for
the company can be assigned for ratemaking purposes.
B. D
EBT AND
P
REFERRED
S
TOCK
The company's books should clearly display the cost of long-term and short-term debt. If
debt will be maturing while the rates will be in effect, replacement costs of that debt
should be considered. In any case, the proper cost of debt is the embedded cost of debt
with adjustments made for current maturities.
If the original debt was sold at a discount, or if expenses were incurred in contracting for
the debt, it is proper that the utility be allowed to increase the coupon rate to amortize the
discount or debt expenses. For debt sold at a premium, the premium should be amortized
so as to decrease the coupon interest rate.
Table III - 4 presents an example of an accepted method of determining a company's
embedded cost of debt. The same procedure should be followed to calculate the
embedded cost of preferred stock.
T
ABLE
III
–
4
(a)
(b)
(c)
(d)
Amount Issued and
Not Refunded or
Canceled
Percent
of Total
(b / Total)
Weighted
Cost
(a x c)
First Mortgage Bonds
5% due 2000
$ 1,000,000
10.00%
0.50%
6% due 2005
$ 500,000
5.00%
0.30%
Sinking Fund Debentures
6.25% due 1998
$ 2,000,000
20.00%
1.25%
8% due 2005
$ 6,500,000
65.00%
5.20%
25
Total
$10,000,000
100.00%
7.25%
The weighted average cost of debt or preferred stock is obtained by multiplying the
interest rate of a particular issue by the ratio of that issue to total permanent debt or
preferred capital. This must be done for each issue and the components must then be
added to arrive at the embedded cost.
C. E
QUITY
1. Fundamentals of the Cost of Equity
The cost of equity capital is much more difficult to determine. It does not have a stated
rate of return or interest as do loans, bonds or preferred stock. An equity investor still
expects to receive a return on their investment. This return is in the form of dividends or
increases in the value of the stock, or both. The cost of equity to a company is the rate of
return necessary to get investors to purchase the company's stock. This rate is not
directly observable in the market place but must be estimated for ratemaking purposes.
The law requires that the estimated cost of equity be high enough to allow the company
“to maintain its financial integrity, to attract capital and to compensate its investors for
the risks assumed.” Federal Power Commission v. Hope Natural Gas Company, 320
U.S. 591, 64 s. Ct- 281, 88 L. ED- 333 (1944). In another case, the Supreme Court of
Texas said the rate of return must be high enough to attract ample capital but need not
be beyond that [amount] Railroad Commission v. Houston Natural Gas Corporation,
289 S.W. 2d 559 (Tex. 1956), Southwestern Bell Telephone Company v. Public Utility
Commission, 571 s.w. 2d 203 (Tex. 1978).
2. Techniques for Estimating the Cost of Equity
Four methods for determining the cost of equity are most frequently presented to the
Commission. Those methods, which will be specifically addressed below are: a)
discounted cash flow, b) discounted cash flow on comparable companies, and c) the
capital asset pricing model (CAPM) and d) comparable earnings analysis.. Utilities will
often employ more than one technique in estimating the cost of equity.
a. Discounted Cash Flow (DCF)
Discounted cash flow is the most widely accepted method of estimating the cost of equity
for publicly traded companies. The DCF technique presumes the basic efficiency of the
market place in setting the price of a stock. It is the action of the market place that
reflects the true cost of capital. The underlying assumption of the DCF model is that
investors are buying securities based on their expected dividend yield and increased
value.
The DCF formula attempts to reproduce that price mechanism to arrive at an
26
estimate for equity return. The constant growth derivation of the DCF is shown as
Expected Return = Dividend rate per share + growth.
D
1
K
e
= + g
P
o
Where K
e
= expected rate of return on equity (the utility's cost of equity)
D
1
= dividends in the upcoming year
P
o
= current price (a trend of 2 or 3 months)
g = long-term growth expectations
In estimating ”g”, the analyst is not concerned with the rate at which the firm will
actually grow, but rather the long-term growth expectations of the investors. Judgment is
required as past performance cannot be automatically assumed to continue indefinitely.
Changes in market potential, gas supply, competitive pricing, regulation, economic
climate, all have an impact on growth. Investors form their expectations of future growth
by analyzing past performance as a guide to the direction the company is headed. Some
utilities also use the growth projection for their company as found in Value Line
Investment Survey, or other reported analyst estimates. The growth in earnings can be
estimated by analyzing the growth in earnings per share (eps), in dividends per share
(dps), and in net book value per share (nbv) over the past 10 to 15 years.
b. DCF on Comparable Companies
Many gas utilities in Texas are part of diversified energy companies. Their operations
typically include exploration, drilling, production, and transmission, as well as
distribution. The market determined cost of equity for such a company reflects the risks
of all the company's operations combined. The calculation of the cost of equity for the
distribution operations of the company, separate from other company functions, is
frequently difficult. To solve this problem, several of the utilities have recently used the
approach of selecting “pure” distribution companies throughout the country, such as
those used in Moody's Public Utility Manual. A DCF analysis is then conducted on each
company of this group to arrive at an average range for the cost of equity.
c. Capital Asset Pricing Model (CAPM)
The Capital Asset Pricing Model (CAPM) is another widely employed equity valuation
model that bases the equity cost of capital on the relationship between risk and expected
return. The general form of its equation is given as:
K
e
= R
f
+ ∃(R
p
)
Where K
e
= expected rate of return on equity (the utility's cost of equity)
R
f
= the market “risk free” rate
∃ = the stock’s beta coefficient
27
R
p
= the market risk premium
Originally developed to analyze the required rates of returns on assets held in portfolios,
the rationale behind the CAPM is that investors need to be compensated in two ways:
time value of money and risk. The time value of money is represented by the risk-free
(R
f
) rate in the formula and compensates the investors for placing money in any
investment over a period of time. Long-term treasury security rates are typically used to
provide this term in the equation. The other half of the formula represents risk and
calculates the amount of compensation the investor needs for taking on additional risk.
This is calculated by taking a risk measure ∃ (beta) derived from the relative risk of a
particular stock compared to that of the entire market, and then applying this as an
adjustment to the aggregate market risk premium (R
p
). The market risk premium is
typically calculated as an overall market rate of return for some period, minus the risk
free rate. Beta values are calculated and published by investment services and are then
applied to the formula to complete the estimate calculation.
The logical basis of the CAPM has lead to its continued wide use among analysts and in
academia, though its empirical results have been mixed and suggest that the CAPM is a
better concept applied to investment portfolios than individual stocks. Nonetheless,
CAPM remains a useful technique in estimating equity returns.
d. Comparable Earnings
The cost of equity to a public utility has been estimated by comparing the accounting
rates of return earned by other firms on their equity capital over one or more historical
time periods. The formula for this calculation is as follows:
X
it
ROE
it
=
BE
it
Where ROE
it
= return on book equity for firm i in period t
X
it
= net income for firm i in period t
BE
it
= firm i's average book equity in period t
These returns are averaged for each year and then the yearly averages are averaged or
trended to arrive at the utility's cost of equity.
The reasons supporting this type of comparable earnings analysis are:
• The average returns realized by other firms are representative of the
productivity of common equity in the economy, and
• A utility's equity capital must provide comparable returns to compensate
28
existing stockholders and attract additional investors.
The problems with this approach are:
• It assumes that other firms have actually earned, on average, their cost of
equity on net book value and that the required return has not changed
significantly over time.
• It is not a market-oriented concept and fails to recognize the prospective
nature of investors' required returns.
• It is vague in defining comparable risk firms and may result in significant
measurement ambiguities.
• Because it is dependent upon what other regulatory bodies have decided,
significant circularity problems can arise.
• The returns on book equity do not conform to the expected positive
relationship between risk and required returns.
Utilities often include diversified companies in their presentation. Only pure distribution
companies should be used such as those listed in Moody's Public Utility Manual.
3. Adjustments to the Cost of Equity
a. Risk Differences
Cost of equity estimates for the utility division of a diversified energy corporation usually
require a downward adjustment to reflect lower risk in relation to the company's total
risk. The company's full range of operations (distribution, exploration, drilling and
production) generates its total risk. Measuring the relative risk for various operations is
difficult to do with precision. Using a DCF analysis on pure gas distribution companies is
one way to avoid having to make these measurements.
b. Diversification Benefits
Another factor that could reduce the cost of equity for a subsidiary or division of a
diversified energy company is the reduction that comes from the parent company's
reduced risk because of diversification. Known as the “portfolio effect,” it simply means
that, as a company diversifies, it is able to reduce risk, thus lowering the cost of equity.
c. Size
Most of the large diversified companies raise all their capital at the parent company level
since it is less expensive than if each individual subsidiary or division were to attempt to
raise capital on its own. The benefit of having access to financial markets through a large
29
diversified company reduces a gas distribution division's or subsidiary's cost of equity, as
well as its cost of debt. Therefore, a downward adjustment would be in order for utility
companies that obtain capital in this manner.
d. Market-to-Book Ratio
Occasionally, a publicly-traded utility will seek a market-to-book adjustment. For
example, if the market value of its shares is lower than book value during the test year
because of market pressure, the cost of equity may be adjusted to reflect a more typical
test year cost of equity. Thus, the cost of equity provides a basis for determining a fair
return to equity. However, other considerations might warrant an adjustment to this
minimum for the use of capital in an effort to achieve other objectives deemed in the
public interest.
Although issuance and flotation costs may range from 3 to 5 percent, it is likely that the
dilution to existing stockholders' equity from such costs is inconsequential. Finally,
purported market pressure associated with the sale of additional equity could cause the
market price to fall below book value. The Commission staff has attempted to measure
market pressure for one of the large utilities and found that on the average it was of
insufficient magnitude to be measured. However, if the company currently has plans to
issue stock during the expected life of the proposed rates, a market-to-book adjustment
might be in order.
D. S
MALL
U
TILITIES
A lack of market data on smaller utilities makes it difficult to estimate the cost of equity
capital. A good approach for estimating this cost is to use the cost of equity for large
utilities as a benchmark. This can then be applied to the smaller company adjusted for
differences in financial and business risk. Business risk is the uncertainty of revenue and
operating expenses. Financial risk results from using debt and involves the uncertainty of
operating income being high enough to cover the fixed costs of capital.
In assessing financial risk, the capital structure of the utility can be compared to that of
the average pure gas distribution system. Some small utilities may be almost totally debt
or equity financed. A low debt ratio reduces the financial risk and would reduce the cost
of equity, but may raise the overall cost of capital since debt is a less expensive source of
capital. On the other hand, companies with high debt ratios have higher financial risk and
a higher cost of equity. But they probably have a lower overall cost of capital. Reduced
(increased) financial risk would warrant a downward (upward) adjustment in the cost of
equity unless a hypothetical capital structure has been used.
Such factors as company size, degree of diversification, service area, growth
characteristics, reliability of gas supply, and management expertise can influence the
certainty of revenue and expenses and, thus, are business risks. The higher a utility's
business risks, the higher its cost of equity.
30
The usual arguments for a higher cost of equity for small firms are that they have greater
business risk and less liquidity.
E. A
TTRITION AND
E
ROSION
Although the Commission has not granted an allowance for attrition and erosion, many
companies argue that an allowance should be made specifically to cover these problems.
If an allowance for such is granted by the regulatory authority, it should not be included
as part of the cost of capital, but should be a specific increment set out for that purpose.
This will prevent confusion if the higher rate is not actually achieved. Evidence needs to
be obtained to show what the actual effects of attrition and erosion have been and to
distinguish these from revenue requirements based on adjusted figures. Some allowance
would also be needed for any additional revenue that will be derived from expected
future growth.
Attrition may be defined as the utility's inability to earn the authorized rate of return.
This inability may arise from an erosion of company earnings resulting from a
disproportionate change in the revenue-cost-rate base relationship over time.
F. A
DDITIONAL
S
OURCES OF
C
APITAL
Deferred taxes, contributions in aid of construction, customer advances and customer
deposits, if not used as a rate base deduction, are included as a part of the capital
structure.
G.
W
EIGHTED
A
VERAGE
(
OR
C
OMPOSITE
)
C
OST OF
C
APITAL
Once the costs associated with each method of financing that a utility employs is known
or estimated, the utility’s overall cost of capital or rate of return can be calculated through
its weighted average cost of capital (WACC). The WACC multiplies the ratio of each
financial component in the company’s capital structure by its relative cost and then sums
these weighted averages to calculate the overall cost of capital.
Table III - 5 presents a basic example of determining a company's weighted average cost
of capital using a capital structure of long-term debt and common equity with their
associated costs:
T
ABLE
III
-
5
Amount Cost
% of Total
Capitalization
Weighted Avg
Cost
Long Term Debt
$ 33,000
7.25%
55.00%
3.99%
Common Equity $ 27,000
10.50%
45.00%
4.73%
Total $ 60,000
100.00%
8.71%
31
SECTION
3
–
R
ETURN ON
R
ATE
B
ASE
Table III - 6 presents a more complex example of the WACC in the case of a company
that has used multiple forms of financing in its capital structure. As above however, the
method of determining a company's weighted average cost of capital remains the same:
T
ABLE
III
–
6
Original Cost (Table III-3)
$1,000,000
Less: Accumulated Depreciation (Table III-3)
$ (200,000)
Net Original Cost (Table III-3)
$ 800,000
Add: Other Rate Base Items (Table III-3)
$ 500,000
Total Invested Capital (Table III-3)
$1,300,000
Multiplied By: Weighted Avg. Cost of Capital (Table
III-5)
9.83%
Required Monetary Return on Invested Capital
$ 127,790
Divided By: Adjusted Value Rate Base (Table III-3)
$1,620,000
Rate of Return on Adjusted Value Rate Base
7.89%
The monetary return on invested capital, which is equal to a company's demonstrated cost
of capital should be divided by the adjusted value rate base to determine the required rate
of return. Some utilities might take the composite cost of capital and apply it to the
adjusted value rate base instead of the total invested capital to determine a required
monetary return (i.e. apply the 9.83% cost of capital to the $1,620,000 adjusted value rate
base, instead of the $1,300,000 invested capital). It has been the position of the
Commission that this is incorrect, and would yield rates that would be far above a
reasonable return on invested capital and more than a fair return on adjusted value.
As the Supreme Court of Texas in the Southwestern Bell
1
case indicated, a regulatory
authority must establish rates within the general guidelines established by T
EX
.
U
TIL
.
C
ODE
Chapter 104 (i.e. not less than a reasonable return on invested capital or more than
a fair return on the adjusted value rate base). This does not deny that the appropriate rate
base is the adjusted value rate base. It recognizes that the most efficient way to determine
a utility's actual monetary needs is to use market derived cost of capital applied to
invested capital.
1
Southwestern Bell Telephone Co. v. Public Utility Commission of Texas, 571
SW2d 503 (Tex. 1978).
32
SECTION
4
-
REVENUE AND EXPENSES
A utility's net income should equal the required monetary return on the utility's rate base.
Net income is defined in T
EX
.
U
TIL
.
C
ODE
§ 104.055 as the total revenue less all
reasonable and necessary expenses as determined by the regulatory authority.
Only those payments found reasonable are included as expense items. T
EX
.
U
TIL
.
C
ODE
§
104.055 provides the authority for promulgating reasonable rules and regulations with
respect to the allowance or disallowance of certain expenses. Consequently, the
Commission has adopted Commission substantive rules §§ 7.501, 7.5252, 7.115, and
7.5414 for determining revenue and expenses.
A. A
LLOCATION
A
MONG
C
LASSES OF
C
ONSUMERS
The revenue and expenses, which are subject to allocation, fall into two categories: either
they are fixed (non-volume-related) or they are variable (volume-related). Rate base
assets are generally allocated the same as fixed expenses.
Variable revenue and expenses (primarily gas sales revenue and gas costs) are uniformly
allocated according to volume of consumption by each class of consumer during the test
year, with adjustment for weather. See Weather Normalization Adjustment, Chapter
III, Section 5(D)(1)(b). Thus, variable expenses seldom create major problems.
Problems frequently arise, however, in the allocation of fixed assets and expenses.
Several of the more common methodologies are set out below.
1. Peak Demand Allocation
The peak demand methodology allocates fixed assets and expenses according to the
volume consumed by each customer class on the system peak demand day of the test year
(this is called the coincident peak). This method assumes that fixed assets and expenses
are determined by the capacity required to serve all customers during a period of peak
demand.
Other methods can be used to measure and allocate peak demand to different customer
classes. These are referred to as modified peak demand methodologies. For example,
peak demand can be determined based on the non-coincident peak, or the total of the
peak demand experienced by each customer class, regardless of the day incurred. Another
modification of peak demand is calculated using the average of more than one peak
demand day during the test year. This method can moderate the allocation of costs to a
customer class with just one large peak demand.
Since peak demands imposed by residential and small commercial customers are far in
excess of average demands, the larger portion of the rate base is often allocated to
residential and small commercial customers. As a result, a system designed to meet the
needs of these primary customers will necessarily carry a large excess capacity that is
33
seldom used. Some utilities can make this excess capacity available to other customers if
they can use gas on an interruptible basis or are unlikely to need large amounts of gas
during periods of peak residential and commercial demand. Revenue received in this way
can then be used to offset the higher costs allocated to residential and commercial
customers.
2. Volumetric Allocation
According to this method, fixed assets and expenses are simply allocated in the same
manner as variable revenue and expenses. Since the industrial class frequently consumes
the majority of gas by volume, this allocation methodology results in much lower
residential and commercial rates. However, this methodology ignores the role of peak
demand on fixed assets and expenses.
3. 50/50 Seaboard
The 50/50 Seaboard allocation method was developed by the Federal Power Commission
as a way to allocate fixed assets while simultaneously recognizing the volumetric and
peak demand factors. Simply stated, this allocation uses 50 percent of each factor. Either
peak demand or modified peak demand allocation may be used for the peak demand
factor.
4. Modified 75/25 Seaboard
The modified 75/25 Seaboard allocation formula is the same as the 50/50 methodology,
except that 75 percent volume and 25 percent peak demand is used. The reason for this
modification is a policy in favor of conservation. Gas users are more likely to conserve
when they incur a higher per unit cost for gas.
When more obscure allocation formulas are used, the utility should justify their use.
Results should be compared to those outlined above. Remember, no allocation method
results in the only correct result. No matter how precise the calculations included in the
utility's rate justification appear, allocation is a matter of judgment and public policy.
B. R
EVENUE
1. Gas Sales
Most utility revenue come from gas sales. Adjustments to test year gas sales volumes
and prices are typically required. Common adjustments include growth normalization,
weather normalization and rate increase annualization. Revenue also should be adjusted
to reflect the current gas purchase cost above the base rate that is recouped through the
purchased gas adjustment clause.
a. Growth Normalization
34
For consistency when using a year-end test year, book revenue should be adjusted to
show a full year’s billing for all customers receiving service at the end of the test year.
This adjustment is required to match the test year revenue with the year-end investment.
Adjustments are based on actual monthly active customer records when available. If
records are not readily available, Commission policy is to assume that changes in the
number of active customers occurred evenly during the test year.
b. Weather Normalization
Gas sales adjustments are commonly made to account for the net effect of below average
and above average heating degree-days during a test year. The adjustment is computed
by comparing the actual number of heating degree days to the normal heating degree-
days experienced in the area for the test year. Test year gas sales volumes and revenue
are adjusted to reflect a normal heating degree day year.
Normal heating degree-day information is based on U.S. Weather Bureau statistics by
weather station. The data is published monthly with annual information available in the
July issue of Climatological Data, National Oceanic and Atmospheric Administration,
Environmental Data and Information Service, National Climatic Center, Ashville, N.C.
www.ncdc.noaa.gov
c. Rate Annualization
If a utility had a rate increase effective for any customer class during the test year,
revenue should be increased for that class to show the effective rate for the entire year.
d. Purchased Gas Cost Above Base Rate
Revenue should reflect the current gas purchase cost above the base rate that is recouped
through the purchased gas adjustment clause (PGA). The amount should include the
unrecovered balance in any correcting account. This amount should be shown separately.
2. Other Revenue
Other utility revenue includes (a) allowance for funds used during construction
(AFUDC), (b) prompt payment discounts and (c) revenue from non-utility sources.
a. Allowance for Funds Used During Construction (AFUDC)
If a utility includes AFUDC as other income during the test year and the Construction
work in progress (CWIP) account is disallowed, AFUDC should also be removed.
b. Inducement For Prompt Payment
If a utility offers an incentive for prompt bill payment by allowing a discount or charges a
penalty for late payments, an adjustment may be necessary. Penalties collected for late
35
payments should be included under Other Revenue, unless the most current rates in effect
during the test year have no provision for late penalties. No adjustment is required if the
most current rates in effect during the test year eliminate late payment penalties.
c. Revenue from Non-Utility Sources
Under T
EX
.
U
TIL
.
C
ODE
§§ 102.153 and 104.058, no profit or loss resulting from the sale
or lease of appliances, fixtures, equipment or other merchandise shall be considered in
determining utility rates, to the extent that such merchandise is not integral to the
provision of utility service. Commission substantive rule § 7.5252(c) dictates that
revenue from non-utility operations be excluded from ratemaking calculations for gas
utility service unless it is clearly shown to be integral to utility operations.
C. E
XPENSES
Adjustments to expenses consistent with the revenue adjustments associated with gas
sales volumes and prices are typically required in a test year. Common adjustments
include growth normalization, weather normalization and rate annualization. Expenses
also should be adjusted to reflect the current purchase gas cost below the base rate that is
refunded through the purchased gas adjustment clause.
1. Lost and Unaccounted for Gas (LUG)
Commission substantive rule § 7.5525(b)(1) allows a utility to expense a maximum of
five percent (5%) of its lost and unaccounted for gas for distribution systems and three
percent (3%) for transmission systems in a test year. Lost and unaccounted for gas is the
difference between the amounts metered in and out of a system.
All lost and unaccounted for gas is presumed “lost” unless a utility can provide evidence
in a ratemaking proceeding that the unaccounted for gas represented company uses,
liquids extraction or meter errors. The Commission may allow greater than five percent
(5%) lost gas if special circumstances can be shown by the utility.
2. Advertising, Membership Dues and Charitable Contributions
Commission substantive rule § 7.5414(a) dictates that actual advertising expenses are
allowed for ratemaking purposes up to one-half of one percent (0.5%) of the gross
receipts of the utility for public utility services. This encourages utilities to fix leaks.
Certain types of expenses, listed below, are excluded:
• advertising expenses for influencing public opinion related to legislative,
administrative or electoral matters;
• expenses associated with any controversial issue of public importance;
36
• expenses in support of social, recreational, fraternal or religious entities; and
• contributions or donations to charitable, religious or nonprofit entities.
3. Past Regulatory Expense
A utility’s administrative and general expense account may include amortization for past
regulatory expense. If the prior expense will be recouped before the effective date of the
new rate schedule, this amount should be eliminated.
If the prior expense has not been recouped before the effective date of the new rates, the
remaining balance should be added to the present regulatory expense and amortized over
the period of years estimated between rate cases.
Rate case expenses can be included in base rates, but historical Commission policy
indicates that the preferred treatment of rate case expense recovery is as a surcharge, as
discussed in Chapter III, Section 5, Tariffs.
4. Depreciation Expense
Commission substantive rule § 7.5252(a) dictates that straight-line depreciation over the
useful life expectancy of any item or facility is required for ratemaking purposes.
Historical Commission practice has been to disallow depreciation rate adjustments unless
fully supported by a depreciation study. The study should include the average service
lives of the property groups, salvage factors and adequacy of the present booked
depreciation reserve.
If a utility depreciates its assets over a shorter life than allowed by the Internal Revenue
Code, Commission practice has been to adjust the undepreciated cost of the assets over
the longer service life unless supported by a depreciation study.
The methodologies used to compute depreciation expense and accumulated depreciation
in the rate base should be consistent. City of Weslaco v. General Telephone Co. of S.W.,
359 S.W.2d 260 (Tex. Civ. App.-San Antonio, 1962, writ ref'd n.r.e.). Also, the Texas
Supreme Court held that it was proper to exclude any depreciation expense on assets
attributable to contribution in aid of construction. Sunbelt Utilities v. Public Util.
Comm’n, 589 S.W.2d 392 (Tex. 1979).
37
Table III-7 shows a sample computation for straight-line depreciation. Assume a utility has
depreciable assets totaling $1,000,000 and the average estimated useful lives are 10 years.
T
ABLE
III
–
7
Depreciable Assets @ Original Cost $1,000,000
Less: Accumulated Depreciation
(3 years @ $100,000/year)
300,000
Net Book Cost $ 700,000
As shown above, the utility would take an annual depreciation expense of $100,000
each year. Assuming three of the 10 years have elapsed, the utility’s balance sheet
would show a net book cost of $700,000.
If the regulatory authority determined that the correct average service life was 28 years
instead of 10 years, the three elapsed years would be deducted from the 28, resulting in
a remaining useful life of 25 years. Thereafter, the $700,000 net book value would be
divided by 25 for a new annual depreciation expense of $28,000. No adjustment would
be made to the accumulated depreciation account other than the annual credits of
$28,000.
5. Other Taxes
Revenue related taxes should be adjusted consistent with adjustments made to revenue.
6. Other Growth Expenses
If revenue adjustments were made due to increased customer counts during the test year,
corresponding adjustments should be made for the associated incremental expenses
incurred by the utility. Expenses requiring adjustment would include gas sales expense,
information expense and customer accounts and service.
Other expense adjustments may be required where costs have increased or decreased
during the test year to bring these accounts to year-end level.
7. Known Changes
Adjustments for known changes that will occur after the end of the test year are generally
allowed if supporting evidence is presented in a ratemaking proceeding. The evidence
should include a reasonably certain amount and effective date of the change. Two
common examples of reasonably known changes are union contracts and postal rate
increases.
8. Interest on Customer Deposits
If customer deposits have been used as a rate base deduction, the interest expense
associated with the deposits should be included as an adjustment.
38
9. Federal Income Tax Expense (FIT)
If adjusted revenue and expenses for the test year yield a net operating income greater
than zero, a utility is allowed to recoup through an adjustment the federal income tax
owed. Table III - 8 shows a typical FIT calculation.
TABLE III – 8
DESCRIPTION
AMOUNT
TOTAL
Return on Investment
Rate Base at Original Cost (Total Invested
Capital from Table III-3)
$1,300,000
Rate of Return (assumed for this example)
10.15%
Monetary Return on Investment
$131,950
Interest Expense (Cost of Capital)
Rate Base at Original Cost (Total Invested
Capital from Table III-3)
$1,300,000
Weighted Avg. Cost of Capital (Table III-5)
9.83%
Total Interest Expense
$127,790
After Tax Income
$4,160
Gross-up Factor
1.538462
Taxable Income
$6,400
Federal Income Tax Rate
35%
Federal Income Tax Expense
$2,240
The return on investment is calculated by multiplying the rate base at original cost by the
rate of return. Interest expense, computed by multiplying the rate base at original cost by
the weighted cost of debt, is subtracted from the return on investment for the resulting
after tax income. A gross-up factor, computed using (1/(1-tax rate)), is applied to the
after tax income for the resulting taxable income. The applicable federal tax rate is then
applied to the taxable income to arrive at the FIT. The Internal Revenue Service
publishes a range of corporate tax rates for each tax year, so consult a corporate tax
expert or accountant for a utility’s appropriate rate.
For other factors that affect a utility’s taxable income, such as investment tax credits and
the situations described below, consult a corporate tax expert or accountant for the
appropriate adjustment to a utility’s taxable income.
When a utility is part of a larger entity and has a net operating loss, or its allocable
portion of income tax deductions exceed test year income, the taxable income is negative
which results in federal income tax savings to the larger entity. That savings would result
39
in a credit adjustment to test year income.
40
SECTION
5
-
RATES
A. R
EVENUE REQUIREMENT
1. Revenue Deficiency or Surplus
The total revenue deficiency or surplus is determined by subtracting adjusted test year
expenses from revenue. Revenue deficiencies are more common during protested
ratemaking proceedings because utilities can lower their rates by filing new tariffs with
their customers and the Commission without a formal hearing.
A typical example of revenue deficiency is a test year net operating income loss and test
year net operating loss sustained by a utility system that is part of a larger legally taxable
entity.
Table III - 9 shows the test year adjusted net operating income loss calculation.
TABLE III – 9
Total Invested Capital (Table III-3)
$ 1,300,000
Weighted Average Cost of Capital (Table III-5)
x 0.0983
Required Monetary Return (Table III-6)
$ 127,790
Adjusted Net Operating Income (loss)
$ (117,130)
Net Operating Income Deficiency
$ 10,660
Tax Reciprocal
1
0.6175
Gross Revenue Deficiency
$ 17,263
1
Tax Reciprocal
Incremental Revenue
Incremental Occupation Tax
Incremental Street and Alley Rental
Incremental Taxable Income
Incremental FIT at 35% (0.950x0.35)
Incremental Net Operating Income
1.0000
0.0200
0.0300
0.9500
0.3325
0.6175
To calculate the tax reciprocal subtract the revenue sensitive taxes from one. This
remainder, incremental taxable income, is then multiplied by the incremental FIT rate
(which ranges from 15 percent to 38 percent). Subtract the product from the incremental
taxable income to yield the tax reciprocal.
41
B. R
ATE
D
ESIGN
The rate structure of a utility determines how the revenue need will be recovered from
each class and type of service provided by the utility. The rate structure is largely a
matter of preference to be settled by the utility and the regulatory authority.
Rates designed to recover the full cost of providing service to a given customer may be a
desirable objective of rate design. Allocation techniques are extremely imprecise.
Because of the imprecision of allocation techniques, the courts have recognized the
discretion of a regulatory authority in designing rates. Rates do not necessarily have to be
set on the "cost" of providing a service.
A regulatory authority may consider factors other than cost. Those factors must address
whether the resulting rate structure is just, reasonable, and not unduly discriminatory. But
a utility must be consistent and may not arbitrarily alter relevant factors. The burden of
proof of the utility includes the obligation to produce relevant information regarding a
proposed change in rate design. Texas Alarm and Signal Assoc. v. Public Utility
Commission of Texas, 603 5.W.2d 766 (Tex. 1980).
Utility charges are commonly classified as customer related or commodity related. The
customer charge may be considered the minimum amount a customer pays to receive gas
service. This charge may or may not reflect the entire fixed cost of providing the
customer service. It has been argued that a customer charge of a magnitude necessary to
recover all the fixed costs in providing service to the customer would be so large as to be
unacceptable to most consumers.
The second component of the rate, the commodity charge, may be assessed through a
straight line meter rate, a per Mcf (thousand cubic feet) charge for all consumption, or a
block meter rate with increasing or decreasing charges for each block of consumption.
Historically, many utilities have offered declining block rates whereby increased
consumption is billed at decreasing rates per Mcf blocks. However, the declining block
rate schedule discourages conservation.
Rate design is becoming an increasingly important tool for regulatory authorities,
utilities, and customers in implementing energy conservation policies. Effective rate
design options include off-peak pricing and time of day pricing that better match the cost
of producing energy to when it is consumed, incentive rates for alternative sources of
energy, and inverted block rates where increased consumption is billed at increasing rates
per Mcf block.
C. T
ARIFFS
Tariffs set forth the rate that should be collected by the utility for each type of service
provided. A tariff includes all rates and charges collected directly or indirectly by any
public utility for any service, product, or commodity as part of their utility operation.
T
EX
.
U
TIL
.
C
ODE
§ 101.003(12).
42
1. Service Charges
Some utilities have sought approval of service charges for items such as reconnections,
appliance services, yard line replacements and returned checks. Proposed changes in
service charges must be cost justified or based on revenue need.
2. Inducement for Prompt Payment
The Quality of Service Rule, Commission substantive rule § 7.45(4)(B), allows a utility
to offer an inducement for prompt payment of bills by allowing a discount in the amount
of five percent. 16 T
EX
.
A
DMIN
.
C
ODE
§ 7.45(4)(B).
3. Purchased Gas Adjustment (PGA)
A purchased gas adjustment (PGA) clause allows the utility to recover its fuel costs on a
timely basis without the need for a formal rate proceeding. The use of fuel adjustment
clauses has been upheld by the Texas Supreme Court, San Antonio Ind. S. D. v. City of
San Antonio, 550 S.W.2d 262 (Tex. 1977).
The Commission has adopted Commission substantive rule § 7.5519(a) which sets forth
the criteria used by the Commission in determining whether to grant a gas utility a
purchased gas adjustment clause. These factors include but are not limited to: 1) the
ability of the gas utility to control prices for gas purchased as affected by competition and
relative competitive advantage; 2) the probability of frequent price changes; and 3) the
availability of alternative gas supply sources.
Purchased gas adjustment clauses usually include a base cost of gas. Gas cost increases or
decreases from this base are calculated and spread across the amount of gas consumed on
a volumetric basis. In changing this base, a regulator should be certain the base used in
the PGA clause conforms to the base used in base rates.
4. Separate Surcharges
It has become more common in recent years for the regulatory authority to allow utilities
to recover rate case expenses, certain taxes, increases in taxes over what has already been
recognized in the cost of service, or other expenses through a separate surcharge on the
customer’s bill. Reasonable rate case expenses may be included in the expense schedule
in setting the final rates or as a surcharge. A surcharge makes the rate case expenses more
visible and insures that the utility neither over collects nor under collects those costs. The
surcharge should encompass any authorized but unrecovered rate case expenses from
prior dockets. A surcharge has the advantage that rate case expenses may be allocated on
a per customer basis or a per Mcf basis. The size of the surcharge per Mcf and the
accounting convenience of the regulatory authority and the utility should determine
which method is used. The surcharge typically is spread over a period of time to reduce
its impact on ratepayers.
43
Rate case expenses can be collected through a fixed monthly surcharge or a volumetric
surcharge and can be collected for up to three years, although typically the surcharge is
authorized for approximately 12 to 24 months. A fixed monthly surcharge is designed to
recover the rate case expense on a per bill basis. A volumetric surcharge is designed to
recover the rate case expense according to consumption over a specified period of time.
When collected volumetrically, it is preferable to set a fixed rate, collected from specific
customers, with a flexible collection period, since the volumes used to calculate the fixed
rate are estimated volumes. Language such as, “recovered over approximately 24
months” provides assurance to the utility that the full amount of authorized expense will
be recovered.
If a surcharge is authorized, interest on the unrecovered balance may be allowed. Interest
may be calculated monthly, expressed as a monthly percentage (annual interest rate
divided by 12 months) and included in the recovery. Interest calculations should not be
added to the unrecovered balance to prevent the collection of interest on interest. The
Commission, if interest is allowed, will often use the deposit interest rate set annually
each December by the Public Utility Commission.
A surcharge is often collected from all customer classes affected by the rate increase or
rate case. The surcharge may be allocated among the customer classes for an equitable
collection using the same rate design allocation used to set the commodity rate for each
class of customer. A periodic report of the utility’s collection of rate case expense is
required by the Commission for docket compliance. This report can be quarterly, semi-
annual or annual, depending upon the length of time set for collection. Quarterly or
semi-annual is preferred. The report should identify the unrecovered balance, the
collection by class of customer, the volumes used for collection by class of customer, the
interest calculation, if authorized, and the ending balance by month. The terms of the
report should be included in an ordering paragraph of the order.
D. SAMPLE CALCULATIONS FOR REVENUE ADJUSTMENTS
These adjustments attempt to take information from the test year and average and
annualize the information to determine what an average year should look like.
1. GAS SALES REVENUE ADJUSTMENTS
a. CUSTOMER GROWTH ADJUSTMENT
Step 1. For each class of customers, determine the net increase (or decrease) in the
number of customers consuming gas. This step is accomplished by subtracting
the number of customers at the end of the test year from the number of customers
at the beginning of the test year.
Assumption: The test year is the 12-month period ending December 31.
44
Number of customers: January 1 1,000
December 31 1,120
Net Increase 120
Step 2. For each class of customers, determine the number of bills for each month of the
test year. If a detailed bill analysis is available, actual numbers should be utilized.
(A bill analysis should include, among other things, the number of Mcf sold
during each month at each rate block for each class of customers, the number of
bills per month at each rate block for each class of customers, and the respective
dollar amounts relating thereto.) In the absence of a detailed bill analysis, it may
be assumed that the net increase in the number of bills occurred evenly
throughout the test year.
Assumptions: No bill analysis was available, and a proportionate share (i.e. 1/12) of the
net increase in customers occurred at the beginning of each month.
Net annual increase
Net monthly increase =
Number of months
120 customer bills
=
12 months
= 10 bills per month
Adjusted number of bills:
(1) (2) (3) (4) (5) (6)
Month Net Number Cumulative Number
Adjusted
of Monthly of Increase of Bills
Number
the Increase Months In Bills at Jan. 1 of Bills
Year Elapsed (2)x(3) (4)+(5)
January 10 x 1 = 10 + 1,000 = 1,010
February 10 x 2 = 20 + 1,000 = 1,020
March 10 x 3 = 30 + 1,000 = 1,030
April 10 x 4 = 40 + 1,000 = 1,040
May 10 x 5 = 50 + 1,000 = 1,050
June 10 x 6 = 60 + 1,000 = 1,060
July 10 x 7 = 70 + 1,000 = 1,070
August 10 x 8 = 80 + 1,000 = 1,080
September 10 x 9 = 90 + 1,000 = 1,090
45
October 10 x 10 = 100 + 1,000 = 1,100
November 10 x 11 = 110 + 1,000 = 1,110
December 10 x 12 = 120 + 1,000 = 1,120
Step 3. For each class of customers, determine the quantity of gas sold during each month
of the test year. (The month of February will be used as an example)
Assumption: 10,200 Mcf of gas was sold during February.
Step 4. For each class of customers, determine the revenue collected during each month
of the test year.
Assumptions: During the test year, the base rates for this class of customers were as
follows:
1 Mcf or fraction thereof $3.00
All consumption over 1 Mcf $2.50 per Mcf
Also, revenue passed through the purchased gas adjustment clause during the
month of February equaled $0.25 per Mcf.
Revenue collected during February:
( 1,020 Mcf) ($3.00 per Mcf) = $ 3,060
2
( 9,180 Mcf) ($2.50 per Mcf) = $22,950
3
(10,200 Mcf) ($0.25 per Mcf) = $ 2,550
4
$28,560
Step 5. For each class of customers, determine the average number of Mcf per bill for
each month of the test year.
Average number of Mcf per bill for February:
Consumption during February 10,200 Mcf
2
Since there were 1,020 bills during the month of February (See #2 above), each
bill included at least some consumption under the first rate block. Consequently,
consumption under the first rate block equaled 1,020 Mcf (1,020 bills x 1 Mcf per bill).
3
Since there were only two rate blocks, gas not consumed under the first block
must have been consumed under the second. (10,200 Mcf - 1,020 Mcf consumed under
the first block = 9,180 Mcf consumed under the second block.)
4
The dollar amount passed through the purchased gas adjustment clause was
expressed on a per Mcf basis and applied to all Mcf consumed during the month of
February.
46
= = 10 Mcf per bill
Number of Bills during February 1,020 bills
Step 6. For each class of customers, determine the average revenue per Mcf for each
month of the test year.
Average revenue per Mcf for February:
February Revenue $28,560
= = $2.80 per Mcf
February Consumption 10,200 Mcf
Step 7. For each class of customers, determine the number of additional bills which
would have been issued during each month of the test year. This step is
accomplished by subtracting the adjusted number of bills per month from the
number of bills at the end of the test year.
Number of additional bills per month:
(1) (2) (3) (4)
Month Number Adjusted Number
of the of Bills at Number of Additional
Year Year End of Bills Bills
______ ________ ________ (2)-(3)
January 1,120 - 1,010 = 110
February 1,120 - 1,020 = 100
March 1,120 - 1,030 = 90
April 1,120 - 1,040 = 80
May 1,120 - 1,050 = 70
June 1,120 - 1,060 = 60
July 1,120 - 1,070 = 50
August 1,120 - 1,080 = 40
September 1,120 - 1,090 = 30
October 1,120 - 1,100 = 20
November 1,120 - 1,110 = 10
December 1,120 - 1,120 = 0
Step 8. For each class of customers, determine the average number of additional Mcf that
would have been sold during each month of the test year if all of the customers
were on the system the whole year.
Average number of additional Mcf sold during February:
(Average number of Mcf per bill) x (Number of Additional Bills) =
(10 Mcf per bill) x (100 bills) = 1,000 Mcf
47
Step 9. For each class of customers, determine the monthly revenue adjustment for each
month of the test year.
Monthly revenue adjustment for February:
(Average monthly revenue per Mcf) x (Average number of additional Mcf sold during
month) = ($2.80 per Mcf) x (1,000 Mcf) = $2,800
Step 10. For each class of customers, add the 12 monthly revenue adjustments
(Step #9 above) to arrive at the total adjustment to revenue to account for growth.
Assumptions: Test year revenue (unadjusted) $430,000
Total growth adjustment 21,000
Test year Revenue adjusted for growth $451,000
b. WEATHER NORMALIZATION ADJUSTMENT
(All figures should have already been adjusted for customer growth)
Step 1. Determine the quantity of gas sold and amount of revenue collected during the
test year.
Quantity of gas actually sold during test year 100,000 Mcf
Adjustment for growth (Assumed) 10,000 Mcf
Adjusted quantity of gas 110,000 Mcf
Revenue collected during test year $430,000
Adjustment for growth 21,000
Adjusted revenue (See Step #10 above) $451,000
Step 2. Ascertain those months during which no Heating Degree Days (HDDs)
occurred:
Assumption: No Heating degree-days occurred during the months of June, July and
August. Heating Degree Days occurred during all other months of the test
year.
Step 3. Determine the average monthly base load quantity and revenue for the relevant
period, i.e., June, July and August.
Base Load Base Load
Month Quantity Revenue
June 6,400 Mcf $26,240
July 6,000 Mcf 24,600
48
August 5,900 Mcf 24,190
Totals 18,300 Mcf $75,030
18,300 Mcf
Average monthly quantity =
(Base Load) 3 months
= 6,100 Mcf per month
$75,030
Average monthly revenue =
(Base Load) 3 months
= $25,010 per month
Step 4. Annualize the average monthly base load quantity and revenue amounts by
multiplying each figure by 12.
Annual base load quantity:
(Average monthly base load quantity) x (12 months) =
(6,100 Mcf per month) x (12 months) = 73,200 Mcf
Annual base load revenue:
(Average monthly base load revenue) x (12 months) =
($25,010 per month) x (12 months) = $300,120
Step 5. Determine the heating load by subtracting the annual base load quantity from the
adjusted quantity of gas sold during the test year (See #1 above).
Adjusted quantity of gas 110,000 Mcf
Annual base load quantity 73,200 Mcf
Heating Load 36,800 Mcf
Step 6. Determine the number of Heating Degree Days actually experienced during the
test year. The source is the National Oceanic and Atmospheric Administration
National Climatic Center, Ashville, N.C.
Assumption: Test year HDDs = 4,872
Step 7. Ascertain the number of HDDs normally experienced in the area.
Assumption: Normal HDDs = 4,800
49
Step 8. Determine the HDD Factor by dividing the normal HDDs into the test year
HDDs.
Test year HDDs
HDD Factor = --------------------
Normal HDDs
4,872 HDDs
= ----------------
4,800 HDDs
= 1.015
5
Step 9. Determine the Adjusted Heating Load by dividing the HDD Factor into the
Heating Load.
Heating Load
Adjusted Heating Load =
HDD Factor
36,800 Mcf
=
1.015
= 36,256 Mcf
Step 10. Determine the Mcf adjustment for normal weather by subtracting the
Heating Load from the Adjusted Heating Load.
Mcf adjustment: Adjusted Heating Load 36,256 Mcf
Heating Load -36,800 Mcf
Adjustment -544 Mcf
6
Step 11. Determine the heating load revenue by subtracting annual base load
revenue from adjusted test year revenue.
Heating load revenue:
5
Since the HDD Factor is greater than one, weather during the test year was
colder than normal. If actual weather had been warmer than normal, the resulting HDD
Factor would be less than one.
6
Since this is a negative number, the adjustment will involve a reduction in test
year volumes.
50
Adjusted test year revenue $451,000
Annual Base Load Revenue -$300,120
Heating Load Revenue $150,880
Step 12. Determine the average revenue per heating load by dividing the heating
load into the heating load revenue.
Heating load revenue
Average revenue per heating load: =
Heating Load
$150,880
=
36,800 Mcf
= $4.10 per Mcf
Step 13. Determine the weather normalization adjustment by multiplying the Mcf
adjustment by the average revenue per heating load.
Weather normalization adjustment:
(-544 Mcf) x ($4.10 per Mcf) = -$2,230
Step 14. Adjust test year revenue to normalize for weather.
Test year revenue $430,000
Adjustment for growth $ 21,000 $451,000
Adjustment for weather $ -2,230
Adjusted test year revenue $448,770
c. RATE ANNUALIZATION ADJUSTMENT
(All figures already should have been adjusted for customer growth and weather)
Step 1. For each class of customers, ascertain whether any rate increase took place during
or after the test year.
Assumption: An increase in residential rates occurred during the test year.
Step 2. Determine the adjusted quantity of gas sold during the test year. (This figure
should reflect the growth and weather adjustments.)
Assumption: 100,000 Mcf of gas was sold during the test year to residential customers.
After a 10,000 Mcf upward adjustment for growth and a 544 Mcf
downward adjustment for weather, the adjusted sales quantity equaled
109,456 Mcf.
51
Step 3. Determine the rates applicable at the end of the test year (or later, if applicable).
Assumption: Residential rates at the end of the test year were as follows:
1 Mcf or fraction thereof $5.00
All consumption over 1 Mcf $4.10 per Mcf
Also, revenue passed through the purchased gas adjustment clause during the last month
of the test year was $0.28 per Mcf. This is the amount by which the current cost of gas
exceeded the base cost.
Step 4. Multiply the adjusted quantity of gas (See Step #2 above) by the current rate (See
Step #3 above) to arrive at test year revenue adjusted for growth, weather, and a
change in rates.
Assumption: Number of bills for test year = 13,440 (1,120 bills per month x 12
months).
Annual Consumption at 1st Block:
(13,440 bills) x (1 Mcf per bill) = 13,440 Mcf
Annual Consumption at 2nd Block:
(109,456 total Mcf*) - (13,440 Mcf at 1st Block) = 96,016 Mcf
* See Step #2 above
Adjusted Revenue:
1st Block: ( 13,440 Mcf) x ($5.00 per Mcf) = $ 67,200
2nd Block: ( 96,016 Mcf) x ($4.10 per Mcf) = $393,666
PGA Clause: (109,456 Mcf) x ($0.28 per Mcf) = $ 30,648
$491,514
The $491,514 figure represents test year revenue from residential gas sales after
adjustment for growth, weather, and increased rates.
2. PURCHASED GAS EXPENSE ADJUSTMENTS
a. CUSTOMER GROWTH ADJUSTMENT
Step 1. For each class of customers, determine the average number of additional Mcf that
would have been sold during each month of the test year with the higher number
of customers. (This calculation was performed in Step #8 of the growth
adjustment to revenue - Ch.III, Sec. 5(D)(1)(a)).
52
Average number of additional Mcf sold during the month of February = 1,000 Mcf
Step 2. For each class of customers, determine the monthly weighted average cost of gas
on a per Mcf basis by dividing the monthly purchases of gas into the monthly purchased
gas expense (Assumed to be $27,600 for February). February purchased gas expense
$27,600
= = $2.50 per Mcf
February purchases 11,040 Mcf
Step 3. For each class of customers, multiply the average number of additional Mcf that
would have been sold during each month with the higher number of customers
(Step #1 above) by the purchased gas expense for that month (Step #2 above) to
arrive at the monthly adjustment.
February Adjustment = (1,000 Mcf) x ($2.50 per Mcf) = $2,500
Step 4. For each class of customers, add the 12 monthly expense adjustments to arrive at
the total purchased gas expense growth adjustment.
Assumption: The sum of the 12 monthly expense adjustments is $27,500.
Step 5. For each class of customers, add the purchased gas expense growth adjustment to
test year purchased gas expense.
Assumption: Purchased gas expense (unadjusted) for gas sold to this class of customers
was $300,000.
Test year purchased gas expense (unadjusted) $300,000
Purchased gas expense growth adjustment $ 27,500
Purchased gas expense adjusted for growth $327,500
b. WEATHER NORMALIZATION ADJUSTMENT
(All figures already should have been adjusted for growth)
Step 1. Determine the Mcf adjustment for normal weather (This calculation was
performed in Step #10 of the weather normalization adjustment to revenue - Ch
III, Sec.5(D)(1)(b)).
Mcf adjustment = -544 Mcf
Step 2. Determine the average purchase price per Mcf by dividing the quantity of gas sold
during the test year into the amount spent to purchase that gas.
53
Test year purchased gas expense $327,500
= = $2.98 per Mcf
(rounded)
Test year sales 110,000 Mcf
Step 3. Multiply the Mcf adjustment (Step #1 above) by the average purchase price (Step
#2 above) to arrive at the weather normalization adjustment to the purchased gas
expense.
(Mcf adjustment) x (Average purchase price) = (-544 Mcf) x ($2.98 per Mcf) = -$1,621
(rounded)
Step 4. Make the weather normalization adjustment to purchased gas expense.
Test year purchased gas expense $300,000
Adjustment for growth $+27,500
$327,500
Adjustment to normalize for weather $ -1,621
Purchased gas expense adjusted for growth and weather $325,879
c. ADJUSTMENT TO REFLECT CHANGE IN BASE COST
OF GAS
Step 1. Determine whether or not the base cost of gas will be changed. If a change will
occur, identify the new base cost of gas.
Assumption: Base cost of gas will be increased from $3.00 per Mcf to $3.28 per Mcf,
which is the latest weighted average cost of gas.
Step 2. Determine the adjusted quantity of gas sold during the test year. This amount was
calculated in Step #2 of the adjustment to revenue to annualize a rate increase.
Ch.III, Sec. 5(D)(1)(c).
Adjusted sales quantity = 109,456 Mcf
Step 3. Determine the adjustment to reflect the change in the base cost of gas as follows:
Adjustment = (adjusted sales quantity) x (per Mcf increase in base cost)
= (109,456 Mcf) x ($0.28 per Mcf)
= $30,648
Step 4. Make the adjustment to reflect the change in the base cost of gas as
follows:
54
Purchased gas expense adjusted for
growth and weather $325,879
Adjustment to reflect change in
base cost of gas $ 30,648
Adjusted purchased gas expense $356,527
d. LOST AND UNACCOUNTED FOR GAS ADJUSTMENT
Assumption: Quantity of gas metered into the system was 252,890 Mcf
Quantity of gas sold was 228,659 Mcf
Step 1. Determine the quantity of gas used by the utility for authorized company use.
Assumption: The Company showed that 4,000 Mcf had been consumed for company
use, and the regulatory authority approved this quantity.
Step 2. Determine the percentage allowance for lost and unaccounted for gas. The
Railroad Commission typically allows five percent for a distribution system.
Step 3. Determine the quantity of gas representing lost and unaccounted for gas for the
most recent twelve-month period ending June 30 as follows:
(Quantity of gas metered into the system) - (Quantity of gas sold) -
(Quantity of company used gas)
= (252,890 Mcf) - (228,659 Mcf) - (4,000 Mcf)
= 20,231 Mcf
Step 4. Determine the percentage of lost and unaccounted-for gas experienced by the
Company as follows:
20,231 Mcf
= 8% (rounded)
252,890 Mcf
Step 5. Since the eight percent lost and unaccounted for gas percentage experienced by
the Company exceeded the five percent ceiling established by the regulatory
authority, the five percent allowance should be calculated as follows:
(Quantity of gas metered in) x (5%)
= (252,890 Mcf) x (0.05)
= (12,645 Mcf (rounded))
Step 6. Determine the lost and unaccounted for gas adjustment as follows:
55
(Excess lost and unaccounted for gas) x (Adjusted base cost of gas)
= (12,645 Mcf) x ($3.28 per Mcf)
= $41,476
Step 7. Make the adjustment for lost and unaccounted for gas as follows:
Purchased gas expense as adjusted for growth,
weather, and change in base cost of gas $356,527
Adjustment for lost and unaccounted for gas $ 41,476
Total adjusted purchased gas expense $398,003
3. PURCHASED GAS ADJUSTMENT (PGA) CLAUSE
a. LOST AND UNACCOUNTED FOR GAS ADJUSTMENT
FACTOR
A typical purchased gas adjustment (PGA) clause will include a factor to reflect an
allowance for lost and unaccounted for gas. This factor may be calculated by using the
following formula:
Factor = 1 + (Percentage Allowance) x (Adjusted Purchased Gas Expense)
Adjusted sales revenue
= 1 + (0.05) x ($803,284)
$1,000,000
7
= 1 + $ 40,164
$ 1,000,000
= 1.0402 (rounded)
b. ADJUSTMENT TO INCREASE BASE OF PGA CLAUSE
Where a percent adjustment to present base rates is the preferred method of arriving at a
new rate schedule, the base of the PGA clause is increased as follows:
1. Determine the new base of the PGA clause (usually the most current cost
of gas).
7
The $1,000,000 was assumed to be the adjusted sales revenue from all classes of
customers.
56
2. Determine the difference between the present base and the new base.
3. Multiply the difference determined in Item 2 times the number of Mcf sold
during
the test year, as adjusted for growth, weather, etc.
4. Add the amount determined in Item 3 to the revenue deficiency before
making the
percent adjustment to the base rates.
Where a new rate schedule is to be designed, simply determine the new base for the PGA
clause and adjust revenue and expenses accordingly. No additional steps are required.
The base of the PGA clause must equal the cost of gas incorporated into the base rates.
The Commission encourages the inclusion of all gas cost in the PGA and discourages the
inclusion of any gas cost in service rates. This improves transparency by isolating the
various components of a natural gas bill, separating the cost of service from the cost of
gas.
57
CHAPTER IV.
BEFORE THE COMMISSION
SECTION
1
-
P
ROCEDURES ON
A
PPEAL FROM
C
ITY
The Railroad Commission of Texas has exclusive appellate jurisdiction over rates set by
cities. T
EX
.
U
TIL
.
C
ODE
§ 102.001(b). A party to a rate proceeding before a
municipality’s governing body may appeal the governing body’s decision to the
Commission.
T
EX
.
U
TIL
.
C
ODE
§ 103.051. The residents of a municipality may appeal to
the Commission the decision of the municipality’s governing body in a rate proceeding
by filing with the Commission a petition for review signed by a number of qualified
voters of the municipality equal to at least the lesser of 20,000 or 10 percent of the
qualified voters of the municipality. T
EX
.
U
TIL
.
C
ODE
§ 103.052. The ratepayers of a
municipally owned utility who are outside the municipality may appeal to the
Commission an action of the municipality’s governing body affecting the municipally
owned utility’s rates by filing with the Commission a petition for review signed by a
number of ratepayers served by the utility outside the municipality equal to at least the
lesser of 10,000 or five percent of those ratepayers. A petition for review is properly
signed if signed by a person or the spouse of a person in whose name residential utility
service is carried. For purposes of determining ratepayers, each person who receives a
separate bill is a ratepayer. A person who receives more than one bill may not be counted
as more than one ratepayer. T
EX
.
U
TIL
.
C
ODE
§ 103.053.
A. R
EPRESENTATION
Parties may represent themselves in a proceeding or may appear through any person
authorized by the parties to represent them. Commission general rule § 1.65.
B. F
ILING OF
D
OCUMENTS
Two copies of all pleadings initiating a proceeding shall be filed with the Director of the
Oversight and Safety Division. Once the proceeding is docketed and a hearings examiner
is assigned, two copies of all other pleadings and documents shall be filed with the
Docket Services Section of the Office of General Counsel. Commission rules §§ 1.24
and 7.2. Pleadings and other documents filed with the Office of General Counsel shall be
deemed filed only when they are actually received by the Docket Services Section of the
Commission’s Office of General Counsel. Pleadings filed after 5:00 p.m. local time of
the commission shall be deemed filed the first day following that is not a Saturday,
Sunday, or official state holiday. Commission general rule § 1.24. Normal business
hours are from 8:00 a.m. to 5:00 p.m. Monday through Friday, excluding State holidays.
Commission general rule§ 7.201. See Commission rules §§ 1.22 -1.29 for classification,
form, and content of pleadings. Documents may be filed in person or mailed to:
58
Director Docket Services
Oversight and Safety Division Office of General Counsel
Railroad Commission of Texas Railroad Commission of Texas
P.O. Box 12967 P.O. Box 12967
Austin, Texas 78711-2967 Austin, Texas 78711-2967
Steps in a Rate Case
Step Action _____ Timeline
1 Utility files Statement of Intent 35 days before effective date.
to increase rates with the city T
EX
.
U
TIL
.
C
ODE
§ 104.102(a).
2 City holds hearing, adopts or rejects proposed Upon complaint by an affected
rates. T
EX
.
U
TIL
.
C
ODE
§§ 103.021-103.022. person, hearing must be entered on
within 30 days after the
effective date of the increase.
T
EX
.
U
TIL
.
C
ODE
§ 104.105(a).
3 A party to the city’s proceeding, the residents Not later than the 30
th
day
of the municipality, or the ratepayers outside of after the date of the final
the municipality may appeal to the governing decision by Commission
body of the municipality. filing a petition for review.
T
EX
.
U
TIL
.
C
ODE
§ 103.054(b). T
EX
.
U
TIL
.
C
ODE
§§ 103.051-
103.054; Commission rule § 7.5.
4 Commission holds a hearing.
5 Commission Hearings Examiner issues Within 60 days after the
Proposal for Decision (PFD). hearing is Finally closed.
Gov’t Code 2001.143
6 Exceptions and Replies are filed. Exceptions: within 15 days
after the date of service of a PFD.
Replies: within 10 days after the
deadline for filing Exceptions.
Commission general rule §
1.142(a).
7 Railroad Commission issues Order. Within 185 days after the date
the appeal is perfected, or the
utility’s proposed rates are
considered approved.
T
EX
.
U
TIL
.
C
ODE
§ 103.05.
59
8 Motions for rehearing. Within 20 days after the date
the final decision or order.
Commission general rule §
1.149.
9 Appeals to the Courts. Not later than the 30
th
day
T
EX
.
U
TIL
.
C
ODE
§ 103.024 & 105.001. after the date on which the
Commission’s decision is
final and appealable.
T
EX
.
G
OV
’
T
C
ODE
§
2001.176.
C. M
OTIONS
Under Commission general rule § 1.27, all motions, unless dictated into the record, must
be in writing. All motions must set forth the relief sought and the reasons therefore. If
based on alleged facts that are not a matter of record, the motion may be supported by an
affidavit. Motions shall be served on all parties in accordance with Commission general
rule § 1.48.
D. C
OMPUTATION OF
T
IME
In computing any period of time, the day from which the period of time begins to run
shall not be included, but the last day of the period being computed shall be included. The
period ends at 5:00 p.m. on the last day of the period unless the last day falls on a
Saturday, Sunday, or State holiday, in which case the period ends on the next State
working day. Commission general rule § 1.8.
E. P
OSTPONEMENTS
,
C
ONTINUANCES AND
E
XTENSIONS OF
D
EADLINES
The time for filing any pleading or other document may be extended upon the granting of
a motion for extension of time. Except for good cause shown, the motion shall be filed
with the Examiner or the Commission prior to the applicable deadline. The motion shall
show that there is good cause for an extension of time and that the need for the extension
is not caused by the negligence, indifference, or lack of diligence of the person filing the
motion. A copy of the motion must be served upon all parties of record
contemporaneously with its filing. Commission general rule § 1.8(b).
Motions for continuance of a hearing must be in writing and filed not less than five days
prior to the hearing, except for good cause shown. Motions must set forth specific
grounds for which the moving party seeks continuance, shall make reference to all similar
motions filed in the proceeding, and shall state whether all parties agree with the relief
requested. Continuances will not be granted based on the need for discovery if discovery
requests have not previously been served upon the person from whom discovery is
sought, except when necessary due to surprise or discovery of facts or evidence
previously undisclosed despite the diligence of the moving party. Commission general
rule § 1.124.
60
F. E
X
P
ARTE
C
ONSULTATION
No person, party or representative may communicate, directly or indirectly, with any
member of the Commission or the Examiner concerning any issue of fact or law, except
on notice and opportunity for each party to participate. Commission general rule § 1.6;
T
EX
.
G
OV
’
T
C
ODE
§ 2001.061.
G. I
NTERVENTIONS AND
P
REFILED
T
ESTIMONY
Any person who has a justifiable or administratively cognizable interest wishing to be
designated as a party in a contested case may file a petition for leave to intervene at least
five days prior to the hearing date. Commission rule § 1.64. The Examiner may require
or permit written testimony and exhibits to be filed and served on all parties at a specified
date prior to the hearing. Commission general rule § 1.105.
H. D
ISCOVERY
The parties are encouraged to promptly engage in informal discovery. Reasonable
requests and cooperation should characterize prehearing discovery. Each party is
expected to make an effort to provide information requested by other parties in a timely
manner. Discovery may be in the form of oral depositions, written interrogatories,
requests for admission of facts or identity of documents, requests for production,
examination, and copying of documents and other materials, and requests for entry upon
and examination of property. Commission general rule § 1.81(a); Texas Rules of Civil
Procedure (TRCP) Rule § 192.1. The scope of discovery is the same as that provided by
the TRCP. Commission general rule § 1.81(b); TRCP Rule § 192.3.
The Examiner may issue discovery orders such as protective orders and orders
compelling discovery responses when necessary. Requests for discovery orders shall
contain a statement under oath or affirmation that, after due diligence, the desired
information cannot be obtained through informal means, and that good cause exists for
requiring discovery. Commission general rule § 1.85(b). Also see the Administrative
Procedures Act (APA), T
EX
.
G
OV
’
T
C
ODE
§ 2001.090. The Commission or the
Examiner may also issue sanctions against a party that fails to comply with a discovery
order. Commission general rule § 1.85(c).
I. A
LIGNMENT OF
P
ARTIES
Parties with common interests or positions in a proceeding may make a joint presentation,
including oral representation, presentation of evidence and briefing, if desired. Parties
intending to align should promptly notify the Examiner and other parties. However,
alignment will not prejudice the right of any party to present a separate point of view
where their position differs from that of the group with which they are aligned. The
Examiner may align the parties if they fail to align themselves. Commission general rule
§ 1.61.
61
J. C
ONSOLIDATION
When two or more applications, petitions, or other proceedings involve common
questions of law or fact, the Commission, Legal Division director, or the examiner may
consolidate the proceedings or direct that there be a joint hearing without formal
consolidation and may take other action to avoid unnecessary costs or delay and to ensure
due process. Commission general rule § 1.125.
K. S
TIPULATIONS
The parties should stipulate to issues whenever possible. Stipulations, other than those
made at the hearing, should be in writing and signed by all parties. Commission general
rule § 1.123.
L. O
BJECTIONS TO
P
REFILED
T
ESTIMONY
If the Examiner allows them, written objections and responses to objections to prefiled
testimony may be filed with Docket Services prior to the date of the hearing. If an
objection is made either prior to or during the hearing, the Examiner may rule at that time
or reserve ruling on the objection.
M. P
REHEARING
C
ONFERENCE
The Examiner may schedule a prehearing conference. At the conference, the parties or
their representatives should be prepared to discuss procedural and substantive matters
involved in the proceeding, and should be authorized to make commitments. The
conference may concern motions, settlement, the amendment of pleadings, admissions or
stipulations which will avoid the unnecessary introduction of evidence, limitations on the
number of witnesses, time to be allotted to each party for presentation of its direct case or
for cross-examination at the hearing, hearing procedure, and any other matter that will
equitably expedite the proceeding. The Examiner may notify the parties in writing of the
disposition of and rulings made on all matters considered at the prehearing conference.
Commission general rule § 1.122.
N. C
OURT
R
EPORTER AND
T
RANSCRIPT
When requested by the Commission, the Examiner, or a party, a court reporter will be
present at the hearing to record and transcribe the hearing. Commission general rule §
1.129. Anyone may obtain a copy of the transcript at set rates by making arrangements
with the reporter.
O. O
RDER OF
P
ROCEDURE AT
H
EARING
The Hearings Examiner will open the hearing with a statement of the scope and purpose
of the hearing. The Examiner will then request appearances for the record by all parties.
62
Thereafter, parties may make motions or opening statements. Commission general rule §
1.128(a).
Following opening statements, if any, each party will be allowed to proceed with their
direct case. The petitioner, applicant, or complainant shall be entitled to open and close.
The Examiner will determine at what stage intervenors shall be permitted to offer
evidence. The Examiner may direct that closing argument be made in writing. The
Examiner may alter the order of procedure if necessary for efficient conduct of the
hearing. Commission general rule § 1.128(b).
P. E
VIDENCE
The rules of evidence as applied in non-jury cases in the Texas District Courts shall be
followed. Commission general rule § 1.101. A witness may adopt their prefiled
testimony, which may be entered into the record without the written testimony being
read. A witness who is offering written testimony shall be sworn and shall identify the
written testimony as a true and accurate representation of what the testimony would be if
the witness were to testify orally, after which the witness shall submit to voir dire and
cross-examination. Written testimony shall be subject to the same evidentiary objections
as oral testimony. Commission general rule § 1.105.(a).
Q. O
BJECTIONS
M
ADE AT
H
EARING
Objections made at the hearing should be sufficiently specific so that the Examiner may
know what action the objecting party desires and the basis of the objection. Unless
requested by the Examiner, supporting statutes and cases need not be cited, but a party
should feel free to do so if such inclusions would be helpful.
R. D
OCUMENTARY
E
VIDENCE
A copy or excerpt of a document may be admitted as evidence if the original is not
readily available and if authenticity is established by competent evidence. When
numerous documents are offered, the Examiner may limit those admitted to a number of
documents which are typical and representative. The Examiner may require the
abstracting or summarizing of relevant data from documents and the presentation of
abstracts or summaries in exhibit form. All parties shall have the right to examine the
documents abstracted or summarized. Commission general rule § 1.104. See Texas
Rules of Evidence (TRE) rule 1005. For example, summaries of business records are
admissible if the underlying records are admissible business records. Purolator Corp. v.
Railroad Commission, 548 S.W.2d 486, 489 (writ ref'd n.r.e.); TRE 1006.
S. O
FFICIAL
N
OTICE
The Examiner may take official notice of judicially heard and determined (cognizable)
facts and generally recognized facts within the area of the Commission's specialized
knowledge. Commission general rule § 1.102. Matters contained within the
63
Commission's records are considered to fall within the area of agency expertise and are
therefore officially cognizable. Texas Administrative Procedures Act (APA), T
EX
.
G
OV
’
T
C
ODE
§ 2001.090.
T. E
XPERT
T
ESTIMONY
If scientific, technical, or other specialized knowledge will assist the trier of fact to
understand the evidence or to determine a fact in issue, a witness qualified as an expert
by knowledge, skill, experience, training, or education may testify thereto in the form of
an opinion or otherwise. TRE 702.
U. P
RESERVATION OF
E
XCLUDED
E
VIDENCE
If an exhibit is identified, objected to, and excluded, the examiner may determine whether
or not the party offering the exhibit wishes to withdraw the offer; if so, the examiner shall
permit the return of the exhibit to the party. If the excluded exhibit is not withdrawn, it
shall be given an exhibit number for identification, shall be endorsed by the examiner
with the ruling, and shall be included in the record for the purpose of preserving an
exception. Commission general rule § 1.106(c).
When the Examiner excludes testimony, the party offering the evidence shall be
permitted to make an offer of proof prior to the close of the hearing. The party may make
the offer by dictating or submitting in writing the substance of the proposed testimony or
by perfecting a bill of exceptions as in civil trials. The Examiner may direct the manner
in which the offer is made and may ask questions if necessary to conclude that the
evidence would be as represented. The Examiner and opposing parties shall be entitled
to cross-examine any witness testifying on a bill of exceptions and to develop evidence
on the bill. The Examiner may direct that bills of exception be transcribed separately and
that reporter’s costs be assessed against the proponent of the bill, subject to Commission
review of the Examiner’s ruling. Commission general rule § 1.108.
V. B
RIEFS
,
C
LOSING
S
TATEMENTS
,
AND
R
EPLY
B
RIEFS
The Examiner may require submission of briefs on legal issues at any time. After the
hearing, the Examiner may require written closing statements or briefs, and written
responses to closing statements, before closing the record.
W. L
ATE
-F
ILED
E
XHIBITS
No exhibit shall be filed after the hearing has been completed, unless specifically
requested and permitted by the Examiner. If the filing of a late-filed exhibit is permitted,
copies shall be served on all parties of record, who will have the opportunity to respond
and submit additional relevant responsive evidence. Commission general rule § 1.106(d).
X. P
ROPOSAL FOR
D
ECISION
,
E
XCEPTIONS AND
R
EPLIES
64
If a majority of the Commissioners have not heard the case or read the record, the
decision, if adverse to a party other than the Commission, may not be made until a
Proposal for Decision (PFD) is served on the parties and an opportunity is afforded to
each party adversely affected to file exceptions and present briefs to the Commission.
The parties may waive the PFD requirement by written stipulation. Commission general
rule § 1.141(a). Any party may file exceptions to the PFD within 15 days after the date of
service of the PFD. Replies to such exceptions may be filed within 10 days after the
deadline for filing such exceptions. Commission general rule § 1.142(a).
Y. N
OTIFICATION OF
O
PEN
M
EETING
After the PFD is issued and exceptions and replies are filed, the Examiner will schedule
the docket for consideration by the Commission at open meeting. The parties will be
notified of the open meeting date through publication in the Texas Register. Parties will
be notified by mail of any order issued by the Commission.
Z. O
RAL
A
RGUMENT
Any party may request oral argument before the Commission prior to the final disposition
of any proceeding, but oral argument will be allowed only at the discretion of the
Commission. A request for oral argument may be made by separate pleading or may be
included in a party’s exceptions, reply to exceptions, brief, or motion for rehearing.
Commission general rule § 1.144.
AA. E
FFECTIVE
D
ATE
The effective date of a final decision or order, unless otherwise stated, is the date of
Commission action, and the effective date shall be incorporated into the body of the
decision. Commission general rule § 1.147.
BB. M
OTIONS FOR
R
EHEARING
A Motion for Rehearing must be filed by a party within 20 days after the date the party or
its attorney of record is notified of the final decision or order. Commission general rule §
1.149(a).
65
CHAPTER V.
INTERIM RATE ADJUSTMENT
SECTION 1 - B
ACKGROUND
A. I
NTERIM
R
ATE
A
DJUSTMENT
R
ULE
(IRA)
On December 24, 2004, the Commission created a rule (§7.7101 of T
EX
.
A
DMIN
.
C
ODE
)
to implement T
EX
.
U
TIL
.
C
ODE
§104.301, which was enacted by the 78th Legislature.
These statutory and rule provisions promote investment in infrastructure that will
improve the reliability and safety of the Texas natural gas system. Previously, the only
way for a utility to increase its rates was to file with the Commission a formal Statement
of Intent rate package, including a comprehensive cost of service rate case. This is
sometimes referenced as “traditional” rate making. Now, the IRA statute and rule allow a
gas utility to apply with the regulatory authority for an adjustment to its base rates to
recover the cost of new infrastructure investment made by a utility since its last
comprehensive rate case. When a utility applies for an interim rate adjustment, it is not
required to submit a comprehensive rate package demonstrating the reasonableness of its
cost of service.
The IRA allows a gas utility to file a tariff or rate schedule reflecting an adjustment to its
rates to recover the cost of new investment in its infrastructure made since the
Commission's most recent order setting rates. Through the interim rate adjustment, a
utility may recover its return on investment, depreciation expense, and related taxes. Any
utility that applies for an interim rate adjustment is required to file a traditional rate case
package, showing its comprehensive cost of service, within five years of filing for its first
IRA.
B. M
OST
R
ECENT
R
ATE
C
ASE
The revenue to be recovered through an interim rate adjustment is incremental to the
revenue requirement established in a gas utilities most recent rate case before the
Commission for the area in which the interim rate adjustment is to be implemented. For
the first interim rate adjustment following a traditional or comprehensive rate case, the
allowed adjustment is based on the difference between the gas utility's invested capital at
the end of the rate case test-year and the invested capital at the end of the calendar-year
following the end of the rate case test-year.
In a traditional rate case, the evidence presented by a utility usually establishes the return
on investment, depreciation expense, and incremental federal income tax, which are then
used to calculate the revenue that is to be collected by the utility. The Commission’s
final order setting a utility’s gas rates usually memorializes these components. The
factors used to calculate the return on investment, depreciation expense, and incremental
federal income tax, which, in turn, are used to compute the revenues to be collected
through the interim rate adjustment, must be the same as those established or used in the
66
final order setting rates in the gas utility's most recent rate case for the area in which the
interim rate adjustment is to be implemented. The same concept applies to a utility’s
allocation requirements. The gas utility must allocate the revenue to be collected through
the interim rate adjustment among the gas utility's customer classes in the same manner
as the cost of service was allocated among customer classes in the utility's most recent
rate case.
SECTION 2 - K
EY
S
TEPS A UTILITY MUST FOLLOW WHEN USING
IRA
1.
Utility must have completed a formal Statement of Intent rate case within two
years of filing for an initial interim rate adjustment (IRA). The bench mark issues
for review and approval in an interim rate adjustment application are set in this
formal rate case – those issues are return of investment, the value established for
tangible assets and the depreciation expense related to those tangible assets, and
related taxes. Also, established in the formal rate case is how these interim rate
expenses will be allocated between the different customer classes (residential,
commercial and industrial). This allocation method is established in the formal
rate case.
2.
The Interim Rate Adjustment rule does not require an evidentiary proceeding (rate
case). The statute and the rule require the regulatory authority only to review a
utility’s method of calculating the interim rate adjustment. The interim rate
adjustment application must include the following reports/documentation:
3.
Utility must provide the regulatory authority certification that it will complete its
notice to utility’s customers before an interim rate adjustment can be
implemented,
4.
Provide an annual investment project report (what hard assets have been put into
use or retired since the formal rate case or previous IRA and the value of those
assets less depreciation expense),
5.
File the annual earnings monitoring report which demonstrates the utility's
earnings and overall rate of return during the preceding calendar year. A gas
utility whose annual earnings monitoring report shows that the utility is earning a
return on invested capital of more than 75 basis points above the return
established by the Commission’s final order setting rates in the utility's most
recent rate case, shall include with its annual earnings monitoring report a
statement of the reasons the proposed IRA rates are not unreasonable or in
violation of the Commission rule.
6.
The allocation factors used to allocate between customer classes and the number
of customers used to calculate the adjustment for each customer class.
67
7.
Utility is required to file on an annual basis an interim rate adjustment whether or
not it had any new investments in the prior year. On the fifth anniversary of the
first interim rate adjustment filing the utility is required to file a formal rate case,
including a comprehensive cost of service rate review. After the approval by the
regulatory authority of the traditional rate case the interim rate adjustment process
can begin again.
8.
Whether the investment in hard assets is used and useful to the customers – new
pipe, new meters, new computer billing system, etc.
9.
Are the benchmarks set in the traditional rate case being met: return on
investment; depreciation expense; ad valorem taxes; revenue related taxes; and
federal income taxes?
10.
Is the utility allocating collection of the interim adjustment revenues in the same
manner that it allocated its overall cost of service in its most recent rate case?
SECTION 3 - S
AMPLE
IRA
C
ALCULATION
12/31/03 12/31/04
Net Investment (traditional rate case value vs. IRA increase) $1,428* $1,470
Increase in Net Investment (incremental increase) 42
Authorized Return on Capital investment (benchmark set in rate case) 8.25%
Incremental Return on Net Invest. $3.47
Incremental Deprecation Expense $2.93
Incremental Fed, and Other Taxes $4.30
Incremental Rev. Requirement (money needed to cover these new costs) $10.65
Annual Number of Customer Bills (14 customers X 12 months) = 168 Bills
Monthly increase per Customer bill ($10.65/168 bills) = $0.06/month
* For the 1
st
year IRA this amount will be the net investment or rate base that was
established in the formal Statement of Intent rate case.
68
CHAPTER VI.
COST OF SERVICE ADJUSTMENT
SECTION 1 - B
ACKGROUND
A. R
ECENT
L
ITIGATED
C
ASES BEFORE THE
R
AILROAD
C
OMMISSION OF
T
EXAS
Until recently, the Commission did not approve proposed Cost of Service Adjustments
(COSA). However, in December 2008, the Commission approved a COSA in GUD No.
9791, Statement of Intent Filed by CenterPoint Energy Entex to Increase the Rates in the
Unincorporated Areas of the Texas Cost Division. Prior to December 2008, utilities had
only three options to increase service rates, a traditional statement of intent to change
rates, the use of an Interim Rate Adjustment, or through a Relocation Cost Recovery
filing. A number of cities in the State of Texas have approved a Rate Review
Mechanism, or an RRM. The Commission has not been presented an opportunity to
decide on an RRM. However, its calculation is very similar to the COSA.
B. M
ECHANISM
The mechanism for calculation of a COSA is dictated by the tariff approved or the
language of the final order approving rates. The Commission does not have a rule in
place to provide guidance. As a result, there may be slight variations from one COSA to
the next. However, the mechanics are basically the same.
The COSA is intended to provide the utility a mechanism for changing the rate to reflect
changes in Operating Expenses, Plant in Service, Return on Investment and Texas
Franchise Taxes. There may be other components of the COSA calculation as approved
on a case-by-case basis. The primary difference between the mechanics of an Interim
Rate Adjustment and a COSA is the inclusion of changes in Operating Expenses and
Revenues in a COSA. In the COSAs approved by the Commission, there is a cap or limit
to the actual increase in any one of the components. The initial approval of a COSA may
also include a requirement that the utility file a traditional statement of intent rate request
within a certain number of years following the initial approval of the COSA.
Calculated on an annual basis, the regulatory authority has a finite time period with
which to conduct its review, usually 90 days. In most COSAs, if, within the 90 day
review period, the company and the regulatory authority with original jurisdiction have
not reached agreement on the proposed cost of service adjustment rate, the regulatory
authority may take action to deny such adjustment and the company has the right to
appeal that decision.
Like an IRA, a COSA calculation typically uses key factors set during the most recent
rate case. These factors may include allocation rates and methodologies, depreciation
rates, and rate of return.
69
SECTION 2 – D
ETERMINING
F
ACTORS IN
C
OST OF
S
ERVICE
A
DJUSTMENTS
Some cities in Texas and the Commission have approved several different types of
adjustments that effectively allow a utility to adjust the base rates for changes in the cost
to serve its customers. Because the cities and the Commission have no specific rule in
place for guidance on key mechanism factors or on the formula itself, each has its own
data points for calculation. Generally though, the mechanisms are designed to allow the
utility a mechanism to adjust its base rates for changes in operation and maintenance
expenses, investment, taxes, working capital and other applicable expenses. Two
primary advantages to these adjustments are the reduction of rate case expenses to litigate
Statement of Intents and the reduction of regulatory lag to the utility. The regulatory
authorities retain all statutory regulatory authority and can initiate a rate inquiry at any
time.
There is a set structure for the COSA calculation, and the regulatory authority has the
ability to review the adjustment and conduct discovery as necessary within the review
period. Several of the adjustments have caps or limits on the overall increase, limiting
the amount of the increase to the customer. The utility must use key components from
the most recent rate case, such as the rate of return and allocation factors.
Key Factors or Data Points in COSAs:
Set period for filing, determination of account balances, and application, i.e., must file by
a certain date using a calendar year for calculations and effective on a set date.
Must use recently approved depreciation methods and rates, rate of return, 13-month
averages for specific accounts, actual tax account balance, allocation rates and
methodologies approved in recent rate case, specific customer count calculations.
Must provide notice, attestation of schedules, and reimbursement of expenses to the
regulatory authority for their review.
Procedures for filing, regulatory review, appeal process and reimbursement of regulatory
expenses.
SECTION 3 – S
AMPLE
C
OST OF
S
ERVICE
A
DJUSTMENT
C
ALCULATION
Step 1: Determine the Balances of Expenses:
Applicable Expenses
Operating Expenses:
Depreciation and Amortization Expense
Taxes Other than Federal Income Tax
Operation and Maintenance Expenses
Customer Related Expenses
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Administrative and General Expenses
Interest on Customer Deposits
Step 2: Determine the Return on Investment:
Net Utility Plant
Other rate base items (materials and supplies inventory and
prepayments)
Cash Working Capital
Less:
Customer Deposits
Customer Advances
Deferred Federal Income Taxes
Step 3: Calculate the Adjustment:
Sample Formula
COSA =
(Operating Expenses + Return on Investment + Franchise Tax –
Actual Non-Gas and Other Revenues)
(1 – Texas Franchise Tax Statutory Rate)
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CHAPTER VII.
GLOSSARY OF GAS UTILITY TERMS
Above the Line -- A term used in the National Association of Regulatory Utility
Commissioners (NARUC) system of accounts to refer to revenue and expenses which are
allowable for ratemaking purposes.
Accelerated Depreciation -- A form of liberalized depreciation in which the asset is
depreciated more rapidly in years immediately following capitalization than in later
years. This depreciation is taken for tax purposes only, since straight-line depreciation is
the only allowable treatment for ratemaking purposes.
Accrued Depreciation -- The amount of depreciation expense taken on an asset since the
initial capitalization of the asset.
Acquisition Adjustment -- The difference between the purchase price paid by a
company for a utility system and the book value of that system at the time of sale,
amortized over some period.
Adjusted Value Rate Base -- A weighted average between original cost, less
depreciation; and current cost, less an adjustment for present age and condition.
Affiliate -- Any corporation or other entity which owns a portion of a utility's stock, or
otherwise exercises control over the utility. See T
EX
.
U
TIL
.
C
ODE
§ 101.003.
Allocation -- The apportionment of rate base, revenue, and expenses among classes of
consumers, distribution systems, or business enterprises.
Allowance for Funds Used During Construction (AFUDC) -- An expense allowed a
utility to compensate for the cost of funds used during the construction of utility assets.
This allowance is not allowed if the utility is permitted to include construction work in
progress in rate base.
Attrition -- Erosion in the ability of a utility to earn authorized rates of return.
Base Load -- A volume of that serves as a constant load over a period of time.
Base Rate -- The utility's rates exclusive of the purchased gas adjustment clause.
Below the Line -- A term from the NARUC system of accounts which refers to revenue
and expenses which are not allowable for ratemaking purposes. Frequently, these revenue
and expenses relate to non-utility related operations of a diversified energy corporation,
or to utility related expenses which are not allowable for ratemaking purposes for some
reason. An example of the latter is charitable contributions.
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Book (Cost) -- The amount at which property or assets are recorded in a company’s
accounts without deducting depreciation, amortization, or various other items.
Business Risk -- The basic risk inherent in a firm's operations, the uncertainty of revenue
and operating expenses.
Capital Structure -- The financing of the firm represented by long-term debt, preferred
stock, and equity.
CAPM - - Capital Asset Pricing Model used in estimating a utilities cost of equity.
Ccf - - One hundred cubic feet.
City Gate -- The central point in the distribution system where gas is stepped down from
the high-pressure transmission line to the lower-pressure distribution lines. Normally, a
meter is attached to the city gate, and the gas transferred through the city gate is charged
at a rate referred to as the city gate rate. The Commission sets this rate.
Comparable Earnings -- A technique for estimating the cost of equity based upon the
average cost of equity for similar companies.
Completed Work Not Yet Classified (CWNC) - - The amount of construction capital
completed but not yet classified in the appropriate FERC accounts.
Construction Work in Progress (CWIP) -- An allowance to rate base for funds
committed to construction of assets which will be placed in utility service at a future date.
Contributions in Aid of Construction -- The payment of funds to a utility to induce the
utility to construct additional facilities in order to serve a customer. A typical example of
these contributions is charges for mainline and service line extension.
Cost of Capital -- The weighted average of the cost of various sources of capital,
generally consisting of outstanding securities such as mortgage debt, preferred and
preference stock, common stock, etc., and retained earnings.
Cost of Equity -- The cost to a company of borrowing money through equity capital. The
sum of capital from retained earnings and the issuance of stocks.
Cost of Service -- The fundamental principle of utility ratemaking, which states that the
utility should be allowed the opportunity to earn its total cost of service, including
operating costs and capital costs, but no more.
Cost of Service Adjustment -- A COSA allows utility rates to vary according to the
utility's investment and operating expenses without a statement of intent filing.
Customer Advances -- Money used by a company, normally for future building projects.
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Customer Deposits -- An amount of money required by a natural gas distribution
company for providing natural gas service to a residential or commercial customer. The
deposit amount for residential customers is based on 1/6 of an annual bill, accrues interest
and is refunded after twelve months of good payment history.
DCF - - Discounted Cash Flow model used in estimating a utility’s cost of equity.
De novo -- A type of appeal in which the lower-court record is not used to review the
case. Rather, the case is retried, as if the parties had come to the appellate court
originally. Rate case appeals are heard by the Railroad Commission on a de novo basis.
Debt Finance Adjustment Clause -- A clause in a utility's rates to allow the utility to
increase the rates to pay the interest costs associated with obtaining debt capital. A debt
finance adjustment clause is normally only considered in the case of a marginally solvent
utility which may be unable to obtain debt capital unless such a clause appears in the
utility's rates.
Debt Ratio -- Total debt divided by total assets. In the context of this packet, it is defined
as long-term debt divided by total long-term (permanent) capital.
Debt/Equity Ratio -- Long-term debt divided by stockholders' equity.
Deferred Taxes -- Federal Income taxes which, by virtue of accelerated or liberalized
depreciation or other tax devices are deferred to a future date.
Depreciation Reserve Ratio-- The ratio of accrued depreciation to original cost. This
ratio is frequently used to calculate the adjustment for age and condition.
Distribution -- The enterprise of selling natural gas to the burner tip customer.
Distribution Plant -- Mains, service connections, and equipment that carry or control the
supply of natural gas from the point of local supply to and including the sales meters
Elasticity -- The variation in demand according to the price of the commodity.
Embedded -- A fixed capital cost, such as interest on debt or dividends on preferred
stock. This is distinguished from variable capital costs, such as return to equity.
Environs -- The area surrounding an incorporated city, but not within the limits of the
city, which include residential and commercial customers who are served off of the same
distribution system as residential and commercial customers inside the city limits.
Ex Parte -- Any instance of communication where all parties to the case are not given
notice and opportunity to participate.
External Funds -- Funds acquired through borrowing or by selling new common or
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preferred stock.
FERC USOA - - Federal Energy Regulatory Commission Uniform System of Accounts.
Financial Risk -- Risk which is caused by a greater percentage of debt being owed by a
business enterprise. This is to be distinguished from business risk.
Flotation Costs -- The cost of issuing stock.
Fuel Adjustment Clause (FAC) -- A term which is synonymous with and used
interchangeably with purchased gas adjustment clause.
General Plant -- The portion of a utility plant which is associated with management,
customer service, billing, and other support functions.
GRIP -- Gas Reliability Infrastructure Program. (See Interim Rate Adjustment)
GURA -- Gas Utility Regulatory Act.
Hearing in Progress -- Period of time between issuance of Notice of Hearing and final
decision.
Heating Degree Day (HDD) -- A unit of measure of the extent to which the average
daily temperature falls below 65. This unit is utilized to estimate heating-related energy
consumption.
Heating Load -- The difference between the annual adjusted quantity of gas and the
annualized average base load for those months with no heating degree-days.
Interim Rate -- Rates which are allowed to be charged by a utility, subject to refund, to
allow the utility to recover its operating costs and debt service costs pending the outcome
of a rate proceeding.
Interim Rate Adjustment (IRA or GRIP) - - An interim adjustment to utility rates to
reflect changes in investment without a statement of intent filing. An IRA is allowed
under statute and Commission rule.
Lead - Lag Study -- A study to determine the cost of the time lag between the point
when a service is rendered and the related operating costs are incurred and the point when
the revenues to recover such costs are received. The operating funds to fill the lag are
usually supplied by the investor and becomes a fixed commitment to the enterprise.
Long-term debt -- All debt due in more than 12 months.
Market Pressure -- The drop in price that occurs when new issues are placed in the
market because of the sudden excess supply of a particular security.
75
Mcf -- One thousand cubic feet.
MMBtu - - One Million British Thermal Units.
Monetary Return --The return a company is allowed to recover for its cost of operation
and an additional return component that covers the cost of capital used to support the
investment in the company.
Net book value per share -- Book equity divided by the number of outstanding shares of
common stock.
Net Current Cost -- Reproduction cost new less adjustment for age and condition.
Net Invested Capital -- Original cost of system less book depreciation.
Notice of Hearing -- A document issued to notify affected parties of the date, time, and
location of a hearing in a contested case.
Off Peak Pricing -- A rate design in which rates are lower in periods of reduced demand.
This type of pricing increases a utility's load factor, since it encourages consumption in
off-peak periods. An example of this type of pricing is summer/winter rates. Another
example is time-of-day pricing.
Peak Demand -- The maximum load during a specified period of time.
Portfolio Effect -- The extent to which the variation in returns (risk) on a combination of
assets (a "portfolio") is less than the sum of the variations of the individual assets.
Proposal for Decision -- A document containing the reasoning behind a decision
recommended to the Commission by the Hearings Examiner.
PURA -- Public Utility Regulatory Act.
Purchased Gas Adjustment Clause (PGA) -- A clause in the utility's tariff that allows
variation of the utility's rates according to variation in the utility's weighted average cost
of gas.
Rate Base -- A utility’s investment in the system, used to calculate the required monetary
return on investment.
Rate of Return -- Percentage of utility’s invested capital, which the utility recovers
through its rates. Also See Return on Investment.
Regulatory Lag -- The period which is required for a utility regulatory authority to
consider a rate increase request filed by a utility.
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Relation back -- The act of making a rate order effective prior to issuance. Rates may be
related back to any period after the regulatory authority acquires jurisdiction.
Reproduction Cost New -- The estimated cost of replacing the utility’s system with
similar new equipment at the present time.
Retention Rate -- The percentage of earnings not paid out in the form of dividends.
Retirement Work-ln-Progress -- An adjustment to rate base and to accumulated
depreciation to account for assets which are in the process of retirement.
Return on Investment -- Percentage of a utility’s invested capital it recovers through its
rates. Also See Monetary Return.
Statement of Intent -- The document required to be filed under GURA with the
regulatory authority having original jurisdiction in order to request a change in rates.
Straight-line Depreciation -- Depreciation in which the annual depreciation expense is
equaled each year over the life of the asset.
Suspension -- Postponement of the effective date of the proposed rate increases
accomplished by issuance of an appropriate order or ordinance.
System-wide Rates -- Rates which are set based upon rate base, revenue, and expense
figures of a utility's entire system, rather than a particular incorporated area.
T
EX
.
A
DMIN
.
C
ODE
– 16 Texas Administrative Code
T
EX
.
U
TIL
.
C
ODE
-- Texas Utilities Code Titles 3 and 4.
Weather Normalization -- A clause in utility rates which adjusts customer bills to
reflect normal temperatures. If temperatures during the measured period are warmer than
normal, customers receive a surcharge. If temperatures during the measured period are
colder than normal, customers receive a credit.
Working Capital -- Used broadly, the term refers to those rate-base allowances other
than the utility plant in service and may include material, fuels, supplies, etc. In the
narrower use, commonly referred to as cash working capital, it relates to the investor-
supplied funds necessary to meet operating expense or going-concern requirements of
business. There is normally a time lag between the point when a service is rendered and
the related operating costs are incurred and the point when the revenues to recover such
costs are received. The operating funds to fill the lag are usually supplied by the investor
and becomes a fixed commitment to the enterprise.
77
BIBLIOGRAPHY
BOOKS
Bonbright, James C., Principles of Public Utility Rates. New York: Columbia University
Press, 1961.
Garfield, Paul J. and Wallace F. Lovejoy, Public Utility Economics. Englewood Cliffs,
N.J.: Prentice-Hall, 1967.
Kahn, Alfred E., The Economics of Regulation: Principles and Institutions Vols. I and 11,
New York: John Wiley & Sons, Inc., 1971.
Weston, J. Fred and Brigham, Eugene F. Managerial Finance. 5th ed. Illinois: Dryden
Press, 1975.
LAW REVIEW ARTICLES
Adams, Representing Clients in Administrative Adjudication Proceedings, 74 NW U. L.
Rev. 854 (1980).
Aman, Jr., Natural Gas and Electricity Utility Rate Reform: Taxation through
Ratemaking, 28 Hastings L. J. 1075 (1977).
Natural Gas Rate Design: A Neglected Issue, 31 V and L. Rev. 1089 (1978).
Natural Gas Rate Regulation: The Conflict in the Application of the Just and Reasonable
Standard, 12 Tulsa L. J. 293 (1976).
Pleitz and Little, Municipalities and Public Utility Regulatory Act, 28 Baylor L. Rev. 977
(1976).
Protection of Public Utility Consumers, 28 Baylor L. Rev. 1061 (1976).
Public Utility Regulation in Texas, Symposium, 28 Baylor L. Rev. 771 (1976).
Rate Design, 28 Baylor L. Rev. 1083 (1976).
Rate Regulation: Alvin Case, 28 Baylor L. Rev. 1073 (1976).
Student Symposium: Public Utility Regulation in Texas, 7 St. Mary’s L. J. SIS (1975).
78
GENERAL PERIODICALS AND ARTICLES
Brigham, Eugene F. and Smith, Keith V., Cost of Capital to the Small Firm Engineering
Economist, Vol. 13, No. 1, pp. 1-24.
Public Utilities Fortnightly, Arlington, Va., Public Utilities Reports, Inc. (biweekly).
Regulation, Washington, D.C., American Enterprise Institute for Public Policy Research
(bimonthly).
Scholes, Myron S., The Market for Securities: Substitution versus Price Pressure and the
Effects of Information on Share Prices Journal of Business, April, 1972, pp. 179-211.
OTHER MATERIALS
Fairchild, Bruce H., “Direct Testimony” Docket No. 2572. Economic Research Division,
Public Utility Commission of Texas, July 1979.
Fairchild, Bruce H., “Estimating the Cost of Equity to Texas Public Utility Companies”
Diss., University of Texas at Austin, May, 1980.
