BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the Matter of Kansas City Power & Light ) File
No. ER-2014-0370 et al.
Company’s Request for Authority to Implement a ) YE-2015-0194
General Rate Increase for Electric Service ) YE-2015-0195
REPORT AND ORDER
TABLE OF CONTENTS
APPEARANCES
.............................................................................................. 3
I. Procedural History ................................................................................. 5
A. Tariff Filings, Notice, and Intervention ................................................ 5
B. Test Year and True-up ..................................................................... 5
C. Local Public Hearings ....................................................................... 6
D. Stipulations and Agreements.............................................................. 7
E. Evidentiary Hearing .......................................................................... 8
F. Case Submission ............................................................................. 8
II. General Matters ..................................................................................... 9
A. General Findings of Fact ................................................................... 9
B. General Conclusions of Law .............................................................. 12
III. Disputed Issues ..................................................................................... 15
A. Cost of capital .................................................................................. 15
B. Fuel adjustment clause ..................................................................... 22
2005 stipulation and agreement……………………………………….. 22
FAC criteria……………………………………………………………….. 28
FAC tariff provisions…………………………………………………….. 30
C. Transmission fee expense ................................................................ 50
D. Property tax expense ....................................................................... 55
E. CIP/cyber-security expense .............................................................. 57
F. La Cygne environmental retrofit project ............................................. 59
G. Rate case expense ........................................................................... 64
H. Management audit ........................................................................... 73
I. Clean Charge Network ...................................................................... 74
J. Income tax issues ............................................................................ 76
CWIP-related
ADIT……………………………………………………….. 76
1KC Place lease ADIT…………………………………………………… 79
Employee compensation ADIT…………………………………………. 81
Net operating losses…………………………………………………….. 82
K. Class cost of service, rate design, and
tariff rules ............................... 86
L. Revenues ........................................................................................ 99
M. Low-income weatherization ............................................................... 101
N. Economic relief pilot program ............................................................ 102
O. True-up issues ................................................................................. 104
ORDERED
PARAGRAPHS .............................................................................. 107
APPEARANCES
KANSAS CITY POWER & LIGHT COMPANY:
Robert J. Hack and Roger W. Steiner, Kansas City Power & Light Company, 1200 Main
Street, 16th Floor, Kansas City, Missouri 64105.
Karl
Zobrist and Lisa A. Gilbreath, Dentons US LLP, 4520 Main
Street, Suite 1100, Kansas City, Missouri 64111.
James W. Fischer, Fischer & Dority,
101 Madison St., Suite 400, Jefferson City, Missouri 65101.
STAFF OF THE MISSOURI PUBLIC SERVICE COMMISSION:
Kevin A. Thompson, Chief Staff Counsel,
Steven Dottheim, Chief Deputy Staff
Counsel, Nathan Williams, Deputy
Counsel, Colleen M. “Cully” Dale, Senior
Staff Counsel, Jeffrey A. Keevil, Senior
Staff Counsel, Cydney D. Mayfield, Senior
Staff Counsel, Nicole Mers, Assistant
Staff Counsel, Marcella Mueth, Assistant
Staff Counsel, Whitney Payne, Assistant
Staff Counsel, Post Office Box 360, Governor Office Building, 200 Madison
Street, Jefferson City, Missouri 65102.
OFFICE OF THE PUBLIC COUNSEL:
Marc D. Poston, Deputy Public Counsel, Timothy Opitz, Assistant Public
Counsel,
PO Box 2230, Jefferson City, Missouri 65102.
MISSOURI DEPARTMENT OF ECONOMIC
DEVELOPMENT- DIVISION OF ENERGY:
Alexander
Antal, Associate General Counsel, PO Box 1157, Jefferson City, Missouri
65102.
MIDWEST ENERGY CONSUMERS GROUP:
David
L. Woodsmall, Woodsmall Law Office, 308 E. High St., Suite 204,
Jefferson City, Missouri 65101.
MISSOURI INDUSTRIAL ENERGY CONSUMERS:
Edward F. Downey, Carole L. Iles, 221
Bolivar St., Suite 101, Jefferson City, Missouri 65109, and Diana M. Vuylsteke, 211 N. Broadway,
Suite 3600, St. Louis, Missouri 63102.
UNITED STATES
DEPT. OF ENERGY AND THE FEDERAL EXECUTIVE AGENCIES:
Sean Tshikororo, 1000 Independence Ave. SW,
Washington, D.C., 20585.
Robert E. Sauls, 625 E. 26th
St., Kansas City, Missouri 64108.
SIERRA CLUB:
Henry
B. Robertson, Great Rivers
Environmental Law Center, 705 Olive Street, Suite
614, St. Louis, Missouri 63101.
Sunil Bector, Sierra Club, 85 Second
St., 2nd Floor, San Francisco, California 94105.
Lisa K. Perfetto, Earthjustice, 48 Wall
St., 19th Floor, New York, New York 10005, and Thomas Cmar, 1101 Lake St., Suite 405B, Oak Park, Illinois 60301.
CONSUMERS COUNCIL OF MISSOURI:
John
B. Coffman, 871 Tuxedo Blvd., St. Louis, Missouri 63119-2044.
BRIGHTERGY, LLC:
Andrew
J. Zellers, General Counsel, 1712 Main St., Kansas City, Missouri 64108.
UNION ELECTRIC COMPANY d/b/a AMEREN
MISSOURI:
James
B. Lowery, Smith Lewis, LLP, 111 S. Ninth St., Columbia, Missouri 65201.
CITY OF KANSAS CITY, MISSOURI:
Mark
W. Comley, 601 Monroe St., Suite 301, Jefferson City, Missouri 65102.
SENIOR REGULATORY LAW JUDGE: Michael Bushmann
REPORT AND ORDER
A. Tariff Filings, Notice, and Intervention
On October 30, 2014, Kansas City Power & Light Company (“KCPL”) filed tariff
sheets designed to implement a general rate increase for utility service. The tariff sheets bore an effective date of November
29, 2014. In order to allow sufficient
time to study the effect of the tariff sheets and to determine if the rates
established by those sheets are just, reasonable, and in the public interest,
the tariff sheets were suspended until September 29, 2015. The Commission directed notice of the filings
and set an intervention deadline. The
Commission granted intervention requests from the following entities: the
Missouri Department of Economic Development- Division of Energy, Midwest Energy
Consumers Group, Missouri Industrial Energy Consumers, Brightergy, LLC, Sierra
Club, Consumers Council of Missouri, U.S. Department of Energy and Federal
Executive Agencies, Union Electric Company d/b/a Ameren Missouri, Missouri Gas
Energy, the City of Kansas City, Missouri, and the International Brotherhood of
Electrical Workers Local Unions No. 412, 1464, and 1613. On January 30, 2015, the Commission
consolidated this case with a related matter in File No. EU-2015-0094.
The test year is a central component in the ratemaking
process. Rates are usually established
based upon a historical test year which focuses on four factors: (1) the rate of return the utility has
an opportunity to earn; (2) the rate base upon which a return may be
earned; (3) the depreciation costs of plant and equipment; and
(4) allowable operating expenses. From these four factors is calculated the
“revenue requirement,” which, in the context of rate setting, is the amount of
revenue ratepayers must generate to pay the costs of producing the utility
service they receive while yielding a reasonable rate of return to the
investors. A historical test year is used because the
past expenses of a utility can be used as a basis for determining what rate is
reasonable to be charged in the future.
The parties agreed to, and the Commission adopted, a test year of
twelve months ending on March 31, 2014, updated through December 31, 2014. The Commission also established the true-up
period to run through May 31, 2015, to reflect any significant and material
impacts on KCPL’s revenue requirement. The
use of a true-up audit and hearing in ratemaking is a compromise between the
use of a historical test year and the use of a projected or future test year. It involves adjustment of the historical test
year figures for known and measurable subsequent or future changes. However, the true-up is generally limited to
only those accounts necessarily affected by some significant known and
measurable change, such as a new labor contract, a new tax rate, or the
completion of a new capital asset. The true-up
is a device employed to reduce regulatory lag, which is “the lapse of time between a change in revenue requirement and the
reflection of that change in rates.”
On December 3, 2014, some of the parties filed a Joint Proposed Procedural Schedule,
which included a recommendation for the dates and locations for local public
hearings to give KCPL’s customers an opportunity to respond to the requested
rate increase. The Commission conducted
local public hearings in Kansas City, Belton, Marshall, and Gladstone.
On June 26, 2015, some of the parties filed a Non-Unanimous Stipulation and Agreement
Regarding Pension and Other Post-Employment Benefits. On July 1, 2015, some of the parties filed a Partial Non-Unanimous Stipulation and
Agreement as to Certain Issues and a Partial
Non-unanimous Stipulation and Agreement as to True Up, Depreciation and Other
Miscellaneous Issues. Although these stipulations and agreements were not
signed by all parties, they became unanimous stipulations and agreements
because no party filed a timely objection. These
stipulations and agreements resolved a number of the issues in dispute between
the parties. The Commission found the
stipulations and agreements to be reasonable and approved them on July 17,
2015. The issues resolved in these three
partial stipulations and agreements will not be addressed further in this
report and order, except as they may relate to any unresolved issues.
On June 16, 2015, some of the parties filed a Non-Unanimous Stipulation and Agreement on
Certain Issues (“Rate Design Agreement”), which addressed issues relating
to class cost of service, rate design, and tariffs. On August 3, 2015, Staff
and KCPL filed a Non-Unanimous Stipulation
and Agreement Regarding Class Kilowatt-Hours, Revenues and Billing
Determinants, and Rate Switcher Revenue Adjustments (“True-Up Agreement”),
which attempted to 1) resolve all issues relating to weather normalization,
rate revenues, and the resulting class billing determinants used in developing
rates for all rate classes, and 2) assign a revenue shortfall of $500,000 for
rate switchers in the LGS and LP rate classes in order to account for any of
those customers migrating to a different rate schedule to receive more
advantageous pricing as a result of the Rate Design Agreement. KCPL objected to the Rate Design Agreement and
the Office of Public Counsel objected to the True-Up Agreement, so those two
stipulations and agreements became joint position statements of the signatory
parties, and all the issues addressed in the Rate Design Agreement and True-Up
Agreement remain for determination after hearing.
E. Evidentiary Hearing
The evidentiary hearing was held on June 15-19, 29 and 30, 2015,
and July 1, 2015. A true-up hearing was held on July 20, 2015. During
the hearings, the parties presented evidence relating to the unresolved issues
previously identified by the parties.
During the evidentiary hearing and true-up hearing held at the
Commission’s offices in Jefferson City, Missouri, the Commission admitted
the testimony of 61 witnesses, received 179 exhibits into evidence, and
took official notice of certain matters. Post-hearing briefs were filed according to
the post-hearing procedural schedule. The final post-hearing briefs were filed on August
3, 2015, and the case was deemed submitted for the Commission’s decision on that
date.
II.
General Matters
A.
General
Findings of Fact
1.
Kansas City Power & Light Company (“KCPL”), founded
in 1882, is a wholly‑owned subsidiary of Great Plains Energy
Incorporated, both of which are headquartered in Kansas City, Missouri. KCPL is a vertically-integrated, regulated
electric utility that provides generation, transmission, and distribution service
as part of its sale of electricity to retail and wholesale customers in
Missouri and Kansas.
2.
The Office of the Public Counsel (“Public
Counsel”) is a party to this case pursuant to Section 386.710(2), RSMo,
and by Commission Rule 4 CSR 240‑2.010(10).
3.
The Staff of the Missouri Public Service
Commission (“Staff”) is a party to this case pursuant to Section 386.071, RSMo,
and Commission Rule 4 CSR 240‑2.010(10).
4.
KCPL provides electric service to
approximately 519,000 customers, including approximately 457,700 residences,
59,300 commercial firms, and 2,100 industrials, municipalities, and other
electric utilities, in the Kansas City metropolitan area and surrounding cities.
5.
KCPL’s base load generating
capacity consists of ownership in four large coal-fired generating stations,
the Wolf Creek nuclear power generating station, 2,200 megawatts (MW) of
natural gas and oil-fired peaking capacity, and 149 MW of wind generating
capacity. In 2011 and 2013, KCPL negotiated long-term power purchase agreements
for additional wind and hydro generation. KCPL operates and maintains
approximately 12,000 miles of distribution lines and 1,800 miles of
transmission lines to serve its customers.
6.
The proposed tariffs filed by KCPL
in this case were designed to generate an aggregate revenue increase of
approximately $120.9 million, or 15.75%, based on a current Missouri
jurisdictional base retail revenue of $767.4 million.
7.
In order to determine the appropriate level of
utility rates, the Commission must calculate a revenue requirement for KCPL,
which is the increase or decrease in revenue KCPL needs in order to provide
safe and reliable service, as measured using KCPL’s existing rates and cost of
service.
8.
The revenue requirement calculation can be
identified by a formula as follows:
Revenue Requirement = Cost of Providing Utility Service or RR= O + (V - D) R
where,
RR = Revenue Requirement;
O = Operating Costs; (such as fuel, payroll,
maintenance, etc.,
Depreciation
and Taxes);
V = Gross Valuation of Property Used for Providing
Service;
D = Accumulated Depreciation Representing the
Capital Recovery
of Gross
Property Investment.
(V – D) = Rate Base (Gross Property Investment less
Accumulated
Depreciation
= Net Property Investment)
R = Overall Rate of Return or Weighted Cost of
Capital
(V
- D) R = Return
Allowed on Net Property Investment
9.
A test year is a historical year used as the
starting point for determining the basis for adjustments that are necessary to
reflect annual revenues and operating costs in calculating
any shortfall or excess of earnings by the utility. Adjustments, such as annualization and
normalization adjustments, are made to the test year results when the
unadjusted results do not fairly represent the utility’s most current annual
level of existing revenue and operating costs.
10.
The test year for this case is the
twelve months ending March 31, 2014, updated to December 31, 2014.
11.
The Commission also selected a
true-up period ending May 31, 2015, in order to account for any significant
changes in KCPL’s cost of service that occurred after the end of the test year
period but prior to the tariff operation of law date.
12.
A normalization adjustment is an adjustment made
to reflect normal, on-going operations of the utility. Revenues or costs that were incurred in the
test year that are determined to be atypical or abnormal will get specific rate
treatment and generally require some type of adjustment to
reflect normal or typical operations. The
normalization process removes abnormal or unusual events from the cost of
service calculations and replaces those events with normal levels of revenues
or costs.
13.
An annualization adjustment is made to a cost or
revenue shown on the utility’s books to reflect a full year’s impact of that
cost or revenue.
14.
The calculated total revenue
requirement is then compared to net income available from existing rates to
determine the incremental change in KCPL’s rate revenues required to cover its
operating costs and provide a fair return on investment used in providing
utility service.
15.
The Commission finds that any
given witness’s qualifications and overall credibility are not dispositive as
to each and every portion of that witness’s testimony. The Commission gives each item or portion of
a witness’s testimony individual weight based upon the detail, depth,
knowledge, expertise, and credibility demonstrated with regard to that specific
testimony. Consequently, the Commission
will make additional specific weight and credibility decisions throughout this
order as to specific items of testimony as is necessary.
16.
Any finding of fact reflecting
that the Commission has made a determination between conflicting evidence is
indicative that the Commission attributed greater weight to that evidence and
found the source of that evidence more credible and more persuasive than that
of the conflicting evidence.
B. General Conclusions of Law
KCPL is an “electrical corporation” and a “public utility” as
defined in Sections 386.020(15) and 386.020(43), RSMo, respectively, and as
such is subject to the personal jurisdiction, supervision, control and
regulation of the Commission under Chapters 386 and 393 of the
Missouri Revised Statutes. The
Commission’s subject matter jurisdiction over KCPL’s rate increase request is
established under Section 393.150, RSMo.
Sections 393.130 and 393.140, RSMo, mandate that the Commission
ensure that all utilities are providing safe and adequate service and that all
rates set by the Commission are just and reasonable. Section 393.150.2, RSMo, makes clear that at
any hearing involving a requested rate increase the burden of proof to show the
proposed increase is just and reasonable rests on the corporation seeking the
rate increase. As the party requesting
the rate increase, KCPL bears the burden of proving that its proposed rate
increase is just and reasonable. In
order to carry its burden of proof, KCPL must meet the preponderance of the evidence
standard. In order to meet this standard, KCPL must
convince the Commission it is “more likely than not” that KCPL’s proposed rate
increase is just and reasonable.
In determining whether
the rates proposed by KCPL are just and reasonable, the Commission must balance
the interests of the investor and the consumer.[32] In
discussing the need for a regulatory body to institute just and reasonable
rates, the United States Supreme Court has held as follows:
Rates which are not sufficient to yield a reasonable
return on the value of the property used at the time it is being used to render
the services are unjust, unreasonable and confiscatory, and their enforcement
deprives the public utility company of its property in violation of the
Fourteenth Amendment.[33]
In the same case, the Supreme Court provided the
following guidance on what is a just and reasonable rate:
What annual rate will constitute just compensation
depends upon many circumstances and must be determined by the exercise of a
fair and enlightened judgment, having regard to all relevant facts. A public utility is entitled to such rates as
will permit it to earn a return on the value of the property which it employs
for the convenience of the public equal to that generally being made at the
same time and in the same general part of the country on investments in other
business undertakings which are attended by corresponding risks and
uncertainties; but it has no constitutional right to profits such as are
realized or anticipated in highly profitable enterprises or speculative
ventures. The return should be
reasonably sufficient to assure confidence in the financial soundness of the
utility and should be adequate, under efficient and economical management, to
maintain and support its credit and enable it to raise the money necessary for
the proper discharge of its public duties.
A rate of return may be reasonable at one time and become too high or
too low by changes affecting opportunities for investment, the money market and
business conditions generally.[34]
The Supreme Court has
further indicated:
‘[R]egulation does not insure that the business
shall produce net revenues.’ But such
considerations aside, the investor interest has a legitimate concern with the
financial integrity of the company whose rates are being regulated. From the investor or company point of view it
is important that there be enough revenue not only for operating expenses but
also for the capital costs of the business.
These include service on the debt and dividends on the stock. By that standard the return to the equity
owner should be commensurate with returns on investments in other enterprises
having corresponding risks. That return,
moreover, should be sufficient to assure confidence in the financial integrity
of the enterprise, so as to maintain its credit and to attract capital.[35]
In undertaking the balancing required by the Constitution, the
Commission is not bound to apply any particular formula or combination of
formulas. Instead, the Supreme Court has
said:
Agencies to whom this legislative power has been
delegated are free, within the ambit of their statutory authority, to make the
pragmatic adjustments which may be called for by particular circumstances.[36]
Furthermore, in quoting the United States Supreme Court
in Hope Natural Gas, the Missouri
Court of Appeals said:
[T]he Commission [is] not bound to the use of any
single formula or combination of formulae in determining rates. Its rate-making function, moreover, involves
the making of ‘pragmatic adjustments.’ …
Under the statutory standard of ‘just and reasonable’ it is the result reached,
not the method employed which is controlling.
It is not theory but the impact of the rate order which counts.[37]
III. Disputed Issues
A. Cost of capital
Findings of
Fact
17.
Four financial analysts offered recommendations
regarding an appropriate cost of capital in this case. Robert B. Hevert
testified on behalf of KCPL. Hevert is Managing Partner of Sussex Economic
Advisors, LLC. He holds a Bachelor of Science degree in Finance from the University
of Delaware and a Master of Business Administration with a concentration in
finance from the University of Massachusetts. He also holds the Chartered
Financial Analyst designation.
He recommends the Commission allow KCPL a return on equity of 10.3 percent,
within a range of 10.0 percent to 10.6 percent.
18.
Michael Gorman testified on behalf of Missouri
Industrial Energy Consumers (“MIEC”) and Midwest Energy Consumers Group
(“MECG”). Gorman is a consultant in the field of public utility regulation and
is a managing principal of Brubaker & Associates. He holds a Bachelor of
Science degree in Electrical Engineering from Southern Illinois University and
a Master’s Degree in Business Administration with a concentration in Finance
from the University of Illinois at Springfield.
Gorman recommends the Commission allow KCPL a return on equity of 9.10 percent,
within a recommended range of 8.80 percent to 9.40 percent.
19.
Maureen L. Reno testified on behalf of the U.S.
Department of Energy and the Federal Executive Agencies. Reno holds a Bachelor
of Arts in Economics from the University of Maine at Orono, Maine and a Master
of Arts in Economics from the University of New Hampshire in Durham, New
Hampshire. She is employed as an independent consultant.
Reno recommends the Commission allow KCPL a return on equity of 9.0 percent,
within a recommended range of 8.2 percent to 9.6 percent.
20.
Zephania Marevangepo testified on behalf of
Staff. Marevangepo is employed by the Commission as a Utility Regulatory
Auditor III in the Financial Analysis Unit. Marevangepo holds a Bachelor of
Science degree in Business Administration from Columbia College in Columbia,
Missouri and a Masters of Business Administration from Lincoln University in
Jefferson City, Missouri.
Marevangepo recommends a return on equity of 9.25 percent, within a range of
9.00 percent to 9.50 percent.
21.
An essential ingredient of the cost-of-service
ratemaking formula is the rate of return, which is premised on the goal of
allowing a utility the opportunity to recover the costs required to secure debt
and equity financing. If the allowed rate of return is based on the costs to
acquire capital, then it is synonymous with the utility’s weighted average cost
of capital, which is calculated by multiplying each component ratio of the
appropriate capital structure by its cost and then summing the results. In
order to arrive at a rate of return, the Commission must examine an appropriate
ratemaking capital structure, KCPL’s embedded cost of debt, and KCPL’s cost of
common equity, or return on equity.
22.
The actual capital structure of Great Plains
Energy Incorporated (“GPE”) as of May 31, 2015, was 50.090 percent common
equity, .552 percent preferred stock, and 49.358 percent long-term debt.
This capital structure is consistent with the capital structure of utility
operating companies held by proxy companies.
23.
In KCPL’s last rate case, File No. ER-2012-0174,
the Commission used a consolidated capital structure and embedded cost of debt for
KCPL consistent with that of GPE, KCPL’s parent company.
24.
In KCPL’s most recent retail rate case in
Kansas, the Kansas Corporation Commission approved the use of a capital
structure based on the GPE consolidated capital structure.
25.
All of the expert witnesses on this issue
recommended using the GPE capital structure for KCPL, except for witness
Maureen Reno.
Ms. Reno used KCPL’s actual capital structure as of December 31, 2014, which
included short-term debt.
26.
The consolidated cost of long-term debt of GPE
as of May 31, 2015, was 5.557 percent.
KCPL’s weighted average coupon rate for KCPL’s debt instruments is consistent
with the prevailing market conditions at the time of issuance.
27.
Excluding short-term debt from the capital
structure is consistent with the Federal Energy Regulatory Commission (“FERC”)
Order 561, which set forth the formula for calculating the allowance for funds
used during construction. Since short-term debt is first used to fund
construction work in progress, that same debt cannot be included in the
regulatory capital structure without double-counting that debt.
28.
A utility’s cost of common equity is the return
investors require on an investment in that company. Investors expect to achieve
their return by receiving dividends and through stock price appreciation.
To comply with standards established by the United States Supreme Court,
the Commission must authorize a return on equity sufficient to maintain
financial integrity, attract capital under reasonable terms, and be
commensurate with returns investors could earn by investing in other
enterprises of comparable risk.
29.
Financial analysts use variations on three
generally accepted methods to estimate a company’s fair rate of return on
equity. The Discounted Cash Flow (“DCF”) method is based on a theory that a
stock’s current price represents the present value of all expected future cash
flows. In its simplest form, the Constant Growth DCF model expresses the cost
of equity as the discount rate that sets the current price equal to expected
cash flows.
The analysts also use variations of the DCF model including the multi-stage
growth DCF and the sustainable growth DCF.
The Risk Premium method is based on the principle that investors require a
higher return to assume a greater risk. Common equity investments have greater
risk than bonds because bonds have more security of payment in bankruptcy
proceedings than common equity and the coupon payments on bonds represent
contractual obligations.
The Capital Asset Pricing Method (“CAPM”) assumes the investor’s required rate
of return on equity is equal to a risk-free rate of interest plus the product
of a company-specific risk factor, beta, and the expected risk premium on the
market portfolio.
No one method is any more correct than any other method in all circumstances.
Analysts balance their use of all three methods to reach a recommended return
on equity.
30.
State public utility commissions in the country
are reducing authorized returns on equity to follow the significant decline in
capital market costs. A comparison of industry authorized returns on equity
indicates that they have been steadily declining over the last several years.
In calendar year 2014, the industry authorized return on equity for fully
litigated cases was 9.63 percent. In the first quarter of 2015, the industry authorized
return on equity for fully litigated cases was 9.57 percent. Witness
Gorman states credibly that based on returns awarded by other commissions, a
reasonable finding for a return on equity in this case is conservatively at 9.5
percent or less.
31.
The Commission mentions the industry authorized
return on equity because KCPL must compete with other utilities all over the
country for the same capital. Therefore, the industry authorized return on
equity provides a reasonableness test for the recommendations offered by the
return on equity experts.
32.
In its decision regarding KCPL’s last rate case,
the Commission established a return on equity of 9.7 percent. Over
the last four years, the market capital costs for Missouri electric utilities are
significantly lower, due to increases in utility stock prices and decreases in
bond yields and utility dividend yields.
33.
KCPL’s expert witness, Robert Hevert, supports
an increased return on equity at 10.3 percent. The Commission finds that such a
return on equity would be excessive. Hevert’s return on equity estimate is high
because 1) his constant growth DCF results are based on excessive and
unsustainable long-term growth rates, 2) his multi-stage DCF is based on a
flawed accelerated dividend cash flow timing and an inflated gross domestic
product growth estimate as a proxy for long-term sustainable growth, 3) his
CAPM is based on inflated market risk premiums, and 4) his bond yield plus risk
premium is based on inflated utility equity risk premiums.
34.
If a fuel adjustment clause is implemented in
this case, it will reduce KCPL’s prospective investment risk, and this risk
reduction should be considered in establishing a reasonable return on equity
for KCPL.
35.
Since April 2015, some capital market and
general economic indicators have changed, indicating expanding macroeconomic
growth and increased required returns.
36.
The return on equity recommendations of
witnesses Gorman, Marevangepo, and Reno are all reasonable and an accurate
estimate of the current market cost of capital for KCPL, as those
recommendations rely on verifiable and independent market data and accepted
market-based rate of return models. Gorman testified credibly that these return
on equity recommendations demonstrate that KCPL’s current cost of equity is 9.5
percent or less.
Conclusions
of Law and Decision
In determining the rate of return, the Commission must first
consider KCPL’s capital structure and cost of debt. This Commission has
historically used the actual capital structure of GPE in determining the
capital structure of KCPL, as has the Kansas Corporation Commission when
setting KCPL’s rates in that state. It is appropriate to use a consistent
capital structure across all regulatory jurisdictions to avoid disagreements
about one operating company’s capital structure having more or less equity than
another operating company. Ms. Reno’s testimony was not persuasive that
short-term debt should be included in the capital structure. The Commission
concludes that in calculating KCPL’s cost of capital, the correct capital
structure to use is the actual capital structure of GPE as of May 31, 2015,
which was 50.090 percent common equity, .552 percent preferred stock, and 49.358
percent long-term debt. The use of short-term debt is not appropriate, so the correct
cost of debt for KCPL is its actual cost of long-term debt as of May 31, 2015,
which was 5.557%.
In order to set a fair rate of return for KCPL, the Commission
must determine the weighted cost of each component of the utility’s capital
structure. One component at issue in
this case is the estimated cost of common equity, or the return on equity. Estimating the cost of common equity capital
is a difficult task, as academic commentators have recognized.[69] Determining a rate of return on equity is imprecise
and involves balancing a utility's need to compensate investors against its
need to keep prices low for consumers.
Missouri court decisions recognize that the Commission has
flexibility in fixing the rate of return, subject to existing economic conditions.[71] “The cases also recognize that the fixing of
rates is a matter largely of prophecy and
because of this commissions, in carrying out their functions, necessarily deal
in what are called ‘zones of reasonableness', the result of which is that they
have some latitude in exercising this most difficult function."[72] Moreover, the United States Supreme Court has
instructed the judiciary not to interfere when the Commission's rate is within
the zone of reasonableness.[73]
The evidence shows that return on equity recommendations of
witnesses Gorman, Marevangepo, and Reno are all reasonable and an accurate
estimate of the current market cost of capital for KCPL. The ranges of those
recommendations overlap, and the upper end of those ranges is between 9.4 percent
and 9.6 percent. The Commission finds that witness Gorman testified credibly
and persuasively that KCPL’s current cost of equity is 9.5 percent or less. The Commission has considered other factors,
such as recent indicators of growth that may suggest an increased return, and
the reduction of investment risk to KCPL by approving a fuel adjustment clause,
which suggests a reduced return. However, based on the competent and
substantial evidence in the record, on its analysis of the expert testimony
offered by the parties, and on its balancing of the interests of the company’s
ratepayers and shareholders, the Commission concludes that 9.5 percent is a
fair and reasonable return on equity for KCPL. This rate of return will allow KCPL
to compete in the capital market for the funds needed to maintain its financial
health.
B. Fuel adjustment clause
2005
stipulation and agreement
Findings of
Fact
37.
A fuel adjustment clause (“FAC”)
is a mechanism established in a general rate case that allows periodic rate
adjustments, outside a general rate proceeding, to reflect increases and
decreases in an electric utility’s prudently incurred fuel and purchased power
costs.
38.
While the three other
investor-owned electric utilities in Missouri have FACs in place, KCPL does not
have an FAC.
In File No. EO-2005-0329, the Commission approved a stipulation and agreement
which included an Experimental Regulatory Plan (“2005 Stipulation”). That 2005 Stipulation
included a provision that stated:
KCPL agrees that, prior to June 1, 2015, it will
not seek to utilize any mechanism authorized in current legislation known
as “SB 179” or other change in state law that would allow riders or surcharges
or changes in rates outside of a general rate case based upon a consideration
of less than all relevant factors. In exchange for this commitment, the
Signatory Parties agree that if KCPL proposes an Interim Energy Charge (“IEC”)
in a general rate case filed before June 1, 2015 in accordance with the
following parameters, they will not assert that such proposal constitutes
retroactive ratemaking or fails to consider all relevant factors:…
(emphasis added)
39.
The 2005 Stipulation, including the above
provision, was approved by the Commission in its Report and Order issued on
July 28, 2005. The Report and Order directed that the signatory parties,
including KCPL, shall abide by all of the terms and requirements in the 2005 Stipulation.
40.
Senate Bill 179 was passed by the Missouri
General Assembly, signed by the Governor, and became effective on January 1, 2006.
This bill became section 386.266, RSMo, which authorizes electrical
corporations to apply to the Commission for an FAC.
41.
In Missouri, public utilities must file tariff
sheets with the Commission with a specific effective date that determines when
rates can first be charged or programs contained on those tariff sheets can be
implemented. The tariff sheets KCPL filed in this case for
an FAC cannot be used by KCPL until the Commission approves an FAC tariff.
42.
Since KCPL’s last rate increase went into effect
on January 26, 2013, KCPL’s costs related to fuel, purchased power, and
transmission have all increased substantially, while actual revenues have
decreased. KCPL had to absorb these increased costs.
43.
While the Commission authorized a return on
equity of 9.7% for KCPL’s Missouri operations, KCPL was only able to earn a
return on equity of 6.5% in 2013, primarily as a result of increases in fuel,
purchased power and transmission costs.
44.
Without an adequate mechanism to timely recover
these cost increases, KCPL will not have a reasonable opportunity to earn its
authorized return on equity in the foreseeable future.
Because of regulatory lag, it is unlikely that these cost increases could be
recovered through a normal rate case.
45.
KCPL competes for credit with other
vertically-integrated electric utilities in the Midwest and throughout the
country, the vast majority of which already have FACs. KCPL’s inability to
recover its costs, over time, could undermine its financial health and
compromise cash flows, which would jeopardize its ability to compete for
capital, maintain service levels, and invest in its system. The resulting
increased capital costs could potentially lead to increased costs to customers.
46.
On June 10, 2015, Missouri Industrial Energy
Consumers and the Office of the Public Counsel filed a Motion to Strike
Pleadings, Reject Tariff Sheets, and Strike Testimony, to remove from the
record portions of KCPL’s evidence and reject tariff its sheets in support of
its request for an FAC, based on the allegation that KCPL violated the 2005
Stipulation and the Commission’s Report and Order in EO-2005-0329. At the evidentiary hearing, the regulatory
law judge deferred a ruling on the motion and took the motion with the case.
Conclusions
of Law and Decision
All parties other than KCPL have expressed the position that KCPL
has violated the terms of the 2005 Stipulation provision stated above that
prohibits KCPL from seeking to utilize a mechanism such as an FAC prior to June
1, 2015. They argue that by filing the rate case and tariff sheets requesting
approval of an FAC before June 1, 2015, KCPL is improperly seeking to utilize
an FAC before that date. KCPL argues that it has complied with the 2005
Stipulation because if the Commission authorizes an FAC for KCPL, any tariff
approving the use of that FAC will not become effective until after June 1,
2015.
The Commission is a body of limited jurisdiction and has only
such powers as are expressly conferred upon it by the statutes and powers
reasonably incidental thereto.[87] The Commission cannot enforce, construe or
annul contracts,[88]
nor can it declare or enforce principles of law or equity.[89]
However, the “Commission is entitled to interpret its own orders and to ascribe
to them a proper meaning and, in so doing, the Commission does not act
judicially but as a fact-finding agency”.
The Commission’s Report and Order in EO-2005-0329 approved the 2005 Stipulation
and ordered the signatory parties, including KCPL, to abide by its terms. In
determining whether KCPL has complied with that Commission order to abide by
the terms of the 2005 Stipulation, the Commission has the authority to
interpret the meaning of the provision of the 2005 Stipulation in dispute.
The 2005 Stipulation was a settlement agreement, and Missouri
courts generally treat settlement agreements as contracts.
“The primary rule in the interpretation of a contract is to ascertain the
intent of the parties and to give effect to that intent.” “Where
there is no ambiguity in the contract, the intent of the parties is to be
gathered from it alone, and the court will not resort to construction where the
intent of the parties is expressed in clear and unambiguous language as there
is nothing to construe. The intent of the parties shall be determined from the
instrument alone.”
“Contract language is ambiguous when there is uncertainty as to its meaning and
it is fairly susceptible to more than one meaning so that reasonable persons
may fairly and honestly differ on construction of its terms.” “Words
are not ambiguous merely because their meaning and application confound the
parties.”
KCPL argues that “seek to utilize” is not ambiguous, and that
under the plain and ordinary meaning of those words, it means in the context of
a rate case that KCPL is prohibited from having an FAC go into effect prior to
June 1, 2015, regardless of when the request is filed. The other parties argue
that KCPL’s interpretation is incorrect, and that by filing its rate case on
October 30, 2014, KCPL was improperly seeking to utilize an FAC in violation of
the 2005 Stipulation. The dictionary is a good source for finding the plain and
ordinary meaning of contract language, but it is important to consider the
contract’s context in applying the appropriate definition.
The dictionary defines “seek” as “to make an attempt: TRY – used with an infinitive”,
and “utilize” is defined as “to make useful … make use of”. So, under those definitions, seeking to
utilize an FAC means to “try to make use of” an FAC. In the context of a rate
case, it is clear that KCPL cannot try to make use of an FAC until the
Commission has approved tariffs authorizing that mechanism. If the Commission
issues a report and order authorizing an FAC, KCPL will file tariffs in
compliance with that order to implement the FAC. Those compliance tariffs would
both be requested and have an effective date after June 1, 2015.
The Commission finds that terms of the 2005 Stipulation are not
ambiguous, so there is no need to apply the rules of contract construction.
Using the plain and ordinary meaning of the words in the 2005 Stipulation
provision at issue, the filing of KCPL’s rate case on October 30, 2014, did not
seek to utilize an FAC prior to June 1, 2015. Therefore, the Commission
concludes that KCPL did not violate the terms of the 2005 Stipulation, and it
has not violated the Commission’s Report and Order approving that agreement. As
a result of this conclusion, the Commission will deny the Motion to Strike
Pleadings, Reject Tariff Sheets, and Strike Testimony filed by Missouri
Industrial Energy Consumers and the Office of the Public Counsel.
Even assuming for the sake of argument that KCPL violated the
2005 Stipulation, the Commission is not a signatory to that agreement and is
not bound by its terms. The Commission may determine for reasons of public
policy and public interest that KCPL should be granted an FAC even if it did
violate the 2005 Stipulation. The evidence shows that KCPL’s costs related to
fuel, purchased power, and transmission have all increased substantially while
actual revenues have decreased, resulting in KCPL’s inability to earn its
authorized return on equity. KCPL’s
inability to recover its costs, over time, could undermine its financial health
and compromise cash flows, which would jeopardize its ability to compete for
capital, maintain service levels, and invest in its system. The resulting
increased capital costs could potentially lead to increased costs to customers.
Since an FAC is a mechanism that would help KCPL to timely recover its increased
costs for fuel, purchased power and transmission and to avoid the negative
consequences of regulatory lag, the Commission concludes that, for reasons of
public policy, if KCPL meets the criteria for an FAC it should be granted such
authority.
FAC
criteria
Findings of Fact
47.
Fuel used by KCPL to generate electricity is
comprised mainly of coal, nuclear, natural gas and oil, and its costs for fuel
and transportation alone are of such a magnitude that they would materially
impact the utility.
48.
The price of coal, natural gas, nuclear fuel,
and oil, as well as the associated transportation costs, are established by
national or international markets, so KCPL does not have control over commodity
prices.
KCPL cannot control the fundamentals that drive the short and long-term fuel
markets, so fuel costs are beyond the control of KCPL’s management.
49.
Since January 2004, the price for natural gas
has ranged from $1.91/million British thermal units (“MMBtu”) to $15.38, which
is a range of seven times the lowest price. In April 2012, natural gas prices
were as low as $1.91/MMBtu, but by February 2014 those prices had more than
tripled to $6.15. In the six months from February to August of 2015 the price
for natural gas dropped almost 40%.
50.
Coal prices experienced price changes similar to
natural gas. In June 2012, coal prices were $.40/MMBtu. In fewer than two
years, the price had almost doubled to $.76/MMBtu. Just a few months after
reaching that high in April 2014, the price had dropped 17% to $.63/MMBtu.
51.
KCPL’s hedging program can manage some of the
short-term volatility in coal prices, but this does not protect against
long-term market shifts or trends.
52.
For the period of 2016 through 2019, the
approximate time that an FAC would operate, only a fraction of KCPL’s coal
requirements are currently under contract.
53.
KCPL’s net energy costs were more volatile than
13 of the 14 companies in the proxy group used in KCPL’s cost of capital
analysis, and more volatile than Missouri’s three other electric utilities that
have FACs.
Conclusions of Law and
Decision
Section 386.266.1, RSMo, allows the Commission to establish an
FAC for KCPL. Commission Rule 4 CSR 240-20.090(2)(C) states, in part, that:
In determining which cost components to include in a
RAM,
the commission will consider, but is not limited to only considering, the
magnitude of the costs, the ability of the utility to manage the costs, the
volatility of the cost component and the incentive provided to the utility as a
result of the inclusion or exclusion of the cost component.
The evidence shows that KCPL’s fuel and transportation costs are
of such a magnitude that they would materially impact the utility, that those
fuel costs are beyond the control of KCPL’s management, and that its fuel costs
are volatile. In addition, Section 386.266.4, RSMo, provides that an FAC must
be “reasonably designed to provide the utility with a sufficient opportunity to
earn a fair return on equity”.
Permitting KCPL to establish an FAC will assist the company in earning
its authorized return on equity. The Commission concludes that KCPL has met the
criteria for the Commission to authorize an FAC and, therefore, KCPL should be
allowed to establish a fuel adjustment clause.
FAC
tariff provisions
1.
What percentage
(customers/company) of changes in costs and revenues should the Commission find
appropriate to flow through the fuel adjustment clause?
Findings of Fact
54.
KCPL is requesting 100% recovery of the costs
included in its proposed FAC.
55.
Staff is recommending 95%/5% sharing, where
customers would be responsible for, or receive the benefit of, 95% of any
deviation in fuel and purchased power costs as defined in the FAC tariff from
the base amount included in rates.
56.
The other three regulated electric utilities in
Missouri have FACs that provide for 95%/5% sharing from the customers of those
companies.
57.
Customers are the parties with the least amount
of control over the cost of acquisition and supply of fuel used to generate
electricity. KCPL’s requested 100% recovery of costs might act as a
disincentive to manage its fuel expense properly.
Conclusions
of Law and Decision
Under Missouri law, the Commission is
authorized to approve rate schedules for an FAC and may include “features
designed to provide the electrical corporation with incentives to improve the
efficiency and cost-effectiveness of its fuel and purchased-power procurement
activities”. The Commission
finds that allowing KCPL to have 100% recovery of its costs in an FAC would act
as a disincentive for KCPL to control those costs. A 95%/5% sharing mechanism,
where customers would be responsible for, or receive the benefit of, 95% of any
deviation in fuel and purchased power costs would provide KCPL a sufficient
opportunity to earn a fair return on equity while protecting KCPL’s customers
by providing the company an incentive to control costs. KCPL’s FAC shall
include an incentive clause providing that 95% of any deviation in fuel and
purchased power costs from the base level shall be passed to customers and 5%
shall be retained by KCPL.
2.
Should the costs and revenues
that are to be included in the FAC be approved by the Commission and explicitly
identified along with the FERC account, subaccount and the resource code in
which KCPL will record the actual cost/revenue? If so, what costs and revenues
should be included and what are their corresponding FERC accounts, subaccounts
and resource codes?
3.
Should the FAC tariff sheets
reflect the accounts, subaccounts, resource codes, and the cost/revenue
description?
Findings of Fact
58.
No additional findings of fact are necessary, as
this is essentially a policy question for Commission determination.
Conclusions of Law and Decision
No party
disagrees that the Commission should approve costs and revenues to be included in
the FAC. The Commission determines that the FAC tariff sheets should identify
costs and revenues by FERC account and subaccount, but that the use of
corporate resource codes is not necessary.
4.
Should Southwest Power Pool
(“SPP”) and other regional transmission organization/independent system
operator transmission fees be included in the FAC, and at what level?
Findings of Fact
59.
KCPL is a member of SPP, a regional transmission
organization (“RTO”). As of March 1, 2014, SPP implemented its Integrated
Marketplace (“IM”), in which SPP is responsible for the market operations of
its participants and generating resources.
60.
KCPL buys back energy from SPP to meet the needs
of its customers. The price at which KCPL purchases energy from the market will
be at a rate set by SPP that reflects a market price.
61.
On a daily basis, KCPL sells all of the power it
generates into the SPP market and purchases from SPP 100% of the electricity it
sells to its retail customers.
62.
KCPL requests that transmission costs associated
with the charges and revenues from SPP billings, and transmission costs to buy
and sell energy, be recovered in rates through the FAC mechanism. KCPL is
proposing that standard point-to-point transmission charges and base plan
funding in FERC account 565 be included.
63.
KCPL is proposing to place all of its wholesale
transmission expenses and revenues into its FAC, not just those that are for
the transportation of purchased power.
64.
The only transportation costs for purchased
power that KCPL incurs are its wholesale transmission expenses that are
incurred to transmit power it has purchased from SPP or other third parties.
65.
KCPL’s wholesale transmission expenses incurred
to transmit power from its own generation resources to its own load are not
incurred for transportation of fuel or purchased power.
66.
KCPL generally does not incur wholesale
transmission expenses to make off-system sales to SPP or to any third party
located within SPP. Pursuant to the SPP tariff, KCPL generally only incurs
wholesale transmission expenses for off-system sales when those sales are to
third parties located outside of SPP.
67.
Only approximately 7.3% of KCPL’s total SPP
wholesale transmission expenses can be reasonably classified as being for
transportation of fuel or purchased power.
68.
KCPL’s transmission costs have been rising, and
projections show that these expenses will continue to increase at a significant
rate from 2014 through 2019.
69.
While KCPL’s transmission costs are increasing,
those costs are known, measurable, and not unpredictable, so the costs are not volatile.
Conclusions of Law and Decision
Section 386.266.1, RSMo, allows an electric utility to make
periodic rate adjustments only to “reflect increases and decreases in its
prudently incurred fuel and purchased-power costs, including transportation”. This
limits the costs that can be flowed through an FAC for recovery. Transportation
costs have been determined to include transmission costs, but limited only to
those connected to purchased power costs.
KCPL argues that all of its SPP transmission fees should be
included in the FAC because those fees are mandatory, increasing in amount, and
volatile. In addition, KCPL states that since all of its power generation is
sold into the SPP market and purchased from that market, all SPP expenses and
revenues related to those individual sales and purchases of transmission
service must be included in the FAC.
The Commission has addressed this issue in recent rate cases. In
the Report and Order issued in File No. ER-2014-0258 for Ameren Missouri, the
Commission stated:
The evidence demonstrated that for purposes of operation of
the MISO tariff, Ameren Missouri sells all the power it generates into the MISO
market and buys back whatever power its needs to serve its native load. From
that fact, Ameren Missouri leaps to its conclusion that since it sells all its
power to MISO and buys all that power back, all such transactions are
off-system sales and purchased power within the meaning of the FAC statute. The
Commission does not accept this point of view.
The drafters of the FAC statute likely did not envision a
situation where a utility would consider all its generation purchased power or
off-system sales. In fact, the policy underlying the FAC statute is clear on
its face. The statute is meant to insulate the utility from unexpected and
uncontrollable fluctuations in transportation costs of purchased power. At the
time the statute was drafted, and even in our more complex present-day system,
the costs of transporting energy in addition to the energy generated by the utility
or energy in excess of what the utility needs to serve it load are the costs
that are unexpected and out of the utility’s control to such an extent that a
deviation from traditional rate making is justified.
Therefore, of the three
reasons Ameren Missouri incurs transmission costs cited earlier, the costs that
should be included in the FAC are 1) costs to transmit electric power it did
not generate to its own load (true purchased power) and 2) costs to transmit
excess electric power it is selling to third parties to locations outside of
MISO (off-system sales). Any other interpretation would expand the reach of the
FAC beyond its intent.
Similarly, in a subsequent rate case for The Empire District
Electric Company, which is also a member of SPP, the Commission concluded:
Furthermore, as has been
the case since the FAC statute was created, the costs of transporting energy in
addition to the energy generated by the utility or energy in excess of what the
utility needs to serve its load are the costs that are unexpected and
out of the utility’s control to such an extent that a deviation from
traditional rate making is justified. Therefore, the costs Empire incurs
related to transmission that are appropriate for the FAC, from a policy
perspective and by statute, are: 1) Costs to transmit electric power it did not
generate to its own load (“true purchased power”); or 2) Costs to transmit
excess electric power it is selling to third parties to locations outside of
its RTO (“Off-system sales”).
The evidence shows in this case that on a daily basis, KCPL sells
all of the power it generates into the SPP market and purchases from SPP 100%
of the electricity it sells to its retail customers. However, based on the
Commission’s analysis in the two cases cited above, it would not be lawful for
KCPL to recover all of its SPP transmission fees through the FAC. In addition,
while KCPL’s transmission costs are increasing, those costs are known,
measurable, and not unpredictable, so the costs are not volatile. The Commission
concludes that the appropriate transmission costs to be included in the FAC are
1) costs to transmit electric power it did not generate to its own load (true
purchased power); and 2) costs to transmit excess electric power it is selling
to third parties to locations outside of SPP (off-system sales).
5.
Should SPP and FERC
Administrative fees (SPP Schedule 1-A and 12) be included in the FAC?
Findings of Fact
70.
SPP Schedule 1-A fees are for SPP expenses
associated with administering its Open Access Transmission Tariff. These
expenses cover regional scheduling, planning, and market-monitoring services
provided to facilitate the transportation of energy on the transmission system.
71.
SPP Schedule 12 fees are an assessment charged
by FERC related to KCPL’s membership in SPP.
72.
Schedule 1-A and 12 fees are administrative in
nature and not directly linked to fuel and purchased power costs. These fees
support the operation of SPP and are not needed for KCPL to buy and sell energy
to meet the needs of its customers.
73.
RTO administrative fees, such as Schedule 1-A
and 12 fees, are not included in the FACs of other regulated utilities in
Missouri.
74.
Schedule 1-A and 12 fees are variable, but not
volatile in nature.
Conclusions of Law and Decision
KCPL has requested that SPP
Schedule 1-A and 12 fees be included in its FAC. The Commission finds that
these fees are administrative in nature and not directly linked to fuel and
purchased power costs. These fees support the operation of SPP and are not
needed for KCPL to buy and sell energy to meet the needs of its customers.
These fees are neither fuel and purchased power expenses nor transportation
expenses incurred to deliver fuel or purchased power. The Commission concludes
that including such fees would be unlawful under Section 386.266.1, RSMo, and,
therefore, Schedule 1-A and 12 fees should not be included in the FAC. These
fees are appropriate for recovery in base rates.
6.
Should all realized gains and
losses from KCPL’s hedging and/or cross hedging practices be included in the
FAC?
Findings of Fact
75.
KCPL has a hedging program to manage the price
risk of coal and natural gas. The coal price hedging program involves a
strategy of laddering into a portfolio of forward contracts for coal. Laddering refers to purchasing multiple
products with different maturity dates. The natural gas hedging program
involves the purchase of futures contracts to lock in a future price.
76.
KCPL’s hedging programs for both of these fuels
has helped to avoid much of the volatility in the coal market, as well as
exposure to natural gas market price risk.
77.
An example of cross-hedging is the use of
natural gas futures contracts to hedge electricity prices, since there is not a
good market for electricity hedging instruments and the price of each have a strong
relationship and move in tandem.
78.
Cross-hedges are the best means for hedging
power purchases or sales.
79.
KCPL has used cross-hedging to achieve a balance
in its hedging programs to reduce risk and volatility but does not do so at
this time.
Conclusions of Law and Decision
KCPL has requested that its realized gains and losses from its
hedging programs be included in the FAC. Hedging programs help to avoid
volatility in the coal market and limit exposure to natural gas market price
risk. Staff does not object to hedging, but opposes cross-hedging power
transactions with natural gas because KCPL does not currently utilize
cross-hedges. KCPL is persuasive that having the option of using both hedging
and cross-hedging would be valuable to reduce risk and volatility. The
Commission concludes that all realized gains and losses from KCPL’s hedging
and/or cross-hedging practices should be included in the FAC.
7.
Should SO2 amortizations, bio
fuels, propane, accessorial charges, broker commissions, fees and margins, be
included in the FAC?
Findings of Fact
80.
Accessorial charges are a necessary part of
transporting coal by rail, including switching and the release and pick-up of
locomotive power. This type of charge is included in railroad tariffs.
81.
KCPL does not have unique account numbers or
resource codes for these costs, so excluding them would increase the
administrative and audit burden of the company.
82.
SO2 amortizations are collected in
FERC account 509.
Conclusions of Law and Decision
KCPL has requested that charges for SO2 amortizations,
bio fuels, propane, accessorial charges, broker commissions, fees, and margins
should be included in the FAC. Staff objects that these terms are not
adequately defined, which KCPL has agreed to do. Including an appropriate
description of these terms would enable KCPL to operate and Staff to audit the
FAC correctly. Since accessorial charges
are included in railroad tariffs and SO2 amortizations are collected
in FERC account 509, the Commission finds that SO2 amortizations,
bio fuels, propane, accessorial charges, broker commissions, fees, and margins
should be included in the FAC, but should also be specifically defined within
the FAC tariff.
8.
Should the FAC include costs and
revenues that KCPL is not currently incurring or receiving other than insurance
recoveries, subrogation recoveries and settlement proceeds related to costs and
revenues included in the FAC?
Findings of Fact
83.
Allowing new costs and revenues to flow through
an FAC would be a modification to the FAC that the Commission approved.
84.
Including a cost or revenue in the FAC that KCPL
does not currently incur or record clouds the transparency of the FAC and
unnecessarily complicates it.
85.
Insurance recoveries, subrogation recoveries and
settlement proceeds related to costs and revenues included in the FAC are
revenues typically related to an unexpected incident or accident. If these
types of revenues do occur, it is likely that at some point in time, prior to
the receipt of the recovery or settlement, there were increased costs or
reduced revenues due to that circumstance that have been included in the fuel
adjustment rates paid by customers.
Conclusions of Law and Decision
KCPL argues that the FAC should include all costs and revenues
relating to net fuel and purchased power costs, whether or not they are
currently being incurred. However,
allowing a new cost or revenue to flow through an FAC is a modification to that
FAC, which under Section 386.266, RSMo, only the Commission has the authority
to modify. It is the Commission that should make the determination as to what
costs or revenues should flow through the FAC, not the electric utility. An
exception to this would be insurance recoveries, subrogation recoveries and
settlement proceeds related to costs and revenues included in the FAC because
such revenue increases are likely the result of circumstances that already
caused additional costs or reduced revenues in the FAC. The Commission
concludes that the FAC should not include costs and revenues that KCPL is not
currently incurring or receiving, other than insurance recoveries, subrogation
recoveries and settlement proceeds related to costs and revenues included in
the FAC.
9.
Does the FAC need to have
exclusionary language added to insure that NERC and FERC penalties are not
included?
Findings of Fact
86.
Staff proposed a change to KCPL’s exemplar
tariff sheet for an FAC to include a statement that all penalties related to
NERC and FERC compliance standards shall be excluded.
87.
The FERC Uniform System of Accounts (“USoA”) provides guidance that such charges should be
recorded in account 557, which is not includible in the FAC, so there could be
no recovery of such penalties even if the language proposed by Staff were not
included.
Conclusions of Law and Decision
Staff and OPC take the position that it would be preferable to
include language to exclude NERC and FERC penalties from the FAC to make that
completely clear. The Commission concludes that it is not necessary to include
this language because the FERC USoA specifically provides that these penalties
are not to be included. The proposed language should not be included in the
FAC.
10.
Should the phrase “miscellaneous
SPP IM charges, including but not limited to,” be included in KCPL’s FAC
tariff?
Findings of Fact
88.
KCPL has proposed including in the FAC the
phrase “miscellaneous SPP IM charges, including but not limited to,” to
account for any changes to SPP IM market charge types directed by SPP. The
inclusion of the word “miscellaneous” referring to charges is vague.
89.
The Commission takes administrative notice of
the FAC tariff for Union Electric Company d/b/a Ameren Missouri, which tariff
sheets are titled MO. P.S.C. Schedule No. 6, Original Sheet No. 70.1through Original
Sheet No. 73.11 and filed with the Commission.
Conclusions of Law and Decision
The Commission finds that the language proposed by KCPL, which
includes the phrase “miscellaneous SPP IM charges, including but not limited
to,” in the FAC tariff, is too vague and open-ended. The Commission concludes
that the FAC tariff for KCPL should include language regarding changes in the
SPP IM market charge types substantially similar to the FAC tariff language on
that subject found in the FAC tariff for Ameren Missouri in MO. P.S.C. Schedule
No. 6, Original Sheet No. 70.1through Original Sheet No. 73.11.
11.
How should OSSR be defined?
Findings of Fact
90.
KCPL has proposed a definition of revenues from
off-system sales (“OSSR”), as follows:
The following revenues or costs reflected in FERC
Account Number 447: all revenues from off-system sales. This includes charges
and credits related to the SPP Integrated Marketplace including, energy, make
whole and out of merit payments and distributions, Over collected losses
payments and distributions, TCR and ARR settlements, virtual energy costs,
revenues and related fees where the virtual energy transaction is a hedge in
support of physical operations related to a generating resource or load,
generation/export charges, ancillary services including non- performance and
distribution payments and charges and other miscellaneous SPP Integrated Market
charges including, but not limited to, uplift charges or credits. It does not
include sales for resale – private utilities or sales for resale –
municipalities.
91.
Staff has proposed a different definition of
OSSR, as follows:
OSSR = Revenues from Off-System Sales:
The following revenues or costs reflected in FERC
Account Number 447: all revenues from off-system sales. This includes charges
and credits related to the SPP Integrated Marketplace including, energy,
ancillary services, revenue sufficiency and neutrality payments and
distributions, Over collected losses payments and distributions, TCR and ARR
settlements, demand reductions, virtual energy costs, revenues and related fees
where the virtual energy transaction is a hedge in support of physical
operations related to a generating resource or load, generation/export charges,
ancillary services including non- performance and distribution payments and SPP
uplift revenues or credits. Off-system sales revenues from full and partial
requirements sales to municipalities that are served through bilateral
contracts in excess of one year shall be excluded from OSSR component.
92.
Staff’s definition of OSSR struck “make whole
and out of merit payments and distributions”, but added ancillary services,
revenue sufficiency, and neutrality.
93.
Staff’s terminology more accurately describes
the type of revenue that should be included in an FAC.
Conclusions of Law and Decision
The Commission finds that Staff’s definition of OSSR more
accurately and specifically describes the type of revenue that should be
included in an FAC. The Commission concludes that KCPL’s FAC tariff should
include Staff’s definition of OSSR.
12.
How should the "J"
component be defined, i.e., how should “Net System Input” be defined for KCPL’s
operations?
Findings of Fact
94.
The “J” component refers to the definition of
KCPL’s jurisdictional allocation calculation. KCPL proposes that the “J”
component be defined as: J = Missouri Retail Energy Ration = Missouri Retail
kWh Sales/Total Retail kWh Sales (KS and MO) + Sales for Resale (Account
447.100 – Municipals).
95.
Staff proposes that the “J” component be defined
as: Missouri Retail Energy Ration = Missouri Retail kWh sales/ Total Net System
Input (NSI), where NSI is defined as [Retail Sales (KS+MO) + Sales for Resale +
Border Customers + Firm Wholesale + Losses].
96.
KCPL’s Kansas customers are mostly residential
and Missouri customers include more commercial and industrial customers. Typically,
a service area composed of residential customers will experience higher line
loss percentage than that of a system with a mixture of residential, commercial
and industrial customers, such as the Missouri service territory.
Conclusion of Law and Decision
KCPL’s recommendation would be appropriate if line losses are
proportional to kWh sales, but line losses between Missouri and Kansas are not proportional
based on the current customer mix (residential v. commercial/ industrial). The
Commission concludes that Staff’s proposed definition of the “J” component is
more appropriate and should be included in KCPL’s FAC tariff.
13.
Should the rate schedules
implementing the FAC have an amount for the Base Factor when the Commission
initially approves them, or not until after the end of the first FAC
accumulation period?
Findings of Fact
97.
Both KCPL and Staff agree that an FAC Base
Factor must be set in this case and that the Base Factor must be stated in the
FAC tariff.
98.
Staff recommends that the Base Factor be
included both in the body of the FAC tariff and on the “formula” sheet.
99.
The actual calculation of the Base Factor will
need to be modified to reflect the Commission’s final decision in this case.
Conclusion of Law and Decision
The Commission concludes that the Base Factor, as modified to
reflect the Commission’s decision in this case, shall be included both in the
body of the FAC tariff and on the “formula” sheet.
14.
How many different voltage levels
of service should be recognized for purposes of applying loss factors?
Findings of Fact
100.
KCPL provided to Staff a loss study dated
October 29, 2014, which contains system loss calculations and determinations
based on data collected during calendar year 2013.
101.
Staff used the information in this loss study in
developing its recommended two primary and secondary voltage level adjustment
factors.
102.
Midwest Energy Consumers Group proposes that KCPL’s
FAC include four voltage levels, primary, secondary, substation, and
transmission.
103.
KCPL’s loss study does not contain applicable
data for losses at the substation level, which is one of the voltage level
distinctions recommended by MECG, so that recommendation is not based on the
data in the loss study.
Conclusion of Law and Decision
Commission Rule 4 CSR 240-20.090(9) requires an electric utility
that desires to implement a rate adjustment mechanism, such as an FAC, to
complete a jurisdictional system loss study of the corresponding energy losses
experienced in its delivery of electricity. This study must be conducted within
24 months prior to the general rate case in which it requests its rate
adjustment mechanism. KCPL’s line loss study, required by this Commission rule,
does not contain applicable data for losses experienced at the substation
level, so recognition of more than two voltage levels is not currently
supported by a necessary study. The Commission concludes that for this rate
case two different voltage levels of service should be recognized for purposes
of applying loss factors.
KCPL is directed to include in its line loss study for its next
general rate case the information necessary to allow the parties to consider
and evaluate if any additional voltage level adjustment factors should be
incorporated into the design of the FAC tariff in KCPL’s next rate case.
15.
What are the appropriate recovery
periods and corresponding accumulation periods for the FAC?
Findings of Fact
104.
KCPL has proposed recovery periods of October
through September and April through March with the corresponding accumulation
periods of January through June and July through December.
KCPL has indicated that neither Staff nor OPC have any objections to this
proposal.
Conclusion of
Law and Decision
The parties that expressed a position on this issue have agreed
that recovery periods of October through September and April through March with
the corresponding accumulation periods of January through June and July through
December should be included in the FAC. The Commission agrees that these
recovery periods and accumulation periods are reasonable and should be included
in the FAC.
16.
Should FAC costs and revenues be
allocated in the accumulation period's actual net energy cost in a manner
consistent with the allocation methodology utilized to set permanent rates in
this case?
Findings of Fact
105.
KCPL, Staff and OPC agree that FAC costs and
revenues should be allocated consistently with the allocation methodology used
to set permanent rates.
Conclusion of Law and Decision
All parties have agreed that costs and revenues should be
allocated consistently with the allocation methodology used to set permanent
rates in this case. The Commission concludes that FAC costs and revenues should
be allocated in the accumulation period's actual net energy cost in a manner
consistent with the allocation methodology used to set permanent rates in this
case.
17.
If the Commission authorizes KCPL
to have a fuel adjustment clause, what FAC-related reporting requirements
should it order KCPL to comply with?
Findings of Fact
106.
Staff has proposed that the following
information be provided due to the accelerated Staff review process necessary
with FAC adjustment filings:
·
As part of the information KCPL submits when it files a tariff
modification to change its Fuel and Purchased Power Adjustment rate, include
KCPL’s calculation of the interest included in the proposed rate;
·
Maintain at KCPL’s corporate headquarters or at some other
mutually-agreed-upon place and make available within a mutually-agreed-upon
time for review, a copy of each and every coal and coal transportation, natural
gas, fuel oil and nuclear fuel contract KCPL has that is in or was in effect
for the previous four years;
·
Within 30 days of the effective date of each and every coal and
coal transportation, natural gas, fuel oil and nuclear fuel contract KCPL
enters into, provide both notice to the Staff of the contract and opportunity
to review the contract at KCPL’s corporate headquarters or at some other
mutually-agreed-upon place;
·
Provide a copy of each and every KCPL hedging policy that is in
effect at the time the tariff changes ordered by the Commission in this rate
case go into effect for Staff to retain;
·
Within 30 days of any change in a KCPL hedging policy, provide a
copy of the changed hedging policy for Staff to retain;
·
Provide a copy of KCPL’s internal policy for participating in the
Southwest Power Pool’s Integrated Market;
·
Maintain at KCPL’s corporate headquarters or at some other
mutually-agreed-upon place and make available within a mutually-agreed-upon
time for review, a copy of each and every bilateral energy or demand
sales/purchase contract;
·
If KCPL revises any internal policy for participating in the
Southwest Power Pool, within 30 days of that revision, provide a copy of the
revised policy with the revisions identified for Staff to retain; and
· The monthly as-burned fuel report
supplied by KCPL required by 4 CSR 240‑3.190(1)(B) shall explicitly
designate fixed and variable components of the average cost per unit burned
including commodity, transportation, emission, tax, fuel blend, and any
additional fixed or variable costs associated with the average cost per unit
reported (Staff is willing to work with KCPL on the electronic format of this
report).
107.
KCPL has agreed to provide this information to
Staff.
Conclusion of Law and Decision
Since KCPL does not object to providing the reporting
requirements recommended by Staff and listed above, the Commission determines
that KCPL shall comply with those reporting requirements.
18.
If the Commission authorizes KCPL
to have an FAC, should KCPL be allowed to add cost and revenue types to its FAC
between rate cases?
Findings of Fact
108.
Allowing new cost and revenues types to flow
through an FAC would be a modification to the FAC that the Commission approved.
109.
Staff has proposed the following FAC tariff
language that would permit changes to cost and revenue types:
Should FERC require any item covered by components
FC, E, PP, TC, OSSR or R to be recorded in an account different than the FERC
accounts listed in such components, such items shall nevertheless be included
in component FC, E, PP, TC, OSSR or R. In the month that the Company begins to
record items in a different account, the Company will file with the Commission
the previous account number, the new account number and what costs or revenues
that flow through the Rider FAC are to be recorded in the account.
Conclusion of Law and Decision
KCPL should not be able to add cost and revenue types to its FAC
between rate cases unless the FAC tariff provides for those changes. The
Commission concludes that the tariff provision proposed by Staff above is
reasonable and should be included in KCPL’s FAC tariff.
19.
If the Commission authorizes KCPL
to have a FAC, should KCPL be required to clearly differentiate itself from GMO
on customer bills?
Findings of Fact
110.
When KCPL and KCP&L Greater Missouri
Operations Company (“GMO”) were brought under GPE, that company decided to use
a single brand, KCPL, for both. At this time, GMO bills only indicate the KCPL
brand name.
111.
The customer’s rate code is present on the bill
and would serve to direct the customer to the correct tariffs for each
individual company. Customer service employees are available to help customers
identify the applicable tariff sheets.
112.
Changing the bill language and presentation
would not be a trivial undertaking, as space on the bill is limited and can
impact various systemic billing processes.
113.
There is no evidence in the evidentiary record
that demonstrates customer confusion regarding which company provides service.
Conclusion of Law and Decision
The evidence shows that although bills for GMO customers do not
have that company name on them, there is other information on the bill that
would direct a customer to the correct tariff for that company. In addition,
customer service employees are available to provide that information, and
changing the bills would cause hardship to KCPL. Since there is no evidence of
customer confusion, the Commission concludes that KCPL should not be required
to clearly differentiate itself from GMO on customer bills.
C.
Transmission
fee expense
Findings of
Fact
114.
In Missouri, rates are usually established based
upon a historical test year where the company’s expenses and the rate base
necessary to produce the revenue requirement are synchronized. The deferral of
costs from a prior period results in costs associated with the production of
revenues in one period being charged against the revenues in a different
period, which violates the “matching principle” required by Generally Accepted
Accounting Principles (GAAP) and the Uniform System of Accounts approved by the
Commission. The matching principle is a fundamental concept of accrual basis
accounting, which provides that in measuring net income for an accounting
period, the costs incurred in that period should be matched against the revenue
generated in the same period. Such matching creates consistency in income
statements and balance sheets by preventing distortions of financial statements
which present an unfair representation of the financial position of the
business. One type of deferral accounting, a “tracker”, has the effect of
either increasing or decreasing a utility’s earnings for a prior period by
increasing or decreasing revenues in future periods, which violates the
matching principle.
115.
A tracker is a rate mechanism under which the
amount of a particular cost of service item actually incurred by a utility is
tracked and compared to the amount of that item currently included in a
utility’s rate levels. Any over-recovery or under-recovery of the item in rates
compared to the actual expenditures made by a utility is then booked to a
regulatory asset or liability account and would be eligible to be included in
the utility’s rates in its next general rate proceeding through an amortization
to expense.
116.
The broad use of trackers should be limited because
they violate the matching principle, tend to unreasonably skew ratemaking
results, and dull the incentives a utility has to operate efficiently and
productively under the rate regulation approach employed in Missouri.
117.
KCPL requested a tracker for transmission fees
it incurs to send and receive power (“transmission”) through the territory of RTOs
such as the Southwest Power Pool (“SPP”).
118.
KCPL’s transmission costs have increased over
the past several years, but administrative fees charged by SPP are projected to
decrease in the future.
119.
KCPL’s transmission costs are normal, ordinary
and recurring operating costs, and not extraordinary.
120.
KCPL’s correct annualized levels of transmission
expense and revenue to recognize in its revenue requirement on a Missouri
jurisdictional basis are the highly confidential amounts stated in Ex. 256 HC,
Lyons True-Up Rebuttal, p. 14, lines 13-14. These amounts do not include any
transmission costs charged to KCPL by reason of Independence Power & Light
becoming a member of SPP.
121.
In surrebuttal testimony, KCPL requested for the
first time that for SPP transmission fees not included in an FAC or afforded
tracker treatment, $5 million of annual estimated Missouri jurisdiction SPP
transmission fees expense should be added to the revenue requirement above the
base amount of Missouri jurisdiction SPP transmission fees. If the forecast
amount recognized in revenue requirement exceeds actual SPP transmission fee
expense during the period rates are in effect, such amounts should be credited
to customers in a subsequent rate case.
Conclusions
of Law and Decision
The Commission has the statutory authority to prescribe methods
for electrical corporations to keep their accounts, records and books.
The Commission has set forth such proper methods in Commission Rule 4 CSR
240-20.030, which requires every electrical corporation to keep all accounts in
conformity with the Uniform System of Accounts (“USoA”) as prescribed by FERC
and published at 18 CFR Part 101 (2013). In the USoA, Accounts 182.3 and 254,
other regulatory assets and liabilities, describe accounts for recording an
item outside the year of occurrence (“deferral”) for determination in a later
action.
The USoA allows deferral for “extraordinary items”, which are defined as:
Those items related to the effects of events and
transactions which have occurred during the current period and which are of
unusual nature and infrequent occurrence shall be considered extraordinary
items. Accordingly, they will be events and transactions of significant effect
which are abnormal and significantly different from the ordinary and typical
activities of the company, and which would not reasonably be expected to recur
in the foreseeable future.
KCPL has requested that the Commission approve the use of a
particular deferral accounting method, a tracker. This type of deferral
accounting to defer costs which may be incurred in the future is similar to an
accounting authority order that defers expenses incurred as a result of a past
event, in that neither constitute ratemaking. Missouri courts have stated that
the granting of an accounting authority order is not ratemaking and creates no
expectation of recovery.
For example, in a recent rate case, the Commission refused to allow recovery of
amounts deferred under a previous accounting authority order.
Like an accounting authority order, a tracker simply defers a cost for
determination in a future rate case where the Commission may determine whether
that cost should be recovered in rates after considering all relevant factors.
KCPL also requested a transmission tracker in its most recent
rate case, ER‑2012‑0174, under a very similar fact situation. That
Commission denied that requested tracker, finding that KCPL had failed to
demonstrate that the projected cost increases were extraordinary:
“Rare” does not describe cost increases in the
utility business generally. Specifically, Applicants’ evidence shows the
following as to transmission. Transmission is an ordinary and typical, not an
abnormal and significantly different, part of Applicants’ activities. Also,
Applicants showed that paying more for transmission than in the previous year
is a foreseeably recurring event, not an unusual and infrequent event. Thus,
“items related to the effects of” transmission cost increases are not rare and,
therefore, are not extraordinary.
The evidence presented in this case showed that KCPL’s
transmission costs, while having increased in recent years, are normal,
ordinary and recurring operation costs. These recurring costs are not abnormal or
significantly different from the ordinary and typical activities of the company,
so they are not extraordinary and, therefore, not subject to deferral under the
USoA. The Commission concludes that KCPL has not met its burden of proof to
demonstrate that projected transmission cost increases are extraordinary, so
its request for a transmission tracker will be denied.
KCPL’s correct annualized levels of transmission expense and
revenue to recognize in its revenue requirement on a Missouri jurisdictional
basis are the amounts stated in Ex. 256 HC, Lyons True-Up Rebuttal, p. 14,
lines 13-14. These amounts do not include any transmission costs charged to
KCPL by reason of Independence Power & Light becoming a member of SPP. KCPL
has also requested that the Commission add to this amount an additional amount
of $5 million, which it claims is an estimate of its increased transmission
costs, subject to refund in a future rate case. Since this request was first
submitted in surrebuttal testimony, it violates Commission Rule 4 CSR
240-2.130(7)(A), which requires that “[d]irect testimony shall include all
testimony and exhibits asserting and explaining that party’s entire
case-in-chief.” By submitting the request for the first time in surrebuttal,
KCPL has prevented other parties from having a sufficient opportunity to
conduct discovery or provide testimony on that matter. The Commission also
finds that KCPL failed to adequately explain how it arrived at its estimate and
how the Commission has the legal authority to grant such relief. For all these
reasons, the Commission concludes that KCPL’s request for an additional $5
million added to the approved base amount of revenue requirement should be
denied.
D. Property tax expense
Findings of
Fact
122.
KCPL requests that the Commission authorize a
tracker mechanism for its expenses related to property taxes determined by
Missouri state assessors. Those expenses would be deferred for consideration by
the Commission to include in rates in KCPL’s next rate case.
123.
A property tax tracker, as with other types of
trackers, would create an inconsistent matching over time of investments,
revenues and expenses.
124.
KCPL’s property tax expenses have been
increasing for the last five years, and may continue to increase in the future.
125.
Property taxes are normal operating costs that
will continue to occur every year, and an annualized level of such expenses to
include in rates can be reasonably calculated. KCPL’s property taxes are not rare
or unusual.
126.
KCPL’s correct level of property tax expense to
recognize in its revenue requirement on a total company basis is $91,616,599.
127.
In surrebuttal testimony, KCPL requested for the
first time that for property tax expenses not afforded tracker treatment, $5.6
million of annual estimated Missouri jurisdiction property tax expense should
be added to the revenue requirement above the base amount of Missouri
jurisdiction property taxes. If the forecast amount recognized in revenue
requirement exceeds actual property tax expenses during the period rates are in
effect, such amounts should be credited to customers in a subsequent rate case.
Conclusions
of Law and Decision
KCPL has requested that the Commission approval the same type of
deferral mechanism for property tax expenses that it requested for transmission
fee expenses. For that reason, the Commission incorporates herein the analysis
contained in the conclusions of law and decision section from the transmission
fee expense issue discussed above. The Commission concludes that KCPL has not
met its burden of proof to demonstrate that projected property tax increases
are extraordinary, so its request for a property tax tracker will be
denied.
KCPL’s correct level of property tax expense to recognize in its
revenue requirement on a total company basis is $91,616,599. KCPL has also
requested that the Commission add to this amount an additional amount of $5.6
million, which it claims is an estimate of its increased property tax costs,
subject to refund in a future rate case. Since this request was first submitted
in surrebuttal testimony, it violates Commission Rule 4 CSR 240-2.130(7)(A),
which requires that “[d]irect testimony shall include all testimony and
exhibits asserting and explaining that party’s entire case-in-chief”. By submitting
the request for the first time in surrebuttal, KCPL has prevented other parties
from having a sufficient opportunity to conduct discovery or provide testimony
on that matter. The Commission also finds that KCPL failed to adequately
explain how it arrived at its estimate and how the Commission has the legal
authority to grant such relief. For all these reasons, the Commission concludes
that the KCPL’s request for an additional $5.6 million added to the approved
base amount of revenue requirement should be denied.
E. CIP/cyber-security expense
Findings of
Fact
128.
In 2007, the FERC designated the North American
Regulatory Commission (“NERC”) as the electric reliability organization under
the Federal Power Act and subsequently approved NERC’s reliability standards,
which include the Critical Infrastructure Protection (“CIP”) standards. CIP
addresses the security of cyber assets essential to the reliable operation of
the electric grid and is continuously evolving due to the fluid nature of
security threats to critical infrastructure. CIP has recently been updated with
Version 5, which includes new standards. KCPL is subject to these CIP standards.
129.
KCPL is requesting that the Commission authorize
a tracker for the costs related to compliance with CIP and other cyber-security
efforts. Those expenses would be deferred for consideration by the Commission
to include in rates in KCPL’s next rate case.
130.
A cyber-security tracker, as with other types of
trackers, would create an inconsistent matching over time of investments,
revenues and expenses.
131.
KCPL’s CIP/cyber-security costs are projected to
increase as a result of the addition of new employees and capital additions,
primarily in 2015. Thereafter, those costs will decrease for the next two
years.
132.
Compliance with CIP and cyber-security standards
will be an ongoing cost for KCPL for the foreseeable future.
133.
KCPL’s correct level of CIP/cyber-security
expense to recognize in its revenue requirement on a Missouri jurisdictional
basis are the highly confidential amounts stated in Ex. 256 HC, Lyons True-Up
Rebuttal, p. 16, lines 1-2.
134.
In surrebuttal testimony, KCPL requested for the
first time that for CIP/cyber-security costs not afforded tracker treatment,
$3.5 million of annual estimated Missouri jurisdiction CIP/cyber-security
expense should be added to the revenue requirement above the base amount of
Missouri jurisdiction CIP/cyber-security expense. If the forecast amount
recognized in revenue requirement exceeds actual CIP/cyber-security expense
during the period rates are in effect, such amounts should be credited to
customers in a subsequent rate case.
Conclusions of Law and
Decision
KCPL has requested that the Commission approval the same type of
deferral mechanism for CIP/cyber-security expenses that it requested for
transmission fee expenses. For that reason, the Commission incorporates herein
the analysis contained in the conclusions of law and decision section from the
transmission fee expense issue discussed above. The Commission concludes that KCPL
has not met its burden of proof to demonstrate that projected
CIP/cyber-security increases are extraordinary, so its request for a tracker
will be denied.
KCPL’s correct annualized levels of transmission expense and
revenue to recognize in its revenue requirement on a Missouri jurisdictional
basis are the amounts stated in Ex. 256 HC, Lyons True-Up Rebuttal, p. 16,
lines 1-2. KCPL has also requested that the Commission add to this amount an
additional amount of $3.5 million, which it claims is an estimate of its
increased CIP/cyber-security costs, subject to refund in a future rate case.
Since this request was first submitted in surrebuttal testimony, it violates
Commission Rule 4 CSR 240-2.130(7)(A), which requires that “[d]irect testimony
shall include all testimony and exhibits asserting and explaining that party’s
entire case-in-chief”. By submitting the request for the first time in
surrebuttal, KCPL has prevented other parties from having a sufficient
opportunity to conduct discovery or provide testimony on that matter. The
Commission also finds that KCPL failed to adequately explain how it arrived at
its estimate and how the Commission has the legal authority to grant such
relief. For all these reasons, the Commission concludes that KCPL’s request for
an additional $3.5 million added to the approved base amount of revenue
requirement should be denied.
F.
La
Cygne environmental retrofit project
Findings of
Fact
135.
The La Cygne generating station is comprised of
two coal-fired units, Unit 1 and Unit 2. KCPL owns 50% of La Cygne, and Kansas
Gas and Electric Company, a wholly-owned subsidiary of Westar Energy, Inc.,
owns the other 50% share. Pursuant to the ownership agreement, KCPL is
responsible for operating both La Cygne units.
136.
KCPL installed emission control equipment to
reduce emissions from La Cygne by June 1, 2015, in order to comply with the
Regional Haze Agreement that KCPL entered with the Kansas Department of Health
and Environment. The emission control equipment is also required for compliance
with the Mercury and Air Toxics Rule, the Cross‑State Air Pollution Rule,
and the National Ambient Air Quality Standards.
137.
The emissions control equipment that was
installed at La Cygne included limestone-based, wet scrubber flue gas
desulfurization systems, fabric filters, mercury control systems on both Units
1 and 2, and low NOx burners, over-fired air, and selective
catalytic reduction system on Unit 2.
138.
KCPL successfully achieved the in-service
criteria for La Cygne. As of March 24, 2015, Unit 2 was in-service, and as
of April 30, 2015, Unit 1 was in-service.
139.
The projected cost of the entire retrofit
project was $1.23 billion. While the final project costs are not yet
determined, there is an indication that the project will be completed at some
level below the estimated cost. Commission’s Staff conducted a construction
audit and prudence review of the project, and concluded that no adjustments
should be proposed regarding the costs KCPL is requesting to be included in
rates in this case. Staff determined that the prudently incurred costs to
include in KCPL’s Missouri rate base for the La Cygne project were
$292,620,121.
140.
Before making the decision to proceed with the
La Cygne environmental retrofit project, in 2010 KCPL conducted a multi-faceted
analysis of a series of alternative long-term resource plans to assess the risk
associated with various critical factors, such as natural gas prices, retail
customer load growth, and carbon dioxide costs. The end result of this process
resulted in an expected 25-year net present value of revenue requirement
(“NPVRR”) that evaluates the risks associated with uncertain factors in the
electric utility industry.
141.
The results of this analysis completed in early
2011 demonstrated that the most cost-effective solution was the retrofitting of
La Cygne Units 1 and 2.
KCPL’s decision to retrofit La Cygne was supported by its determination that
retiring the La Cygne units and replacing them with combined-cycle natural gas
generation would have resulted in a significant reliance on the relatively more
volatile natural gas market.
142.
KCPL submitted its analysis of whether to retire
or retrofit La Cygne to the Kansas Corporation Commission on February 23, 2011,
as part of a petition for predetermination, which sought authorization to
recover expenditures on the La Cygne retrofits.
The Kansas commission granted KCPL’s petition on August 19, 2011.
143.
Sierra Club’s witness Rachel Wilson alleges that
KCPL was imprudent in 1) failing to consider missing elements in its
calculations that would have raised the costs to retrofit La Cygne, and 2) deciding
to continue with the retrofit project in 2011 and 2012. She argues that while natural gas prices were
declining during this period of time, KCPL should have re-evaluated its
analysis using 2011 and 2012 forecasts from the Energy Information
Administration’s Annual Energy Outlook (“AEO”). Wilson alleges that using this
AEO forecast would have revealed that retirement of La Cygne units would have
been the more economic choice.
144.
KCPL did not fail to consider a reasonable level
of cost-effective energy efficiency or a full range of options for addressing
regulations such as non-gas supply options. The net benefits in KCPL’s original
analysis significantly exceeded other alternative plans considered. KCPL did not consider the conversion from a
wet to a dry bottom ash system for Unit 2, but the projected costs would not
have meaningfully changed the results.
145.
In KCPL’s original analysis, it utilized several
long-term forecasts regarding gas prices, which produces better results over
time than using a single forecast.
KCPL did not use the single AEO forecast alone because that forecast does not
take into account future regulations that can produce upward pressure on gas
prices.
146.
KCPL re-evaluated whether it was appropriate to
retrofit the La Cygne units on four occasions, once each in 2012, 2013, 2014
and 2015, as part of KCPL’s integrated resource planning (“IRP”) process. The
2012 IRP planning work started in the summer of 2011, included the 2012 AEO
forecast, and assumed that no project costs had been committed.
147.
Witness Burton Crawford testified credibly that
the results of each re-evaluation of the La Cygne analysis during the IRP
processes demonstrated that continuing with the retrofit project resulted in
lower overall costs than resource plans that included retiring those units.
Conclusions of Law and
Decision
In rate cases, there is initially a presumption that a utility’s
expenditures incurred in providing utility service, which are one component of
its revenue requirement, are prudent.[211] This presumption can be rebutted upon a
showing of serious doubt as to the prudence of the expenditure, at which point
the utility must dispel this doubt and prove the questioned expenditure is
prudent.[212] The Commission has interpreted this process
as follows:
In the context of a rate case, the parties
challenging the conduct, decision, transaction, or expenditures of a utility
have the initial burden of showing inefficiency or improvidence, thereby
defeating the presumption of prudence accorded the utility. The utility then has the burden of showing
that the challenged items were indeed prudent.
Prudence is measured by the standard of reasonable care requiring due
diligence, based on the circumstances that existed at the time the challenged
item occurred, including what the utility’s management knew or should have
known. In making this analysis, the
Commission is mindful that “[t]he company has a lawful right to manage its own
affairs and conduct its business in any way it may choose, provided that in so
doing it does not injuriously affect the public.[213]
Testimony on behalf of Sierra Club from Ms. Wilson raised a
serious doubt about KCPL’s decision to proceed with the La Cygne retrofit
project following authorization of the project by the Kansas Corporation
Commission. Natural gas prices did fall shortly after KCPL completed its
original analysis showing that the retrofit project was a lower-cost option
than retirement of the units, and that original analysis did not take into
account an AEO forecast showing those lower gas prices. Ms. Wilson alleges that
KCPL waited too long to re-evaluate its original decision, and if it had done
so it would have found that retirement was actually the lower-cost option after
considering the lower gas prices.
KCPL’s witnesses testified credibly, however, that the 2012 re-evaluation
process was started just a few months after the release of the 2012 AEO
forecast, that they included that forecast, in addition to several other more
reliable forecasts, in their planning process, and that the result of the 2012
IRP process yielded the same result as the original KCPL analysis that was
approved in Kansas. When the retrofit project was re-evaluated each year in
2012-2015, those studies showed that the retrofit project resulted in lower
overall costs than resource plans that included retiring those units. In
addition, the evidence shows that KCPL did not fail to consider missing
elements in its calculations that would have raised the costs to retrofit La
Cygne.
The Commission concludes that KCPL has met its burden of proof to
demonstrate that, based on the circumstances that existed at the time, KCPL was
prudent in choosing to proceed with the La Cygne environmental retrofit
project. The correct and prudently
incurred costs to include in KCPL’s Missouri rate base for the La Cygne project
are $292,620,121.
G.
Rate
case expense
Findings of Fact
148.
Rate case expense can be defined as all
incremental costs incurred by a utility directly related to an application to
change its general rate levels.
149.
KCPL’s total rate case expense as of August 12,
2015, is $1,024,304.
150.
Rate case expense can benefit both utility
shareholders and customers, though often in different ways. A utility and its
shareholders directly benefit from this expense because generally these costs
are incurred in order to increase a utility’s revenues and, ultimately, its
profitability. Customers benefit generally from being served by financially
healthy utilities, which is bolstered in part by the ability of a utility to
periodically seek increased rates to recover increasing expenses and earn a
return on investments in their systems.
151.
The rate case process can be adversarial in
nature, with the utility and ratepayers on opposing sides.
152.
KCPL engaged several outside experts and
consultants in this case. Witness Spanos performed
the depreciation study required by Commission rules. Mr. Hevert performed a cost of capital/capital structure
analysis using industry-wide data. Witness Rogers did a highly-specialized
study to determine the cost of dismantling non‑nuclear generating units.
Mr. Overcast testified on the topic of regulatory mechanisms. These types of
testimonies and studies are generally performed by outside experts in rate cases
in Missouri.
153.
Staff and OPC propose that the expenses of KCPL
witness Overcast be disallowed as duplicative of testimony given by other
witnesses.
154.
KCPL retained the services of witness Overcast
to respond to other parties opposed to KCPL’s requests for a fuel adjustment
clause and trackers. Mr. Overcast was hired to provide a nationwide view of how
other jurisdictions have approached such alternative regulatory mechanisms.
155.
KCPL was represented in this case by both
in-house and external legal counsel. KCPL used two in-house attorneys and
employed two outside attorneys. The two outside attorneys have represented KCPL
in numerous rate cases and other Commission proceedings in the past to
supplement the in-house legal team.
156.
OPC witness Addo
proposed adjustments to rate case expenses, including reducing the hourly rates
of KCPL outside attorneys to $200/hour, based on the rates one attorney charged
Ameren Missouri and the results of a 2013 survey of hourly rates by the
Missouri Bar.
157.
Mr. Addo did not
compare the background and experience of the KCPL attorneys with that of the
Ameren Missouri attorney, and he did not calculate the number of hours or
examine the tasks that Ameren Missouri’s counsel performed on a prior rate
case.
158.
In Missouri, almost all utilities hire witnesses
to sponsor their rate of return/return on equity positions in rate cases and
often hire consultants to handle other issues, as well.
159.
In a rate case, a utility chooses how many and
what type of consultants it will engage, what issues to pursue, and what legal
strategies it will employ, and therefore, the extent of rate case expense is
largely at KCPL’s discretion.
160.
The expenses in this case are driven primarily
by issues raised by KCPL, which has complete control over the content and methodologies
proposed in its rate cases. For example, KCPL has requested several trackers,
two of which have never been requested before in Missouri and two of which were
first presented in rebuttal testimony,
and has requested recovery in rates of the expenses from the Clean Charge
Network.
161.
KCPL has requested that all costs and expenses
associated with legal representation, consultants, and expert witnesses be
included in its increased revenue requirement.
162.
All consumer groups were represented by hired counsel
in this case, and some also engaged expert witnesses. While KCPL is able to
recoup the costs of its legal counsel and expenses through utility service
rates, OPC, the entity representing ratepayers, operates within a tight annual
budget, and interveners pay their own legal expenses.
163.
Prudency reviews, by their nature, are not a
strong incentive to control costs. The utility holds all the information a
challenging party needs to prove imprudence, and it is not likely a challenging
party could identify all instances of imprudence, even when engaged in a
conscientious prudence review.
164.
Awarding a utility all of its incurred rate case
expenses could provide that utility with a significant financial advantage over
other participants in the rate case process, who may be constrained by
budgetary and other financial restrictions. Such a practice does not encourage
reasonable levels of cost containment in the utility’s rate case expense
decisions.
165.
An incentive for a utility to limit its rate
case expense is to tie a utility’s percentage recovery of rate case expense to
the percentage of its rate increase request that the Commission finds just and
reasonable. Use of this approach would directly tie a utility’s recovery of
rate case expense to both the reasonableness of its issue positions and the
dollar value sought from customers in a rate case.
166.
KCPL previously filed rate cases in 2006, 2007,
2009, 2010, and 2012.
In recent rate cases, KCPL has incurred rate case expenses substantially higher
than historical levels and higher than other utilities in Missouri.
167.
Prudence is not the only consideration in
determining what costs should be included in rates; the benefit to customers
must also be considered when deciding what costs are reasonable for customer
rates.
168.
KCPL has pursued issues in this case that
benefit only the shareholders, such as La Cygne construction accounting and
some elements of the rate of return recommendation.
Utility expenses that are highly discretionary and do not benefit customers,
such as charitable donations, political lobbying expenses, and incentive
compensation tied to earnings per share, are typically allocated entirely to
shareholders.
169.
Staff and OPC recommend that the Commission
require shareholders and ratepayers to share the rate case expense costs
equally.
Staff also proposes, as an alternative to equal sharing of expenses, that KCPL
receive rate recovery of rate case expenses in proportion to the amount of rate
relief it is granted compared to the amount of its original rate increase
request.
Conclusion of Law and Decision
In a rate case, the Commission has broad discretion to determine
which expenses a utility may recover from ratepayers. The Missouri Supreme
Court has stated that the Commission’s statutory power and authority to set
rates “necessarily includes the power and authority to determine what items are
properly includable in a utility's operating expenses and to determine and
decide what treatment should be accorded such expense items.”
The Commission’s authority extends to allocating an expense between certain
classes or groups of ratepayers
and to requiring company shareholders to bear expenses the Commission finds to
be unreasonable or unnecessary.
As stated above, there is initially a presumption that a utility’s
expenditures incurred in providing utility service, which are one component of
its revenue requirement, are prudent.[242] This presumption can be rebutted upon a
showing of serious doubt as to the prudence of the expenditure, at which point
the utility must dispel this doubt and prove the questioned expenditure is
prudent.[243]
Staff and OPC allege that the expenses of witness Overcast should
be disallowed because his testimony was duplicative and those expenses were
imprudent. Similarly, OPC and MECG argue
that the fees of KCPL’s outside attorneys were imprudent and should be reduced
to $200/hour or disallowed entirely. These
expenses for experts, consultants, and attorneys do not lend themselves to
review for prudence. Unlike industry standards for pipe size or transmission
line capacity, there is no accessible appropriate standard for determining
whether one consultant’s analysis was truly unnecessary or if one attorney’s
expertise is worth more than another’s. The evidence does not reveal a bright
line solution to this problem, and the Commission will not disallow these or
any other rate case expenses in this case.
Instead, the Commission will consider whether it is reasonable
that KCPL shareholders cover a portion of KCPL’s rate case expense. In one sense,
rate case expense is like other common operational expenses that a utility must
incur to provide utility services to customers. Since customers benefit from
having just and reasonable rates, it is appropriate for customers to bear some
portion of the utility’s cost of prosecuting a rate case.
However, rate case expense is also different from most other
types of utility operational expenses, in that 1) the rate case process is
adversarial in nature, with the utility on one side and its customers on the
other; 2) rate case expense produces some direct benefits to shareholders that
are not shared with customers, such as seeking a higher return on equity; 3)
requiring all rate case expense to be paid by ratepayers provides the utility
with an inequitable financial advantage over other case participants; and 4)
full reimbursement of all rate case expense does nothing to encourage
reasonable levels of cost containment.
The Commission has the legal authority to apportion rate case
expense between ratepayers and shareholders. Under Missouri law, the Commission
must set just and reasonable rates,
and rates that include all of the utility’s rate case expense, for the reasons
set forth above, may not be just or reasonable.
Moreover, this Commission has already found rate case expense sharing to be
just and reasonable in at least one prior case. In a 1986 decision, In the Matter of Arkansas Power and Light
Company, the Commission “adopted Public Counsel’s proposed disallowance of
one-half of rate case expense.” It is also important to note that there are a
number of other cases where the Commission acknowledged it has this authority.
KCPL argues that it would be unlawful for the Commission to adopt
a new policy related to the recovery of rate case expense without conducting a
rulemaking proceeding under Chapter 536, RSMo. The Commission agrees that it
cannot prospectively change its statement of general applicability that
implements, interprets or prescribes law or policy, or that describes the
organization, procedure, or practice requirements before this agency. [248] Agencies cannot engage in this type of
rulemaking by an adjudicated order.[249]
However, the Commission is not
announcing a general change in policy regarding rate case expense for all
utilities in this Report and Order. Rather, the Commission is setting just and
reasonable rates under the particular facts of this case, so the Commission is
not engaging in improper rulemaking.
The evidence shows that the expenses in this case are driven
primarily by issues raised by KCPL, which has complete control over the content
and methodologies proposed when it files its rate cases. In this case, KCPL has
requested three new trackers, two of which have never been requested before in
Missouri. KCPL has also requested recovery in rates of the expenses from the
Clean Charge Network, which is a type of expense that has never been raised in
a rate case before this Commission. Each of these issues are unique to KCPL,
and while KCPL always has the opportunity to pursue new and unique issues in a
rate case, the decision to do so is entirely with KCPL’s power. In addition,
KCPL has pursued some issues that only directly benefit shareholders, such as
the La Cygne accounting authority and, of course, a higher ROE. In recent rate
cases, KCPL has incurred rate case expenses substantially higher than
historical levels and higher than other utilities in Missouri.
The Commission finds that in order to set just and reasonable
rates under the facts in this case, the Commission will require KCPL
shareholders to cover a portion of KCPL’s rate case expense. One method to
encourage KCPL to limit its rate case expenditures would be to link KCPL’s
percentage recovery of rate case expense to the percentage of its rate increase
request the Commission finds just and reasonable.
The Commission determines that this approach would directly link KCPL’s
recovery of rate case expense to both the reasonableness of its issue positions
and the dollar value sought from customers in this rate case.
The Commission concludes that KCPL should receive rate recovery
of its rate case expenses in proportion to the amount of revenue requirement it
is granted as a result of this Report and Order, compared to the amount of its
revenue requirement rate increase originally requested. This amount should be
normalized over three years. The Commission also finds that it is appropriate
to require a full allocation to ratepayers of the expenses for KCPL’s
depreciation study, recovered over five years, because this study is required
under Commission rules to be conducted every five years.
H.
Management
audit
Findings of Fact
170.
KCPL’s Administrative & General (“A&G”)
costs from 2011 through 2013 were higher than three other utilities operating
in this region. While the reasons for this are unknown, it may be due to a
structural problem.
171.
Staff’s
analysis of KCPL’s A&G expenses, which examined the peer group utilities
that KCPL used to determine executive compensation, credibly demonstrated that
KCPL has some of the highest A&G expenses of its national peers and
Missouri utilities. Of the group examined, KCPL has the highest A&G costs
per customer, per dollar of revenue, and compared to its operations and
maintenance expense, and the third highest A&G expense per megawatt hour of
electricity sold.
172.
A management audit focused on identifying and
achieving efficiencies and cost reductions should benefit both KCPL’s customers
and shareholders.
Conclusions of Law and
Decision
MECG and MIEC witness Kollen has recommended that the Commission
direct KCPL to undergo a management audit by an independent auditor to identify
cost savings and efficiencies. The evidence showed that KCPL’s A&G expenses
are significantly higher than its peers, but that the cause for this
discrepancy is unknown. The Commission finds that it would benefit both
customers and shareholders to find efficiencies and reduce costs, so a
management audit is a reasonable mechanism to accomplish this result. However,
rather than charge the costs of such an audit to KCPL’s customers or
shareholders, such an audit could be performed by the Commission’s Staff. The
Commission will initiate a separate case after this case is concluded that
directs the Commission’s Staff[255]
to audit KCPL’s A&G expenses.
I.
Clean
Charge Network
Findings of Fact
173.
On January 26, 2015, KCPL publicly announced
that it had launched a joint initiative (“Clean Charge Network”) with KCP&L
Greater Operations Company to install and operate more than 1,000 electric
vehicle charging stations throughout the greater Kansas City region. The
charging stations would be capable of supporting more than 10,000 electric
vehicles and upon completion would be the largest such utility-owned
installation in the United States.
174.
During a two-year pilot period, the Clean Charge
Network would offer free charging on every station to all electric vehicle
drivers. Any electricity costs for charging station usage would be paid by
partnering organizations during the pilot period.
175.
KCPL has initiated the Clean Charge Network to
promote environmental sustainability, reduce carbon emissions, and help the
Kansas City region attain EPA regional ozone standards.
176.
KCPL has requested that the charging stations
placed in service in its Missouri service territory as of May 31, 2015, be
included in rate base as a part of the revenue requirement for this case.
As of that date, KCPL has invested $732,559 in its Clean Charge Network in
Missouri, but plans to invest a total of $7-8 million.
177.
KCPL developed the Clean Charge Network project
without soliciting input from any of the parties to this case, including those
parties representing customers who would bear the costs of the project if the
Commission includes those costs in KCPL’s revenue requirement.
178.
KCPL has not established any criteria by which
it proposes to measure the success of the Clean Charge Network, and has not
conducted studies concerning the five areas of alleged public benefit –
beneficial electrification, environmental benefits, economic development,
customer programs, and cost and efficiency benefits.
179.
Important program details relating to ratepayer
subsidies, program goals, income distribution, public participation, tariffs,
program design, scope of the investment, risk shifting, cost-benefit analysis,
participating organizations, host sites, free electricity offerings,
anti-competitive subsidies, and proper performance-based measures to determine
effectiveness are all missing from KCPL’s proposal and would be best addressed
in a separate working case.
180.
A KCPL witness agreed that a working case would
be a good place to address long-term policy issues relating to the Clean Charge
Network, including potential impacts on both customers and the company.
Conclusions of Law and
Decision
KCPL’s proposed Clean Charge Network is an important first step
in creating an infrastructure to serve the increasing number of customers who
choose to purchase electric vehicles, and the Commission commends KCPL for its
efforts to anticipate this future demand and for its commitment to
environmental sustainability. However, this issue was raised for the first time
more than three months after KCPL first filed this case and without seeking
input from this Commission or other parties to the case. The proposal currently
lacks important information that is critical to designing and implementing a
program unlike any other existing in the state. While the Commission believes
that it would be beneficial to move forward with the Clean Charge Network, it
is premature to require KCPL’s customers to bear the costs of the program. The
Commission concludes that KCPL has failed to meet its burden of proof to
demonstrate that the charging stations placed in service in its Missouri
service territory as of May 31, 2015, should be included in rate base as a part
of the revenue requirement for this case, so that request will be denied. The
Commission will establish a working case in order to address the legal and
long-term policy issues relating to the Clean Charge Network.
J.
Income
tax issues
CWIP-related ADIT
Findings of Fact
181.
Accumulated deferred income taxes (“ADIT”) are
assets or liabilities that represent the cumulative amounts of additional income
taxes that are estimated to become receivable or payable in future periods. Future
income taxes are impacted by tax returns filed today because of differences between
book accounting and income tax accounting regarding the timing of revenue or
expense recognition.
182.
Specific provisions within GAAP require
recognition of income tax impacts from these book/tax timing differences, by
recording ADIT assets or liabilities. ADIT assets generally occur when revenue
taxation occurs prior to book recognition of the revenues or when the tax
deductibility for expenses is subsequent to the book recognition of the
expense. ADIT liabilities, on the other hand, represent delayed taxation of
revenues or advance deduction of expenses, in relation to the timing of the
same transactions on the books. ADIT balances exist to recognize that certain
tax expenses are determinable today, but actually become payable in the future
whenever book/tax timing differences ultimately reverse.
183.
From a ratemaking perspective, a utility’s
persistently large credit ADIT balances caused by the deferred payment of
recorded tax expenses represent a significant source of capital to the utility.
ADIT balances represent a form of zero-cost capital to the utility created by
the income tax savings permitted under tax laws and regulations that are not
immediately “flowed through” to ratepayers and would benefit only shareholders
unless properly recognized as a rate base reduction. ADIT balances are normally
included in rate base as reductions by regulators, so as to limit the utility
to only a return on the net amount of investor-supplied capital to support rate
base assets.
184.
KCPL records ADIT that is associated with
Construction Work in Progress (“CWIP”) reflected on its books and records. This
ADIT represents a free source of capital funds available for use by the utility
before the construction project is completed and included in plant-in-service.
CWIP is excluded from the rate base on which KCPL earns a return in the
ratemaking process. Although CWIP is not included in rate base, KCPL is allowed
to earn an Allowance for Funds Used During Construction ("AFUDC")
before the property under construction is added to rate base. AFUDC is accrued
during the construction of the asset and included in rate base when the plant
is placed into service. The amount of AFUDC is included in depreciation and
rate base over the life of the plant. For the calculation of AFUDC, there is no
consideration for ADIT as a reduction to the base on which it is calculated;
the AFUDC is calculated on the “gross” amount, with no consideration of ADIT.
185.
Because ADIT is not considered in the
calculation of AFUDC, the benefit must be accounted for by an offset to rate
base for ADIT associated with CWIP balances.
186.
KCPL ratepayers provide fully-normalized income
taxes in the cost of service regardless of the actual amount paid to the IRS. Even
if KCPL is not realizing all the benefits of accelerated depreciation due to a
net operating loss position, it does not invalidate the fact that ratepayers
are providing several million dollars in cash income taxes.
Conclusions of Law and
Decision
KCPL excluded the ADIT liability related to CWIP since the
capital expenditures have not been included in rate base. KCPL argues that
since CWIP cannot be included in rates in Missouri, KCPL’s shareholders, not
its customers, are paying the costs associated with plant under construction.
KCPL states that it is unfair to include the ADIT offset to rate base when the
CWIP itself may not be included.
The Commission considered this issue recently in another rate
case. In reaching the conclusion that it is appropriate to reduce rate base for
CWIP-related ADIT balances, that Commission stated that:
CWIP related ADIT balances must be accounted for in
rate base because AFUDC is applied to Ameren Missouri’s gross investment in
CWIP, with no recognition given to the CWIP-related ADIT amounts that serve to
reduce the company’s actual net capital requirements for CWIP… In other
words, failure to recognize the CWIP-related ADIT balance in the company’s rate
base will overstate the companies AFUDC costs and future rate base, essentially
allowing the company to earn AFUDC and a return on capital supplied by
ratepayers.
KCPL asserts that its situation is different than that of the
utility at issue in File No. ER-2012-0166 because KCPL has a net operating
loss and, as a consequence, KCPL has more deductions than it has revenues
during the applicable period, so it has not and will not receive a cash tax
benefit. However, KCPL ratepayers provide fully-normalized income taxes in cost
of service regardless of whether KCPL pays those taxes concurrently to the IRS.
Even if KCPL is not realizing all the benefits of accelerated depreciation due
to a net operating loss position, it does not invalidate the fact that
ratepayers are providing several million dollars in cash income taxes. The
Commission concludes that the amount of ADIT related to CWIP should be an
additional reduction to KCPL’s rate base.
1KC Place lease ADIT
Findings of Fact
187.
KCPL occupies leased office space in downtown
Kansas City in a building known as 1 KC Place and has received certain lease
abatement benefits in connection with its lease agreement. On its books, KCPL
has recorded a significant liability balance to recognize the delayed
obligation to make additional lease payments. In connection with this liability
balance, a large and offsetting deferred tax asset was recorded to recognize
that accrued but unpaid future lease costs are not currently deductible for
income tax purposes. KCPL proposes to include in rate base the debit ADIT item
to increase rate base, but not the corresponding accrued lease liability
balance that would reduce rate base if recognized.
188.
The accrued liability for the deferred rent
payments on the 1KC Place lease has not been included in rate base, but this
accrued liability is being amortized as a reduction to rent expense.
189.
This reduced rent expense is included in the
cash voucher line within the expense lead day calculations of KCP&L’s lead
lag study. Although there has not been a separate lead lag computation on the
1KC Lease directly, the reduction in rent expense is included in the overall
cash working capital computations and in the rent expense included in cost of
service.
Conclusions of Law and
Decision
A proposed adjustment concerns the ADIT asset related to the
1KC Place lease. This ADIT increases rate base, unlike the ADIT related to
CWIP. Because the deduction for the 1KC Place lease has not been taken on a tax
return, but has been taken for financial and regulatory purposes, the ADIT
asset represents tax benefits that the ratepayers have received in computing
income tax expense but that KCPL has not received on its tax returns.
KCPL has not included the accrued liability for the deferred rent
payments on the 1KC Place lease in rate base. This exclusion is appropriate
because the accrued liability is being amortized monthly as a reduction to rent
expense in cost of service. This reduced rent expense is also included in
KCPL’s lead lag computation of cash working capital. The Commission concludes
that the impact of this liability has been included in the case, and the ADIT asset
related to this liability should be included in rate base, so no adjustment
should be made.
Employee compensation ADIT
Findings of Fact
190.
Certain elements of employee compensation are
paid much later than they are earned, requiring the Company to recognize an
accrued liability for such deferred compensation and bonus pay that is owed to
its employees.
191.
The accrued liability for the employee
compensation and bonus pay has not been included in rate base.
192.
This accrued liability is for two different
items. One item is the ADIT asset for the deferred compensation, where certain
executives have elected to defer the payout of a portion of their salary and
incentive compensation to a future period. The second item is the ADIT asset
for the incentive compensation (bonus pay) that is accrued during the year, but
is not paid out in cash until March 15 of the following year. For both of these
items, the salary and incentive compensation is included in cost of service
expense and in the total payroll or cash voucher line on the lead day
calculations of KCP&L’s lead lag study. Although there has not been a
separate lead lag computation on these liabilities directly, the salary and
incentive compensation is included in the overall cash working capital
computations and in the payroll expense included in cost of service.
Conclusions of Law and
Decision
The proposed adjustment to exclude the ADIT asset related to
employee compensation and bonus pay from rate base would also decrease the
revenue requirement. The proposed adjustment, which is similar to the proposal
for the 1KC Place lease, is based on an argument that the liability for the
accrued employee compensation and bonus pay is not in rate base so the ADIT
asset related to this tax timing difference should also be excluded. However,
both deferred compensation and bonus pay are included in the overall cash
working capital computations, and the payroll expense is included in cost of
service. Therefore, since the impact of this liability has been included in
this case, the Commission concludes that the ADIT asset related to this
liability should be included in rate base and no adjustment should be made.
Net operating tax losses
Findings of Fact
193.
KCPL files its taxes as part of a consolidated
group, consisting of GPE and its affiliated companies. Consolidated filing
benefits the entire group, but it is the nature of a consolidated filing that
any given member may be better off in some years and worse off in other years
as a result of consolidated filing.
194.
A net
operating loss (“NOL”) is created when, in any year, a taxpayer reports more
deductions than it has taxable income. Under the generally applicable tax
rules, an NOL can be carried back two years or forward 20 years. In the year in
which it is carried to, an NOL is treated like an additional deduction,
reducing the taxable income otherwise produced in that year.
When an NOL must be carried forward, a portion of the deductions claimed
by the taxpayer in the year that the NOL is created will not offset taxable
income and not reduce the taxpayer’s tax liability – thus, no cost-free capital
was received for the amount of NOL that did not reduce the tax liability.
195.
In KCPL’s rate case application, it reflected
the impact of its NOL carryforward for tax purposes as an ADIT asset (a
deferred tax asset) of approximately $37.8 million. This had the effect of
increasing rate base by that amount (by decreasing the overall ADIT balance
which reduces rate base).
196.
KCPL reduces its rate base by its net ADIT
liability balance (sum of deferred tax assets and deferred tax liabilities) as
a result of timing differences between deductions for tax purposes and
financial statement purposes. The net deferred tax liability is used to reduce
rate base because it represents a source of cost-free capital (a reduction in
the amount of cash paid for tax purposes) that KCPL has received as a
consequence of claiming certain tax deductions. In a year that KCPL generates a
net operating loss for tax purposes that is carried forward, the NOL
carryforward reduces the amount of cost-free capital it received. Therefore,
KCPL has reflected in its rate base computation the actual impact its NOL has
had on the amount of cost-free capital it received using the method prescribed
under the Internal Revenue Service regulations to allocate losses to companies
within a consolidated group.
197.
KCPL computes the amount of NOLs allocated to
each subsidiary based on when and how the NOLs are used by the consolidated
group in accordance with the Tax Allocation Agreement Among Great Plains Energy
Incorporated and Affiliates (“Tax Allocation Agreement”). The Tax Allocation
Agreement was put in place to ensure that each subsidiary received benefit for
all tax attributes when used by the consolidated group and to ensure that all
subsidiaries paid any tax liabilities it incurred or got benefit for any tax
credits or NOLs it generated, but only when incurred or used by the
consolidated group. This method most accurately represents the economics and
the cash flow that actually occurs when a consolidated return is filed.
198.
In its calculations, KCPL has used the actual
amount of cost-free capital it actually received; it has used the amounts
reflected on its financial records. These amounts reflect the actual cash that
KCPL has received in connection with the claiming of its tax deductions.
199.
MECG proposes to reduce the NOL carryforward
ADIT asset by computing the NOL amounts on a KCPL “stand-alone” basis instead
of using the amounts computed under the Tax Allocation Agreement. This proposed
adjustment would involve imputing an additional amount of cost-free capital
equal to the additional amount that would have been received as of the end of
the true-up period had KCPL filed in this stand-alone basis. This approach
would produce more cost-free capital than KCPL actually received, thereby
reducing the amount of deferred tax asset included in rate base.
Conclusions of Law and
Decision
MECG has proposed an adjustment that would reduce KCPL’s rate
base amount as a result of reducing the NOL carryforward ADIT asset by
computing the NOL amounts on a KCPL “stand-alone” basis instead of using the
amounts computed under the Tax Allocation Agreement. MECG suggests that the
Commission’s affiliate transaction rule may be used to justify a change in the
way the NOL deferred tax assets are computed for KCPL. Commission Rule 4 CSR
240-20.015(2) states:
(2) Standards.
(A) A regulated
electrical corporation shall not provide a financial advantage to an affiliated
entity. For the purposes of this rule, a regulated electrical corporation shall
be deemed to provide a financial advantage to an affiliated entity if –
1. It compensates an affiliated entity for good
or services above the lesser of –
A. The fair market price; or
B. The fully
distributed cost to the regulated electrical corporation to provide the goods
or services for itself; or
2. It transfers information, assets, goods or
services of any kind to an affiliated entity below the greater of –
A. The fair market price; or
B. The fully distributed cost to the regulated electrical corporation.
Section
4 CSR 240-20.015(1)(B) defines affiliate transaction as:
B. Affiliate
transaction means any transaction for the provision, purchase or sale of any
information, asset, product or service, or portion of any product or service,
between a regulated electrical corporation and an affiliated entity, …
The Commission has ruled on this issue in a recent case with a
very similar fact situation. In that case, the Commission stated that “[t]he
Commission’s affiliate transaction rules do not apply in this situation because
there is no transaction involved. The affiliate transaction rules are intended
to control transfers of goods or services between regulated utilities and their
affiliates… where there is no transaction, the restrictions of
the rule have no meaning.”
The Commission finds that the affiliate transaction rule does not apply to this
situation.
In that prior case, where Ameren Missouri used the consolidated
NOL as allocated to the utility under a tax allocation agreement between the
subsidiaries of a consolidated group, the Commission stated that:
Ameren Missouri proposes to use the NOLC [net
operating loss carryforward] it has actually accumulated rather than a
hypothetical NOLC proposed by MIEC and supported by Staff, MIEC advocates a
policy that arrangements between affiliates should always be interpreted in a
manner that benefits ratepayers, even if that results in a detriment to the
utility. There is no basis in law or fact for such a policy. The Commission
must balance the interests of ratepayers and shareholders to set just and
reasonable rates. Ameren Missouri’s position is fair and will be adopted.
MECG attempts to distinguish the prior case by alleging that the
Tax Allocation Agreement to which KCPL is obligated does not benefit KCPL or
its ratepayers. Even if no benefits have accrued to KCPL in the recent past,
that does not mean that KCPL and its ratepayers will not benefit in the future.
There is no evidence in the record showing that KCPL has attempted to
manipulate its tax obligations to take advantage of ratepayers, and the
Commission will not question management decisions made by the company with
regard to its tax filings under such a tax allocation agreement. The Commission
concludes the proposed adjustment to the computation of ADIT assets related to
net operating losses should be rejected.
K.
Class
cost of service, rate design, and tariff rules
1. Class cost of service-production plant-
What methodology should the Commission use to allocate fixed production plant
costs among customer classes?
2. Rate design
a. What methodology is most reasonable for
allocating net cost of service
among the customer classes in this case?
b. How should any revenue increase be
allocated among rate schedules?
c.
What,
if any, interclass shift in revenue responsibilities should the
Commission make?
Findings of Fact
200.
A class cost of service study is a method by
which utility costs and revenues are reconciled across different customer
classes. In general, utilities incur three categories of costs: 1)
customer-related costs, which are costs associated with connecting customers to
the distribution system, metering usage and other customer support functions;
2) energy-related costs, which are costs that tend to change with the amount of
electricity sold; and 3) demand-related costs, which are costs associated
with meeting maximum electricity demands.
201.
KCPL has invested almost $8.7 billion in its
various production, transmission and distribution facilities. Of this, over 63
percent is associated with KCPL’s investment in its various methods of
generating electricity.
202.
Separate class cost of service studies were
provided by KCPL, Staff, OPC, MECG/MIEC, and the U.S. Department of Energy.
203.
The Commission benefits from the presentation of
alternative class cost of service studies, but those study results should only
be used as a guide.
204.
On June 16, 2015, some of the parties filed a Non-Unanimous Stipulation and Agreement on
Certain Issues (“Rate Design Agreement”), which addressed issues relating
to class cost of service, rate design, and tariffs. That Rate Design Agreement stated, in part,
that:
Class Cost of Service, Production Plant: The
Signatories agree that the Commission should allocate any increase to revenue
requirement resulting from this case as an equal percentage increase to all the
classes. Given that an equal percent revenue allocation is consistent with some
party recommendations contained on the record, the Signatories do not believe
that the Commission needs to make specific findings as to the appropriate
methodology for allocating production plant costs among the customer classes.
Rate Design: The
Signatories agree that the appropriate methodology, in this case, for most
reasonably allocating net cost of service among the customer classes, for
allocating revenue increase among rate schedules, and for interclass shifts in
revenue responsibilities, should be an equal percentage increase to all
customer classes.
The Rate Design Agreement is attached hereto as
Attachment A and incorporated herein. KCPL objected to the Rate Design
Agreement.
Conclusions of Law and
Decision
Based on the evidence in this case, the Commission finds that
acceptance of the provisions of the Rate Design Agreement on these issues is a
fair and reasonable resolution of these issues, since an equal percent revenue
allocation is consistent with some party recommendations. The Commission adopts
the provisions of the Rate Design Agreement stated above.
3. Residential customer charge- At what level
should the Commission set KCPL’s residential customer charge?
Findings of Fact
205.
The residential customer charge is designed to include
those costs necessary to make electric service available to the customer,
regardless of the level of electric service utilized. Examples of such costs
include monthly meter reading, billing, postage, customer accounting service
expenses, a portion of costs associated with meter investment, and the service
line.
206.
KCPL proposes to increase the customer charge
for the residential class from $9.00 to $25.00, an increase of approximately
178 percent for those customers.
207.
KCPL’s residential customer-related costs are
$11.88 per month, which is based on the results of Staff’s class cost of
service study.
208.
KCPL requests that the Commission include as part
of the customer charge additional costs for local facility equipment, which are
costs for the secondary distribution system and line transformers.
209.
KCPL’s proposal to include local facility
equipment costs in the residential customer charge is inconsistent with its own
class cost of service study. That study defines local facility equipment as
demand-related, and those types of costs are typically recovered through a
demand charge for those customers that are demand-metered. However, residential
customers are not demand-metered, so their demand-related costs are usually
recovered through energy charges, not monthly customer charges.
210.
The signatory parties to the Rate Design
Agreement recommended that the Commission decline to increase the current customer
charge of $9.00 per month.
Conclusions of Law and
Decision
Customer-related costs are generally recovered through the
customer charge, which serves to prevent higher usage customers from
subsidizing lower usage customers, sends all customers more accurate energy
pricing signals, and provides more stable and predictable funding for
utilities’ fixed costs. Other costs are
recovered through volumetric rates that vary with the amount of electricity
used. Staff’s class cost of service study determined that the costs related to
residential customers are $11.88 per month. While KCPL requests that additional
costs related to local facility equipment be included in the customer charge,
the Commission finds that inclusion of those additional costs would be inappropriate
because that request is inconsistent with KCPL’s own class cost of service
study.
Determining an appropriate customer charge is a question of rate
design, not a question of the company’s revenue requirement. Any increase in
the company’s customer charge should be accompanied by a decrease in volumetric
rates so that, in theory, the company recovers the same amount of revenue. The
Commission considers that an important goal of rate design is to recover costs
from those who cause the costs to be incurred. Therefore, the Commission
concludes that the appropriate residential customer charge is $11.88 per month,
based on Staff’s cost of service study.
4. Residential energy charge- At what level
should the Commission set KCPL’s residential energy charges?
Findings of Fact
211.
In KCPL’s rate design proposal for the
residential class, the company has made a number of adjustments, particularly
to the winter rate block structures. In KCPL’s last rate case, off-peak winter
rate schedules were providing less than their cost of service. The Commission
ordered that certain rates blocks within the class should be increased by an
additional five percent.
212.
In this case, KCPL is proposing to decrease some
of the very rates that the Commission previously ordered to increase. Because a
class cost of service study shows that the off-peak winter rate schedules are
providing a higher return than the on-peak summer rate schedules, decreasing
the rates at this time may have unintended results.
213.
In the Rate Design Agreement, the signatory
parties agreed that, “[w]ith regard to the residential energy charge, the
Signatories agree that after accounting for the continuation of the existing
customer charges, the residential energy charges will be increased by the same
percentages to achieve required revenues.”
Conclusions of Law and
Decision
The Commission finds that KCPL’s proposed adjustments regarding
the residential energy charges are inappropriate due to possible unintended results.
The Commission finds that acceptance of the provisions of the Rate Design
Agreement on this issue is a fair and reasonable resolution of the issue. Since
the Commission has decided to increase the residential customer charge, that
provision will need to be modified slightly. The Commission concludes that after
accounting for the increase in the existing customer charges, the residential
energy charges will be increased by the same percentages to achieve required
revenues.
5. Time of day – should the time of day rate
be frozen from the addition of future customers (KCPL proposal) or should KCPL
be required to file modified time of day tariff provisions in its next rate
case?
6. Special rates-two-part time-of-use- Should
the two-part time of use rate be eliminated from the addition of future
customers (KCPL proposal) or should KCPL file a modified two-part time of use
tariff provisions in its next rate case?
7. Real time pricing tariffs – should the real
time pricing rate be frozen from the addition of future customers or should
KCPL file modified real time pricing tariff provisions in its next rate case?
Findings of Fact
214.
KCPL proposes to freeze availability of the
residential time-of-use rate because it only has 38 customers and does not
perform as it should.
KCPL also proposes to freeze two special rates, the two-part time-of-use and
real time pricing tariffs, because they are not used or no longer functional.
215.
KCPL opposes imposing a new time-of-use rate
because it is beginning two projects that will fundamentally impact a
time-of-use design, the AMI metering roll-out and the implementation of a new
billing system. KCPL cannot commit to a schedule for a new time-of-use tariff
because it needs more information about these new system projects and possible
impacts to integrated resource planning and MEEIA programs.
216.
The Division of Energy proposes that two-part
time-of-use and real time pricing tariffs remain available and that KCPL be
required to submit revised tariffs and supporting documentation in its next
rate case.
217. In
the Rate Design Agreement, the signatory parties agreed that:
Regarding time of day rates, the Signatories agree
that current residential and other special two-part time-of-day or real time
pricing tariffs remain available, and the Signatories would request that the
Commission order Kansas City Power & Light Company to complete a study
regarding these issues within 2 years in which no party is obligated to support
the findings of that study or any proposed tariff design as a result of that
study.
Conclusions of Law and
Decision
KCPL has requested that the Commission freeze the residential
time-of-use rates, two-part time-of-use, and real time pricing tariffs in this
proceeding and not require KCPL to file new tariffs in its next rate case. The
Commission agrees that these rates should be frozen from the addition of future
customers for the present time. However, it is clear that all of these rates
need to be redesigned, and at least the time-of-use tariff is far too important
in meeting the goals of MEEIA and providing customer choices for energy efficiency
and bill savings to redesign at an unknown time in the future. The Commission
concludes that KCPL should complete a study regarding all of these issues
within two years of the effective date of this order.
8.
Should
the ResB rate structure be changed to make it consistent with ResA and ResC
rate structures?
Findings
of Fact
218.
The residential class has three main sub-class
rate classifications – general use (ResA), one meter general use and space heat
(ResB), and two meter rate with general use on one meter and a separate meter
for space heating (ResC).
219.
Staff has recommended a rate structure change to
ResB to make it consistent with ResA and ResC rate structures, to which KCPL
agrees.
220.
In the Rate Design Agreement, the signatory
parties stated that “[t]he Signatories agree to allow modification to the
structure of the ResB rate to add an intermediate block rate which will be set
equal to the first block rate to make it consistent with the ResA and ResC rate
structures.”
Conclusions of Law and
Decision
Based on the evidence in this case, the Commission finds that
acceptance of the provisions of the Rate Design Agreement on this issue is a
fair and reasonable resolution of the issue. The Commission adopts the
provisions of the Rate Design Agreement stated above.
9.
Commercial
and industrial –
a.
SG, MG,
LP and LGS energy charges – at what level should the Commission set KCPL’s SG,
MG, LP and LGS energy charges?
b.
SG, MG,
LP and LGS separate meter space heating energy charges and the first energy
block rate for the winter rates – at what level should these energy charges be
set?
c. Should the Commission adopt
MIEC/MECG’s rate design proposal for the LGS and LP rate classes, or some a
variant of it?
Findings of Fact
221.
KCPL’s Large General Service (“LGS”) and Large
Power Service (“LP”) tariffs consist of a series of charges differentiated by
voltage level. There are separate charges for service at secondary voltage,
service at primary voltage, service at substation voltage, and service at
transmission voltage. The rates charged at the higher voltage levels are lower
than the rates charged at the lower voltage levels in order to recognize
differences in cost of service.
222.
In KCPL’s
LGS and LP rate schedules, the specific energy charges to be applied to a
particular customer’s usage decrease as the customer’s load factor increases.
Energy usage is charged in a sequential manner, so that energy is first billed
at the initial 180 hour energy block; any usage in excess of this is billed at
the second 180 hour energy block; and any remaining usage is billed at the tail
block rate. In order to receive the benefit of the lower energy charges in the
second energy block and the tail block, customers must first fill the preceding
blocks and pay for energy at the associated higher energy rate.
223.
These tariffs collect revenue through, among
others, a demand and energy charge, but KCPL is currently collecting a large
portion of its fixed costs through LGS and LP energy charges, rather than just
collecting its variable costs.
224.
In the Rate Design Agreement, the signatory
parties agreed as follows:
Except
as provided in the following paragraph, as rate design relates to Commercial
and Industrial classes the Signatories agree with the following as it relates
to section B(e)(1)-(3) and section (B)(f)(1) and (3) in the Issues List:
the following rate components of each class be increased across-the-board for
each class on an equal percentage basis after:
• Increasing the first winter energy block rate of the
frozen All-Electric Service rate schedules for the SGS, MGS, and LGS rate
classes increasing by an additional 5%;
• Changing the winter second and third SGS all
electric block rates to match the winter second and third general service SGS
block rates.
As explained in the pre-filed Direct Cost of Service
and Rate Design testimony of Maurice Brubaker, at pages 32-33, the general
service LGS and LP second block energy rates shall receive 75% of the
applicable class percentage increases and there shall be no increase to the
tail blocks of the general service LGS and LP energy rates. Any remaining
increase in revenue requirement for these classes shall be collected through an
equal percentage increase in the customer, demand and first energy blocks.
Conclusions of Law and
Decision
Based on the evidence in this case, the Commission finds that
acceptance of the provisions of the Rate Design Agreement on these issues is a
fair and reasonable resolution of the issues. The Commission adopts the
provisions of the Rate Design Agreement stated in paragraph 225 above.
10.
Special
interruptible – should the special interruptible rate be frozen from the
addition of future customers?
Findings
of Fact
225.
KCPL has proposed to freeze or eliminate the
special interruptible rate.
226.
In the Rate Design Agreement, the signatory parties
state that “[t]he Signatories do not oppose Kansas City Power & Light
Company’s request to eliminate the special interruptible rate.”
Conclusions of Law and
Decision
Based on the evidence in this case, the Commission finds that
acceptance of the provisions of the Rate Design Agreement on this issue is a
fair and reasonable resolution of the issue. The Commission adopts the
provisions of the Rate Design Agreement stated above, and the special
interruptible rate is eliminated.
11. Tariff rules and regulations- Should the
return check charge be applied to payment forms beyond checks (electronic
payments)?
Findings
of Fact
227.
KCPL has a large number of customers who no
longer use paper checks for payment, but instead use electronic payment
methods.
228.
KCPL has proposed to revise its tariff to extend
the return payment charge to all forms of payment received by the company in
the event of insufficient funds.
229.
Staff supports KCPL’s proposal,
and no other party has provided testimony or evidence on this issue.
Conclusions of Law and
Decision
KCPL’s request to extend the return payment charge to all forms
of payment received by the company in the event of insufficient funds is
reasonable. The Commission concludes that KCPL’s tariff should be revised such
that the return check charge shall be applied to payment forms beyond checks.
12. Tariff rules and regulations- Should the
collection charge be increased to reflect the cost of this service?
Findings of Fact
230.
KCPL has proposed to revise its tariff to
increase the collection charge from $25 to $30 for in-field payments to reflect
the cost of the service and to make the charge consistent with the current GMO
collection charge.
231.
Staff supports KCPL’s proposal,
and no other party has provided testimony or evidence on this issue.
Conclusions
of Law and Decision
KCPL requests to increase the collection charge for in-field
payments. KCPL argues that this increase is to reflect the cost of the service
and to make the charge consistent with the current GMO collection charge. The Commission
concludes that KCPL has not adequately explained the need for this increased
charge, and so has failed to meet its burden of proof to demonstrate that the
increase is necessary. The Commission denies the request to increase the
collection charge, and it will remain at $25.00.
13. Economic development rider/urban core
development rider – Should the Commission approve the Division of Energy’s
proposal to link MEEIA participation to receipt of EDR and UCD incentives?
Findings of Fact
232.
KCPL’s economic development rider (“EDR”) is
designed to encourage industrial and commercial business development in
Missouri and retain existing load where possible. The urban core development
rider (“UCD”) has the purpose of encouraging industrial and commercial business
development within a specific section of KCPL’s service territory.
Only four KCPL customers participate in the EDR rider.
233.
Division of Energy proposes that KCPL’s EDR and
UCD riders be changed to require that customers participate in applicable MEEIA
programs to be eligible for taking service under the special EDR and UCD rates.
The Division of Energy altered its proposal to make it easier for customers to
opt-out of MEEIA programs and still receive the special EDR and UCD rates.
234.
The EDR was re-designed in October 2013 to make
the rider more functional for customers.
235.
The Division of Energy’s proposal would be
nearly impossible to administer because the proposal requires participation in
all cost-effective energy efficiency programs.
Conclusions of Law and
Decision
The Division of Energy recommends that the Commission require
KCPL to link MEEIA participation with the receipt of EDR and UCD incentives.
The MEEIA statute, Section 393.1075.7, RSMo, allows certain large users of
electricity to opt out of participation in MEEIA programs, and the Division of
Energy has amended its proposal to make it easier for such customers to opt-out
and still receive EDR and UCD rates. However, the evidence showed that this
proposal would be difficult for KCPL to administer. The EDR and UCD programs do
not have high participation at this time, and adding further restrictions to
this recently re-designed program would be counter-productive. In a recent
Ameren Missouri rate case, File No. ER-2014-0258, this Commission rejected a
very similar proposal and instead decided to establish a collaborative to
examine this issue more closely. The Commission concludes that this proposal
should be rejected, as well.
14. Should KCPL be required to establish a
working group to review its Standby Service Tariff to ensure that rates are
cost-based and reflect best practices?
Findings of Fact
236.
Properly designed standby rates can facilitate
efficiency gains, energy independence and demand-side management opportunities
associated with combined heat and power (“CHP”) technologies. Standby rates are
a key factor in determining the cost-effectiveness of such CHP projects.
237.
KCPL has a standby rate tariff, which went into
effect in 1997 and was revised in 2013.
238.
Standby rate tariffs for The Empire District
Electric Company and Ameren Missouri are currently under review by
stakeholders.
239.
In the Rate Design Agreement, the signatory
parties agreed that “a working group should be formed to review KCP&L’s
Standby Service Tariff for the purposes of 1) ensuring that the design of
standby rates and the terms and conditions of service are consistent with best
practices and 2) to develop recommendations on cost-based rate levels.
Signatories request that the Commission order KCP&L to file a new Standby
Service Tariff in its next general rate case.”
Conclusions of Law and
Decision
While the standby rate is important for CHP projects, there has
been no adequate showing that the existing KCPL tariff is deficient. The
Commission finds it is not mandatory that KCPL to file a new standby rate
tariff in its next general rate case.
The Commission will not adopt the provision above in the Rate Design
Agreement. However, since the standby rate tariffs of other electric utilities
are currently under review, the Commission concludes that KCPL should complete
a study regarding this issue within two years of the effective date of this
order.
L.
Revenues
Findings of Fact
240.
In Section K, subsection 9 above, the Commission
adopted provisions of the Rate Design Agreement regarding rate design for the
LGS and LP classes for commercial and industrial customers. This provision
recovers the bulk of the LGS and LP class revenue increase from this case
through the second block energy rates for those classes, but has no increase
for the third block energy rates.
241.
This provision creates the potential for some
customers to benefit from switching to a different and more advantageous rate
schedule.
242.
KCPL should have the opportunity to earn its
revenue requirement when customers are switching rates schedules due to rate
design shifts.
243.
Staff estimated that an adjustment of no more
than $250,000 should be made for possible LGS customers switching rates.
244.
KCPL estimated that the company could lose
revenues of approximately $590,000 due to rate switching from the rate design
provision in the Rate Design Agreement. KCPL’s estimate is more credible than
the Staff estimate because KCPL looked at all commercial and industrial
customers who may switch rates, while Staff only looked at the Large Power
Class.
245.
On August 3, 2015, Staff and KCPL
filed a Non-Unanimous Stipulation and
Agreement Regarding Class Kilowatt-Hours, Revenues and Billing Determinants,
and Rate Switcher Revenue Adjustments (“True-Up Agreement”), which attempted
to 1) resolve all issues relating to weather normalization, rate revenues, and
the resulting class billing determinants used in developing rates for all rate
classes, and 2) assign a revenue shortfall of $500,000 for rate switchers in
the LGS and LP rate classes in order to account for any of those customers
migrating to a different rate schedule to receive more advantageous pricing as
a result of the Rate Design Agreement. Since OPC objected to the True-Up
Agreement, it is a joint position statement, but Staff and KCPL urge the
Commission to adopt its terms. OPC only objected to the provision relating to
rate switching. The True-up Agreement is attached hereto as Attachment B and
incorporated herein by reference.
Conclusions of Law and
Decision
KCPL’s estimate was that it would lose revenues of approximately
$590,000 if certain customers switched to a rate with more advantageous
pricing. The True-Up Agreement proposed an adjustment of $500,000 to account
for rate switching customers which is a more reasonable estimate, as not all
customers would be likely to switch rates at the same time. Based on the evidence in this case, the
Commission finds that acceptance of all the provisions of the True-Up Agreement
on the issues contained therein is a fair and reasonable resolution of those
issues. The Commission adopts the provisions of the True-Up Agreement in their
entirety as stated in Attachment A to this Report and Order.
M.
Low
income weatherization
Findings of Fact
246.
The Commission has authorized KCPL to
participate in a program to weatherize homes of low-income residents called the
Income Eligible Weatherization Program (“Program”). KCPL operates the Program
independently of a similar federal weatherization program and provides funding
to community action agencies that deliver such services within KCPL’s service
territory.
247.
In Missouri, only KCPL and GMO operate their
weatherization programs under the Missouri Energy Efficiency Investment Act
(“MEEIA”). Other regulated electric utilities fund their weatherization
services through customer contributions in base rates. Base rate recovery is
preferable to recovery through MEEIA because regulated electric utilities offer
MEEIA on a voluntary basis, and there is no guarantee that weatherization
programs will be offered if a utility does not participate in MEEIA.
248.
Ninety-nine percent of MEEIA weatherization
funds go to single-family homes. Funding the Program through KCPL’s base rates
would allow Program funds to be made available to multi-family homes.
249.
Before collecting Program funds through MEEIA,
KCPL collected Program funds through base rates. KCPL presently has a surplus
of Program funds previously collected through base rates.
Conclusions of Law and
Decision
Since the Program is an important service that benefits
low-income residents, the Commission considers continuity of the Program to be
a valuable goal. To avoid any continuity problems in the future, the Commission
finds that collecting Program funds through base rates to be preferable. This
will also provide for consistency across the state, as most other regulated
electric utilities collect weatherization funds through base rates. The
Commission concludes that KCPL should resume recovery of low-income
weatherization program costs in base rates following the conclusion of KCPL’s
MEEIA Cycle 1 and cease recovery of these costs in future MEEIA applications.
With regard to any surplus Program funds recovered previously through base
rates, the unexpended low‑income weatherization program funds collected
through KCPL’s base rates should be used to offset any expenditures relating to
the Program.
N.
Economic
Relief Pilot Program
Findings of Fact
250.
KCPL originally established the Economic Relief
Pilot Program (“ERPP”) to deliver energy affordability benefits to KCPL’s
qualifying low-income customers. The ERPP currently provides up to $50 in bill
credit for up to 1,000 participants. One half of the funding for the ERPP comes
from shareholders and the other half from ratepayers. Between January 2013 and
September 2014, the average number of monthly participants was approximately
949, and 20,355 customer bills received an ERPP credit.
251.
In this case, KCPL proposes to double the amount
of ERPP funding to $630,000 for shareholders and $630,000 for ratepayers. KCPL
is also proposing to raise the current limit of participants to 1,500 and
increase the available monthly bill credit to $65.
252.
Currently any unused ERPP funds are to be used
to offset demand-side management programs. KCPL recently received approval to
offer its demand-side management programs under MEEIA, so KCPL proposes to
direct any future unused ERPP funds to its Dollar-Aide program, which helps
families pay heating, cooling and water bills during difficult financial times.
Staff recommends that any unspent funds be made available for future ERPP
expenditures.
253.
The current ERPP tariff makes the program
available to customers with an annual household income no greater than 185
percent of the Federal Poverty Level. Due to the Federal Poverty Level
increasing in 2009, Staff recommends that KCPL change the eligibility
requirement to 200 percent of the Federal Poverty Level.
254.
KCPL does not oppose Staff’s recommendations to
expand the eligibility requirements and make unspent ERPP funds available for
future ERPP expenditures.
Conclusions of Law and
Decision
The ERPP is an important and valuable program to assist
low-income customers with bill affordability. KCPL should be commended for
establishing this program and recommending that it be expanded. The Commission
concludes that the ERPP should be expanded as proposed by KCPL by doubling the
funding, increasing the number of participants, and increasing the available
bill credit. The eligibility requirements should be changed to 200 percent of
the Federal Poverty Level, and any unspent ERPP funds should be made available
for future ERPP expenditures to ensure these funds are used as they were
intended and not for some other purpose.
O.
True-up
issues
Findings of Fact
255.
KCPL has proposed two adjustments to its revenue
requirement for events that occur outside of the true-up period in this case:
1) KCPL has proposed to remove two capacity agreements that expire on September
30, 2015; and 2) KCPL has included the potential cost increases for
transmission expenses from Independence Power & Light’s membership in SPP.
256.
In this case, the true-up period ended on May
31, 2015. A true-up is used to include the impacts of known and measurable
material events that occur after the update period and that are much closer to
when rates are going to be in effect to be reflected in the determination of
rates.
The term “known and measurable” relates to items or events affecting a
utility’s cost of service that must have been realized (known) and must be
calculable with a high degree of accuracy (measurable).
257.
On April 13, 2015, SPP filed with the FERC, on
behalf of the City of Independence, Missouri, revisions to its Open Access
Transmission Tariff to implement the annual transmission revenue requirement
for Independence Power & Light (“IPL”) to be included in KCPL’s
transmission pricing zone. On June 12, 2015, FERC approved those tariff
revisions, subject to refund, with an effective date of June 1, 2015.
258.
FERC has not yet determined if SPP’s tariff will
result in just and reasonable rates, which further decision is subject to
additional hearing and settlement procedures.
259.
KCPL has protested the FERC decision and
continues to argue in the ongoing FERC proceeding that it should not be
required to pay any increased net transmission expenses resulting from IPL’s
membership in SPP. KCPL intends to
challenge the assignment of IPL’s costs to KCPL up to and including a final
non-reviewable FERC order.
260.
KCPL has made estimates of the impact of this
FERC decision on its transmission revenues and expenses, but KCPL has not
received an invoice from SPP with specific costs related to the addition of IPL
in KCPL’s SPP pricing zone and does not expect to receive such an invoice until
at least September 2015.
261.
KCPL has two capacity sales agreements with the
Kansas Municipal Energy Agency (“KMEA”) that will expire on September 30, 2015.
By these agreements, KCPL agreed to provide energy service to KMEA on a firm
capacity basis.
262.
The net impact on KCPL’s cost of service from
these two contracts is $1.453 million (total company basis).
Conclusions of Law and Decision
KCPL has proposed that the Commission should include in its
revenue requirement costs incurred from IPL’s membership in SPP and exclude
revenues from KCPL’s agreements with the KMEA. For such true-up adjustments,
those costs and revenues must be known and measurable. The IPL costs imposed on
KCPL are not yet known and measurable because KCPL is continuing to fight those
costs in FERC’s ongoing proceedings, and FERC has not yet provided KCPL with an
invoice that specifies any cost increases. The revenues that KCPL will lose at
the expiration of the KMEA contracts on September 30, 2015, are known and
measurable because as of May 31, 2015 it was known that the contracts will
expire on September 30, and the amount of revenues lost is measurable with accuracy.
The Commission concludes that any increased costs KCPL may incur related to
IPL’s membership in SPP should be excluded from the revenue requirement and
that the revenues from the expiration of the KMEA contracts should also be
excluded.
Decision Summary
In making this decision as described above, the Commission has
considered the positions and arguments of all of the parties. Failure to specifically address a piece of
evidence, position or argument of any party does not indicate that the
Commission has failed to consider relevant evidence, but indicates rather that
the material was not dispositive of this decision.
Additionally, KCPL provides safe and adequate service, and the
Commission concludes, based upon its independent review of the whole record,
that the rates approved as a result of this order support the provision of safe
and adequate service. The revenue increase
approved by the Commission is no more than what is sufficient to keep KCPL’s
utility plants in proper repair for effective public service and provide to KCPL’s
investors an opportunity to earn a reasonable return upon funds invested.
By statute, orders of the Commission become effective in thirty
days, unless the Commission establishes a different effective date. In order that this case can proceed
expeditiously, the Commission will make this order effective on September 15,
2015.
THE COMMISSION ORDERS THAT:
1.
The Motion to Strike Pleadings, Reject Tariff
Sheets, and Strike Testimony filed by Missouri Industrial Energy Consumers and
the Office of the Public Counsel on June 10, 2015, is denied.
2.
The tariff sheets submitted on October 30, 2014,
by Kansas City Power
& Company, assigned Tariff Nos. YE-2015-0194 and YE-2015-0195, are rejected.
3.
Kansas City Power & Light Company is authorized to
file tariff sheets sufficient to recover revenues approved in compliance with
this order. Kansas City Power & Light Company shall
file its compliance tariff sheets no later than September 8, 2015.
4.
Kansas City Power & Light Company shall file the information
required by Section 393.275.1, RSMo 2000, and Commission Rule 4 CSR 240-10.060
no later than September 8, 2015.
5.
The Staff of the Missouri Public Service
Commission shall file its recommendation concerning approval of Kansas City Power & Light
Company’s compliance tariff sheets no later than September 14, 2015.
6.
Any other party wishing to respond or comment regarding Kansas
City Power & Light Company’s compliance tariff sheets shall file the
response or comment no later than September 14, 2015.
7.
The Non-Unanimous
Stipulation and Agreement on Certain Issues filed by some of the parties on
June 16, 2015, is attached hereto as Attachment A and incorporated herein by
reference.
8.
Staff and Kansas City Power &
Light Company’s Non-Unanimous Stipulation
and Agreement Regarding Class Kilowatt-Hours, Revenues and Billing
Determinants, and Rate Switcher Revenue Adjustments filed on August 3,
2015, is attached hereto as Attachment B and incorporated herein by reference.
9.
This Report and Order shall become effective on September
15, 2015, except that Ordered Paragraphs 3, 4, 5 and 6 shall become effective
upon issuance.
BY THE COMMISSION
Morris L.
Woodruff
Secretary
Hall,
Chm., Stoll, Kenney, and
Rupp,
CC., concur and certify
compliance
with the provisions of
Section
536.080, RSMo.
Coleman,
C., abstains.
Dated
at Jefferson City, Missouri,
on
this 2nd day of September, 2015
