EXHIBIT 99.5
BEFORE THE ARIZONA CORPORATION COMMISSION
COMMISSIONERS Arizona Corporation Commission
DOCKETED
JEFF HATCH-MILLER Chairman
WILLIAM A. MUNDELL APR - 7 2005
MARC SPITZER DOCKETED BY NR
MIKE GLEASON
KRISTIN K. MAYES
IN THE MATTER OF THE APPLICATION OF ARIZONA DOCKET NO. E-01345A-03-0437
PUBLIC SERVICE COMPANY FOR A HEARING TO DETERMINE
THE FAIR VALUE OF THE UTILITY PROPERTY OF THE
COMPANY FOR RATEMAKING PURPOSES, TO FIX A JUST AND DECISION NO. 67744
REASONABLE RATE OF RETURN THEREON, TO APPROVE RATE
SCHEDULES DESIGNED TO DEVELOP SUCH RETURN, AND FOR
APPROVAL OF PURCHASED POWER CONTRACT.
OPINION AND ORDER
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DATES OF PROCEDURAL August 13, 2003, January 6, February 18,
CONFERENCES: April 7, 15, 28 May 26, June 14, August 18,
and October 27, 2004
DATES OF HEARING: November 8, 9, 10, 29, 30, December 1, 2,
and 3, 2004
PLACE OF HEARING: Phoenix, Arizona
ADMINISTRATIVE LAW JUDGE: Lyn Farmer
IN ATTENDANCE: Marc Spitzer, Chairman
William A. Mundell, Commissioner
Jeff Hatch-Miller, Commissioner
Mike Gleason, Commissioner
Kristin K. Mayes, Commissioner
APPEARANCES: Mr. Thomas L. Mumaw and Ms. Karilee S.
Ramaley, PINNACLE WEST CAPITAL CORPORATION;
Mr. Jeffrey B. Guldner and Ms. Kimberly
Grouse, SNELL & WILMER, L.L.P., on behalf of
Arizona Public Service Company;
Mr. C. Webb Crockett, FENNEMORE CRAIG, P.C.,
on behalf of AECC and Phelps Dodge;
Mr. Patrick J. Black, FENNEMORE CRAIG, P.C.,
on behalf of Panda Gila River;
Mr. S. David Childers, LOW & CHILDERS, P.C.,
Mr. James M. Van Nostrand, and Ms. Katherine
McDowell STOEL RIVES, L.L.P., on behalf of
Arizona Competitive Power Alliance;
Mr. Lawrence V. Robertson, Jr., MUNGER
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DOCKET NO. E-01345A-03-0437
CHADWICK, on behalf of Southwestern Power
Group II, Mesquite Power, and Bowie Power
Station, LLC, and Mr. Theodore Roberts,
SEMPRA ENERGY RESOURCES, on behalf of
Mesquite Power;
Mr. Scott S. Wakefield, Chief Counsel, and
Mr. Daniel Pozefsky, on behalf of the
Residential Utility Consumer Office;
Mr. Walter W. Meek, President, on behalf of
the Arizona Utility Investors Association;
Mr. Raymond S. Heyman, Ms. Laura E.
Schoeler, and Ms. Laura Sixkiller, ROSHKA,
HEYMAN & DeWULF, on behalf of UniSource
Energy Services;
Major Allen G. Erickson on behalf of the
Federal Executive Agencies;
Mr. Jay I. Moyes, MOYES STOREY, on behalf of
PPL Sundance and PPL Southwest Generation
Holdings;
Mr. Nicolas J. Enoch, LUBIN & ENOCH, on
behalf of the International Brotherhood of
Electrical Workers;
Mr. William P. Sullivan and Mr. Michael A.
Curtis, MARTINEZ & CURTIS, P.C., on behalf
of the Town of Wickenburg, Arizona;
Mr. Bill Murphy, MURPHY CONSULTING and Mr.
Douglas V. Fant, LAW OFFICES OF DOUGLAS V.
FANT, on behalf of the Arizona Cogeneration
Association;
Mr. Marvin S. Cohen, SACKS TIERNEY, P.A., on
behalf of Constellation NewEnergy and
Strategic Energy;
Mr. Andrew W. Bettwy and Ms. Karen S.
Haller, on behalf of Southwest Gas
Corporation;
Mr. Timothy M. Hogan, ARIZONA CENTER FOR LAW
IN THE PUBLIC INTEREST, and Ms. Anne C.
Ronan, on behalf of Western Resources
Advocates and Southwest Energy Efficiency
Project;
Mr. Jesse A. Dillon, on behalf of PPL
Services Corporation;
Mr. Brian Babiars and Ms. Cynthia Zwick,
WESTERN ARIZONA COUNCIL OF GOVERNMENTS, on
behalf of Arizona Community Action
Association;
Mr. Paul R. Michaud, MICHAUD LAW FIRM, on
behalf of Dome Valley Energy Partners, LLC;
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
Mr. Michael L. Kurtz, BOEHM, KURTZ & LOWRY,
on behalf of Kroger Company;
Mr. Christopher Kempley, Chief Counsel, Mr.
Jason D. Gellman and Ms. Janet F. Wagner,
Attorneys, Legal Division, on behalf of the
Utilities Division of the Arizona
Corporation Commission.
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
INDEX
I. DISCUSSION.................................................... 5
II. PRE-SETTLEMENT POSITIONS OF PARTIES........................... 6
III. SETTLEMENT AGREEMENT.......................................... 6
a. INTRODUCTION......................................... 6
b. REVENUE REQUIREMENTS................................. 8
c. PWEC ASSET TREATMENT................................. 8
d. COST OF CAPITAL...................................... 13
e POWER SUPPLY ADJUSTOR (PSA).......................... 13
f. DEPRECIATION......................................... 19
g. $234 MILLION WRITE-OFF............................... 19
h. DEMAND SIDE MANAGEMENT ("DSM")....................... 19
i. ENVIRONMENTAL PORTFOLIO STANDARD AND
OTHER RENEWABLE PROGRAMS............................ 23
j. COMPETITIVE PROCUREMENT OF POWER..................... 25
k. REGULATORY ISSUES.................................... 26
l. COMPETITION RULES COMPLIANCE CHARGE ("CRCC")......... 27
m. LOW INCOME PROGRAM................................... 27
n. RETURNING CUSTOMER DIRECT ACCESS CHARGE ("RCDAC").... 28
o. SERVICE SCHEDULE CHANGES............................. 28
p. NUCLEAR DECOMMISSIONING.............................. 28
q. TRANSMISSION COST ADJUSTOR ("TCA")................... 28
r. DISTRIBUTED GENERATION............................... 29
s. BARK BEETLE REMEDIATION.............................. 31
t. RATE DESIGN.......................................... 31
u. LITIGATION AND OTHER ISSUES.......................... 33
v. SUMMARY.............................................. 34
IV. FINDINGS OF FACT.............................................. 35
V. CONCLUSIONS OF LAW............................................ 40
VI. ORDER......................................................... 41
DECISION NO. 67744
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BY THE COMMISSION:
I. DISCUSSION
On June 27, 2003, Arizona Public Service Company ("APS" or "Company")
filed with the Arizona Corporation Commission ("Commission") an application for
a rate increase and for approval of a purchased power contract. The application
states that the $175.1 million rate increase is needed to maintain the Company's
credit ratings and attract new capital on reasonable terms, recover its cost of
service, and permit APS to earn a fair rate of return on the fair value of its
assets devoted to public service. The application requested that the Commission
recognize the higher fuel and purchased power expenses being incurred by the
Company; allow APS to include in rates at cost of service certain generation
assets of Pinnacle West Energy Corporation ("PWEC"); permit APS to recover the
$234 million write-off taken under the 1999 Settlement Agreement; and provide
for the recovery of all prudently incurred costs to comply with the Commission's
Retail Electric Competition Rules, A.A.C. R14-2-1601, et seq. ("Electric
Competition Rules"), including the one-third of costs associated with the
planned divestiture of generation from APS to PWEC that was not previously
deferred. APS also requested approval of depreciation and amortization rates and
a review of its long-term purchased power contract with PWEC if the assets are
not rate based.
On July 25, 2003, the Utilities Division Staff ("Staff") of the Commission
filed a letter stating that the application was found sufficient and classified
the applicant as a Class A utility.
By Procedural Order issued August 6, 2003, a Procedural Conference was
scheduled for August 13, 2003, and intervention was granted to the Arizonans for
Electric Choice and Competition ("AECC"), the Federal Executive Agencies
("FEA"), the Kroger Company ("Kroger"), the Residential Utility Consumer Office
("RUCO"), the Arizona Utility Investors Association, Inc., ("AUIA") and Phelps
Dodge Corporation and Phelps Dodge Mining Company ("Phelps Dodge").
By various Procedural Orders, intervention was granted to: the
International Brotherhood of Electrical Workers, AFL-CIO, CLC, Local Unions 387,
640 and 769 (collectively, "IBEW"), the Arizona Cogeneration
Association/Distributed Generation Association of Arizona ("ACA" or "DEAA"),
Panda Gila River, L.P. ("Panda"), Arizona Water Company ("AWC"), Southwest Gas
Corporation ("SWG"), Western Resource Advocates ("WRA"), Constellation
NewEnergy, Inc.
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("CNE"), Strategic Energy, L.L.C. ("SEL"), Dome Valley Energy Partners, LLC
("DVEP"), UniSource Energy Services ("UES"), Arizona Community Action
Association ("ACAA"), Arizona Competitive Power Alliance ("Alliance"), the Town
of Wickenburg ("Wickenburg")(1), the Arizona Solar Energy Industries Association
("AriSEIA"), the Arizona Association of Retired Persons ("AARP"), Southwest
Energy Efficiency Project ("SWEEP"), PPL Sundance, LLC ("PPL Sundance"), PPL
Southwest Generation Holdings, LLC ("PPL Southwest"), Southwestern Power Group
II, LLC ("SWPG"), Mesquite Power, LLC ("Mesquite") and Bowie Power Station, LLC
("Bowie").
On November 5, 2003, Staff filed a Motion to Consolidate ("Motion") the
preliminary inquiry created by Decision No. 65796 and by Procedural Order the
Motion was granted, authorizing Staff to include its report in this docket.
II. PRE-SETTLEMENT POSITIONS OF PARTIES
APS Staff RUCO Settlement Agreement
Revenue requirement +$175.1 M -$142.7 M -$53.6 M +$ 75.5 M
Return on Equity 11.5 % 9.0% 9.5% 10.25%
Debt cost 5.8 % 5.8% 5.8% 5.8%
Capital Structure 50/50 55/45 55/45 55/45
Cost of Capital 8.67 % 7.3% 7.43% 7.8%
PWEC assets $ 848 M - (2) $ 700 M
III. SETTLEMENT AGREEMENT
a. INTRODUCTION
On August 18, 2004, a Settlement Agreement signed by 22 parties(3) was
docketed with the Commission. AWC, SWG, and UES do not oppose the Settlement
Agreement, and the AARP made public comment supporting it. The only party
opposed to the Commission's adoption of the Settlement Agreement that presented
testimony and evidence is the Arizona Cogeneration
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(1) On August 18, 2004, Wickenburg moved to withdraw its intervention.
(2) Phase 1.
(3) APS, ACAA, Alliance, AECC, AriSEIA, AUIA, Bowie, CNE, DVEP, FEA, IBEW,
Kroger, Mesquite, Phelps Dodge, PPL Southwest, PPL Sundance, RUCO, SWEEP, SWPG,
Staff, SEL, and WRA.
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Association/Distributed Generation Association of Arizona.(4)
APS' central objectives in settling were to preserve the company's
financial integrity;(5) resolve the issue of asset "bifurcation"; and to
determine the company's future public service obligations.
Staff believes that the Settlement Agreement is in the public interest
because: it is fair to ratepayers because it precludes inappropriate utility
profits and results in just and reasonable rates; it is fair to the utility
because it provides revenues necessary to provide reliable electric service
along with an opportunity for a reasonable profit; the proposal balances many
diverse interests including those of low-income customers, the renewable energy
sector, Demand Side Management ("DSM") advocates, merchant generators, and
retail energy marketers; it allows APS to rate base the PWEC assets, which are
the generating plants originally built by APS' affiliate, PWEC, at a value that
is significantly below their book value; potentially anti-competitive effects
that may be associated with rate basing the PWEC assets are addressed through a
self-build moratorium, a competitive solicitation in 2005, through workshops to
address future resource planning and acquisition issues, and by adopting
cost-based unbundling for generation and revenue cycle services in the rate
design for general service customers, encouraging those customers to shop for
competitive services; the Settlement Agreement resolves long, complex litigation
by resolving issues associated with prior Commission decisions that are on
appeal; the Settlement Agreement facilitates the provision of electric service
at the lowest reasonable rates; it provides additional discounts to low-income
APS customers, increases funding for advertising these discounts, and increases
funding for APS' low-income weatherization program; and because it includes a
comprehensive DSM proposal intended to foster the development of new DSM
programs while ensuring that the expenditures will be reasonable and subject to
appropriate Commission oversight.(6)
RUCO noted that this rate case allowed sufficient opportunity for it to
fully audit the Company's cost-of-service study and allowed all parties to be
included in the negotiations. RUCO points to the very substantial, nearly
universal consensus reached in the Settlement Agreement as
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(4) New Harquahala Generating Company, LLC and Panda made statements objecting
to the rate basing of the PWEC assets.
(5) Defined as the ability to attract capital on reasonable terms and earn a
reasonable return. Tr. p. 420.
(6) Summary of settlement testimony of Ernest Johnson.
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indicating that the public interest has been served. According to RUCO, the
"ultimate expression of the agreement having met the Public Interest is the
degree to which rate increases have been minimized without jeopardizing the
financial integrity of the applicant."(7)
The Alliance's central objective is to continue towards a viable and
effective wholesale market into which Alliance members can sell their power.
According to the Alliance, there are several key provisions in the Settlement
Agreement that accomplish that goal: the restrictions on self-build coupled with
the high growth rate in APS' service territory; and the 1,000 megawatt Request
for Proposal ("RFP") in 2005. The Settlement Agreement also preserves the
financial stability and creditworthiness of the Alliance's target customer -
APS.(8)
b. REVENUE REQUIREMENTS
For ratemaking purposes and for purposes of the Settlement Agreement, the
parties agree that APS will receive a total increase of $75.5 million over its
adjusted 2002 test year ("TY") revenue of $1,791,584,000. This represents an
increase in base rates of $67.6 million and a Competition Rules Compliance
Charge ("CRCC") surcharge collecting $7.9 million. Pursuant to the Settlement
Agreement filed on August 18, 2004, as corrected in the hearing, the Company's
fair value rate base ("FVRB") is $5,054,426,000.(9) According to the Settlement
Agreement, this revenue increase will allow the Company the opportunity to earn
a fair value rate of return of 5.92 percent. According to the Company and Staff,
the revenue requirement contained in the Settlement Agreement provides
sufficient revenues for APS to provide adequate and reliable service.(10)
c. PWEC ASSET TREATMENT
The Settlement Agreement provides that APS will acquire and rate base
generation units owned by PWEC.(11) Those units include: West Phoenix CC-4; West
Phoenix CC-5; Saguaro CT-3; Redhawk CC-1; and Redhawk CC-2 ("PWEC assets").
Pursuant to the Settlement Agreement, the
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(7) Summary of settlement testimony of Stephen Ahearn.
(8) Tr. p. 458.
(9) Paragraph 4 to the Settlement Agreement states the FVRB is $6,281,885,000,
however, during the hearing, that amount was corrected to $5,054,426,000. Tr. p.
692.
(10) Tr. p. 810.
(11) On November 10, 2004, PWEC filed a letter with the Commission indicating
that it would abide by the provisions of the Settlement Agreement that require
PWEC to take or refrain from taking any action in order to carry out the intent
of the Settlement Agreement.
DECISION NO. 67744
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original cost rate base ("OCRB") of the PWEC assets will be $700 million which
is $148 million less than the original cost of the assets as of December 31,
2004. According to the Settlement Agreement, this represents a reasonable
estimate of the value of the remaining term of the Track B contract between APS
and PWEC.(12) APS agrees to forgo any present or future claims of stranded costs
associated with these PWEC assets. According to the Settlement Agreement, APS is
required to seek approval of certain aspects of the asset transfer from the
Federal Energy Regulatory Commission ("FERC"). APS agreed to file a request for
FERC approval within 30 days of the Commission's approval of the Settlement
Agreement, and the parties have agreed not to oppose the FERC application. The
Settlement Agreement provides for a bridge purchased power agreement ("Bridge
PPA") to be implemented once new rates are put in place, until the actual date
of the transfer of assets. APS and PWEC will execute a cost-based PPA which will
be based on the value of the PWEC assets, and fuel costs and off-system sales
revenue will flow into the power supply adjustor ("PSA"). If FERC denies the
asset transfer, then the Bridge PPA will become a 30 year PPA, with prices
reflecting cost-of-service as if the PWEC assets were rate-based at the $700
million amount in the Settlement Agreement, and with the associated fuel costs
and off-system sales revenue flowing through the PSA. The basis point credit
established in Decision No. 65796 will continue as long as the debt between APS
and PWEC associated with the PWEC assets is outstanding. Credit for amounts
deferred after December 31, 2004 will be accounted for in APS' next rate case.
The Settlement Agreement also provides that West Phoenix CC-4 and West Phoenix
CC-5 will be deemed "local generation" and during must-run conditions,
generation from the West Phoenix facilities will be available at FERC-approved
cost-of-service prices to electric service providers ("ESPs") serving direct
access loads in the Phoenix load pocket.
Treatment of the PWEC assets requires not only a regulatory ratemaking
type analysis, but also an analysis of how rate basing these assets fits with
the Commission's overall plan for wholesale and retail electric competition in
Arizona.
For the last ten years, the Commission has studied, discussed, and
deliberated about electric
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(12) Docket Nos. E-00000A-02-0051 et al.
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competition through workshops, rulemakings, hearings, and open meetings. Several
versions of electric competition rules have been adopted, and litigation
concerning Commission decisions has been conducted. Throughout this time, the
Commission has always maintained its intent to encourage competition in the
electric industry. In the wake of the California energy crisis the Commission
opened dockets to examine changing industry and market conditions and
introspectively analyzed their impact on Arizona's existing rules. The
Commission reacted in a measured manner to flawed rules in other jurisdictions
and corrected, but did not change, its course.
The Commission continues to support competition as yielding economic and
environmental benefits to Arizona consumers. The $148,000,000 discount from book
for the rate-based PWEC assets is indicative of these benefits. Recent
transactions reflected in the record, including below-cost sales, foreclosures
and bankruptcies, establish that the shareholders of the power plants' builders
absorbed the costs and bore the brunt of a declining market, rather than Arizona
ratepayers. The discounted conveyance of the PWEC assets to APS is further
support for this proposition. APS' request and the Settlement Agreement's
provision allowing APS to acquire the PWEC assets and put them in rate base
raises the issue of whether such action would undermine the Commission's stated
intent to encourage retail and wholesale competition. The terms of the
Settlement Agreement taken as a whole indicate to us that the answer to that
question is "no".
During the hearing on the Settlement Agreement, the parties presented
evidence demonstrating that the PWEC acquisition was the most beneficial option
for ratepayers. Staff testified that the responses to APS' last formal RFP did
not indicate to Staff that the market would provide a superior alternative to
the rate basing of the PWEC assets. The testimony indicates that growth in APS'
service territory is a minimum of 3 percent per year. APS argued that even with
rate basing the PWEC assets, APS' needs would not be met, and it would have to
procure additional power to meet the needs of its customers. The Settlement
Agreement provides that APS will issue an RFP for an additional 1000 megawatts,
thereby giving other market participants an opportunity to compete. The
organization created to represent the interests of the merchant community, the
Alliance, supports the transfer of assets, because it believes that resolving
the broader issues of overall market structure, the self-build guidelines and
future RFPs, together with the reduction in
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DOCKET NO. E-01345A-03-0437
litigation risk will further its overall goal of promoting a viable and
effective wholesale market. The key provision that the Alliance relies on is the
1,000 megawatt RFP in 2005 that provides a degree of certainty regarding the
timing of an initial increment of APS' future needs to be met from the wholesale
market. Also, the Alliance believes that opportunities will exist for its
members because of the self-build limitation and the high growth rate in
Arizona. The proponents of retail competition also support the asset transfer;
in large part because APS agrees to forgo any present or future claims of
stranded costs associated with the PWEC assets, because rates are unbundled, and
because of the treatment of the West Phoenix facilities.
We believe that nothing in the Settlement Agreement prevents the continued
development of electric competition. Any potential anti-competitive effects of
the asset transfer will be addressed through the competitive solicitations, the
self-build moratorium,(13) and Staff's workshops to address future resource
planning and acquisition issues. As discussed below, the evidence indicates that
the asset transfer captures the benefit of the competitive procurement that took
place as a result of the Track B proceeding.
The original cost of the PWEC assets at December 31, 2004 was $848
million. Traditionally, when a utility builds plant, unless there is a finding
of imprudency, that portion of the plant that is used and useful is put into
rate base and the utility is allowed an opportunity to earn a reasonable rate of
return on that investment. This situation is different from the traditional rate
case. APS did not build the PWEC assets; they were built by APS' affiliate
during a time when the Commission intended APS to divest itself of generation.
During the proceeding on APS' financing application, concern was raised that APS
and its affiliates took actions that gave it an unfair advantage as compared to
its potential competitors. In Decision No. 65796, which granted APS' financing
request, we directed Staff to conduct a preliminary inquiry into the issue of
APS and its affiliate's compliance with our electric competition rules, Decision
No. 61973, and applicable law. The Settlement Agreement provides that the
preliminary inquiry will be concluded with no further action by the
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(13) Neither APS nor PWEC will build the Redhawk Units 3 & 4. PWEC's February
2003 self-certification filing with the Commission stated that the two remaining
units pursuant to its Certificate of Environmental Compatibility ("CEC") would
not be built. Tr. pp. 594-5.
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Commission. Accordingly, we make no finding as to why or for whom the PWEC
assets were built, and base our resolution of the rate basing issue solely on
the merits of the terms of acquisition. We believe that if there were a serious
threat to competition, we would hear from those affected, loudly and strongly.
Therefore, we were keenly interested in the position of the members of the
Alliance, as they are one type of entity that could be harmed. The Alliance
supports the acquisition of the PWEC assets by APS. Every person or entity that
will be affected by the rate basing of the PWEC assets had the opportunity to
participate and present evidence and testimony on this issue. Although two
independent power producers made comments objecting to the acquisition without
an RFP, neither presented any evidence that demonstrated that competition would
be harmed, nor rebutted the testimony and evidence concerning APS' recent RFP.
Initially Staff recommended that the PWEC assets not be rate based, but
after analyzing the Company's rebuttal testimony and evidence, agreed that a
reduction of $148 million in original cost rate base made the acquisition
beneficial to ratepayers. The evidence in the record is substantial that APS'
analysis of other options versus rate basing PWEC assets showed that: using an
"other build" analysis, rate basing the PWEC assets would cost $300-600 million
less than cost to build other plants such as Combustion Turbines ("CT"); using a
comparable sales analysis showed that other recent sales had a per kW cost in
excess of $527 and the PWEC assets are at $417; when compared to the offers
resulting from the recent RFP conducted by APS, the PWEC assets (when valued at
the before discount $848 million level) showed benefits of $600-900 million; and
using a discounted cash flow analysis the PWEC assets had a savings of $250
million to $1 billion.
As part of the settlement, APS agreed to reflect an original cost rate
base value of $700 million, representing a $148 million disallowance. The effect
of a reduction in rate base is to immediately reduce the revenue requirement,
and to preserve that diminished revenue requirement for the life of the plant.
The analyses showing that the rate basing of the PWEC assets will result
in lower rates than other options, together with no showing that such an
acquisition would harm the development of a competitive wholesale or retail
market indicate that it is reasonable and in the public interest for APS to
acquire and rate base the PWEC assets as set forth in the Settlement Agreement.
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d. COST OF CAPITAL
The Settlement Agreement adopts a capital structure of 55 percent
long-term debt and 45 percent equity for ratemaking purposes. The parties agree
that a 10.25 percent return on common equity and a 5.8 percent embedded cost of
long-term debt is appropriate.
e. POWER SUPPLY ADJUSTOR (PSA)
The Settlement Agreement provides that a PSA be implemented and remain in
effect for a minimum of five years, with reviews available during APS' next rate
case, or upon APS' filing its report on the PSA four years after rates are
implemented in this rate case. Regardless of the review/report, the PSA cannot
be abolished until five years have expired. The Settlement Agreement provides
that APS will file a plan of administration as part of its tariff filing that
describes how the PSA will operate. According to the Settlement Agreement, the
PSA will have the following characteristics:
- Includes both fuel and purchased power;
- The adjustor rate will initially be set at zero and will thereafter
be reset on April 1 of each year, beginning with April 1, 2006. APS
will submit a publicly available report on March 1 showing the
calculation of the new rate, which will become effective unless
suspended by the Commission;
- Incentive mechanism where APS and its customers share 10 percent and
90 percent, respectively, the costs and savings;
- Bandwidth that limits annual change in adjustor of plus or minus
$0.004 per kilowatt hour, with additional recoverable or refundable
amounts recorded in balancing account;
- Surcharge possible if balancing account reaches plus or minus $50
million and Commission approves;
- Off-system sales margins credited to PSA balance;
- Recovery of prudent, direct costs of contracts for hedging fuel and
purchased power costs;
- Interest on balancing account will accrue based on the one-year
nominal Treasury constant maturities rate;
- The Commission or its Staff may review the prudence of fuel and
power purchases at any
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time;
- The Commission or its Staff may review any calculations associated
with the PSA at any time; and
- Any costs flowed through the adjustor are subject to refund if the
Commission later determines that the costs were not prudently
incurred.
The Settlement Agreement provides that APS shall provide monthly reports
to Staff's Compliance Section and to RUCO detailing all calculations related to
the PSA, and shall also provide monthly reports to Staff about APS' generating
units, power purchases, and fuel purchases. An APS officer must certify under
oath that all the information provided in the reports is true and accurate to
the best of his or her information and belief. The Settlement Agreement also
provides that direct access customers and customers served under rates E-36,
SP-1, Solar-1, and Solar-2 are excluded from paying PSA charges. Under the
Settlement Agreement, the PSA remains in effect for 5 years, and if after that,
the Commission abolishes the PSA, it must provide for any under- or
over-recovery and can adjust base rates to reflect costs for fuel and purchased
power. The parties agree that a base cost of fuel and purchased power of
$.020743 per kWh should be reflected in APS' base rates.
Decision No. 61973 (October 6, 1999) adopting the previous APS settlement,
required APS to request, and the Commission to approve, a "power supply
adjuster" mechanism to recover the cost of providing power for standard offer
and/or provider of last resort customers.
In Decision No. 66567 (November 18, 2003), the Commission approved the
concept of a Purchased Power Adjustor ("PPA") which included purchased power
costs and did not include the cost of fuel. The Decision noted that the adjustor
mechanism approved therein may be modified or eliminated in this rate case. As
noted in that Decision, there are advantages and disadvantages to adjustor
mechanisms:
Advantages: 1) the reporting requirements and forecasts facilitate utility
planning and Staff overview of costs; 2) an adjustor that works correctly, over
time, reduces the volatility of a utility's earnings and the risk reduction can
be reflected in the cost of equity capital in a rate case and result in lower
rates; 3) adjustors can create price signals to consumers, but the effectiveness
is reduced considerably when a band is included; 4) adjustors can help reduce
the frequency of rate cases; 5)
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regulatory lag between the incurrence of an expense and its recovery is reduced
and generational inequities are also reduced.
Disadvantages: 1) adjustors can reduce incentives to minimize costs; 2) an
adjustor that includes fuel or purchased power costs potentially biases capital
investment decisions towards those with lower capital costs and higher fuel
costs; 3) adjustors create another layer of regulation to rate cases, increasing
the cost of regulation to the utility, its customers, and to the Commission; 4)
an adjustor can shift a disproportionate proportion of the risk of forced
outages and systems operations from shareholders to ratepayers; 5) adjustors
result in piecemeal regulation - an adjustor reflects an increase in one expense
but ignores offsetting savings in other costs; 6) adjustors are complex and
often difficult for analysts to read and interpret, and are difficult to explain
to customers; 7) proper monitoring of adjustor filings and audits require the
devotion of significant Staff resources; and 8) rates are less stable, resulting
in rates changing frequently, making it difficult for customers to plan energy
consumption and the purchase of energy consuming appliances.
Although we recently approved the concept of a PSA, we are concerned about
the PSA as proposed in the Settlement Agreement. The benefits of this PSA are
that over time, the utility's earnings will be stabilized, thereby preserving
its financial integrity and in the longer term, improve the likelihood that the
company will attract capital on reasonable terms, to the benefit of ratepayers.
Further, as part of the negotiations, the parties were able to agree on a lower
overall revenue increase because a PSA was to be implemented. AECC pointed out
that if an adjustor remains in effect for long enough, it becomes a credit, and
therefore, the PSA should remain in effect for five years.(14)
The disadvantages are real and significant - from a customer standpoint,
adjustors are difficult to understand and they can cause annual price increases.
From a regulatory standpoint, they require significant Commission staff
resources to properly monitor filings, costs, and compliance and to respond to
consumer inquiries and complaints. The most significant change that will occur
with a PSA is the shifting of the risk that fuel costs will increase above the
base rates established in the Settlement Agreement. Currently, if fuel costs or
any other costs rise above the level embedded in
- ------------------------
(14) Tr. p. 1249.
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
the existing rate structure, the company's shareholders feel the impact.
Likewise, if the costs decrease, the shareholders benefit. Under a PSA, the
shareholders are insulated from the change in costs, because now the ratepayers
are obligated to pay the additional costs. Further, the testimony was clear that
costs are going to be increasing, not only because natural gas prices will
increase, but also because APS' "mix" of fuel will change as growth occurs.(15)
That mix will include an increasing amount of natural gas to supply the new
generation. When compared to APS' other fuel sources such as nuclear or coal,
natural gas is a substantially higher cost fuel. So here, the PSA will not only
be collecting additional revenues due to fuel price increases, but also
increases due to growth that is met with generation from a high cost fuel.(16)
Although the Settlement Agreement provides that APS will increase its
demand side management and renewables, and we agree that those resources are
increasingly important, they will not likely have a significant ameliorating
cost impact in the near future. We disagree with the parties that a 90/10
sharing is sufficient incentive for APS to continue to effectively hedge its
natural gas costs. Going from a 100 percent at-risk position to 10 percent
at-risk almost seems like a "free pass," especially when a revenue increase is
added. Although the Settlement Agreement provides that all costs will be subject
to review for prudency before they can be recovered, prudency reviews,
especially transactions in the wholesale market, can be difficult to conduct
after the fact. Although we have confidence in our Staff's ability to conduct
prudency reviews, we do not believe they provide as much incentive to APS on the
front end to hedge costs as exists today without a PSA. The band-width limit
will help limit drastic increases, but ultimately, APS will be able to recover
all the costs from ratepayers.(17)
Accordingly, for these reasons, we believe that provisions of the PSA need
to be modified to protect the ratepayers. We agree that the use of an adjustor
when fuel costs are volatile prevents a
- ------------------------------
(15) As growth occurs, the per unit cost of fuel will increase. Tr. p. 1238.
Currently, nuclear is 32 percent of sales and represents 7.4 percent of the
costs of generation; coal is 45 percent of sales and 29.7 percent of generation
costs; natural gas is 18 percent of sales and 47.4 percent of generation costs;
and purchased power is 5 percent of sales and 15.5 percent of generation costs.
Tr. p. 1257. In five years, natural gas is expected to be 29-30 percent of
sales. TR. p. 1258.
(16) See discussion Tr. p. 1259, PSA will always be increasing.
(17) Staff's late-filed exhibit S-35 filed December 14, 2004 in response to a
request from Commissioner Mundell to extrapolate the effects of the PSA over
several years, contained an error and on March 9, 2005, Staff filed a corrected
exhibit.
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
utility's financial condition from deteriorating. We are less inclined, however,
to adopt an adjustor as a way to keep pace with load growth. Although APS'
rebuttal testimony indicated that its fixed costs would increase in relation to
its load growth, we are concerned about the potential for single-issue
ratemaking and whether APS' fixed costs will increase in the same proportion as
its fuel costs. According to the late-filed exhibits, the majority of the
increased fuel costs are caused by increased load growth, rather than price
volatility in fuel. In effect, the adjustor as designed provides annual step
increases in rates. We believe APS must have an incentive to file a rate case so
that we can determine the accuracy of its assertion about expenses. Therefore,
we will adopt an adjustor that collects or refunds the annual fuel costs that
differ from the base year level. However, we will limit the adjustor to 4 mil
from the base level over the entire term of the PSA and will cap the balancing
account to an aggregate amount of $100 million. Should the Company seek to
recover or refund a bank balance pursuant to Paragraph 19E of the Settlement
Agreement, the timing and manner of recovery or refund of that existing bank
balance will be addressed at such time. In no event shall the Company allow the
bank balance to reach $100 million prior to seeking recovery or refund.
Following a proceeding to recover or refund a bank balance between $50 million
and $100 million, the bank balance shall be reset to zero unless otherwise
ordered by the Commission.
Further, we will limit the amount of "annual net fuel and purchased power
costs" (as shown in Staff Exhibit 23)(18) that can be used to calculate the
annual PSA to no more than $776,200,000. Any fuel or purchased power costs above
that level will not be recovered from ratepayers. We believe that this "cap" on
fuel and purchased power costs will further encourage APS to manage its costs,
and will help to prevent large account balances from occurring in one year.
Because the PSA actually adjusts for growth, putting a "cap" on recovery of
these costs will help insure that APS will file a rate application when
necessary.(19) Since there is no moratorium on filing a rate case, APS can file
a rate case to reset base rates if it deems it necessary because that cap is
reached. Further, although the Settlement Agreement provides that the PSA will
be in effect for 5 years, if APS files a rate case
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(18) For example, under "Average Usage Scenario One", the line reads "Annual Net
Fuel and Purchased Power Costs: $524,600,000."
(19) See S-35 filed March 9, 2005, Scenario 11A - even when the price of gas
remains constant, the PSA adjustor increases, because the adjustor uses total
costs (not price) which reflects the growth which is being met by the higher
priced fuel, natural gas.
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
prior to the expiration of that 5 year term or if we find that APS has not
complied with the terms of the PSA, we believe that the Commission should be
able to eliminate the PSA if appropriate. Finally, we will not allow any fuel
costs from 2005 that were incurred prior to the effective date of this Decision
to be included in the calculation of the PSA implemented in 2006. We believe
that these additional provisions to the PSA will help to lessen the detrimental
impact to ratepayers of this change to an adjustor mechanism.
Implementing an adjustor mechanism will have a significant impact upon
both APS and its customers. For many years now, in their monthly bills, APS
customers have paid rates that reflect the costs that APS is allowed to recover
for providing that service. With the implementation of an adjustor, those
ratepayers will be obligated to pay additional amounts for service they received
in the previous year. This represents a major shift in responsibility for
increased costs, from APS and its shareholders to ratepayers. According to APS,
such a shift is necessary for the company to preserve its financial integrity.
Although the parties submitted a written statement describing the
calculation of off-system sales in response to a question from Commissioner
Mundell, we are concerned that the method may not capture the full margin on
each sale.(20) Additionally, we want to make sure that off-system sales are not
being made below costs - Staff needs to study ways to insure that these
off-system sales margins are being determined accurately and that ratepayers are
receiving the full 90 percent of the benefits. Accordingly, we will direct Staff
to establish a method that accurately reflects the appropriate fuel costs and
revenue for off-system sales, so that the full margin is known and properly
accounted for. Within three years of the effective date of this Decision, Staff
shall commence a procurement review of APS' fuel, purchased power, generating
practices and off-system sales practices.
In response to Commissioner Gleason's suggestion to set up a webpage
explaining its bill, APS indicated that it was planning to have a new bill
format, and agreed to also set up a website to
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(20) For example, a wholesale contract may have an embedded cost of fuel built
into the price of the energy that is different from the cost of fuel use to
generate the energy - if the "sales margin" is defined as the difference between
the actual cost of fuel and the revenue from the sale, the true sales margin
will not be captured. We also take administrative notice of FERC Docket No.
PA04-11-000 and the FERC's December 16, 2004 Order Approving Audit Reports and
Directing Compliance Actions, specifically relating to treatment of off-system
sales.
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
explain the bills. Because the implementation of an adjustor will be a major
change in the way that customers are billed, we believe that APS should also
implement a customer education program explaining how its PSA will work and we
will order APS to maintain on its website information explaining the billing
format, rates, and charges, including up-to-date information about the PSA and
current gas costs. It is important that the customer education program be
implemented in a timely fashion, before this summer. APS needs to make its
customers aware that with the implementation of an adjustor, ratepayers will be
obligated to pay additional amounts for service they received in the previous
year. It is essential, and only fair, that customers understand that their usage
this summer can have an effect on their electric bills the following year.
Because we are concerned about the impact of the PSA on low-income
customers, the PSA shall not apply to the bills of individuals who are enrolled
in the Company's Energy Support program. Finally, given our concerns and the
modifications we require to the PSA, we will require the parties to the
Settlement Agreement to submit a PSA Plan of Administration that reflects the
determinations in this Decision, for our approval.
f. DEPRECIATION
The Settlement Agreement adopts Staff's recommended service lives, and
Appendix A to the Settlement Agreement sets forth the remaining service lives,
net salvage allowance, annual depreciation rates, and reserve allocation for
each category of APS depreciable property as agreed to by the parties. The
parties agree that the Statement of Financial Accounting Standards ("SFAS") 143
will not be adopted for ratemaking purposes.
g. $234 MILLION WRITE-OFF
The Settlement Agreement provides that APS will not recover the $234
million write-off attributable to Decision No. 61973 in this case, nor shall APS
seek to recover the write-off in any subsequent proceeding. The ESP and large
consumer witnesses testified that this provision was critical to the development
of flourishing retail markets and will help direct access service from being
undercut by future stranded costs claims.
h. DEMAND SIDE MANAGEMENT ("DSM")
Demand-side management ("DSM") is "the planning, implementation, and
evaluation of
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
programs to shift peak load to off-peak hours, to reduce peak demand (kW), and
to reduce energy consumption (kWh) in a cost-effective manner."(21)
DSM is addressed in three areas of the Settlement Agreement: in the
funding, programs, plans and reporting provisions; in the study of rate design
modifications; and in the competitive procurement process.
Funding for DSM comes in both base rates ($10 million per year) and
through implementation of an adjustor (average of $6 million per year).(22) DSM
funding will be used for "approved eligible DSM-related items," including
"energy-efficiency DSM programs,"(23) a performance incentive,(24) and low
income bill assistance.(25) APS is obligated to spend $13 million in 2005 on DSM
projects.(26)
Appendix B to the Settlement Agreement is a preliminary plan ("Preliminary
Plan") for eligible DSM-related items for 2005. The Preliminary Plan includes
$6.9 million for commercial, industrial, and small business customer programs,
including new construction, retrofitting existing facilities, training and
education, design assistance, and financial incentives; it includes $6.2 million
for residential customers, including new construction and existing homes and
HVAC, education, training, expanded low income weatherization, and bill
assistance; $1.3 million for measurement, evaluation, and research; and $1.6
million for performance incentive.(27) Within 120 days of the Commission's
approval of the Preliminary Plan, APS will, with input and assistance from the
collaborative working group, submit a Final Plan for Commission approval.
In order to help the state's public and charter schools mitigate the
effects of the rate increase, the DSM Working Group should make every effort to
target DSM programs to schools and to make the implementation of DSM in schools
a top priority.
The adjustor will collect DSM costs that are above the $10 million annual
level included in
- -----------------------------------------
(21) Direct testimony of Barbara Keene, February 3, 2004.
(22) APS will spend at least $48 million during calendar years 2005-2007.
(23) "Energy-efficient DSM" is defined as "the planning, implementation and
evaluation of programs that reduce the use of electricity by means of
energy-efficiency products, services, or practices." Settlement Agreement par.
40.
(24) Id. par. 45.
(25) Id. par. 42.
(26) Tr. p. 969.
(27) APS' share of DSM net economic benefits, capped at 10 percent of total DSM
expenditures.
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
base rates. The adjustor rate will initially be set at zero, and will be
adjusted yearly on March 1, based upon the account balance and the appropriate
kWh or kW charge. The DSM adjustor will apply to both standard offer and direct
access customers.
The Settlement Agreement does not provide for the recovery of net lost
revenues. The Settlement Agreement provides that if during 2005 through 2007,
APS does not spend at least $30 million of the base rate allowance for approved
and eligible DSM-related items; the unspent amount will be credited to the
account balance for the DSM adjustor.
On residential customers' bills, the DSM adjustor will be combined with
the EPS adjustor and be called an "Environmental Benefits Surcharge."(28) As
part of its tariff compliance filing, within 60 days of this Decision, APS must
file a Plan of Administration for Staff review and approval.
Pursuant to the Settlement Agreement, APS is required to "implement and
maintain a collaborative DSM working group to solicit and facilitate stakeholder
input, advise APS on program implementation, develop future DSM programs, and
review DSM program performance."(29) The working group will review the plans,
but APS is responsible for demonstrating appropriateness of its programs to the
Commission. APS is required to conduct a study to review and evaluate whether
large customers should be allowed to self-direct DSM investments and file the
study within one year. APS is also required to study rate designs that encourage
energy efficiency, discourage wasteful and uneconomic use of energy, and reduce
peak demand. The plan for the study and analysis of rate design modifications
must be presented to the collaborative DSM working group within 90 days, and APS
must submit to the Commission the final results as part of its next rate case,
or within 15 months of this Decision, whichever is first. APS is required to
develop and propose appropriate rate design modifications. Additionally, APS is
required to file mid-year and end-year reports on each DSM program. All DSM
year-end reports filed at the Commission by APS must be certified by an Officer
of the Company.
Pursuant to the Settlement Agreement, APS is to invite DSM resources to
participate in its RFP and other competitive solicitations, and must evaluate
them in a consistent and comparable
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(28) Settlement Agreement par. 50.
(29) Id. par. 54.
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
manner.
SWEEP supports the DSM provisions in the Settlement Agreement. Although it
originally recommended that the Commission should substantially increase energy
efficiency by setting target goals of 7 percent of total energy resources needed
to meet retail load in 2010 from energy efficiency and 17 percent in 2020, it
agreed that the Settlement Agreement's requirement of DSM funding is reasonable
and justified given the cost-effective benefits that will be achieved. SWEEP
believes that the level of funding in the Settlement Agreement is a valuable and
meaningful step towards encouraging and supporting energy efficiency for APS
customers, especially since the Commission can approve additional DSM program
funding through the adjustment mechanism.
In response to questioning from Commissioner Spitzer, the witness for
SWEEP testified that DSM is the most efficient way to mitigate market and fuel
price increases and it reduces customer vulnerability to price volatility, by
reducing the need for new power plant construction and new transmission
lines.(30) Even customers who do not participate in the DSM programs will
benefit, both from an economic perspective as well as from the environmental and
health standpoint.(31) The Preliminary DSM Plan attached as Exhibit B to the
Settlement Agreement is a good start towards developing cost-effective DSM
programs. However, we are concerned that our approval of the Settlement
Agreement and Exhibit B may result in stakeholders focusing too narrowly when
attempting to comply with the DSM goals of this Order. Particularly, we note
that there are no demand response programs included in Exhibit B. Given the
response by APS' customers to last summer's outage as discussed by Commissioner
Hatch-Miller,(32) it is clear that when proper signals are given, customers will
respond by reducing their demand.
We also think it is clear that the traditional demand response programs
that define "off-peak" hours as between 9:00 p.m. to 9:00 a.m. are ineffective
in creating an incentive to residential ratepayers to shift their electricity
consumption to "off peak" hours. Common sense indicates that a substantial
number of ratepayers cannot or are not able to take advantage of such programs
as 9:00 p.m. is an unrealistic time to commence the "off peak" period because
most ratepayers are either
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(30) Tr. p. 877.
(31) Tr. p. 930.
(32) See discussion Tr. pp. 1384-1394.
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
asleep or preparing to sleep at that time.(33) Further, the start time begins
many hours after the actual peak has subsided. Finally, the inconvenience of a
9:00 p.m. start time assures that the demand response to "off peak" hours and
programs is miscalculated. Therefore, in an effort to expedite APS' addressing
demand response programs, we will order APS to file additional time-of-use
programs that are similar to the Time Advantage and Combined Advantage Plans
with different peak schedule(s) and tariff(s) options, within six months of the
effective date of this Decision.
We believe that it would be beneficial, perhaps in conjunction with the
rate design time-of-use study and the use of "advanced" or "smart" meters, to
evaluate and implement programs designed to reduce APS' summer peak demand.
Accordingly, we will encourage submission of such DSM programs.
i. ENVIRONMENTAL PORTFOLIO STANDARD AND OTHER RENEWABLES PROGRAMS
The Settlement Agreement addresses renewable energy in three areas: a
special renewable energy solicitation; the environmental portfolio standard
("EPS") and in the competitive procurement of power.
The Settlement Agreement requires APS to issue a special RFP in 2005
seeking at least 100 MW and at least 250,000 MWh per year of renewable energy
resources including solar, biomass/biogas, wind, small hydro (under 10 MW),
hydrogen (other than from natural gas) or geothermal for delivery beginning in
2006. In order to take advantage of any available federal tax credits for
renewable energy production, APS should issue the 100 MW RFP no later than May
15, 2005. APS also will seek to acquire at least ten percent of its annual
incremental peak capacity needs from renewable resources. Among other
requirements, the renewable resources must be no more costly than 125 percent of
the reasonably estimated market price of conventional resource alternatives and
APS can acquire out-of-state resources to meet the goal if sufficient in-state
qualified bids are not received. However, if APS determines that it cannot meet
this requirement through in-state resources, it must bring its proposal to
purchase out-of-state resources to Staff and obtain Commission approval before
making the out-of-state purchase.
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(33) We do not need a study, workshop or to evaluate the proposed test demand
programs to convince us regarding residential demand programs in this matter.
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
The Settlement Agreement also provides that renewable resources acquired
through the special RFP or future solicitations shall be subject to the
Commission's customary prudence review. And while the Settlement Agreement
further stipulates that a renewable resource purchase shall not be found
imprudent solely because the cost of the renewable resource exceeds market
price, we stipulate conversely that a renewable resource purchase shall not be
rendered prudent solely by virtue of the resource's cost being below 125 percent
of market price.
The special RFP does not displace APS' requirements under the EPS. APS
will continue to collect $6 million annually in base rates and the existing EPS
surcharge, which provided $6.5 million during the test year, will be converted
to an adjustment mechanism, which will allow for Commission-approved changes to
APS' EPS funding.
The Settlement Agreement does not alter the existing EPS or the current
level of funding, but it changes the EPS surcharge into an adjustor so that the
Commission has the flexibility to change funding levels and rates in the future.
APS' current rates and surcharge total $12.5 million and pursuant to the
Settlement Agreement, $6 million of this amount will be recovered in base rates
and $6.5 million in the EPS adjustor.
Under the Settlement Agreement, APS will allow and encourage all renewable
resources to participate in its competitive power procurement.
In response to a request from Commissioner Spitzer, several parties filed
late-filed exhibits concerning the recently enacted American Jobs Creation Act
of 2004. According to APS, the Act provides for a domestic production deduction
for its generation activities, and also extends renewable electricity production
credits through 2005 and expands the types of renewable resources eligible for
the credits.(34) In its December 10, 2004 response, WRA stated that "renewable
energy appears to be at a disadvantage relative to gas-fired generation because
the tax burden tends to fall more heavily on capital intensive projects such as
renewable energy generation. Therefore, such tax burden differentials may add
further support for the preference for renewable energy in the settlement
agreement and for production tax credits as means to `level the playing field'
between gas-fired
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(34) Previously, only wind, closed-loop biomass and poultry waste were included,
and now open-loop biomass, geothermal energy, solar energy, small irrigation
power, and municipal solid waste are included as qualified energy resources.
DECISION NO 67744
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DOCKET NO. E-01345A-03-0437
resources and renewable energy."
j. COMPETITIVE PROCUREMENT OF POWER
The Settlement Agreement provides that APS will issue an RFP or other
competitive solicitation(s) in 2005 seeking long-term resources of not less than
1000 MW for 2007 and beyond. "Long-term" resource is defined as acquisition of a
generating facility or an interest in one, or any PPA of 5 years or longer. No
APS affiliate will participate in this RFP/solicitation, and in the future will
not participate unless an independent monitor is appointed. Further, APS will
not self-build any facility with an in-service date prior to January 1, 2015,
unless expressly authorized by the Commission. As defined in the Settlement
Agreement, "self-build" does not include the acquisition of a generating unit or
interest in one from a non-affiliated merchant or utility generator, the
acquisition of temporary generation needed for system reliability, distributed
generation of less than 50 MW per location, renewable resources, or the
up-rating of APS generation.
We generally agree that the self-build moratorium proposed in the
Agreement is useful for addressing the potentially anti-competitive effects that
may be associated with rate-basing the PWEC assets. However, to fully realize
the benefits of the moratorium for that purpose, the moratorium should apply to
the acquisition of a generating unit or interest in one from any merchant or
utility generator, as well as to building new units. Accordingly, we will modify
the definition of "self-build" to include the acquisition of a generating unit
or interest in a generating unit from any merchant or utility generator.
Consistent with the definition in the Settlement Agreement, "self-build" will
not include the acquisition of temporary generation needed for system
reliability, distributed generation of less than fifty MW per location,
renewable resources, or up-rating of APS generation, which up-rating shall not
include the installation of new units.
Similarly, we will require APS to obtain the Commission's expressed
approval for APS' acquisition of any generating facility or interest in a
generating facility pursuant to a RFP or other competitive solicitation(35)
issued before January 1, 2015. Our determination herein should not be construed
as signaling in any manner the ultimate regulatory treatment that can or will be
accorded to
- -----------------------
(35) Competitive solicitation includes a RFP issued pursuant to Paragraph 78 of
the Settlement Agreement or any solicitation issued by APS in using its
Secondary Procurement Protocol pursuant to Paragraph 80 of the Settlement
Agreement.
DECISION NO 67744
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DOCKET NO. E-01345A-03-0437
any generating facility or interest in any generating facility ultimately
acquired by APS. APS will continue to use its Secondary Procurement Protocol
except as modified by the Settlement Agreement or by Commission decision. The
Commission's Staff will schedule workshops on resource planning, focusing on
developing needed infrastructure and a flexible, timely, and fair competitive
procurement process. As discussed above, the rate basing of PWEC assets, at a
discount, should not be construed as an abandonment of competition by this
Commission. The industry-wide question, "how will new generation be built and by
whom?", is particularly trenchant in Arizona due to high forecast growth in
customer load. The self-build moratorium agreed to by APS is consistent with the
Commission's support for competitive wholesale electricity markets.
The workshops conducted by Staff on the development of needed
infrastructure shall include consideration of the feasibility and implementation
of an expanded use of utility-scale solar electric generation integrated with
existing coal fired operations. APS' aging coal fired plants face an
increasingly emissions regulated future which may require sizeable investments
to improve emissions control performance.
By integrating solar generation with the existing generation and
transmission infrastructure at coal fired facilities, it may be possible to
create synergies that take advantage of existing site infrastructure to lower
the cost of building and operating solar electric generation, while reducing the
environmental impact of coal fired generation. Generation from a solar electric
project will add fuel-free, net-plant energy output resulting in environmental
benefits and lower energy specific water usage. A long-term benefit of such a
strategy would be that after all life extension measures are exhausted for the
fueled power complexes, there will be many decades of useful life remaining in
the transmission assets serving these sites. These valuable assets could be
utilized by emission and water free solar generation built incrementally over
the next decades in the expansive buffer zone property around many of the
existing coal plants.
k. REGULATORY ISSUES
In the Settlement Agreement, the parties acknowledge that APS has the
obligation to plan for and serve all customers in its certificated service area
and to recognize through its planning, the existence of any Commission direct
access program and the potential for future direct access
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
customers. Any change in retail access as well as the resale by APS and other
Affected Utilities of Revenue Cycle Services to ESPs will be addressed through
the Electric Competition Advisory Group ("ECAG") or similar process. The parties
acknowledge that APS may join a FERC-approved Regional Transmission Organization
("RTO") or entity and may participate in those activities without further order
or authorization from the Commission.
l. COMPETITION RULES COMPLIANCE CHARGE ("CRCC")
Included in the total test year revenue requirement is approximately $8
million for the Competition Rules Compliance Charge. APS will recover $47.7
million plus interest through a CRCC of $0.000338/kWh over a collection period
of 5 years. When that amount is collected, the CRCC will immediately terminate,
and if the amount is under or over recovered, then APS must file an application
for the appropriate remedy.
m. LOW INCOME PROGRAMS
APS will increase funding for marketing its E-3 and E-4 tariffs to a total
of $150,000 as set forth in the Settlement Agreement. The parties' intent is to
insulate eligible low income customers from the effects of the rate increase
resulting from the Settlement Agreement. On December 17, 2004, the ACAA filed a
response to Commissioner Mayes' question about automatic enrollment in utility
discount programs, indicating that they have initiated a discussion with the
Arizona Department of Economic Security ("DES") to facilitate the automatic
enrollment in utility discount programs, as well as other agency managed
programs. ACAA is in the process of adding the utility discount application
forms to its website, which will allow the form to be sent electronically to the
appropriate entity for processing. Concerning marketing efforts, ACAA stated
that it engages in various outreach efforts throughout the state, providing
information about the E-3 discount program available through APS. ACAA indicated
that DES is currently charged with the official marketing of the program, but
there is currently no affirmative marketing of the program "as their resources
are severely limited." Also in response to Commissioner Mayes' request, APS
filed information concerning its low income programs. APS stated that it has
renewed its conversations with DES and ACAA, requesting feedback on increasing
participation through automated signup for the E-3 and E-4 programs. Both
agencies expressed interest and APS states that it will continue to work with
both
DECISION NO. 67744
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DOCKET NO. E-01345A-03-0437
agencies to determine the efficiency and practicality of such a streamlined
approach.
The Commission believes that APS should work to make its low-income
assistance programs widely available, including to Native Americans living
inside the Company's service territory. Within six months of the effective date
of this Order, APS shall develop an outreach plan that will enable it to better
inform the state's Tribes about the Company's low-income assistance programs.
The plan should be filed with the Commission and made available to Tribal
authorities within APS' service territory.
n. RETURNING CUSTOMER DIRECT ACCESS CHARGE ("RCDAC")
The Settlement Agreement provides that APS can recover from Direct Access
customers the additional cost that would otherwise be imposed on other Standard
Offer customers if and when the former return to Standard Offer from their
competitive suppliers. The RCDAC shall not last longer than 12 months for any
individual customer. The charge will apply only to individual customers or
aggregated groups of 3 MW or greater who do not provide APS with one year's
advance notice of intent to return to Standard Offer service. APS will file a
Plan of Administration as part of its tariff compliance filing.
o. SERVICE SCHEDULE CHANGES
The Settlement Agreement adopts several of APS' proposed changes to
service schedules, including Schedule 3, but with the retention of the 1,000
foot construction allowance for individual residential customers and also with
any individual residential advances of costs being refundable. Several APS
customers made public comment about the line extension policy and how it has not
been modified in a long time. We will direct Staff to work with APS to review
its line extension policy and determine whether the construction allowance
should be modified.
p. NUCLEAR DECOMMISSIONING
The decommissioning costs as recommended by APS are adopted as set forth
in Appendix I to the Settlement Agreement.
q. TRANSMISSION COST ADJUSTOR ("TCA")
The Settlement Agreement establishes a transmission cost adjustor ("TCA")
to ensure that any potential direct access customers pay the same for
transmission as Standard Offer customers.
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The TCA is limited to recovery of costs associated with changes in APS' open
access transmission tariff ("OATT") or equivalent tariff. The TCA goes into
effect when the transmission component of retail rates exceeds the test year
base amount of $0.00476(36) per kWh by 5 percent and APS obtains Commission
approval of a TCA rate.
r. DISTRIBUTED GENERATION
Generally, distributed generation is small-scale power generation units
strategically located near customers and load centers. According to the
ACA/DEAA, the benefits of distributed energy systems include: greater grid
reliability; increased grid stability (voltage support along transmission
lines); increased system efficiency (reduction in transmission line losses);
increased efficiency; flexibility; decreased pressure on natural gas (demand and
cost); leverage of resources; and sustainable installations.
The Settlement Agreement provides that Staff shall schedule workshops to
consider outstanding issues affecting distributed generation and shall refer to
the results of the prior distributed generation workshops for issues to study.
ACA/DEAA presented its objectives at hearing as follows: a DG workshop
with strong Staff leadership; clear goals, ground rules, milestones, and
deadlines; participants with authority; continuing reports to ACC and
management; and a process to bring contested issues to the Commission for
resolution. None of the proponents of the Settlement Agreement oppose Commission
adoption of these objectives.
In its post-hearing brief, ACA/DEAA listed the following guidelines as
"overriding criteria": 1) rates must be fair; 2) rates should be designed to
send as efficient as possible pricing signals to consumers; 3) impediments to
customer choices, such as unnecessarily difficult and expensive interconnection
to the grid, should be eliminated to the maximum extent possible; 4) all
generators should be treated fairly - large and small; and 5) proposals, if
implemented, should not interfere with the Commission's public policy goals.
ACA/DEAA made 3 recommendations: 1) Rate Design - the Commission should adopt an
experimental rate for partial requirement customers. The proposal
- ---------------------
(36) Paragraph 106 of the Settlement Agreement contains a typo; the amount
"$0.000476" should actually be "$0.00476," Tr. p. 1168.
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would mimic SRP's E-32 rate, which includes time of day rates and summer/winter
rates. ACA/DEAA proposed to limit participation to 50 MWs of new customer load
each year for 5 years - both generation and supplemental load. It appears that
this is the first alternative rate schedule that ACA/DEAA has proposed, and no
party has had an opportunity to evaluate and comment on the proposal.
Accordingly, we decline to adopt the proposal in this docket, but we believe
that this proposal may be a good starting point for discussion in the DG
workshop.
ACA/DEAA further recommended that the Texas standard is best suited for
application to the APS system and that the provisions of California rule 21
would serve as a second choice for DG standards in Arizona. ACA/DEAA also
recommended that the Commission consider a program to install self generation to
reduce the electricity on the power grid. We believe that both of these
recommendations should also be discussed and developed during the course of the
workshop.
The proponents of the Settlement Agreement recommend that specific issues
concerning DG should be addressed in workshops devoted to distributed
generation. Paragraphs 108 and 109 direct Staff to schedule workshops to address
outstanding DG issues. They believe that such a process would use the work done
in previous workshops and would also address the technical aspects of connecting
distributed generation in a way that would apply to all regulated utilities in
Arizona. To be successful, the process would require a strict timetable for
producing recommendations for the Commission's consideration. The proponents
argue that Schedule E-32 should not be redesigned to meet the specialized needs
of partial requirements service, but that the rate design for partial
requirements service should be addressed in the workshop. Approximately 95,000
full requirement customers receive service under Schedule E-32, and according to
the proponents, it is an integral part of the Settlement Agreement. The
proponents believe that ACA/DEAA's proposal to put the rate increase in the
energy portion would create a massive subsidy from higher load factor customers
to lower load factor customers. The demand related charges are necessary for
pricing the capacity related costs of the APS system for the full requirement
customers. The proponents argue that DG requires partial requirement service -
which is a very specialized product that includes maintenance power, standby
power, and supplemental power - and it should have its own rate, which can be
addressed in the proposed DG workshop.
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We agree with ACA/DEAA that DG can have significant benefits to APS and to
its ratepayers and we want to encourage the growth of DG that can provide those
benefits. Additionally, we find some of the suggestions made in ACA/DEAA's post
hearing brief persuasive. However, our decision is rooted in the record made in
this case, and those suggestions were not fully delineated, nor subjected to
cross examination at the Hearing. At this point, we agree with the participants
that the E-32 schedule should not be modified to accommodate the particular
needs associated with DG. Therefore, we believe that the parties should address
the issue of an appropriate rate schedule for DG during the workshop process,
and direct the parties to develop a schedule that is designed particularly for
DG customers. Further, we direct the parties to begin the process by evaluating
the three recommendations made by ACA/DEAA in its post hearing brief.
s. BARK BEETLE REMEDIATION
APS is authorized to defer for later recovery the reasonable and prudent
direct costs of bark beetle remediation that exceed the test year levels of tree
and brush control. In the next rate case, the Commission will determine the
reasonableness, prudence, and allocation of the costs, and will determine the
appropriate amortization period.
t. RATE DESIGN
Attached to the Settlement Agreement is Appendix J, which sets forth the
rates adopted in the Settlement Agreement. The rates are designed to permit APS
to recover an additional $67.5 million in base revenues, including an additional
3.94 percent for the residential rate class and a 3.57 percent increase for the
general service rate class. The rates were designed to move toward costs and
remove subsidizations, thereby promoting equity among customers. The base rates
will also permit cost-based unbundling of distribution and revenue cycle
services, including metering, and meter reading and billing. The parties believe
that this will give appropriate price signals necessary for shopping. APS will
continue on-peak and off-peak rates for winter billing for all residential
time-of-use customers under Schedules ET-1 and ECT-1R. Within 180 days APS will
submit a study to Staff that examines other ways APS can implement more
flexibility in changing APS' on- and off-peak time periods and other time-of-use
characteristics, making those periods more reflective of actual system peak time
periods. APS shall also include in the aforementioned study a cost-benefit
analysis
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of Surepay, APS' automatic payment program. The Company is to examine the cost
effectiveness of the program and to explore the possibility of offering a
discount to those customer who participate in Surepay. The Settlement Agreement
adopts APS' proposed experimental time-of-use periods for ET-1 and ECT-1R. For
general service customers, the existing on-peak time periods will remain the
same and the summer rate period will begin in May and conclude in October. The
general service rate schedules will also permit cost-based unbundling of
generation and revenue cycle services and will be differentiated by voltage
levels. An additional primary service discount of $2.74/kW for military base
customers served directly from APS substations will be adopted. The Settlement
Agreement modifies Schedule E-32 in order to simplify the design, make it more
cost-based, and to smooth out the rate impact across customers of varying sizes
within the rate schedule. Changes include the addition of an energy block for
customers with loads under 20 kW and an additional demand billing block for
customers with loads greater than 100 kW. A time-of-use option will also be
available to E-32 customers. Testimony was offered at the hearing that there was
an inadvertent omission in Appendix J to the Settlement Agreement for Rate
E-32-TOU in that the delivery-related demand charge for Rate E-32-TOU should
have been reduced after the first 100 kW of demand for residual off-peak
demand(37) and that the initial rate block for residual off-peak delivery should
be applied only to the first 100kW of combined on-peak and residual off-peak
demand. We will, therefore, direct APS to modify Rate E-32-TOU in accordance
with these changes in its compliance filings. As discussed above, ACA/DEAA
objected to the company's E-32 schedule. One of ACA/DEAA's concern was the
almost doubling of the demand charge. The Commission has open dockets involving
APS' metering and bill estimation procedures, including the estimation of
demand. Although we are not resolving those issues in this rate case, we are
concerned that APS properly meter, read meters and bill its customers timely and
accurately. (38) It is imperative, especially given
- -------------------------
(37) Instead of remaining at the initial level of $7.722 per kW-month, after the
first 100 kW of demand, the unbundled residual off-peak demand charge for
delivery at Secondary voltage will be reduced to $3.497; after the first 100kW
of demand, the unbundled residual off-peak demand charge for delivery at Primary
voltage will be reduced to $2.877, with both of these changes incorporated into
the bundled rate as well.
(38) Also, we note that apparently APS is deleting a bill estimation procedure
for EC-1 and ECT-1R. It is not clear whether these are the tariffs that Staff
has alleged APS has not been following, but nothing in this Decision will affect
our ability to make findings in Docket Nos. E-01345A-04-0657, et al. or impose
any appropriate fines, sanctions, or remedies in those dockets.
DECISION NO. 67744
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the increase in the demand charge, that APS reduce the instances where it
estimates demand.
In a response (dated August 18, 2004) to a question from Commissioner
Mundell regarding the break-over points for tiered rates, the parties to the
Settlement Agreement indicated that rate E-12 has the most customers. The
response also stated that the average use by a customer on rate E-12 is 770 kWh
per month. Rate E-12 has three tiers with break-over points at 400 kWh per month
and 800 kWh per month. Paragraph 57 of the Settlement Agreement requires APS to
conduct a rate design study analyzing rate design modifications to promote
energy efficiency, conservation, and reduce peak demand. As part of the study,
we will require that one of the rate design modifications that APS shall
investigate is to lower the first break-over point in rate E-12 to 350 kWh per
month and lower the second break-over point to 750 kWh per month. In addition,
the charge (rate) per kWh in the first tier (less than 350 kWh per month) should
be lowered, while the rate for the third tier (over 750 kWh per month) should be
raised. We will require that APS propose this type of rate design, or something
very similar, for rate E-12 in its next rate case. We believe this type rate
design, coupled with the DSM measures outlined in this Order, will encourage
customers, especially high-use customers, to conserve energy (thereby lowering
overall demand) and/or move to time-of-use rates (thereby lowering peak demand).
If APS or any party to the next APS rate case believes this type rate design
would be detrimental to APS and/or its customers, that party shall provide a
detailed explanation and examples as to how and why this type rate design would
be detrimental.
Several schedules are "frozen" and APS will provide notice approved by
Staff to those customers that those rates will be eliminated in APS' next rate
case. Such notice will be provided at the conclusion of this docket and at the
time that APS files its next rate case.
u. LITIGATION AND OTHER ISSUES
The Settlement Agreement provides that APS will dismiss with prejudice all
appeals of Decision No. 65154, the Track A Order, and APS and its affiliates
will dismiss litigation related to Decision Nos. 65154 and 61973 and/or any
alleged breach of contract, and APS and its affiliates shall forgo any claim
that APS, PWEC, Pinnacle West Capital Corporation or any of APS' affiliates were
harmed by Decision No. 65154, and the Preliminary Inquiry ordered in Decision
No. 65796 shall be concluded with no further action by the Commission, once the
Settlement Agreement is approved in
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accordance with Section XXI of the Settlement Agreement by a Commission Decision
that is final and no longer subject to judicial review.
The Commission is also concerned that service reliability on rural Tribal
lands has become degraded. Therefore, within six months of the effective date of
this Order, APS should compile its SAIFI, CAIDI and SAIDI numbers for all Tribal
territories it serves and provide to the Commission a report on proposed options
for improving reliability in these areas. Moreover, APS shall participate in any
future dockets related to enhancing reliability statewide.
v. SUMMARY
This Settlement Agreement resolves numerous significant, complex, and
conflicting issues affecting many parties with very different perspectives and
interests. As with every settlement, the give and take nature of negotiations
ends up with a product that no one party initially proposed. The key question
when deciding whether to approve such a settlement is whether the end result
resolves the important issues fairly and reasonably when taken together as a
whole, and in such a way that will promote the public interest. We believe that
the Settlement Agreement reached by these 22 parties, with the modifications
that we make herein, reaches such a result. Our agreement to rate base the PWEC
assets does not mean that we are retreating from our commitment to encourage the
development of competition, and we expect APS and its affiliates to fully comply
with all the pro-competition requirements in the Settlement Agreement and other
Commission decisions and rules. Additionally, our adoption of a PSA will be a
significant change for APS customers, and we expect APS to educate and inform
its customers about all aspects of that adjustor charge in a way that will
minimize confusion and misunderstandings. We also expect APS to have the
required information posted to its website and its customer education program up
and running before June 1, 2005, in order to allow customers the opportunity to
implement their own conservation measures. Finally, we want to make it clear to
APS that our adoption of a PSA does not relieve it of its obligation to
effectively and efficiently manage its fuel costs, and that we will closely
monitor APS' performance.
* * * * * * * * * *
Having considered the entire record herein and being fully advised in the
premises, the Commission finds, concludes, and orders that:
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IV. FINDINGS OF FACT
1. APS is a public service corporation principally engaged in furnishing
electricity in the State of Arizona. APS provides either retail or wholesale
electric service to substantially all of Arizona, with the major exceptions of
the Tucson metropolitan area and about one-half of the Phoenix metropolitan
area. APS also generates, sells and delivers electricity to wholesale customers
in the western United States.
2. On June 27, 2003, APS filed with the Commission an application for a
$175.1 million rate increase and for approval of a purchased power contract.
3. Notice of the application was provided in accordance with the law.
4. Intervention was granted to AECC, FEA, Kroger, RUCO, AUIA, Phelps
Dodge, IBEW, ACA/DEAA, Panda, AWC, SWG, WRA, CNE, SEL, DVEP, UES, ACAA,
Alliance, Wickenburg, AriSEIA, AARP, SWEEP, PPL Sundance, PPL Southwest, SWPG,
Mesquite, and Bowie.
5. By Procedural Order issued August 15, 2003, the hearing was set to
commence on April 7, 2004, and procedural dates were established for the filing
of testimony and evidence.
6. On February 6, 2004, APS filed a Motion to Amend the Rate Case
Procedural Schedule, and a procedural conference was held on February 18, 2004
to discuss the Motion.
7. By Amended Rate Case Procedural Order issued on February 20, 2004, the
hearing date was rescheduled for May 25, 2004 and other procedural dates were
modified.
8. On April 6, 2004, Staff filed a Motion to Amend the Procedural Schedule
and on April 8, 2004, Staff filed a Memorandum indicating that representatives
of APS had contacted Staff about the possibility of conducting settlement
negotiations.
9. A public comment hearing was held on April 7, 2004.
10. On April 13, 2004, APS filed its Response to Staff's Motion and Staff
Notice of Settlement Negotiations and requested a temporary suspension of the
procedural schedule in order for settlement discussions to take place.
11. Pursuant to Procedural Orders issued April 7 and 12, 2004, a
procedural conference to discuss Staff's Motion was held on April 15, 2004. By
Procedural Order issued April 16, 2004, new
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DOCKET NO. E-01345A-03-0437
procedural dates were established and another procedural conference was
scheduled for April 28, 2004.
12. The April 28, 2004 procedural conference was held as scheduled and by
Procedural Order issued April 29, 2004, the procedural schedule was stayed and
another procedural conference was scheduled for May 26, 2004.
13. Pursuant to procedural conferences held on May 26 and June 14, 2004,
and Procedural Orders issued on May 26, June 18, and July 20, 2004, the stay was
extended in order to allow the parties to discuss settlement.
14. At the August 18, 2004 Procedural Conference, the parties announced
that they had reached a settlement, and the Settlement Agreement was docketed on
that date.
15. On August 20, 2004, an Amended Rate Case Procedural Order was issued
setting the hearing on the Settlement Agreement to commence on November 8, 2004.
16. The hearing was held as scheduled on November 8, 9, 10, 29, 30 and
December 1, 2, and 3, 2004. Public comment was taken and testimony from the
proponents of the Settlement Agreement was presented in panel format, and
testimony from the ACA/DEAA was also presented in a panel format.
17. The Test Year ending 2002 Plant in Service was $4,876,901,000,
excluding transmission plant, and including the PWEC assets as of December 31,
2004.
18. APS' FVRB is $5,054,426,000 and a 5.92 fair value rate of return is
appropriate.
19. It is just and reasonable to authorize a total annual revenue increase
in the amount of $75,500,000, consisting of an increase in base rates of
approximately 3.77 percent or $67.6 million, and an increase in the CRCC
surcharge of approximately .44 percent, which will collect $7.9 million.
20. A Power Supply Adjustor as set forth in the Settlement Agreement and
as modified herein, is in the public interest.
21. APS is authorized to acquire the PWEC generation assets and rate base
those assets at a value of $700 million as of December 31, 2004, under the terms
and conditions as set forth in the Settlement Agreement and herein.
22. The Settlement Agreement will allow APS the opportunity to earn a
reasonable rate of
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DOCKET NO. E-01345A-03-0437
return on its investment, will provide revenues sufficient for the Company to
provide efficient and reliable service, and will allow for continued development
of electric competition in Arizona.
23. APS shall implement a customer education program explaining how its
PSA will work and shall maintain on its website information explaining the
billing format, rates, and charges, including up-to-date information about the
PSA and current gas costs. APS shall submit its plan to implement its customer
education program within 30 days of the effective date of this Decision to the
Director of the Utilities Division for review and Staff shall keep the
Commission apprised of the consumer education program. Furthermore, APS shall
post the required information on its website within 30 days of the effective
date of this Decision.
24. The parties to the Settlement Agreement shall submit a PSA Plan of
Administration that reflects the determinations in this Decision for Commission
approval within 60 days of the effective date of this Decision.
25. The depreciation rates and the costs for nuclear decommissioning as
set forth in the Settlement Agreement are reasonable and appropriate.
26. Testimony was offered at the hearing that there was an inadvertent
omission in Appendix J to the Settlement Agreement for Rate E-32-TOU in that the
delivery-related demand charge for Rate E-032-TOU should have been reduced after
the first 100 kW of demand for residual off-peak demand and that the initial
rate block for residual off-peak delivery should be applied only to the first
100 kW of combined on-peak and residual off-peak demand. We will, therefore,
direct APS to modify Rate E-32-TOU in accordance with these changes in its
compliance filings.
27. We direct the parties to begin the DG workshop process by evaluating
the three recommendations made by ACA/DEAA in its post hearing brief.
28. In its study to be filed within 180 days of the effective date of this
Decision concerning flexibility of on- and off-peak time periods and other
time-of-use characteristics, APS shall also include a cost-benefit analysis of
Surepay, APS' automatic payment program. The Company shall examine the cost
effectiveness of the program and explore the possibility of offering a discount
to those customers who participate in Surepay.
29. APS shall file additional time-of-use programs that are similar to the
Time Advantage
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and Combined Advantage Plans with different peak schedule(s) and tariff(s)
options, within six months of the effective date of this Decision.
30. In a response (dated August 18, 2004) to a question from Commissioner
Mundell regarding the break-over points for tiered rates, the parties to the
Settlement Agreement indicated that rate E-12 has the most customers. The
response also stated that the average use by a customer on rate E-12 is 770 kWh
per month. Rate E-12 has three tiers with break-over points at 400 kWh per month
and 800 kWh per month. Paragraph 57 of the Settlement Agreement requires APS to
conduct a rate design study analyzing rate design modifications to promote
energy efficiency, conservation, and reduce peak demand. As part of the study,
we will require that one of the rate design modifications that APS shall
investigate is to lower the first break-over point in rate E-12 to 350 kWh per
month and lower the second break-over point to 750 kWh per month. In addition,
the charge (rate) per kWh in the first tier (less than 350 kWh per month) should
be lowered, while the rate for the third tier (over 750 kWh per month) should be
raised. We will require that APS propose this type of rate design, or something
very similar, for rate E-12 in its next rate case. We believe this type rate
design, coupled with the DSM measures outlined in this Order, will encourage
customers, especially high-use customers, to conserve energy (thereby lowering
overall demand) and/or move to time-of-use rates (thereby lowering peak demand).
If APS or any party to the next APS rate case believes this type rate design
would be detrimental to APS and/or its customers, that party shall provide a
detailed explanation and examples as to how and why this type rate design would
be detrimental.
31. In order to help the state's public and charter schools mitigate the
effects of the rate increase, the DSM Working Group should make every effort to
target DSM programs to schools and to make the implementation of DSM in schools
a top priority.
32. All DSM year-end reports filed at the Commission by APS must be
certified by an Officer of the Company.
33. We are modifying the definition of "self-build" to include the
acquisition of a generating unit or interest in a generating unit from any
merchant or utility generator, and we will require APS to obtain the
Commission's expressed approval for APS' acquisition of any generating facility
or interest in a generating facility pursuant to a RFP or other competitive
solicitation issued
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before January 1, 2015. Our determination herein should not be construed as
signaling in any manner the ultimate regulatory treatment that can or will be
accorded to any generating facility or interest in a generating facility
ultimately acquired by APS.
34. The workshops conducted by Staff on the development of needed
infrastructure shall include consideration of the feasibility and implementation
of an expanded use of utility-scale solar electric generation integrated with
existing coal fired operations. APS' aging coal fired plants face an
increasingly emissions regulated future which may require sizeable investments
to improve emissions control performance.
35. The Settlement Agreement also provides that renewable resources
acquired through the special RFP or future solicitations shall be subject to the
Commission's customary prudence review. And while the Settlement Agreement
further stipulates that a renewable resource purchase shall not be found
imprudent solely because the cost of the renewable resource exceeds market
price, we stipulate conversely that a renewable resource purchase shall not be
rendered prudent solely by virtue of the resource's cost being below 125 percent
of market price.
36. In order to take advantage of any available federal tax credits for
renewable energy production, APS should issue the 100 MW RFP no later than May
15, 2005.
37. If Arizona Public Service Company determines that it cannot meet the
goal for renewable energy resources as set forth in Paragraph 69 of the
Settlement Agreement, through in-state resources, it shall bring its proposal to
purchase out-of-state resources to Staff and obtain Commission approval before
making the out-of-state purchase.
38. We agree that the use of an adjustor when fuel costs are volatile
prevents a utility's financial condition from deteriorating. We are less
inclined, however, to adopt an adjustor as a way to keep pace with load growth.
Although APS' rebuttal testimony indicated that its fixed costs would increase
in relation to its load growth, we are concerned about the potential for
single-issue ratemaking and whether APS' fixed costs will increase in the same
proportion as its fuel costs. According to the late-filed exhibits, the majority
of the increased fuel costs are caused by increased load growth, rather than
price volatility in fuel. In effect, the adjustor as designed provides annual
step increases in rates. We believe APS must have an incentive to file a rate
case so that we can
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DOCKET NO. E-01345A-03-0437
determine the accuracy of its assertion about expenses. Therefore, we will adopt
an adjustor that collects or refunds the annual fuel costs that differ from the
base year level. However, we will limit the adjustor to 4 mil from the base
level over the entire term of the PSA and will cap the balancing account to an
aggregate amount of $100 million. Should the Company seek to recover or refund a
bank balance pursuant to Paragraph 19E of the Settlement Agreement, the timing
and manner of recovery or refund of that existing bank balance will be addressed
at such time. In no event shall the Company allow the bank balance to reach $100
million prior to seeking recovery or refund. Following a proceeding to recover
or refund a bank balance between $50 million and $100 million, the bank balance
shall be reset to zero unless otherwise ordered by the Commission.
39. Within three years of the effective date of this Decision, Staff shall
commence a procurement review of APS' fuel, purchased power, generating
practices and off-system sales practices.
40. Because we are concerned about the impact of the PSA on low-income
customers, the PSA shall not apply to the bills of individuals who are enrolled
in the Company's Energy Support program.
41. APS should work to make its low-income assistance programs widely
available, including to Native Americans living inside the Company's service
territory. Within six months of the effective date of this Order, APS shall
develop an outreach plan that will enable it to better inform the state's Tribes
about the Company's low-income assistance program. The plan should be filed with
the Commission and made available to Tribal authorities within APS' service
territory.
42. The Commission is also concerned that service reliability on rural
Tribal lands has become degraded. Therefore, within six months of the effective
date of this Order, APS should compile its SAIFI, CAIDI and SAIDI numbers for
all Tribal territories it serves and provide to the Commission a report on
proposed options for improving reliability in these areas. Moreover, APS shall
participate in any future dockets related to enhancing reliability statewide.
V. CONCLUSIONS OF LAW
1. Arizona Public Service Company is a public service corporation within
the meaning of Article XV of the Arizona Constitution and A.R.S. Sections
40-222, 250, 251, and 376.
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2. The Commission has jurisdiction over Arizona Public Service Company and
the subject matter of the application.
3. Notice of the application was provided in accordance with the law.
4. The Settlement Agreement, with the modifications and additional
provisions contained herein, resolves all matters raised by APS' rate
application in a manner that is just and reasonable, and promotes the public
interest.
5. The fair value of APS' rate base is $5,054,426,000, and 5.92 percent is
a reasonable rate of return on APS' rate base.
6. The rates, charges, and conditions of service established herein are
just and reasonable.
7. APS should be directed to file revised tariffs consistent with the
Settlement Agreement and the findings contained in this Order.
VI. ORDER
IT IS THEREFORE ORDERED that the Settlement Agreement attached hereto as
Attachment A as modified herein is approved.
IT IS FURTHER ORDERED that Arizona Public Service Company is hereby
directed to file with the Commission on or before March 31, 2005, revised
schedules of rates and charges consistent with Exhibit A and the findings
herein.
IT IS FURTHER ORDERED that the revised schedules of rates and charges
shall be effective for all service rendered on and after April 1, 2005.
IT IS FURTHER ORDERED that Arizona Public Service Company shall notify its
affected customers of the revised schedules of rates and charges authorized
herein by means of an insert in its next regularly scheduled billing and by
posting on its website, in a form approved by the Commission's Utilities
Division Staff.
IT IS FURTHER ORDERED that Arizona Public Service Company shall implement
a customer education program explaining how its PSA will work and shall maintain
on its website information explaining the billing format, rates, and charges,
including up-to-date information about the PSA and current gas costs.
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IT IS FURTHER ORDERED that within 30 days of the effective date of this
Decision, Arizona Public Service Company shall submit its plan to implement its
customer education program to the Director of the Utilities Division for review
and Staff shall keep the Commission apprised of the consumer education program.
IT IS FURTHER ORDERED that within 30 days of the effective date of this
Decision, Arizona Public Service Company shall post on its website, information
explaining the billing format, rates, and charges, including up-to-date
information about the PSA and current gas costs.
IT IS FURTHER ORDERED that Arizona Public Service Company shall implement
and comply with the terms of the Settlement Agreement including filing all
reports, studies, and plans as set forth in the Settlement Agreement and as
modified herein.
IT IS FURTHER ORDERED that the parties to the Settlement Agreement shall
submit a PSA Plan of Administration that reflects the determinations in this
Decision for Commission approval within 60 days of the effective date of this
Decision.
IT IS FURTHER ORDERED that Arizona Public Service Company shall forgo any
present or future claims of stranded costs associated with any of the PWEC
assets.
IT IS FURTHER ORDERED that the Commission's Utilities Division Staff shall
schedule workshops on resource planning issues and distributed generation issues
within 90 days of the effective date of this Decision.
IT IS FURTHER ORDERED that Arizona Public Service Company shall modify
Rate E-32-TOU in accordance with the discussion and findings herein.
IT IS FURTHER ORDERED that the parties shall begin the DG workshop process
by evaluating the three recommendations made by ACA/DEAA in its post hearing
brief.
IT IS FURTHER ORDERED that in its study to be filed within 180 days of the
effective date of this Decision concerning flexibility of on- and off-peak time
periods and other time-of-use characteristics, Arizona Public Service Company
shall also include a cost-benefit analysis of Surepay, Arizona Public Service
Company's automatic payment program. The Company shall examine the cost
effectiveness of the program and explore the possibility of offering a discount
to those customers who participate in Surepay.
DECISION NO. 67744
42
DOCKET NO. E-01345A-03-0437
IT IS FURTHER ORDERED that Arizona Public Service Company shall file
additional time-of-use programs that are similar to the Time Advantage and
Combined Advantage Plans with different peak schedule(s) and tariff(s) options,
within six months of the effective date of this Decision.
IT IS FURTHER ORDERED that Arizona Public Service Company's rate design
study shall include the issues addressed in Findings of Fact No. 30, and Arizona
Public Service Company shall propose a rate design addressing these issues in
its next rate case.
IT IS FURTHER ORDERED that in order to help the state's public and charter
schools mitigate the effects of the rate increase, the DSM Working Group should
make every effort to target DSM programs to schools and to make the
implementation of DSM in schools a top priority.
IT IS FURTHER ORDERED that all DSM year-end reports filed at the
Commission by Arizona Public Service Company must be certified by an Officer of
the Company.
IT IS FURTHER ORDERED that Arizona Public Service Company shall comply
with Findings of Facts No. 33 when acquiring a generating unit or an interest in
one.
IT IS FURTHER ORDERED that the resource planning workshops shall include
consideration of the feasibility and implementation of an expanded use of
utility-scale solar electric generation integrated with existing coal fired
operations.
IT IS FURTHER ORDERED that in order to take advantage of any available
federal tax credits for renewable energy production, Arizona Public Service
Company shall issue the 100 MW RFP no later than May 15, 2005.
IT IS FURTHER ORDERED that if Arizona Public Service Company determines
that it cannot meet the goal for renewable energy resources as set forth in
Paragraph 69 of the Settlement Agreement, through in-state resources, it shall
bring its proposal to purchase out-of-state resources to Staff and obtain
Commission approval before making the out-of-state purchase.
IT IS FURTHER ORDERED that within three years of the effective date of
this Decision, Staff shall commence a procurement review of Arizona Public
Service Company's fuel, purchased power, generating practices and off-system
sales practices.
IT IS FURTHER ORDERED that the PSA shall not apply to the bills of
individuals who are
DECISION NO. 67744
43
DOCKET NO. E-01345A-03-0437
enrolled in the Company's Energy Support program.
IT IS FURTHER ORDERED that within six months of the effective date of this
Decision, Arizona Public Service Company shall develop an outreach plan that
will enable it to better inform the state's Tribes about the Company's
low-income assistance programs. The plan shall be filed with the Commission and
made available to Tribal authorities within Arizona Public Service Company's
service territory.
IT IS FURTHER ORDERED that within six months of the effective date of this
Decision, Arizona Public Service Company shall compile its SAIFI, CAIDI and
SAIDI numbers for all Tribal territories it serves and provide to the Commission
a report on proposed options for improving reliability in these areas, and
Arizona Public Service Company shall participate in any future dockets related
to enhancing reliability statewide.
DECISION NO. 67744
44
DOCKET NO. E-01345A-03-0437
IT IS FURTHER ORDERED that the Commission's Utilities Division Staff shall
initiate a rulemaking proceeding to modify A.A.C. R14-2-1618 within 120 days of
the effective date of this Decision.
IT IS FURTHER ORDERED that this Decision shall become effective
immediately.
BY ORDER OF THE ARIZONA CORPORATION COMMISSION.
/s/ Jeff Hatch-Miller /s/ William A. Mundell /s/ Marc Spitzer
- --------------------- ---------------------- ----------------
CHAIRMAN COMMISSIONER COMMISSIONER
/s/ Kristin K. Mayes
- ------------ -----------
COMMISSIONER COMMISSIONER
IN WITNESS WHEREOF, I, BRIAN C. McNEIL, Executive
Secretary of the Arizona Corporation Commission,
have hereunto set my hand and caused the official
seal of the Commission to be affixed at the
Capitol, in the City of Phoenix, this 7th day of
April, 2005.
/s/ Brian C. McNEIL
-------------------------------
BRIAN C. McNEIL
EXECUTIVE SECRETARY
DISSENT /s/ Mike Gleason
----------------
DISSENT _____________________
DECISION NO. 67744
45
SERVICE LIST FOR: ARIZONA PUBLIC SERVICE COMPANY
DOCKET NO.: E-01345A-03-0437
THOMAS L. MUMAW BILL MURPHY
KARILEE S. RAMALEY MURPHY CONSULTING
PINNACLE WEST 2422 E. PALO VERDE DRIVE
CAPITAL CORPORATION PHOENIX, ARIZONA 85016
P.O. BOX 53999, MS 8695 CONSULTANT FOR ARIZONA COGENERATION
PHOENIX, ARIZONA 85072-3999 ASSN.
KIMBERLY GROUSE JAY L. SHAPIRO
SNELL & WILMER PATRICK J. BLACK
ONE ARIZONA CENTER FENNEMORE CRAIG
400 E. VAN BUREN STREET 3003 N. CENTRAL AVENUE, SUITE 2600
PHOENIX, ARIZONA 85004-2202 PHOENIX, ARIZONA 85012
ATTORNEYS FOR ARIZONA PUBLIC SERVICE ATTORNEYS FOR PANDA GILA RIVER, L.P.
COMPANY
ROBERT W. GEAKE
C. WEBB CROCKETT ARIZONA WATER COMPANY
FENNEMORE CRAIG P.O. BOX 29006
3003 N. CENTRAL AVENUE, SUITE 2600 PHOENIX, ARIZONA 85038-9006
PHOENIX, ARIZONA 85012
ATTORNEYS FOR AECC AND PHELPS DODGE ANDREW W. BETTWY
BRIDGET A. BRANIGAN
MAJOR ALLEN G. ERICKSON SOUTHWEST GAS CORPORATION
AFCES A/ULT 5241 SPRING MOUNTAIN ROAD
139 BARNES DRIVE, SUITE 1 LAS VEGAS, NEVADA 89150
TYNDALL AFB, FLORIDA 32403-5319
ATTORNEY FOR FEA TIMOTHY M. HOGAN
ARIZONA CENTER FOR LAW
MICHAEL L. KURTZ IN THE PUBLIC INTEREST
BOEHM, KURTZ & LOWRY 202 E. MCDOWELL RD., SUITE 153
36 E. SEVENTH STREET, SUITE 2110 PHOENIX, ARIZONA 85004
CINCINNATI, OHIO 45202 ATTORNEYS FOR WESTERN RESOURCE
ATTORNEYS FOR KROGER COMPANY ADVOCATES AND
SOUTHWEST ENERGY EFFICIENCY PROJECT
SCOTT WAKEFIELD
RUCO PAUL R. MICHAUD
1110 W. WASHINGTON ST., SUITE 220 MICHAUD LAW FIRM
PHOENIX, ARIZONA 85007 23 CRIMSON HEIGHTS ROAD,
PORTLAND, CT 06480
WALTER W. MEEK ATTORNEYS FOR DOME VALLEY ENERGY
AUIA PARTNERS, LLC
2100 N. CENTRAL AVE., SUITE 210
PHOENIX, ARIZONA 85067 MARVIN S. COHEN
SACKS TIERNEY, P.A.
NICHOLAS J. ENOCH 4250 NORTH DRINKWATER BLVD.,
LUBIN & ENOCH 4TH FLOOR
349 N. FOURTH AVENUE SCOTTSDALE, AZ 85251-3693
PHOENIX, ARIZONA 85003 ATTORNEYS FOR CONSTELLATION
ATTORNEYS FOR IBEW NEWENERGY, INC., STRATEGIC ENERGY,
L.L.C.
DECISION NO. 67744
46
JEFF SCHLEGEL REBECCA C. SALISBURY
SWEEP ARIZONA REPRESENTATIVE 56TH FIGHTER WING JA
1167 W. SAMALAYUCA DRIVE 7383 N. LITCHFIELD ROAD
TUCSON, AZ 85704 LUKE AFB, AZ 85309-1540
ATTORNEY FOR FEDERAL EXECUTIVE
RAYMOND S. HEYMAN AGENCIES
LAURA SCHOELER
ROSHKA, HEYMAN & DEWULF JON POSTON
400 E. VAN BUREN, SUITE 800 AARP ELECTRIC RATE PROJECT
PHOENIX, ARIZONA 85004 6733 EAST DALE LANE
ATTORNEYS FOR UNISOURCE ENERGY CAVE CREEK, AZ 85331
SERVICES
CORALETTE HANNON
DEBORAH R. SCOTT AARP DEPARTMENT OF STATE AFFIARS
UNISOURCE ENERGY SERVICES 6705 REEDY CREEK ROAD
ONE SOUTH CHURCH STREET, SUITE 200 CHARLOTTE, NC 28215
TUCSON, ARIZONA 85702
LAWRENCE V. ROBERTSON
J. WILLIAM MOORE MUNGER CHADWICK
1144 E. JEFFERSON 333 N. WILMOT, STE. 300
PHOENIX, ARIZONA 85034 TUCSON, AZ 85711
ATTORNEY FOR KROGER CO. ATTORNEYS FOR SOUTHWESTERN POWER
GROUP II, LLC,
CYNTHIA ZWICK MESQUITE POWER AND BOWIE POWER
ARIZONA COMMUNITY ACTION ASSOCIATION STATION
2627 N. 3RD STREET, STE. TWO
PHOENIX, AZ 85004 JAY I. MOYES
MOYES STOREY
S. DAVID CHILDERS LOW & CHILDERS 1850 N. CENTRAL AVE, #1100
2999 NORTH 44TH STREET, STE. 250 PHOENIX, AZ 85004
PHOENIX, AZ 85018 ATTORNEYS FOR PPL SUNDANCE, LLC
ATTORNEY FOR ARIZONA COMPETITIVE AND PPL SOUTHWEST GENERATION
POWER ALLIANCE HOLDINGS, LLC
JAMES M. VAN NOSTRAND JESSE A. DILLON
KATHERINE MCDOWELL PPL SERVICES CORPORATION
GEORGE M. GALLOWAY TWO N. NINTH STREET
STOEL RIVES ALLENTOWN, PA 18101
900 SW FIFTH AVENUE, STE. 2600
PORTLAND, OR 97204 SEAN SEITZ
ATTORNEYS FOR ARIZONA COMPETITIVE ARISEIA
POWER ALLIANCE 5056 S. 40TH STREET, SUITE C
PHOENIX, ARIZONA 85040
GREG PATTERSON, EXECUTIVE DIRECTOR
ARIZONA COMPETITIVE POWER ALLIANCE ROBERT ANNAN
916 WEST ADAMS, STE. 3 ANNAN GROUP
PHOENIX, AZ 85007 6605 E. EVENING GLOW DRIVE
PHOENIX, AZ 85262
MICHAEL A. CURTIS
MARTINEZ & CURTIS, P.C. DOUGLAS V. FANT
2712 N. SEVENTH STREET AZCOGEN ASSOCIATION
PHOENIX, AZ 85006-1090 80 E. COLUMBUS
ATTORNEYS FOR TOWN OF WICKENBURG PHOENIX, AZ 85012
CYNTHIA ZWICK
ARIZONA COMMUNITY ACTION ASSOCIATION
224 SOUTH THIRD AVE
YUMA, AZ 85364
DECISION NO. 67744
47
CHRISTOPHER KEMPLEY, CHIEF COUNSEL ERNEST G. JOHNSON, DIRECTOR
LEGAL DIVISION UTILITIES DIVISION
ARIZONA CORPORATION COMMISSION ARIZONA CORPORATION COMMISSION
1200 WEST WASHINGTON STREET 1200 WEST WASHINGTON STREET
PHOENIX, AZ 85007 PHOENIX, AZ 85007
DECISION NO. 67744
48
DOCKET NO. E-01345A-03-0437
ATTACHMENT A
PROPOSED SETTLEMENT
OF
DOCKET NO. E-01345A-03-0437
ARIZONA PUBLIC SERVICE
COMPANY
REQUEST FOR RATE
ADJUSTMENT
DECISION NO. 67744