20190801PAC to Staff Attach 5-2.pdf

llllllllllllllllIIIIIIIIll IIIoJIIoIIWoJIIoJ 41 M ll6llll0)H I
BEFORE THE ARIZONA CORPORATION COMMISSION
Arizona Corporation Commission
DOCKETED
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2 COMMISSIONERS
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TOM FORESE - Chairman
BOB BURNS
DOUG LITTLE
ANDY TOBIN
BOYD w. DUNN
AUG 1 8 2011
DOCKETEDB
DOCKET NO. E-01345A-16-0036
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IN THE MATTER OF THE APPLICATION OF
ARIZONA 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 REASONABLE RATE OF RETURN
THEREON, TO APPROVE RATE SCHEDULES
DESIGNED TO DEVELOP SUCH RETURN.
DOCKET no. E-01345A-16-0123ll
DECISION no.7629512
IN THE MATTER OF FUEL AND PURCHASED
POWER PROCUREMENT AUDITS FOR ARIZONA
PUBLIC SERVICE COMPANY.
OPINION AND ORDER13
DATE OF HEARING:14 October 20, 2016 and January l 1, 2017 (Procedural
Conferences), April 20, 2017 (Pre-Hearing Conference),
April 24, 25, 26, 27, 28, May 1 and 2.15
PLACE OF HEARING:Phoenix, Arizona16
PUBLIC COMMENT HEARINGS:17
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March 15, 2017 (Douglas, Arizona), March 22, 2017
(Phoenix, Arizona),March 29, 2017 (Clarkdale,
Arizona); April 3, 2017 (Flagstaff, Arizona); April 20,
2017 (Yuma, Arizona)
19 ADMINISTRATIVE LAW JUDGE:Teena .lillian
20 APPEARANCES:
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Mr. Thomas Loquvam, Mr. Thomas Mum aw, Ms.
Melissa Krueger, Ms. Amanda Ho, PINNACLE WEST
CAPITAL CORPORATION, and Mr. Ray Herman,
SNELL & WILMER, LLP on behalf of Arizona Public
Service Company,
23 Ms. Meghan H. Grabel, OSBORN MALEDON, on
behalf of Arizona Investment Council,24
25 Mr. Nicholas J. Enoch, LUBIN & ENOCH, PC, on behalf
of Local Unions 387 and 769 of IBEW, AFL-CIO,
26 Mr. Timothy J. Sabo, SNELL & WILMER, LLP, on
behalf of REP America d/b/a ConservAmerica,27
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S:\TJibilian\APS20l6Rates\l60036o&o.Amended.docx l
DOCKET NO. E-01345A-I6-0036 ET AL.
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Mr. Garry D. Hays, LAW OFFICES OF GARRY D.
HAYS, PC, on behalf of Arizona Solar Deployment
Alliance,
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Mr. Timothy Hogan,ARIZONA CENTER FOR LAW
IN THE PUBLIC INTEREST, on behalf of Arizona
School Boards Association, Arizona Association of
School Business Officials, Arizona Community Action
Association,Cynthia Zwick,Western Resource
Advocates, Southwest Energy Efficiency Project and
Vote Solar,
Osuala,Mr.David Bender and Ms.Chinyere
EARTHJUSTICE, on behalf of Vote Solar,
Mr. Giancarlo G. Estrada, KAMPER ESTRADA, LLP,
on behalf of Solar Energy Industries Association,
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Mr. Court S. Rich, ROSE LAW GROUP, PC, on behalf
of Energy Freedom Coalition of America,
ll Mr. Craig A. Marks, CRAIG A. MARKS, PLLC, on
bchalfofArizona Utility Ratepayer Alliancc,
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Mr. Kurt J. Boehm, BOEHM KURTZ & LOWRY, on
behalf of The Kroger Co.,
14 Mr. Scott s. Wakefield, HEINTON & CURRY, PLLC,
on behalf of Wal-Mart Stores, Inc. and Sam's West, Inc.,
Ms. Brittany L. DeLorenzo, on behalf of IO DATA
CENTERS, LLC;
Mr. Patrick J. Black, FENNEMORE CRAIG, pp, on
behalf of Freeport Minerals Corporation and Arizonans
for Electric Choice and Competition,
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Mr. Lawrence V. Robertson, Jr., on behalf of Calpine
Energy Solutions, LLC, Constellation New Energy, Inc.,
and Direct Energy Business, LLC,
Mr. Greg Patterson, MUNGER CHADWICK, on behalf
of Arizona Competitive Power Alliance,
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Mr. Jason Moyes, MOYES SELLERS & HENDRICKS,
LTD, on behalf of Electrical District Number Eight and
McMullen Valley Water Conservation & Drainage
District,
Harquahala Valley Power District and Maricopa County
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Mr.Albert H.Acken,RYLEY CARLOCK &
APPLEWHITE, on behalf of Electrical District Number
Six, Pinal County, Arizona, Electrical District Number
Seven of the County of Maricopa, State of Arizona,
Agiila Imgation District Tonopah Irrigation District
Municipal Water Conservation District Number One,
DECISION no.2 76295
DOCKET no. E-01345A-16-0036 ET AL.
Capt. Lanny L. Zieman and Capt. Natalie A. Cepak, on
behalf of Federal Executive Agencies,
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Mr. John B Coffman, JOHN B. COFFMAN, LLC, and
Ms. Ann-Marie Anderson, WRIGHT WELKER &
PAUOLE, PLC, on behalf of AARP,
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Mr. Greg Eisert, on behalf of Sun City Homeowners
Association,
Mr. Al Gervenack, on behalf of Property Owners &
Residents Association,
Mr. Richard Gayer, pro se, and
Mr. Warren Woodward, pro se,
Mr. Daniel W. Pozefsky, on behalf of the Residential
Utility Consumer Office,
Ms. Maureen A. Scott, Senior Staff Counsel, Mr. Wesley
C. Van Cleve, and Mr. Charles H. Hains, Staff Attomeys,
Legal Division, on behalf of the Utilities Division of the
Arizona Corporation Commission.
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DECISION no.3 76295
DOCKET NO. E-01345A-16-0036 ET AL.
TABLE OF CONTENTSl
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BACKGROUND
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1.
II.
III.
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b.
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d.
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v.
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xiv.15
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PROCEDURAL 4
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PARTIAL SETTLEMENT 7
Overview 7
Settling Parties 7
Non-Settling Parties 7
Bifurcation of Section 30 of the Settlement Agreement........................... 7
Procedural Opposition to Settlement Agreement Process 8
ED8/McMullen 8
Mr. Gayer 9
Mr.10
IBEW 14
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Vote Solar 15
Freeport / AECC / Calpine / CNE / Direct Energy...................... 16
Staff 18
Resolution 20
xv.
xvi.
xvii.
SUBSTANTIVELY UNDISPUTED SETTLEMENT AGREEMENTIv.18
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a.
b.
c.
d.21
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AG
Fair Value Rate Base and Revenue Requirement.................................... 21
Cost of Capital 22
Base Fuel Rate 22
Bill Impact 22
Rate Case Stability 22
Four Corners Units 4 and 22
Ocotillo Modernization Project 23
Property Tax Rate Deferral 23
Tax Expense Adjustor 23
Other Significant Provisions 23
Rate Design for Low Income Customers 23
Rate Design for DG 24
-X Program 27
Power Procurement Audit 29
c.
f.
g.
h.
i.
j.
k.
I.
m.
n.
SUBSTANTIVELY DISPUTED SETTLEMENT AGREEMENT ISSUES 30
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76295iDECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
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111.
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Use of Unspent DSMAC Funds 30
Staff 31
Resolution 32
Mr. Gayer 32
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vi.Staff 34
vii.Resolution 34
Disputed Rate Design Issues 35
Basic Service Charges 35
Mr.39
ConservAmerica.................................................................. 42
Vote Solar 43
Staff 45
Resolution 46
Choice of Rate Plan / 90 Day Trial 47
Mr. Gayer 48
Mr.49
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Staff 52
10.Resolution 53
Time Of Use Hours 55
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ii DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
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VII.
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d.
Vote Solar 58
Staff 59
Resolution 59
ADOPTION OF THE SETTLEMENT AGREEMENT 60
INCENTIVIZING BATTERY STORAGE FOR E-32 L CUSTOMERS 60
APS's E-32 L and E-32 TOU 61
EFCA's Proposed Optional E-32 63
APS's Alternative Proposal for an Up-Front Incentive
("E-32 UFl") Pilot 71
EFCA's Proposed Modifications to its Optional E-32 Rate Proposal.... 75
Resolution 78e.
am. STORAGE TO BE INCLUDED IN ANALYSES OF NEW
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Determinations12
RESOURCE OPTIONS 80
WATER ENERGY 81
l I FINDINGS OF FACT 81
Procedural 81
13 CONCLUSIONS OF LAW 107
107ORDER
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DECISION no.iii 76295
DOCKET no. E-01345A-16-0036 ET AL.
l BY THE COMMISSION:
2 PROCEDURAL HISTORYI.
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On June 1, 2016, Arizona Public Service Company ("APS" or "Company") filed with the
Arizona Corporation Commission ("Commission") the above-captioned Rate Case Application
("Applieation").' In the Application, which is based on a test year ending December 31, 2015, APS
sought a $165.9 million net increase in base rates, changes in some of its adjustor mechanisms,
establishment of a mandatory new three-part demand-based rate design for residential and small
commercial rate design, reduction of on-peak time-of-use hours, and grandfathering of existing solar
customers while modifying net metering arrangements for new solar customers.
On July 22, 2016, a Rate Case Procedural Order was issued setting the procedural schedule and
associated procedural deadlines for the Application, and indicating that pursuant to Commission
Decision No. 75047 (April 30, 2015), issues related to APS's proposed Automated Meter Opt-Out
Service Schedule would also be addressed in this proceeding.
On August l, 2016, a Procedural Order was issued granting a Motion by the Commission's
Utilities Division ("Staff') to consolidate Docket No. E-ol 345A-16-0123 with the Application.
Parties to this docket are APS, the Commission's Utilities Division ("Staff'), Richard Gayer,
Patricia Ferré, Warren Woodward, IO Data Centers, LLC ("IO"), Freeport Minerals Corporation
("Freeport"), Arizonans for Electric Choice and Competition ("AECC"), Sun City Home Owners
Association ("SCI-IOA"), Western Resource Advocates ("WRA"), Arizona Investment Council
("AIC"), Arizona Utility Ratepayer Alliance ("AURA"), Property Owners and Residents Association
of Sun City West ("PORA"), Arizona Solar Energy Industries Association ("AriSEIA"), Arizona
School Boards Association ("ASBA"), Arizona Association of School Business Officials ("AASBO"),
Cynthia Zwick (in her personal capacity), Arizona Community Action Association ("ACAA"),
Southwest Energy Efficiency Project ("SWEEP"), the Residential Utility Consumer Office ("RUCO"),
Vote Solar, Electrical District Number Eight and McMullen Valley Water Conservation & Drainage
District (collectively, "ED8/McMullen"), The Kroger Co. ("Kroger"), Tucson Electric Power
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' On January 29, 2016, APS filed its Notice of Intent to File a Rate Case Application and Request to Open Docket.28
762954DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
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Company ("TEP"), Pima County, Solar Energy Industries Association ("SEIA"), the Energy Freedom
Sam's West, Inc.Coalition of America ("EFCA"), Wal-Mart Stores,
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Inc. and (collectively,
"Walmart"), Local Unions 387 and 769 of the International Brotherhood of Electrical Workers, AFL-
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CIO (collectively, "the IBEW Locals"), Calcine Energy Solutions LLC ("C alpine")(formerly Noble
Energy Solutions, LLC), the Arizona Competitive Power Alliance ("the Alliance"), Electrical District
Number Six, Pinal County, Arizona ("ED 6"), Electrical District Numbcr Seven of the County of
Maricopa, State of Arizona ("ED7"), Aquila Irrigation District ("AID"), Tonopah Irrigation District
("TID"), Harquahala Valley Power District ("HVPD"), and Maricopa County Municipal Watcr
Conservation District Number One ("MWD") (collectively, "Districts"), the Federal Executive
Agencies ("FEA"), Constellation New Energy, Inc. ("CNE"), Direct Energy Business, LLC ("Direct
Energy"), AARP, the City of Sedona ("Sedona"), Arizona Solar Deployment Alliance ("ASDA"), the
City of Coolidge ("Coolidge"), REP Americad/b/aConservAmerica ("ConservAmerica"), and Granite
Creek Power & Gas and Granite Creek Farms LLC (collectively, "Granite Creek").
The full procedural history of this proceeding is set forth in the Findings of Fact herein.
On May 17, 2017, APS, AIC, the IBEW Locals, ConservAmerica, ASDA, Vote Solar, EFCA,
SEIA, AriSEIA, AURA,Freeport, AECC, Calpine, CNE,Direct Energy,Walmart, FEA,
ED8/McMullen, the Districts, ACAA, SWEEP, AARP, Mr. Gayer, Mr. Woodward, RUCO, and Staff
filed Initial Closing Briefs.2
On June l, 2017, APS, AIC, the IBEW Locals, ConservAmerica, EFCA, SEIA, Freeport,
20 AECC, Calpine, CNE, Direct Energy, SWEEP, Mr. Woodward, and Staff filed Reply Closing Briefs.3
Numerous public comments were filed.
Following the parties' filings of Initial Closing Briefs and Reply Closing Briefs, this matter was
taken under advisement by the Administrative Law Judge pending the submission of a Recommended
Opinion and Order for the consideration of the Commission.
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2 Freeport AECC Calcine, CNE, and Direct Energy jointly filed an Initial Closing Brief. Mr. Gayer filed his Initial Closing
Brief on May 15 2017.
3 Freeport, AECC, Calpine, CNE, and Direct Energy jointly tiled a Reply Closing Brief. On June l, 2017, RUCO filed
notice that it would not be filing a Reply Closing Briefs
76295DECISION no.5
DOCKET NO. E-01345A-16-0036 ET AL.
l ll.BACKGROUND
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APS, which is the largest subsidiary of Pinnacle West Capital Corporation ("Pinnacle West"),
is the largest electric provider in Arizona, and serves more than 1.2 million customers, in l l of
Arizona's 15 counties. APS employs more than 6,300 employees, including employees at jointly-
owned generating facilities for which APS serves as the generating facilities manager. In addition to
the Palo Verde Nuclear Generating Station, which APS co-owns and operates, APS owns and operates
six natural gas plants, two coal-fired plants, and renewable energy power generating facilities. APS
currently generates approximately l l percent of its electricity from more than 1,200 MW of renewable
resources. APS also owns and operates more than 35,000 miles of transmission and distribution lines
to deliver energy to its customers.4
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APS's current rates and charges were authorized by Decision No. 73183 (May 24, 2012) in
Docket No. E-0l 345A-l 1-0224. Among other things, Decision No. 73 183 approved a Lost Fixed Cost
Recovery Mechanism ("LFCR") which allows for the recovery of lost fixed costs, as measured by
revenue per kph, associated with energy efficiency and distributed generation ("DG").
On December 3, 2013, the Commission issued Decision No. 74202 in Docket No. E-01345A-
13-0248, which acted upon an Application by APS to begin to address, in the LFCR, a cost shift from
DG customers to non-DG customers.
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On December 23, 2014, the Commission issued Decision No. 74876, which authorized the Four
19 Corners Rate Rider as contemplated by Decision No. 73183.5
On January 3, 20]7, the Commission issued Decision No. 75859 in the generic Docket No. E-
00000J-l4-0023, In the Matter of the Commission's Investigation of the Value and Cost of Distributed
Generation, which established methodologies to be used in electric utility rate cases before the
Commission for calculating the value of DG exports. Decision No. 75859 was amended by Decision
No. 75932 (January 13, 2017) to establish parameters for grand fathering of DG customers, and clarified
by Decision No. 76149 (June 22, 2017) regarding publication of the spreadsheet model to be used for
the Resource Comparison Methodology ("RCP") in rate cases as ordered by Decision No. 75859.
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4 Hearing Exhibit APS-14 (Direct Testimony of Daniel Froetscher) at 3.
5 Decision No. 74978 (February 9, 20l 5)(Order Granting Rehearing) amended Decision No. 74876 to add two additional
Findings of Fact.
DECISION no.6 76295
DOCKET NO. E-01345A-16-0036 ET AL.
l PARTIAL SETTLEMENT AGREEMENTIII.
2 Overview
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a.
On March l, 20]7, a Settlement Term Sheet was filed in the case, indicating that many, but not
all, parties to this case were in support of a Settlement Agreement, and outlining the terms. On March
27, 2017, the Settlement Agreement was filed. A copy of the signed Settlement Agreement, which was
admitted into evidence during the hearing in this proceeding as Hearing Exhibit A-29, is attached hereto
7 as Exhibit A.
8 Settling Parties
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b.
The parties to the Settlement Agreement are APS, AIC, the IBEW Locals, ConservAmerica,
ASDA, Vote Solar, EFCA, SEIA, AriSE1A, AURA, Freeport, AECC, Direct Energy, CNE, Calpine,
the Alliance, Walmart, Kroger, Granite Creek, FEA, Coolidge, WRA, ASBA, AASBO, SCHOA,
PORA, ACAA, RUCO, and Staff ("Settling Parties").
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Parties who did not sign the Settlement Agreement are Richard Gayer, Patricia Ferré, Warren
Woodward, IO, Cynthia Zwick (in her personal capacity), SWEEP, ED8/McMullen, the Districts,
AARP, and Sedona."
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d.Bifurcation of Section 30 of the Settlement Agreement
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Pursuant to Commission Decision No. 74057 (April 30, 2015) and the Rate Case Procedural
Order in these dockets, issues related to APS's Proposed Automated Meter Opt-Out Service Schedule
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were addressed in this proceeding.
Section 30 of the Settlement Agreement provides:
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30.1
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The AMI Opt-Out program will be approved as proposed by APS except
the fees will be changed to reflect an upfront fee of $50 to change out a
standard meter for a non-standard meter and monthly fee of $5.Sec
Service Schedule 1, attached as Appendix M.
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30.2 Changes to Schedule l are attached in Appendix M.
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" IO appeared through counsel at the hearing but did not otherwise participate in the hearing or post-hearing briefing process
as a party. Patricia Ferré, Cynthia Zwick, and Sedona who did not sign the Settlement Agreement, did not participate in
the hearing or posthearing briefing process as parties.
76295DECISION no.7
DOCKET no. E-0I 345A-16-0036 ET AL.
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The issues surrounding the Settlement Agreement Proposed AMI Opt-Out program were
heavily litigated in this proceeding. These issues will be bifurcated from this Decision, and will be
addressed in a forthcoming Decision.
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Procedural Opposition to Settlement Agreement/ Process
ED8/McMulleni.
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ED8/McMullen states that it intervened in this case "in hopes of raising questions about the
reruning trend of settled rate cases that have become almost automatic before the Arizona Corporation
Commission, at least when it comes to APS."7 ED8/McMullen assert that settlement agreements do
not provide ratepayers assurances that they are not being taken advantage of by a monopoly.8
ED8/McMullen are critical of the fact that APS opened settlement negotiations by presenting a
compromise offer, and of Staffs and RUCO's testimony comparing the revenue requirement in the
settlement agreement to the revenue requirement APS proposed in the Application.°
ED8/McMullen are critical of RUCO's position that the Settlement Agreement terms would
provide benefits that would not be possible in a litigated case. ED8/McMullen opine that it is "wholly
presumptuous to assert that a fully litigated case and subsequent decision by the Commissioners would
be detrimental to the ratepayers when compared to the settlement agreement."'° ED8/McMullen argue
that none of the parties supporting the Settlement Agreement addressed the validity of the relief APS
requested in its Application, defended APS's need for the relief the Settlement Agreement would
provide, or explained the consequences of denying APS a rate increase." ED8/McMullen propose that
"the Settlement Agreement be rejected and this matter be opened for a full evidentiary proceeding on
the merits."l2
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7ED8/McMullen Initial Closing Brief("Br.")at 6.
8 ld.at 7.
<1 Although ED8/McMullen filed post-hearing briefs, they raised no objections to specific Settlement Agreement revenue
requirement issues and offered no substantive revenue requirement evidence.
10 ED8/McMullen Br. at l l.
11 ED8/McMullen Br. at 9, 11.
12 ED8/McMullen Br. at 11.
762958DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
l ii.Districts
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The Districts contend that "the proposed non-unanimous settlement is the flawed result of a
flawed process," that its terms will require ratepayers to "pay hundreds of millions of dollars to provide
a windfall to APS and to resolve APS's battles with EFCA," and that "[m]eanwhile the District's
farmers are losing options for affordable power."'3 The Districts state that their wholesale contracts
with APS index their contractual rate to the E-34 retail rate, and contend that the rising rates are
unaffordable for the farmers the Districts serve.'4 The Districts are concerned that wholesale power
from APS will not be a viable alternative to the power they currently procure from the Navajo
Generating Station ("NGS").'5
The Districts argue that Rule 408 of the Arizona Rules of Evidence ("Rule 408") does not
protect the settling parties from being forced to answer questions regarding the settlement process,'°
that exclusion of"evidence regarding the settlement process's many flaws" was prejudicial error,'7 and
that "[e]videncc regarding the settlement process must be allowed in an evidentiary hearing that is
being held solely for the purpose of evaluating whether the settlement is in the public interest."'l' The
Districts claim that "the settlement process failed to provide for a meaningful opportunity for all, and
APS cannot meet its burden that the non-unanimous settlement agreement is in the public's interest."'°
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Mr. Gayer
Mr. Gayer asserts that "the entire settlement process and resulting agreement (APS 29) should
be set aside and this entire rate case should be litigatedab initi0."20 Mr. Gayer submits that Rule 408
is not a bar to use of settlement discussions when they are offered for a relevant purpose other than
proving the validity of a claim or its amount.2' Mr. Gayer believes that the Decision in this matter
should reflect that the settlement negotiations and the Settlement Agreement constitute serious
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13 Districts Br. at 2.
14 ld. at 5. Although the Districts filed post-hearing briefs, they raised no objections to specific Settlement Agreement
revenue requirement issues, and offered no substantive revenue requirement evidence.
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"' Districts Br. at 4.
17 Id. at 5.
18 Districts Br. at 4.
"9 Id. at 5.
20 Gayer Br.at 4. See also Gayer Reply Br. at 8.
21 Gayer Br. at 4. citingto Bradshaw v. State Farm Mutual Auto Ins. Co., 157 Ariz. 411, 420 (I988).
9 DECISION no.76295
DOCKET NO. E-01345A-16-0036 ET AL.
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violations of procedural due process, so that in the future there will be no such negotiations or
agreements and that all rate cases will be fully litigated openly in the public."
3 Mr. Woodwardiv.
4 Mr. Woodward believes the settlement process was "fatally flawed,"23 and supports the
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arguments of ED8/McMullen, the Districts, and Mr. Gayer against the Settlement Agreement." Mr.
Woodward is critical ofRUCO'sand Staff's support of the Settlement Agreement, claiming that RUCO
is out of touch with and does not represent residential ratepayers,25 that Staff is biased toward Aps,2'*
and that Staffs characterization of the settlement process as inclusive and transparent is incorrect."
Mr. Woodward is generally critical ofAPS's, and of all parties' defense of the Settlement Agrccmcnt,28
contending that evidence he brought to the settlement discussions, and his initial objections to the
settlement process itself, were ignored." Mr. Woodward claims that the Settlement Agreement is not
in the public interest,3° and must be set aside in order to obtain a just outcome."
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APS responds that the criticisms of the settlement process are not supported by the evidence,
and that they reflect a misunderstanding of the role of settlements in Commission proceedings, and of
the safeguards in the Commission's process that protect the public interest." APS asserts that the
parties critical of the settlement process fail to consider that settling disputed issues generally promotes
good public policy, and fail to acknowledge the benefits the Settlement Agreement provides to
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22 Gayer Br. at 15 and Reply Br. at 9.
23 Woodward Br. at 40, citing to Hearing Exhibit Woodward-6 (Direct Testimony of Warren Woodward on the Settlement
Agreement) and Hearing Exhibit Woodward-7 (Rebuttal Testimony of Warren Woodward on the Settlement Agreement)
Woodward Reply Br. at 23, citing to Hearing Exhibit Woodward-6 (Direct Testimony of Warren Woodward on the
Settlement Agreement) at Sections III.E, III.F and to Clearing Exhibit Woodward-7 (Rebuttal Testimony of Warren
Woodward on the Settlement Agreement) at Section VI.
24 Woodward Br. at 40.
25ld. at 39, 40, citing to Woodward-7 (Rebuttal Testimony of Warren Woodward on the Settlement Agreement) at Section
IlI.B and Woodward Reply Br. at 22,.
26 Woodward Br. at 40, citing to Tr. at 1268, 1275-76, and 1304 (Staff witness Abinah).
27 Woodward Br. at 3034.
28Woodward Reply Br. at 22-28. For example, Mr. Woodward claims: "Indeed, the false notion that a fair consideration
has occurred by an enlightened majority runs throughout the arguments of those parties in support of the Settlement
Agreement." Woodward Reply Br. at 26.
zo Woodward Reply Br. at 28-30.
30 Id. at 28 32.
31 Woodward Reply Br. at 27.
32 APS Br. at 52, 55.
DECISION no.10 76295
DOCKET NO. E-01345A-16-0036 ET AL.
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customers." APS points out that participation in the settlement discussions, which were led by the
Director of the Commission's Utilities Division, was such that the discussions had to be held in the
hearing room to accommodate all the participants." APS states that all parties were allowed to
participate in the settlement discussions, and that despite the divergent interests of the participants, the
parties engaged in open, transparent, and arm's length negotiations over the nearly three month process,
that the process was fair, and the outcome was just, reasonable, and in the public interest." APS further
states that the testimony in this case shows that "all parties were provided the opportunity to raise and
discuss any issues they so chose during the Settlement negotiations, and had the opportunity to present
their evidence at the hearing."3° In particular, APS points to the testimony of non-signatory party
witnesses that the settlement process was conducted in a fair manner, and that parties had the
opportunity to be heard and have their issues fairly considered."
APS contends that arguments in opposition to the structuring of the settlement process, and
even the existence of a settlement process, should not be afforded weight because: l) while it was
necessary to initially bifurcate discussions into revenue requirement and rate design, there was no
separate revenue requirement settlement, 2) complaints about the settlement process appear to be
colored by dissatisfaction with the settlement outcome, and 3) in a large case with 40 parties, "[t]here
is nothing procedurally or substantively improper about one-offmectings that don't involve all parties,
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as APS Reply Br. at l.
34 APS Br. at 52-53.
35 ld. at 53, referring to Hearing Exhibit VoteSolar-l (Direct Testimony of Briana Kobor on the Settlement Agreement);
Hearing Exhibit Walmart-5 (Direct Testimony of Chris Hendrix on the Settlement Agreement), Hearing Exhibit AURA-3
at 2 (Direct Testimony of Patrick Quinn on the Settlement Agreement) Hearing Exhibit RUCO-6 at 2 (Direct Testimony
of David Tenney on the Settlement Agreement) Hearing Exhibit ACAA-l at 3 (Direct Testimony of Cynthia Zwick on the
Settlement Agreement), Hearing Exhibit AIC-5 at 2 (Direct Testimony of Gary Yaquinto on the Settlement Agreement),
Tr. at 109495 (RUCO witness Tenney), Tr. at 1281-82, 1266, 1274 (Staff witness Elijah Abinah).
36 APS Br. at 55, citing to Tr. at 45 (Kroger counsel Boehm), Tr. at 74 (Staff counsel Van Cleve), Tr. at 184-185 (APS
witness Lockwood), Tr. at 722 (AARP witness Coffman) Tr. at 906 (Gayer), Tr. 988 (Woodward) Tr. at l 164 (SWEEP
witness Schlegel). APS also references Hearing Exhibit APSX at 3-4 (Direct Testimony of Barbara Lockwood on the
Settlement Agreement),Hearing Exhibit AARPl at 3 (Direct Testimony of John B. Coffman on the Settlement
Agreement), Hearing Exhibit ACAA-l at 3 (Direct Testimony of Cynthia Zwick on the Settlement Agreement) Hearing
Exhibit AIC-5 at 2 (Direct Testimony of Gary Yaquinto on the Settlement Agreement) Hearing Exhibit AURA~3 at 2
(Direct Testimony of Patrick Quinn on the Settlement Agreement) Hearing Exhibit ConservAmerica-3 at 1-2 (Direct
Testimony of Paul Walker on the Settlement Agreement), Hearing Exhibit RUCO-6 at 2 (Direct Testimony of David Tenney
on the Settlement Agreement), Hearing Exhibit VoteSolar2 at l (Direct Testimony of Briana Kobor on the Settlement
Agreement).
37 APS Br. at 5354, citing to Hearing Exhibit AARP-l (Direct Testimony of John B. Coffman on the Settlement
Agreement) Hearing Exhibit SWEEP3 (Direct Testimony of Jeff Schlegel on the Settlement Agreement), and Tr. at 575-
76 (ED8/McMullen witness Jim Downing).
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
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or meetings among smaller subsets of parties with unique interests."38 APS asserts that settlements are
not open meetings, but are confidential negotiations between litigants, with the outcome of the
negotiations being made public and fully vetted at an evidentiary hearing."
In response to the Districts' argument that the Settlement Agreement terms benefitting EFCA
render the Settlement Agreement flawed and not of benefit to customers, APS points out that EFCA is
only one party out of 29 Settling Parties with diverse interests, and that the agreement among these
parties represents compromise and balance among all those interests, not an imbalance toward only
one party's interests.4°APS asserts that the diversity of the Settling Parties, which include
representatives of several customer groups, including residential, limited-income, retiree, public
schools and school business officials, federal agencies, and large industrial and commercial customers,
is evidence in itself that the Settlement Agreement is in the public interest.'*' APS also points to the
benefit of ERICA's agreement with the Signing Parties in this case, as the agreement has opened the
door to collaboration in the future, as opposed to continual litigation of disputed issues surrounding the
integration of DG."
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APS states that with the exception of the Districts, all parties who did not sign the Settlement
Agreement, but participated in the evidentiary hearing, acknowledged that they had ample opportunity
to participate in the settlement process and had a full and fair opportunity to present their case in the
evidentiary hearing." APS points out that the Districts acknowledged that they had the opportunity to
present evidence in this case, and that they did not introduce testimony, by choice.44 APS contends
that after "declining to cross examine witnesses on substantive Settlement terms, and choosing to not
put on their own evidence challenging the Settlement, the Districts cannot now complain that they have
been shut out of the process."45
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as APS Br. at 54-55.
39 Id. at 55.
40 APS Reply Br. at I.
41 ld. at 2.
42 APS Reply Br. at l.
43 Id. at 2, citing to Tr. at 722 (AARP witness Coffman), Tr. at 906 (Gayer); Tr. at 988 (Woodward), Tr. at 1164 (SWEEP
witness Schlegel), and Tr. at 575-76 (ED8/McMullen witness Downing).
44 APS Br. at 55, APS Reply Br. at 2-3, citing to Tr. at 1314 (Albert Acken, counsel for the Districts).
45 APS Reply Br. at 3.
12 DECISION no.76295
DOCKET NO. E-01345A-16-0036 ET AL.
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APS addresses the Districts' arguments appearing in their Initial Closing Brief that APS's rates
are unaffordable to the farmers who are the Districts' retail customers.4" APS states that the long-term
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wholesale power contracts between APS and the Districts are the result of negotiations between the
parties, who agreed to the incorporation of APS's general service E-34 rate, and also include agreed-
upon negotiated charges for transmission and distribution which are subject exclusively to Federal
Energy Regulatory Commission ("FERC") jurisdiction." Moreover, APS argues that over the last few
years, the Districts have purchased little or no power from Aps,48 that the Districts admittedly have
other power purchasing options, that the Districts have access to Federal preference power, and that
the Districts are therefore not "captive" customers ofAps.4° APS is critical of the Districts' arguments
regarding whether APS power would be an economic alternative if the NGS closes, stating that the
Districts fail to acknowledge that they have other power options, including Federal preference power,
self-generation, other utilities, or market purchases, and fail to explain why they should pay rates lower
than cost, to be subsidized by other customers.5°
14 AICvi.
15 AIC believes that any criticism of the settlement process is unfounded.5' AIC states that the
16 Settlement Agreement is the result of a difficult but inclusive and collaborative effort, that AIC and
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other parties were provided advance notice of meetings for the discussion of the possibility of
settlement, that parties were afforded ample opportunity to participate in the discussions, and that to
aid discussions, term sheets and other supplemental materials were distributed prior to the meetings to
allow parties to follow the progress of the settlement discussions."AIC states that no party got
everything it wanted, and that the terms of the Settlement Agreement demonstrate that the settlement
was a compromise involving a collaborative effort of give and take."
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46 Id. al 35.
47 APS Reply Br. at 4.
48 ld., citing to Tr. at 579 (ED8/McMullen witness Downing).
49 APS Reply Br. at 4, citing to Districts Reply Br. at 5 and Tr. at 579 (ED8/McMullen witness Downing).
50 APS Reply Br. at 45.
51AIC Br.at 12.
52Id.
53 Id.
7629513DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
l vii.IBEW Locals
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The IBEW Locals state that the Settlement Agreement "was negotiated in an open and
transparent process, is supported by the evidence, and is in the public interest."54 The IBEW Locals
state that they have a long history of negotiating differences with APS, and that the settlement process
in this case involved "the exact same type of give and take exercise that transpired between the parties
to reach the Settlement Agreement."55 The IBEW Locals state that all interveners were invited to
participate in settlement discussions and were always notified of settlement meetings, term sheets and
handouts were distributed in advance, each party had an opportunity to be present and heard, there was
no attempt by any party to intimidate any other party into settlement, and while not all of the non-
signatories' issues were resolved in the Settlement Agreement, neither were they ignored, and any
issues not addressed in the Settlement Agreement were the subject of serious bargaining among
capable, knowledgeable parties.5° The IBEW Locals find the fact that only five of the 40 intervening
parties filed testimony in opposition to the Settlement Agreement, while 29 signed on, should lend
great weight to demonstrating that the Settlement Agreement is just, reasonable, and in the public
interest.57
16 viii.ConservAmerica
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ConservAmerica asserts that the settlement process was fair and appropriate," that all the
parties, which represent many divergent interests and differing perspectives, had a chance to
participate, and many did, that the process was open and inclusive, and that all viewpoints were heard.5°
ConservAmerica states that ED8/McMullen received a full evidentiary hearing on the merits,
and that ED8/McMullen were free to cross-examine witnesses on all the pre-settlement testimony that
was admitted into the record, and to raise any specific objections to the settlement revenue requirement,
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54 IBEW Locals Br. at 2.
55 Id. at 3 (emphasis in original).
56 IBEW Locals Reply Br. at 3.
57 Id.
58 ConsewAmerica Reply Br. at l.
59 ConservAmerica Br. at l, citing to Hearing Exhibit ConservAmerica3 (Direct Testimony of Paul Walker on the
Settlement Agreement) at 12.
76295DECISION no.14
DOCKET NO. E-01345A-16-0036 ET AL.
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but chose not to do s0.60 ConservAmerica also points out that ED8/McMullen chose not to offer any
substantive testimony of their own on revenue requirement or on any other issue."'
response to the Districts' arguments that the settlement process suffered from unequal
bargaining power, ConservAmerica states that many parties filed extensive revenue requirement
testimony and were well represented by counsel, and that collectively, the parties have resources equal
to or greater than Aps.°2 ConservAmerica points out that the Districts offered no testimony in support
of their allegation of unequal bargaining power tainting the settlement process, that the Districts are
represented by one of the largest law firms in Arizona, and that as utilities, the Districts had the
knowledge and resources to produce revenue requirement testimony, if they had chosen to do so.63
ConservAmerica responds to Mr. Woodward's allegations regarding RUCO and Staff as being
"without any proof, much less the heavy proof needed to impeach the credibility of the public servants
in Staff and Ruco."°4 ConservAmerica states that while it disagrees with Mr. Woodward on many
things, it believes he is acting on his sincere beliefs, and that the same courtesy should be accorded
other parties to this case."5
15 ASDAix.
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ASDA states that the settlement process was fair and inclusive, and that the resulting Settlement
Agreement is in the public interest.6"' ASDA requests that the Commission approve the Settlement
Agreement without modification.°7
19 Vote Solar
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x.
Vote Solar states that "[l]ike all parties, Vote Solar had an opportunity to actively participate in
settlement negotiations.""8 Vote Solar "worked with APS, Staff and other parties to reach a
compromise and contributed to drafting settlement terms that protect solar customers consistent with
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60 ConservAmerica Reply Br. at 1-2.
61 Id. at l.
"2 ConservAmerica Br. at 2.
as ConservAmerica Reply Br. at 2.
<>4 Id. at 3.
as ld.
of ASDA Br. at 12, citing to Hearing Exhibit ASDA-l (Direct Testimony of Sean Seitz on the Settlement Agreement) at
2.
67 ASDA Br. at 2.
68 Vote Solar Br. at 3.
76295DECISION no.15
DOCKET no. E-01345A-16-0036 ET AL.
l this Commission's orders.""°Vote Solar believes that the settlement "achieves a reasonable
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compromise on a range of issues affecting APS and its customers," and as a whole strikes a "delicate
balance between competing issues on numerous interrelated issues among the signatory parties."7°
Vote Solar believes the Settlement Agreement is just, reasonable, fair, and in the public interest, and
requests that it be approved without modification."
6 EFCAxi.
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EFCA states that the process leading to the Settlement Agreement was open, transparent, and
all interested parties had an opportunity to be heard.72 EFCA states that during the many settlement
conferences that were held following notice to all parties of settlement discussions on December 29,
2016, each party had the opportunity to raise and have its issues considered multiple times during the
negotiations."
12 xii.AURA
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AURA asserts that the negotiation process leading to the Settlement Agreement was fair and
proper, and that a settlement process is an appropriate way to resolve this rate case.74 AURA's witness
testified that the Settlement Agreement is the result of many hours of negotiations and a willingness of
the parties to compromise, that the negotiations were conducted fairly and reasonably with notice, in a
way that allowed each party the opportunity to participate in every step of the negotiation, by
teleconference, if necessary, that all documents were made available to all parties in the discussions,
and that all parties were allowed to express their positions fully.75
20 xiii.Freeport / AECC / Calpine / CNE / Direct Energy
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Freeport, AECC, Calpine, CNE, and Direct Energy state that the fact that all parties to this
proceeding did not sign the Settlement Agreement does not mean that it is not in the public interest,
but rather means that not all parties' viewpoints could be accommodated in the broader context of the
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°° ld.
70 ld.
71 Vote Solar Br. at 2-8.
72 EFCA Br. at 22.
73 Id.
74 AURA Br. at 12.
vs ld., citing to Hearing Exhibit AURA-3 (Direct Testimony of Patrick Quinn on the Settlement Agreement) at 2.
76295DECISION no.16
DOCKET no. E-01345A-16-0036 ET AL.
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Settlement Agreement."Freeport, AECC, Calpine, CNE, and Direct Energy state that many
viewpoints were accommodated by the Settlement Agreement, as well as the broad spectrum of
stakeholder interests represented by the Settling Parties."
4 ACAAxiv.
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ACAA states that the settlement process was fair and open, where all parties had a chance to be
heard, and that ACAA attended the majority of the meetings and was able to participate fully in the
development of the Settlement Agreement. ACAA believes the Settlement Agreement is a reasonable
outcome to the good faith negotiation between the parties, that it represents a just and reasonable
outcome for APS's low-income customers, and that it deserves the Commission's approva1.7°
10 xv.RUCO
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RUCO states that the Settlement Agreement's achievement of consensus by a substantial
majority of the parties in this matter is extraordinary, given the diverse interests and the nature of the
issues involved. RUCO contends that the Settlement Agreement "is a comprehensive solution to a
litany of issues which is fair to all involved, results in fair and reasonable rates and is in the public
interest."8° RUC() states that its settlement position differs from its direct case position as a result of
negotiation and give-and-take compromise, that it has conducted a forensic analysis of APS's rate
request as far as residential interests are concerned, and that RUCO is very aware of what it is giving
up and what it is getting in the Settlement Agreement." RUCO "is completely satisfied that this
Settlement is in the best interests of the ratepayers under the circumstances of this case," and believes
it is unlikely that ratepayers would be better coffin a litigated case than under the terms of the Settlement
Agreement.82 RUCO asserts that the Settlement Agreement is "very balanced and fair to everyone's
interests overall" and that it achieves the agreement of the solar interests to withdraw any appeals of
the Value of Solar Decisions, and to refrain from seeking to undermine the Settlement Agreement
through ballot initiatives, legislation, or advocacy at the Commission, which is something that the
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76 Freeport, AECC Calcine, CNE, and Direct Energy Br. at 8.
77 Id.
78 ACAA Br. at 3.
19 Id. at 34.
80 RUCO Br. at 1.
81 ld. at 4, 78.
82 id. at 4-5,8.
7629517DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
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Commission could not order parties to do if the case is litigated." While RUCO does not support every
provision of the Settlement Agreement individually, it believes that when viewed in its entirety, the
Settlement Agreement constitutes "a fair and reasonable resolution of a very complicated and
contentious case for ratepayers and for the state of Arizona" and recommends that the Commission
approve it!"
6 Staffxvi.
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Staff states that the proposed Settlement Agreement is the result of a transparent and open
process, and represents agreement among a diverse group of stakeholders."Staff disputes the
Districts' allegations that parties were shut out of the settlement process.8° Staff states that throughout
the settlement process, all parties were notified of settlement discussions and had multiple opportunities
to be present and heard on their issues, and that although not all parties were signatories to the
Settlement Agreement, it incorporates provisions that were either direct suggestions or were prompted
by the express positions of non-signatories.87 Staff finds it noteworthy that of the approximately 10
parties who did not sign the Settlement Agreement, only about six filed testimony in opposition to it,
and several of those parties acknowledged and voiced support for many provisions in the Settlement
Agreement.8** Staff disputes the Districts' "power imbalance" allegations, emphasizing that Staff was
17 an impartial participant and like RUCO, had no monetary interest in the outcome of this case. Staff
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states that its goal in cases before the Commission is "to assist the Commission in finding a resolution
to each case that balances the interest of both the Company and its customers, that is in the public
interest, and that it results in rates that are just and reasonable to consumers."89 Staff disagrees with
the Districts' contention that APS is receiving a "windfall" in the Settlement Agreement.°° Staff states
that the Districts filed no revenue requirement or rate design testimony in this case, and apparently rely
on Staffs and RUCO's initial Direct Testimonies to support their allegations.°' Staff believes that the
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83 ld. at 2, 4.
84 ld. at 4-5.
as Staff Br. at 7.
so Staff Reply Br. at 7
av Staff Br. at 8, Staff Reply Br. at 7.
xx Staff Br. at 2021, referencing SWEEP and AARP positions, Staff Reply Br. at 8.
89 Staff Reply Br.at 7.
90 Id. at 10.
al Id.,Staff Reply Br. at 10.
76295DECISION no.18
DOCKET no. E-01345A-16-0036 ET AL.
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Settlement Agreement reasonably balances APS's interests with the interests of consumers and
stakeholders with divergent interests.92
Staff disagrees with the Districts' allegations that they were prevented from introducing
evidence to demonstrate that the settlement process was flawed." While acknowledging that Rule 408
does not prohibit all uses of evidence of a compromise, Staff states that the objections Staff and other
parties raised during cross-examination by the Districts' counsel were to the Districts' attempts to
characterize the positions of parties during negotiations, which under Rule 408 is normally
inadmissiblc.94 Staff states that the fact that some smaller meetings were held between Staff and other
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parties does not mean that the process was closed and that some parties were favored over others, as
the District imp1ies.°5 Staff states that it met with any party that requested a meeting, and showed no
favoritism.°6
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Staff states that the concern ED8/McMullen expressed that settlement of APS's rate cases in
the past may have led to significant additions to rate base over the years without "thorough scrutiny"
ignores the "extensive process Staff undertakes as part of each rate case to ensure that assets were
prudently acquired and are used and useful in serving customers."°7 In response to Ed8/McMullen's
criticism of Staff's testimony comparing the revenue requirement in the Settlement Agreement to the
revenue requirement APS proposed in its rate application, instead of to Staff"s initial proposal in
refiled Direct Testimony, Staff responds that it is not unusual for Staff's position to change in rate
cases, based on other parties' testimony and on information received from applicants, and therefore the
comparison to the Company's application is appropriate."
Staff responds to Mr. Woodward's and Mr. Gayer's attacks on the settlement process and on
22 Staff's role in the case, stating they are unwarranted.°° Staff states that its role in cases bctbre the
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92 Staff Reply Br. at 8.
93 Id. at 9.
94 Id., citingto Murray v. Murray,239 Ariz. 174, 367 P.3d (App. 2016). Staff also notes in response to arguments by Mr.
Gayer that "[i]f settlement discussions were disclosed, and parties' compromising of positions offered in the course of
negotiations were made public, this would act to chill meaningful and candid discussions and would result in overall harm
to the process. The ALJls rulings regarding Rule 408 were appropriate in this case." Staff Reply Br. at 15.
95 Staff Reply Br. at 9.
9° ld.
97 Staff Reply Br. at 10.
98Id., Staff Reply Br. at l l .
99 Staff Reply Br. at 11, 15.
7629519DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
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Commission is to make reasonable recommendations that balance the interests of both ratepayers and
the utility, and that that favoring the ratepayer interest too much can jeopardize the utility's financial
health and can impair its ability to provide reasonable and cost effective servicc.'°° Staff states that all
parties had an opportunity to participate in the settlement process, and that the hearing on the Settlement
Agreement provided those parties in opposition to the Settlement Agreement an opportunity to
effectively make their points, which are a part of the record that the Commission will consider when it
decides whether or not to adopt the Settlement Agreement. 101 As a signatory to the Settlement
Agreement, Staff believes that it reflects the appropriate balance between ratepayer and utility interests,
that the process in amving at the Settlement Agreement was fair, and that the provisions of the
Settlement Agreement are in the public interest and should be adopted without any modification.'°2
ll xvii.Resolution
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Having examined and considered all arguments made regarding procedural opposition to the
settlement process that the parties to this proceeding undertook, we find that the arguments arc without
merit and pose no ban°ier to our consideration of the substance of the Settlement Agreement. Wc note
the dissatisfaction of some parties with the outcome of the Settlement Agreement including the issues
regarding non-AMI meters litigated in this proceeding. Given the large number of interveners, and the
broad range of interests they represent, it is understandable that a total consensus was not reached.
However, there is no support in the record for a finding of impropriety in the settlement process, and
the fact that an individual party did not have its position incorporated in the Settlement Agreement does
not reflect a deficiency in the settlement process or the Settlement Agreement itself Our forthcoming
bifurcated Decision on the litigated issues regarding non-AMI meters will not revisit the issue of
whether any alleged improprieties occurred.
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100 ld. at 11.
101 Staff Reply Br. at 15.
102 Id. at 11,17.
7629520DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
l Iv.SUBSTANTIVELY UNDISPUTED SETTLEMENT AGREEMENT ISSUES
2 a.Fair Value Rate Base and Revenue Requirement
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While some parties contest the way the revenue requirement would be collected from
customers, no party to this proceeding contests the revenue requirement. 103 Many of the Settling Parties
completed a thorough analysis of APS's rate case filing prior to the time the parties began settlement
negotiations. 104
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The uncontested Settlement Agreement fair value rate base ("FVRB") is $9,990,561 ,000, total
adjusted test year revenue is $2,888,903,000, and the non-fuel, non-depreciation revenue requirement
increase is $87.25 mi1lion.I05 When the Settlement Agreement reduction forbade fuel of$53.63 million
and the increase for depreciation of $61.00 million is taken into account, the result is a net base rate
increase of$94.624 million, exclusive of the adjustor transfer of$267.95 million.l06
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Alter including the transferred adjustor mechanism amount of $267.95 million, the total base
rate revenue requirement is $362.58 million.l07 This amount is comprised of (1) a non-fuel base rate
increase of $l48.250 million, which includes a return on and of post-test year plant in service as of
December 31, 2016, (2) a base fuel rate decrease of $53.63 million, and (3) the transfer from adjustor
mechanisms of$267.95 million to base rates. 108 APS agrees to impute, in future rate cases, net revenue
growth for any revenue producing plant included in post-test year plant. 109
The transferred adjustor mechanism amount includes a transfer to base rates, and a zeroing out
19 or reduction of the revenue requirements currently collected through the Renewable Energy Adjustor
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103 See, Ag., SWEEP Br. at 6, AARP Br.at 5.
low See e.g.FEA Br. at 1-6, referring to Hearing Exhibit FEAl (Direct Testimony of Brian Andrews)(depreciation
expense), Hearing Exhibit FEA-l (Direct Testimony of Michael Gorman)(cost of capital), and Hearing Exhibit FEA- l
(Direct Testimony of Amanda Alderson)(cost of service study). FEA commented that it is a signatory to the Settlement
Agreement because it represents a reasonable compromise on the many complex issues in the case concerning APSs
revenue requirement the revenue spread across rate classes and rate design. Through its witnesses FEA presented
evidence concerning cost of capital depreciation rates and expense and a cost of service study. FEA is not opposing the
cost of capital or any of its components filed in the Settlement Agreement and states that while the Settlement Agreement
does not address the concerns it raised regarding depreciation FEA "agrees to the total settlement in aggregate rather than
individual elements of the settlement which comprise specific findings on revenue requirement cost of service and rate
design."
105 Settlement Agreement Section 3 (page 8).
106 ld.
107
108 Id.
109 ld.
7629521DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
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Clause ("REAC"), Demand Side Management Adjustor Clause ("DSMAC"),Transmission Cost
Adjustor ("TCA"), Environmental Impact Surcharge ("ElS"), Four Comers Rate Rider ("FCRR"), and
the System Benefits Charge ("SBC"). | lo
4 b.Cost of Capital
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The Settlement Agreement adopts, for ratemaking purposes, an original cost of capital structure
comprised of 44.2 percent debt and 55.8 percent common equity, a return on common equity of 10.0
percent and an embedded cost of debt of 5. la percent.l 11 The Settling Parties agree to a fair value rate
ofretum ("FVROR") of5.59 percent, which includes a 0.8 percent return on the fair value increment' 12
9 Base Fuel Ratec.
10 The Settlement Agreement adopts a base fuel rate of $0.030168 per kph, which is lowered
l l from the $0.032071 set by Decision No. 73183.
12 d.Bill Impact
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The Settlement Agreement rates result in an average a 3.28 percent bill impact when new rates
become effective, with an average 4.54 percent bill impact for residential customers, and an average
1.93 percent bill impact on general service customers.' 13
16 e.Rate Case Stability Provision
17 As part of the Settlement Agreement, APS agrees not to file its next general rate case before
18 June 1, 2019, with a test year ending no earlier than December 31, 2018.114
19 f.Four Corners Units 4 and 5
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The Settlement Agreement provides that this docket will remain open to allow APS to file a
request that its rates be adjusted no later than January 1, 2019 to reflect its proposed addition of
Selective Catalytic Reduction ("SCR") equipment at the Four Comers Generating Station, and acts
forth filing requirements and parameters regarding such filing."5 The Settlement Agreement
authorizes APS to defer, for possible later recovery through rates, all non-fuel costs of owning,
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110 Id., Section 8 (page ll).
ill Settlement Agreement Section 5 (page 9).
112 Id.
113 Settlement Agreement Section 4 (pages 8-9).
114 Id., Section 2 (page 8).
115 Id., Section 9 (page 12-13).
DECISION no,22 76295
DOCKET NO. E-01345A-I6-0036 ET AL.
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operating, and maintaining the Selective Catalytic Reduction environmental controls at the Four
Comers Power Plant from the date such controls go into service until the inclusion of such costs into
3 rates.
4 Ocotillo Modernization Project
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g.
The Settlement Agreement authorizes APS to defer, for possible later recovery through rates,
all non-fuel costs of owning, operating, and maintaining the Ocotillo Modernization Project and retiring
the existing steam generation at Ocotillo.' 16
8 h.Property Tax Rate Deferral
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The Settlement Agreement provides that APS shall be allowed to defer for future recovery (or
credit to customers) the Arizona property tax expense above or below the test year caused by changes
to the applicable composite property tax rate, subject to the provisions set forth in the Settlement
Agreement Section.' 17
13 .|.Tax Expense Adjustor Mechanism
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The Settlement Agreement provides that in the event that significant Federal income tax reform
legislation is enacted and becomes effective prior to the conclusion of Arizona Public Service
Company's next general rate case, and such legislation materially impacts the Company's annual
revenue requirements APS will create a rate adjustment mechanism to enable the pass-through of
income tax effects to customers.' 18
19 j Other Significant Provisions
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21
Section 1.5 of the Settlement Agreement cites several provisions that the Settling Parties note
as significant in balancing the rate increase with benefits for APS's customers.' 19
22 k.Rate Design for Low-Income Customers
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The Settlement Agreement includes changes to existing rate design provisions benefiting low-
income customers. 120
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116 Id., Section 10 (page 13).
1171d., Section ll (page 13).
118 Id., Section 16 (pages 16-17).
"9 ld., Section 1.5 (page 6).
120 ld. Section 29 (pages 26-27).
76295DECISION no.23
DOCKET no. E-01345A-16-0036 ET AL.
l ACAA states that it intervened to ensure that low-income customers in Arizona had a voice in
2
3
this rate case. ACAA states that nearly one in five Arizonans are in poverty, and that the energy burden
for low-income households is much higher than the energy burden for the average APS customer.
4 ACAA states that the Settlement Agreement:
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provides substantial assistance to make electricity bills more affordable for those least
able to pay for them. Increasing the low-income discount and low-income medical
discount will make bills more affordable for low-income customers. For a family of
three at the poverty level in the test year, this will decrease the average energy burden
from 8.1% to 6.0%. As was stated in direct testimony, a 6% energy burden is generally
considered to be affordable, in this case, the discount has allowed someone with a
previously unaffordable bill to now be able to better afford it12l9
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ACAA also points favorably to the Settlement Agreement's requirement that APS pay $1.25
million in crisis bill assistance per year, which ACAA states will help thousands of APS customers in
hardship situations that render them unable to pay their electric bill. ACAA states that the provision
of consistent funding from year to year ensures the availability of such crisis assistance for several
years. 12214
15 Staff states that through the addition of the $ l .25 million annually for the crisis bill program to
I6 assist customers with incomes less than or equal to 200% of the Federal Poverty Income Guidelines,
17 these low-income ratepayers will receive direct assistance to defray the impact of the Settlement
lg Agreement rate increase. 123 In addition to the crisis bill assistance program, the Settlement Agreement
19 increases funding and simplifies the bill discount for the E-3 Energy Support Program for limited
income customers, with a flat 25% bill discount.'2420
l.Rate Design for DG Customers
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22 The Settlement Agreement proposes the following for customers with Distributed
Generation: 12523
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121 ACAA Br. at 2.
122 Id. at 3.
123 Staff Br. at 13.
124 Id. citing to Hearing Exhibit APS-6 (Direct Testimony of Charles Miessner on the Settlement Agreement) at 5 and Tr.
at 316 (APS witness Lockwood).
12 s Settlement Agreement Section 18 (pages 19-20)
7629524DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
18.1
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DG customers are eligible for four different rate schedules including all
proposed TOU and Demand rates. DG customers that select TOU-E will be
subject to a Grid Access Charge as reflected in Appendix F.2
18.23
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5
The self-consumption offset rate for TOU-E will be $0.105/kWh, which is
inclusive of the Grid Access Charge, but exclusive of taxes and adjustors. This
is an approximately $0. l 20/kWh offset rate after these adjustments. The offset
rate is based on the load profile and production profile of APS customers with
DG during the test year. Individual customer offset will vary based on individual
usage patterns and DG system size, orientation, and production.6
18.37
8
9
The Resource Comparison Proxy Rate ("RCP") for exported energy established
in Decision No. 75859, as amended by Decision No. 75932, will be $0. l29/kWh
in year one, which is inclusive of undifferentiated transmission, distribution, and
loss components. This export rate was calculated using a 20]5 base year with
an adjustment to achieve the final export rate. Attached as Appendix H is the
RCP Rate Rider, POA and EPR-6 Legacy Rate Rider.10
18.411
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This first year export rate is the product of settlement negotiations and does not
create any precedent, imply any change to the structure of or detail in the
Resource Comparison Proxy, or otherwise change any aspect of Decision No.
75859.
13
18.514
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DG customers that file a completed interconnection application before the rate
effective date adopted in the Decision in this case shall be grandfathered
consistent with Section 18.6 for a period of twenty years, with the twenty year
period beginning from the date the system is interconnected with Aps.
16
18.6
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18
19
20
21
As contemplated in Decision No. 75859, grandfathered DG customers will
continue to take service under full retail rate net metering and will continue to
take service on their current tariff schedule for the length of the grandfathering
period, which for APS are rate schedules E-12, ET-l, ET-2, ECT-1, or ECT-2.
In its next rate case, APS will propose that the rates on each of these legacy
tariffs will be updated with an equal percent increase applied to every rate
component equal to the residential average base rate increase approved.In
addition, grandfathered DG customers currently served on E-3 or E-4 will
continue on the current E-3 or E-4 Rate Riders for as long as they acct the
eligibility criteria and/or discontinue participation in the program.22
23
24
25
Vote Solar states that it participated in this proceeding to advocate for fair rates and rate designs
that benefit all customers and support the integration of DG in Arizona.I26 While the Settlement
Agreement does not incorporate all the rate design options for DG customers that Vote Solar initially
proposed, it provides them with more rate options than APS initially proposed. 127 Vote Solar states that
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126 Vote Solar Br. at 2.
127 Id. at 4.
76295DECISION no.25
DOCKET no. E-01345A-16-0036 ET AL.
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the Settlement Agreement provisions, all taken together, including the negotiated Grid Access Charge,
benefit existing DG customers and establish a just and reasonable RCP rate for new DG customers who
sell their excess energy back to the grid.128 Vote Solar believes that adoption of all the provisions of
the Settlement Agreement together will provide a just, reasonable, and fair outcome in the public
interest, and requests that the Settlement Agreement be approved without modification.
SEIA supports the Grid Access Charge established in the Settlement Agreement, as it is "within
the range of possible outcomes presented for litigation."'2° SEIA emphasizes that "the Settlement
Agreement's provision that DG customers are eligible for four different rate options is a fair and
reasonable outcome that preserves customer choice and provides APS a reasonable opportunity to
recover its costs of service"130 and "treats DG and non-DG customers in a non-discriminatory
manner."I31 SEIA is pleased that under the Settlement Agreement, residential DG customers can take
service under the same TOU tariff that is available to non-DG customers. In regard to the settled RCP
price, SEIA states that while it is below what SEIA would have recommended, SEIA supports the
Settlement Agreement outcome as reasonable. SEIA is also supportive of the Settlement Agreement's
grandfathering provisions for DG customers, because they preserve the expectations of solar DG
customers at the time they invested in solar DG, they provide a reasonable window for customers
currently pursuing solar DG to complete their installations, they are fair, and they are consistent with
Decision No. 75859. SEIA states that the Settlement Agreement resolves policy disputes between
APS, Staff RUCO and the solar industry "in favor of stable solar policies and rates up through APS's
next rate case so long as the Settlement Agreement is approved without material modification" and
recommends its approval.'32
EFCA states that the provisions of the Settlement Agreement that promote the continued
expansion of DG (choice orate schedules for DG customers, setting the RCP, and grandfathcring solar
DG customers) are of great benefit, because they will reduce the time and resources of the Commission
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128 Id. at 5, 8.
129 SEIA Br. at 4 citing to Hearing Exhibit SEIA-2 (Direct Testimony of Sara Birmingham on the Settlement Agreement)
at 5.
130SEIA Br. at 4.
131 ld. at 3.
132 Id. at 2, 7.
DECISION no.26 76295
DOCKET no. E-01345A-16-0036 ET AL.
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3 customers.
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that would otherwise be expended on litigation.'33 EFCA agrees with the Settling Parties that the
Settlement Agreement presents a fair and balanced compromise, and will ultimately benefit APS's
EFCA recognizes that the Commission has the discretion to reject the Settlement
Agreement in whole or in part, and reserves the right to object to and appeal any Commission Decision
that denies or modifies any aspect of the Settlement Agreement.'34
RUCO notes that a significant benefit of the Settlement Agreement is the progress it makes on
modernizing rates and minimizing the cost shift from DG to non-DG customers, while still allowing
the rooftop solar industry to transact.'35
In regard to the Settlement Agreement provisions relating to rooftop solar, Staff states:
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A critical cornerstone of the heavily negotiated balance struck on these contentious
issues is the agreement of parties to withdraw any appeals of the Commission's VOS
orders, Decisions No. 75859 and 75932. Paragraph XXXV of the Settlement requires
Signatories to withdraw any pending challenges to Decisions No. 75859 and 75932 and
to refrain from pursuing any challenges to either Decision in any forum. Further, the
Agreement requires a stay of any pending appeals of these Decisions until a final order
is issued in the present matter that adopts the material terms of the Agreement. In concert
with other provisions of the Settlement that require Signatories to mutually support and
defend a Commission Order that adopts all material terms of the Settlement, a separate
agreement was executed between APS, the solar providers and their respective affiliates
as well as several others, wherein the signatories agree not to take steps to undermine
the Agreement in any forum through ballot initiative, legislation, or advocacy. 136
17
m.AG-X Program
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Freeport and AECC (a customer group), along with Calpine, CNE, and Direct Energy
(generation service providers, or "GSPs" who are serving customers under APS's current AG-l tariff)
support the Settlement Agreement as a whole, but their particular concern is the negotiated outcome of
the AG-X program, which is detailed in Section 23 of the Settlement Agreement, and further depicted
in Attachment K to the Settlement Agreement.'37 Freeport, AECC, Calpine, CNE, and Direct Energy
state that the AG-X program modifies the existing AG-l program which was initially approved in
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133 EFCA Br. at 23.
134 EFCA Reply Br. at 19.
135 RUCO Br. at 4.
136 Staff Br. at 17.
137 Freeport, AECC, Calpine, CNE, and Direct Energy Br. at 4 and Reply Br. at 7.
7629527DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
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Decision No. 73 l 83 (May 24, 2012) in the form ofAPS's Experimental Rate Rider AG-l .138 The AG-
1 program is a "buy-through" program under which participating large commercial and industrial
customers may obtain generation from third-party GSPs to serve all or a portion of their power
requirements, and Freeport, AECC, Calpine, CNE, and Direct Energy state that it is an example of the
"mixed competition-regulation" rate design model that has recently emerged in the electric utility
industry and represents a means of effecting needed changes to the existing regulatory framework to
accommodate changing conditions.l3° Participating AG-l customers, who were selected by means of
a lottery conducted by APS, remain APS customers for their other electric service needs, including
transmission and distribution service.
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ll
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21
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The Settlement Agreement proposes continuation of the experimental AG-l program in the
form of the AG-X program, which is no longer characterized as experimental.Freeport, AECC,
Calpine, CNE, and Direct Energy state that "the continuation of APS's existing AG-l 'buy-through'
program, as modified in the form of the AG-X program, represents a constructive means for continuing
to advance [current] rate design objectives with respect to large commercial and industrial customers
on APS's system.I40 Freeport, AECC, Calpine, CNE, and Direct Energy describe the positions of
various parties to adjust APS's existing rate schedules to "(i) more properly reflect the realities of a
rapidly and significantly changing electric utility industry, and (ii) better match cost causation and rate
recovery responsibility" and believe that the AG-X program proposed in the Settlement Agreement
meets those rate design objectives. 141 Accordingly, Freeport, AECC, Calpine, CNE, and Direct Energy
believe the Commission should approve the AG-X program, in conjunction with its approval of the
Settlement Agreement in its entirety.
Walmart is also a participant in the current AG-l program, and takes service from a GSP at 53
omits 73 retail locations in the APS service territory. 142 Noting that the Settlement Agreement, to which
it is a party, includes provisions that APS will not file a new base rate application until at least June l,
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138Freeport, AECC, Calpine, CNE, and Direct Energy Br. at 2-3 (detailing the history oftheAG-l program from inception
through the present).
130 Freeport, AECC, Calpine,CNE,and Direct Energy Br. at 3; Freeport, AECC, Calcine, CNE, and Direct Energy Reply
Br. at 4.
140 Freeport AECC Calpine, CNE, and Direct Energy Reply Br. at 3.
141 ld. at 3-6.
142 Walkman Br. at l, citing to Hearing Exhibit Walmart-l (Direct Testimony of Gregory Tillman) at3.
DECISION no.7629528
DOCKET NO. E-01345A-16-0036 ET AL.
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2019, and also that it retains a buy-through program, now to be known as AG-X, which is a somewhat
modified, non-experimental version of the current AG-l program, Walmart urges the Commission to
adopt the Settlement Agreement.'43
Staff states that the Settlement Agreement's AG-X program provides for a continuation of the
AG-l program with changes that anticipate and prevent the under-recovery issues presented by the
AG-l tariff, improve upon other aspects of the program, and expand it to allow more opportunity for
qualifying General Service customers to participate.'44
8 Power Procurement Auditn.
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Decision No. 73183 required Staff to perform an audit of APS's fuel and purchase power
activities. APS requests approval of Staff witness Dennis Schumaker's recommendations regarding
the fuel and purchase power audit, with requested modifications from APS, agreed to by Staff 145 APS
proposes that the time allowed for APS to conduct an audit of its PSA filings as required by Staff
Recommendation No. 111-2 be extended from twelve months to eighteen months, in order to allow APS
sufficient time to fully implement Staffs other recommendations prior to auditing the PSA filings.I46
Staff agreed to this modification.'47 APS also proposes that Staff Recommendation No. 111-5, which
would require APS to reconfigure its systems to disallow transactions when a counterparty is
overexposed, be removed, due to unintended negative consequences to reliability that could result.'48
Staff also agreed to this modification, noting that APS has other ways built into its system to flag
potential credit and over-exposure issues.'4°
The results of Staffs audit of APS's fuel and purchase power activities and resulting
21 recommendations are reasonable and should be adopted. APS will be required to comply with Staffs
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143 Walmart Br. at 1-2.
144 Staff Br. at 15 citing to Hearing Exhibit APS-6 (Direct Testimony of Charles Miessner on the Settlement Agreement)
at 15.
145 APS Br. at 67, citing to Hearing Exhibit APS-3 (Rebuttal Testimony ofBarbara Lockwood on the Settlement Agreement)
at 10-1 l and Tr. at 735-737 (Staff witness Schumaker).
146 APS Br. at 67, citing to Hearing Exhibit APS-3 (Rebuttal Testimony ofBarbara Lockwood on the Settlement Agreement)
at 10.
147 APS Br. at 67, citing to Tr. at 73536 (Staff witness Schumaker).
148 APS Br. at 67, citing to Hearing Exhibit APS-3 (Rebuttal Testimony ofBarbara Lockwood on the Settlement Agreement)
at 10-1 1.
149 APS Br. at 67, citing to Tr. at 737 (Staff witness Schumaker).
76295DECISION no.29
DOCKET no. E-01345A-16-0036 ET AL.
recommendations, with the exception of the modifications to Staff Recommendation No. 111-2 and Staff
Recommendation No. 111-5, as proposed by APS and agreed to by Staff.
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3 v.SUBSTANTIVELY DISPUTED SETTLEMENT AGREEMENT ISSUES
4 Use of Unspent DSMAC Funds
5
a.
To mitigate the first year bill impacts, the Settling Parties agreed that APS will refund to
customers through the DSMAC $15 million in collected, but unspent DSMAC funds.1506
7 i.SWEEP
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SWEEP opposes this refund of DSMAC funds, and proposes instead that any use of, or any
timely refund 0£ the DSMAC unspent funds be addressed in the DSM Implementation Plan proceeding
10 instead of in this rate case proceeding.'5' SWEEP argues that its proposed process would provide
l l adequate due process in a proceeding that is focused on DSM issues.'52 SWEEP is concerned that if
12 the unspent DSMAC funds are not used to fund DSM programs, APS will have insufficient funds to
13 adequately support those programs and customer projects.'53 SWEEP asserts that for the third year in
14 a row, the funding for the APS DSM budget has been short of that needed to support DSM programs
15 and meet customer needs, and that unspent funds could be used to make up the difference, as the
16 Commission has ordered in the past.154 SWEEP is concerned that if the unspent funds are ordered
17 refunded in this proceeding, customers and stakeholders will not have been aware of the Settlement
18 Agreement proposal or have had an opportunity to participate, and that the issues in this rate proceeding
19 are not directly relevant to the scope and focus of the DSM proceeding. 155
In response to Staffs statement on brief that the unspent DSMAC funds are not funding any
21 programs that would be tenninated as a result of the Settlement Agreement proposed refund, SWEEP
22 states that it is concerned not just with termination of programs, but with reductions in spending and
23 reductions in customer incentives.'5°
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150 Settlement Agreement Section 4 (page 9).
151 SWEEP Br.at 5,19.
152ld. at 5.
153ld. at 19.
154 Id.,SWEEP Reply Br. at 9.
155SWEEP Br. at 20 SWEEP Reply Br. at 11.
156 SWEEP Reply Br. at 9.
DECISION no.30 76295
DOCKET NO. E-01345A-16-0036 ET AL.
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SWEEP contends that "in April 2017, APS reduced custom incentive levels for its commercial
and industrial customers by 45% and cut the incentives for customer studies by 50% because it has
insufficient DSMAC funds to meet customer interest in the programs."'57 SWEEP charges that APS's
arguments ignore that its DSM programs are facing a funding shortfall in 2017, and that DSMAC
unspent funds could be used to provide adequate and stable funding for those programs, in the manner
the Commission ordered in 2015 and 2016958
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SWEEP contends that the magnitude of the rate increase in the Settlement Agreement (4.54%
for the residential class) does not require the gradualism that APS argues the refund of the unspent
DSMAC funds would provide.I5°
APSii.
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APS states that the Settling Parties agreed that the $15 million of unspent and unallocated
DSMAC funds should be returned to customers now. APS asserts that returning the funds to customers
is always within the Commission's discretion, and that a refund at this time, rather than waiting for a
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18 Staff
subsequent proceeding, would provide some gradualism for any rate increase ordered in this matter.
APS contends that using the unspent DSMAC funds would not impact existing DSM programs or
customers, and that, to the extent needed, the Commission can modify the DSMAC to collect additional
funds as necessary for the 2017 DSM Implementation Plan or budget. 160
iii.
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Staff believes that SWEEP's opposition to refunding the $15 million of unspent DSMAC funds
is without merit, and states that if it were adopted, the delicate balance reached by widely divergent
parties to the Settlement Agreement would be disturbed. 161 Staff states that SWEEP acknowledges that
the funds in question are not funding any current programs that would be terminated as a result of the
refund of this ratepayer money, and admits that nothing would prevent the Commission firm ordering
a refund, either through approval of the Settlement Agreement, or through APS's DSM Implementation
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157 Id. citing to Hearing Exhibit SWEEP 4 (Rebuttal Testimony of Jeff Schlegel on the Settlement Agreement) at 13-14.
158 SWEEP Reply Br. at 8-10.
159 Id. at l l
'°0 APS Br. at 55-56.
161 Staff Br. at 24.
76295DECISION no.31
DOCKET no. E-01345A-l6-0036 ET AL.
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Plan proceeding.162 Staff contends that the Commission retains the ability to modify the level of the
DSMAC to collect sufficient funds to accomplish the Commission's priorities, which can address
SWEEP's concerns regarding adequate support for programs and customer projects. Staff argues that
SWEEP's due process arguments are without merit, because it is Staffs understanding that the $15
million refund to ratepayers will actually take place in the DSM docket, alter approval of the Settlement
Agreement in this proceeding.'°3 Staff believes that the provision regarding the refund of $15 million
in collected but unspent DSMAC funds to ratepayers to mitigate the first year rate impacts to ratepayers
should be approved.
iv.Resolution
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Alter examining and considering the facts and arguments presented regarding the Settlement
Agreement's provision regarding the refund of $15 million in collected but unspent DSMAC funds to
ratepayers to mitigate the first year rate impacts to ratepayers, we find that the provision is well-
supported, reasonable, and in the public interest.
b.AZ Sun II
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Section 28 of the Settlement Agreement pertains to approval of the proposed AZ Sun II
program, under which APS will use third-party solar contractors, competitively selected through an
RFP process, to install rooftop solar systems on the roofs of low- and moderate-income homeowners.
Under the Settlement Agreement, APS will propose a program of $10 - $15 million per year in direct
capital costs. The Settlement Agreement provides that expenses of the program eligible for recovery,
including capital carrying costs, may be reviewed for prudence in each annual REST docket, and will
be recoverable through APS's Renewable Energy Adjustment Clause until its next rate case, when APS
may request that the capital costs of the installed solar systems be included in rate base."64
Mr. Gaver
Mr. Gayer asserts that the AZ Sun II program is "worthless," "wastes customers' money," and
25 "unfairly competes with private solar installers."'°5 Mr. Gayer argues that his Hearing Exhibit Gayer-
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162 ld.citingto Tr. at l 143, l 167-68 (SWEEP witness Schlegel).
163 Staff Reply Br. at 6.
164 Settlement Agreement Section 28 (pages 2423).
"65 Gayer Br. at 1415, citing to Tr. at 78-82 (public comment of Dru Bacon).
DECISION no.32 76295
DOCKET no. E-01345A-16-0036 ET AL.
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17 demonstrates that "all 1.2 million APS customers will pay 87 cents per month for AZ Sun II.""'6
Mr. Gayer proposes that if the AZ Sun II proposal is approved, the Commission order that all ofAPS's
customers should also share the cost of reading non-AMI meters.'°7
4 ii.APS
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10 iii.
APS states that the AZ Sun II program is a creative and reasonable negotiation outcome that
will help meet the needs and interests of various parties in this case, and emphasizes that the outcome
is one which would not have resulted from a litigated proceeding. APS points out that the AZ Sun II
provisions include an agreement by APS not to implement any additional utility-owned residential
solar DG programs prior to APS's next general rate case. 168
ConservAmerica
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ConservAmcrica asserts that while the impact of the proposed AZ Sun II on residential
customers would be small, the benefits would be great. ConservAmerica disputes the validity of the
inputs to Hearing Exhibit Gayer-17, and of the conclusions Mr. Gayer attempts to draw from it.
ConsewAmcrica explains that Hearing Exhibit Gayer- l7 is flawed, because it assumes that the $ lo to
$15 million in AZ Sun II costs would be recovered directly from APS customers.Instead, as
ConserveAmerica explains, the $ l0 to S l5 million in capital costs would be APS-invested funds, which
if put into rate base in a future rate case, would then be eligible to earn a return which would be
calculated into the revenue requirement, and that only a portion of the resulting revenue requirement
would be recovered from residential ratepayers."'°
In response to Mr. Gayer's charge that the AZ Sun II program would create unfair competition
with solar installers, ConservAmerica points out that Settling Parties to this case who represent actual
solar companies do not share Mr. Gayer's view, and that Mr. Gayer cited to public comment, and not
evidence, for this allegation. ConservAmerica asserts that AZ Sun II is targeted at the underserved
market of low- and moderate- income APS customers, and will therefore have little effect on rooftop
solar competition.l70
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we Gayer Br. at 15, citing to Hearing Exhibit Gayer17.
167 Gayer Br. at 15 16 Gayer Reply Br. at 10.
168 APS Br. at 15, 16.
169 ConservAmerica Reply Br. at 7.170
DECISION no.33 76295
DOCKET NO. E-01345A-l6-0036 ET AL.
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ConservAmerica's witness testified that subsidized rooftop solar in Arizona benefits the
wealthy, and leaves the poor behind.l7I ConservAmerica contends that this should change, and believes
that the AZ Sun II program would provide a "small but good start at broadening access to rooftop solar
in Arizona" with 65% of funding dedicated to low-income customers, and the remainder available for
either low- or moderate-income customers. 172
6 iv.AC AA
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ACAA states that the AZ Sun II program will provide the option to "go solar" for thousands of
low-income households who previously did not have such an opportunity, and that with a credit of up
to $600 per year, electric bills will be much more affordable for these low-income customers. 173
10 v.RUCO
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RUCO states that the Settlement Agreement's AZ Sun II program will provide benefits to
ratepayers beyond this rate case by making utility-owned solar DG available to low- and moderate-
income APS customers, a segment of APS customers who have not heretofore been able to participate
in solar DG for financial reasons.'74
15 vi.
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M
Staff states that through adoption of the AZ Sun II program, lower- and moderate-income
residential customers, as well as certain schools and rural municipalities, will have the opportunity to
install rooftop solar facilities and receive a monthly bill credit in exchange for granting APS rooftop
access.'75 The program requires APS to invest between Sl() and $15 million annually over a term of
three years, with at least 65 percent of each year's annual program expenditure dedicated to residential
installations.176
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171 ConservAmerica Br. at 4-5, ConservAmerica Reply Br. at 7, 8 citing to Hearing Exhibit ConservAmerical (Direct
Testimony of Paul Walker) at 9-14 and Hearing Exhibit ConsevrAmerica-3 (Direct Testimony of Paul Walker on the
Settlement Agreement) at 12-13 (wealthiest neighborhoods in Arizona have a solar penetration rate of 2.99% and poorest
neighborhoods 0.82%).
172 ConservAmerica Br. at 5.
173 ACAA Br. at 3.
174 Rico Br. at 3.
175 Staff Br. at 14.176 ld.
DECISION no.34 76295
DOCKET NO. E-01345A-16-0036 ET AL.
l Resolutionvii.
2
3
4
After examining and considering the facts and arguments presented regarding the Settlement
Agreement's provision regarding the AZ Sun II program, we find that the provision is well-supported,
reasonable, and in the public interest.
5 Mr. Gayer's proposal regarding the costs of reading non-AMI meters will be addressed in a
6 forthcoming separate Decision in this docket.
7 c.Disputed Rate Design Issues
8 i.Basic Service Charges ("BSCs")
9 The following table depicts the BSCs proposed by the Settlement Agreement, SWEEP, and
10
Timeof UseResidential
Basic
Residential
Extra Small
Residential
BasicLarge
3Part
Demand
Rates
AA R P :
Settlement
Agreement
RateSchedule
12 R-TOU-ER-BasicR-XS R-Basic Large
On-Site
Technology
Pilot
Program
R-T€chI77R-2 & R-3
13
14 (Available to
all customers)
(2 1000
kWh/month)
(600- I000
kWh/month)
(<_600
kWh/month)
RateSchedule
Qualifications
.Appendix F
(Available to to Settlementall customers)Agreement"
15
$8.67 $17.00$17.00$8.67$8.67
16
N/A
17
(Time
Advantage
Rate)
(Time
Advantage
Rate)
(E- l2
Residential-
Basic)
(E- 12
Residential-
Basic)
(E- 12
Residential-
Basic)
18
$15.00$20.00 $13.00 $13.00$15.00$10.0019
20
N/A$29.79 $34.12$24.51 $24.51$24.5 l
Current BSC
On Current
Similar Rate
Schedule
Settlement
Agreement
BSCI79
APS Fixed
Cost
Calculations
for BSCIRI)21
22
23
24
25
26
27
28
177 R-Tech is a TOU rate with on-peak and off-peak demand and energy charges, initially available to up to 10,000
customers to help reduce APSs system peak. APS Br. at 10. This experimental rate was developed to ineentivize
technology adoption, RUCO Br. at 3, and is available to customers that adopt certain home energy technologies such as
battery storage. Staff Br. at 17. The RTech three-part pilot rate program is for residential customers with two or more
qualifying primary on-site technologies, that also includes a BSC, and one TOU rate available to all customers with a BSC
for non-DG customers and a Grid Access Charge for DG customers. Vote Solar Br. at 7. The Settlement Agreement
provides that the Commission will review the R-Tech rate once 6,000 customers have signed up for Ir. EFCA Reply Br. at
19-20, citing to Section 17.1 of the Settlement Agreement. The RTech rate is intended toleadto lower coststoratepayers
in the future.RUCOBr. at 3.
178 Settlement Agreement at Appendix F.
179 Settlement Agreement Sections 17.1-17.7 (pages 17-19)
180 APS Reply Br. at 9 referring to Hearing Exhibit APS32 (outliningfixedcosts to serve by customer class and rate, from
the Cost of Service Study).
76295DECISION no.35
DOCKET no. E-01345A-16-0036 ET AL.
l
2
SWEEP BSC
(Based on its
Fixed Cost
Calculations)'l*l
$8.00 not addressed not addressed
$8.00
or $10.00$8.00
3
AARP BSCISZ
a n0 o nota used not addressed not addressednotausednotaused
$8.00
or $10.00
$10.00
[O $13.00
4
SWEEP1.
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
SWEEP docs not contest the revenue requirement or the size of the R-XS, R-Basic, or Small
General Service bill increases overall on average.l83 However, SWEEP opposes the BSCs proposed in
the Settlement Agreement for residential, extra small general service, and small general service
customers, based on its assertion that the Settlement Agreement BSCs are "very large increases in fixed
charges."'84 SWEEP contends that the Settlement Agreement's increases to the BSCs would cause
customers "with different usage levels" to experience "unfair, unjust, and unreasonable bill impacts."'85
SWEEP argues that because the Settlement Agreement rate design increases the BSC, which is a fixed
charge portion of customers' bills, it "would result in the loss of customers' control over a significant
portion of their utility bi11s."'**°
SWEEP finds it problematic that under the Settlement Agreement proposed BSCs, some
customers will experience a higher percentage increase in their BSCs than in their overall bill
amounts.l87 SWEEP contends that this leaves such customers with no meaningful opportunity to
mitigate the effect of the overall bill increase.188 SWEEP believes "[i]t is crucial for the Commission
to examine and consider the range of significant bill impacts on real customers in its review of the
Settlement Agreement."'8° SWEEP contends that the BSCs approved in TEP's recent rate Decision20
21
22
23
24
25
26
27
28
181 SWEEP Br. at5.SWEEP also proposes that the General Service Extra-Small BSC and the Small General Service BSC
rates both be set at $12.00 as opposed to those rates set forth in Appendix G to the Settlement Agreement.
182 AARP Br. at 36.
183 SWEEP Br. at 6, citing to Tr. at | 1 is (swEEp witness Schlegel).184 Id.
185 SWEEP Br. at 6 14, citing to Tr. at l l 18, l 134 (SWEEP witness Schlegel), SWEEP Reply Br. at 56 citing to Tr. at
l 121 (SWEEP witness Schlegcl).
Isa SWEEP Br. at 6, citing to Tr. at 1118, (SWEEP witness Schlegel), See also SWEEP Br. at 1 1, and SWEEP Reply Br.
at 5, citing to Hearing Exhibit SWEEP-4 (Rebuttal Testimony of Jeff Schlegel on the Settlement Agreement) at 10, and
SWEEP Br. at 14.
187 SWEEP Br. at 10. SWEEP Reply Br. at 5, citing to Hearing Exhibit SWEEP-6.Sec'also SWEEP Br. at 11-14, citing to
Tr. at 1 1 19-1 121 and 1128-1 135 (SWEEP witness Schlegel), and to Hearing Exhibit SWEEP-8A.
Las SWEEP Br. at 10, SWEEP Reply Br. at 5, citing to Hearing Exhibit SWEEP-6.
is SWEEP Br. at 6, 14, citing to Tr. at 1121 (SWEEP witness Schlegel).
7629536DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
l are the "appropriate point of comparison" for Commission consideration in this case.190 SWEEP
2
3
disagrees with APS that the Settlement Agreement proposed BSCs are consistent with those approved
for TEp.'°'
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SWEEP proposes that the Residential Basic rates be set at $7.97 (or rounded up to $8.00) for
R-XS, R-Basic, R-Basic Large, and TOU-E rates.l°2 SWEEP believes that its proposed BSCs "would
eliminate or reduce the unfair effects of the Settlement-proposed rates and higher BSCs on customers
and the bill impacts."'°3 SWEEP alternatively proposes that should the Commission wish to incentivize
uptake of the TOU-E rate through the BSC, the R-XS and TOU-E BSCs be set at $7.97 (or rounded up
to $8.00), and set the R-Basic and R-Basic Large rates at $l 0.194
SWEEP contends that the Settlement Agreement BSCs for R-XS, R-Basic, R-Basic Large,
General Service Extra-Small and the Small General Service, which were derived through the settlement
compromise process, are not cost-based or cost justified, and that only SWEEP's proposed BSCs are
c0st.jusrified."'5 SWEEP disagrees with APS that the purpose of the Bscs should be to reflect the
larger category of fixed costs of service.'°" SWEEP argues that only costs that vary with the number
of customers should be used to determine the BSC, and not all the larger category of fixed costs, which
do not vary with the number of customers.'°7 SWEEP criticizes the Settlement Agreement BSCs
because they include some distribution costs, and some costs that are not customer related.I°8 SWEEP
asserts that the Settlement Agreement BSCs should not include transformer costs, even though they are
near a customer's residence, because transformer size and the number of transformers are both based
on load, and not on the number of customers.'°° SWEEP asserts that the load a customer places on the
21
22
23
24
25
26
27
28
190 SWEEP Br. al 6, 15.
191 ld. at 15.
192 Id. at 5.
193 Id. at 14 citing to Hearing Exhibit SWEEP-8A.
194 SWEEP Br. at 5.
195 ld. at 10, SWEEP Reply Br. at 5
1%SWEEP Br. at 910, SWEEP Reply Br. at 4-5 citing to Tr. at 341 (APS witness Miessner) and l 122-23 (SWEEP witness
Schlegel).
197 SWEEP Br. at 9-10, SWEEP Reply Br. at 5, citing to Tr. at 341 (APS witness Miessner) and 1 122-23 (SWEEP witness
Schlegel).
ws SWEEP Br. at 9, SWEEP Reply Br. at 4, citing to Hearing Exhibit APS-32 (APS Data Response Staff5.23) and Hearing
Exhibit SWEEP-3 (Direct Testimony of Jeff Schlegel on the Settlement Agreement) at 6.
199 SWEEP Br. at 9.
7629537DECISION no.
DOCKET no. E-01345A-]6-0036 ET AL.
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system can vary greatly, depending on how much energy a given customer can consume (such as, for
instance, the difference between a small apartment residence load and a 10,000 sq. ft. residence load).200
SWEEP states that the customer costs included in its proposed BSCs are based on FERC
accounts and account numbers consistent with the Uniform System of Accounts for Public Utilities
("USOA").2°l SWEEP summed the customer costs contained in the FERC USOA accounts for APS's
meters, meter reading, billing, and customer services costs in order to reach its recommended BSCs.202
SWEEP states that it included APS's costs for the appropriate FERC USOA plant and expense
accounts.203 SWEEP contends that the end result of its BSC analysis is "an objective and evidence-
based, bottom-up summation of the appropriate customer costs as the basis for the BSCs."204 SWEEP
contends that the Basic Service Method it used to calculate its proposed BSCs is based on cost causation
and is the only equitable method for calculating Bscs.205
12 AARP2.
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14
15
16
17
18
19
20
AARP opposes the Settlement Agreement's proposed BSCs, stating that it is concerned by the
"dramatic increase in the fixed charge for most R-Basic customers to S l5.00."206 AARP contends that
the BSC for R-Basic customers should be set at $10.00, or no higher than $13.00 per month, with the
energy rate adjusted accordingly.2°7 AARP states that such a change to the Settlement Agreement rate
design "would be a very minor adjustment, a change that leaves APS revenue neutral. But nonetheless,
it would be a change that could result in significant savings for many customers."208 AARP states that
this would make the R-Basic BSC more comparable with the Settlement Agreement proposed BSC for
TOU customers.2°°
21 AARP is not requesting any change to the Settlement Agreement proposed BSCs for R-Basic
22 Large customers of $20.00, or the Settlement Agreement proposed BSCs for R-XS customers of
23
24
25
26
27
28
200 Id.
201 SWEEP Br. at 89, SWEEP Reply Br. at 4, citing to Hearing Exhibit SWEEP-5 and Tr. at l 1251 128 (SWEEP witness
Schlegel).
202 SWEEP Br. at 9 SWEEP Reply Br. at 4,citingto Tr. at 1124-1128 (SWEEP witness Schlegcl).
203SWEEP Br.at 9 SWEEP Reply Br. at4, citingtoTr.at 1124-1 128 (SWEEP witness Schlegel).
204 SWEEP Br. at 9, SWEEP Reply Br. at 4, citing to Tr. at l128 (SWEEP witness Schlegel).
205 SWEEP Br. at 7, SWEEP Reply Br. at 3.
206 AARP Br. at 3.
207 AARP Br. at 3-6.
208 AARP Br. at 6.
209 AARP Br. at 6.
76295DECISION no.38
DOCKET no. E-01345A-16-0036 ET AL.
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$ l0.00.210 AARP believes that "[c]harging residential customers too much in the BSC, limits the ability
of those customers to control their monthly bills and reduces the incentive for energy efficiency and
energy conservation measures, especially for low usage customers."2" AARP agrees with SWEEP's
position that the BSC should include only direct costs which vary with the number of customers on the
system, including meters, billing, the service drop, and customer installation expense,2I 2 and believes
that SWEEP's methodology would produce a much lower BSC than the Settlement Agreement
Proposal.2'3 AARP contends that the BSC proposed in the Settlement Agreement for R-Basic
customers does not meet the ratemaking principles of public acceptability, gradualism, or simplicity.214
Mr. Woodward3.
10 Mr. Woodward supports the arguments of AARP and SWEEP to lessen the BSCs on standard
l l rates.2l 5
12 4.APS
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APS asserts that the Settlement Agreement's tiered BSCs are reasonable, cost-based, further
good rate policy, and are consistent with prior Commission Decisions.2"' APS contends that the non-
settling parties' objections to the BSCs agreed upon by the Settling Partics overlook actual fixed costs
incurred to serve customers, and due to Distributed Generation, placing hied costs in volumetric rates
unduly risks exacerbating the cost shift.2'7 APS states that the Settlement Agreement rate design would
reduce BSCs for more than 50 percent of APS's customers.2'8 APS contends that it incurs
approximately $28 per month in fixed costs to serve its customers, as measured by the straight Basic
Customer Method,2I° and that the Settlement Agreement BSCs reflect compromises with a diverse
21
22
23
24
25
26
27
28
210 AARP Br. at4.
211AAPR Br. at 4, citing to Hearing Exhibit AARP-l (Direct Testimony of John B. Coffman on the Settlement Agreement)
at 3, AARP Br. at 5.
212 AARP Br. at 5, citing to Hearing Exhibit SWEEP-3 (Direct Testimony of Jeff Schlegel on the Settlement Agreement)
at 6.
213 AARP Br. at 5.
214 AARP Br. at 5.
215 Woodward Br. at 42, Reply Br. at 23.
216 APS Br. at 61-66, APS Reply Br. at 7-10.
217 APS Br. at 61-66.
218 ld. citing to Tr. at 299 (APS witness Lockwood) and 1153 (SWEEP witness Schlegel).
219 APS Br. at 62 citing to Tr. at 802 and 845 (APS witness Snook) APS Reply Br. at 8, referring to Hearing Exhibit APS-
32 (the range by residential rate is between $24 and $34, and includes revenue cycle costs, such as metering billing,
customer service and certain distribution related costs).
76295DECISION no.39
DOCKET NO. E-01345A-l6-0036 ET AL.
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group of interests represented by the Settling Parties. APS contends that any BSC below $28.52 is
cost-justified, regardless of SWEEP's assertions to the contrary.220
Customers receiving an increase in their BSC under the Settlement Agreement are free to
4 choose the new TOU-E rate or a time-based demand rate, which have BSCs of $13 in addition to
5 providing an opportunity to save money by shitting usage.221 Additionally, the Settlement Agreement
6 increases and simplifies assistance to low-income customers.222
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APS criticizes SWEEP's calculation of BSCs because it omits the costs of service drops and
customer facilities, both of which should be included when calculating a BSC under the Basic Customer
Method.223 APS points out that SWEEP's witness acknowledged that the Settlement Agreement's R-
Basic BSC charge does not recover all APS's fixed costs.224 APS asserts that SWEEP's position also
overlooks the fact that because residential DG customers self-supply a portion of their volumetric
needs, if recovery of fixed costs is left in volumetric rates instead of moved to BSCs, costs will be
shifted to residential customers without DG, including limited income customers.225 APS states that
the dynamic caused by the integration of DG limits the flexibility of policy decisions regarding the
nature and size of basic service charges.226
APS notes that neither SWEEP nor AARP contest the agreed upon revenue requirement, but
that they are contesting only the allocation of costs between the BSCs and volumetric energy charges
for the higher-usage customers on standard, non-time differentiated rates.227 APS responds that the
BSCs agreed to by the Settling Parties are cost-based, designed to recover fixed costs in a fair manner,
and are supported by the evidence.228 In response to SWEEP's claims that some customers could
experience larger bill impacts than average, APS acknowledges that even using the best rate design
practices, sometimes customers within a class, or near the border between two rate classes, will
experience anomalous results, but such anomalies do not render a rate structure unfair, provided that
24
25
26
27
28
220 APS Reply Br. at 8.
221 APS Br. at 63.
222 APS Br. at 63, citing to Settlement Agreement Sections 29.1-29.3 (pages 26-27).
223 APS Br. at 64, citing to Tr. at 801-802 and 843844 (Aps witness Snook).
224 APS Br. at 64-65, citing to Tr. at l 153 (SWEEP witness Schlegel).
225 APS Br. at 65-66.MMmM
227 APS Reply Br. at 7.
228 ld.
76295DECISION no.40
DOCKET NO. E-01345A-I6-0036 ET AL.
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the overall impacts to the majority of customers are fair and reasonable.22° APS believes that the
support of the Settlement Agreement by a broad range of diverse customer interests attests to the fair
and balanced nature of the rate design, and asserts that SWEEP's claims do not provide a reason to
condemn the entire structure of the BSCs, but instead strengthens the case for offering a strong and
effective customer education program regarding the transition to the new rate structure.230
APS asserts that the Settling Parties in this case are proposing a BSC structure consistent with
that the Commission recently adopted in Decision Nos.75697 (August 18, 20l6)(UNS Electric, Inc.
("UNSE") Rates) and 75975 (February 24, 2017) (TEP Rates), in order to address the changing load
characteristics of the residential customer class.1 The BSC structure includes higher BSCs for higher-
10
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14
15 5.
16
17
18
19
20
21
22
23
24
usage customers who choose to stay on standard two-part rates, in order to incept them to move to
time- or demand-differentiated rates. APS argues that SWEEP's proposal for BSCs that collect the
"bare minimum" of costs through the BSCs goes against the Commission's policy adopted in the recent
UNSE and TEP Rate Decisions to incentivize customers to try rate plans that can benefit them with
cost savings on their bills and potential system peak reduetions.232
MQ
AIC submits that to keep up with the evolution of the electric power grid, utility rate design
must evolve too, and that rates need to provide a utility with an opportunity to recover its fixed costs
while also allowing customers options for installing cost-effective behind-the-meter technologies that
offer them an opportunity to save energy and money.233 AIC contends that the Settlement Agreement
rate design appropriately uses the BSC to recover fixed costs while at the same time acting as a price
signal to influence customer choice of rate plans.234 AIC explains that charging a lower BSC for time-
differentiated or time and demand-differentiated rate plans was deliberate on the part of the Settling
Parties, in order to incentivize customers to choose such a plan, and to send a more accurate price signal
to a greater number of customers.235 AIC points out that if the Commission were to change the BSCs
25
26
27
229 APS Rely Br. at 9-10.
230 ld. at 10.
231 APS Reply Br. at l l, citing to Decision No. 75697 at 64, 66 and Decision No. 75975 at 64.
232 APS Reply Br. at 12.
233 AIC Br. at 1; AIC Reply Br. at 3.
234 AIC Br. at 5.
28 235 ld. at 6, citing to Tr. at 171 (APS witness Lockwood).
41 DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
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to a lower dollar amount as advocated by some parties, the energy rate would have to increase
accordingly,23" and stresses that putting cost recovery into the energy rate would exacerbate the shifting
of cost recovery from those with consumption-lowering behind-the-meter technologies to those without
such technoIogies.237 AIC contends that the Settlement Agreement rate design reached an equitable
balance, and that neither SWEEP's nor AARP's arguments to decrease the BSC warrant altering the
Settlement Agreement at the expense of reducing the total benefit to all ratepayers.
AIC points out that SWEEP's and AARP's arguments overlook the fact that a customer with
concerns about the BSC of a rate plan has a number of other rate plan options from which to choose.
AIC believes that the compromise reached in the Settlement Agreement regarding BSCs is a balanced
approach and should be adopted.238
ConservAmerica6.
12
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17
ConservAmerica asserts that the current two-part rate design, which is focused on kph sales
for cost recovery, is broken in that it no longer makes sense from a social equity standpoint or from a
cost-causation standpoint at a time when rooftop solar and other new technologies decrease billed kph
without reducing the fixed costs of the utility system.23° ConservAmerica is concerned that because of
the current decline in kph (energy) sales, placing additional fixed costs in the energy usage charges
"shifts these fixed costs from wealthier rooftop solar customers to poorer non-solar customers,"24° and
18
19
"will only enhance the growing inequities as more affluent customers adopt new technologies to limit
or eliminate their kph, while other customers are left behind to bear the costs."241 ConservAmerica
20
21
states that the amount of the fixed charges included in the BSCs is a matter of policy, and that there is
no dispute that APS's fixed costs this proceeding.
22
exceed any of the proposed BSCs in
ConservAmerica argues that in a time when some customers have very little kph usage but still cause
23 significant fixed costs, fairness requires a BSC that adequately recovers fixed costs.
24
25
26
27
28
236 AIC Br. at 6, citing to Tr at 314 (APS witness Lockwood).
237 AIC Br. at 6
238 Id.
239 ConservAmerica Br. at 2, citing to Hearing Exhibit ConservAmerica-2 (Direct Rate Design Testimony of Paul Walker)
at 2 10.
240 ConservAmerica Br. at 2, citing to Hearing Exhibit ConservAmerica-2 (Direct Rate Design Testimony of Paul Walker)
at 15.
241 Consent/America Reply Br. at 3.
76295DECISION no.42
DOCKET NO. E-01345A-16-0036 ET AL.
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ConservAmerica points out SWEEP's acknowledgement that under the Settlement Agreement,
a majority of customers will see a reduction in their Bsc$.242 In response to SWEEP's concerns of the
impact of increases in BSCs on R-Basic and R-Basic Large customers, ConservAmerica states that the
intent of the Settlement Agreement's higher BSCs for those rate plans is to encourage customers to
move to time-differentiated or demand-differentiated rates and change their consumption behavior,
which will benefit all customers by reducing system peak, thereby creating emissions and cost savings
for everyone.243 ConservAmerica contends that, as acknowledged by SWEEP's witness, moving from
basic two-part rates to such rate plans will actually allow customers multiple opportunities to control
their be, while reducing costs.244
ConservAmerica states that the Settlement Agrecment's R-Basic BSC of$ l5 is the same as that
approved for UNSE, and less than the $20 BSC for the comparable rate charged by Salt River Project
("SRP").245 ConservAmerica points out that, as acknowledged by AARP's witness, the higher BSC
for the R-Basic rate plan is an incentive for customers to move to TOU and demand rate plans, as the
Commission approved in the recent UNSE rate Decision.246 In response to AARP's contention that a
reduced BSC would be revenue neutral, ConservAmerica states that this is so only when considering
the test year billing determinants in this case.247 ConservAmerica states that as kph sales continue to
fall, it would not be revenue neutral, and more fixed costs would go unrecovered, necessitating a larger
revenue requirement to be recovered in the next rate case.248
19 Vote Solar7.
20
21
22
Vote Solar contends that the seven different residential rate options in the Settlement
Agreement, which would replace Vote Solar's preferred standard tiered rate, when considered with the
balance of issues addressed by the Settlement Agreement, are reasonable and in the public interest.24°
23
24
25
26
27
28
242 Id. at 4, citing to Tr. at l 15152 (SWEEP witness Schlegel).
243 ConservAmerica Br. at2 citing to Tr. at 1264-65 (Staff witness Abinah), ConscrvAmcrica Reply Br. ate.
244 ConservAmerica Reply Br. at 4, citing to Tr. at l 151-52 (SWEEP witness Schlcgcl).
245 ConservAmerica Br. at 3~4, citing to Hearing Exhibit ConservAmerica4 (Rebuttal Testimony of Paul Walker on the
Settlement Agreement) at 5-6.
246 ConservAmerica Br. at 3, citing to Tr. at 707 (AARP witness Coffman).
247 ConservAmerica Reply Br. at3.
248ld.at3-4.
24<>VoteSolar Br. at 7.
76295DECISION no.43
DOCKET no. E-01345A-16-0036 ET AL.
l AURA8.
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9 9.
AURA states that it was concerned with APS's original proposals for mandatory three-part
demand rates and high BSCs for residential customers, but that the Settlement Agreement resolved
these concerns, with no mandatory demand rates for any residential ratepayer, and with many more
rate design options for residential customers. AURA's witness testified that the "modest increases to
basic service charge for customers under 600kWh/month and actual reductions to service charges for
TOU and three-part-rate customers more than offset the larger (though lower than initially proposed)
increases for customers using more than 600kWh/month." 250
ACAA
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ll
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16
ACAA states that the Settlement Agreement rate design provides a marked improvement over
APS's initial request, in that it has no mandatory demand charges, but instead gives customers the
option to enroll in a demand charge rate or not, and it has much lower BSCs for the R-XS rate than
APS initially requested. ACAA notes that the BSC for R-XS is $10 under the Settlement Agreement,
decreasing from $18. ACAA states that high BSCs affect low-income customers especially hard,
because theaverage low-income customer uses less energy than the average non-low-income customer,
and that the R-XS rate will allow low-income customers to better manage their bills.251
17 FEA10.
18
19
20
2]
FEA believes that the spread of the revenue increase across customer classes represents a
reasonable compromise on complex cost of service issues, and that the ultimate rates for retail
customers proposed by the Settlement Agreement are reasonable.252
11.
22
23
24
25
RUCO
RUCO states that while it does not dismiss the concerns raised by AARP and SWEEP on this
issue, RUCO sees it from a different perspective. RUCO believes that the increase to the R-Basic rate
is outweighed by the other benefits of the Settlement Agreement.253 RUCO asserts that: l) the focus
by AARP and SWEEP on the increase to the BSC for R-Basic customers ignores the overall bill impact
26
27
28
250 AURA Br. at 23, citing to Hearing Exhibit AURA-3 (Direct Testimony of Patrick Quinn on the Settlement Agreement)
at 4-5, 6.
251 ACAA Br. at 2-3.
252 FEA Br. at 6.
253 RUCO Br. at 5.
7629544DECISION no.
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after the energy usage component is factored in, 2) the number of customers currently on rate plans
equivalent to the R-Basic and R-Basic Large rate together constitutes a small percentage of APS's
residential customers (approximately 18 percent) while approximately 82 percent will see either a
decrease or a very small increase in their BSC,254 3) the Settlement Agreement BSC rate design is
consistent with Commission precedent in recent rate cases for TEP and UNSE, where the Commission
decided to incentivize customers to move to a TOU rate,255 and 4) R-Basic customers who prefer a
lower BSC have a variety of options from which to choose.256
12.Staff
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Staff contends that the arguments of AARP and SWEEP in opposition to the BSCs proposed in
the Settlement Agreement are not compelling.257 Staff contends that AARP's criticism of the R-Basic
BSC is without evidentiary support, other than AARP's opinion that $13 is "too high" and "higher than
similar customers must pay under the most recent Arizona Commission decisions changing rates for
UNS and TEP."258 Staff points out that at the hearing, AARP's witness acknowledged that UNSE
currently has a $15 BSC for most residential customers.25°Staff also points out that AARP
acknowledged that there are many components of the Settlement Agreement that would be beneficial
to AARP membership in Arizona, that there are AARP members with various energy usage levels, that
there are low-income AARP members who stand to benefit from the continuation and expansion of the
low-income programs contained in the Settlement Agreement, and that AARP has acknowledged that
several of the residential rate design provisions are appropriate, and AARP takes no issue with them.260
Staff states that SWEEP's position 1) overlooks the fact that the Settlement Agreement rate
design continues to recover a significant portion of customer bills through volumetric charges that
customers can reduce through efficiency measures, and 2) fails to address the cost recovery concerns
of the utility or the necessary balancing of the wide-ranging interests accommodated by the Settlement
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25
26
27
28
254 RUCO Br. at 5-6
255 Id. at 6, citing to Decision No. 7596 at 65-66 and Decision No. 75975 at 64.RUCO points out that the $15 BSC in the
UNSE case for a similar rate plan is the same as that proposed here in the Settlement Agreement.
256 RUCO Br. at 6.
251 Staff Br. at 21-22, Staff Reply Br. at 2-3, 6.
258 Staff Br. at 2 l, citing to Hearing Exhibit AARP-l (Rebuttal Testimony of John B. Coffman on the Settlement Agreement)
at 4.
259 Staff Br. at 2 l, citing to Tr. at 706-07.
zoo Staff Br. at 20.
7629545DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
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Agreement.26'Staff states that SWEEP attempts to justify its recommendation for lower BSCs by
focusing on the percentage increases in the BSCs instead of on the overall bill impact percentage of the
rate increase on customers. Staff explains that while on its face, some of the percent increases to the
BSCs appear to be large, it is important to consider the overall rate increase impact of4.54% for the
average residential customer, pointing out that SWEEP does not take issue with the overall rate
increase, or with the fact that APS incurs the costs included in the Settlement Agreement BSCs.
Staff notes that SWEEP is a nonprofit agency that advances its energy efficiency goals, and that its
"narrowly focused advocacy promoting energy efficiency" drives SWEEP's proposal to put most of
the rate increase into volumetric charges.2°3 Staff points out that the Settlement Agreement rate design
utilizes the same two methods, the Basic Customer Method and the Minimum System Method to
calculate the BSCs that the Commission relied on to inform its policy decision in the recent TEP Rate
Decision.264 Staff states that while it would agree with SWEEP that BSCs should not be set based on
what has been authorized for other electric utilities, a comparison to other Arizona electric utility BSCs
can be an appropriate benchmark or factor to consider, among others.2"5
Staff contends that the rates as structured in the Settlement Agreement, including the BSCs,
properly balance the needs of customers' continued ability to save through energy efficiency with the
need for APS to better recover its authorized revenue requirement, and that the Settlement Agreement
18 should be approved without modification.
19 13.Resolution
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22
Alter examination of the evidence and the legal arguments on this contested issue, we find that
the BSCs set forth in the Settlement Agreement reasonably and appropriately balance the interests of
the ratepayers and the Company, and are in the public interest.
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261 Id. at 23, Staff Reply Br. at 3.
262 Staff Reply Br. at 2-3.
263 Staff Br. at 23, Staff Reply Br. at 3.
264 Staff Br. at 22-23, Staff Reply Br. at 2, citing to Decision No. 75975 at 64.
265 Staff Reply Br. at 3.
7629546DECISION no.
DOCKET no. E-01345A-l6-0_36 ET AL.
l ii.Choice of Rate Plan / 90-Day Trial Period
2 Section 19.1 of the Settlement Agreement provides as follows:
3
4
5
6
7
All customers may select R-Basic, R-Basic Large, TOU-E, R-2, R-3, R-Tcch or R-XS
if they qualify until May l, 2018, except to the extent grandfathered under other sections
of this Settlement Agreement. Distributed Generation customers will not be eligible for
R-XS, R-Basic or R-Basic Large. After May l, 2018, R-Basic Large will no longer be
available to new customers or customers who are on another rate. New customers alter
May 1, 2018 may choose TOU-E, R-2, R-3 or if they qualify, R-XS or R-Tech. After
90 days, new customers may opt-out of their current rate and select R-Basic if they
qualify. Customers transitioning to R-Basic must stay on that rate for at least 12
months.2668
SWEEP1.9
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9927017
18
AARP
SWEEP proposes that the Settlement Agreement's 90-day trial period for new customers be
eliminated.267 SWEEP believes that on their first day as an APS customer, customers should be allowed
to choose their rate plan from among options for which they are eligible, without waiting 90 days.268
SWEEP proposes that if the Commission approves the 90-day waiting period, the Commission should
also require APS to notify customers of all rates available to them at the end of the 90-day period.26°
In response to APS's assertion that a significant majority of customers will save money on the
new rates, SWEEP responds "[i]fthat is true, then customers will choose the rates that save them the
most money.SWEEP believes that with incentives for customers to move to time-of-use rates, the
90-day trial period is not justified.27'
2.19
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22
AARP opposes any limits on the availability of residential rate design options as proposed in
Section 19.1 of the Settlement Agreement.272 AARP requests that the Commission reject the provision
in the Settlement Agreement that precludes new customers, after May l, 2018, from choosing the R-
Basic rate plan until after first taking service under a TOU plan for a period of 90 days2273 AARP23
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25
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28
zoo Settlement Agreement Section 19.1 (page 20).
267 SWEEP Br. at 5, 16, SWEEP Reply Br. at 7.
268 SWEEP Br. at 6; SWEEP Reply Br. at 7.
zoo SWEEP Br. at 17, SWEEP Reply Br. at 8.
270 SWEEP Reply Br. at 7.
271 ld.
272AARP Br. at 3.
273 Id. at 6, 8.
76295DECISION no.47
DOCKET no. E-01345A-16-0036 ET AL.
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asserts that the 90-day trial period "is unnecessarily complicated and confusing, and it would prevent
many customers from choosing the rate option that they believe is the best plan for them."274 AARP
argues that the 90-day trial period for new customers "would create a policy of discriminatory treatment
towards new customers and would also create a high bonier for switching to a Basic rate plan later."275
AARP contends that the 90-day trial period "would likely be confusing and frustrating for the affected
customers, creating the need for considerable customer education."27"
AARP alludes to "extreme difficulty" that a customer would face in attempting to switch to an
R-Basic plan after the 90-day trial period, and states that AARP would expect most customers to be
"confused about how to switch alter 90 days."277 AARP claims that "[i]t appears that the proposed 90-
day provision is an attempt by APS to divert large numbers of unwitting residential customers onto a
demand Iate.»»278
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19 Mr. Gaver
AARP is concerned that the Settlement Agreement lacks specificity regarding how customers
will be notified of their choice to change rate plans after the 90-day trial period has elapsed.279 AARP
proposes that if the 90-day trial period is adopted, APS be specifically required to provide written
notification to new customers as to all of the rate options that will be available to them, including R-
Basic, oNer the 90-day trial period has elapsed.280 In addition, AARP proposes that APS be required
to notify new customers at or about 90 days after they begin taking service on a TOU or Demand Rate
plan of their eligibility to switch to an R-Basic plan.281
3.
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Mr. Gayer contends that the Settlement Agreement's 90-day trial period for new customers is
discriminatory under A.R.S. § 40-334, would violate new customers' due process rights, and would
constitute a form of consumer fraud under A.R.S. § 44-1521 HZ Seq.282 Mr. Gayer believes new
customers should be allowed to choose from any rate for which they qualify when they become a new
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274 Id. al 8.
275 ld.
276 Id.
277 AARP Br. at 7.
278 AARP Br.at 7.
279 ld.
280 Id..al 9.
281 Id.
282 Gayer Br. at 9-12.
7629548DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
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customer and should not be required to take service for a 90-day trial period on a time-based rate.283
Mr. Gayer proposes that if the Commission approves the 90-day trial period, APS should be required
to inform new customers of their options sufficiently before the 90 days have passed so that their newly
chosen rate will be effective on the date that the 90-day period expires.284
5 Mr. Woodward4.
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9
Mr. Woodward asserts that the 90-day trial period for new customers to take service under TOU
or demand rates is unjust because he believes they are unaffordable for some customers, and that it
should be removed. 285 He supports the arguments of AARP and SWEEP to remove the 90-day trial
period but if approved, to hold APS accountable for effective customer notification as to their options
10 alter the 90-day trial period. In addition, Mr. Woodward contends that APS should not receive $5
l l million to use for customer education on the new rate design proposals in the Settlement Agreement.28°
12 5.
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APS believes that AARP and SWEEP, in their opposition to the 90-day trial period provision
of the Settlement Agreement, fail to consider the importance of how customer rate choices impact all
customers and the system as a whole,287 and that they fail to consider the balance that was struck in the
Settlement Agreement between parties with widely divergent views.288 APS states that the 90-day trial
period in the Settlement Agreement would expose new customers to modem rates that are time- or
demand-differentiated while still allowing them to move to rates that are not time- or demand-
differentiated at the end of the 90-day trial period, when they will have a minimum of three rate plan
choices.289 APS states that data shows that a significant majority of APS customers will save money
on time- or demand-differentiated rates, with savings occurring even before customers modify their
behavior and shift usage.290 However, customers whose average monthly usage is 600 kph or below
are less likely to benefit as much from timc- or demand-differentiated rates, and the terms of the
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283 Gayer Br. at 15 Gayer Reply Br. at 9.
284 ld.
285 Woodward Br. at 4 l ,42 citing to Hearing Exhibit Woodward- l generally (Direct Testimony of Warren Woodward) and
Hearing Exhibit Woodward-6 generally (Direct Testimony of Warren Woodward on the Settlement Agreement).
286 Woodward Br. at 42.
287 APS Reply Br. at 57.
28s ld. at 6.
289 APS Br.at 56,57.
290Id., APS Reply Br. at 5, citing to Tr. at 858-60 (APS witness Snook).
DECISION NO.49 76295
DOCKET NO. E-01345A-16-0036 ET AL.
l Settlement Agreement therefore exempt these low-usage, R-XS customers from the 90-day trial
2 period.2°I
3
4
APS believes it is important to balance the benefits that accrue to all customers from time- and
demand-differentiated rates with individual customer choice.2°2 APS describes the benefits as follows:
5
6
7
When customers react to rates that are time-differentiated, and in particular rates with
demand components, they shift load to off-peak periods, taking service when there is
excess supply and capacity. This not only permits short-term cost savings with lower
fuel costs, but also the possibility that APS can avoid building new infrastructure to
meet growing peak demand."
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APS states that the 90-day trial period for new customers that the Settling Parties agreed to is a
compromise position designed to achieve a balance.2°4 While the 90-day trial period does not adopt
the outcome sought by those who are opposed to any changes to APS's rate design, neither does it
adopt the outcome sought by APS that all customers take service on time-differentiated demand
rates.2°5 APS contends that the Settlement Agreement 90-day trial period provision establishes a more
moderate path towards implementing time- and demand-differentiated rates than APS's initial
proposal, and that part of the moderation involves customers being able to return to the R-Basic rate
after the 90-day ma1.2""
APS takes issue with AARP's arguments that the 90-day trial period would "likely be confusing
and frustrating for the affected customers,"2°7 and AARP's assertion that customers would prefer a
basic rate plan. APS posits that AARP's position that a TOU or demand rate could be detrimental to
customers lacks evidentiary support, and likely reflects national, and not local interests. APS states that
AARP does not represent the concerns of local seniors groups such as PORA in Sun City West, and
SCHOA in Sun City, both of which are signatories to the Settlement Agreement. 298 And APS points
to the admission by AARP's witness that AARP never gathered data from its constituents regarding
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27
28
291 APS Br. at 57.
292 ld. at 58.
293 Id., referring to Hearing Exhibit APS-7 (Rebuttal Testimony of Charles Miessner on the Settlement Agreement) at 12
13.
294 APS Br. at 58 Reply Br. at 6.
295 APS Br. at 58.
z96 ld. at 7-8, Reply Br. at 6.
297 APS Reply Br. at 5, citing to AARP Br. at 8.
298 APS Reply Br. at 5.
76295DECISION no.50
DOCKET NO. E-01345A-16-0036 ET AL.
l
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4
whether they would prefer lower overall bills, or a simpler bill structure.2°° APS believes that the fact
that over half of its customers are already on a TOU rate demonstrates that APS customers have the
ability to adapt to and manage time-differentiated rates, and that there is no basis for an assumption
that future APS customers will be less sophisticated.3°°
5 AIC6.
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8
9
AIC contends that, in contrast to the characterization by AARP of "taking away" customer
choice, the Settlement Agreement provides a choice of seven residential rate options, and balances
customers' individual interests and customer choice with the benefits that moving all customers toward
time-differentiated and demand-differentiated rate plans would provide." I
10 ConservAmerica7.
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ConservAmerica believes that the Settlement Agreement rate design, of which the 90-day trial
period for new customers is an integral part, is fairer than the current rate design, is a sensible limitation,
because it applies only to new customers, and only for a limited time, will promote reductions in costs
and emissions, and should be approved. ConservAmeriea asserts that providing new customers with
experience on time-differentiated and demand-differentiated rate plans, after customer education, will
benefit those customers because many will save money, while beginning to provide the benefits for all
customers - lower costs, reduced emissions, and reduced inequities - that will come from having more
customers taking service under the TOU or demand rate plans, and modifying their usage patters
accordingly.3°2 ConservAmerica agrees with Staff that 90 days is an appropriate time period to provide
customers with their usage data so that they can determine which rate plan is better for them.303
In response to Mr. Gayer's argument that the 90-day trial period would violate due process,
ConservAmerica responds that adequate public notice was provided which more than satisfied any due
process tequif¢men[s304
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25
26
27
28
299 Id.citing to Tr. at 724 (AARP witness Coffman).
300 APS Reply Br. at 5-6.
301 AIC Reply Br. at 3.
302 ConservAmerica Br. at 4, ConservAmerica Reply Br. at 5.
303 ConservAmerica Br. at 4, citing to Tr. at 1268 (Staff witness Abinah).
304 ConservAmerica Reply Br. at 5. ConservAmerica asserts that there are no constitutional or statutory provisions requiring
notice of setting utility rates. ConservAmerica Reply Br. at 4-6 citing to Appeal Q/Office QfConsumerAdvocate 803 A.2d
1054, 1059 (N.H. 2002), and referring to Arizona Corp. Comm n v. Tucson Ins. & Bonding Agency, 3 Ariz. App. 458 463
76295DECISION no.51
DOCKET no. E-01345A-16-0036 ET AL.
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ConservAmerica responds to AARP's statement on brief that public comments oppose
"mandatory demand charges," pointing out that the terms of the Settlement Agreement do not require
any customer, including new customers in the 90-day trial period, to take service on a demand charge
rate p1an.305
5 RUCO8.
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RUCO believes that new customers will not be disadvantaged by the 90-day trial period before
they can sign up for the R-Basic rate plan because: 1) there are new rate plans available to choose from,
2) those rate plans have BSCs that are either decreasing from present BSCs or increasing only slightly,
and 3) the new TOU options, with lower BSCs, will provide the new customers with more control over
the variable portion of their bills than does the R-Basic rate plan. RUCO asserts that having new
customers try a TOU option for 90 days will result in more customer control, energy efficiency, and
will better reflect cost causation, and that customers will have the choice to go to the R-Basic plan otter
the 90-day trial period if they wish to do 50.306
Staff9.
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Staff states that the purpose of the 90-day trial period is to encourage the implementation of
newer and updated rate designs going forward. Staff believes that inclusion of the 90-day trial period
for new customers strikes an appropriate balance in that it gives customers options with respect to rate
plans while also providing a reasonable means for APS to educate customers on new updated rate
designs.3°7
Staff agrees with the proposals of SWEEP and AARP that APS be required to notify customers
near the end of the 90-day period about their option to switch to another rate,3°8 and that such
notification should be accompanied with information on the estimated bill impact of switching to
another rate.309 Staff states that the Settlement Agreement already provides that APS will expend $5
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28
415 P.2d 472, 477 (1966),Walker v.De Concini,86 Ariz. 143 148, 341 P.2d 933, 937 (1959); Arizona Administrative
Code ("A.A.C.") R142105(B) and A.A.C. R143-109(B).
305 ConservAmerica Reply Br. at 4, citing to AARP Br. at 15 and to Settlement Agreement at Section 191 (page 20).
306 RUCO Br. al 7.
307 Staff Reply Br. at 5.
308 Staff Reply Br. at 5, 6 citing to SWEEP Br. at 17, AARP Br. at 9-10, and Hearing Exhibit S-12 (Rebuttal Testimony of
Ralph Smith on the Settlement Agreement) at 9.
309 Staff Reply Br. at 5, citing to Hearing Exhibit S-12 (Rebuttal Testimony of Ralph Smith on the Settlement Agreement)
at9.
76295DECISION NO.52
DOCKET NO. E-01345A-16-0036 ET AL.
1
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5
million of over collected DSMAC funds toward ratepayer education to help them understand and
manage new rates and rate options, and that Staff sees no inconsistency with the Settlement Agreement
if the Commission were to order APS to develop a notice as part of its customer education program to
inform new ratepayers subject to the 90-day trial period of their rate options at the conclusion of the
trial period.310
6 Resolution10.
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After examination of the evidence and the legal arguments on this contested issue, we find that
the 90-day trial period for new customers as set forth in the Settlement Agreement is in the public
interest. Notably, however, the Settlement Agreement provides at most an eight-month window for
customers who are on another rate to evaluate several new rate plans.We find there is sufficient
evidence in the record and it is in the public interest for existing customers to have additional time to
12
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adequately consider the R-Basic Large plan. We therefore recommend that the sunset for R-Basic
Large be modified as follows: "After September 1, 2018, R-Basic Large will no longer be available to
customers who are on another rate."
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25
Educating customers about the energy efficiency effects of both time-differentiated and
demand-differentiated rate plans will encourage customers to be cognizant of efficient energy use. This
customer knowledge will ultimately benefit all APS customers. For new customers, a short trial period
on their choice of either a time- or demand-differentiated rate is reasonable, in order to demonstrate
how they can manage their usage in order to better control their bills.The 90-day trial period
reasonably and appropriately balances the goal of increased energy efficiency with the customer
interest of having a variety of rate plans from which to choose, so that customers can decide, based on
specific facts particular to them, which rate plan works best for their individual circumstances.
Arguments have been advanced regarding the lack of specificity in the Settlement Agreement
in regard to educating customers about their rate plan choices at the end of the 90-day trial period. The
Settlement Agreement provides that:
26 APS will make a one-time allocation of $5 million from over-collected DSMAC funds
to DSM programs for education and to help customers manage new rates and rate27
28 310 Staff Reply Br. at 67.
DECISION no.53 76295
DOCKET no. E-01345A-l6-0036 ET AL.
l
2
options including services and tools available to customers to help them manage their
utility costs.APS shall file an outreach and education plan and shall provide
stakeholders with an opportunity to review and comment on the draft plan prior to
completing its final plan. 31 1
3
The record does not support elimination of Section 27.1 of the Settlement Agreement. APS has
4 indicated that it is committed to making sure that customers are aware of their options, and that it will
5 notify customers through a variety of different channels and encourage customers to choose the rate
6 plan that works best for them.312 The evidentiary record supports the imposition of the following
7 specific requirement for the Settlement Agreement's customer outreach and education plan:
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The draft plan that APS files according to Section 27 of the Settlement Agreement shall
include a form of notice to inform new ratepayers subject to the 90-day trial period of
their rate options at the conclusion of the trial period, accompanied by information on
the estimated bill impact of switching to another rate, and shall address a suitable
method for delivery of such notice so that such customers will receive the notice shortly
after, or concurrently with, their second bill, in order to provide them with sufficient
notice should they wish to begin taking service at that time on the R-Basic rate plan
instead of a time- or demand-differentiated rate plan.
13
14
Because the Settlement Agreement does not set forth deadlines for the roll out of the customer
education plans, we will require APS to file a draft Customer Education and Outreach Program
15
("CEOP") in Docket Control within 15 business days of a Commission Decision in this matter. The
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CEOP should contain at a minimum, simple, easy to understand information regarding the new rate
plans, the transition plan, and the plans available after May l, 2018. Stakeholders will have 10 days
thereafter to review and comment on the draft plan. APS will have 10 additional days following the
review and comment deadline to submit a final plan for Commission Staff's consideration and
20
approval .
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The Settlement Agreement makes significant changes to the existing rate plans. We find that
it is in the public's interest to have adequate notice in a timely manner so customers can evaluate the
available plans before the deadline. The evidentiary record supports the imposition of the following
specific requirements for the Settlement Agreement's CEOP:
25
26
27
28
311 See Settlement Agreement Section 27.1 (page 24).
312See Hearing Exhibit APS-3 (Rebuttal Testimony of Barbara Lockwood on the Settlement Agreement) at 6, and Tr. at
251, 293 (APS witness Lockwood).
7629554DECISION no.
DOCKET NO. E-01345A-l6-0036 ET AL.
1 The draft CEOP should include a font of notice for both new customers and customers
who are on another rate.
2
3
For customers who are on another rate, the final approved notice must be provided to
the customers on another rate at least 3 billing cycles prior to May l, 2018, or the date
on which APS's new rate plans commence, whichever occurs later.
4
5
For both new customers and customers who are on another rate, the form of notice in
the dali CEOP shall inform the customers of their rate options after May l, 2018,
accompanied by information on the estimated bill impact of switching to another rate.
6
iii.Time of Use Hours
7
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9
The Settlement Agreement provides for TOU on-peak rates from 3:00 p.m. to 8:00 p.m. on
weekdays, excluding holidays.3l3 In addition, the Settlement Agreement provides for a Winter Super
Off-peak period from 10:00 a.m. to 3:00 p.m. weekdays during the winter months.3l4
10
SWEEP1.
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SWEEP proposes that the on-peak period for residential TOU rates be set for 4:00 p.m. to 7:00
p.m. instead.3'5 SWEEP contends that "[a] five-hour (3:00 pm to 8:00 pm) on-peak period virtually
mandates that Arizona families and other customers (e.g., homebound customers) will face high on-
peak charges without any real flexibility to move some activities and energy use to off-peak periods."316
SWEEP contends that "[t]he Commission should not set the on-peak period for 2020 or future
years in this rate case, that decision could be made and is more appropriately made in the next rate case
with the then-current facts available for consideration."3'7 SWEEP argues that APS's testimony
regarding its peak load shape shows that the three summer hours with the highest peak demand are
4:00 p.m. to 7:00 p.m.318 SWEEP asserts that if customers could shift some of their demand to hours
before 4:00 p.m., they would not increase the APS system demand between 4:00 p.m. and 7:00 p.m.3l9
SWEEP asserts that the shorter on-peak period it proposes would be attractive to more customers, and
additional customers would move to TOU rates.32°
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27
28
313 Settlement Agreement Section 17.8 (page 19).
314 Settlement Agreement Section 17.4 (page 18).
315 SWEEP Br. at 5, 15, SWEEP Reply Br. at 6.
316 SWEEP Br. at 15, citing to Hearing Exhibit SWEEP 4 (Rebuttal Testimony of Jeff Schlegel on the Settlement
Agreement) at 12.
3lv SWEEP Reply Br. at 7.
318SWEEP Br. at 16 and Reply Br. at 6, referring to Hearing Exhibit APS-7 (Rebuttal Testimony of Charles Miessner on
the Settlement Agreement) at 9, Figure l and to Tr. at 1137 (SWEEP witness Schlegel).
319 SWEEP Br. at 16, SWEEP Reply Br. at 7.
320 Id., citing to Tr. at 1138 (SWEEP witness Schlegel).
7629555DECISION no.
DOCKET NO. E-01345A-l6-0036 ET AL.
l AARP2.
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3
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5 Districts
AARP opposes the 3:00 to 8:00 p.m. on-peak period proposed in the Settlement Agreemcnt.321
AARP asserts that this late in the day peak period "will leave many seniors with less flexibility to adjust
their usage to find savings."322 AARP supports SWEEP's position.323
3.
6
8
The Districts assert that the Settlement Agreement's proposed time of use rates would be
7 "punishing for working families."324
4.
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APS contends that the Settlement Agreement's proposed 3:00 p.m. to 8:00 p.m. on peak time
period properly balances system realities with customer convenience, and that SWEEP's proposal
disregards actual system conditions and the policy goal ofintluencing prospective usage.325 APS states
that the Settlement Agreement reduces the number of on-peak hours, and adds more off-peak holidays,
compared to the present TOU tariffs, which have on-peak periods from 12:00 noon to 7:00 p.m. and
9:00 a.m. to 9:00 p.m.326 APS asserts that the Settlement Agreement on-peak hours are part of a
carefully crafted and balanced rate design agreed upon by the Settling Parties, and that failure to adopt
them has the potential to disrupt the balance and the result desired by numerous parties, particularly
the solar intervenors.327
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APS asserts that the Settlement Agreement on-peak hours are aligned with APS's highest
system peaks and costs,328 and that energy use during system peak should properly align with the costs
to provide that service.32° In contrast, the current TOU on-peak hours send customers the wrong
conservation message.330 APS's witness James Wilde explains that current on-peak times encourage
conservation at mid-day and early afternoon, when demand and wholesale prices are low, and energy
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321 AARP Br. at 3.
322 ld. at 3, 11.
323 ld. 81 11.
324 Districts Br. at 2 -3.
325 APS Reply Br. at 6
326 APS Br. at 58, citing to Tr. at 341 (APS witness Miessner) and Hearing Exhibit APSI9 (Direct Testimony of James
Wilde) at 12.
327 APS Br. at 61.
328 ld. at 58, citing to Tr. at 341 (APS witness Miessner).
329 APS Br. at 61 .
330 APS Br. at 5859, citing to Exhibit APS-19 (Direct Testimony flames Wilde) at 13-14.
76295DECISION no.56
DOCKET NO. E-01345A-16-0036 ET AL.
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abundant on the regional system, but not in the evening hours when system demand is peaking and
wholesale prices are high331
APS witness Charles Miessner included a graph in his refiled testimony showing APS's
System Summer Peak Hours.332 APS states that APS has a very broad peak, and that in the summer
months APS's load open remains within 5% of the peak hour for 4-5 hours, such that on-peak time
periods must run later in the evening.333 APS's witness testified that in the summer months particularly,
system peak is generally expected to occur between 7:00 p.m. and 9:00 p.m.334 APS projects that the
trend for later system peak loads will continue in the future.335
APS argues that TOU periods should not be set looking backward, but looking forward, in order
to maximize the benefits of energy conservation that occur when customers shift usage.33°APS
acknowledges SWEEP's argument that the Settlement Agreement's proposed 3:00 p.m. to 8:00 p.m.
on peak time period may be inconvenient for customers, but points out that the resulting shift in usage
by customers may allow APS to avoid or delay construction of new infrastructure, and the period is
shorter than existing on-peak time periods" APS asserts that the proposed 3:00 p.m. to 8:00 p.m. on
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331APS Br. at 58-59, citing to Exhibit APS-I9 (Direct Testimony of James Wilde) at 13-14.
332Hearing Exhibit APS-7 (Rebuttal Testimony of Charles Miessner on the Settlement Agreement) at 9, Figure l.
Figure I APS Summer System Sumer PeakHours17
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4 -_
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21
no s
100%
Sus
60%
40%
20%
as
lam 8 am Noun 1 a Sum 7 a 922
23
Qlcs\ Year *DIS system load. lop 80 hours. Junethrough September.
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333 APS Br. at 59, citing to Hearing Exhibit APS-7 (Rebuttal Testimony of Charles Miessner on the Settlement Agreement
Testimony) at 9, Figure l.
334 Hearing Exhibit APS-19 (Direct Testimony of James Wilde) at 14.
335 APS Br. at 59-60, citing to Hearing Exhibit APS-7 (Miessner Rebuttal Settlement Agreement Testimony) at 12, Figure
2 (Time of Day Relative Energy & Capacity Heat Map).
336 APS Br. at 60.
331 ld. at 60-61 .
76295DECISIONno.57
DOCKET NO. E-01345A-16-0_36 ET AL.
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peak time period was carefully crafted to maximize the efficiencies of shiNing load to off-peak.338
Without a change in the on-peak period to align it with actual system peak, system costs will not be
reduced, and the entire purpose of on-peak rates would be undermined. APS believes its current TOU
customers and new TOU customers can and will respond to the new shorter on-peak times in a
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meaningful manner, and that setting forward-looking on-peak periods would also remove the need for
extensive customer re-education in future rate cases.33°
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Along with the other rate design changes in the Settlement Agreement, AIC supports the
adjusted on-peak hours of3:00 p.m. to 8:00 p.m. in the Settlement Agreement, noting that the majority
of parties support the change.34° AIC states that the new hours allow customers to take advantage of
fewer on-peak hours, and more off-peak holidays, than they currently have, while focusing more
accurately on the time of day when demand reduction is needed most, and argues that "[t]he TOU on-
peak periods were carefully designed to achieve the stated revenue amount, properly align the cost of
providing service during on-peak times, and preserve the economics of rooftop solar - they should
remain unmodified in the Sett1ement."34'
16 Vote Solar6.
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Vote Solar asserts that "when considered with the balance of many different issues addressed
18 by the Proposed Settlement Agreement, the 3 p.m. to 8 p.m. period peak is reasonable."342
SEIA7.
20 SEIA supports the 3:00 p.m. to 8:00 p.m. on-peak period established in the Settlement
21 Agreement.343
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338 APS Reply Br. at 7.
339 APS Br. at 60-61.
340 AIC Br. at 5 AIC Reply Br. at 3.
341 AIC Reply Br. at 3 4.
342 Vote Solar Br. at 6, citing to Hearing Exhibit Vote Solar-2 (Direct Testimony of Brianna Kobor on the Settlement
Agreement) at 5.
343 SEIA Br. at 4, citing to Hearing Exhibit SEIA-2 (Direct Testimony of Sara Birmingham on the Settlement Agreement)
at 5.
DECISION no.58 76295
DOCKET no. E-01345A-16-0036 ET AL.
l Staff8.
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Staff characterizes SWEEP's proposed modification to the Settlement Agreement's on-peak
hours, to 4:00 to 7:00 p.m., as unbalanced and one-sided, and as being based on customer convenience
rather than APS's system peak.344 Staff asserts that while SWEEP's argument that its proposal would
be attractive to more customers and lead more customers to subscribe to TOU rates might seem
reasonable on its face, SWEEP's advocacy is narrowly focused on its own interests, and does not strike
an appropriate balance between customer needs and utility needs.345 Staff emphasizes that the
Settlement Agreement would provide customers with a shorter on-peak period than they currently have,
and would add four additional off-peak holidays.346
Staff states that the Settlement Agreement's on-peak hours off :00 p.m. to 8:00 p.m. are aligned
with APS's highest peaks and costs,347 that it is undisputed that APS has a very broad peak, where
loads remain very near peak until as late as 9:00 p.m.,348 and that even though APS's peak has not yet
occurred after 7:00 p.m., its loads remain very near peak until 8:00 to 9:00 p.m.349 Staff points out that
SWEEP acknowledged two factors that support approval of the on-peak period of 3:00 p.m. to 8:00
p.m. agreed to by the Settling Parties: l) APS's system peak can shift to a later time than SWEEP's
proposed 7:00 p.m. cutoff, and 2) APS's peak period has shifted over time, to later in the day.350
Staff contends that the Settlement Agreement's proposed changes to TOU on-peak hours
balance competing interests, and move APS's rate design in the right direction by sending appropriate
cost signals to encourage customers to shift load to off-peak hours.351
9.Resolution
21 We agree with Staff that the TOU on-pcak period proposed in the Settlement Agreement
22 "strikes that appropriate balance between the [TOU] customer's ability to adjust usage into off-peak
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344 Staff Br. at 23.
345 Staff Reply Br. at 4.
346 Staff Br. at 23, Staff Reply Br. at 4.
347 Staff Reply Br. at 4, citing to Tr. at 341 (APS witness Miessner).
348 Staff Reply Br. at 4, citing to Hearing Exhibit APS-7 (Rebuttal Testimony of Charles Miessner on the Settlement
Agreement) at 9.
349 Staff Reply Br. at 4.
350 Staff Br. at 23; Staff Reply Br. at 4, citing to Tr. at l 174, l 176-77 (SWEEP witness Schlegel).
331 Staff Br. at 23 Staff Reply Br. at 4.
DECISION no.59 76295
DOCKET no. E-01345A-16-0036 ET AL.
l hours while recognizing that demand on APS's system can remain high after 7200 p.m."352 The
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arguments advanced by SWEEP and AARP in favor of rejecting the proposed Settlement Agreement
on-peak TOU hours are not convincing on this important point. The Settlement Agreement provides
customers with more off-peak hours than TOU customers currently have, and importantly, customers
retain the choice to take service under the R-Basic rate plan, if they determine that the on-peak hours,
which reflect system costs, are not suited to their individual energy usage patterns.
7 ADOPTION OF THE SETTLEMENT AGREEMENTvi.
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After reviewing the Settlement Agreement in its entirety, as well as the arguments in support
of and in opposition to its adoption, we believe the Settlement Agreement is in the public interest and
should be adopted, as discussed herein.353 As the Settlement proponents point out, a broad range of
parties representing vastly different interests were able to craft a comprehensive agreement through
negotiation and compromise. The Settlement Agreement provides a number of benefits for customers,
including: a base rate increase substantially less than originally requested by APS, increased rate
options for residential customers, including TOU rates with additional non-peak hours and days, a stay-
out provision that precludes APS from seeking another base rate increase prior to June l, 2019, a pilot
program to incept customers to adopt technologies to manage demand and reduce system peak,
increased assistance for low-income customers, continuation of a buy-through program for industrial
18 customers, and a collaborative resolution of issues related to DG customers and net metering. When
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viewed in its totality, the benefits of adopting the Settlement Agreement outweigh the arguments in
opposition raised by several non-signatory parties. We will therefore adopt the Settlement Agreement,
for the reasons set forth above.
22 Vll.INCENTIVIZING BATTERY STORAGE FOR E-32 L CUSTOMERS
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The Settling Parties did not reach agreement on the rate design issue of ratcheted rates for APS's
large commercial customers. The interested parties litigated it in this proceeding, and their arguments
are set forth here.
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352 See Staff Reply Br. at 4.
353 As stated out the outset of the discussion, Section 30 of the Settlement Agreement is bifurcated from our Decision today.
and will be addressed in a forthcoming Decision.
76295DECISION no.60
DOCKET no. E-01345A-16-0_36 ET AL.
l a.APS's E-32 L and E-32 L TOU Rates
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APS's E-32 L and E-32 L TOU rates354 apply to large commercial customers whose average
demand is 401-3,000 kW per month, and include an 80 percent demand ratchet, declining demand
blocks, and a decreased off-peak demand charge for the E-32 L TOU rate.355 These rates were
established in APS's prior rate case, where the parties agreed that instead of paying an LFCR to address
unrecovered fixed costs, E-32 L and E-32 L TOU customers would take service under rates that
included, among other cost-recovery protections, a ratchet.35" APS states that as an existing approved
rate structure, its E-32 L and E-32 L TOU rates are entitled to the legal presumption that they are just
and reasonable, absent persuasive evidence to the contrary.357
APS states that the differential in the on-peak and the off-peak demand charges, which under
the Settlement Agreement's proposed rates would be $5.98/kW on-peak, but only $2.275/kW off-peak,
incentivizes customers to shift their consumption to off-peak periods.358 The ratchet is for 80 percent
of the customer's peak demand imposed on the system during APS's peak summer months, and remains
in effect for the single year following that customer's summer peak.359 APS states that ratchets are
advantageous because they: (i) mitigate any cost shift, (ii) promote revenue stability, (iii) promote
equitable rate design, and (iv) promote efficient use of the system.3°°
APS states that the ratchet is cost based, and poses no barriers to commercial customers to
install battery storage.3"l APS asserts that ratcheted rates properly incentivize storage technologies,
because reductions in energy usage result in bill savings (due to the fact that reductions in energy usage
are not affected by the ratchet), because the ratchet period is a rolling 12 months, such that reductions
in demand that occur after the summer peak will result in savings the following summer, and because
the ratchet emphasizes the importance of reducing summer demand.3"2 APS states that the ratchet
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354 See Settlement Agreement Appendix I.
355 APS Br. at 33.
356 APS Reply Br. at 19.
357 APS Reply Br.at 29, referring to Tucson Elem.Power Co. v.Ariz. Corp. Comm n 132 Ariz. 240, 242, 645 P.2d 231
233 (1982),Lilac/i/ieldPark Serf. Co. v Ariz.Corp. Comm n 178 Ariz. 43I,434 874 P.2d 988, 991 (App. 1994), and PPL
Walling/OrdEnergy LLC v F.E.R.C.,419 F.3d 1194 1199 (D.C. Cir.2005).
358 APS Reply Br. at 30, referring to Settlement Agreement Appendix G at l l of 14.
359 APS Br. at 28.
360 Id. at 40, citing to Hearing Exhibit Staff-11 (Direct Testimony of Ralph Smith on the Settlement Agreement) at 22-23.
361 APS Br. at 3233.
362 Id. at 38.
76295DECISION NO.61
DOCKET no. E-01345A-16-0036 ET AL.
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serves to promote the recovery of costs by the customers who cause them. APS believes that the fact
that E-32 L customers install energy efficiency in proportion to other general service customers
suggests that the current E-32 L rate structure does not impede customer efforts to reduce load.363
APS states that the off-peak demand charge in the E-32 L TOU rate recognizes that significant
costs exist year round, during both peak and off-peak periods of the day, and the off-peak demand
charge is appropriately set at less than half of the on-peak charge.3°4 APS points out that the R-Tech
residential rate in the Settlement Agreement also has an off-peak demand charge which serves as a
safeguard to ensure that the customer who causes a cost pays that cost.365 APS contends that off-peak
usage drives costs too, and that removing the off-peak demand charge from the E-32 L TOU rate would
remove an essential safeguard for cost recovery, and would be inappropriate because it currently allows
sophisticated customers the opportunity to shift their load to avoid costs far beyond system savings.366
APS states that when a technology reduces grid costs, the cost of service savings will equal the bill
savings, avoiding shifting of costs to other customers.3°7
AIC supports approval of the E-32 L rates as proposed by APS.368 AlC asserts that a demand
ratchet is a common feature of commercial billing rate design and its purpose is to help ensure that a
customer pays its appropriate level of grid costs when demand is billed on a monthly basis, and that
for this class of customer, because grid infrastructure is commonly upgraded to serve the customer's
specific requirements, the demand ratchet is important for recovering those costs.3°° AIC states that if
APS invests in infrastructure to serve a customer with a specific demand requirement, and that
customer's demand drops or fluctuates, there is a likelihood that APS's investment costs will be
strandcd.370 AIC contends that APS's proposed E-32 L rates reflect APS's consistent advocacy for
rates that provide clear and accurate price signals, regardless of the type of technology customers
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363 APS Reply Br. at 20.
364 APS Br at 37, citing to Tr. at 422, 442, 473 (APS witness Miessner) and referring to Hearing Exhibit APS-6 (Direct
Testimony of Charles Miessner on the Settlement Agreement) at 19 APS Reply Br. at 30.
365 APS Br. at 38, citing to Tr. at 802, 803 (APS witness Snook).
366 APS Br. at 38, APS Reply Br. at 30.
367 APS Reply Br. at 2122, citing to Tr. at 372 (APS witness Miessner).
368 AIC Br. at 7, 11.
369 ld at 8, citing to Hearing Exhibit APS6 (Direct Testimony of Charles Miessner on the Settlement Agreement) at 17.
370 AIC Br. at 89, citing to Hearing Exhibit APS-6 (Direct Testimony of Charles Miessner on the Settlement Agreement)
at 18 and Tr. at 1000 (Staff witness Ralph Smith).
76295DECISION no.62
DOCKET no. E-01345A-16-0036 ET AL.
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choose to adopt.371 AIC states that when costs are appropriately reflected in rates, as AIC contends
they are in the E-32 rates, proper price signals are sent to incentivize customers to change behavior to
take advantage of that cost-based price signal, for example, by installing energy storage to reduce its
dernand.372 AIC believes that rate design should incentivize long term reduction in summertime peak
demand in a predictable and sustainable manner, and that the E-32 L rate sends the appropriate price
signal to do that while also providing an incentive for customers to adopt storage technology.373
EFCA contends that demand ratchets serve as an impediment to the adoption of storage because
they act like unavoidable fixed charges and therefore send poor price signa1s.374 EFCA asserts that
with a demand ratchet, the absence of strong price signals to reduce load during system peak provides
no economic incentive for customers to adopt storage,375 and because of the annual reset of the ratchet,
a customer installing storage must wait a full year to recognize the benefit of their storage investment.
EFCA states that because the ratchet is set based on a customer's usage during any 15-minute interval
in the summer months, a single unexpected or unmitigated demand surge can set the ratchet for the
next year, and the customer has no incentive to reduce demand in the current month.377 EFCA contends
that in addition to the ratchet, two other features of the existing rate design fail to foster peak reduction
and deployment of storage solutions.378 EFCA asserts that the first block of declining block demand
charges in both existing rates is so small that it is unavoidable, thus acting as an unavoidable fixed
charge,37° and that the off-peak demand charge in the E-32 L TOU rate actually charges customers for
shifting peak consumption to system off-peak.38°
20 b. EFCA's Proposed Optional E-32 Rate
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EFCA proposes that in addition to APS's E-32 L and E-32 L TOU rates, the Commission also
adopt its proposed optional non-ratchet tariffs ("Optional E-32 Rates") which would be available to
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371 AIC Reply Br. at 5.
372 Id.
373 Id.
374 EFCA Br. at 4_6.
375 Id. at 5-6.
376 ld. at 7.
377 Id. at 6.
378 ld. at 7-9.
379 Id at 8, citing to Tr. at 1204 (EFCA witness Mark E. Garrett).
380 EFCA Br. at 8-9, citing to Hearing Exhibit EFCA4 (Direct Rate Design Testimony of Mark E. Garrett) at 1415.
DECISION no.63 76295
DOCKET no. E-01345A-16-0036 ET AL.
1 customers taking service under APS's E-32 L and E-32 L TOU rates. EFCA's proposed Optional E-
2 32 Rates are shown in the following two tables reproduced from Hearing Exhibit EFCA-14 (Rebuttal
3 Testimony of Mark E. Garrett on the Settlement Agreement) at l 5-16:
4 lack I: Upnonal Los Moral: Rain
5
§!:n.l;.Bsm2::.Bll£h$11
6
Sauce:
E A29.l l 1d
ELA Jl5(c)
lF (A
Pmposexi
Av Unit RocsA\ Rev
EFCA
Una
EF(A
Pmpou4
Revenue
EF(A
Proposes!
.o Rachel
APS
Proposed
Revenue
Senlanem
APS
Unit
APS
Puugosed
Senlemeni
kW Rnlcs
wih Rnlchct
§.llllBL12l!17 ss
8
s 58489047 *.97".860 s 19 67
8030.347 451.488 s 17.79
364.199 28205 s l2.°\
s I l0976J7
47391410
802105
7 2s 241
45 817
J l 8 3 7 l
26.71
18 $3
24.26
\7.27
1865
12.\7
415527
2.557.331
31.060
41s.42s
2.410
25715
x | 1097637
4739l 410
w2.1os
7228.24 I
45.822
m377
25.37
17.6\
23.05
\6.41
1762
11.75
437.397
269l .929
34aoo
44015 I
2.600
27089
kW Sczonduy her I
kW Selwlldary lr 2
kW Prlnary In \
kW Pnrnuy Mia 2
kW Tnnsmnslon Na I
kW Tnnsmisunn lie: 29
$66883593 s 66381593sso.ssJs93
10
s
l l
26.621 s 1290
s s 4 .3 2 s ws 2746.$61 x 19 vs
s 7614J87 427102 s l 7.B3
s 343.43312
s I 1I9750l
43.128447
820.m4
6793842
42998
301l3S
419266
2327295
33820
393282
2.2s0
2434 I
26.71
1863
24.26
17.27
\s.ss
12.J7
s I 1197.50 I
4:.\2s441
x20.s44
6793842
42.298
Sm .I JS
25.37
17.61
23.05
16.41
17.62
11.75
441 .333
2449784
35.600
4 I 39s |
2400
2$.622
Proof Summa Demand Revenue
MIBLIZIXIkW Secondary ms I S
kW Senoodary in: 2
aw prim-vv Ia I
ow pm-Iv nu 2
KW Tmslnhsioa lie: l
kW Tnnsnssbn nm 2
$62283768 s 62.'83768$62283 768Proof Wins Damed Revenue13
14
Table 2: Optional LGsTol Sponge Rates
15 &1LBS M 2!; £BlB. 4M
16
Source
EFCA 29 1 aid
EFCA 31 5(c)
EFCA
Proposed
RatesAv Rev
&tsn1=.B:m2xsJisn.e!1.Q1IEsBKJM
EFCA Propcscd
Revenue
kW Rates
o Ratchet Av Uhns
EFCA
Units
EFCA
Proposal
o Ratchet
APS
Proposed
Revenue
APS Proposed
Scttkmcnt
kW Rates APS
was Ratchet Urns17inmmsnlzm s216890 16 96s 3678113sss
18
ss 1.257.187 15621 Le 6219
20
10075 s 1486s149693
21
477093
2.371444
174l 18
655458
96.535
865.451
34727
260474
9l20
105. I I s
2.723
32.735
lsas
1242
673
355
1783
12 33
598
3.44
1675
ll 03
5 13
3 30
25888 s
191 002
25862
184773
5.415
70212
5809
75627
544
9.530
531
9.913
477.093
2371444
174118
655.458
96535
86545]
34.727
260.474
9.120
l05\ 15
2723
32735
175]
ll 80
6.40
3 37
16 94
ll 71
568
3.27
1592
10 48
487
3 14
27.250
201055
27223
194498
5100
73.907
6.11s
79.607
573
10032
559
l 0435
kW her I secondary on
kW Ilzr 2 secondary on
kW tncf I secondary . oH
kW her 2 secondary off
kW her I primary on
kW tncr 2 primary on
kW nor 1 primary off
kW her 2 prrnaxy off
kW her I Iransmnsslon on
kW t 1cr 2 transmssuon on
kW her I transmission ofT
kW her 2 transmlssnon off
22 s $50849935084.993s 5084993Proof Summer Demand Revenue
s217795 1690s 368135934865 ss23ss
24
s54593 16 59s905811
25
s11747 14 58s17130226
27
642.544
2.21 l .222
170/73
596.8"0
89422
611098
30.530
l 7476 I
9 168
l 23.52S
2.806
35803
18 43
1242
673
3 55
17 83
12 33
59s
3 44
1675
ll 03
5 13
3 20
l 82930
25365
168243
5016
49577
5.107
50740
547
I 1200
547
l l .200
642.544
227 l222
170773
596820
89422
611098
30530
174761
9.168
123.525
2.s06
35803
17 51
ll 80
640
3 37
1694
ll 71
568
3 27
15 92
1048
4 87
304
36.700
192558
26.700
177.098
5280
52186
5.376
534 l I
576
I I 789
576
1 | 7s9
$4758472s4758472s 4758472
!:il!&Ll2IH
kW her l secondary on
kW her 2 secondary on
kW Mr l secondary off
kW her 2 secondary off
kWucr I vfvmry on
kWue12 primary on
kw Mr I primary °tT
kWher2 pnmnryoff
kW her l lransmssxm on
kW new 2 lransmssnon on
kW her I lransmvssnon oft
kW her 2 uansmsuon off
Proof Wntcr Durand Revenue28
76295DECISION no.64
DOCKET no. E-01345A-16-0036 ET AL.
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EFCA contends that APS's current E-32 L rate structure acts as an impediment to the adoption
of energy storage technology by sending poor price signals.38l EFCA claims that its proposed Optional
E-32 Storage rate will incentivize deployment of storage technologies immediately and begin offsetting
costly infrastructure investments needed to meet APS's projected 50 percent load growth over the next
15 years by shifting E-32 L customers' demand off-peak.382 EFCA states that the Commission recently
ordered UNSE to consider designing rates that match cost causation with revenue recovery and to
evaluate methods of revenue recovery that do not involve ratchets,383 and ordered TEP to file an
Optional Rate tariff without a demand ratchet for its large commercial class customers who elect to
adopt storage technology.384 EFCA disagrees with APS's arguments that the UNSE and TEP rate case
Decisions should not be given weight in the Commission's determinations on this disputed issue.385
EFCA contends that its proposed Optional E-32 Rate is cost-based, revenue neutral, and
contrary to APS's claims, will not cause APS to experience stranded costs.38° EFCA asserts that its
proposed Optional E-32 Rate proposal addresses a real and pressing issue,387 and will not cause a cost
shift.388 EFCA characterizes APS's comparison of the proposed Optional E-32 Rate to net metering as
a "scare tactic" without support,38° and contends that APS's opposition to it is motivated by its business
interests, and not its customers,3°° pointing out that the E-32 customers participating in this proceeding
have not opposed adoption of the proposed Optional E-32 Rate." |
AIC believes that it would be bad public policy to adopt EFCA's Optional E-32 Rate
proposal.3°2 AIC warns that removing the ratchet would not only put cost recovery at risk,3°3 but if
adopted, EFCA's rate proposal would cause the same cost shitting problems that net metering did, by
maximizing bill savings for individual customers irrespective of the actual reduction in costs to the
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381 EFCA Br. at 48.WMmML
383 Id. at 12, citing to Decision No. 75697 at 86.
3s4 EFCA Br. at 12, citing to Decision No. 75975 at 188 193.
385 EFCA Reply Br. at 16.
386 EFCA Br. at I 3-I8.
387 EFCA Reply Br. at 5.
388ld.at 13.
389EFCA Reply Br. at 4.
390 ld. at 14.
391 ld. at 17.
392AIC Br. at 10.
393ld., citing to Tr. at 1239 (EFCA witness Mark E. Garrett), 141 (APS witness Lockwood).
76295DECISION no.65
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utility to serve that customer, and shifting those unrecovered costs to non-storage customcrs.3°4 AIC
urges the Commission to instead approve cost-based rates that are technologically neutral, and not vote
to eliminate cost-based rates in favor of rates that include an incentive for a particular technology.395
AIC argues that EFCA's proposal only addresses third-party interests, in contrast to APS's
proposal, which is balanced and takes into account the utility and its customers.3°" AIC states that
"EFCA represents 'businesses that develop, provide, and research customers' adoption of residential
and commercial distributed energy resources"'397 and asserts that "ERICA's advocacy on the E-32
demand ratchet issue is intended to directly benefit third-party businesses, not the utility's
AIC states that approximately 960 customers take service on the E-32 L rate, they are
typically a very sophisticated class of customers, a number of interveners in this case are members of
this class of customers, that none of the interveners supports EFCA's proposal or objects to APS's
proposal, and that EFCA does not represent any of the customers in the class.3°°
AIC is dismissive of ERICA's claim that demand ratchets discourage the adoption of energy
storage. 400 AIC argues that a ratchet does not eliminate any potential for first year demand savings
from storage, if the storage is installed at the appropriate time, that the sophisticated energy customers
in this rate class don't make energy decisions based on first year savings, but over the life of the
investment, and that one of the goals of a ratchet is to reduce summer month loads, and using storage
to reduce summer load would not reduce demand savings on an annual basis whenever winter loads
are lower than summer loads.4°1
20 AIC argues that although TEP was ordered to implement an optional non-ratcheted rate for its
21 Large General Service ("LGS") customers in future rate cases, that the Commission is not bound to
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394 AIC Br. at 10, citing to Hearing Exhibit APS-6 (Direct Testimony of Charles Miessner on the Settlement Agreement) at
16.
395 AIC Br. at 10, citing to Tr. at 140 (Aps witness Lockwood).
396 AIC Br. at 8, AIC Reply Br. at 5.
391 AIC Br. at 8, citing to Tr. at 1234-35 (EFCA witness Mark E. Garrett).
398 AIC Br. at 8, citing to Tr. at 1234 (EFCA witness Mark E. Garrett) AIC Reply Br. at 5.
399 AIC Br. at 8, AIC Reply Br. at 5.
400 AIC Br. at 910.
401 Id., citing to Hearing Exhibit APS-6 (Direct Testimony of Charles Miessner on the Settlement Agreement) at 16 and Tr.
at 346 (APS witness Miessner).
7629566DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.
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require APS to do so, and that because TEP's and APS's ratchets are not substantially similar, the
concerns the Commission may have had in the TEP case are not present in APS's E-32 L rates.4°2
APS recommends that the existing E-32 L and E-32 L TOU rate design be adopted, and that
EFCA's proposed Optional E-32 Rate be rejected. APS asserts that EFCA's proposal would "over
reward load reduction in the winter months when load reduction is not generally needed."403 APS
asserts that EFCA has failed to explain how battery storage that is dispersed dependent upon sales by
EFCA's members could supplant APS's need to plan for and build infrastructure based on system
needs.40"APS states that battery storage is an unproven technology that does not supplant APS's
responsibility to plan for and meet peak demand, and APS must stand ready to serve the entire load
during peak in the event a battery fails to discharge a customer's needed power for the entire length of
its peak period. APS states that being ready to supply 100 percent of a battery customer's peak load is
a standby service that requires the same amount of fixed infrastructure needed if the customer never
installed battery storage.4°5 APS states that the record is bereft of specific evidence regarding the
capabilities of behind-the-meter battery storage such as consistent dispatch capability and longevity,
when installations would occur, what size the installations would be, and how much system peak load
battery customers would actually mitigate, if any.406 APS states that for system peak to be mitigated,
E-32 customers would have to discharge their batteries reliably, every day, and that whether the
technology is reliable in this regard is currently unknown.407
In response to EFCA's statement that adoption of the Optional E-32 Storage rate will begin
offsetting costly infrastructure investments needed to meet APS's projected 50 percent load growth
over the next 15 years by shifting E-32 L commercial customers' demand off-peak, APS states that
while its 2017 [RP forecasts a 50% increase in residential load, this forecast is a conservative planning
estimate, and does not translate into actual system costs, and that EFCA's use of the entire 15 years
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402 AIC Reply Br. at 7.
403 APS Reply Br. at 17, citing to Tr. at 345346 (APS witness Miessner).
404 APS Reply Br. at 17.
405 ld.
406 APS Reply Br. at 14.
407 Id. at 15.
7629567DECISION no.
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instead of the compound annual growth rate in residential customers of 2.5 percent to support its
optional commercial rate design is misleading and speculative.4°8
APS contends that EFCA's request for special rate treatment for prospective battery energy
storage customers is not in the public interest, and can be granted only at the expense of other APS
customers, similar to the cost shift caused by the net energy metering ("NEM") structure for existing
rooftop solar customers.40° APS states that EFCA's proposal would remove the basic safeguards from
the E-32 L and E-32 L TOU rates that ensure that E-32 L customers pay their proper amount of grid
costs, and that the resulting unrecovered costs would be shifted from E-32 L customers who install
battery storage to E-32 L customers who have no battery storage.4'° APS points out that no member
of the E-32 L customer class, several of whom are active participants in this proceeding, is requesting
the change to E-32 L rates, and APS argues that it is likely due to the cost shift that would result from
EFCA's proposal that this is the case.4"APS argues that EFCA is proposing the promotion of a
specific technology through rate subsidies that lacks any support from potentially affected customers,
and that while it is understandable that EFCA is promoting the installation of a product by one of its
members, there is no need to create new problems by disturbing a functioning rate structure that has
the broad support of those taking service under it.412
APS contends that EFCA's witness acknowledged that EFCA's Optional E-32 Rate proposal
would cause a cost shift when he testified that it might be appropriate for customers on that proposed
rate to be included in the LFCR to minimize the loss of revenue, and that the LFCR would only spread
to all other customers the cost shift responsibility that would rightfully be borne by large commercial
customers with battery storage installed.4l3 APS asserts that its E-32 L class is particularly vulnerable
to cost shifts, because these customers account for 10 percent of APS's total revenues, but constitute
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408 ld. at 16.
409 APS Br. at 32-33.
410 Id. at 33 34.
411 Id.
412 APS Br. at 37.
413 Id. at 35 citing to Ir. at 1249-50 (EFCA witness Mark E. Garrett). EFCA argued on brief that Mr. Garrett also testified
that "there is no cost shift emanating from the ratchets." EFCA Reply Br. at 2-3, citing to Tr. at 1215 (EFCA witness Mark
E. Garrett). EFCA argues that "Mr Garrett was clear that he believes it is unnecessary to subject the Optional Rate to the
LFCR but that he suggested it was an option for the Commission to consider if it was concerned about this issue in spite of
the lack of evidence supporting the lost fixed cost claim." EFCA Reply Br. at 3.
7629568DECISION no.
DOCKET no. E-01345A-I6-0036 ET AL.
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contributes a substantial amount to the grid's fixed costs, the cost shift risk for each battery storage
installation is heightened, and due to the fact that there are only a small number of other E-32 L
customers onto which unpaid fixed costs are shifted, the consequences of the cost shift are higher for
each affected customer.4'5 APS asserts that eliminating the ratchet would require that demand rates be
increased by $7 million,4"' and making the ratchet optional would require an even larger increase.4'7
APS states that because the off-peak demand revenue for the E-32 L class is 22 percent of the total
demand revenue, its elimination could be even more significant.4'8 APS states that while the cost shifts
would not occur immediately, they would begin as soon as the first customer began installing storage
and avoiding contributions, under EFCA's Optional E-32 Rate, to the fixed costs necessary to serve
them.419
12 APS contends that the LGS ratchets discussed in the recent UNSE and TEP rate Decisions do
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not offer a useful comparison to the APS's E-32 L ratchets, because they do not function in the same
way APS's E-32 L ratchets fL1nction.420 Unlike APS's E-32 L ratchets, both TEP and UNSE's LGS
ratchets are based on the highest demands during the preceding 1 l months, which includes all the non-
summer months, and also apply to non-peak hours of the day.42l In the UNSE case, affected LGS
customers with off-peak loads intervened and registered their complaints about the UNSE LGS
ratchet,422 and the Decision in that case responded to their concems.423 APS points out that in the TEP
case, TEP sought to create a new medium general service class of service for customers with average
demand of 20 kW to 300 kW per month, and to use a ratchet in the rate design for the new class,424
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414 APS Br. al 35.
415 Id.
416 APS Br. at 36, citing to Hearing Exhibit EFCA-14 (Rebuttal Testimony of Mark E. Garrett on the Settlement Agreement)
at 15-16, Tables l and 2, referring to APS Response to Data Request EFCA 31.5(c) in which APS provided the $7 million
calculation.
417 APS Br. at 36, citing to Tr. at 465 (APS witness Miessner), APS Reply Br. at 30.
418 APS Br. at 36, referring to Hearing Exhibit EFCA-14 (Rebuttal Testimony of Mark E. Garrett on the Settlement
Agreement) at l, Table 2, showing in the APS Proposed Revenue column that the off-peak charges are designed to generate
$2,171,728 of the total E-32 L TOU class revenue of$9,843,465.
419 APS Br. at 36.
420 ld. at 4143.
421 Id. at 41, citing to Tr. at 350 (Miessner).
422 APS Br. at 41.
423 See Decision No. 75697 at 86.
424 APS Br. at 41, citing to Decision No. 75975 at 7273.
DECISION no.69 76295
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whereas APS's E-32 L rates with ratchets apply to larger customers, with average demand of 40] to
3,000 kW.425 APS contends that the TEP rate case Decision, which ordered TEP to create an optional
non-ratchet rate for TEP's LGS class included no discussion of the cost-shil ramifications of removing
ratchets from rate design for larger customers, and does not establish a strong policy disfavoring
ratchets, but states that ratchets may "make sense for large customers which tend to have high load
factors."42°
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APS argues that the modifications EFCA proposes in this proceeding to the E-32 L ratcheted
rate designs, which specifically remove not only the ratchets, but also the declining block rate structure
and off-peak demand rate structures, were neither proposed nor considered in the UNSE and TEP rate
cases, and that the Commission's direction to TEP to propose a non-ratcheted rate design is far different
from EFCA's detailed and broad-sweeping proposal in this proceeding.427 APS states that EFCA has
not explained its contention that tiered demand rates or off-peak demand charges impede adoption of
storage technology.428 APS responds to EFCA's criticisms of the first tier charge as constituting a
"fixed" charge as without merit, stating that customers are billed for their usage, and that requiring
customers to pay for their usage does not make a charge "fixed."42° APS asserts that EFCA has also
failed to explain how the existence of two demand tiers would impede the development of battery
storage, or to prove its contention that it would.430
APS contends that ERICA's primary concern, regarding the lack of "first year savings" by
customers installing storage is really a business model problem, which could be addressed by timing
battery installations to go online prior to the summer billing period, or by structuring contract payments
to better match payments with savings.43' APS suggests that other contractual options could mitigate
battery vendors' first year savings issue, such as 1) reducing or eliminating charges in the first year, 2)
reducing prices in the off-season, and 3) staging installations so that the first year installation is smaller
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425 APS Br. at 42.
426 ld. citing to Decision No. 75975 at 94.
427 APS Br. at 43.
428 APS Reply Br. at 28-29.MmM
430 ld.
431 APS Br. at 39. citing to Hearing Exhibit APS-6 (Direct Testimony of Charles Micssner on the Settlement Agreement)
at 19-22 and referring to Tr. at 459-460 (APS witness Miessner) APS Reply Br. at 20.
7629570DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
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and only reduces demand by the 20 percent ratchet amount, with the second-year installation being
larger.432
3 APS asserts that it is better for E-32 L customers to understand how ratchets work in
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conjunction with battery storage, than for incentives that are not tied to reducible costs to be buried in
rate design.433 APS states that the issue here is not whether to incentivizc battery storage, but how to
do it. APS is opposed to rates that are intentionally designed to help the business model of some
interveners at the expense of APS's customers.434 APS urges the Commission to take a balanced
approach to protect the interests of all customers in the E-32 L class, and not just those who purchase
battery storage from EFCA's members.435
APS states that customers pay for incentives, and because they will be held responsible
financially through rates for any battery storage subsidy, its cost-effectiveness must be quantifiable and
reviewable.43" APS asserts that EFCA's proposal lacks any explanation of how it will achieve
meaningful load rcduction.437 APS characterizes ERICA's proposal as the opposite of utility planning
- "an unquantified incentive, embedded in rates, filled by customers, and designed to spur the
installation of batteries without regard to (i) system location or need, (ii) cost-effectiveness, or (iii) the
possibility of more-targeted alternatives."438
17 c. APS's Alternative Proposal for an Up-Front Incentive ("E-32 UFI") Pilot
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APS contends that if the Commission wishes to incentivize customer-installed batteries beyond
the current E-32 L rate design, a transparent incentive mechanism such as its proposed E-32 UFI
program, as set forth in Hearing Exhibit APS-33, is a better policy alternative than EFCA's proposed
Optional E-32 L Rate. Hearing Exhibit APS-33 is reproduced here for reference:22
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432 APS Br. an 39.
423 ld. APS Reply Br. al 21
434 APS Reply Br. at 21.
435 Id.
436 APS Reply Br. at 26.
437 Id. at 24.
438 ld. at 25, 26.
DECISION no.71 76295
DOCKET no. E-01345A-16-0036 ET AL.
APS Proposed Pilot for E-32L TOU Customers Installing Storage
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S2M annual program cap for each year for the period of 2017-2019 funded through the
DSMAC adjustor.
o Eligibility is limited to E-32L customers and must be on a TOU rate
o Cash incentive amounts would be limited to 50% of individual system cost and
would not exceed $100,000 per installation
o Incentive payments would be paid commensurate with the duration of storage (at
the rated continuous power) technology aligned with system benefits as follows:7
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Amount of
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1 hour 20%15
o All kph stored and discharged through participating systems would be credited
towards APS annual DSM compliance requirements
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O Participating systems must complete all required interconnection approvals prior to
operation and include all required metering and communication infrastructure18
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2.Participating customers are eligible for a one-time demand forgiveness once per year where
a single 15-minute demand interval would be omitted. The customer must initiate the
request for this adjustment within 30 days of receiving their bill.
3.Upon approval of the storage system interconnection, the existing billing basis for the
ratchet value will be reset to reflect the anticipated kW demand reduction from the storage
system.23
24 APS states that its proposed E-32 UFI program would address EFCA's first-year savings
25 concern by "(i) offering an up-front cash incentive, (ii) resetting a customer's demand that would be
26 used to establish the ratchet when the customer installs storage based on the design criteria of the
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72 DECISION no.76295
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storage technology, and (iii) providing a demand forgiveness once per year to address a circumstance
where the equipment does not function as intended."43°
APS asserts that its proposed E-32 UFI program, added to the existing E-32 L and E-32 L TOU
rates, would provide additional incentives for the installation of battery storage while protecting other
customers from undue cost shifts, and would avoid creating the same challenges for battery storage
that net metering created for rooftop s01ar.440 APS states that its proposal places only $2 million at
risk, while maintaining the revenue recovery safeguards built into the existing E-32 L rates, to which
no E-32 L customer has objected.44I APS states that the E-32 UFI program would "test whether battery
storage technology consistently and reliably reduces peak demand," and would also "provide a means
to assess the overall economics of the technology."442 APS states that the assessments would occur
under controlled circumstances, similar to the Settlement Agreement proposed R-Tech program for
residential customers.443
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APS asserts that if the Commission wishes to achieve certain policy objectives related to
customer-sited technology, the best course of action is to do so in a transparent manner, which can be
tapered as technology costs decline.444 APS contends that the ability to taper incentives is critical,
because without declining incentives, technologies are not forced to improve, technology tends to
mature to meet marketplace needs, but the presence of incentives tends to retard the growth and
maturity of a technology.445 APS states that an advantage to incentivizing the installation of battery
storage through its proposed E-32 UFI program is that the Commission retains control to increase the
amount of the incentives, if $2 million each year does not result in enough battery installations to meet
the Commission's policy objectives, and also to reduce the incentives as market costs decline.44" APS
contrasts this with EFCA's proposal, which lacks this flexibility,447 and asserts that only APS's
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439 APS Br. at 39-40, citing to Tr. at 458 (APS witness Miessner) and 814816 (APS witness Snook).
440 APS Br. at 33.
441 Id. at37.
442 Id., citing to Tr. at 802-803 (APS witness Snook).
443 APS Br. at 37 citing to Tr. at 802-803 (APS witness Snook).
444 APS Reply Br.at 22.
445 Id.citing to Tr. at 590 (APS witness Bordenkircher).
446 APS Br. at 37, APS Reply Br. at 24.
447 APS Reply Br. at 24.
76295DECISION no.73
DOCKET no. E-01345A-16-0036 ET AL.
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proposal offers the Commission control over a targeted, transparent tool to protect against the risk that
incentives will create a "new runaway nEm."44*
AIC states that if the Commission wants to offer large commercial and industrial customers an
option in addition to the currently structured E-32 L rate design, AIC supports APS's proposed E-32
UFI demand side management program as a compromise, where customers would be eligible for an
up-front incentive of up to 50 percent of the total system costs or $100,000 depending on the storage
duration, the design point, and the number of storage hours.449 AIC contends that up-front incentives
would prevent future controversy regarding the embedded subsidies in EFCA's Optional E-32 Rate
proposa1.45° AIC recommends approval of the E-32 UFI program as a sound regulatory policy decision,
as opposed to imbedding an incentive in rate design.45 |
EFCA argues that APS's proffered altcmative to the Optional E-32 Rate proposal is inadequate,
and urges the Commission not to adopt it.452 EFCA asserts that "the preferred approach to encouraging
energy efficiency development is not through incentives designed to overcome barriers, but instead to
simply remove the barrier itself"453 EFCA is critical ofAPS's E-32 UFI proposal because it retains the
ratchet mechanism, the declining block demand charge, and the off-peak demand charge for TOU
customers. EFCA characterizes the E-32 UFI proposal as retaining all the impediments to deploying
storage that are inherent to the existing rates, but providing subsidies from other ratepayers to overcome
those impediments.454 EFCA asserts that APS presented no evidence to support adoption of the E-32
UFI program,455 performed no comparative analysis of the E-32 UFI program and the Optional E-32
Rates, and did not determine if any peak reduction would result from its implementation.45° EFCA
charges that the E-32 UFI program is "not a serious attempt at proposing an alternative to a non-
ratcheted rate design or addressing peak reduction and should be disregarded."457 EFCA contends that
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448 Id. at 26.
449 AIC Br. at ll, citing to Tr. at 812-813 (APS witness Snook).
450 AIC Br. at 10.
451 Id. at 10 ll.
452 EFCA Br. al 19-20.
453 Id. at 19 citing to Tr. at I 156-57 (SWEEP witness Schlegel), EFCA Reply Br. at 7.
454 EFCA Br. at 19.
455 Id.
456 Id.,citing to Tr. at I 187 (APS witness Snook).
457 EFCA Br. at 19-20.
76295DECISION no.74
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"even if subsidizing storage was appropriate,"458 the proposed $2 million annual E-32 UFI subsidy
would be inadequate to generate meaningful storage deployment and peak reduction.45°
APS asserts that EFCA's criticism of the magnitude of the $2 million annual UFI proposal
ignores the Commission's ability to increase incentives to achieve its desired objectives.4"° APS
contends that the magnitude of the incentives embedded in EFCA's proposal aren't known, but
calculates that they "far exceed $2 million annually,"4°' that eliminating the ratchet would require that
demand rates be increased by $7 million,4"2 and that making the ratchet optional would require an even
larger inctea§e463
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APS cautions that if customers install batteries as a result of the rate design incentives EFCA
proposes, the Commission will never know how much of the value of the incentives has gone to third-
party sellers of the technology - whether the price customers paid for the subsidy was too high for the
benefit customers received from the subsidy.4"4 In addition, the Commission would have no means to
scale back the rate design incentive, as it would have with a direct up front incentive.4"5 APS also points
out that customers, along with EFCA, would very likely want to be grandfathered on the rate design
incentive in the future.4"°
16 d. ERICA's Proposed Modifications to its Optional E-32 Rate Proposal
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While asserting that there is no evidentiary support for modifying its proposed Optional E-32
Rate, EFCA asserts that it could easily be modified in order to address APS's criticisms, and EFCA is
not opposed to its adoption with modifications set forth in its Initial Closing Brief and again in its Reply
Closing Brief4"7 In response to criticisms that its Optional E-32 Rate proposal is too narrowly tailored
to benefit only customers utilizing energy storage technology, EFCA states that it is not opposed to
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458 Id. at 19.
459 Id. citing to Tr. at 1225 ((EFCA witness Mark E. Garrett).
"60 APS Reply Br. at 24.
461 Id. at 23.
462 APS Br. at 36, citing to Hearing Exhibit EFCA-14 (Rebuttal Testimony of Mark F.. Garrett on the Settlement Agreement)
at 15-16 Tables l and 2,referring to APS Response to Data Request EFCA 3 l.5 (c) in which APS provided the $7 million
calculation.
463 APS Br. at 36, citing to Tr. at 465 (APS witness Miessner), APS Reply Br. at 30.
464 APS Reply Br. at 24.465 Id.
466 APS Reply Br. at 22-23.
467 EFCA Br. at 2021, 23, EFCA Reply Br. at 1819.
76295DECISION no.75
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allowing customers adopting other energy efficiency mechanisms, and not only storage, that would
meet a minimum kilowatt reduction with their technology to qualify for enrollment.4"8 In response to
criticisms that its Optional E-32 Rate Proposal is too broad, in that it would allow any size storage
battery to qualify, EFCA states that it is not opposed to the Commission setting a minimum requirement
for the size of a storage system to qualify.4°° EFCA suggests that an appropriate threshold would be
for a customer's storage system to serve, at a minimum, 10 percent of the customer's prior year peak
demand.470 EFCA asserts that this sizing requirement would ensure that participating customers have
invested in enough energy storage to provide a meaningful benefit to the grid, but would not "force
customers to install too-large of a system that exceeds their needs and would render the investment
eost-ineffective."47' In response to criticisms that its Optional E-32 Rate Proposal would expose APS
to under-recovery of its costs, EFCA contends that the only evidence presented in this proceeding
demonstrates that before the ratchet was introduced, APS collected all its fixed costs from the E-32 L
rate class.472 EFCA states that in exchange for making its proposed Optional E-32 Rates available, the
Commission could make customers on its proposed Optional E-32 Rates again subject to the LFCR.473
In its Reply Closing Brief, EFCA offered an additional modification to its proposed Optional
16 E-32 Rates as follows:
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[Ethe Commission wishes to proceed in a very conservative manner one other possibility
exists. The Commission could modify the Optional Rates to effectively operate as a
pilot program triggering an automatic review to assess its efficacy and impacts.
Specifically, EFCA suggests that when and if, prior to the filing of APS' next rate case,
the pilot program reaches 15% of existing E-32 L and E-32 L TOU customers by
number or when the customers taking service under the Optional Rates have installed
battery storage that would be capable [at] reducing peak demand in an amount equal to
15% of total peak demand for the E-32 L and E-32 L TOU classes from the last year
before the Optional Rates are put in place, whichever comes first, an automatic
Commission review would be triggered.Such a pilot program would give the
Commission an opportunity to check in on the progress of the Optional Rate.474
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468 EFCA Br. at 20.
469 Id. at21.
410 Id., citing to Tr. at 1223, 1229 (EFCA witness Mark E. Garrett).
471 Id.
472 EFCA Br. at 21, citing to Hearing Exhibit EFCA-9 (APS Response to EFCA Data Request 33).
473EFCA Br. at 2 l,citing to Tr.at 1228-29 (EFCA witness Mark E. Garrett).
474 EFCA ReplyBr.at 18-19.
76295DECISION no.76
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The purpose of legal briefs is not to enter new evidence into the record, but to allow parties an
opportunity to set forth their legal arguments on evidence presented in a proceeding. Because EFCA
waited until the filing of its Reply Closing Brief to make its fourth proffered modification to EFCA's
proposed Optional E-32 Rates, the parties had no opportunity to respond to it in any manner. EFCA's
Reply Closing Brief proposal does not constitute evidence subject to cross-examination of sponsoring
witness, and no party has had an opportunity to advance legal arguments in response to it.
AIC responded to the three modifications that EFCA proposed to its Optional E-32 Rates as
8 follows:
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Presented for the first time in EFCA's post-hearing brief, no party had an opportunity
to cross examine EFCA or APS regarding the impact of those changes on participating
and non-participating customers or on any other aspect of the modified rate design.
EFCA has the burden of justifying its proposed modifications with record evidence,
which - having made the proposals alter the hearing in this matter had concluded - it
simply cannot d0.475
13
15
16
17
AIC also states that the modifications appear to be insufficient to address the concerns APS
14 raised with EFCA's initial proposal.476 AIC recommends that if the Commission determines that the
public interest requires incentives for energy storage for the E-32 customer class, it should adopt APS's
proposed E-32 UFI program.477
APS asserts that "EFCA would only suggest revisiting the (settlement in the last rate case)
18 decision exempting E-32 L customers from paying the LFCR if lost fixed costs were on the horizon."478
19 APS further asserts that applying the LFCR would not avoid a cost shift, but would socialize the lost
20 revenues due to EFCA's proposal by shifting them on to base rates paid by other customers when they
21 are reallocated in the next rate case.479 APS contends that EFCA's willingness to apply the LFCR to
22 its Optional E-32 Rate Proposal constitutes an admission that it would shift costs.48°
23
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25
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475 AIC Reply Br. at 7. As set forth above in this section EFCA's witness responded to questions at the hearing regarding
potential modifications to its Optional E-32 Rates proposal. See also Tr. at 1223 1228-29, 124647, 1249-51, 1256 (EFCA
witness Mark Garrett).
476Id.
477 ld.
478 APS Reply Br. at 19.
479
4s0 APS ReplyBr. at 20.
7629577DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
l Resolutione.
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While we agree with APS and AIC that the recent UNSE and TEP rate Decisions do not offer
a direct comparison to APS's E-32 L ratchets, we also believe that it would be useful to create a new,
optional, non-ratchetcd, storage-friendly rate. This new, optional rate should eliminate the demand
ratchet, off-peak demand charge, and declining block demand charge currently included in APS's E-
32L and E-32L TOU rate.
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The R-Tech Tariff we approve herein as part of the Settlement and TEP's recently implemented
Large General Service Time-of-Use Storage Program (the TEP Tariff) set forth a number of safeguards
and restrictions that should be utilized in conjunction with our approval of an optional storage-friendly
rate to avoid any negative unintended consequences and ensure a smooth and meaningful
implementation of an optional tariff We find those safeguards and restrictions to be appropriate and
necessary and will require that APS adopt them in connection with the new, optional tariff directed in
this proceeding. Accordingly, we order that, within 120 days from the date of this order, APS file a
new, optional storage-friendly tariff and order that the tariff shall include the following restrictions and
safeguards similar to those in both the R-Tech and TEP Tariff:
16 Program Size
17
18
19
20
APS's optional Large General Service Time-of-Use Storage Program Tariff (the Optional
Tariff) will be capped at a peak demand total of 35,000 kW for installed systems and active
interconnection applications, on a first-come first-served basis. Allotments shall be reserved at the
time of submittal of a complete interconnection application.
22
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21 Stakeholder Process
Once 70% of the initial program capacity has been reached, and if such threshold has been
reached prior to APS's next general rate case filing, APS will evaluate whether the costs of the program
are less than the system benefits it provides. If APS determines that the costs are less than the benefits,
APS shall provide notice and promptly convene a meeting of the interested parties to this Docket to
discuss the future of the program. If all parties to that discussion agree on a new program size for the
Optional Tariff that shall apply until the Commission determines the disposition of the Optional Tariff
during APS's next general rate case, APS shall file a notice in this Docket to that effect and the program
76295DECISION no.78
DOCKET NO. E-01345A-16-0036 ET AL.
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shall remain in effect up to the new agreed upon customer participation level, unless the Commission
orders otherwise. However, if all parties cannot agree upon a new customer participation level, APS
within 90 days of the finalization of the discussions, shall file a request with the Commission to
4 establish the terms and conditions under which the program will continue or terminate.If APS
5
6
7
determines that the costs are greater than the system benefits, APS will file a request with the
Commission to freeze the program until changes can be made in APS's next general rate case.
Minimum Peak Demand Reduction
8
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13
To qualify for the Optional Tariff, a customer must install a chemical, mechanical or thermal
energy storage system that is capable of allowing the customer to offset a minimum of 20% of their
measured peak demand during the On-Peak period. The determination of the measured peak demand
for purposes of the calculation will be based on the customer's previous year's measured peak demand
during such period prior to installation of storage facilities. If this is a new facility, the calculation of
the 20% demand reduction will be determined based on APS's total estimated peak demand designed
14
15
16
17
18
for the facility.
VAR Support
In order to qualify for the program where a power producing facility is installed, inverters must
be capable of and configured to provide VAR support so that a near unity power factor of at least 95%
is maintained during operation.
19 TOU Hours
20
21
22
23
24
25
26
For purposes of the APS Optional Tariff the On-Peak period under the program will be
determined as the 6 greatest average system demand hours during the previous three years by season.
The Off-Peak period will be determined as the 12 lowest average system demand hours during the
previous three years by season. All other hours shall be deemed as Remaining Hours.
Annual Reporting
Until such time that a final order is issued in APS's next general rate case, on July l of each
year APS shall submit an informational filing in the docket, reporting on the status of the APS Optional
27 Tariff. The report will include: (i) the number of customers, both in the current year and cumulatively,
28 that are participating in the program (including the proportion of these customers relative to the entire
7629579DECISIONno.
DOCKET no. E-01345A-16-0036 ET AL.
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large commercial class), (ii) the total peak demand of such customers relative to the initial program
allotment of 35,000 kw, (iii) observed peak demand reductions, if any, of customers participating in
the program, (iv) recommended changes, if any, to the Time-of Use periods for the program, (v) if
available, information regarding the average time to process applications from customers requesting
participation in the program, and (vi) current year and cumulative kph exported to the grid by
participating customers.
Rate Desi fr
The APS Optional Tariff shall not include a demand ratchet, Off-Peak demand charge or
declining block demand charge. On-Peak billing demand shall be equal to the greatest measured 15
minute interval demand read of the meter during the On-Peak Hours or the Remaining Hours during
the billing period. The APS Optional Tariff may include a minimum contract demand provision. The
APS Optional Tariff may also include a summer and winter Off-Peak excess demand charge for Off-
Peak exceeding 150% of On-Peak billing demand. The customer service charge component of the APS
Optional Tariff will be structured to maintain proper price signals to incept peak demand reduction
while also ensuring appropriate cost recovery.Storage customers taking service under the APS
Optional Tariff that also have distributed generation remain eligible for the EPR-6 net metering rider.
17 Vlll.STORAGE TO BE INCLUDED IN ANALYSES OF NEW RESOURCE OPTIONS
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28
Energy storage is a valuable tool for electric utilities to comply with the state's energy policies.
Prioritizing energy storage can likewise help reduce a utility's peak demand and address load and
generation challenges while also providing benefits to other parts of the system. All utilities - including
APS - should explore these energy storage opportunities on a more regular and specific basis due to
the potential to help utilities manage demand while also offering opportunities for new investment and
consumer service options.
When acquiring new resources or considering transmission or distribution system upgrades
where appropriate, utilities should perform sufficient analyses of resources and transmission and
distribution system upgrades that include energy storage such that the full benefits of energy storage
are being considered. Energy storage should be compared to caseload resources and non-baseload
resources when a utility is considering acquiring a new resource and should be compared to alternative
7629580DECISION NO.
DOCKET no. E-01345A-16-0_36 ET AL.
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upgrades when a utility is considering transmission and distribution upgrades. The Commission's
definition of "caseload resources" is as follows: resources that provide a continuous supply of
electricity and are not used for load-following, which are traditionally operated continuously with high
capacity factors. "Non-baseload resources" refer to resources that arc used by the utility for load-
following, grid support, load reduction, and other services.
6 WATER ENERGY NEXUSl x.
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Water conservation is a key issue facing Arizona, particularly when existing Arizona water
utilities are experiencing significant water loss levels. Efforts to reduce water loss levels can also result
in benefits from reductions in electric consumption. For example, a reduction in water loss at a water
utility could result in a reduction in electricity consumption due to reduced pumping operations.
Utilities like APS should explore opportunities to partner with local water utilities in furtherance of
reducing both electricity and water consumption.
One such opportunity exists in connection with APS's 2018 Demand Side Management
Implementation Plan filing. APS should develop and propose to the Commission, for approval, a
program available to water utilities within its service territory that would result in a reduction in water
loss, electricity, consumption, or peak demand. APS should evaluate all available opportunities to
conserve and more efficiently use water and electricity in tandem and maximize these opportunities in
the program it will propose to the Commission. APS should involve the Commission's Water
Committee in these efforts. The nexus between electricity consumption and water conservation is an
important issue that we anticipate addressing with other electric utilities in future rate cases.
**********21
22 Having considered the entire record herein and being fully advised in the premises, the
23 Commission finds, concludes, and orders that:
24 FINDINGS OF FACT
25 Procedural Histor
26 1.On January 29, 2016, APS filed a Notice of Intent to File a Rate Case Application and
27 Request to Open Docket.
28 2.On February 5, 2016, Richard Gayer, Patricia Ferré and Warren Woodward each filed
7629581DECISION no.
DOCKET no. E-01345A-16-0_36 ET AL.
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4 4.
5 5.
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6.
7.
8 8.
9 9.
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l a Motion to Intervene.
3.On February 17, 2016, by Procedural Order, Richard Gayer, Patricia Ferré and Warren
Woodward were granted intervention.
On February 22 and March 7, 2016, Mr. Woodward filed comments in the docket.
On February 23, 2016, Mr. Gayer filed a Notice of Consent to Email Service.
On February 29, 2016, Mr. Woodward filed a Notice of Consent to Email Service.
On February 29, 2016, IO filed a Motion to Intervene.
On March 7, 2016, Mr. Woodward filed comments in the docket.
On March 21, 2016, a Procedural Order was issued granting intervention to IO and
10 granting requests to receive service by email.
10.On April 4, 2016, Freeport and AECC jointly filed a Motion to Intervene and Consent
12 to Email Service.
1 l.On April 21, 2016, a Procedural Order was issued granting intervention to Freeport and
14 AECC and granting requests to receive service by email.
12.On May 27, 2016, SCHOA filed a Motion to Intervene and a Consent to Email Service.
13.On June 1, 2016, APS filed the Application.
14.On June 3, 2016, WRA filed a Motion for Leave to Intervene and a Consent to Email
18 Service.
19 15.On June 7, 2016, AIC filed a Motion for Leave to Intervene and a Consent to Email
20 Service.
21
22
16.
17.
On June 14, 2016, APS filed a Notice of Errata.
On June 14, 2016, AURA filed a Motion for Leave to Intervene and Consent to Email
23 Service.
24 18.On June 14, 2016, a Procedural Order was issued granting interventions to SCHOA,
25 WRA and AIC and granting requests to receive service by email.
26 19.On June 15, 2016, PORA filed an Application to Intervene and a Consent to Email
27 Service.
28 20.On June 16, 2016, AriSEIA filed its Application to Intervene and a Consent to Email
76295DECISION no.82
DOCKET NO. E-01345A-16-0036 ET AL.
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Service.
21.On June 16, 2016, ASBA/AASBOjointly filed a Motion for Leave to intervene.
22.On June 17, 2016, SCHOA filed a Clarification.
23.On June 17, 2016, Cynthia Zwick, in her individual capacity, and ACAA jointly filed a
5 Motion for Leave to Intervene. ACAA also filed a Consent to Email Service.
24.On June 17, 2016, APS filed its Opposition to AURA's Motion for Leave to Intervene.
25.On June 22, 2016,RUCO filed a Motion for Leave to Intervene.
26.On June 22, 2016, APS docketed copies of its lead/lag study and excerpts from the
Handy-Whitman Bulletin No. 182 used to calculate its proposed reconstruction cost new less
l l
10 depreciation ("RCND") rate base.
27.On June 22, 2016, SWEEP filed a Motion for Leave to Intervene and a Consent to Email
13 On June 23, 2016, APS filed its Second Notice of Errata.
14
12 Service.
28.
29.
30.
On June 27, 2016, Vote Solar filed a Motion for Leave to Intervene and a Consent to
20 On June 28, 2016, APS filed its Reply in Opposition to AURA's Motion to Intervene.
On June 24, 2016, AURA filed its Response in Support of Motion to Intervene.
15 On June 24, 2016, APS filed a copy of the notice it provided to parties of record of the
16 Rate Case Technical Conferences scheduled for July 20, 2016, August 23, 2016, September 29, 2016,
17 and October 26, 2016.
18 31
19 Email Service.
32.
33.On June 29, 2016, the ED8/McMullen jointly filed a Motion for Leave to Intervene and21
22 a Consent to Email Service.
23
36.
34.On July l, 2016, Staff issued a Letter of Sufficiency pursuant to A.A.C. R14-2-103,
24 classifying APS as a Class A utility.
25 35.On July l, 2016,AURA filed a Motion to Strike.
26 On July 5, 2016, Kroger filed a Motion for Leave to Intervene and a Consent to Email
27 Service.
28 37.On July 5, 2016, John William Moore, Jr., filed with the Commission a Motion to
7629583DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
l Associate CounselPro Hoc Vice to associate Kurt J. Boehm and Jody Kylen Cohn as counsel for Kroger
in this matter.2
3 38.
4 39.
On July 5, 2016, APS filed its Reply in Opposition to AURA's Motion to Strike.
July 6, 2016, AURA filed its Response to APS's Reply in Opposition to AURA's
5 Motion to Strike.
6 40.On July 7, 2016, TEP filed a Motion for Leave to Intervene and a Consent to Email
7 Service.
41.On July 8, 2016, Pima County filed a Motion for Leave to Intervene and a Consent to
10
l l
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9 Email Service.
42.
43.
On July I l, 2016, Staff filed a Request for Procedural Schedule.
On July 12, 2016, SEIA filed a Motion for Leave to Intervene and a Consent to Email
12 Service.
13 44.
14 45.
On July 15, 2016, EFCA filed a Motion to Intervene.
On July 18, 2016 Walmart filed an Application for Leave to Intervene and a Consent to
16
15 Email Service.
46.On July 19, 2016, Staff filed a Motion to Consolidate, requesting that this docket be
17 consolidated with Docket No. E-01345A-16-0123.
25
51.
18 47.On July 22, 2017, APS filed a copy of the presentation from its second Rate Case
19 Technical Conference.
20 48.On July 22, 2016, a Rate Case Procedural Order was issued setting the procedural
21 schedule and associated procedural deadlines for this matter, granting intervention to AURA, PORA,
22 AriSEIA, ASBA/AASBO, Cynthia Zwick (in her personal capacity), ACAA, SWEEP, RUCO, Vote
23 Solar, ED8/McMullen, Kroger, TEP, Pima County and SEIA, and granting several requests to receive
24 service by email.
49.On July 28, 2016, Mr. Woodward filed a Motion for Reconsideration of the July 22,
26 2016 Procedural Order.
27 50.On July 29, 2016, the IBEW Locals filed an Application for Leave to Intervene.
28 On August 1, 2016, a Procedural Order was issued granting Staff"s request to
76295DECISION no.84
DOCKET NO. E-01345A-16-0036 ET AL.
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consolidate the above-captioned dockets, correcting typographical errors in the July 22, 2016 Rate Case
Procedural Order, granting interventions to EFCA and Walmart, and granting requests to receive
3 service by email.
52.
53.
54.
55.
56.
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15 60.
On August 1, 2016, Mr. Woodward filed comments.
On August 1, 2016, Noble Solutions filed an Application for Leave to Intervene.
On August 3, 2016, the Alliance filed an Application for Leave to Intervene.
On August 3, 2016, FEA filed a Motion for Leave to Intervene.
On August 3, 2016, Karen S. White filed with the Commission a Motion to Associate
Counsel Pro Had Vice to associate Thomas A. Jernigan as counsel for FEA in this matter.
57.On August 5, 2016, APS filed a Motion for Clarification and Extension of Time.
58.On August 9, 2016, a Procedural Order was issued granting APS's Motion for
Clarification and Extension of Time. The Procedural Order also granted intervention to the IBEW
Locals, Noble Solutions and the Alliance, and approved a consent to email service.
59.On August l l, 2016, EFCA filed a Consent to Service by Email.
On August 15, 2016, Staff filed a Consent to Email Service.
On August 17, 2016, Noble Solutions filed a Consent to Email Service.
On August 24, 2016, APS filed a copy of the presentation from its second Rate Case
16 61
17 62
18 Technical Conference.
19 63 .On August 24, 2016, the Districts jointly filed an Application for Leave to Intervene
20 and a Consent to Email Service.
64.On August 25, 2016, Correspondence from Commissioner Bob Bums was filed in the21
22 docket.
23 65.On September 6, 2016, a Procedural Order was issued granting the Districts'
24 Application for Leave to Intervene, and granting requests for service by email.
On September 6, 2016, CNE filed an Application for Leave to Intervene.
On September 6, 2016, Mr. Woodward filed two sets of comments.
On September 9, 2016, APS filed correspondence regarding subpoenas dated August
25 66.
26 67.
27 68.
28 25,2016.
7629585DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
69.
70.
On September 9, 2016, APS filed a Motion to Sever.
On September 9, 2016, APS filed a Motion to Quash, or in the Alternative, to Decline
l
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3 to Hear.
4 71.On September 12, 2016, APS filed correspondence regarding subpoenas dated August
5 25,2016.
72.6
7
On September 13, 2016, APS filed an Affidavit of Publication and Proof ofMailing.
On September 13, 2016, Correspondence from Commissioner Bob Bums was filed in73.
8 the docket.
9 74.
ll
On September 27, 2016, Karen S. White filed a Motion to Associate Counsel Pro Hoc
10 Vice to associate Thomas A. Jernigan as counsel for FEA in this matter pursuant to Arizona Supreme
Court Rule 38(a), to which was attached a certification of service indicating that the Motion was served
13
12 on all parties.
75.
14
On September 30, 2016, Direct Energy filed an Application for Leave to Intervene.
76.On September 30, 2016, APS filed a copy of the presentation from its third Rate Case
15 Technical Conference.
16 77.
17
18
78.
79.
On October 3, 2016, Mr. Woodward filed a Notice of Change of Address.
On October 3, 2016, EFCA filed a Notice of Deposition of Barbara D. Lockwood.
On October 6, 2016, APS filed a Motion for Procedural Conference and Interim
19
20
Protective Order.
80.On October 7, 2016, Timothy M. Hogan filed Motions to Associate Counsel Pro Hoc
21 Vice to associate Chinyere Ashley Osuala and David Bender as counsel for Vote Solar in this matter.
22 On October 1 1, 2016, counsel for Noble Solutions, CNE, and Direct Energy filed a
23
24
81
Notice of Change of Address.
On October 12, 2016, AARP filed an Application to Intervene and a Motion to Associate
25
82.
Counsel Pro Hoc Vice to associate John B. CoffMan as counsel for AARP in this matter.
83.
84.
26 On October 12, 2016, EFCA filed its Response to APS's Motion for Procedural
27 Conference and Interim Protective Order.
28 On October 13, 2016, Mr. Woodward filed comments.
DECISION no.86 76295
DOCKET NO. E-01345A-16-0036 ET AL.
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85.On October 14, 2016, Mr. Woodward filed a Response to Chairman Littlc's October 4,
2 2016 Memorandum and Call for Rccusal.
86.On October 14, 2016, a Procedural Order was issued granting APS's request for an
interim protective order regarding EFCA's October 3, 2016 Notice of Deposition, and setting a
procedural conference to be held on October 20, 2016, for the purpose of discussing discovery issues,
including but not limited to the deposition of APS witness Barbara D. Lockwood.
87.On October 17, 2016, APS filed a Consent to Email Service.
88.On October 18, 2016, APS filed its Reply in Support of Motion for Procedural
Conference and Interim Protective Order.
89.On October 18, 2016, Correspondence from Commissioner Doug Little was filed in the
12
13
10
1 1 docket.
90.
91.
14 92.
On October 19, 2016, FEA and Votc Solar each filed a Consent to Email Service.
On October 19, 2016, AURA filed its Response in Support of the Notice of Deposition.
On October 20, 2016, a procedural conference was held as scheduled by the Procedural
15 Order issued October 14, 2016.APS, EFCA, TEP, Walmart, Freeport Minerals, AECC, Noble
16 Solutions, CNE, Direct Energy, PORA, the Alliance, RUCO, and Staff appeared through counsel or
17 lay representative. APS, Noble Solutions, CNE, Direct Energy, EFCA, and Staff provided comments
18 and arguments regarding discovery issues, and the matter was taken under advisement.
19 93.On October 21, 2016, a Procedural Order was issued granting intervention to AARP,
20 admitting counsel for AARP pro hoc vice in this matter, and rescheduling the date of the pre-hearing
21 conference in this matter to March 13, 2017.
22 94.On October 24, 2016, Sedona filed an Application to Intervene and a Consent to Email
23 Service.
24 95.On October 26, 2016, Mr. Woodward filed his Reply to Commissioner Little's October
25 18, 2016 Memorandum, and Call for Recusal.
26 96.On October 27, November 1, November 8, and November 9, 2016, AARP filed
27 Consents to Email Service.
28 97.On November 2, 2016, ASDA filed an Application to Intervene and a Consent to Email
76295DECISION NO.87
DOCKET no. E-01345A-16-0036 ET AL.
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98.On November 4, 2016, EFCA filed a Supplemental Statement of Authority.
99.On November 4, 2016, APS filed a copy of the presentation from its fourth Rate Case
Technical Conference.
100.On November 9, 2016, APS filed a Response to EFCA's Supplemental Statement of
7
6 Authority.
101.
102.8
9 103.
On November 9, 2016, Sur run Inc. filed an Application for Leave to Intervene.
On November 10, 2016, Coolidge filed an Application for Leave to Intervene.
On November 10, 2016, ConservAmeriea filed an Application for Leave to Intervene
10 and Consent to Service by Email.
104.On November 10, 2016, Granite Creek jointly filed an Application for Leave to1 1
12 Intervene and a Consent to Email Service.
105.On November 15, 2016, Mr. Woodward filed comments.13
14
15
106.
107.
18
On November 15, 2016, Sur run filed a Consent to Email Service.
On November 17, 2016, a Procedural Order was issued granting intervention to AARP,
16 Sedona, and ASDA, granting requests for service by email, and setting procedural deadlines regarding
17 the deposition of APS witness Barbara Lockwood.
108.
19
110.
On November 18, 2016, Granite Creek filed a Notice of Change of Address.
109.On November 18, 2016, APS docketed a letter addressed to the Commissioners to which
20 was attached a copy of materials from the presentation from its third Rate Case Technical Conference.
On November 21 , 2016, APS docketed a copy of the presentation from its rate case Cost21
22 of Service Model Technical Session.
111.
25
26
23 On November 23, a Procedural Order was issued granting intervention to Sun run,
24 Coolidge, ConservAmcrica, and Granite Creek.
1 12.On November 28, 2016, Ms. Ferré filed a Consent to Email Scrvice.
l 13.On November 30, 2016, EFCA filed a Notice of Deposition of Barbara D. Lockwood.
27 The Notice indicated that EFCA and APS settled upon December 15, 2016, at 9:00 a.m. as the date and
28 time of the deposition.
76295DECISION NO.88
DOCKET no. E-01345A-16-0036 ET AL.
l 114.
2 1 15.
3
4
5
6
117.7
8 118.
On December 2, 2016, AARP filed a Request to Add Courtesy Email.
On December 5, 2016, EFCA filed its Emergency Motion to Compel Production of
Barbara Lockwood Calendar in Advance of Lockwood Deposition.
l 16.On December 5, 2016, EFCA filed its Emergency Motion for Expedited Consideration
Regarding Emergency Motion to Compel Production of Barbara Lockwood Calendar in Advance of
Lockwood Deposition.
On December 5, 2016, EFCA filed its Personal Consultation Certificate.
On December 7, 2016, APS filed its Response in Opposition to EFCA's Motion to
9 Compel.
10
ll
12
119.
120.
121.
On December 7, 2016, APS filed its Motion to Compel.
On December 7, 2016, Mr. Gayer filed his Direct Testimony.
On December 9, 2016, Coolidge filed a Consent to Email Service.
13 122.
14
On December 12, 2016, EFCA filed its Reply in Support of Emergency Motion to
Compel Production of Barbara Lockwood Calendar in Advance of Lockwood Deposition and its
126.
25
26
27
28
15 Emergency Motion to Compel Production of Report Regarding Rate Impact.
16 123.On December 13, 2016, by Procedural Order, EFCA's Motion to Compel Production of
17 Barbara Lockwood's Calendar was denied and Energy Freedom Coalition of America was ordered to
18 file, no later than December 16, 2016, its Response to Arizona Public Service Company's December
19 7, 2016 Motion to Compel.
20 124.On December 13, 2016, EFCA filed a Notice of Withdrawal of its Emergency Motion
21 to Compel Production of Report Regarding Rate Impact.
22 125.On December 14, 2016, Sur run filed a Notice of Withdrawal as Intervenor.
23 On December 14, 2016, Patricia Lee Repo of Snell & Wilmer LLP filed a Notice of
24 Appearance on behalf of APS.
127.On December 16, 2016, AriSE1A filed a Notice of Consent to Email Service.
128.On December 19, 2016, EFCA filed its Response to the Motion to Compel filed by APS.
129.On December 19, 2016, Staff filed a Request for Extension of Filing Deadline.
130.On December 20, 2016, the IBEW Locals filed the Direct Testimony of G. David
7629589DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
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2 131.On December 21, 2016, the FEA filed the Direct Testimony of its witnesses Brian C.
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4
5
7
8
Andrews and Michael P. Gorman.
132.On December 21, 2016, Mr. Woodward filed his Direct Testimony.
133.On December 21, 2016, a Procedural Order was issued extending the deadline for the
6 filing of Intervenor Direct Testimony to December 28, 2016, approving the request of Sur run, Inc. to
withdraw as an intervenor, and approving SEIA's consent to email service request.
134.On December 22, 2016, ConservAmerica filed the Direct Testimony of its witness Paul
9 Walker.
10 On December 22, 2016, RUCO filed the Direct Testimony omits witnesses John Cassidy
ll
135.
and Frank Radigan.
12 136.
137.
On December 27, 2016, Mr. Woodward filed his Motion to Compel.
On December 27, 2016, APS filed its Reply to ERICA's Response to APS's Motion to13
14 Compel.
15
16
138.
139.
140.
On December 27, 2016, CNE and Direct Energy each tiled a Consent to Email Service.
On December 28, 2016, AIC filed the Direct Testimony of its witness Branko Terzik.
On December 28, 2016, ED8/McMullen filed the Direct Testimony of their witness
141.
142.
On December 28, 2016, AECC filed the Direct Testimony omits witness Kevin Higgins.
On December 28, 2016, Walmart filed the Direct Testimony of its witness Gregory W.
17
18 James D. Downing.
19
20
21 Tillman.
22 143.
144.
On December 28, 2016, SWEEP filed the Direct Testimony omits witness Jeff Schlegel.
On December 28, 2016, EFCA filed the Direct Testimony omits witness Mark E. Garrett.
On December 28, 2016, Staff filed the Direct Testimony of its witnesses Ralph Smith,
146.On December 29, 2016, APS filed its Notice of Intent of Revenue Requirement
23
24 145.
25 David Parcell, Michael Lewis, and Candrea Allen.
26
27 Settlement Discussions.
28 147.On December 30, 2016, APS filed its Notice of Filing Supplemental Testimony, to
76295DECISION no.90
DOCKET NO. E-01345A-16-0036 ET AL.
l
2
3
5
6
7
which was attached the Supplemental Direct Testimony of Jeffrey M. Burke, setting forth APS's
proposed valuation of DG exports using the RCP Methodology.
148.On December 30, 2016, EFCA filed its Sur-Response to APS's Motion to Compel,
4 Motion to Strike Reply Brief, and Notice of Lodging Sur-Response.
149.On December 30, 2016, EFCA filed its Notice of Deposition of Charles A. Miessner.
On December 30, 2016, EFCA filed its Notice of Deposition of Leland R. Snook.
On December 30, 2016, APS filed its Response to Mr. Woodward's Motion to Compel.
On January 3, 2017, Mr. Woodward filed his Reply to APS's Response to his Motion8
9
10
150.
151.
152.
to Compel.
153.On January 4, 2017, APS filed its Response to EFCA's Motion to Strike Reply Brief
154.
155.
14
16
l l and Notice of Lodging Sur-Response.
12 On January 5, 2017, APS filed a Motion for Protective Order.
13 On January 6, 2017, EFCA filed its Response to APS's Motion for Protective Order.
156.On January 6, 2017, EFCA filed its Emergency Motion for Expedited Consideration
15 Regarding EFCA's Response to APS's Motion for Protective Order.
157.On January 6, 2017, EFCA filed its Amended Notice of Deposition of Leland R. Snook.
On January 6, 2017, Staff filed its Notice of Time and Location for Settlement17158.
18 Discussions.
19 159.On January 9, 2017, Vote Solar filed its Expedited Motion to Strike and for Procedural
161.
20 Order.
21 160.On January 9, 2017, a Procedural Order was issued setting a procedural conference for
22 the dual purpose of addressing the issue of incorporating the RCP Methodology into this proceeding,
23 as directed by Decision No. 75859, and for hearing oral argument on APS's Motion for Protective
24 Order and responsive pleadings.
25 On January 10, 2017, Mr. Gayer docketed a supplement to his Direct Testimony.
26 162.On January ll, 2017, the procedural conference convened as scheduled. Appearances
27 were entered by counsel for APS, AIC, ASDA, Vote Solar, SEIA, EFCA, IO, the Alliance, the FEA,
28 ED8/McMullen, PORA, RUCO, and Staff
7629591DECISION no.
DOCKET no. E-0i 345A-16-0036 ET AL.
l 163.
2
3
4
5
On January 13, 2017, a Procedural Order was issued rescheduling the hearing date in
this matter, along with associated procedural deadlines, in order to facilitate the incorporation of the
RCP Methodology into this proceeding pursuant to Decision No. 75859, extending the timcclock by
33 days accordingly, denying Vote Solar's Motion to Strike, and Granting APS's Motion for Protective
Order in regard to EFCA's Notices of Deposition of APS witnesses Leland R. Snook and Charles A.
6 Miessner.
7 164.On January 13, 2017, EFCA filed its Amended Notice of Deposition of Charles A.
8 Miessner.
9 165.On January 13, 2017, EFCA filed its second Amended Notice of Deposition of Leland
10 R. Snook.
ll 166.
12
13
On January 18, 2017, PORA filed a request to allow Mr. Robert Miller, PORA Director
and Chair of Utilities Liaison Committee, to appear and represent PORA as an alterative designee to
act "with or in the stead or absence of" PORA's representatives Albert Gervenack and Rob Robbins in
15 167.
16
17
18
14 this proceeding.
On January 18, 2017, a Procedural Order was issued clarifying that public comment
would be taken commencing at 10:00 a.m. on March 22, 2017, which was the publicly noticed first day
of hearing in this matter, that the evidentiary portion of this proceeding would commence at 10:00 a.m.
on April 24, 2017, and that parties wishing to participate in the hearing were required to attend the
19
20
April 20, 2017 pre-hearing conference.
168.On January 18, 2017, EFCA filed its Motion for Reconsideration of the Approval of
21 APS's Motion for Protective Order.
22 169.On January 19, 2017, Mr. Woodward filed his Motion to Compel APS to Fully Answer
23 Woodward's Data Request 2.19.
24 170.
25 171.
26 172.
On January 19, 2017, EFCA filed a Motion to Associate Counsel Pro Hac Vice.
On January 19, 2017, Commissioner Bums filed correspondence.
On January 20, 2017, APS filed its Response to Mr. Woodward's Second Motion to
27 Compel.
28 173.On January 25, 2017, Mr. Woodward filed a Reply to APS's January 20, 2017
7629592DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
l Response.
l74.2
3
On January 27, 2017, Coolidge filed the Direct Testimony omits witness Rick Miller.
On January 27, 2017, Kroger filed the Direct Testimony omits witness Stephen J. Baron
176.5
6 l 77.
175.
4 on Cost of Service and Rate Design issues.
On January 30, 2017, Calpine filed notice omits name change.
On January 31, 2017, Freeport and AECC filed a request to remove C. Webb Crockett
7 from the service list in this matter.
8 178.
9 179.
On February 3, 2017, PORA filed the Direct Testimony omits witness Al Gervenack.
On February 3, 2017, the FEA filed the Direct Testimony of its witness Amanda M.
10 Alderson.
l l 180.On February 3, 2017, Walmart filed the Direct Testimony of its witnesses Gregory W.
15
12 Tillman and Chris Hendrix.
13 181.On February 3, 2017, AIC filed the Direct Testimony of its witnesses Gary Yaquinto,
14 Branko Terzik and Daniel G. Hansen.
182.On February 3, 2017, RUCO filed the Direct Testimony omits witnesses Frank Radigan
16 and Lon Huber.
17 183.
184.18
19
20
185.
186.
On February 3, 2017, Vote Solar filed the Direct Testimony omits witness Briana Kobor.
On February 3, 2017, ACAA filed the Direct Testimony omits witness Cynthia Zwick.
On February 3, 2017, SWEEP filed the Direct Testimony omits witness Jeff Sch1cgc1.
On February 3, 2017, SEIA filed the Direct Testimony omits witness R. Thomas Beach.
23
21 187.On February 3, 2017, EFCA filed the Direct Testimony of its witnesses James A.
22 Heidell and Mark E. Garrett.
188.On February 3, 2017, Freeport, AECC, Calpine, CNE, and Direct Energy filed the
24 Direct Testimony of their witness Kevin C. Higgins.
25 189.On February3, 2017, AURA filed the Direct Testimony omits witnesses Patrick J . Quinn
26 and Scott Rubin.
27 190.On February 3, 2017, ConservAmerica filed the Dircct Testimony of its witness Paul
28 Walker.
7629593DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
l 191.
3
4
5
6
7
8
9
l l
13
14
15
On February 3, 2017, Staff filed the Direct Testimony of its witnesses Ralph C. Smith
2 and Matt Connolly.
192.On February 6, 2017, a Procedural Order was issued granting Mr. Woodward's First
Motion to Compel, granting PORA's Request for authorization of Robert Miller to represent PORA as
an additional lay representative in this matter, and admitting Curt Ledford to appear pro hoc vice in
this matter.
193.On February 6, 2017, the IBEW Locals filed the Direct Testimony of their witness G.
David Vandever (Rate Design).
194.On February 7, 2017, Walmart filed a Notice of Errata in filing the Direct Testimony of
10 Gregory W. Tillman and Chris Hendrix (Rate Design).
195.On February 7, 2017, the IBEW Locals filed a Motion for Extension of Time and the
12 Direct Testimony of David Vandever.
196.On February 7, 2017, Commissioner Bums filed correspondence.
197.On February 9, 2017, Mr. Woodward filed a Motion for Clarification.
198.On February9, 2017, APS filed a Notice of Non-Objection to the IBEW Locals' Motion
On February 9, 2017, APS filed a Response to Mr. Woodward's Motion for
16 for Extension of Time.
17 199.
18 Clarification.
19 200.On February 16, 2017, Karen White, counsel for the FEA, filed a Motion to Associate
Counsel Pro Hac Vice.
201.On February 21, 2017, Commissioner Tobin filed correspondence.
202.On February 22, 2017, Chairman Forese filed correspondence.
20
21
22
23
24
On February 22, Commissioner Bums Hled correspondence.
On February 24, 2017, APS filed a Request for Extension of Time, and requested
On February 24, 2017, a Procedural Order was issued granting the Request for
203
204.
25 expedited consideration.
26 205.
27 Extension of Time.
28 206.On February 24, 2017, Granite Creek filed its Notice of Direct Filing for a Ruling on
7629594DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
I
2 207.
3 208.
5
Unattended Matters in the Matter of Fuel and Purchased Power Procurement.
On February 27, 2017, Chairman Forese filed Correspondence.
On February 28, 2017, Mr. Woodward filed his Motion to Compel Compliance with
4 February 6, 2017 Procedural Order.
209.On March l, 2017, Staff filed its Notice of Filing Settlement Term Sheet. Exhibit B to
the Settlement Term Sheet indicated the following parties' support of the Settlement Agreement
outlined in the March 1, 2017 Settlement Term Sheet: APS, AIC, the IBEW Locals, ConservAmerica,
6
7
8
9
ASDA, Vote Solar, EFCA, SEIA, AriSEIA, AURA, Direct Energy, Freeport, AECC, Calpine, CNE,
the Alliance, Walmart, Kroger, Granite Creek, FEA, Coolidge, ASBA, AASBO, WRA, SCHOA,
ll
10 PORT, ACAA, Ruco, and Staff
2 l 0.
12 211.
On March 2, 2017, Staff filed its Request for Modification of Procedural Schedule.
On March 2, 2017, Mr. Woodward filed his Motion for Rcconsideration of February 6,
14
13 2017 Procedural Order.
2 l2.
15
On March 3, 2017, APS filed its Response to Mr. Woodward's Third Motion to Compel.
On March 3, 2016, a Procedural Order was issued Modifying Filing Deadlines.
On March 6, 2017, Mr. Woodward filed his Reply to APS's Response.
On March 7, 2017, a Procedural Order was issued regarding Public Comment in
21
213.
16 214.
17 215.
18 Douglas Arizona.
19 216.On March 10, 2017, a Procedural Order was issued denying Mr. Woodward's Motion
20 to Compel Compliance with February 6, 2017 Procedural Order filed on February 28, 2017.
217.On March 10, 2017, APS and Pinnacle West filed a Renewed Motion to Quash.
22 218.On March 14, 2017, Commissioner Bums filed a Response and Objection to Motion to
23 Quash, or, in the Alternative, to Decline to Hear.
24 219.On March 15, 2017, a Procedural Order was issued regarding Public Comment in Yuma,
25 Arizona.
26 220.
27 221 .
28 222.
On March 21, 2017, APS filed a Certification of Publication.
On March 21, 2017, Staff filed Direct Testimony omits witness Dennis J. Shumaker.
On March 24, 2017, a Procedural Order was issued regarding Public Comment in
DECISION no.95 76295
DOCKET no. E-01345A-16-0036 ET AL.
l
2
Clarkdale, Arizona.
223.On March 24, 2017, a Procedural Order was issued changing the deadline for
3 Publication of the Clarkdale, Arizona Public Comment Session.
4
5
224.On March 24, 2017, Commissioner Forese filed Correspondence.
225.On March 24, 2017, Staff filed a Request for an Extension of Time to docket the
7
8
9
226.
227.
228.
10
ll
12
13
15
16
17
18
19
6 Settlement Agreement.
On March 27, 2017, Commissioner Little filed Correspondence.
On March 27, 2017, Commissioner Tobin filed Correspondence.
On March 27, 2017, a Settlement Agreement was filed, signed by APS, AIC, the IBEW
Locals, ConservAmerica, ASDA, Vote Solar, EFCA, SEIA, AriSEIA, AURA, Direct Energy, Freeport,
AECC, Calpine, CNE, the Alliance, Walmart, Kroger, Granite Creek, FEA, Coolidge, ASBA, AASBO,
WRA, SCHOA, PORA, ACAA, RUCO, and Staff.
229.On March 28, 2017, a Procedural Order was issued regarding Public Comment in
14 Flagstaff, Arizona.
230.On March 29, 2017, Commissioner Bums filed Correspondence.
23 I.On March 29, 20]7, a Procedural Order was issued changing the venue of the Flagstaff
Public Comment Session.
232.On March 30, 2017, APS filed a Certification of Pub1ication.
233.On March 30, 2017, the IBEW Locals filed Direct Testimony orG. David Vandever in
20 Support of Settlement Agreement.
21 234.On March 31, 2017, Staff docketed a Notice of Filing stating that the remaining
22 appendices to the Settlement Agreement would be filed on April 3, 2017.
235.On March 31, 2017, AURA filed the Direct Testimony of its witness Patrick J. Quinn23
24 on the Settlement Agreement.
25 236.On April 3, 2017, Mr. Gayer filed his Direct Testimony in Opposition to the Settlement
On April 3, 2017, AIC filed the Direct Testimony of its witness Gary Yaquinto in
26 Agreement.
27 237.
28 Support of Settlement Agreement.
7629596DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
l 238.On April 3, 2017, FEA filed the Direct Testimony of its witness Amanda M. Aldcrson
3
2 in Support of the Settlement Agreement.
239.On April 3, 2017, Patricia Ferré filed her Direct Testimony in Opposition to the
5 240.
7 241.
9
ll
13 244.
15 245.
17 246.
19 247.
21 248.
23 249.
25 250.
27 251.
4 Settlement Agreement.
On April 3, 2017, Mr. Woodward filed his Direct Testimony in Opposition to the
6 Settlement Agreement.
On April 3, 2017, Mr. Woodward filed the Direct Testimony of his witness Erik S.
8 Anderson, P.E. in Opposition to the Settlement Agreement.
242.On April 3, 2017, Mr. Woodward filed the Direct Testimony of his witness Dr. Sam
10 Milham, MD, MPH in Opposition to the Settlement Agreement.
243.On April 3, 2017, RUCO filed the Direct Testimony omits witness David P. Tenney in
12 Support of the Settlement Agreemcnt.
On April 3, 2017, ASDA filed the Direct Testimony omits witness Sean Seitz in Support
14 of the Settlement Agreement.
On April 3, 2017, Staff filed the Direct Testimony of its witnesses Ralph C. Smith and
16 Elijah O Abinah in Support of the Settlement Agreement.
On April 3, 2017, SWEEP filed the Direct Testimony of its witness Jeff Schlegel in
18 Opposition to the Settlement Agreement.
On April 3, 2017, ConservAmerica filed the Direct Testimony of its witness Paul
20 Walker in Support of the Settlement Agreement.
On April 3, 2017, EFCA filed the Direct Testimony of its witness James A. Heidell in
22 Support of the Settlement Agreement.
On April 3, 2017, EFCA filed the Direct Testimony of its witness Mark E. Garrett on
24 Commercial and Industrial Customer Rate Design.
On April 3, 2017, AARP filed the Direct Testimony of its witness John B. Coffman in
26 Opposition to the Settlement Agreement.
On April 3, 2017, AriSEIA filed the Direct Testimony of its witness Sara Birmingham
28 and R. Thomas Beach in Support of the Settlement Agreement.
7629597DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
l 252.
3 253.
5 254.
7
9
l l 257.
13 258.
On April 3, 2017, ACAA filed the Direct Testimony of its witness Cynthia Zwick in
2 Support of the Settlement Agreement.
April 3, 2017, APS filed the Direct Testimony of its witnesses Barbara Lockwood,
4 Leland Snook and Charles Miessner in Support of the Settlement Agreement.
On April 3, 2017, ED8/McMullen filed the Direct Testimony of their witness James D.
6 Downing in Opposition to Settlement Agreement.
255.On April 3, 2017, Freeport, AECC, Calpine, NcwEncrgy and Direct filed the Direct
8 Testimony of their witness Kevin C. Higgins in Support of the Settlement Agreement.
256.On April 3, 2017, Vote Solar filed the Direct Testimony omits witness Briana Kobor in
l()Support of the Settlement Agreement.
On April 3, 2017, Walmart tiled the Direct Testimony of its witness Chris Hendrix in
12 Support of Settlement Agreement.
On April 3, 2017, Staff filed a Notice ofFiling Remaining Appendices to the Settlement
14 Agreement.
15 259.
16 260.
17
18
19
20
21
22
23 261.
On April 5, 2017, APS filed a Certification of Publication.
On April 6, 2017, a Stipulated Motion was jointly filed in this docket by Staff RUCO,
APS, and the "Solar Parties" (ASDA, AriSEIA, SEIA, Vote Solar, and EFCA), ("Moving Parties")
stipulating to the entry of a Protective Order in this docket to govern the treatment of the Joint Solar
Cooperation Agreement ("JscA")4*" as requested by APS, the Solar Parties, and other entities who are
not interveners in this docket. The Moving Parties requested that a Protective Order to Govern the
Treatment of the Joint Solar Cooperation Agreement ("JSCA Protective Order") be entered in the form
attached to the Stipulated Motion as Exhibit A.
On April 7, 2017, Staff filed a Notice of Errata with a revision to the requested JSCA
24 Protective Order.
25 262.On April 10, 2017, counsel for Calpine, CNE, and Direct Energy filed a Motion to
26 Participate Telephonically in the Prehearing Conference, or in the Alternative, to be Excused from
27
28 481 The JSCA is an agreementbetweenAPS, the Solar Parties, and certain other entities who are not interveners in this case.
7629598DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.
2
3
4
l Attendance.
263.
264.
265.
On April I l, 2017, APS filed a Certification of Publication.
On April l l, 2017, Commissioner Bums filed Correspondence.
On April 13, 2017, Vote Solar filed a Motion to Participate Telephonically in Prehcaring
5 Conference or, in the Alterative, to be Excused from Attendance.
6
7
266.
267.
On April 14, 2017, a Protective Order was issued.
On April 17, 2017, Mary R. O'Grady filed a Motion to Associate Counsel Pro Hoc Vice
8 to associate Matthew E. Price as counsel for APS and Pinnacle West.
9 268.On April 17, 2017, Mr. Woodward, APS, Vote Solar and the IBEW Locals filed
l l
15
10 Responses to Commissioner Bums' April l 1, 2017 Correspondence Request.
269.On April 17, 2017, APS filed the Rebuttal Testimony of its witnesses Barbara
12 Lockwood, Leland Snook, Charles Miessner and Scott Bordenkircher on the Settlement Agreement.
13 270.On April 17, 2017, ConservAmerica filed the Rebuttal Testimony of its witness Paul
14 Walker in Support of the Settlement Agreement.
271.On April 17, 2017, Staff filed the Rebuttal Testimony of its witness Ralph C. Smith in
17
16 Support of the Settlement Agreement.
272.On April 17, 2017, SWEEP tiled the Rebuttal Testimony omits witness Jeff Schlegel in
274.
18 Opposition to the Settlement Agreement.
19 273.On April 17, 2017, Mr. Woodward filed his Rebuttal Testimony in Opposition to the
20 Settlement Agreement.
On April 17, 2017, APS and Pinnacle West filed a Motion to Associate Counsel pro hoc21
22 vice.
On April 17, 2017, EFCA filed a Motion for One Day Extension of Reply Testimony
278.
23 275.
24 of Mark E. Garrett.
25 276.On April 18, 2017, ED8/McMullen, AriSEIA, RUCO and EFCA filed Responses to
26 Commissioner Bums' April 1 1, 2017 Correspondence.
27 277.On April 18, 2017, a Procedural Order was issued admitting counsel pro hoc vice.
28 On April 18, 2017, EFCA filed the Rebuttal Testimony omits witness Mark E. Garrett.
7629599DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.
On April 19, 2017, Commissioner Bums filed Correspondence.
On April 19, 2017, Elijah Abinah, Director of the Utilities Division, filed
1
2
3
4
279.
280.
Correspondence.
281.On April 19, 2017, APS filed a Jointly-Developed Proposed Witness and Hearing
5 Schedule.
6
7
8
9
10
11
13
14
15
16 290.
282.On April 19, 2017, APS filed the Testimony Summaries of Barbara Lockwood, Leland
Snook, Charles Miessner and Scott Bordenkircher.
283.On April 20, 2017, the City of Sedona filed a Notice of Filing of Correspondence
284.On April 20, 2017, EFCA filed a Notice of Errata.
285.On April 21 , 2017, Commissioner Burns filed Correspondence.
286.On April 21, 2017, Commissioner Bums docketed court filings from the Maricopa
12 County Superior Court.
287.On April 21, 2017, Staff filed a Notice of Filing Supplemental Responses.
288.On April 24, 2017, Mr. Gayer filed the Summary of his Testimony.
289.On April 25, 2017, SWEEP filed the Testimony Summary of JeffSchlege1.
On April 26, 2017, APS filed an Objection to Commissioner Bums' Demand for
Witnesses, and (2) Approval of His Counsel Participating in Questioning (Expedited Ruling and
17 Testimony.
18 291.On April 26, 2017, Commissioner Bums filed his Emergency Motion for Relief (1)
19 Confirming that the Administrative Law Judge will Facilitate Calling and Questioning of Hearing
20
21 Suspension and Continuance of Hearing Requested).
22 292.On April 26, 2017, ED8/McMullen filed the Testimony Summary of James D.
24
294.
295.
26
27
28 296.
23 Downing.
293.On April 26, 2017, Staff filed the Testimony Summaries of Ralph C Smith, Elijah O.
25 Abinah and Dennis J. Schumaker.
On April 26, 2017, EFCA filed the Testimony Summary for Mark E. Garrett.
On April 27, 2017, RUCO filed the Testimony Summary of David P. Tenney.
On April 27, 2017, Mr. Woodward filed the Testimony Summary of Dr. Sam Milham,
DECISION no.76295100
DOCKET no. E-01345A-16-0036 ET AL.
1 MD, MPH.
2 297.On April 27, 2017, Mr. Woodward filed the Testimony Summary of Erik S. Anderson,
3 PE.
4
5
298.
299.
On April 27, 2017, Mr. Woodward filed his Testimony Summary.
On April 27, 2017, Commissioner Bums filed a Motion for Determination of
300.
6 Disqualification and for Stay of Proceedings Pending Full Investigation.
On May 1, 2017, Mr. Gayer filed a Motion to Suspend Proceedings Regarding the 90-7
8
9 301.
10 302.
Day Fair Notice Issue.
On May 4, 2017, APS filed the Declaration of Barbara Lockwood.
On May 4, 2017, SWEEP filed a Notice of Filing Corrected SWEEP Exhibit 6 and
On May 9, 2017, SWEEP filed its Notice of Filing Late Filed SWEEP Exhibits PA and
l l Related Corrections to SWEEP Exhibit 4.
12 303
13 8B.
14 304.On May 1 1, 2017, Mr. Woodward filed Corrections to Hearings Transcript Prepared by
15 Coash & Coash.
305.16
17
On May 15, 2017, Mr. Gayer filed his Initial Closing Brief.
306.On May 17, 2017, APS, AIC, the IBEW Locals, ConservAmerica, ASDA, Vote Solar,
18 EFCA, SEIA, AriSEIA, AURA, AECC, Freeport, Calpine, CNE, Direct Energy, Walmart, FEA,
19 ED8/McMullen, the Districts, ACAA, SWEEP, AARP, Mr. Woodward, RUCO, and Staff filed their
20 Initial Closing Briefs.
21 307.
22 308.
On May 26, 2017, a Special Open Meeting Revised Notice was docketed.
On May 30, 2017, Mr. Gayer filed his Reply Closing Brief.
23 309.On May 30, 2017, Commissioner Dunn filed Correspondence.
24 310.On June l, 2017, APS, AIC, the IBEW Locals, ConservAmerica, AECC, Freeport,
25 EFCA, SEIA, Calpine, CNE, Direct Energy, SWEEP, Mr. Woodward, and Staff filed their Reply
26 Closing Briefs.
27 31 1.
28 312.
On June 1, 2017, RUCO filed notice that it would not be filing a Reply Closing Brief.
On June 2, 2017, Commissioner Bums filed Correspondence, an Emergency Motion to
76295DECISION no.101
DOCKET NO. E-01345A-16-0036 ET AL.
2
3
4
5
6
7
8
9
I l
12
l Compel Compliance with Investigatory Subpoenas (Expedited Ruling and Suspension and
Continuance of Rate Case Proceedings Requested) and an Emergency Renewed Motion for Relief
Staying These Rate-Making Proceedings (Expedited Ruling Requested).
3 l 3.On June 5, 2017, Commissioner Bums filed a Notice of Errata Regarding Certificate of
Service for Emergency Motion to Compel Compliance with Investigatory Subpoenas (Expedited
Ruling and Suspension and Continuance of Rate Case Proceedings Requested).
314.On June 15, 2017, APS filed its Opposition to the Emergency Renewed Motion of
Commissioner Robert Bums for Relief Staying these Rate-Making Proceedings and its Opposition to
Emergency Motion of Commissioner Robert Bums to Compel Compliance with Investigatory
I()Subpoenas.
315.
316.
On June 20, 2017, Commissioner Little filed Correspondence.
On June 20, 20 l7, Commissioner Dunn filed a Proposed Interlocutory Order (Discovery
14 On June 20, 2017, Commissioner Bums filed a Response to Commissioner Dunn's
la Motions).
3 la.
15 Proposed Interlocutory Order.
16 318.On June 20, 2017, Commissioner Dunn filed a Proposed Amendment to the Proposed
17 Interlocutory Order.
18 319.On June 20, 2017, Chairman Foresee filed a Proposed Amendment to the Proposed
19 Interlocutory Order.
20 320.On June 26, 2017, Commissioner Bums filed a letter requesting the docketing of the
21 deposition transcripts of APS witnesses Barbara Lockwood, Charles A. Miessner, and Lcland R.
22 Snook.
23
24
321.
322.
On June 27, 2017, the Commission issued Decision No. 76161 .
On June 28, 2017, Commissioner Bums filed an Application for Rehearing of Decision
25 No.76l6l.
26 On June 29, 2017, FEA filed a Notice of Withdrawal of Attorney-of-Record Capt.323.
27 Natalie A. Ccpak.
28 324.On June 30, 2017, APS filed a response to Commissioner Bums' request for deposition
76295DECISION NO.l 02
DOCKET NO. E-01345A-16-0036 ET AL.
2
l transcripts.
325.
3 326.
On July 14, 2017, Commissioner Tobin filed Correspondence.
On July 21, 2017, EFCA docketed a letter in response to Commissioner Tobin's July
4 14, 2107 Correspondence.
5 Determinations
6 327.
7
8
9
10
l l
The rates, terns and conditions of the Settlement Agreement are just, fair and reasonable
and in the public interest, and should be adopted as set forth in the Settlement Agreement, except that
the issues surrounding the Settlement Agreement Proposed AMI Opt-Out program, which were heavily
litigated in this proceeding, will be bifurcated from this Decision, and will be addressed in a
forthcoming Decision.
328.The fair value of APS's jurisdictional rate base for the test year ending December 31,
13
12 2015 is s9,990,561,000.
329.APS'stotal adjusted test year revenue is $2,888,903,000.
14 330.A capital structure comprised of 44.2 percent debt and 55.8 percent common equity is
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15 appropriate for establishing rates in this matter.
33 l .
18 332.
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23 334.
25 335.
A return on common equity of 10.0 percent and an embedded cost of debt of 5.13
17 percent are appropriate estimates of the cost of capital for establishing rates in this matter.
A fair value rate of return of 5.59 percent, which includes a 0.8 percent return on the
19 fair value increment, is appropriate for establishing rates in this matter.
333.APS should be authorized a $362.58 million base rate increase comprised oaf increase
in its non-fuel base rates of$l48.250 million, a fuel base rate decrease of$53.63 million and a transfer
of cost recovery from adjustor mechanisms to base rates of $267.95 million.
Under the rems of the Settlement Agreement, the average bill impact is 4.54 percent
24 for residential customers, and 1.93 percent for general service customers.
A base cost of fuel and power of $0.030168 per kph is appropriate under the terms of
27 336.
28 337.
26 the Settlement Agreement.
The record in this matter should remain open as described in the Settlement Agreement.
The draft plan that APS files according to Section 27 of the Settlement Agreement
76295DECISION no.103
DOCKET no. E-01345A-16-0036 ET AL.
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should include a form of notice for customers who are on another rate that informs the customers of
their rate options after May l, 2018, accompanied by information on the estimated bill impact of
switching to another rate. For customers who are on another rate, the final approved notice must be
provided to the existing customer at least 3 billing cycles prior to May l, 2018, or the date on which
APS'snew rate plans commence, whichever event occurs later. It should also include a form of notice
to inform new ratepayers subject to the 90-day trial period of their rate options at the conclusion of the
trial period, and address a suitable method for delivery of such notice so that such customers will
receive the notice shortly after, or concurrently with, their second bill, in order to provide them with
sufficient notice should they wish to begin taking service at that time on the R-Basic rate plan instead
of a time- or demand-differentiated rate plan.
APS should be required to comply with the Staff recommendations in regard to its power
13 339.
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12 procurement procedures and documentation.
Optional rates to encourage the adoption of battery storage among APS E-32L and E-
32L TOU customers should be added and approved and the tariffshall include the following restrictions
and safeguards similar to those in both the R-Tech and TEP Tariff:
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Program Size
APS's optional Large General Service Time-of-Use Storage Program Tariff (the Optional Tariff) will
be capped at a peak demand total of 35,000 kW for installed systems and active interconnection
applications, on a first-come first-served basis. Allotments shall be reserved at the time of submittal
of a complete interconnection application.
Stakeholder Process
Once 70% of the initial program capacity has been reached, and if such threshold has been reached
prior to APS's next general rate case filing, APS will evaluate whether the costs of the program are
less than the system benefits it provides. If APS determines that the costs are less than the benefits,
APS shall provide notice and promptly convene a meeting of the interested parties to this Docket to
discuss the future of the program. If all parties to that discussion agree on a new program size for the
Optional Tariff that shall apply until the Commission determines the disposition of the Optional
Tariff during APS's next general rate case, APS shall file a notice in this Docket to that effect and the
76295DECISION no.l04
DOCKET no. E-01345A-16-0036 ET AL.
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program shall remain in effect up to the new agreed upon customer participation level, unless the
Commission orders otherwise. However, if all parties cannot agree upon a new customer
participation level, APS within 90 days of the finalization of the discussions, shall tile a request with
the Commission to establish the terms and conditions under which the program will continue or
terminate. If APS determines that the costs are greater than the system benefits, APS will file a
request with the Commission to freeze the program until changes can be made in APS'snext general
rate case.
8 Minimum Peak Demand Reduction
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To qualify for the Optional Tariff, a customer must install a chemical, mechanical or thermal energy
storage system that is capable of allowing the customer to offset a minimum of 20% of their
measured peak demand during the On-Peak period. The determination of the measured peak demand
for purposes of the calculation will be based on the customer's previous year's measured peak
demand during such period prior to installation of storage facilities. If this is a new facility, the
calculation of the 20% demand reduction will be determined based on APS's total estimated peak
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demand designed for the facility.
VAR Support
In order to qualify for the program where a power producing facility is installed, inverters must be
capable of and configured to provide VAR support so that a near unity power factor of at least 95% is
maintained during operation.
20 TOU Hours
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For purposes of the APS Optional Tariff, the On-Peak period under the program will be determined
as the 6 greatest average system demand hours during the previous three years by season. The Off-
Peak period will be determined as the 12 lowest average system demand hours during the previous
three years by season. All other hours shall be deemed as Remaining Hours.
Annual Reporting
Until such time that a final order is issued in APS's next general rate case, on July l of each year
APS shall submit an informational filing in the docket, reporting on the status of the APS Optional
Tariff. The report will include: (i) the number of customers, both in the current year and
76295105DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
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cumulatively, that are participating in the program (including the proportion of these customers
relative to the entire large commercial class), (ii) the total peak demand of such customers relative to
the initial program allotment of 35,000 kw, (iii) observed peak demand reductions, if any, of
customers participating in the program, (iv) recommended changes, if any, to the Time-of Use
periods for the program, (v) if available, information regarding the average time to process
applications from customers requesting participation in the program, and (vi) current year and
cumulative kph exported to the grid by participating customers.
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16 while also ensuring appropriate cost recovery.
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Rate Design
The APS Optional Tariff shall not include a demand ratchet, Off-Peak demand charge or declining
block demand charge. On-Peak billing demand shall be equal to the greatest measured 15 minute
interval demand read of the meter during the On-Peak Hours or the Remaining Hours during the billing
period.The APS Optional Tariff may include a minimum contract demand provision. The APS
Optional Tariff may also include a summer and winter Off-Peak excess demand charge for Off-Peak
exceeding l 50% of On-Peak billing demand. The customer service charge component of the APS
Optional Tariff will be structured to maintain proper price signals to incept peak demand reduction
Storage customers taking service under the APS
Optional Tariff that also have distributed generation remain eligible for the EPR-6 net metering rider.
18 340.Forest bioenergy has become an increasingly important energy source in Arizona, for
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many reasons. Forest bioenergy is a carbon-neutral, renewable energy source. It creates energy for
the grid while encouraging responsible forest management and reducing the risk of wildfires. Federal
agencies like the U.S. Department of Energy, the U.S. Department of Agriculture, and the
Environmental Protection Agency have recently been directed to develop policies which recognize
these benefits and encourage the use of forest biocnergy as an energy source. The energy community
in Arizona should likewise explore the benefits of this important energy source.
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DECISION no.106 76295
DOCKET NO. E-0I 345A-16-0036 ET AL.
l CONCLUSIONS OF LAW
2 1.APS is a public service corporation within the meaning of Article XV, Sections 3 and
3 14 of the Arizona Constitution, A.R.S. §§ 40-203, -204, -221, -250, -251, and -361, and A.A.c. R14-
4 2-801 et. seq.
5 2.
6 3.
7 4.
8 5.
The Commission has jurisdiction over APS and the subject matter of the applications.
Notice of the application and hearing was provided in accordance with the law.
The rate and charges produced by the Settlement Agreement are just and reasonable.
Adoption of the Settlement Agreement as discussed herein is in the public interest.
9 ORDER
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IT IS THEREFORE ORDERED that the Settlement Agreement attached hereto as Exhibit A is
adopted, as modified herein, except that the issues surrounding the Settlcmcnt Agreement Proposed
AMI Opt-Out program, which were heavily litigated in this proceeding, will be bifurcated from this
Decision, and will be addressed in a forthcoming Decision.
IT IS FURTHER ORDERED that the Settlement Agreement is hereby modified as follows:
15 After September l, 2018, R-Basic Large will no longer be available to customers who are on another
16 rate.
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IT IS FURTHER ORDERED that Arizona Public Service Company is hereby direct to file with
the Commission on or before August 18, 2017, revised schedules of rates and charges and Plans of
Administration consistent with Exhibit A and the findings herein.
IT IS FURTHER ORDERED that this rate case shall be held open to allow Arizona Public
Service Company to file a request that its rates be adjusted no later than January 1, 2019 to reflect its
proposed addition of Selective Catalytic Reduction equipment at the Four Comers Generating Station.
IT IS FURTHER ORDERED that the revised schedules of rates and charges shall be effective
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for all service rendered on and after August 19, 2017. The grand fathering date for customers submitting
interconnection applications for DG systems is extended through August 3 l , 2017.
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 acceptable to the Commission's
76295DECISION no.107
DOCKET NO. E-01345A-16-0036 ET AL.
l Utilities Division Staff.
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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.
IT IS FURTHER ORDERED that Arizona Public Service Company shall, in future rate cases,
6 impute net revenue growth for any revenue producing plant included in post-test year plant.
IT IS FURTHER ORDERED that as set forth in the Settlement Agreement, Arizona Public
Service Company shall not file its next general rate case before June l, 2019, with a test year ending
no earlier than December 3 l , 2018.
IT IS FURTHER ORDERED that $1.25 million of the revenue requirement increase approved
l l in this order is dedicated to funding Arizona Public Service Company's crisis bill assistance program.
IT IS FURTHER ORDERED that Arizona Public Service Company is hereby authorized to
defer, for possible later recovery through rates, all non-fuel costs (as defined herein to include all O&M,
property taxes, depreciation, and a return at APS's embedded cost of debt in this proceeding) ofowning,
operating, and maintaining the Ocotillo Modernization Projcct and retiring the existing steam
generation at Ocotillo. Nothing in this Ordering Paragraph shall be construed in any way to limit the
Commission's authority to review the entirety of the project and to make any disallowances thereof
due to imprudence, errors or inappropriate application of the requirements of this Decision. The interest
component of the deferral shall be set at the embedded cost of debt established in this Decision.
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IT IS FURTHER ORDERED that Arizona Public Service Company is authorized to defer for
possible later recovery through rates, all non-fuel costs (as defined herein to include all O&M, property
taxes, depreciation, and a return at APS's embedded cost of debt in this proceeding) of owning,
operating, and maintaining the Selective Catalytic Reduction environmental controls at the Four
Comers Power Plant. Nothing in this Decision shall be construed in any way to limit this Commission's
authority to review the entirety of the project and to make any disallowances thereofdue to imprudence,
errors or inappropriate application of the requirements of this Decision.
IT IS FURTHER ORDERED that Arizona Public Service Company is hereby authorized to
28 defer, for future recovery (or credit to customers), the Arizona property tax expense above or below
108 DECISION no.7
DOCKET NO. E-01345A-16-0036 ET AL.
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the test year caused by changes to the applicable composite property tax rate, subject to the provisions
set forth in the Settlement Agreement Section l l.
IT IS FURTHER ORDERED that in the event that significant Federal income tax reform
legislation is enacted and becomes effective prior to the conclusion of Arizona Public Service
Company's next general rate case, and such legislation materially impacts the Company's annual
revenue requirements Arizona Public Service Company is hereby authorized to create a rate adjustment
mechanism to enable the pass-through of income tax effects to customers, in accordance with the
requirements set forth in Section 16 of the Settlement Agreement.
IT IS FURTHER ORDERED that the disposition of collected but unspent DSMAC funds as set
10 forth in the Settlement Agreement is approved, consistent with the discussion herein.
IT IS FURTHER ORDERED that within 15 business days of a Commission Decision in this
matter, APS shall file, with Docket Control, a draft Customer Education and Outreach Program
("CEOP") for the Commission Staffs review and approval. Stakeholders will have 10 calendar days
to provide comment and APS will have 10 days thereafter to file a final plan. The Commission Staff
shall approve a Final CEOP. The draft CEOP shall include a proposed form of notice for both customers
who are on another rate and new customers that informs the customers of their rate options after May
l, 2018, accompanied by information on the estimated bill impact of switching to another rate. For
customers who are on another rate, the final approved notice must be provided to the existing customer
at least 3 billing cycles prior to May l, 2018, or the date on which APS's new rate plans commence,
whichever occurs later.
IT IS FURTHER ORDERED that the draft plan that Arizona Public Service Company files
according to Section 27 of the Settlement Agreement shall include a form of notice to inform new
ratepayers subject to the 90-day trial period of their rate options at the conclusion of the trial period,
accompanied by information on the estimated bill impact of switching to another rate, and shall address
a suitable method for delivery of such notice so that such customers will receive the notice shortly after,
or concurrently with, their second bill, in order to provide them with sufficient notice should they wish
to begin taking service at that time on the R-Basic rate plan instead of a time- or demand-differentiated
rate plan.
76295DECISION no.109
DOCKET no. E-01345A-16-0036 ET AL.
1 IT IS FURTHER ORDERED that Arizona Public Service Company shall implement the
2 following Staff recommendations within the following timeframes in regard to power procurement
3
4
procedures and documentation:
Staff
Recommendation
11- 15
6 111-1
7 111-2
IQ8
111-3
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0-6 months111-4ll
Initiation
Description Timeframe
Perform a study to determine if changes can be made to the coal 0-6 months
su Ly chain to yield some plant efficiencies.
Improve spreadsheet usage and associated references and cross 0-12 months
references on how used.
Have internal or external auditors audit PSA filings, as they have 0-18 months
yet to address PSA filing procedures.
Incorporate more detailed implementation steps, including 0-6 months
sample screen prints, in Monthly PSA Filings documentation,
plus risk management documentation, which should be reviewed
and modified, as necessa , at least annually .
Develop formal written documentation for supplemental fuel
char 'es or refunds.¢
12
13
IT IS FURTHER ORDERED that Arizona Public Service Company shall, within 120 days from
the date of this order, file a new, optional storage-friendly tariff and that the tariff shall include the
14 .. .. ...following restrictions and safeguards similar to those in both the R-Tech and TEP Tariff:
15 .PI02T8M Size
16 .......APS's optional Large General Service Time-of-Use Storage Program Tariff (the Optional Tariff) will
17 ...be capped at a peak demand total of 35,000 kW for installed systems and active interconnection
18 ....applications, on a first-come first-served basls. Allotments shall be reserved at the time of submittal
19 ....of a complete interconnection application.
20 Stakeholder Process
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22
23
Once 70% of the initial program capacity has been reached, and if such threshold has been reached
prior to APS's next general rate case filing, APS will evaluate whether the costs of the program are less
than the system benefits it provides. If APS determines that the costs are less than the benefits, APS
24 shall provide notice and promptly convene a meeting of the interested parties to this Docket to discuss
25 the future of the program. If all parties to that discussion agree on a new program size for the Optional
26 Tariff that shall apply until the Commission determines the disposition of the Optional Tariff during
27 APS's next general rate case, APS shall file a notice in this Docket to that effect and the program shall
28
76295l 10 DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
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remain in effect up to the new agreed upon customer participation level, unless the Commission orders
otherwise. However, if all parties cannot agree upon a new customer participation level, APS within
120 days of the finalization of the discussions, shall file a request with the Commission to establish the
terms and conditions under which the program will continue or terminate. If APS determines that the
costs are greater than the system benefits, APS will file a request with the Commission to freeze the
program until changes can be made in APS's next general rate case.
Minimum Peak Demand Reduction
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To qualify for the Optional Tariff a customer must install a chemical, mechanical or thermal energy
storage system that is capable of allowing the customer to offset a minimum of 20% of their measured
peak demand during the On-Peak period. The determination of the measured peak demand for purposes
of the calculation will be based on the customer's previous year's measured peak demand during such
period prior to installation of storage facilities. If this is a new facility, the calculation of the 20%
demand reduction will be determined based on APS's total estimated peak demand designed for the
14
15
16
17
18
facility.
VAR Support
In order to qualify for the program where a power producing facility is installed, inverters must be
capable of and configircd to provide VAR support so that a near unity power factor of at least 95% is
maintained during operation.
19 TOU Hours
20
2]
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23
24
25
26
27
28
For purposes of the APS Optional Tariff, the On-Peak period under the program will be determined as
the 6 greatest average system demand hours during the previous three years by season. The Off-Peak
period will be determined as the 12 lowest average system demand hours during the previous three
years by season. All other hours shall be deemed as Remaining Hours.
Annual Reporting
Until such time that a final order is issued in APS'snext general rate case, on July l of each year APS
shall submit an informational filing in the docket, reporting on the status of the APS Optional Tariff.
The report will include: (i) the number of customers, both in the current year and cumulatively, that are
participating in the program (including the proportion of these customers relative to the entire large
76295DECISION no.Il l
DOCKET NO. E-01345A-16-0036 ET AL.
l
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commercial class), (ii) the total peak demand of such customers relative to the initial program allotment
of35,000 kw, (iii) observed peak demand reductions, if any, of customers participating in the program,
(iv) recommended changes, if any, to the Time-of Use periods for the program, (v) if available,
information regarding the average time to process applications from customers requesting participation
in the program, and (vi) current year and cumulative kph exported to the grid by participating
6 customers.
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Rate Design
The APS Optional Tariff shall not include a demand ratchet, Off-Peak demand charge or declining
block demand charge. On-Peak billing demand shall be equal to the greatest measured 15 minute
interval demand read of the meter during the On-Peak Hours or the Remaining Hours during the billing
period. The APS Optional Tariff may include a minimum contract demand provision. The APS
Optional Tariff may also include a summer and winter Off-Peak excess demand charge for Off-Peak
exceeding 150% of On-Peak billing demand. The customer service charge component of the APS
Optional Tariff will be structured to maintain proper price signals to incept peak demand reduction
while also ensuring appropriate cost recovery. Storage customers taking service under the APS
Optional Tariff that also have distributed generation remain eligible for the EPR-6 net metering rider.
IT IS FURTHER ORDERED that when acquiring any new resource or transmission or
distribution upgrade where appropriate, APS shall demonstrate that its analysis of resource and system
upgrade options include a storage alterative. In the analysis, APS must demonstrate that it has
reasonably considered all of the costs and benefits of each resource or system upgrade option, allowing
for comparisons to be made on similar terms and planning assumptions. Energy storage shall also be
included as a resource option in any analysis of caseload resources as well as any analysis of non-
23 caseload resources.
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25
26
27
IT IS FURTHER ORDERED that APS shall include accurate cost data in its modeling
assumptions in connection with the above Ordering Paragraph. APS shall account for the forecasted
decline in energy storage costs and ensure that storage resources are modeled in such a way that the
Integrated Resource Planning model captures their impact. Costs shall also be transparent by providing
28
76295DECISION no.112
DOCKET no. E-01345A-16-0036 ET AL.
l the cost of each technology with and without state and federal tax incentives and/or credits. APS shall
3
2 also identify and analyze a reasonable, representative range of storage technologies and chemistries.
IT IS FURTHER ORDERED that as part of its 2018 Demand Side Management
4
5
Implementation Plan filing, APS shall develop and propose to the Commission, for approval, a program
available to water utilities within its service territory that would result in a reduction in water loss,
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6 electricity, consumption, or peak demand.
IT IS FURTHER ORDERED that APS shall report back to the Commission within 90 calendar
days of the docketing of this Order, and provide at least three scenarios for forest bioenergy that
examine low-, medium-, and high-use of forest bioenergy. This report shall take into consideration
forest thinning activities, and evaluate the costs of said activities, any adjustments that should be made
to APS's revenue requirement or power supply adjustor, environmental benefits, and any other relevant
information that will help the Commission moving forward. This report shall also include the amount
of forest acres affected by each case scenario, as well as projected water savings. In connection with
this report, APS is expected to consult with the following parties:Salt River Project, Arizona
Department of Water Resources, Arizona State Forester's Office, United States Forest Service, Four
Forest Restoration Initiative, and other relevant stakeholders.
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DECISION NO.113 76295
DOCKET no. E-01345A-16-0036 ET AL.
1 IT IS FURTHER ORDERED that the Commission's Federal Affairs Committee shall review
2
3
the APS forest bioenergy report and return to the Commission with appropriate recommendations.
T IS F R ORDERED that this Decision shall become effective immediately.
ARIZONA CORPORATION COMMISSION.4 .
5
6
COM ISSIONER DUNNCHAIRMANFORESE
7
DISSENT
I ITTLE COMMISSIONER BURNSSIOBIN9 COMMISSIO
10
l l 1944-
IN WITNESS WHEREOF, I, TED VOGT, Executive Director of
the Arizona Corporation Commission, have hereunto set my
hand and caused the official seal of the Commission to be affixed
at the Ca ital, in the City of Phoenix, this day
of 2017.-+'12
13
\"f\.v
\* _`~\-.. ~ ~ /
`` <4\.,
§.:. .-..>\.. _;»..`.`:\.\.,-..4 ../,
'I...4\-._ .L..:..-Rx .. -.
\/A .
14 `_
l TED VOGT
EXECUTI E DIRECTOR
15
/
/16 DISSEN
17
18 DISSENT
TJ/It19
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114 DECISION no. 76295
..¢8 BOB BURNS
Commissioner
L "§
..;-r
.,.,.»<*
COMMISSIONERS
TOM FORESE - Chairman
BOB BURNS
DOUG LITTLE
ANDY TOBIN
BOYD DUNN ARIZONA CORPORATION COMMISSION
August 16, 2017
RE:Dissenting Opinion in APS Rate Case
Dockets No. E-01345A-16-0036, E-01345A-16-0123
Dear Commissioners, Parties and Stakeholders:
I strongly dissent from this decision, and reiterate the positions I expressed in my earlier motions
in this rate case and in my comments raised at relevant Commission Staff and Regular Open
Meetings. The analysis I have raised, and the precedent, constitutional and statutory provisions
I have cited, all establish that this decision is a violation of my legal rights and obligations to
advance the public's interest, and in violation of this Commission's constitutional obligations to
the public.
Furthermore, the evidence presented in this case did not justify the rate increase.RUCO,
Commission Staff and EFCA all originally testified that the evidence supported a 0% rate
increase, or even a rate decrease. This decision takes away customer choice and requires
customers to be on time-of-use or demand rates regardless of their needs or desires. Making it
more expensive to run air conditioners, do laundry or cook during 3:00-8:00 p.m. on our hot
summer days is bad policy.
Fortunately, Arizona law allows the courts to overturn this vote, to require APS to make
appropriate refunds to customers, and to eliminate any risks that pro-APS bias or partiality will
affect any more rate decisions. I want to assure the Arizona citizens who depend on us daily that
I will not succumb to the strategy of APS and the Commissioners, who have accepted their
invitation to ignore Arizona customers. I will not allow them to safeguard the improper approval
of a rate increase by simply outspending me with the massive amounts of public tax dollars and
hard-earned ratepayer monies they have now committed to an army of lawyers. I will continue
my struggle to enforce the constitutional rights the framers of our government intended. I will
continue my fight to protect the interests of Arizona's utility customers against the unacceptable
undue influence by a regulated monopoly that our State's founders expected us to resolutely
resist.
76Decision No
August 16, 2017
Commissioners, Parties and Stakeholders
Page 2
The Commission's decision to proceed with a vote approving the APS rate request, especially
by a final order that does not remind APS of its potential duty to refund consumer payments
should my legal challenges succeed and without imposing a bond requirement to guarantee
funding for immediate refunds should they be required, ignores the substantial rate impacts that
will detrimentally affect Arizona customers within the next few days. It also violates
fundamental constitutional obligations our framers put in place to assure that bias and
disqualification issues are fully investigated, disclosed and acted on to protect consumers and
parties.
As I stated at the meeting, the citizens who created this Commission and gave it unique Powers
through our constitution, expected we would consider fully and protect the interests of utility
consumers, not our own personal interests. My colleagues' decisions to disregard consumer
interests and cast votes approving this rate request fell far short of those expectations, acting
outside their legal authority and creating an illegal and unenforceable order and approval.
For these reasons and for all the reasons outlined in my filings in this docket, my comments at
Staff and Regular Open Meetings, including the Open Meeting where this decision was
approved, I dissent.
Sincerely,
Robert L. Burns
Commissioner
Decision No
l ARIZONA PUBLIC SERVICE COMPANYSERVICE LIST FOR:
E-01345A-16-0036 AND E-01345A-I6-01232 DOCKET NO.:
3
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Patrick J. Black
C. Webb Crockett
FENNEMORE CRAIG PC
2394 E. Camelback Road, Suite 600
Phoenix, Arizona 85016
Attorneys for Freeport Minerals Corporation and
Arizonans for Electric Choice and Competition
wcrocket(a1fclaw.co1n
[e-mail]
khi2szins(Hener2vstrat.com
Consented to Service by Email8
9
Thomas A. Loquvam
Thomas L. Mum aw
Melissa M. Krueger
PINNACLE WEST CAPITAL CORPORATION
400 North 5th Street, MS 8695
Phoenix,AZ 85004
Attorneys for Arizona Public Service Company
Thomas.Loquvam(dl;pirmaclewest.com
Thomas.Mumaw61wpinnaclewest.com
Melissa.Kreu2er(1lipinnaclewest.com
Amanda.Ho(tzpinnaclewest.com
[e-mail]
prcfb(aswlaw.com
Consented to Service b Email
10
Daniel Pozefsky, Chief Counsel
RESIDENTIAL UTILITY CONSUMER OFFICE
l l 10 W. Washington, Suite 220
Phoenix, AZ 85007
12
Matthew E.Price
JENNER & BLOCK
1099 New York Avenue, NW Suite 900
Washington, DC 200014412
Attorneys for Arizona Public Service Company and
Pinnacle West Capital Corporation13
14
15
Greg Eisert, Director
Steven Puck, Director
Government Affairs
SUN CITY HOMEOWNERS ASSOCIATION
10401 W. Coggins Drive
Sun City,AZ 85351
ure2eiser1(a42tnail.co1n
Qeven.puck(a4cox.net
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Mary R. O'Grady
OSBORN MALEDON, P.A.
2929 North Central Avenue, 2 let Floor
Phoenix,AZ 85012
Attorneys for Arizona Public Service Company and
Pinnacle West Capital Corporation
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Patricia Ferré
P.O. Box 433
Payson, AZ 85547
pFerréact(a mac.com
Consented to Service by Email
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Richard Gayer
526 W. Wilshire Drive
Phoenix, AZ 85003
f28VCf((( cox.nct
Consented to Service by Email22
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Timothy M. Hogan
ARIZONA CENTER FOR LAW IN THE PUBLIC
INTEREST
514 W. Roosevelt st.
Phoenix,AZ 85003
Attorneys for Wester Resource Advocates,
Southwest Energy Efficiency Project, and Vote Solar
tho2an(a.aic(waclpi.or2
ken.wilson(dwestemresourcesorg
[e-mail]
emckeman(dswener2v.or2
bbaatz(daceee.or2
[e-mail]2
[e-mail]
[e-mail]§z
cfitzgerrell(ZUear1hiustice.org
Consented to Service by Email24
Warren Woodward
55 Ross Circle
Sedona, AZ 86336
w6345789(a?vahoo.com
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T. Hogan
ARIZONA CENTER FOR LAW IN THE PUBLIC
INTEREST
514 W. Roosevelt St.
Phoenix AZ 85003
Attorneys for Arizona School Boards Association and
Arizona Association of School Business Officials
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Anthony L. Wander
Alan L. Kiernan
Brittany L. DeLorenzo
IO DATA CENTERS LLC
615 n. 48th St.
Phoenix, AZ 85008
DECISION no. 76295115
DOCKET no. E-01345A-l6-0036 ET AL
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Meghan H. Grabel
OSBORN MALEDON, P.A.
2929 N Central Ave., Suite 2100
Phoenix, Arizona 85012
Attorneys for Arizona Investment Council
Merabel(a;oinlaw.coni
<[e-mail]
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Jay I. Moyes
MOYES SELLERS & HENDRICKS LTD
1850 N. Central Avenue, Suite l 100
Phoenix, AZ 85012
Attorneys for Electrical District Number Eight and
McMullen Valley Water Conservation & Drainage
District
[e-mail]
iimoves(¢2law-rnsh.com
[e-mail]
Consented to Service by Email
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Craig A. Marks
CRAIG A. MARKS, PLC
10645 n. Tatum Blvd., Suite 200676
Phoenix, AZ 85028
Attorney for Arizona Utility Ratepayer Alliance
[e-mail]2
Pat.ouinn47474(a.s1mail.com
Consented to Service by Email
Kun J. Boehm
Jody Kyler Cohn
BOEHM KURTZ & LOWRY
36 E. Seventh Street, Suite 1510
Cincinnati, OH 45202
Attorneys for The Kroger Co.9
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John William Moore Jr.
7321 North 16th Street
Phoenix, AZ 85020
Attorney for The Kroger Co.
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Al Gervenack, Director
Rob Robbins President
Robert Miller, Director
PROPERTY OWNERS & RESIDENTS
ASSOCIATION
13815 Camino del Sol
Sun City West, AZ 85372
[e-mail]§z
[e-mail]2
Bob.miller@1'porascw.or2
Consented to Service by Email
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Giancarlo G. Estrada
KAMPER ESTRADA, LLP
3030 N. 3rd Street, Suite 770
Phoenix, AZ 85012
Attorneys for Solar Energy Industries Association
2estrada(ivlawphx.com
[e-mail]
kcrandallQ1eq-research.com
Consented to Service by Email
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Tom Harris, Chairman
ARIZONA SOLAR ENERGY INDUSTRIES
ASSOCIATION
2122 W. Lone Cactus Dr. Suite 2
Phoenix, AZ 85027
n.Harrislu AriSEIA_.qg
Consented to Service by Email18
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Cynthia Zwick, Executive Director
Kevin Hengehold, Energy Program Director
ARIZONA COMMUNITY ACTION
ASSOCIATION
2700 N. 3rd Street, Suite 3040
Phoenix, AZ 85004
czwick(&2azcaa.org
khcnncho1d(1lazcaa.oru
Michael W. Patten
Jason D. Gellman
SNELL & WILMER LLP
One Arizona Center
400 East Van Buren Street
Phoenix AZ 85004
Attorneys for Tucson Electric Power Company
n1pa[[€ll@1.i8Wla\y€0)
[e-mail]
[e-mail]
Bcarroll6iltep.com
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Charles Wesselhoft, Deputy County Attorney
PIMA COUNTY ATTORNEY'S OFFICE
32 North Stone Avenue Suite 2100
Tucson AZ 85701
Charles.Wessclholi(z1pcao.pima.gov
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Lawrence V. Roberson, Jr.
210 Continental Road Suite 2 leA
Green Valley, AZ 85622
Attorney for Calpine Energy Solutions LLC,
Constellation New Energy, Inc., and Direct Energy
Business, LLC
[e-mail]]
Consented to Service by Email
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DECISION no. 76295116
DOCKET no. E-01345A-16-0036 ET AL
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Court S. Rich
ROSE LAW GROUP PC
7144 E. Stetson Drive, Suite 300
Scottsdale, AZ 8525 l
Attorneys for Energy Freedom Coalition of America
[e-mail]
hslau2hter@i>roselawizroup.com
cledford(é1;mcdonaIdcargngcom
Consented to Service by Email
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Greg Patterson
MUNGER CHADWICK
916 West Adams, Suite 3
Phoenix AZ 85007
Attorneys for Arizona Competitive Power Alliance
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Albert H. Acken
Sheryl A. Sweeney
Samuel L. Lowland
RYLEY CARLOCK & APPLEWHITE
One N. Central Avenue, Suite 1200
Phoenix, AZ 85004
Attorneys for Electrical District Number Six, Penal
County, Arizona,
Electrical District Number Seven of the County of
Maricopa, State of Arizona,
Aquila Irrigation District, Tonopah Inigation District,
Harquahala Valley Power District,
and Maricopa County Municipal Water Conservation
District Number One
aacken&lrcalaw.com
[e-mail]
[e-mail]
iiw(d*krsaline.com
Consented to Service by Email
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Scott S. Wakefield
HIENTON CURRY, PLLC
5045 N. l2'*' Street, Suite 110
Phoenix,AZ 85014
Attorneys for Walmart Stores, Inc.
swakefield(a:hclaw2roup.com
mlouuee(a8hclaw2roup.com
Stephen.chriss(a1Walmart.com
Gre2.tillman@WalmarLcom
chris.hendrix(&Wa1man.com13
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Thomas A. Jernigan
Karen S. White
Lanny I. Zieman
FEDERAL EXECUTIVE AGENCIES
U.S. Air Force Utility Law Field Support Center
139 Bames Drive, Suite l
Tyndall Air Force Base, FL 32403
Attorneys for Federal Executive Agencies
thomas.iemi2an.3(a;us.af.mil
[e-mail]
andrew.unsicker(i1Qus.a£mil
lannvzieman. l(ivus.af.1nQ
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Nicholas J. Enoch
Kaitlyn A. Redfield-Ortiz
Emily A. Tomabene
LUBIN & ENOCH, PC
349 N. 4th Avenue
Phoenix,AZ 85003
Attorneys for Local Unions 387 and
769 ofIBEW, AFL-CIO18
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Garry D. Hays
THE LAW OFFICES OF GARRY D. HAYS, PC
2198 E. Camelback Rd., Suite 305
Phoenix, AZ 85016
Attorney for the Arizona Solar Deployment Alliance
2havs(a lawudlrcom
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Ann-Marie Anderson
WRIGHT WELKER & PAUOLE, PLC
10429 South 51st Street, Suite 285
Phoenix,AZ 85044
Attorneys for AARP
aanderson(dZwwpfirm.com
sennin sWam .or
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aallen6z&wwpfirm.coni
[e-mail]
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Thomas E. Stewart, General Manager
GRANITE CREEK POWER & GAS LLC
GRANITE CREEK FARMS LLC
5316 E. Voltaire Ave.
Scottsdale, AZ 852543643
IOUIIII ucfaz.com
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Robert L. Pickels, Jr.
Sedona City Attorney's Office
102 Roadrunner Drive
Sedona,AZ 86336
Attorneys for City of Sedona
rpickels@sedonaaz.2ov
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117 DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL
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Denis M. Fitzgibbons
FITZGIBBONS LAW OFFICES, PLC
1 15 E. Cottonwood Lane, Suite 150
PO Box 11208
Casa Grande AZ 85130
Attorney for City of Coolidge
denis(u litzgibbonslawxonl
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Timothy J. Sabo
SNELL & WILMER, LLP
One Arizona Center
400 E. Van Buren St.
Phoenix, AZ 85004
Attorneys for REP America d/b/a ConservAmerica
tsabo(a.1swlaw.com
[e-mail]
docket(i12swlaw.com
pwalker@iconservamericaorg
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Andy Kvesic Director
Legal Division
ARIZONA CORPORATION COMMISSION
1200 West Washington Street
Phoenix, AZ 85007
Attorneys for the Utilities Division
LegalDiv(cLazcc.gov
Utildivservicebvemail@azcc.2ov
[e-mail]
CHains61 azcc.gov
WVanCleve0l azcc.2ov
TFord(idazcc.2ov
[e-mail]
CFitzsimmons(é1Qazcc.gov
KChristine(d*azcc.gov
EAbinah@azcc.2ov
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76295118DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
EXHIBIT A
l
ARIZONA PUBLIC SERVICE COMPANY
DOCKET nos. E-01345A-16-0036 and E-01345A_16_0123
SETTLEMENT AGREEMENT
MARCH 27 2017
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
TABLE OF CONTENTS
1.5
11.RATE CASE STABILITY PROVISION 8
111.
Iv.8
v.COST OF CAPITAL
VI.DEPRECIATION/AMORTIZATION AND DECOMMISSIONING
VII.FUEL AND POWER SUPPLY ADJUSTMENT PROVISIONS 10
am.
..ll
TRANSFER OF ITEMS FROM ADJUSTMENT
MECHANISMS TO BASE RATES
lx.RATE TREATMENT RELATED TO THE INSTALLATION OF
SELECTIVEATALYTIC REDUCTION EQUIPMENT AT FOUR
CORNERS UNITS 4 AND 5
x.COST DEFERRAL RELATED TO THE OCOTILLO
MODERNIZATION PROJECT 13
xi.COST DEFFERAL RELATED TO CHANGES IN ARIZONA
PROPERTY TAX RATE
XII.COST OF SERVICE
XIII.NAVAJO GENERATING STATION 14
XIV.ANNUAL WORKFORCE PLANNING REPORT 14
xv.SELF-BUILD MORATORIUM 15
XVI.TAX EXPENSE ADJUSTOR MECHANISM 16
XVII.RESIDENTIAL RATE 17
XVIII.
19
RESIDENTIAL RATE DESIGN FOR DISTRIBUTED
GENERATION CUSTOMERS
XIX.RESIDENTIAL RATE AVAILABILITY 20
Page 2 of32
DECISION no.76295
DOCKET NO. E-01345A-16-0036 ET AL.
x x .COMMERCIAL AND INDUSTRIAL RATE DESIGN........................21
XXI.
XXII.SCHOOLS DISCOUNT RATE RIDER 21
XXIII.AG-X 21
XXIV.MILITARY CUSTOMERS
XXV.REVENUE
XXVI.EFFECTIVE DATE OF RATE PLANS AND
TRANSITION PLAN 24
IXXVII.FIVE MILLION DSMAC ALLOCATION 24
IIIXXVIII.AZ SUN II 24
XXIX.LIMITED INCOME PROGRAMS 76
x x x .AMI OPT-OUT/SCHEDULE
XXXI.SCHEDULE 3 27
XXXII.LOST FIXED COST RECOVERY MECHANISM...............................27
XXXIII.ENVIRONMENTAL IMPROVEMENT SURCHARGE
XXXIV.TRANSMISSION COST ADJUSTMENT MECHANISM
XXXV.CHALLENGES TO DECISION nos.75859 AND 75932 28
XXXVI.POWER SUPPLY ADJUSTOR AUDIT 29
XXXVII.COMPLIANCE MATTERS
XXXVIII.FORCE MAJEURE PROVISION 29
XXXIX.COMMISSION EVALUATION OF PROPOSED SETTLEMENT......29
XL.MISCELLANEOUS PROVISIONS 30
Page 3 of32
DECISION no._
DOCKET no. E-01345A-16-0036 ET AL.
I
SETTLEMENT AGREEMENT
ARIZONA PUBLIC SERVICE COMPANY'S REQUEST FOR A RATE
INCREASE (DOCKET no. E-01345-A-0036)AND
THE FUEL AND PURCHASED POWER PROCUREMENT AUDIT OF APS
(DOCKET NO. E-01345A-l6-0123)
issues related to Arizona Public Service Company s ("APS" or "Company ) application
The purpose of this Settlement Agreement ("Agreement") is to settle disputed
to increase its rates (Docket No. E-01345A-16-0036) and the fuel and purchased power
procurement audit ofAPS (Docket No. E-1345A-16-0123). This Agreement is entered
into by the following entities:
Arizona Corporation Commission - Utilities Division Staff
Arizona Public Service Company
Residential Utility Consumer Office
Arizona Utility Ratepayer Alliance
Federal Executive Agencies
Arizona Solar Deployment Alliance
Arizona Solar Energy Industries Association
Vote Solar
Solar Energy Industries Association
Arizona School Boards Association and the Arizona Association of School Business Officials
Arizonans for Electric Choice and Competition
Western Resource Advocates
Wal-Mart Stores, Inc. and Sam's West, Inc.
Local Unions 387 and 769 of the International Brotherhood of Electrical Workers, AFL-CIO
Freeport Minerals Corporation
Arizona Community Action Association
The Kroger Co.
Arizona Investment Council
Property Owners & Residents Association, Sun City West
Sun City Home Owners Association
REP America d/b/aConservAmerica
Constellation New Energy, LLC
Direct Energy Business, LLC
Calpine Energy Solutions, LLC
Arizona Competitive Power Alliance
Energy Freedom Coalition of America
City of Coolidge
Granite Creek Farms, LLC
Granite Creek Power & Gas, LLC
These entities shall be referred to collectively as Signing Parties, a single entity
shall be referred to individually as a Signing Party.
Page 4 of32
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
1.RECITALS
1.1 APS filed the rate application underlying ACC Docket No. E-01345A-16-
0036 on June 1, 2016. On August 6, 2016, the administrative law judge
granted a motion to consolidate the Fuel and Purchased Power
Procurement Audits, ACC Docket No. E-01345A-16-0123, with APS's
rate case.Collectively, these dockets may be referred to herein as the
Docket.
1.2
I
II
Subsequently, the Commission approved applications to intervene filed
by Richard Gayer, Patricia Ferre, Warren Woodward, Arizona Solar
Deployment Alliance ("ASDA"), IO Data Centers, LLC ("IO"), Freeport
Minerals Corporation (Freeport) and Arizonans for Electric Choice and
Competition (collectively, "AECC"), Sun City Home Owners Association
("Sun City HOA"), Western Resource Advocates ("WRA"), Arizona
Investment Council ("AIC"), Arizona Utility Ratepayer Alliance
("AURA"), Property Owners and Residents Association, Sun City West
("PORA"), Arizona Solar Energy Industries Association ("AriSEIA"),
Arizona School Boards Association ("ASBA") and Arizona Association
of School Business Officials ("AASBO")(collectively,
"ASBA/AASBO"),Cynthia Zwick,Arizona Community Action
Association ("ACAA"),Southwest Energy Efficiency Project
("SWEEP"), the Residential Utility Consumer Office ("RUCO"), Vote
Solar, Electrical District Number Eight and McMullen Valley Water
Conservation & Drainage District (collectively, "ED8/McMullen"), The
Kroger Co. ("Kroger"), Tucson Electric Power Company ("TEP"), Pima
County, Solar Energy Industries Association ("SEIA"), the Energy
Freedom Coalition of America ("EFCA"), Wal-Mart Stores, Inc. and
Sam's West, Inc. (collectively, "Wal-Mart"), Local Unions 387 and 769
of the International Brotherhood of Electrical Workers, AFL-CIO
(collectively, "the IBEW Locals"), Noble Americas Energy Solutions
LLC ("Noble Solutions"), the Arizona Competitive Power Alliance ("the
Alliance"), Electrical District Number Six, Pinal County, Arizona
("ED 6"), Electrical District Number Seven of the County of Maricopa,
State of Arizona ("ED "7), Aquila Irrigation District ("AID"), Tonopah
Irrigation District ("TID"), Harquahala Valley Power District ("HVPD");
and Maricopa County Municipal Water Conservation District Number
One ("MWD") (collectively, Districts); Sur Run, the Federal Executive
Agencies ("FEA"), Constellation New Energy, Inc. ("CNE"), Direct
Energy, Inc. ("Direct Energy"), AARP, the city of Coolidge
("Coolidge"), REP America d/b/a ConservAmerica ("ConservAmerica"),
Page 5 of32
DECISION NO.76295
DOCKET no. E-01345A-l6-0036 ET AL.
and Granite Creek Power & Gas and Granite Creek Farms LLC
(collectively, "Granite Creek").Sur Run subsequently withdrew its
intervention.
1.3 APS filed a notice of revenue requirement settlement discussions on
December 29, 2016. Revenue requirement settlement discussions began
on January 12, 20 l7, rate design settlement discussions began on February
6, 2017. The settlement discussions were open, transparent, and inclusive
of all parties to this Docket who desired to participate. All parties to this
Docket were notified of the settlement discussion process, were
encouraged to participate in the negotiations, and were provided with an
equal opportunity to participate.
l .4 The terms of this Agreement are just, reasonable, fair, and in the public
interest in that they, among other things, establish just and reasonable rates
for APS customers, promote the reliability of the electric system, as well
as the convenience, comfort and safety, and the preservation of health, of
the employees and customers of APS consistent with the Commission's
obligations under Arizona law, resolve the issues arising from this Docket,
and avoid unnecessary litigation expense and delay.
1.5 The Signing Parties believe that this Agreement balances APS's rate
increase with benefits for customers. The Signing Parties agree that some
of the significant provisions of the Agreement include:
a.A $87.25 million non-fuel, non-depreciation revenue requirement
increase, or a reduction of $58.96 million from APS's original
application.
b.An average 4.54% bill impact for residential customers compared
to an average 7.96% bill impact for residential customers in APS's
original application.
c.A refund to customers through the Demand Side Management
Adjustor Clause ("DSMAC"), of $15 million in collected, but
unspent DSMAC funds to mitigate the first year bill impacts.
d.A rate case stay out, in which APS agrees not to file a new general
rate case filing prior to June l, 2019,
Page 6 of32
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
e.A program to expand access to utility owned rooftop solar for low
and moderate income Arizonans, Title I Schools, and rural
governments,
f.Continuation of a buy-through rate for Industrial and large General
Service customers,
Continuation of crisis bill assistance for low income customers,g.
h.More off-peak hours and holidays for time-differentiated rates,
i.A moratorium on new self-build generation until January l, 2022
and through December 31, 2027 for construction of combined-
cycle generating units,
j An experimental pilot technology rate initially available for up to
10,000 customers,
k.New updated rate designs with rate options for all customers.
1.An educational plan and concerted outreach effort by APS on its
various rate plans with transitional rates in place until May 1, 2018
to allow for customer education,
m.Additional discounts for Schools and Military Customers,
n.Resolution of Solar Distributed Generation ("DG") issues for the
term of the Settlement Agreement,
o.Agreement by Signing Parties to withdraw any appeals of the
Commission's Value of Solar Decisions (Docket Nos.75859 and
75932)
p.Agreement by Signing Parties to refrain from pursuing actions in
any forum that are inconsistent with the provisions of the
Settlement Agreement.
1.6 The Signing Parties request that the Commission find that the rates. terms
and conditions of this Agreement are just, fair and reasonable and in the
public interest in accordance with Article 15, Sections 3 and 14 of the
Arizona Constitution and Arizona Revised Statutes Section 40-250 along
with any and all other necessary findings, and to approve the Agreement
and order that it and the rates contained herein become effective on July
1, 2017.
Page 7 of32
DECISION no.76295
DOCKET NO. E-01345A-16-0_36 ET AL.
TERMS AND CONDITIONS
II.RATE CASE STABILITY PROVISION
4.2 APS will not file its next general rate case before June 1, 2019. The test
year end date for the base rate increase filing contemplated in this section
shall be no earlier than December 31, 2018.
RATE INCREASE111.
3.1.APS shall receive a $87.25 million non-fuel, non-depreciation revenue
requirement increase. When the reduction for base fuel of $53.63 million
and the increase for depreciation of $61.00 million is taken into account,
the result is a net base rate increase of $94.624 million, exclusive of the
adjustor transfer described below in Paragraph 3.2.
3.2 APS also requested to transfer amounts collected in adjustor mechanisms
to base rates, which is revenue neutral since the adjustor balances will be
reduced with the transfer to base rates. After including the transferred
adjustor mechanism amount of$267.95 million, the Company's total base
rate revenue requirement is $362.58 million ("revenue requirement").
This amount is comprised of: (1) a non-fuel base rate increase of$148.250
million, which includes a return on and of plant that is in service as of
December 31, 2016 ("Post-Test Year Plant"), twelve (12) months beyond
the test year ending December 31, 2015 (the "20 l5 Test Year"), (2) a base
fuel rate decrease of $53.63 million, and (3) the transfer from adjustor
mechanisms of $267.95 million to base rates described in Paragraph VIII
herein. When these amounts are netted together, this amounts to a net
base rate increase of $94.624 million.
3.3 The Company's jurisdictional fair value rate base used to establish the
rates agreed to herein is $9,990,56l,000. APS's total adjusted Test Year
revenue is $2,888,903,000.
3.4 In future rate cases, APS will agree to impute net revenue growth for any
revenue producing plant included in post-test year plant.
BILL IMPACTiv.
4.1 When new rates become effective, customers will have on average a
3.28% bill impact.
a.Residential customers will have on average a 4.54% bill impact.
Page 8 of32
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
b.General Service customers will have on average a 1.93% bill
impact.
4.2 To mitigate the first year bill impacts, APS will refund to customers
through the DSMAC $15 million in collected, but unspent DSMAC funds.
COST OF CAPITALv.
5.1 An original cost of capital structure comprised of 44.2% debt and 55.8%
common equity shall be adopted for ratemaking purposes for this Docket.
5.2 A return on common equity of 10.0% and an embedded cost of debt of
5.13% shall be adopted for ratemaking purposes for this Docket.
5.3 The Signing Parties agree to a fair value rate of return of 5.59% for this
Docket, which includes a 0.8% return on the fair value increment.
5.4 The provisions set forth herein regarding the quantification of fair value
rate base, fair value rate of return, and the revenue requirement are made
for purposes of settlement only and should not be construed as admissions
against interest or waivers of litigation positions related to other of future
cases.
VI.DEPRECIATION/AMORTIZATION AND DECOMMISSIONING
6.1 APS will lower its proposed annual depreciation expense pro forma on
APS's as filed SFR C-2 by $20 million per year, resulting in a $61 million
increase in depreciation expense (inclusive of the Cholla 2 Regulatory
Asset Amortization), by adjusting its proposed lives/net salvage rates for
its distribution accounts and by accelerating the amortization of the
present excess depreciation reserves for Palo Verde.
6.2 The annual depreciation expense for the Palo Verde Nuclear Generating
Station will be decreased by $21 million.
6.3 The decrease in Palo Verde depreciation not needed to fund the reduction
in revenue requirements described in Section 6.1 above ("Excess
Amount") will be offset by a more rapid amortization of the Cholla 2
regulatory asset such that there will be no additional impact on APS's
revenue requirement in this case.
6.4 Should the Cholla 2 regulatory asset become fully amortized prior to
APS's next general rate case, the Excess Amount will be used to accelerate
Page 9 of32
DECISION NO.76295
DOCKET no. E-01345A-16-0036 ET AL.
the recovery of APS's remaining investment in the Navajo Generating
Station.
6.5 For purposes of settling this rate case, APS's depreciation rates will be
deemed to use the straight-line method, vintage group procedure, and
remaining life technique.
6.6 In APS's next rate case, APS will file a depreciation rate study that
includes alternative calculations for cost of removal and dismantlement
(negative net salvage) using the "FAS l43" discounted net present value
method, computed using a discount rate to be agreed upon.
6.7 A copy of APS's agreed upon depreciation rates is attached as
Appendix A.
6.8 APS's annual nuclear decommissioning expense proposal will be adopted.
A copy of the decommissioning contribution schedule is attached as
Appendix B.
¢6.9 Subject to the discussion herein of Cholla 2, the Company shall use its
proposed amortization rates for regulatory assets and liabilities as well as
for other intangibles.
VII.FUEL AND POWER SUPPLY ADJUSTMENT PROVISIONS
7.1 The base fuel rate shall be lowered from $0.03207l per kph as set in the
Decision No. 73183 to $0.030168 per kph. This change shall take effect
on the effective date of the new rates contained in this Agreement, in
accordance with the Plan of Administration for the Power Supply Adjustor
("PSA") to be approved in this case.
7.2 APS shall be permitted to include chemical costs for lime, ammonia and
sulfur that are incurred in the generation process in the PSA.
7.3 APS shall be permitted to include third-party storage expenses in the PSA
provided that APS files for approval to include any third-party storage
contract with the Commission 90 days before it becomes effective.
7.4 The September 30 Preliminary Annual PSA Rate filing and the December
31 Final Annual PSA Rate calculation filing will be consolidated into one
annual reset filing that will occur annually on or before November 30.
Unless the Commission otherwise acts on the APS calculation by
Page 10 of32
DECISION no.76295
I DOCKET NO. E-01345A-l6-0036 ET AL.
February 1, the PSA rate proposed by APS will go into effect with the first
billing cycle in February.
7.5 The PSA Plan of Administration shall be amended as necessary to reflect
the terms of this Agreement and shall be approved concurrent with the
approval of this Agreement. The revised PSA Plan of Administration is
attached as Appendix C.
ITEMS FROM ADJUSTMENT MECHANISMS TOam. TRANSFER OF
BASE RATES
8.1 The Signing Parties agree that certain revenue requirements collected
through the Renewable Energy Adjustor Clause ("REAC"), DSMAC
Lost Fixed Cost Recovery ("LFCR"), Transmission Cost Adjustor
("TCA"), Environmental Impact Surcharge ("ElS"), Four Corners Rate
Rider ("FCRR"), and the System Benefits Charge ("SBC") adjustment
mechanisms shall be transferred to base rates and those adjustor rates will
be zeroed out or reduced, as proposed by APS herein.
8.2 Adjustor transfers agreed to herein shall include the portion of
transmission revenue requirements that was collected in the test year for
the TCA, the portion of the lost fixed costs that was collected in the test
year for the LFCR, the portion of environmental compliance revenue
requirements that was collected in the test year for the ElS, an increase in
the portion of energy efficiency expense to be collected in base rates from
the DSMAC, the revenue requirement of Arizona Sun related renewable
generation, the Schools and Governments Program and the Community
Power Project will be transferred from the REAC into base rates, the
portion of APS's acquisition of Southern California Edison's share of
Four Corners currently collected in the Four Corners Rate Rider, and the
portion of the System Benefits reduction that went into effect January 1,
2016 to reflect Palo Verde Unit 2 having been fully funded in the nuclear
decommissioning trust.The specific amounts in each adjustor to be
transferred to base rates pursuant to this Section are identified in
Appendix D. The amounts transferred will be calculated using Staffs
revenue conversion factor.
8.3 On the effective date of the new rates contained in this Agreement, the
REAC, DSMAC, LFCR, TCA, ElS, FCRR and SBC rates shall be reduced
to reflect the removal of the amounts identified in Appendix D.
I
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lx.RATE TREATMENT RELATED TO THE INSTALLATION OF
SELECTIVE CATALYTIC REDUCTIONS AT FOUR CORNERS UNITS
4 AND 5
9.1 The parties agree that this Docket shall remain open for the sole purpose
of allowing APS to file a request that its rates be adjusted no later than
January 1, 2019 to reflect the proposed addition of Selective Catalytic
Reduction ("SCR") equipment at Four Corners, as requested in APS's
application in this Docket.
9.2 APS shall be authorized by the Commission to defer for possible later
recovery through rates, all non-fuel costs (as defined herein to include all
O&M, property taxes, depreciation, and a return at APS's embedded cost
of debt in this proceeding) of owning, operating and maintaining the
Selective Catalytic Reduction environmental controls at the Four Corners
Power Plant from the date such controls go into service until the inclusion
of such costs into rates. Nothing in this paragraph shall be construed in
any way to limit this Commission's authority to review the entirety of the
project and to make any disallowances thereof due to imprudence, errors
or inappropriate application of the requirements of this Decision.The
interest component of the SCR deferral will be set at APS's embedded
cost of debt established in this Agreement.
9.3 Any filing seeking a rate adjustment pursuant to Section 9.1 shall include
the following schedules: (1) the most current APS balance sheet at the
time of filing, (2) the most current APS income statement at the time of
filing, (3) an earnings schedule that demonstrates that the operating
income resulting from the rate adjustment does not result in a return on
rate base in excess of that authorized by this Agreement in the period after
the rate adjustment becomes effective, (4) a revenue requirement
calculation, including the amortization of any deferred costs, (5) an
adjusted rate base schedule, and (6) a typical bill analysis under present
and filed rates. The Signing Parties agree to use good faith efforts to
process this rate adj vestment request such that any resulting rate adj vestment
becomes effective no later than January 1, 2019, pursuant to Section 9. l .
9.4 The Signing Parties shall not present any issues in the rate adjustment
proceeding other than those specifically described in this Section.
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9.5 Section 9 is agreed to without prejudice to any position taken by a Signing
Party in any other pending proceeding, including ASBA/AASBO v. ACC,
l CA-CC-l 5-0001
OCOTILLOTHEx.TOCOSTDEFERRALRELATED
MODERNIZATION PROJECT
10.1
1
APS will be authorized to defer for possible later recovery through rates,
all non-fuel costs (as defined herein to include all O&M,property taxes,
depreciation, and a return at APSis embedded cost of debt in this
proceeding)of owning,operating, and maintaining the Ocotillo
Modernization Project ("OMP") and retiring the existing steam generation
at Ocotillo. Nothing in this paragraph shall be construed in any way to
limit the Commission's authority to review the entirety of the project and
to make any disallowances thereof due to imprudence, errors or
inappropriate application of the requirements of this Decision.The
interest component of the Ocotillo deferral will be set at APS's embedded
cost of debt established in this Agreement.
10.2 The entire OMP will be in service before the rate effective date of APS's
next general rate case, and the entire OMP investment will be addressed
and resolved in that proceeding.
10.3 This agreement does not address the prudence of the OMP, and a deferral
of the OMP costs does not guarantee recovery of those costs.
Consideration ofOMP in APS's next general rate case does not create any
precedent, guarantee, or certainty regarding the consideration or treatment
of post-test year plant.
TO CHANGES IN ARIZONAxi.COST DEFERRAL RELATED
PROPERTY TAX RATE
11.1 APS shall be allowed to defer for future recovery (or credit to customers)
the Arizona property tax expense above or below the test year caused by
changes to the applicable Arizona composite properly tax rate.
11.2 The property tax deferral will not accrue interest during the deferral
period, unless it is negative, in which case, it will accrue interest in favor
of APS's customers at APS's short term debt rate.
11.3 Beginning with the effective date of the Commission decision resulting
from APS's next general rate case, any final properly tax rate deferral that
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has a positive balance will be recovered from customers over 10 years,
with a return at APSis short term debt rate, also with a return on any
unrefunded negative balance at the same short term debt rate.
11.4 The Signing Parties reserve the right to review APS's property tax
deferrals in APS's next general rate case for reasonableness and prudence.
11.5 Prior to the next APS general rate case, APS will meet and confer with
Staff, RUCO and other stakeholders regarding the appropriate ratemaking
treatment for the two year lag on payment of property taxes for post-test
year plant.
x11.COST OF SERVICE STUDY
12.1 APS agrees in its next rate case to make available to parties its cost of
service study in an Excel spreadsheet with inputs linked to outputs so that
parties can change the inputs as necessary to reflect their position in the
case. APS will meet and confer with stakeholders prior to filing to discuss
the cost of service format.
12.2 In its next general rate case, APS agrees to perform the Average and
Excess methodology to allocate production demand costs to residential
and general service classes and then reallocate production demand within
the residential sub-classes based on CP. This does not preclude APS or
other stakeholders from proposing alternative allocation methods.
XIII. NAVAJO GENERATING STATION
13.1 APS will address any potential impacts of the closure of the Navajo
Generating Station prior to the filing of APS's next rate case in Docket
No. E-00000C-17-0039. To the extent it deems appropriate, APS may
request that a separate Docket specific to APS be opened to address any
issues pertaining to APS's interest in the Navajo Generating Station.
XIV. ANNUAL WORKFORCE PLANNING REPORT
14.1 APS shall file a workforce planning report with the Commission
containing the following information: (i) the identification of each of the
specific challenges or issues APS faces regarding workforce planning, (ii)
the specific action(s) APS is taking to address each challenge or issue, and
(iii) an update of the progress APS has made toward resolving each
challenge or issue. The workforce planning report shall be filed on an
annual basis, in this Docket, on or before May 3 lst, until the conclusion
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of the next APS general rate case, and shall be limited to the following job
classifications:Electrician-Journeyman,Lineman-Journeyman,
Technician-E&I, and Operator-Power Plant (a/k/a Auxiliary Operators
and Control Operators). At a minimum, the workforce planning report
shall set forth: (i) the number of employees then currently holding these
positions, (ii) the present mean and median ages of APS's workforce with
respect to these job classifications, (iii) the share of retirement-eligible
employees, both as a percentage and in absolute terms, in each of these
job classifications; and (iv) the anticipated hiring level and attrition level
for each of these job classifications.
14.2 The obligation contained in this Section XIV for APS to file a workforce
planning report supersedes any prior workforce planning reporting
requirement including the requirement in Decision No. 73183 .
xv.SELF-BUILD MORATORIUM
15.1 APS will not pursue any new self-build generation option having an in-
service date prior to January l, 2022 unless expressly authorized by the
Commission. Such restriction shall extend to December 31, 2027 with
regard to the construction of combined-cycle generating units.
15.2 This self-build moratorium does not include any of the following: (l) the
OMP, (2) the acquisition of a generating unit or an interest in a generating
unit from a non-affiliated merchant or utility generator, (3) the acquisition
of generation needed for system reliability when under the circumstances
the seeking of prior Commission approval is impossible or impractical;
(4) distributed generation or storage of less than 50 MW per location, (5)
microgrids irrespective of size, (6) renewable generation, or (7) updates or
repowering of existing APS-owned generation.
15.3 As part of any APS request for Commission authorization to self-build
generation, APS will address:
a.The Company's specific unmet needs for additional long-term
resources.
b.The Company's efforts to secure adequate and reasonably-priced
long-term resources from the competitive wholesale market to meet
these needs.
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c.The reasons why APS believes those efforts have been
unsuccessful, either in whole or in part.
d.The extent to which the request to self-build generation is
consistent with any applicable Company resource plans and
competitive resource acquisition rules.
e.The anticipated cost of the proposed self-build option in
comparison with suitable alternatives available from the
competitive market for the relevant analysis period.
15.4 Nothing in this section shall be construed as relieving APS of its
obligation to prudently acquire generating resources, including, but not
limited to, seeking the above authorization to self-build a generating
resource or resources.
15.5 The issuance of any RFP or the conduct of any other competitive
solicitation in the future shall not, in and of itself, preclude APS from
negotiating bilateral agreements with non-affiliated parties.
XVI. TAX EXPENSE ADJUSTOR MECHANISM
16.1 In the event that significant Federal income tax reform legislation is
enacted and becomes effective prior to the conclusion of APS's next
general rate case, and such legislation materially impacts the Company's
annual revenue requirements, APS will create a rate adjustment
mechanism to enable the pass-through of income tax effects to customers.
16.2 This adjustor mechanism has the following elements:
a.The change in revenue requirements due to Federal tax reform will
be measured as the change in:
i.The Federal Income Tax Rate (currently 35%) applied to the
Company's Adjusted 2015 Test Year,
ii.The annual amortization of any resulting excess deferred
income tax regulatory account compared to the Company's
Adjusted 2015 Test Year, and,
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iii.Permanent income tax adj ustments (such as interest expense
and/or property tax expense deductibility) compared to those
taken in the Company's Adjusted 2015 Test Year.
b.The Company will change retail rates through the Tax Expense
Adjustor Mechanism (TEAM).
i.The rate will be computed on a prospective basis each year
based on the jurisdictional retail income tax change as
compared to the income tax expense used to set rates in this
proceeding combined with the Company's projection of
jurisdictional retail sales for the coming year. The rate will
be filed on December let and will become effective with the
first billing cycle in March of each year.
ii.The adjustment will be assessed to each customer as an equal
per kph charge.
iii.The adjustor mechanism will include a balancing account
such that any under- or over-collected balance will bé
recovered or refunded in the following year.
iv.Each year's under- or over-collected balance will accrue
interest at the Company's applicable cost of short-term debt.
16.3 The TEAM will terminate with the effective date of APS's next general
rate case.
16.4 The Plan of Administration for the TEAM is attached as Appendix E.
XVII.RESIDENTIAL RATE DESIGN
17.1 R-XS:Rate Schedule "R-XS" is available to customers without
distributed generation using 600 or less kph per month on average. The
Basic Service Charge for R-XS is $10 for the average billing month,
calculated at a daily rate of $0.329.
17.2 R-Basic:Rate Schedule "R-Basic" is available to customers without
distributed generation using more than 600 kph but less than 1,000 kph
per month on average. The Basic Service Charge for R-Basic is $15.00
for the average billing month, calculated at a daily rate of $0.493.
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I
17.3 R-Basic Large: Rate Schedule "R-Basic Large" is available to customers
without distributed generation using 1,000 kph per month or more on
average. The Basic Service Charge for R-Basic Large is $20.00 for the
average billing month, calculated at a daily rate of $0.658.
17.4 TOU-E: Rate Schedule "TOU-E" is available to all customers. The Basic
Service Charge for "TOU-E" is $13 for the average billing month,
calculated at a daily rate of $0.427. Winter Super Off-peak hours are from
10:00am - 3:00pm. Customers currently on a Time Advantage rate plan
will transition to this rate unless they select to voluntarily move to another
rate for which they are eligible. For DG customers, the average off-set
rate shall be inclusive of the Grid Access Charge described in Section
18.1.
17.5 R-2: Rate Schedule "R-2" is a three-part rate available to all customers.
The Basic Service Charge for R-2 is $13 for the average billing month,
calculated at a daily rate of $0.427.
17.6 R-3: Rate Schedule R-3 is a three-part rate available to all customers. The
Basic Service Charge for R-3 is $13 for the average billing month,
calculated at a daily rate of$0.427. Customers currently on the Combined
Advantage rate plan will transition to this rate unless they select to
voluntarily move to another rate for which they are eligible.
17.7 R-Tech: An Optional R-Tech Pilot Rate Program shall be created that will
initially serve up to 10,000 customers.It is a three-part rate that is
available to residential customers when the following criteria are met: (1)
two or more qualifying primary on-site technologies were purchased
within 90 days of the customer enrolling in the rate, or (2) one qualifying
primary on-site technology was purchased within 90 days of the customer
enrolling in the rate and two or more qualifying secondary on-site
technologies. Qualifying technologies are set forth in Rate Schedule R-
Tech attached hereto as Appendix F. The Basic Service Charge for R-
Tech is $15 for the average billing month, calculated at a daily rate of
$0.493.
a.Once 6,000 customers have signed up to take service under this
program, and if such threshold has been reached prior to the
Company's next general rate case filing, the Company shall
provide notice and promptly convene a meeting of the interested
parties to this Docket to discuss the future of the Pilot Program. If
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each of the parties to that discussion agree on a new customer
participation level for the R-Tech Pilot Program that shall apply
until the Commission determines the disposition of the R-Tech
Pilot Program during the Company's next general rate case the
Company shall file a notice in this Docket to that effect and the
program shall continue to be offered up to the new agreed upon
customer participation level.
b.However, if all parties cannot agree to a new customer participation
level, then APS shall file a report on the R-Tech Pilot Program and
request that the Commission determine whether to continue,
expand, or terminate the program in the Docket within 90 days of
the date that 7,000 customers have begun taking service under this
program. The Commission will then promptly review the program
and determine if it should continue, terminate, or be adjusted.
c.The Signatories have agreed to a rate design for the R-Tech Pilot
Rate Program as set forth in Appendix F .
17.8 The on-peak period will be 3:00 pm - 8:00 pm weekdays for TOU-E, R-
2, R-3, and R-Tech, excluding holidays specified in Appendix F.
17.9 Attached as Appendix G is the Residential and Commercial rate summary.
DISTRIBUTEDFORXVIII.RESIDENTIAL RATE DESIGN
GENERATION CUSTOMERS
18.1 DG customers are eligible for four different rate schedules including all
proposed TOU and Demand rates. DG customers that select TOU-E will
be subject to a Grid Access Charge as reflected in Appendix F.
18.2 The self-consumption offset rate for TOU-E will be $0.105/kWh, which
is inclusive of the Grid Access Charge, but exclusive of taxes and
adjustors. This is an approximately $0.120/kWh offset rate after these
adjustments. The offset rate is based on the load profile and production
profile of APS customers with DG during the test year.Individual
customer offset will vary based on individual usage patterns and DG
system size, orientation, and production.
18.3 The Resource Comparison Proxy Rate ("RCP") for exported energy
established in Decision No. 75859, as amended by Decision No. 75932,
will be $0.129/kWh in year one, which is inclusive of undifferentiated
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DECISION NO.76295
DOCKET no. E-0i345A-16-0036 ET AL.
transmission, distribution, and loss components. This export rate was
calculated using a 2015 base year with an adjustment to achieve the final
export rate. Attached as Appendix H is the RCP Rate Rider, POA and
EPR-6 Legacy Rate Rider.
18.4 This first year export rate is the product of settlement negotiations and
does not create any precedent, imply any change to the structure of or
detail in the Resource Comparison Proxy, or otherwise change any aspect
of Decision No. 75859.
18.5 DG customers that file a completed interconnection application before the
rate effective date adopted in the Decision in this case shall be
grandfathered consistent with Section 18.6 for a period of twenty years,
with the twenty year period beginning from the date the system is
interconnected with APS.
18.6 As contemplated in Decision No. 75859, grandfathered DG customers
will continue to take service under full retail rate net metering and will
continue to take service on their current tariff schedule for the length of
the grandfathering period, which for APS are rate schedules E-12, ET-1,
ET-2, ECT-1, or ECT-2. In its next rate case, APS will propose that the
rates on each of these legacy tariffs will be updated with an equal percent
increase applied to every rate component equal to the residential average
base rate increase approved. In addition, grandfathered DG customers
currently served on E-3 or E-4 will continue on the current E-3 or E-4 Rate
Riders for as long as they meet the eligibility criteria and/or discontinue
participation in the program.
XIX. RESIDENTIAL RATE AVAILABILITY
19.1 All customers may select R-Basic, R-Basic Large, TOU-E, R-2, R-3, R-
Tech or R-XS if they qualify until May l, 2018, except to the extent
grandfathered under other sections of this Settlement Agreement.
Distributed Generation customers will not be eligible for R-XS, R-Basic
or R-Basic Large. After May l, 2018, R-Basic Large will no longer be
available to new customers or customers who are on another rate. New
customers after May 1, 2018 may choose TOU-E, R-2, R-3 or if they
qualify, R-XS or R-Tech. After 90 days, new customers may opt-out of
their current rate and select R-Basic if they qualify.Customers
transitioning to R-Basic must stay on that rate for at least 12 months.
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DECISION no.76295
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xx. COMMERCIAL AND INDUSTRIAL RATE DESIGN
20.1 APS's General Service XS non-demand rate is adopted and attached as
Appendix G.
20.2 APS's Aggregation feature and Extra High Load Factor Rate are as
proposed by the Company. Copies of these Schedules are attached as
Appendix I.
20.3 Economic Development Service Schedule 9 is approved as modified by
Staff and is attached as Appendix J.
20.4 There will be no change to the current net metering structure for non-
residential solar customers until addressed in a future Value of Solar or
other proceeding.
20.5 The Signing Parties agree that issues related to the non-ratchet rate design
alternative for C&I remain unresolved by this Agreement, and the Signing
Parties agree they may present their respective positions in the hearing
scheduled in this proceeding.
20.6 The on-peak period will be 3:00 pm - 8:00 pm weekdays for XS through
E32-L, but will remain unchanged for E-35.
XXI. E-32L RATE DESIGN
21.1 APS agrees to redesign E-32 L in a revenue neutral manner to recover an
additional amount of $1 .36 per kW in the unbundled generation charges.
XXII.SCHOOLS DISCOUNT RATE RIDER
22.1 All public schools and public school districts will be eligible for a new
rate rider. If they apply for service under this rate rider they receive a
discount of $0.0024/kWh.
AG-XXXIII.
23.1 The capacity reserve charge applicable to AG-X customers will be equal
to $5.5398 per kW-month (60% of current FERC demand charge of
$9.233 per kW), applied to 100% of the customer's billing demand.
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23.2 This charge and other parameters will be re-evaluated in APS's next rate
case, including whether AG-X should be evaluated as a separate customer
class in the cost of service study.
23.3 AG-X customers must provide 1-year notice to return to APS's cost-of-
service rates. At APS's option, customers seeking to return with less
notice must pay market-based rates until the 1-year notice period is
attained.
23.4 The Administrative Management Fee for the program will be increased to
$1.80 per Mwh.
23.5 A retail energy imbalance protocol specifically designed to measure how
well an AG-X Generation Service Provider ("GSP") is matching its retail
buy-through customer load on an hourly basis will replace the FERC
energy imbalance protocol. Energy Imbalance will be determined based
on each GSP's aggregated hourly customer load.
a.Within the range of +/- 15% each hour or +/- 2 MW, whichever is
greater, GSPs would pay based on Schedule 4 of APS's OATT,
which now reflects the terms of the CAISO imbalance charges.
b.Greater than 15% each hour or +/- 2 MW, whichever is greater, in
addition to the charges in a.above, GSPs would pay a penalty of $3
per Mwh.
c.In addition to the imbalance provisions described above, GSPs with
20% of hourly deviations greater than 20% of the scheduled amount
occurring in a calendar month will receive a notice of intent to
terminate the GSP's eligibility in the program unless remedied.
Imbalances of this magnitude and frequency will be deemed
"Excessive."Should Excessive imbalances occur again in a
subsequent month, within 12 months from the date of the notice,
the GSP's eligibility may be terminated. To avoid termination, a
GSP must demonstrate to APS that it is operating in good faith to
match its resources to its load. In the event of GSP termination, the
customer will be required to secure a replacement GSP within 60
days.
23.6 The PSA mitigation will remain in place. However the mitigation is
modified such that the resale of capacity and energy displaced by AG-X
is established at a flat $1,250,000 per month of off-system sales margins
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and excluded from the PSA rather than using a pro-rata share of such
margins.
23.7 AG-X will remain at 200 MW but the prior restrictions as to 100 MW
from each of the E-32L and E-34/35 rate schedules is eliminated,
however, 100 MW would be allocated to 20 MW single-site customers
with load factors above 70% unless not fully subscribed during the
solicitation process.
23.8 Line losses for scheduling AG-X load will be modified to reflect
transmission voltage service when applicable.Ii
23.9 The 10 MW minimum aggregation level will be retained.Current
provisions on the size of single site loads eligible for aggregation also will
remain in place.
23.10 There will be a new lottery if the service is oversubscribed - otherwise,
first come, first served. After the initial re-lottery, if necessary, customers
who enter the program will not be required to participate in a subsequent
lottery to remain in the program.°
23.1 l The AG-1 deferral will be recovered over 5 years from all non-residential
customer classes, except the street and area lighting customer classes. The
amount will be allocated to each class based on adjusted Test Year kph.
APS will not propose a deferral of unmitigated costs resulting from AG-
X, if any, nor propose the collection of unmitigated costs resulting from
AG-X, if any, before or in its next rate case. Attached as Appendix K is
the AG-X rate schedule.
XXIV.MILITARY CUSTOMERS
24.1 The unbundled delivery charge for service at military-primary voltage
under rates E-34 and E-35 will be reduced to a level that results in any
applicable military customer getting a net impact bill increase equal to the
average for all retail customers.
XXV.REVENUE SPREAD
25.1 For the revised revenue requirement, APS will keep the same revenue
spread between Residential and General Service classes. However, within
General Service, because GS extra small and small customers originally
had a near zero net bill impact, the reduction will be spread to all other GS
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DECISION no.76295
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Attached ascustomers proportionally to the original revenue spread.
Appendix L is the revenue spread/targets summary.
XXVI.EFFECTIVE DATE OF RATE PLANS AND TRANSITION PLAN
26.1 The rate increase will go into effect on the effective date of the
Commission's Decision in this case using transition rates which for
purposes of this Agreement are defined as existing Residential and extra
small General Service rate schedules with updated revenue requirements.
Customers will have the opportunity to select any rate which they qualify
for, and APS will provide them information on options that would
minimize their bill. Customers that do not select a different rate will
transition to the updated rate plan most like their existing rate on or before
May l, 2018. At least 90 days before transitioning customers who have
not selected a rate, APS will provide a report to the ACC indicating the
total number of customers who have not made a selection.
XXVII.FIVE MILLION DSMAC ALLOCATION
27.1 APS will make a one-time allocation of $5 million from over-collected
DSMAC funds to DSM programs for education and to help customers
manage new rates and rate options including services and tools available
to customers to help them manage their utility costs. APS shall file an
outreach and education plan and shall provide stakeholders with an
opportunity for review and comment on the draft plan prior to completing
its final plan.
XXVIII.AZ SUN II
28.1 APS will implement a new program for utility-owned solar distributed
generation. The purpose of this program is to expand access to rooftop
solar for low and moderate income Arizonans.For this program,
distributed generation will be defined as photovoltaic solar generation
connected to the distribution system.APS will use third-party solar
contractors to install the solar systems. The third-party solar contractors
will be competitively selected through an RFP process. APS will own all
the generation, renewable energy credits and other attributes from this
program.
28.2 All reasonable and prudent costs incurred by APS pursuant to this
program will be recoverable through the Renewable Energy Adjustment
Clause until the next rate case.
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a.Expenses eligible for recovery through the Renewable Energy
Adjustment Clause include all O&M expenses, property taxes,
marketing and advertising expenses, and the capital carrying costs
of any capital investment by APS through this program
(depreciation expenses at rates established by the Commission, and
return on both debt and equity at the pre-tax weighted average cost
of capital).
b.APS may request that the capital costs of the solar systems installed
under this program be included in rate base in its next rate case.
c.APS's expenses under this program may be reviewed for prudence
in each annual REST docket. Further, if APS includes any of these
solar systems in rate base in the next rate case, those systems will
be subject to a prudence review in that case.
d.APS will propose a program not less than $10 million per year, and
not more than $15 million per year, in direct capital costs for the
program. At least 65% of annual program will be dedicated to
residential installations as defined in subsection 28.4.b. At the end
of nine months of each program year, any unspent funds dedicated
to low income residential installations can be used for other eligible
customers.
e.Relation to annual REST docket. The program is approved in this
Docket, and APS does not need to seek further approval in the
REST Docket for the program or the spending authorized herein.
However, APS shall report the number of installations, capital
costs, and expenses in each annual REST docket. Further, recovery
of the expenses through the Renewable Energy Adj vestment Clause
will be reviewed in the annual REST dockets as described herein.
28.3 This program will be available throughout APS's service area, including
in rural Arizona.
28.4 This program is limited to low and moderate income residential APS
customers as defined below, as well as non-profits that serve low or
moderate income APS residential customers, Title I schools, and rural
government customers. Rural government is defined as any state, local or
tribal government entity in or serving a rural municipality.Rural
Municipality means Arizona incorporated cities and towns with
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populations of less than 150,000 (based on U.S. Census Bureau 2010
population data) not contiguous with or situated within a Metro Area.
Metro Area means a city with a population of 750,000 or more and its
contiguous and surrounding communities.
a.Moderate income is defined as a household earning less than 100%
of the median Arizona household income.APS will verify the
income of each program participant.
b.Low income is defined as a household with income at or below
200% of the federal poverty level. APS will verify the income of
each program participant.
28.5 APS may include any multi-family housing (such as apartment buildings)
in the program.
28.6 Each residential APS customer participating in the program, upon
installation of the solar system, will receive a bill credit of $10-50 per
month applied to their APS bill. APS will work with stakeholders to
discuss and determine the reasonable level of bill credit dependent upon
type of installation. All other terms and conditions of the customer's rate
option will continue to apply.
28.7 This program is approved for a period of three years from and after the
date APS files a notice of program commencement in this Docket. APS
will file the notice no later than three months after the effective date of the
Commission's decision in this Docket. APS agrees to not implement any
additional utility-owned residential solar distribution generation programs
prior to APS's next general rate case beyond AZ Sun II, as outlined above.
28.8 APS will file a report with the Commission on the status of the program
every quarter during the term of the program. The reporting will list the
number of installs in each eligible category until the next APS rate case.
XXIX.LIMITED INCOME PROGRAMS
29.1 The E-3 Energy Support Program for limited income customers will be
revised to provide eligible customers with a flat 25% bill discount.
29.2 The E-4 Medical Support Program for limited income customers who
have life sustaining medical equipment will be revised to provide eligible
customers with a flat 35% bill discount.
Page 26 of 32
DECISION NO.76295
DOCKET no. E-01345A_16-0036 ET AL.
29.3 APS agrees to fund $1.25 million annually the crisis bill program to assist
customers whose incomes are less than or equal to 200% of the Federal
Poverty Income Guidelines.
x x x .AMI OPT-OUT/SCHEDULE l
30.1 The AMI Opt-Out program will be approved as proposed by APS except
the fees will be changed to reflect an upfront fee of $50 to change out a
standard meter for a non-standard meter and monthly fee of $5.See
Service Schedule l, attached as Appendix M.
30.2 Changes to Schedule I are attached in Appendix M.
XXXI.SCHEDULE 3
31.1 APS will create a new classification in Schedule 3: "Rural Municipal
Business Developments" which means a tract of land that has (l) been
divided into contiguous lots, (2) is owned and developed by a Rural
Municipality and, (3) where the Rural Municipality will be the lease-holder
for future, permanent lessee applicants.
¢
31.2 Extension Facilities will be installed to Rural Municipal Business
Developments on the basis of an Economic Feasibility analysis in advance
of an application for service by permanent lessee applicants.
31.3 The refund eligibility period will be seven years (Rather than 5 years that
applies to other classifications).
31.4 Advance payment of one-half of the project costs is due before the start of
Company construction. The balance of the project cost will be required 7
years from the Execution Date of the agreement if the project has not
become economically feasible by the end of the refundable period. Any
unrefunded advance balance paid at the start of the project plus the balance
of project costs due at the end of the refund period will become a non-
refundable contribution in aid of construction 7 years from the Execution
Date of the agreement. (Rather than full advance required before start of
construction). Changes to Schedule 3 are attached as Appendix N.
XXXII.LOST FIXED COST RECOVERY MECHANISM
32.1 The LFCR opt-out rate option approved in Decision 73183 will be
removed.
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DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
32.2 The adjustment will no longer be applied to customer's bills as an equal
percentage surcharge, but rather as a capacity (demand) charge per kW for
customers with a demand rate and as a kph charge for customers with a
two-part rate without demand.
32.3 APS shall submit its LFCR compliance filings on February 15th of each
year. New LFCR rates shall take effect, upon Commission approval, with
the first billing cycle in May of each year.The LFCR Plan of
Administration is attached as Appendix O.
XXXIII.TO ENVIRONMENTAL IMPROVEMENTMODIFICATION
SURCHARGE
33.1 APS shall be permitted to increase the cumulative per kph cap rate for
the Environmental Improvement Surcharge ("ElS") from the current
$0.00016 to a new rate of $0.00050 and include a balancing account.
33.2 A copy of the revised ElS Plan of Administration is attached as
Appendix p.
XXXIV.TRANSMISSION COST ADJUSTMENT MECHANISM
34.1 APS shall be permitted to add a balancing account to the TCA.
34.2 Consistent with the Commission's directive in Decision No. 72430, the
annual TCA adjustment will become effective June l of each year without
the need for affirmative Commission approval, consistent with the process
approved by the Commission in Decision No. 72430.
34.3 A copy of the proposed TCA Plan of Administration is attached as
Appendix Q
XXXV.CHALLENGES TO DECISION nos. 75859 AND 75932
35.1 Upon final approval of the Settlement Agreement by way of a final non-
appealable Commission Order that includes no material changes to the
terms of the Settlement Agreement, all Signing Parties will promptly take
all necessary actions to (i) withdraw any challenge to Decision Nos. 75859
and 75932 they have filed. and (ii) refrain from pursuing any legal
challenge to Decision Nos. 75859 and 75932 in any forum.
35.2 Prior to the issuance of a non-appealable Commission Order in this rate
case, the Signing Parties agree to work together to secure a stay of any and
Page 28 of32
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
l
all appeals that will suspend the filing of all pleadings, motions, briefings,
or other coin documents, until after the Commission issues its final Order
in this case.
XXXVI.POWER SUPPLY ADJUSTOR AUDIT
36.1 Staff will docket the final audit report of APS's Power Supply Adjustor
("PSA") and the Signing Parties agree that any issues relating to the PSA
audit report will be addressed in the hearing on this matter.
XXXVII.COMPLIANCE MATTERS
37.1 Staffs Recommendation for elimination or waiver of certain compliance
requirements will be adopted.A list of the items to be eliminated or
waived is attached as Appendix R.
37.2 Within ten days after the Commission issues an order in this matter, APS
shall file compliance schedules associated with this Docket for Staff
review. Subject to Staff review, such compliance schedules will become
effective on the effective date of the new rates contained in this
Agreement.`
XXXVIII.FORCE MAJEURE PROVISION
38.1
l
l
l
Nothing in this Agreement shall prevent APS from requesting a change to
its base rates in the event of conditions or circumstances that constitute an
emergency. For the purposes of this Agreement, the term "emergency" is
limited to an extraordinary event that, in the Commission's judgment,
requires base rate relief in order to protect the public interest.This
provision is not intended to preclude any party, including any Signing
Parly to this Agreement, from opposing an application for rate relief filed
by APS pursuant to this paragraph. Nothing in this provision is intended
to limit the Commission's ability to change rates at any time pursuant to
its lawful authority.
XXXIX.COMMISSION EVALUATION OF PROPOSED SETTLEMENT
39.1 All currently filed testimony and exhibits shall be offered into the
Commission's record as evidence.
39.2 The Signing Parties recognize that Staff does not have the power to bind
the Commission. For purposes of proposing a settlement agreement, Staff
acts in the same manner as any party to a Commission proceeding.
Page 29 of32
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
39.3
ll
This Agreement shall serve as a procedural device by which the Signing
Parties will submit their proposed settlement of APS's pending rate case,
Docket No. E-01345A-16-0036 consolidated with Docket No. E-01345A-
16-0123, to the Commission.
39.4 The Signing Parties recognize that the Commission will independently
consider and evaluate the terms of this Agreement. If the Commission
issues an order adopting all material terms of this Agreement, such action
shall constitute Commission approval of the Agreement. Thereafter, the
Signing Parties shall abide by the terms as approved by the Commission.
39.5 If the Commission fails to issue an order adopting all material terms of
this Agreement, any or all of the Signing Parties may withdraw from this
Agreement, and such Signing Party(ies) may pursue without prejudice
their respective remedies at law.For the purposes of this Agreement,
whether a term is material shall be left to the discretion of the Signing
Party choosing to withdraw from the Agreement.If a Signing Party
withdraws from the Agreement pursuant to this paragraph and files an
application for rehearing, the other Signing Parties, whether or not the
party has withdrawn from the Agreement, except for Staff, shall support
the application for rehearing by filing a document with the Commission
that supports approval of and future adherence to the Agreement in its
entirety.Staff shall not be obligated to file any document or take any
position regarding the withdrawing Signing Party's application for
rehearing.
XL.MISCELLANEOUS PROVISIONS
40.1 This case has attracted a large number of participants with widely diverse
interests.To achieve consensus for settlement, many participants are
accepting positions that, in any other circumstances, they would be
unwilling to accept.They are doing so because this Agreement, as a
whole, is consistent with with the broad public interest. The acceptance
by any Signing Party of a specific element of this Agreement shall not be
considered as precedent for acceptance of that element in any other
context.
40.2 No Signing Party is bound by any position asserted in negotiations, except
as expressly stated in this Agreement.No Signing Party shall offer
evidence of conduct or statements made in the course of negotiating this
Agreement before this Commission, any other regulatory agency,or any
court, and no statement, communication or position of any party, their
Page 30 of32
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
representatives, attorneys, or witnesses in the course of negotiations or in
support of this Agreement shall be considered an admission or support for
any position taken in any other forum or action.
l40.3 Neither this Agreement nor any of the positions taken in this Agreement
by any of the Signing Parties may be referred to, cited, or relied upon as
precedent in any proceeding before the Commission, any other regulatory
agency, or any court for any purpose except to secure approval of this
Agreement and enforce its terms.
40.4 To the extent any provision of this Agreement is inconsistent with any
existing Commission order, rule, or regulation, this Agreement shall
control.
40.5 Each of the terms of this Agreement is in consideration of all other terms
of this Agreement. Accordingly, the terms are not severable.
40.6 The Signing Parties shall make reasonable and good faith efforts
necessary to obtain a Commission order approving this Agreement. The
Signing Parties shall support and defend this Agreement before the
Commission. Subject to subsection 40.5, if the Commission adopts an
order approving all material terms of the Agreement, the Signing Parties
will support and defend the Commission's order before any court or
regulatory agency in which it may be at issue.
40.7 This Agreement may be executed in any number of counterparts and by
each Signing Party on separate counterparts, each of which when so
executed and delivered shall be deemed an original and all of which taken
together shall constitute one and the same instrument. This Agreement
may also be executed electronically or by facsimile.
Page 31 of32
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
ARIZONA CORPORATION COMMISSION
\/
\By:
Name:Eliiah Abinah
Title:Acting Director. Utilities Division
Date:March 24. 2017
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
By:
Arizona Public Service Company
E I,JL
Name:Barbara Lockwood
Title:Vice President. Regulation
Date:March 24.1 2017
¢
76295DECISION no.
DOCKET no. E-01345A_16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos.E-01345A-16-0036 & E-01345A_16-0123
SIGNATURE PAGE
Residential Utility Consumer Office
4By 2
Name:/Da o / /7'Z~ /Le y
9/VC ufwTitle:
Date :2/2;¢//7
76295DECISION no.
I DOCKET no. E-01345A-16-0036 ET AL.
i
l
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
[Arizona Utility Ratepayer Alliance]
I
By:
Name: Patrick] Quinn
Title: Managing Partner
Date:March 24, 2017
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
4Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
FEDERAL EXECUTIVE AGENCIES
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By:
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L. Ziernan, Captain, USAFe. L
Title: Utilities Litigation Attorney
Date: 24 March 2017
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76295DECISION no.
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DOCKET no. E-01345A_16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGN ATUR E P AGE
ARIZONA SOLAR DEPLOYMENT
ALLIANCE 4By:
Name: SEAN M. SEITZ
Title: PRESIDENT
Date: MARCH24, 2017
76295DECISION no.
DOCKET no. E-01345A-16-0_36 ET AL.
i
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A_16-0123
SIGNATURE PAGE
[INSERT PARTY NAME/COMPANY]
By:
Tom HarrisName:
Title:Treasurer AriSElA
Date:Mar. 24. 2017
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
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[INSERT PARTY NAME/COMPANY]
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Date :
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76295DECISION NO.
l
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A.16-0123
SIGNATURE PAGE
By:
Solar Energy Industries Association
Name:Sean Gallagher
Title:Vice-President State AHlairs
3/24/17Date;
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76295DECISION no.
DOCKET no. E-01345A_I6-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A_16-0036 & E-01345A-16-0123
SIGNATURE PAGE
B
ENERGY FREEDOM
COALITION OF AMERICA
Name:Court S. Rich
Title:Attornev for Energy Freedom
Coalition of America. LLC
Date:8/1-1//7
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
I
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
Arizona School Boards Association and the
Arizona Association of School Business
Officials
/By:
Name: Timothy M. Hogan
Title: Attomev
Date:3/23/17
»
l
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A_I6-0123i
i SIGNATURE PAGE
ARIZONANS FOR ELECTRIC
CHOICE AND COMPETITION
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Name: Stan Barnes
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Title: President
¢Date: March 24, 2017
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
WESTERN RESOURCE ADVOCATES
4By:
Name:John Nielsen
Title:Clean Energv Program Director
Date:3/24/2017
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76295
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
Wal-Mart Stores, Inc. and S
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76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
CINLUBo,p.
By:
Name: Nicholas J. Enoch, Esq.
Title: Attorney for Interveners
IBEW Locals 387 & 769
Date: March 24, 2017
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76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.l
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A_16-0123
SIGNATURE PAGE
FREEPORT MINERALS
CORPORATION
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76295DECISION no.
lDOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos.E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
[INSERT PARTY NAME/COMPANY]
l
By:
Name: C a Zyvick
Titler. Executive Director
Arizona Communitv Action Assoc.
Date: March 24 2017
•
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
1
Arizona Public Service Company
Proposed Settlement Agreement
DocketNos.E-01345A-16-0036 & E.01345A-16-0123
SIGNATURE PAGE
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612-'T/2017
DECISION no.76295
DOCKET NO. E-01345A-16_0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos.E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
ARIZONA INVESTMENT COUNCIL
By:
Name:GarvYaquinto
Title:President& CEO
Date:3/24/2017
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76295
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 &E-01345A-16-0123
SIGN ATUR E PAGE
Property Owners & Residents Association
(PORT) Sun City West
I ,By:
Name: A1 Gervenack
Title:Director. Board of Directors
Date; lviarch 24, 2017
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76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos.E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
[SUN CITY HOME OWNERS
ASSOCIATION (SCHOA)]
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Title:Director. Chairman of Government
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Date:24 March 2017
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76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos.E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
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76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
1
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
Constellation New Energy, LLC
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Name:Lawrence V. Robertson. Jr.
Title:Attomev
Date:March 24. 2017
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76295DECISION no.
DOCKET NO. E-01345A-I6-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-I6-0123
SIGNATURE PAGE
Direct Energy Business, LLC
By:2n.»~»»--lt>~'R-94:84,Sf
Name:Lawrence V. Robertson. Jr.
Title:Attomev
Date:March 24. 2017
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-I6-0123
SIGNATURE PAGE
Calcine Energy Solutions, LLC
£.......x>- (lé-..&. N,By.
Name:Lawrence V. Robertson. Jr.
Title:Attomev
Date:March 24. 20] 7
DECISION no. 76295
DOCKET no. E-01345A-16-0036 ET AL.
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76295DECISION no.
l
DOCKET NO. E-01345A_16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos.E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
By:
CITY OF COOLIDGE
w
Name: Denis M. Fitzgibbons
Title: City of Attomey
Date: March 24, 2017
.
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Arizona Public Service Company
Proposed Settlement Agreement
Docket Nos. E-01345A-16-0036 & E-01345A-16-0123
SIGNATURE PAGE
Granite Creek Farms LLC
Granite Creek Power & Gas LLC
/ 7
/4. ,4 /
a n
B 23//
Inez Thomas E Ste I
Title: General Manager
Date:3/26/2017
Q
.¢¢. ,/, , ¢ ' f ::
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Settlement A reedment A Bendix Index
A
I•¢
C
l_
E
F
G
H
Iu
J
K
L
M
N
De recition Rates
Annual Nuclear Decommissioning Ex else
PSA Plan of Administration
Adustors Transferred to Base Rates
TEAM Plan of Administration
R-XS, R-Basic, R-Basic Lai e, TOU-E, R-2, R-3 Rate Schedules, R-Tech Pilot Rate
Residential and Commercial Rate Summa
RCP Rate Rider and POA, EPR-6, and EPR-6 Le ac Rate Rider
E-32L, E-32L TOU, XHLF Rate Schedule
Service Schedule 9
AG-X Rate Schedule
Revenue S read/Tar eta
Service Schedule l
Service Schedule 3
LFCR Plan of Administration
ElS Plan of Administration
TCA Plan of Administration
Com liane Re uirements Eliminated or Waived
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
l
Appendix A
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix A
Page 1 of 8
\\
i
Statement AARIZONA PUBLIC SERVICE COMPANY
Component Accrual Rates
Current:VG Procedure I RL Technique
Proposed: VG Procedure / RL Technique
Account Description
A
Current (at 12/31/2015)
Investment Net Salvage Total
B c D-B+C
Proposed (at 12/31/2015)
Investment Net Salvage Total
E F G=E*F
2.82%
2.49%
2.84%
2.61 %
2.79%
2.59%
2.52%
2.17%
2.51 %
2.27%
2.46%
2.27%
0.30%
0.32%
0.33%
o.34%
0.33%
0.32%
5.01 %
3.78%
4.45%
4.50%
4.77%
4.08%
0.42%
0.39%
0.50%
0.47%
0.59%
0.42%
5.43%
4.17%
4.95%
4.97%
5.36%
4.50%
i
1
l
1.34%
1.50%
1.45%
1.19%
1.51 %
1.42%
0.01 %
0.05%
0.02%
0.01 %
0.04%
0.03%
1.35%
1.55%
1.47%
1.20%
1.55%
1.45%
0.98%
0.83%
0.92%
0.40%
1.35%
0.87%
0.96%
0.77%
0.89%
0.39%
1.30%
0.84%
0.02%
0.06%
0.03%
0.01 %
0.05%
0.03%
9
.l\
l
l
3.04%
3.14%
2.40%
3.30%
3.11%
3.35%
3.02%
0.09%
0.15%
-0.10%
-0.32%
0.06%
-0.15%
0.22%
2.95%
2.99%
2.30%
2.98%
3.05%
3.20%
2.80%
3.60%
3.62%
3.28%
3.86%
3.71 %
4.08%
3.67%
0.26%
0.19%
0.15%
0.12%
024%
0.21 %
0.15%
3.86%
3.81 °/o
3.43%
3.98%
3.95%
4.29%
3.82%
0.11%0.09%
2.67%
2.31 %
1.84%
1.86%
1.75%
2.29%
0.37%
0.33%
0. 11%
2.51 %
1.91%
1.78%
1.85%
1.74%
1.91%
0.37%
0.33%
0.09%
2.67%
2.42%
1.84%
2.23%
2.08%
2.40%
2.51 %
2.00%
1.78%
2.22%
2.07%
2.00%
0.07%
0.20%
0.08%
0.08%
-0.02%
0.26%
-0.08%
0.08%
0.09%
0.07%
0.10%
0.19%
019%
0.20%
0.17%
0.20%
0.06%
0.33%
-0.03%
0.34%
Q13%
0.05%
0.31 %
0.18%
0.16%
1.58%
2.20%
8.79%
2.10%
1.95%
1.92%
1.57%
2.34%
1.70%
1.68%
5.52%
4.84%
2.11%
1.72%
2.14%
1.66%
2.28%
8.79%
2.29%
2.14%
2.12%
1.74%
2.54%
1.76%
2.01 %
5.49%
4.84%
2.42%
1.90%
2.30%
1.57%
2.19%
6.67%
2.29%
255%
1.98%
1.57%
2.63%
1.68%
2.20%
3.68%
3.82%
2.34%
1.72%
225°/o
1.64%
1.99%
8.67%
2.27%
2.81 %
1.90%
1.65%
2.72%
1.75%
2.30%
3.88%
3.82%
2.68%
1.85%
2.30%
0. 13%
0.02%
0.17%
0.02%
2.19%
12.08%
5.35%
6.30%
2.69%
12.88°/o
4.83%
6.46%
2.32%
12.10%
5.35%
6.34%
2.52%
12.86%
4.83%
6.40%0.04%0.06%
STEAM PRODUCTION
311.00 Structures and Improvements
312.00 Boiler Plant Equipment
314.00 Turbogenerator Units
315.00 Accessory Electric Equipment
316.00 Miscellaneous Power Plant Equipment
Total Steam Production Plant
NUCLEAR PRODUCTION
321 .00 Structures and Improvements
322.00 Reactor Plant Equipment
323.00 Turbogenerator Units
324.00 Accessory Electric Equipment
325.00 Miscellaneous Power Plant Equipment
Total Nuclear Production Plant
OTHER PRODUCTION
341.00 Structures and Improvements
342.00 Fuel Holders Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
345.00 Miscellaneous Power Plant Equipment
Total Other Production Plant
TRANSMISSION PLANT
352.02 Structures and Improvements
353.00 Station Equipment
354.00 Towers and Fixtures
355.00 Poles and Fixtures
356.00 Overhead Conductors and Devices
Total Transmission Plant
DISTRIBUTION PLANT
361 .00 Structures and Improvements
362.00 Station Equipment
363.00 Storage Battery Equipment
364.01 Poles Towers and Fixtures Wood
364.02 Poles Towers and Fixtures - Steel
365.00 Overhead Conductors and Devices
366.00 Underground Conduit
367.00 Underground Conductors and Devices
368.00 Line Transformers
369.00 Semioes
370.01 Meters Electronic
370.03 Meters AMI
371 .00 Installations on Customers Premises
373.00 Street Lighting and Signal Systems
Total Distribution Plant
GENERAL PLANT
Depreciable
390.00 Structures and Improvements
391 .CM Of6oe Fum. and Equip. - Computer
397.00 Communication Equipment
Total Depreciable
Page 1of B
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix A
Page 2 of 8i
Statement AARIZONA PUBLIC SERVICE COMPANY
Component AccrualRates
Current:VG Procedure / RL Technique
Proposed; VG Procedure / RL Technique
Account Description
A
Current (at 12/31/2015)
Investment Net Salvage Total
a c o~e~c
Proposed (at 12/31/2015)
Investment Net Salvage Total
E F GE°F
0.04%
0.03%
- 20 Year Amortization 9
o- 20 Year Amortization -.
- 20 Year Amortization _.
- 20 YearAmortlzation -»
- 24 YearAmortizetion -»
4.86%486%
6.07%6.11%
2.42%2.45%
»-20 Year Amortization -
- 20 Year Amortization -
»- 20 Year Amoruzation -
- 20 Year Amortization -4
- 24 Year Amortization -
4.86%4.86%
6.15%6.20%
2.61%2.77%
0.05%
0.16%
Amortizable
391.FE Offlce Fum. and Equip. Furniture
393.00 Stores Equipment
394.00 Tools Shop and Garage Equipment
395.00 Laboratory Equipment
398.00 Miscellaneous Equipment
Total Amortizable
Total General Plant
TOTALUTILITY
STEAM PRODUCTION lay inn)
Cholla
311 .00 Structures andImprovements
312.00 Boiler Plant Equipment
314.00 Turbogenerator Units
315.00 Accessory Electric Equipment
316.00 Miscellaneous Power Plant Equipment
Total Cholla
2.85%
3.56%
3.53%
2.55%
3.00%
3.36%
0.14%
0.25%
0.18%
014%
0.20%
0.22%
2.99%
3.81%
3.71%
2.69%
3.20%
3.58%
7.05%
7.02%
6.64%
6.10%
7.37%
6.90%
0.50%
0.57%
0.46%
0.43%
0.55%
0.54%
7.55%
7.59%
7.10%
6.53%
7.92%
7.44%
chou Unit1
311 .00 Structures and Improvements
312.00 Boiler Plant Equipment
314.00 Turbogenerator Units
315.00 Accessory Electric Equipment
316.00 Miscellaneous Power Plant Equipment
Total Cholera Unit 1
3.60%
4.22%
4.59%
3.65%
3.45%
4.22%
0.17%
0.26%
0.24%
0.19%
0.19%
0.25%
3.77%
4.48%
4.83%
3.84%
3.64%
4.47%
5.36%
6.04%
6.37%
5.48%
5.15%
602%
5.80%
6.69%
6.95%
5.96%
5.60%
6.63%
0.44%0.65%0.58%
0.48%0.45%0.61 %
It3
311.00 StructuresandImprovements
312.00 Boiler Plant Equipment
314.00 Turbogenerator Units
315.00 Accessory Electric Equipment
316.00 Miscellaneous PowerPlantEquipment
Total Cholla Unit 3
2.19%
3.40%
3.04%
2 16°/o
2 4B°/o
3. 15%
2.29%
3.65%
3.19%
2.28%
263%
3.36%
0.10%
0.25%
0.15%
0 12%
0.15%
0.21%
0.46%
0.55%
0.39%
0 42%
0.52%
051 %
7.02%
7.28%
6.72%
5.99%
7.24%
7.05%
7.48%
7.83%
7 11%
6 41 °/0
7.76%
7.55%
I
2.94%
3.32%
2.67%
2.96%
3.16%
3.12%
3.09%
3.57%
2.80%
3.14%
3.38%
3.32%
0.15%
0.25%
0.13%
0.18%
0.22%
0.20%
7.19%
7.27%
8.50%
7.29%
7.89%
7.31 %
0.52%
0.60%
0.63%
0.47%
0.59%
0.56%
7.71 %
7.87%
9.13%
7.76%
848%
7.87%
Ch la c mm
311.00 Structures and Improvements
312.00 Boiler Plant Equipment
314.00 Turbogenerator Units
315.00 Accessory Electric Equipment
316.00 Miscellaneous Power Plant Equipment
Total Cholla Common
Four Corners
311 .00 StructuresandImprovements
312.00 Boiler Plant Equipment
314.00 Turbogenerator Units
31500 Accessory Elem:tric Equipment
316.00 Miscellaneous Power Plant Equipment
Total Four Corners
1.35%
0.85%
0.95%
1.40%
1.09%
0.94%
0.51%
0.37%
0.42%
0.56%
0.29%
0.39%
1.86%
1.22%
1.37%
1.96%
1.38%
1.33%
2.62%
1.78%
190%
2.98%
2.69%
1.97%
0.26%
0.26%
0.30%
0.39%
0.39%
0.28%
2.36%
1.S2%
1 .60%
2.59%
230°/0
1.69%
Pa9e 2oI8
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
Appendix A
Page 3 of 8
Statement AARIZONA PUBLIC SERVICE COMPANY
Component Accrual Rates
Current:VG Procedure / RL Technique
Proposed; VG Procedure / RL Technique
Account Description
A c
Current (at 12/31/2015)
Investment Net Sa\vage Total
B D=5*C
Proposed (at 12/31 I2015)
Investment Net Salvage Total
E F <se»r
l
l
l
l
0.98%
0.77%
0.92%
1.06%
0.54%
0.80%
0.52%
0.36%
0.43%
0.57%
0.18%
0.38%
1.50%
1.13%
1.35%
1.63%
0.72%
1.18%
0.31%
0.24%
0.30%
0.41 %
0.40%
0.26%
1.75%
1.40%
1.55%
2.12%
2.02%
1.50%
2.06%
154%
1.85%
2.53%
2.42%
1.75%l\
2.23%
2.09%
1.65%
2.39%
2.50%
2.21%
0 48%
049%
0.28%
0.53%
0.58%
0. 50%
2.71%
2.58%
1.93%
2.92%
3.08%
2.71%
0.16%
0.44%
0.27%
0.36%
0.34%
0.35%
3.81%
3.44%
2.87%
393%
3 03%
3.50%
3.97%
3.88%
3.14%
4.29%
3.37%
3.85%
3.34%
3.42%
2.71 %
2.93%
3.75%
3.33%
3.58%
3.70%
2.91 %
3.14%
4.04%
3.59%
0.24%
0.28%
0.20%
0.21 %
0.29%
0.26%
020°/o
0.19%
0.15%
0.17%
0.29%
0.19%
3.78%
3.52%
2.72%
3.06%
4 19%
3.49%
3.98%
3.71 %
2.87%
3.23%
4 48%
3.68%
4.91 %
341 %
4.74%
4.55%
5.80%
4.30%
0.88%
0.65%
0.88%
0.84%
1 10%
0.80%
5.79%¢
4.06%
5.62%
5.39%
6.90%
5.10%
12.93%
10.86%
12.13%
15.44%
16.10%
12.40°/o
10.65%
8.89%
9.88%
12.68%
13.34%
10.17%
228%
1.97%
2.25%
2.76%
2.76%
2.23%
1.34%
1.50%
1.45%
1.19%
1.51%
1.42%
0.01%
0.05%
0.02%
0.01%
0.04%
0.03%
0.98%
0.83%
0.92%
0.40%
1.35%
0.87%
0.02%
0.06%
0.03%
001 %
0.05%
0.03%
0.96%
0.77%
0.89%
0.39%
1.30%
0.84%
1.35%
1.55%
1.47%
1.20%
1.55%
1.45%
0.04%
0.02%
0.01 °/0
0.02%
0.03%
1.13%
1.45%
1.41%
1.11%
1.29%
1.34%
0.00%
0.01 %
0.05%
0.00%
0.04%
0.01%
1.13%
1.49%
1.43%
1 12%
1.31%
137%
0.18%
0.60%
0.79%
0. 19%
0.40%
0.50%
0.19%
0.62%
0.83%
0.20%
0.43%
0.51 %
Four Comers Units 4-5
311 .00 Structures and Improvements
312.00 Boiler Plant Equipment
314.00 Turbogenerator Units
315.00 Accessory Electric Equipment
316.00 Miscellaneous Power Plant Equipment
Total Four Corners Units 4-5
Four Corners Common
311 .00 Structures and Improvements
312.00 Boiler Plant Equipment
314.00 Turbogenerator Units
315.00 Accessory Electric Equipment
316.00 Miscellaneous Power Plant Equipment
Total Four Corners Common
Navajo Units 1-3
311 .00 Structures and Improvements
312.00 Boiler Plant Equipment
314 .00 Turf>ogenerator Units
315.00 Accessory Electric Equipment
316.00 Miscellaneous Power Plant Equipment
Total Navajo Units 1-3
Ocotillo Units 12
311 00 Structures and Improvements
312.00 Boiler Plant Equipment
314 .00 Turbogenerator Units
315.00 Accessory Electric Equipment
316.00 Miscellaneous Power Plant Equipment
Total Ocotillo Units1-2
NUCLEAR PRODUCTION (by Unit)
Palo Verde
321 .00 Structures and Improvements
322.00 Reactor Plant Equipment
323.00 Turbogenerator Units
324.00 Accessory Electric Equipment
325.00 Miscellaneous Power Plant Equipment
Total Palo Verde
Palo Verde Unit 1
321 .of Structures and Improvements
322.00 Reactor Plant Equipment
323.00 Turbogenerator Units
324.00 Accessory Electric Equipment
325.00 Miscellaneous Power Plant Equipment
Total Palo Verde Unit 1
Palo Verde Unit 2
321 OO Structures and Improvements
322.00 Reactor Plant Equipment
323.00 Turbogenerator Units
324.00 Accessory Electric Equipment
325.00 Miscellaneous Power Plant Equipment
Total Palo Verde Unit 2
0.01 %
0.08%
0.01%
0.01 %
0.02%
0.05%
1.20%
1.52%
1.41 %
1.25%
1 45%
1.41%
121%
1.60%
1 .42%
1.26%
1.47%
1.46%
0.37%
0.96%
1.11%
0.47%
0.69%
0.82%
0.37%
1 .02%
1 .14%
0.48%
0.72%
0.85%
0.00%
0.06%
0.03%
0.01 %
0.03%
0.03%
Page3018
76295DECISION no.
DOCKET no. E-01345A-16_0036 ET AL.
Appendix A
Page 4 of 8
Statement AARIZONA PUBLIC SERVICE COMPANY
Component Accrual Rates
Current:VG Procedure/ RL Technique
Proposed; VG Procedure / RL Technique
Account Descrlptron
A
Current (at 12/31/2015)
Investment Net Salvage Total
8 c o=s»c
Proposed (at 12/31/20151
Investment Net Salvage Total
E r 644
1.22%
1.56%
1.48%
1.24%
1.36%
1.44%
0.05%
0.02%
0.01 %
0.02%
0.03%
1.22%
1.61%
1.50%
1.25%
138%
1.47%
0.29%
0.81 %
0.81 %
0.39%
0.55%
0.66%
0.00%
0.09%
001 %
0.01 %
0.04%
0.05%
0.29%
0.90%
0.83%
Q41 %
0 59%
0.11 %
1.69%
2.01 %
1.45%
2.05%
2.92%
1.43%
1.71%
2.04%
1.46%
0.02%
0.03%
0.01 °/o
2.08%
2.96%
150%
0.03%
0.04%
0.17%
1.43%
1.69%
1.48%
1.71%
2.20%
2.09%
0.05%
0.02%
2.19%
2.05%
0.01 %
0.04%
1.30%
1.22%
2.15%
1.21 °/o
1.64%
1.40%
0.02%
0.06%
0.04%
Q01 %
0.06%
0.04%
1.31%
0.98%
2.31%
1.08%
1.94%
1.46%
1.32%
1.28%
2. 19%
122%
1.70%
1.44%
1.34%
1.40%
2.54%
1.09%
2.00%
1.54%
0.02%
0.42%
0. 24%
0. 01 %
0. 06%
0. 08%
.
487%
0.89%
0.23%
0.27%
0.04%
0.67%
-0.09%
16.13%
2409%
11.37%
18.97%
23.54%
24.08%
14.16%
15.94%
25.17%
220%
19.92%
24.63%
2536%
8 11 %
0.81 %
1.08%
9.17%
0.95%
1.09%
1.28%
6.05%
5.13%
0.90%
-0.25%
-0.28%
0.02%
0.70%
0.10%
-0.26%
0.01 %
0.02%
001%
0.02%
.0.03%
Q01 %
Palo Verde Unit 3
321 .00 Structures and Improvements
322.00 Reactor Plant Equipment
323.00 Turbogenerator Units
324.00 Accessory Electric Equipment
325.00 Miscellaneous Power Plant Equipment
Total Palo Verde Unit 3
Palo Verde Water Reclamation
321 .00 Structures and Improvements
322.00 Reactor Plant Equipment
323.00 Turtiogerierator Units
324.00 Accessory Electric Equipment
325.00 Miscellaneous Power Plant Equipment
Total Palo Verde Water Reclamation
Palo Verde Common
321 .00 Structures and Improvements
322 00 Reactor Plant Equipment
323.00 Turbogenerator Units
324.00 Accessory Electric Equipment
325.00 Miscellaneous Power Plant Equipment
Total Palo Verde Common
OTHER PRODUCTION inv Unit)
Douglas CT
341 .00 Structures and Improvements
342.00 Fuel Holders Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equlpmenl
346.00 Miscellaneous Power Plant Equipment
Total Douglas CT
l
3.99%
1.97%
0.70%
2.83%
1.54%
2.05%
1.68%
-0.20%
-0.10%
-0.03%
-061 %
-0.06%
0 09%
0.23%
Ocotillo CT Units 1-2
341 .00 Structures and Improvements
342.00 Fuel Holders. Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total ocaino CT Units 12
0.48%
Q19%
0.70%
0.25%
0.27%
0.20%
0.48%
5.50%
3.72%
5.41 °/a
4.73%
4.84%
448%
5.07%
5 98%
3.91 °/o
6 11°/o
4.98%
5.11%
4.3B%
5.55%
4.19%
2.07%
0.73%
3.44%
1.60%
2.14%
1.91 %
Redhawk cc Units 12
3.13%
3.63%
3.11%
3.33%
3.11%
3.60%
3.27%
4.00%
4.37%
3.97%
4 33%
3.97%
4 41 %
421 %
0.20%
0.23%
0.26%
-0.11 %
0.19%
020%
0.02%
4.20%
4.60%
4.23%
422%
416%
4.61 %
4.23%
341 .00 Structures and improvements
342.00 Fuel Holders Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total Redhawk cc Units 1-2
3.01%
345%
3.03%
2.50%
3.01%
3 42%
2.71%
-0.12%
0.18%
0.08%
-0.83%
~0.10%
~018°/u
-0.56%
Page 4 of e
76295DECISION no.
DOCKET no. E-01345A_16_0036 ET AL.
Appendix A
Page 5 of 8
Statement AARIZONA PUBLIC SERVICE COMPANY
Component Accrual Rates
Current:VG Procedure / RL Technique
Proposed; VG Procedure / RL Technique
Account Description
A
Proposed (at 12/31/2015)
Investment Net Salvage Total
E F G'E°F
Current (at 12/31/2015)
Investment Net Salvage Total
a c o-s»c
4.61%
2.29%
4.56%
3.12%
4.33%
2.36%
3.67%
0.41%
0.13%
0.47%
0.15%
0.25%
0 11%
0.27%
4.60%
1.27%
0.71 %
2.92%
0.55%
2.57%
2.16%
-0.22%
-0.03%
0.03%
-0. 19%
0.01 %
0.12%
0.13%
4.20%
2.16%
4.09%
2.97%
4.08%
2 25%
3.40%
438%
1.24%
0.68%
2.73%
0.54%
2.45%
2.03%
4.61%
2.29%
4.60%
2.87%
4.37%
2.36%
4.11%
0.41 %
0.13%
0.50%
0.15%
0.25%
0.11 %
0.38%
4.38%
1.24%
0.43%
2.84%
0.45%
2.45%
1.34%
420°/o
2.16%
4.10%
2.72%
4.12%
2.25%
3.73%
4.60%
1 .27%
0.45%
3.36%
0.46%
2.57%
1 .46%
0.22%
0.03%
-0.02%
052%
-0.01 %
0.12%
0.12%
4.19%
3.16%
3.16%
0.20%
0.15%
0.16%
3.99%
3.01 %
3.00%
2.85%
2.85%
2.85%
-0.14%
0.14%
0.14%
2.71%
2.71%
2.71%
0.16%3.23%2.71%3.07%-0.14%2.85%
3.88%0.28%3.58%0.01 %3.35%3. 36%
3.79%0.26%3.53%3.33%3. 33%
3.79%
3.79%
3.79%
3.79%
3.53%
353%
3.53%
3.53%
0.26%
0.26%
0.26%
0.26%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.76%0.24%3.52%3.33%3.33%
0.24%
0.24%
024%
0.24%
3.76%
376%
3.76%
3.76%
3.52%
3.52%
3.52%
3.52%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
333%
3.33%
Saguaro
341 .00 Structures and Improvements
342.00 Fuel Holders Products and Acoessorres
343.00 Prime Movers
344 of Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total Saguaro
Saquaro CT Units 12
341 .00 Structures and Improvements
342.00 Fuel Holders. Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total Saguaro CT Units 1-2
Saguaro CT Unit 3
341 00 Structures and Improvements
342.00 Fuel Holders Products and Accessories
343.00 Prime Movers
34400 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total Saguaro CT Unit 3
Solar Units
341 .00 Structures and Improvements
342.00 Fuel Holders Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total Solar Units
Chino valley
341 .05 Structures and Improvements
342.05 Fuel Holders Products and Accessories
343.05 Prime Movers
344.05 Generators and Devices
345.05 Accessory Electric Equipment
346.05 Miscellaneous Power Plant Equipment
Total Chino Valley
Cotton Center
341 .05 Structures and Improvements
M205 Fuel Holders Products and Accessories
343.05 Prime Movers
344.05 Generators and Devices
345.05 Accessory Electric Equipment
346.05 Miscellaneous Power Plant Equipment
Total Cotton Center
Page 5018
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix A
Page 6 of 8
Statement AARIZONA PUBLIC SERVICE COMPANY
Component Accrual Rates
Current;VG Procedure / RL Technique
Proposed.VG Procedure / RL Technique
Account Description
A
Current (at 12/31/2015)
Investment Net Salvage Total
a c D=B*C
Proposed (at 12/31/2015)
Investment Net Salvage Tota I
E F G'E*F
3.33%3.33%4.51%5.03%0.52%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
4.51 %
4.51 %
4.51%
4.51%
0.52%
0.52%
0.52%
0.52%
5.03%
5.03%
503%
5.03%
3.33%3.33%3.48%0.30%3.78%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.48%
3.48%
3.48%
3.48%
0.30%
0.30%
0.30%
0.30%
3.78%
3.78%
3.78%
3.78%
3.33%3.33%3 46%0.36%3.82%
3.33%
3.33%
3.33%
3.33%3.33%
3.33%
3.33%
3.33%
3.46%
3.46%
3.46%
3.46%
0.36%
0.36%
0. 36%
0.36%
3.82%
3.82%
3.82%
3.82%
3.33%3.33%3.51%0.16%3.67%
3.33%
3.33%
333°/0
3.33%
3.33%
3.33%
3.33%
3.33%
3.50%
3.48%
3.42%
3.50%
3.66%
3.64%
3.57%
3.66%
0.16%
0 16%
0.15%
0.16%
-3.55%0.20%3.35%1.31%0.03%1.34%
3.93%
7.41 %
-0.86%
-0.37%
3.07%
7.04%
0.08%
0.22%
3.44%
4.23%
3.52%
4.45%
4.65%3.94%-071%3.59%3.71%0.12%
3.33%4.51%3.33%0.54%505%
Desert Star
341 .05 Structures and Improvements
342.05 Fuel Holders. Products and Accessories
343.05 Prime Movers
344.05 Generators and Devices
345.05 Accessory Electric Equipment
M605 Miscellaneous Power Plant Equipment
Total Desert Star
Foothills Units 12
341 .05 StructuresandImprovements
342.05 Fuel Holders, Products and Accessories
343.05 Prime Movers
344.05 Generators and Devices
345.05 Accessory Eiecirie Equipment
346.05 Miscellaneous Power Plant Equipment
Total Foothills Units 12
Gila Bend
341 .05 Structures and Improvements
342.05 Fuel Holders. Products and Accessories
343.05 Prime Movers
344.05 Generators and Devices
345.05 Accessory Electric Equipment
346.05. Miscellaneous Power Plant Equipment
Total Gila Bend
Hider Units1 2
341 .05 Structures and Improvements
342.05 Fuel Holders Products and Accessories
34305 Prime Movers
344.05 Generators and Devices
345.05 Accessory Electric Equipment
346.05 Miscellaneous Power Plant Equipment
Total Hyder Units1 2
Legacy Units
341 .00 Structures and Improvements
342.00 Fuel Holders, Products and Accessories
343.00 Prime Movers
344.00 Generators andDevices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total Legacy Units
Luke AFB
341 .05 Structures and Improvements
342.05 FuelHolders. Products and Accessories
343.05 Prime Movers
344.05 Generators and Devices
345.05 Accessory Electric Equipment
346.05 Miscellaneous Power Plant Equipment
Total Luke AFB
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
4.51%
4.51%
4.51%
4.51%
5.05%
5.05%
5.05%
5.05%
0.54%
0.54%
0.54%
0.54%
Page 6of8
76295DECISIONno.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix A
Page 7 of 8
Statement AARIZONA PUBLIC SERVICE COMPANY
Component Accrual Rates
Currents VG Procedure I RL Technique
Proposed: VG Procedure / RL Technique l
l
l
li
Account Descnptron
A
Current (at 12/31/2015)
Investment Net Salvage Total
B c o=ec
Proposed (at 12/31 I2015)
Investment Net Salvage Total
E F GEF
3.33%3.53%3.33%0.18%371%
I
3.33%
3.33%
3.33%
3.33%
3.55%
3. 54%
0.18%
0.18%
3.73%
3.72%
3.33%3.33%3.55%0.18%3.73%
3.33%3.33%3.52%0.30%3.82%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
3.33%
0.30%
o. KG%
0.30%
030%
3.52%
3.52%
3.52%
3.52%
3.82%
3.82%
3.82%
3.82%
2.06%
2.05%
2.04%
2.51 %
2.05%
2.49%
2.06%
0.10%
0.10%
0.11%
-0.13%
-0.10%
-012%
0.11%
1.96%
1.95%
1.93%
2.38%
1.95%
2.37%
1.95%
249%
2.45%
284%
4.45%
2.41 %
2.85%
2.44%
2.72%
2.57%
2.46%
4.67°/o
2.54%
300%
2.57%
0.23%
0.12%
0.12%
0.22%
0.13%
0 15°/o
0.13%
3.04%
3.67%
2.73%
3.33%
3.51 %
3.80%
3.18%
2.89%
350%
2.64%
297%
3.36%
3.63%
294%
-0.15%
0.17%
-0.09%
0.36%
-0.15%
-0.17%
-0.24%
3.39%
3.81 %
3.64%
3.88%
4.53%
4.45%
3.84%
0.23%
0.19%
0.19%
0.03%
0.29%
0.23°/o
0.11 '/o
3.62%
400%
3.83%
3.91 %
4.82%
4.6B°/0
3.95%
5.00%
4.02%
4.03%
3.94%
-0.24%
0.18%
4.76%
3.84%
0.19%
0.20%
4.22%
4.14%
Roof Tops
341 .05 Structures and Improvements
342.05 Fuel Holders Products and Accessories
343.05 Prime Movers
344.05 Generators and Devices
345.05 Accessory Eleclnc Equipment
346.05 Miscellaneous Power Plant Equipment
Total Roof Tops
Paloma
341 .05 Structures and Improvements
342.0s Fuel Holders. Products and Accessories
343.05 Prime Movers
344.05 Generators and Devices
345.05 Accessory Electric Equipment
346.05 Miscellaneous Power Plant Equipment
Total Paloma
Sundance
341 .00 Structures and Improvements
342.00 Fuel Holders Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total Sun Dance
West Phoenix
341 .00 Structures and Improvements
M2.00 Fuel Holders Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total West Phoenix
West Phoenix cc Units 13
341 .00 Structures and Improvements
342.00 Fuel Holders. Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total West Phoenix cc Units 1-3
4.00%
5.21 %
4.82%
4.21%
-0.65%
-0.15%
-0.18%
0.48%
0.14%
0.35%
023°/o
0.19%
414°/0
5.56%
5.05%
4.40%
3.43%
3.86%
3.99%
3.59%
4.08%
4.01 %
4 17%
4.07%
-0.15%
-015%
-0.15%
-0.30%
0.18%
-0.17%
-0.19%
West Phoenix CC Unit 4
341 .OO Structures and Improvements
342.00 Fuel Holders Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total West Phoenix CC Unit 4
2.90%
2.83%
2.83%
277%
3.39%
3.55%
2.83%
0.17%
0.16%
0.02%
0.18%
0.20%
0.22%
0.08%
3.05%
2.98%
2.98%
3.07%
357%
3.72%
3.02%
3.30%
3.21%
321 %
3.80%
4.00%
4.50%
3.40%
3 47%
3.37%
3.23%
398%
4.20%
4.72%
3.48%
Page 7 of e
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix A
Page 8 of 8
Statement AARIZONA PUBLIC SERVICE COMPANY
Component Accrual Rates
Current:VG Procedure / RL Technique
Proposed: VG Procedure / RL Technique
Account Description
A
Current (at 12/31/2015)
Investment Net Salvage Total
8 c o=s~c
Proposed (at 12/31/2015)
Investment Net Salvage Total
e F G=i»r
2.92%0.15%2.77%0.18%3.48%3.66%
3.01%
2.97%
2.91%
3.40%
2.98%
2.93%
2.78%
2.76%
3.23%
2.83%
-0.08%
-019%
0.15%
-0.17%
-0.15%
0.20%
0.09%
0. 19%
0.22%
0.03%
3.53%
3.76%
3.52%
4.12%
3.67%
3.73%
3.67%
3.71 %
4.34%
3.70%
I
3.80%
0.61 %
1.00%
2.25%
0.95%
3.25%
1.62%
-O. 19°/o
-0.03%
-0.03%
-0.21%
-0.04%
»0.16°/o
0.10%
3.61%
0.58%
0.97%
204%
0.91%
3.09%
1.52%
6.05%
3 36%
5.03%
4.80%
2.61 %
352%
4.86%
0.46%
0.17%
0.49%
0.29%
0.13%
0.26%
040%
6.51%
3.53%
5.52%
5.09%
2.74%
3.78%
5.26%
2.76%2.44%2.64%0.24%-0.12%2.68%
-0.12%2.76%2.64%0.24%2.44%2. 68%
2.41 °/o
0.90%
2.54%
1.29%
1.15%
1.82%
2.26%
-0.09%
0.04%
-0.13%
-0.24%
0.05%
-0.09%
0.13%
2.32%
0.86%
2.41 %
1.05%
110%
173%
2. 13%
4.70%
1.86%
2.98%
3.36%
2.94%
2.88%
3.06%
4.99%
196%
3.17%
3.57%
3.21%
303%
3.25%
0.29%
0.10%
0.19%
0.21 °/o
027%
0 15%
0.19%
l-0.08%2.29%
0.11%
0.09%
127%
0.75%
1 11%
0.80%
2.21%
0.11%
-0.09%
1.03%
0.72%
1.05%
0.71%
5.30%
1.50%
3.24%
3.57%
311%
2.50%
3 40%
0.31%
0.08%
0.44%
0.21%
0.27%
0.12%
0.28%
-0.24%
0.03%
0.06%
-0.09%
499%
1.42%
2.80%
3.36%
2.84%
2.38%
3.12%
West Phoenix CC Unit 5
341 OF Structures and Improvements
342.00 Fuel Holders, Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total West Phoenix ec Unit 5
West Phoenix CT Units 1-2
341 00 Structures and Improvements
342.00 Fuel Holders. Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total West Phoenix CT unit 12
West Phoqnlx Common
341 .00 Structures and Improvements
342.00 Fuel Holders Products and Accessories
34300 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total West Phoenix Common
Yucca
341 00 Structures and Improvements
342.00 Fuel Holders Products and Accessories
343.00 Prime Movers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total Yucca
Yucca CT Units 1-4
341 .00 Structures and Improvements
342.00 Fuel Holders Products and Accessories
343.00 PrimeMovers
344.00 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total Yucca CT Units 1-4
Yucca CT Units 5-6
341 .00 StructuresandImprovements
M200 Fuel Holders Products and Accessories
343.00 Prime Movers
34400 Generators and Devices
345.00 Accessory Electric Equipment
346.00 Miscellaneous Power Plant Equipment
Total Yucca CT Unltx 5-6
0.15%
-0.15%
0.15%
-0.15%
0. 15%
0.15%
0.15%
2.82%
2.82%
2.82%
2.82%
2.82%
2.82%
2.82%
3.29%
3.01%
3.01%
3.14%
3.41%
3.70%
3.03%
2.97%
2.97%
2.97%
2.97%
2.97%
2.97%
2.97%
0.17%
0.15%
0.15%
0.16%
0.23%
0.19%
0.15%
3.46%
3.16%
3.16%
3.30%
3.64%
3.89%
3.18%
Pa9e 8o1B
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
Appendix B
DECISION no.76295
DOCKET NO. E-01345A-16-0036 ET AL.
Appendix B
Page 1 of 1
Palo Verde Decommissioning Trust Amounts
Test Year Ended 12/31/2015
(Dollars in Thousands)
TQTAL2
4/24/2046
UNIT 2
6/1/2 4
UNIT 1
$
I
•
449
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
377
189
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
868
217
YEAR
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
$
ACC
Jurisdictional
Amount
2265
2265
2265
2265
2265
2265
2265
2265
2265
2265
2265
2265
2265
2265
2265
2265
2265
2265
2,265
2265
2265
2265
2265
2265
2265
2,265
2265
2265
2265
2078
1244
1028
70049$
2281
2281
2281
2281
2.281
2281
2281
2,281
2281
2,281
2281
2281
2281
2281
2281
2,281
2281
2281
2281
2.281
2.281
2281
2281
2281
2281
2281
2281
2281
2281
2092
1253
1036
70528$$
11/25/2047
UNIT 3
1a32
1036
1036
1.036
1,036
1036
1036
1036
1036
1,036
1036
1036
1036
1036
1036
1036
1036
1036
1036
1036
1036
1036
1036
1036
1036
1036
1036
1.036
1036
1036
1036
1036
33,9332538911 207$
1. ACC Jurisdictional share is approximately 99.32°/o.
2. Arizona Public Service Company ("APS") is proposing to keep the level of Decommissioning Trust funding constant.
Therefore APS is not proposing any additional funding even though APS anticipates higher amounts than what are
reflected in this Schedule.
76295DECISION NO.
DOCKET NO. E-01345A-16-0036 ET AL.
Appendix C
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
Appendix C
PLAN oF ADMINISTRATION Page 1 of 20
POWER SUPPLY ADIUSTMENTGaps
Power Supply Adjustment
Plan of Administration
Table of Contents
1. General
2. PSA
3. Calculation of the PSA Rate
4. Filing and Procedural
5. Verification and 5
6. Definitions
8. Compliance
9. Allowable
1. General Description
This document describes the plan for administering the Power Supply Adjustment mechanism
("PSA") approved for Arizona Public Service Company (APS) by the Commission on ]ume 28,
2007 in Decision No. 69663, and subsequent amended by the Commission in Decision Nos.
71448 (December 30, 2009), 73183 (May 24, 2012), and XXXXX (xxx xx, 201X). The PSA
provides for the recovery of fuel and purchased power costs and other production-related
variable costs to the extent that diode costs deviate from the amount recovered through APS's
Base PSA Cost (fB0.030667 per kph) authorized in Decision No. XXXXX, from XXX XX, 201X.¢
Non-fuel production costs included in the PSA relate to environmental chemical expenses
which vary directly with power plant production.The production-related environmental
chemical costs are limited to expenses for lime, sulfur and ammonia used at fossil fuel
generation sites. The PSA allows for the refund or recovery of said costs that deviate from the
base cost amount of $0.000500 per kWhl.
In addition, die PSA allows for the refund or recovery of the net margins from sales of emission
allowances, to the extent the actual sales margins deviate from the base cost amount of
($0.000001) per kWh 2 and for recovery of mandated carbon emission costs when it is economical
to incur those costs as discussed below.
li
i
APS shall not incur mandatory carbon emission allowance costs unless it passes those costs on
to the California entities that are purchasing energy from APS. In no event shall APS incur
California's carbon emission allowance costs when doing so is not an economical choice for
APS's Arizona ratepayers.
i
1 $0.000500 per kph is the result of the following: (2015 chemical costs of $13527111 / 2015 test year native load
sales of 27,030,686 Mwh)/1000.
2($0.000001) per kph is the result of the following: (2015 net gains from sales of SON allowances of $25181 / 2015 test
year native load sales of 27,030,686 Mwh) / 1000.
EffectiveDate XX/XX/ XXX Page 1 of 11
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix C
fPLAN o1= ADMINISTRATION Page 2 o 20
POWER SUPPLY ADIUSTMENTQ ops
The PSA described in this Plan of Administration ("POA") uses a forward-looking estimate of
fuel and purchased power costs and environmental chemical costs for fossil fuel production,
and margins on the sales of emission allowances ("PSA Costs") to set a rate that is then
reconciled to actual costs experienced.
This PSA includes a limit of $0.004 per kilowatt-hour (kph) on the amount the PSA rate may
change in any one year absent express approval of the Commission. This PSA also provides a
mechanism for mid-year rate adjustment by eider the Commission or the Company (only if
overcollection) in the event that conditions change sufficiently to cause extraordinarily high
balances to accrue under application of this PSA.
2.PSA Components
The PSA Rate will consist of three components designed to provide for the recovery of actual,
prudently incurred PSA Costs. Those components are:
1. The Forward Component.which recovers or refunds differences between expected PSA
Year's3 PSA Costs and those embedded in base rates.
2. The Historical Component. which tracks the differences between the PSA Year's actual
PSA Costs (fuel, purchased power and other allowable costs) and the recovery of those
same cost elements through the combination of base rates and the Forward Component,
and which provides for their recovery or refund during the next PSA Year.
3. The Transition Component which provides for:
a. The opportunity to seek mid-year changes in the PSA rate in cases where variances
between the anticipated recovery of fuel and purchased power and other allowable
costs for the PSA Year under the combination of base rates and the Forward
Component become so large as to warrant recovery/ refund, should the
Commission deem such an adjustment to be appropriate or if the Company
requests to make such refund of an overcollection.
b. The tracking of balances resulting from the application of the Transition
Components, in order to provide a basis for the refund or recovery of any such
balances.
Except for circumstances when the Commission approves new base rates, a PSA Year begins on
February 1 and ends on the ensuing January 31. In the event that new base rates become
effective on a date other than February 1, die Commission may, at its discretion, adjust any or
all of the PSA components to reflect the new base rates.
On or before November 30 of each year, APS will submit a PSA Rate filing, which shall include
a calculation of the three components of the proposed PSA Rate. This filing shall be
accompanied by such supporting information as Staff determines to be required.
a. Forward Component Description
The Forward Component is intended to refund or recover the difference between: (1) PSA Costs
embedded in base rates and (2) the forecast PSA Costs over a PSA Year that begins on February
3 Each February 1 through January 31 period shall constitute a PSA Year
EffectiveDate XX/XX/ XXX
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Page 2 of 11
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix C
PLAN o1= ADMINISTRATION Page 3 of 20
POWER SUPPLY ADIUSTMENTGaps
1 and ends on the ensuing January 31. APS will submit, on or before November 30 of each year,
a forecast for the upcoming calendar year (January 1-December 31) of its PSA Costs. It will also
submit a forecast of kph sales for the same calendar year, and divide the forecast costs by the
forecast sales to produce the cents/ kph unit rate required to collect those costs over those sales.
The result of subtracting the Base PSA Costs from this unit rate shall be the Forward
Component.
APS shall maintain and report monthly the balances in a Forward Component Tracking
Account, which will record APS's over/under-recovery of its actual PSA Costs as compared to
the Base PSA Costs recovered in revenue. The balance calculated as a result of these steps is
then reduced by the current month's collection of Forward Component revenue. This account
will operate on a PSA Year basis (i.e. February to January), and its balances will be used to
administer this PSA's Historical Component, which is described immediately below.
b. Historical Component Description
The Historical Component in any current PSA Year is intended to refund or recover the
balances accumulated in the Forward Component Tracking Account (described above) and
Historical Component Tracking Account (described below) during the immediately preceding
PSA Year. The sum of the projected Forward Component Tracking Account balance on ]january
31 of the following calendar year and the projected Historical Component Tracking Account
balance on ]january 31 of the following calendar year is divided by the forecast kph sades used
to set the Forward Component for the coming PSA Year. That result comprises the proposed
Historical Component for the coming PSA year.
APS shall maintain and report monthly the balances in a Historical Component Tracking
Account, which will reflect monthly collections under the Historical Component and the
amounts approved for use in calculating the Historical Component.
Each annual November 30 APS filing will include an accumulation of Forward Component
Tracking Account balances and Historical Component Tracking Account balances for the
preceding February through October and an estimate of the balances for November through
January (the remaining three months of the current PSA Year). The APS filing shall use these
balances to calculate the Historical Component for the coming PSA Years.
The November 30 filing's use of estimated balances for November through ]january (with
supporting workpapers) is required to allow the PSA review process to begin in a way that will
support its completion and a Commission decision, if necessary, prior to February 1.
The Historical Component Tracking Account will measure the changes each month in the
Historical Component balance used to establish the current Historical Component as a result of
collections under the Historical Component in effect. It will subtract each month's Historical
Component collections from the Historical Component balance. The Historical Component
4 For example, the November 30 2008 filing would include actual balances for February through October of 2008 and
estimated balances for November 2008 through January 2009.
Page 3 of llEffective Date XX/XX/ XXX
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.Appendix C
PLAN oF ADMINISTRATION Page 4 of 20
POWER SUPPLY ADIUSTMENTQ ops
Account will also include Applicable Interest on any balances. APS shall file the amounts and
supporting calculations and workpapers for this account each month.
c. Transition Component Description
The Transition Component will be used as the method for incorporating any approved mid-
year changes to the PSA rate. APS or Staff may request at any time a change in the PSA rate
through an adjustment to the Transition Component to address a significant imbalance between
anticipated collections and costs for the PSA Year under the Forward Component element of
this PSA. After the review of such request, the Commission may provide for the refund or
collection of such balance (through a change to the Transition Component Balance) over such
period as the Commission determines appropriate through a unit rate ($/ kph) imposed as part
of the Transition Component. The Commission on its own motion may also change the PSA rate
as described above.
Notwithstanding the preceding paragraph, APS may at any time during the PSA Year request
to reduce the PSA through the Transition Component, which request shall be deemed approved
and become effective beginning with the first billing cycle of the month following the filing of
such a request, provided APS files the request within the first 15 days of a month and Staff does
not file opposition to the request.
¢A Transition Component Tracldng Account will measure the changes each month in the
Transition Component balance. APS, Staff, or the Commission on its own motion may request
that the balance in any Transition Component Tracking Account at the end of the period set for
recovery be included in the establishment of the Transition Component for the coming PSA
Year.
The Transition Component Account will also include Applicable Interest as determined by the
Commission. APS shall file the amounts and supporting calculations and workpapers for this
account each month.
As it must do for the Historical Component filing, APS shall file on or before November 30 of
each year an accumulation of Transition Component Tracking Account balances for the
preceding February through October and an estimate of the balances for November through
January (the remaining three months of the prior PSA Year). Those balances will form the basis
for setting the preliminary Transition Component for the coming PSA Year.
3.Calculation of the PSA Rate
The PSA rate is the sum of the three components;i.e.,Forward Component, Historical
Component, and Transition Component. The PSA rate shall be applied to customer bills. Unless
the Commission has otherwise acted on a new PSA rate by February 1, the proposed PSA rate
shall go into effect. However, the PSA rate may not change from die prior year's PSA rate by
more than plus or minus $0.004 per kph without an offsetting change in the Base Cost of Fuel
and Purchased Power. The PSA rate shall be applicable to APS's retail electric rate schedules
Effective Date XX/XX/ XXX
76295
Page 4 of ll
DECISIONno.
DOCKET no. E-01345A-16-0036 ET AL.Appendix C
PLAN OF ADMINISTRATION Page 5 of 20
POWER SUPPLY ADIUSTMENTo ops
(with the exception of E-36 XL, AG-X, Direct Access service and any other rate that is exempt
from the PSA) and is adjusted annually. The PSA Rate shall be applied to the customer's bill as
a monthly kph charge that is the same for all customer classes.
The PSA rate shall be reset on February 1 of each year, and shall be effective with the first
February billing cycle unless suspended by the Commission. It is not prorated.
4. Filingand Procedural Deadlines
a.November 30 Filing
APS shall file the PSA rate with all Component calculations for the PSA year beginning on the
next February 1, including all supporting data, with the Commission on or before November 30
of each year. That calculation shall use a forecast of kph sales and of PSA Costs for the coming
calendar year, with all inputs and assumptions being the most current available for the Forward
Component. The filing will also include the Historical Component calculation for the year
beginning on the next February 1, with all supporting data. That calculation shall use the same
forecast of sales used for the Forward Component calculation. The Transition Component filing
shall also include a proposed method for addressing the over or under recovery of any
Transition Component balances that result from changes in the sales forecasts or recovery
periods set or any additions to or subtractions from Transition Component balances reviewed
or approved by the Commission since the last February 1 resetting of the new PSA.5
b. Additional Filings
APS shall also file with the Commission any additional information that the Staff determines it
requires to verify the component calculations, account balances, and any other matter pertinent
to the PSA.
c. Review Process
The Commission Staff and interested parties shall have an opportunity to review the November
30 forecast, balances, and supporting data on which the cadculadons of the three PSA
components have been based. Any objections to the November 30 calculations shall be filed
within 60 days of the APS filing. Before Storage Product Costs may be calculated in the PSA,
APS will first seek approval. APS will request this approval by filing the third party storage
contract with the Commission at least 90 days before the contract becomes effective. Unless the
Commission has otherwise acted on the APS calculation by February 1, the PSA rate proposed
by APS shall go into effect with the first February billing cycle.
5.Verification and Audit
s This method assumes that the Commission defers the recovery of any approved Transition Component Balance
changes until the next February 1 PSA resetting. The Commission may also, as part of the approval of any such
Transition Component Balance change, make a PSA change effective on dates and across periods as it determines to
be appropriate when it approves such a Transition Component Balance change.
Page 5 of 11EffectiveDateXX/XX/XXX
76295DECISION no.
DOCKET no. E-01345A-l6-0036 ET AL.Appendix C
f 2PLAN o1= ADMINISTRATION Page 6 o 0
POWER SUPPLY AD]USTMENTQ ops
The amounts charged through the PSA shall be subject to periodic audit to assure their
completeness and accuracy and to assure that all fuel and purchased power and other allowable
costs were incurred reasonably and prudently. The Commission may, after notice and
opportunity for hearing, make such adjustments to existing balances or to already recovered
amounts as it finds necessary to correct any accounting or calculation errors or to address any
costs found to be unreasonable or imprudent. Such adjustments, with appropriate interest, shall
be recovered or refunded through the Transition Component.
6. Definitions
Applicable Interest - Interest is applied on the PSA balance annually at the following rates: any
over-collection existing at the end of the PSA year will be credited an amount equal to interest
at a rate equal to the Company's authorized Return on Equity ("ROE") or APS's then-existing
short term borrowing rate, whichever is greater, and will be refunded to customers over the
following 12 months; any under-collection existing at the end of the PSA Year will be debited an
amount equal to interest at a rate equal to the Company's authorized ROE or APS's then-
existing short term borrowing rate, whichever is less, and will be recovered from customers
over the following 12 months.
Base Chemical Costs - An amount generally expressed as a rate per kph, which reflects the
non-fuel production costs embedded in the base rates as approved by the Commission in APS's
most recent rate case. The production-related environmental chemical costs are limited to
expenses for lime, sulfur and ammonia used at fossil fuel generation sites. The Base Chemical
Costs are set at $0.000500 per kph effective on XXX XX, 201X.
Base Cost of Fuel and Purchased Power - An amount generally expressed as a rate per kph,
which reflects the fuel and purchased power costs embedded in the base rates as approved by
the Commission in APS's most recent rate case. The Base Cost of Fuel and Purchased Power
recovered in base revenue is the approved rate per kph times the applicable sales volumes.
Decision No. XXXXX set the base cost at $0.030168 per kph effective on XXX XX, 201X.
Base Net Margins on the Sale of Emission Allowances - An amount generally expressed as a
rate per kph, which reflects the net margins on sales of 502 emission allowances embedded in
the base rates as approved by the Commission in APS's most recent rate case. The Base Net
Margins on the Sale of Emission Allowances is set at ($0.000001) per kph effective on XXX XX,
201x.
Base PSA Costs- A rate equal to the sum of Base Cost of Fuel and Purchased Power as defined
above, the Base Chemical Costs, and the Base Net Margins on the Sale of Emission Allowances.
Forward Component - An amount generally expressed as a rate per kph charge that is updated
annually on February 1 of each year and effective with the first billing cycle in February. The
Forward Component for the PSA Year will adjust for the difference between the forecast PSA
Costs generally expressed as a rate per kph less the Base PSA Costs generally expressed as a
rate per kph embedded in APS's base rates. The result of this calculation will equal the
Forward Component, generally expressed as a rate per kph.
Effective Date XX/XX/XXX
76295
Page 6 of 11
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix C
PLAN OF ADMINISTRATION Page 7 of 20
POWER SUPPLY ADIUSTMENTGaps
Forward Component Tracking Account - An account that records on a monthly basis APS's
over/under-recovery of its actual PSA Costs as compared to the actual Base PSA Costs
recovered in revenue and Forward Component revenue, plus Applicable Interest. The balance
of this account as of the end of each PSA Year is, subject to periodic audit, reflected in the next
Historical Component calculation. APS files the balances and supporting details underlying this
Account with the Commission on a monthly basis.
Historical Component - An amount generally expressed as a rate per kph charge that is
updated annually on February 1 of each year and effective with the first billing cycle in
February unless suspended by the Commission. The purpose of dies charge is to provide for a
true-up mechanism to reconcile any over or under-recovered amounts from the preceding PSA
Year tracking account balances to be refunded/collected from customers in the coming year's
PSA rate.
Historical Com anent Trackin Account - An account that records on a monthly basis the
account balance to be collected via Me Historical Component rate as compared to the actual
Historical Component revenues; plus Applicable Interest at year end. The balance of which at
the close of the preceding PSA Year is, subject to periodic audit, then reflected in the next
Historical Component calculation. APS files the balances and supporting details underlying Mis
Account with the Commission on a monthly basis.
ISFSI - Costs associated with the Independent Spent Fuel Storage Installation that stores spent
nuclear fuel.
Mandated Carbon Emission Allowance Costs- The costs incurred in purchasing allowances to
meet legal requirements, beginning in 2013, that electricity from resources which emit carbon
must be accompanied by carbon emission allowances equal to the amount of carbon emitted in
generating the electricity (recorded in FERC Account 509 - Allowances).iII Mark-to-Market Accounting- Recording the value of qualifying commodity contracts to reflect
their current market value relative to their actual cost.I|
Native Load- Native load refers to the energy for both customer load in the balancing authority
area for which APS has a generation service obligation plus PacifiCorp Supplemental Sales.
Net Margins on the Sale of Emission Allowances... Revenues incurred from the sale of emission
allowances net of the costs incurred to produce the excess allowances.
PacifiCorp Supplemental Sales - The PacifiCorp Supplemental Sales agreement is a long-term
contract from 1990 which requires APS to offer a certain amount of energy to PacifiCorp each
year. It is a component of the set of agreements that led to the sale of Cholla Unit 4 to PacifiCorp
and the establishment of the seasonal diversity exchange with PacifiCorp.
Preference Power- Power allocated to APS wholesale customers by federal power agencies such
as the Western Area Power Administration.
PSA - The Power Supply Adjushnent mechanism approved by the Commission.
EffectiveDate XX/XX/ XXX
76295
Page 7of11
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix C
PLAN oF ADMINISTRATION Page 8 of 20
POWER SUPPLY ADJUSTMENTGaps
PSA Costs - The combination of System Book Fuel and Purchased Power Costs net of the
System Book Off-System Sales Revenues plus costs for environmental chemicals used in power
production at fossil and nuclear production sites, approved storage product costs, and the Net
Margins on the Sales of Emission Allowances.
PSA Year - A consecutive 12-month period generally beginning each February 1.
Rate Schedule AG-X-Alterative Generation Rate Schedule approved by the Commission in
Decision No. XXXXX. Resale of capacity and energy displaced by Rate Schedule AG-X shall be
excluded from the PSA at a flat amount of $1,250,000 a month. The portion of capacity and
energy sales margins that is not the result of displacement from Rate Schedule AG-X will
continue to be a credit to the PSA.
Storage Product Costs -AH costs associated with third-party storage facilities, including rent,
capacity, and lease payments for electricity storage facilities (e.g. batteries) that APS utilizes in
the dispatch of generated or purchased electricity .
System Book Fuel and Purchased Power Cost - The costs recorded for the fuel and purchased
power used by APS to serve both Native Load and off-system sales, less the costs associated
with applicable special contracts, E-36 XL, AG-X, RCDAC-1, ISFSI, and Mark-to-Market
Accounting adjustments. Wheeling costs and broker fees are included up to the level in the Base
Cost of Fuel and Purchased Power authorized in Decision No.xxxxx.
a
Svstem Book Off-Svstem Sales Revenue - The revenue recorded from sales made to non-Nadve
Load customers, for the purpose of optimizing the APS system, using APS-owned or contracted
generation and purchased power, less Mark-to-Market Accounting adjustments.
Traditional Sales-for-Resale- The portion of load from Native Load wholesale customers that is
served by APS, excluding the load served with Preference Power.
Transition Component- An amount generally expressed as a rate per kph charge to be applied
when necessary to provide for significant changes between estimated and actual costs under the
Forward Component.
Transition Component Tracking Account - An account dirt records on a monthly basis the
account balance to be collected via the Transition Component as compared to the actual
Transition Component revenues, plus applicable interest; the balance of which upon
Commission consideration may then be reflected in the next Transition Component calculation.
APS files the balances and supporting details underlying this Account with the Commission on
a monthly basis.
Wheeling Costs (FERC Account 565, Transmission of Electricity by Others)- Amounts payable
to others for the transmission of APS's electricity over transmission facilities owned by others.
7.Schedules
Samples of the following schedules are attached to this Plan of Administration
Effective Date XX/XX/XXX
76295
Page 8of11
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix C
PLAN OF ADMINISTRATION Page 9 of 20
POWER SUPPLY ADIUSTMENTQ ops
Schedule 1
Schedule 2
Schedule 3
Schedule 4
Schedule 5
Sehedule 6
Schedule 7
Power Supply Adjustment (PSA) Rate Calculation
PSA Forward Component Rate Calculation
PSA Year Forward Component Tracking Account
PSA Historical Component Rate Calculation
Historical Component Tracking Account
PSA Transition Component Rate Calculation
PSA Transition Tracking Account
8.Compliance Reports
APS shall provide monthly reports to Staff and to the Residential Utility Consumer Office
detailing all calculations related to the PSA. An APS Principal Officer, as listed in APS's annual
report filed with the Commission's Corporations Division, shall certify under oath that all
information provided in the reports itemized below is true and accurate to the best of his or her
information and belief. These monthly reports shall be due within 30 days of the end of the
reporting period.
The publicly available reports will include at a minimum:
1. The PSA Rate Calculation (Schedule 1); Forward Component, Historical Component,
and Transition Component Calculations (Schedules 2, 4, and 6); Annual Forward
Component, Historical Component, and Transition Component Tracking Account
Balances (Schedules 3, 5, and 7). Additional information will provide other relative
inputs and outputs such as:
a. Total power and fuel costs.
b. Margins on the sale of excess emission allowances.
c.Environmental chemical costs for fossil generation.
d. Customer sales in both MWh and thousands of dollars by customer class.
e.Number of customers by customer class.
f.A detailed listing of all items excluded from the PSA calculations.
g. A detailed listing of any adjustments to the adjustor reports.
h. Total off-system sales revenues.
i.System losses in MW and Mwh.
j.Monthly maximum retail demand in MW.
2. Identification of a contact person and phone number from APS for questions.
APS shall provide to Commission Staff monthly reports containing the information listed
below. These reports shall be due within 30 days of the end of the reporting period. All of these
additional reports will be provided confidentially.
A. Information for each generating unit shall include the following items:
1. Net generation, in MWh per month, and 12 months cumulatively.
2. Average heat rate, both monthly and 12-month average.
3. Equivalent forced-outage factor, both monthly and 12-month average.
Page 9 of 11EffectiveDate XX/XX/ XXX
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DOCKET no. E-01345A-16-0036 ET AL.Appendix C
1PLAN OF ADMIN1STRAT1ONPa9e 0 of 20
POWER SUPPLY ADJUSTMENTQ ops
5.
6.
4. Outage information for each month including, but not limited to, event type, start date
and time, end date and time, and a description.
Total fuel costs per month.
The fuel cost per kph per month.
B. Information on power purchases shall include the following items per seller (information on
economy interchange purchases may be aggregated):
1. The quantity purchased in Mwh.
2. The demand purchased in MW to the extent specified in the contract.
3. The total cost for demand to the extent specified in the contract.
4. The total cost of energy.
C. Information on off-system sales shall include the following items:
1.An itemization of off-system sales margins per buyer.
2.Details on negative off-system sales margins.
D. Fuel purchase information shall include die following items:
1. Natural gas interstate pipeline costs, itemized by pipeline and by individual cost
components, such as reservation charge, usage, surcharges and fuel.
2. Natural gas commodity costs, categorized by short-term purchases (one month or less)
and longer term purchases, including price per therm or per MCF, total cost, supply
basin, and volume by contract.
E. APS will also provide:
1. Monthly projections for the next 12-month period showing estimated (over)/ under-
collected amounts.
2. A summary of unplanned outage costs by resource type.
3. A summary of the net margins on the sale of emission allowances.
4. The data necessary to arrive at the System and Off-System Book Fuel and Purchased
Power cost reflected in the non-confidential filing.
5. The data necessary to arrive at the Native Load Energy Sales MWh reflected in the non-
confidential filing.
Work papers and other documents that contain proprietary or confidential information will be
provided to the Commission Staff under an appropriate confidentiality agreement. APS will
keep fuel and purchased power invoices and cont:racts available for Commission review. The
Commission has the right to review the prudence of fuel and power purchases and any
calculations associated with the PSA at any time. Any costs flowed through the PSA are subject
to refund if those costs are found to be imprudently incurred.
9.Allowable Costs
a. Accounts
The allowable PSA costs include fuel and purchased power costs incurred to provide service to
retail customers. And, the prudent direct costs of contracts used for hedging system fuel and
purchased power will be recovered under the PSA.Additionally, costs for specified
EffectiveDate XX/XX/ XXX
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DECISION no.
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fPLANQFADM1N1STRAT1ONPa9e 11 o 20
POWER SUPPLY ADIUSTMENTQ ops
environmental chemicals that vary with power generated at fossil power plants, storage
product costs, and the net margins on the sale of emission allowances and Mandated Carbon
Emission Allowance Costs will also be refunded or recovered through the PSA. The allowable
cost components include the following Federal Energy Regulatory Commission (FERC)
accounts:
c
•
a
•
•
•
•
501 Fuel (Steam)
518 Fuel (Nuclear) less ISFSI regulatory amortization
547 Fuel (Other Production)
555 Purchased Power
565 Wheeling (Transmission of Electricity by Others)
411 O&M (Margins on the Sale of Emission Allowances)
509 Allowancest>
Additionally, broker fees recorded in FERC account 557 up to the amount included in the Base
Fuel Cost, costs for environmental chemicals used in power production in FERC accounts 502
and 549, and the FERC account where applicable Storage Product Costs will be recorded are
allowable accounts.
These accounts are subject to change if the Federal Energy Regulatory Commission alters its
accounting requirements or definitions.
b. Directly Assi,<znable Power Supply Costs Excluded
¢
Decision No. 66567 provides APS the ability to recover reasonable and prudent costs associated
with customers who have left APS standard offer service, including special contract rates, for a
competitive generation supplier and then return to standard offer service. For administrative
purposes, customers who were direct access customers since origination of service and request
standard offer service would be considered to be returning customers. A direct assignment or
special adjustment may be applied that recognizes the cost differential between the power
purchases needed to accommodate the returning customer and the power supply cost
component of the otherwise applicable standard offer service rate. This process is described in
the Returning Customer Direct Access Charge rate schedule and associated Plan for
Administration filed with the Commission.
In addition, if APS purchases power under specific terms on behalf of a standard offer special
contract customer, the costs of that power may be directly assigned. In both cases,where
specific power supply costs are identified and directly assigned to a large returning customer or
standard offer special contract customer or group of customers, these costs will be excluded
from the Adjustor Rate calculations. Schedule E-36 XL and AG-X customers are directly
assigned power supply costs based on the APS system incremental cost at the time the customer
is consuming power from the APS system so their power supply costs and kph usage are
excluded from the PSA.
6 Or any successor FERC account used to record the costs of purchasing carbon emission allowances.
Effective Date XX/XX/ XXX
76295
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Appendix D
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
\
Appendix D
Page 1 of 1
rTr
$ in Millions
°/o
4.46%
1.59%
0.09%
0.35°/o
1.30°/o
2.00%
-0.51°/o
9.28%
$
$128.785
46.054
2.459
9.993
37.596
57.670
(14.604)
$267.953
Transmission Cost Adjustor Transfer
Lost Fixed Cost Recovery Adjustor Transfer
Environmental Improvement Surcharge Transfer
Demand Side Management Adjustment Clause Transfer
Renewable Energy Adjustment Clause Transfer
Four Corners Rate Rider Transfer
System Benefits Charge Transfer
Total Surcharge Transfer
»
76295DECISION no.
lDOCKET no. E-01345A-l6-0036 ET AL.
Appendix E
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.Appendix E
Page 1 of 15
PLAN OF ADMINISTRATION
TAX EXPENSE ADJUSTOR MECHANISMGaps
Tax Expense Adjustor Mechanism
Plan of Administration
Table of Contents
l
1 General l
2.l
3. Calculation 2
4. TEAM 8alancing 2
5. Filing and Procedural Deadlines 3
6 Compliance 3
1. General Description
This document describes the plan for administering the Federal Income Tax Expense
Adjustor Mechanism (TEAM) approved for Arizona Public Service Company (APS or
Company) by the Arizona Corporation Commission (ACC or Commission) on [insert date]
in Decision No. XXXXX. In the event that significant Federal income tax reform
legislation is enacted and effective prior to the conclusion of APSs next General Rate Case
(GRC), and such legislation materially impacts 1 the Company's annual revenue
requirements, the TEAM enables the pass-through of these income tax effects to
customers.The TEAM will be calculated upon the effective date of legislation, and
annually on a prospective basis, and will terminate upon the conclusion of APS's next
GRC.
2.Definitions
Annual Tax Expense Adjustment - The Annual Tax Expense Adjustment represents the
amount to be passed through to jurisdictional retail customers in the subsequent twelve
month period and is applied to customer bills via a $ per kph adjustment.
Base Revenue Requirements Change -The change in the Company's Base Revenue
Requirements as a result of any Federal income tax reform legislation will be measured as
the change in:
c.
a. The Federal Income Tax Rate-Test Year as compared to the Federal Income
Tax Rate-Revised as applied to the Company's Adjusted 2015 Test Year,
b. Annual amortization of any resulting excess deferred income tax regulatory
account compared to the Company's Adjusted 2015 Test Year, and,
Permanent income tax adjustments (such as interest expense and/or property
tax expense deductibility) compared to those taken in the Company's
Adjusted 2015 Test Year.
1"Material impacts" is defined as changing APS's revenue requirement by more than $5 million.
Page I of 3
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix E
Page 2 of 15
PLAN OF ADMINISTRATION
TAX EXPENSE ADJUSTOR MECHANISMQ ops l
Federal Income Tax Rate-Revised - The Federal income tax rate that is revised as a result
of any Federal income tax reform legislation enacted and effective subsequent to Decision
No. XXXXX and prior to the conclusion ofAPS's next GRC.
Federal Income Tax Rate-Test Year .- The Federal income tax rate of 35% in effect and
utilized in the 2015 Test Year as approved by the Commission in Decision No. XXXXX.
Forecasted Retail kph Sales .- The forecasted calendar year energy (kph) sales served
under applicable ACC jurisdictional retail electric rate schedules. A true-up reconciliation
of the forecasted data will be completed in the following year through the Balancing
Account.
3. Calculation of TEAM
The Annual Tax Expense Adjustment is calculated annually and represents the amount to
be passed through to jurisdictional retail customers. The adjustment is calculated based
on the Company's Base Revenue Requirements Change resulting from any Federal income
tax reform legislation enacted and effective subsequent to that used to set rates as approved
in Decision No. XXXXX, and prior to the conclusion of APSs next GRC, as defined
above.
The Annual Tax Expense Adjustment will be applied to applicable customers' total bill via
a S per kph adjust°ment over the twelve month period beginning March l of the year
following the rate filing described in Section 5 below. The TEAM $ per kph rate is
calculated by dividing the Annual Tax Expense Adjustment by the Forecasted Retail kph
Sales as determined in Schedule l of the filing.
4. TEAM Balancing Account
APS will maintain accounting records that accumulate the difference between the
calculated Annual Tax Expense Adjustment as compared to the actual amounts applied to
customers' total bills through the TEAM $ per kph adjustment during the pass-through
period (March through February). Additionally, as a result of utilizing Forecasted Retail
kph Sales, the balancing account will contain a true-up component in which estimated
balances will be replaced with actual balances for the prior year filing.
The difference will be recorded to the TEAM Balancing Account each month and will
accrue interest at the Company's applicable cost of short-term debt. In the event that the
Annual Tax Expense Adjustment is more or less than the amount passed through to
customers as of the last billing cycle of February, the over or under collection, plus interest,
will be subtracted from or added to the TEAM calculation in the subsequent period.
Page2 ola
76295DECISION no.
DOCKET no. E-01345A-16-0_36 ET AL.Appendix E
Page 3 of 15
PLAN OF ADMINISTRATION
TAX EXPENSE ADJUSTOR MECHANISMQ ops
5. Filing and Procedural Deadlines
APS will file the Annual Tax Expense Adjustment, including all Compliance Reports, with
the Commission for the upcoming year by December 1", terminating at the conclusion of
APS's next GRC.
The Commission Staff and interested parties will have the opportunity to review the
TEAM filing and supporting data in the adjustor calculation. Unless the Commission has
otherwise acted or Staff has filed an objection by March 151, the new TEAM $ per kphrate
proposed by APS will go into effect with the first billing cycle in March (without proration)
and will remain in effect for the following 12-month period.
6. Compliance Reports
APS will provide an annual report to Staff and the Residential Utility Consumer Office
detailing all calculations related to the TEAM S per kph adjustment. The reports will
include the following Schedules 1 through 3 as attached to this document:
Schedule l:
Schedule 2:
Schedule 3:
Current Year Annual Tax Expense Adj vestment and TEAM $
per kph Credit
Current Year TEAM Balancing Account
Adjusted 2015 Test Year SFR Schedules (as follows):
Schedule 3-Al :
l
l
l
l
l
l
l
Schedule 3-Bl(l ):
Schedule 3-B1(2):
Schedule 3-B2:
Schedule 3-B3:
Schedule 3-C 1 (1 ):
Schedule 3-C 1(2):
Schedule 3-C2:
Schedule 3-C3:
Schedule 3-C2 Detail:
Computation of Increase in Gross Revenue
Requirements
Summary of Original Cost Rate Base Elements
Summary of RCND Rate Base Elements
Original Cost Rate Base Pro Forma Adjustments
RCND Rate Base Pro Forma Adjustments
Total Company Adjusted Test Year Income Statement
ACC Jurisdiction Adjusted Test Year Income
Statement
Income Statement Pro Forma Adjustments
Computation of Gross Revenue Conversion Factor
Detail of Pro Forma Adjustments as Shown on
Schedule 3-C2
Page 3 of 3
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76295DECISION no.
DOCKET no. E-01345A-I6-0036 ET AL.Appendix E
Page 11 of 15
i
iDue to the confidential nature of the Financial information contained in this form the future filings will be confidential
ARIZONA PUBLIC SERVICE COMPANY
iSchedule 3-C1 (1) - TEAM
TOTAL COMPANY
ADJUSTED TEST YEAR INCOME STATEMENT
T EST Y EAR ENDED 12/31/2015
(Dollars in Thousands)
Total Company i
Line
Settlement
Results After
Proforma
NO.. .Line
uh.
T EA M
Proforma
Adlll§1l1l§lJ1§.
(B)
A$1l.U§.Illl£Ll1§_
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Settlement
Test Year
EJJ$1§s1l2L3l!2QJ.i
(A)
1.
2.
3.
1.
2.
3.
4.4.
Electric Operating Revenues
Revenues from Base Rates
Revenues from Surcharges
Other Electric Revenues
Total
5.
6.
5.
6.
7.7.
8.
9.
10.
Operating expenses 2
Electric fuel and purchased power
Operations and maintenance excluding fuel expenses
Depreciation and amortization
Income taxes
Other taxes
Total
8.
9.
10.
11.11.Operating income
_
12.
13.
14.
15.
16.
12.
13.
14.
15.
16.
Other income (deductions):
Income taxes
Allowance for equity funds used during construction
Other income
Other expense
Total
17.income before interest deductions17
18.
19.
20.
21.
22.
Interest deductions:
Interest on longterm debt
Interest on shortterm borrowings
Debt discount. premium and expense
Allowance for borrowed funds used during construction
Total
18.
19
20.
21.
22.
23.Net income23.
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.iAppendix E
Page 12 of 15
Due to the confidential nature of the financial information contained in this form the future filings will be confidential
ARIZONA PUBLIC SERVICE COMPANY
Schedule 3-C1 (2) - TEAM
ACC JURISDICTION
ADJUSTED TEST YEAR INCOME STATEMENT
TEST YEAR ENDED 12/31/2015
(Dollars in Thousands)
ACCJurisdiction
Settlement
Results After
Proforma Line
ALQ..Line
N.(2.
TE A M
Proforma
AS1iLI§.IM§D1§.
(B)
Asliu§.ILD§D1§
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Settlement
Test Year
Eme¢J25z1an1s.
(A)
1.
2
3.
1.
2.
3.
4.4.
Electric Operating Revenues
Revenues from Base Rates
Revenues from Surcharges
Other Electric Revenues
Total
5.
5.
7.
8.
9.
10.
Operating expenses:
Electric fuel and purchased power
Operations and maintenance excluding fuel expenses
Depreciation and amortization
Income taxes
Other taxes
Total
5.
6
7.
8
9.
10.
11.11.Operating income
12.
13.
14.
15.
16.
Other income (deductions):
Income taxes
Allowance for equity funds used during construction
Other income
Other expense
Total
12.
13.
14.
15.
16.
17.17.Income before interest deductions
18.
19.
20.
21.
22.
Interest deductions:
Interest on longterm debt
Interest on shortterm borrowings
Debt discount premium and expense
Allowance for borrowed funds used during construction
Total
18.
19.
20.
21.
22.
Net income 23.23.
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
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76295DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix F
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 1 of 26
Q ops RATE SCHEDULE R-XS
EXTRA SMALL RESIDENTIAL SERVICE
AVAILABILITY
This rate schedule is available to full requirements residential Customers with an average
monthly energy usage of 600 kilowatt-hours (kph) or less who do not have an on-site
distributed generation system. For new customers, initial annual average monthly energy
usage will be based on historical energy consumption at the Customer's site. Annual
reassignment will begin with January 2019 bills.
DESCRIPTION
This rate has two parts: a basic service charge and an energy charge. Energy charges are based
on how much energy (kph) is used during the month. This rate does not have time-of-use
charges, seasonal charges, or a demand charge.
CHARGES
The monthly bill will consist of the following charges, plus adjustments:
Bundled Charges
$0.329
$011672
per day
per kph
Basic Service Charge
Energy Charge °
Unbundled Components of the Bundled Charges
Bundled Charges consist of the components shown below. These are not additional charges.
Basic Service Char e Com orients
$0.072
$0.104
$0.072
$0.081
per day
per day
per day
per day
Customer Accounts Charge
Metering Charge
Meter Reading Charge
Billing Charge
a Char eCo orients
$0.00276
$0.01097
$003112
$0.07187
per kph
per kph
per kph
per kph
Ever
System Benefits Charge:
Transmission Charge
Delivery Charge
Generation Charge
A.C.C. No. XXXX
Original
Rate Schedule RXS
Effective:xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title; Manager Regulation and Pricing
Page 1 of 3
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 2 of 26
Q ops RATE SCHEDULE R-XS
EXTRA SMALL RESIDENTIAL SERVICE
ADTUSTMENTS
The bill will include the following adjustments:
1. The Renewable Energy Adjustment Charge, Adjustment Schedule REAC-1.
2. The Power Supply Adjustment charges, Adjustment Schedule PSA-1.
3.
4.
The Transmission Cost Adjustment charge, adjustment Schedule TCA-1 .
The Environmental Improvement Surcharge, Adjustment Schedules ElS.
5. The Demand Side Management Adjustment charge, Adjustment Schedule DSMAC-1.
6. The Lost Fixed Cost Recovery Adjustment charge, Adjustment Schedule LFCR.
7.Direct Access customers returning to Standard Offer service may be subject to a
Returning Customer Direct Access Charge, Adjustment Schedule RCDAC-1.
8. The Tax Expense Adjustment charge, Adjustment Schedule TEAM.
9.Any applicable taxes and governmental fees that are assessed on APS's revenues, prices,
sales volume, or generation volume.
RATE RIDERS
Eligible rate riders for this rate schedule are:
Limited income discount
Limited income medical discount
Green Power
E-3
E-4
Gpsl, Gps2, Gps3
SERVICE DETAILS
1.APS provides electric service under the Company's Service Schedules. These schedules
provide details about how the Company serves its Customers, and they have provisions
and charges thatmay affect die Customer's bill (for example, service connection charges).
2.Electric service provided will be single-phase, 60 Hertz at APS's standard voltages available
at the Customer site. Three-phase service is required for motors of an individual rated
capacity of 71/2 HPor more.
A.C.C. No.XXXX
Original
Rate Schedule RXS
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A.Miessner
Title: Manager Regulation and Pricing
Page 2of3
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 3 of 26
I Q ops RATE SCHEDULE R-XS
EXTRA SMALL RESIDENTIAL SERVICE
3.Electric service is supplied at a single point of delivery and measured through a single
meter.
4.Direct Access Customers who purchase available electric services from a supplier other than
APS may take service under this schedule. The bill for these Customers will only include
the Unbundled Component charges for Customer Accounts, Delivery, System Benefits, and
any applicable Adjustments. If metering and billing services are not available from another
supplier, those services will be provided by APS and billed to the Customer at the charges
shown below.
v
A.CC No.XXXX
Original
Rate Schedule RXS
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager, Regulation and Pricing
Page3of3
76295DECISION no.
iDOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 4 of 26
Q ops RATE SCHEDULE R-BASIC
SMALL RESIDENTIAL SERVICE
AVAILABILITY
This rate schedule is available to residential Customers with an annual average monthly energy
usage of more than 600 but less than 1,000 kilowatt-hours (kph) who do not have an on-site
distributed generation system. For new customers, initial annual average monthly energy
usage will be based on historical energy consumption at the Customer's site. Annual
reassignment will begin with January 2019 bills.
Starting May 1, 2018, first-time Customers are not eligible for this rate for a period of ninety (90)
days from the date service begins. After this initial 90-day period, qualifying Customers may
move to this rate at any time but must remain on this R-Basic rate schedule for at least twelve
(12) consecutive months before moving to another residential rate schedule for which the
Customer may qualify.
DESCRIPTION
This rate has two parts: a basic service charge and an energy charge. Energy charges are based
on how much energy (kph) is used during the month. This rate does not vary by time-of-use,
season, or demand (how much energy is used at one time).
CHARGES
The monthly bill will consist of the following charges, plus adjustments:
Bundled Charges
$0.493
$0.12393
per day
per kph
Basic Service Charge
Energy Charge
Unbundled Components of the Bundled Charges
Bundled Charges consist of the components shown below. These are not additional charges.
Basic Service Char e Com orients
$0.125
$0.215
$0.072
$0.081
per day
per day
per day
per day
Customer Accounts Charge
Metering Charge
Meter Reading Charge
Billing Charge
A.C.C. No.XXXX
Original
Rate Schedule RBasic
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessncr
Title: Manager Regulation and Pricing
Page 1 of3
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 5 of 26
Gaps RATE SCHEDULE R-BASIC
SMALL RESIDENTIAL SERVICE
a Char e Com orients
$000276
$001097
$003112
$007908
per kph
per kph
per kph
per kph
Ever
System Benefits Charge
Transmission Charge
Delivery Charge
Generation Charge
ADIUSTMENTS
The bill will include the following adjustments:
1. The Renewable Energy Adjustment Charge, Adjustment Schedule REAC-1.
2. The Power Supply Adjustment charge, Adjustment Schedule PSA-1.
3. The Transmission Cost Adjushnent charge, adjustment Schedule TCA-1 .
4. The Environmental Improvement Surcharge, Adjustment Schedule ElS.
5. The Demand Side Management Adjustment charge, Adjustment Schedule DSMAC-1 .
¢
6. The Lost Fixed Cost Recovery Adjustment charge, Adjustment Schedule LFCR.
7. The Tax Expense Adjustment charge, Adjustment Schedule TEAM.
8.Direct Access customers returning to Standard Offer service may be subject to a
Returning Customer Direct Access Charge, Adjustment Schedule RCDAC-1 .
9.Any applicable taxes and governmental fees that are assessed on APS's revenues, prices,
salesvolume, or generation volume.
RATE RIDERS
Eligible rate riders for this rate schedule are:
Limited income discount
Limited income medical discount
Green Power
E-3
E-4
GPS-1, GPS-2, GPS-3
Acc. No. XXXX
Original
Rate Schedule RBasic
Effective:xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by:Charles A. Miessner
Title: Manager, Regulation and Pricing
Page 2 of 3
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 6 of 26
Q ops RATE SCHEDULE R-BASIC
SMALL RESIDENTIAL SERVICE
SERVICE DETAILS
1.APS provides electric service under the Company's Service Schedules. These schedules
provide details about how the Company serves its Customers, and they have provisions
and charges that may affect the Customer's bill (for example, service connection charges).
2.Electric service provided will be single-phase, 60 Hertz at APS's standard voltages available
at the Customer site. Three-phase service is required for motors of an individual rated
capacity of 71/z HP or more.
3.Electric service is supplied at a single point of delivery and measured through a single
meter.
4.Direct Access Customers who purchase available electric services from a supplier other dram
APS may take service under this schedule. The bill for these Customers will only include
the Unbundled Component charges for Customer Accounts, Delivery, System Benefits, and
any applicable Adjustments. If metering and billing services are not available from another
supplier, those services will be provided by APS and billed to the Customer at the charges
shown above.
o
A.C.C. No. xxxx
Original
Rate Schedule RBasic
Effective:xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix,Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 3 of 3
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 7 of 26
Gaps RATE SCHEDULE R-BASIC L
LARGE RESIDENTIAL SERVICE
AVAILABILITY
This rate schedule is available to residential Customers with an annual average monthly energy
usage of 1,000 kilowatt-hours (kph) or more who do not have an on-site distributed generation
system. For new customers, initial annual average monthly energy usage will be based on
historical energy consumption at the Customer's site.
Eligibility for this rate schedule will be frozen on May 1, 2018. After this date, Customers may
not elect to take service under this rate, whether they are new or moving from a different rate.
Charges on this schedule may change.
DESCRIPTION
This rate has two parts: a basic service charge and an energy charge. Energy charges are based
on how much energy (kph) is used during the month. This rate does not vary by time-of-use,
season, or demand (how much energy is used at one time).
CHARGES
The monthly bill will consist of the following charges, plus adjustments:
Bundled Charges
s
$0.658
$013412
per day
per kph
Basic Service Charge
Energy Charge
Unbundled Components of the Bundled Charges
Bundled Charges consist of the components shown below. These are not additional charges.
Basic Service Char e Com orients
$0.290
$0.215
$0.072
$0.081
per day
per day
per day
per day
Customer Accounts Charge
Metering Charge
Meter Reading Charge
Billing Charge
A.C.C. No. XXXX
Original
Rate Schedule RBasic L
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby: Charles A.Miessner
Title: Manager Regulation and Pricing
Page 1 of 3
76295DECISION no.
l
DOCKET NO. E-01345A-16-0036 ET AL.Appendix F
Page 8of 26
Q ops RATE SCHEDULE R-BASIC L
LARGE RESIDENTIAL SERVICE
Char e Com orients
$000276
380.01097
$003112
$008927
per kph
per kph
per kph
per kph
Ener
System Benefits Charge
Transmission Charge
Delivery Charge
Generation Charge
ADIUSTMENrS
The bill will include the following adjustments:
1. The Renewable Energy Adjustment Charge, Adjustment Schedule REAC-1 .
2. The Power Supply Adjustment charge, Adjustment Schedule PSA-1.
3. The Transmission Cost Adjustment charge, adjustment Schedule TCA-1 .
4. The Environmental Improvement Surcharge, Adjustment Schedule ElS.
5. The Demand Side Management Adjustment charge,Adjustment Schedule DSMAC-1.
6.The Lost Fixed Cost Recovery Adjustment charge, Adjustment Schedule LFCR.
¢
7.The Tax Expense AdjusUnent charge, Adjustment Schedule TEAM.
8.Direct Access customers returning to Standard Offer service may be subject to a
Returning Customer Direct Access Charge, Adjustment Schedule RCDAC-1 .
9.Any applicable taxes and governmental fees that are assessed on APS's revenues, prices,
sales volume, or generation volume.
RATE RIDERS
Eligible rate riders for this rate schedule are:
Limited income discount
Limited income medical discount
Green Power
E-3
E-4
Gp54, Gp92, GPS?)
A.c.c. No. XXXX
Original
Rate Schedule RBasic L
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 2 of 3
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 9 of 26
Q ops RATE SCHEDULE R-BASIC L
LARGE RESIDENTIAL SERVICE
SERVICE DETAILS
1.APS provides electric service under the Company's Service Schedules. These schedules
provide details about how the Company serves its Customers, and May have provisions
and charges that may affect the Customer's bill (for example, service connection charges).
2.Electric service provided will be single-phase, 60 Hertz at APS's standard voltages available
at the Customer site. Three-phase service is required for motors of an individual rated
capacity of 7 VS HP or more.
3. Electric service is supplied at a single point of delivery and measured through a single
meter.
4.Direct Access Customers who purchase available electric services from a supplier other than
APS may take service under this schedule. The bill for these Customers will only include
the Unbundled Component charges for Customer Accounts, Delivery, System Benefits, and
any applicable Adjustments. If metering and billing services are not available from another
supplier, those services will be provided by APS and billed to the Customer at the charges
shown above.
¢
Acc No. XXXX
Original
Rate Schedule R~Basic l.
Effective: xxxx
ARIZONA PUBLIC sERv1cr COMPANY
Phoenix,Arizona
Filed by:Charles A.Miessner
Title: Manager Regulation and Pricing
Page 3 of 3
76295DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 10 of 26
IQ ops RATE SCHEDULE TOU-E
RESIDENTIAL TIME-OF-USE SERVICE
AVAILABILITY
This rate schedule is available to all residential Customers, including Partial Requirements
Customers with an on-site distributed generation system.
DESCR1PT1ON
This rate has two parts: a basic service charge and an energy charge. The energy charge will
vary by season (summer or winter) and by the time of day that the energy is used (On-Peak or
Off-Peak). This rate does not include a demand charge.
TIME PERIODS
The On-Peak time period for residential rate schedules is 3 p.m. to 8 p.m. Monday through
Friday year round. This rate also has a Super Off-Peak period, which is 10 a.m. to 3 p.m.
Monday through Friday during the winter billing cycles of November through April. All other
hours are Off-Peak hours.
The following holidays are also included in the Off-Peak hours:
¢
•
•
•
•
•
•
•
•
•
•
New Year's Day - January 1*
Martin Luther King Day - Third Monday in January
Presidents Day - Third Monday in February
Cesar Chavez Day - March 31*
Memorial Day - Last Monday in May
Independence Day - ]fly 4*
Labor Day - First Monday in September
Veterans Day - November 11*
Thanksgiving - Fourth Thursday in November
Christmas Day - December 25*
*If these holidays fall on a Saturday, Me preceding Friday will be Off-peak. If they fall on a
Sunday, the following Monday will be Off-Peak.
The rate also varies by summer and winter seasons. The summer season is the May dirough
October billing cycles and the winter season is the November dmrough April billing cycles.
CHARGES
The monthly bill will consist of the following charges, plus adjustments:
Bundled Charges
$0.427 per dayBasic Service Charge
A.C.C. No. xxxx
Rate Schedule TOUE
Original
Effective:xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: CharlesA.Miessner
Title: Manager Regulation and Pricing
Page 1 of 4
DECISION no.76295
i1DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 11 of 26
Gaps RATE SCHEDULE TOU-E
RESIDENTIAL TIME-OF-USE SERVICE
I9 __
Bundled Char es continued:
Summer Winter
$0.24314 $023068
50.10873 $0.10873
$().()3200
per kph
per kph
per kph
On-Peak Energy Charge
Off-Peak Energy Charge
Super Off-Peak Energy Charge
Unbundled Components of the Bundled Charges
Bundled Charges consist of the components shown below. These are not additional charges.
Basic Service Char e Com orients
$0.073
$0.201
$0.072
$0.081
per day
per day
per day
per day
Customer Accounts Charge
Metering Charge
Meter Reading Charge
Billing Charge
5
per kph
per kph
Ener Char e Com orients
System Benefits Charge $0.00276
Transmission Charge $0.01097
__Summer
$003112
$0.19829
$006388
Winter
$001105
$0.18583
$006388
$000722
per kph
per kph
per kph
per kph
Delivery Charge
Generation On-Peak Charge
Generation Gff-Peak Charge
Generation Super Off-Peak Charge
CHARGE FOR ON-SITE DISTRIBUTED GENERATION CUSTOMERS
The monthly bill for Customers on this rate schedule who have an on-site distributed
generation system will also include a Grid Access Charge. This charge will apply to the
nameplate kW-dc power rating of the Customer's distributed generation facility:
$0.93 per kW-dc of generationGrid Access Charge
A.C.C. No. xxxx
Rate Schedule TOUE
Original
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix, Arizona
Filed by: Charles A.Miessner
Title: Manager Regulation and Pricing
Page 2 of 4
DECISION no.76295
ii
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 12 of 26
Q ops RATE SCHEDULE TOU-E
RESIDENTIAL TIME-OF-USE SERVICE
ADIUSTMENTS
The bill will include the following adjustments:
1. The Renewable Energy Adjustment Charge, Adjustment Schedule REAC-1 .
2. The Power Supply Adjustment charge, Adjustment Schedule PSA-1.
3. The Transmission Cost Adjustment charge, Adjustment Schedule TCA-1.
4. The Environmental Improvement Surcharge, Adjustment Schedule ElS.
5. The Demand Side Management Adjustment charge, Adjustment Schedule DSMAC-1.
6. The Lost Fixed Cost Recovery Adjustment charge, Adjustment Schedule LFCR.
7. The Tax Expense Adjustment charge, Adjustment Schedule TEAM.
8.Direct Access customers returning to Standard Offer service may be subject to a
Returning Customer Direct Access Charge, Adjustment Schedule RCDAC-1.
9.Any applicable taxes and governmental fees that are assessed on APS's revenues, prices,
sales volume, or generation volume.
RATE RIDERS
Eligible rate riders for this rate schedule are:
CPP (RFS)Critical Peak Pricing (Residential)
EPR-2 Partial Requirements
EPR-6 Partial Requirements - Net Metering (Residential Non-Solar)
RCP Resource Comparison Proxy
E-3 Limited income discount
E-4 Limited income medical discount
GPS-1, GPS-2, GPS-3 Green Power
A.C.C. No. xxxx
Rate Schedule TOUE
Original
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: CharlesA.Miessner
Title: Manager, Regulation and Pricing
Page 3 of 4
76295DECISION no.
DOCKET no. E-01345A-l6-0036 ET AL.Appendix F
Page 13 of 26
Q ops RATE SCHEDULE TOU-E
RESIDENTIAL TIME-OF-USE SERVICE
SERVICE DETAILS
1.APS provides electric service under the Company's Service Schedules. These schedules
provide details about how the Company serves its Customers, and they have provisions
and charges that may affect the Customer's bill (for example, service connection charges).
2.Electric service provided will be single-phase, 60 Hertz at APS's standard voltages available
at the Customer site. Three-phase service is required for motors of an individual rated
capacity of 7 V2 HP or more.
3. Electric service is supplied at a single point of delivery and measured through a single
meter.
4.Direct Access Customers who purchase available electric services from a supplier other than
APS may take service under this schedule. The bill for these Customers will only include
the Unbundled Component charges for Customer Acounts, Delivery, System Benefits, and
any applicable Adjustments. If metering and billing services are not available from another
supplier, those services will be provided by APS and billed to the Customer at the charges
shown above.
A.C.C. No. xxxx
Rate Schedule TOU-E
Original
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 4 of 4
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.Appendix F
Page 14 of 26
Q ops RATE SCHEDULE R-2
RESIDENTIAL SERVICE
AVAILABILITY
This rate schedule is available to all residential Customers, including Partial Requirements
Customers with an on-site distributed generation system.
DESCRIPTION
This rate has three parts: a basic service charge, a demand charge for the highest amount of
demand (kW) averaged in a one hour On-Peak period for the month, and an energy charge for
the total energy (kph) used for the entire month. The energy charge will vary by season
(summer or winter) and by the time of day that the energy is used (On-Peak or Off-Peak). The
demand charge will not vary by season.
TIME PERIODS
The On-Peak time period for residential rate schedules is 3 p.m. to 8 p.m. Monday through
Friday year round. All other hours are Off-Peak hours.
The following holidays are also included in the Off-Peak hours:
¢
•
•
•
•
•
•
•
•
•
•
New Year's Day - January 1*
Martin Luther King Day - Third Monday in ]january
Presidents Day - Third Monday in February
Cesar Chavez Day - March 31*
Memorial Day - Last Monday in May
Independence Day - ]ugly 4*
Labor Day - First Monday in September
Veterans Day - November 11*
Thanksgiving - Fourth Thursday in November
Christmas Day - December 25*
*If these holidays fall on a Saturday, the preceding Friday will be Off-peak. If they fall on a
Sunday, the following Monday will be Off-Peak.
The rate also varies by summer and winter seasons. The summer season is the May through
October billing cycles and the winter season is the November through April billing cycles.
CHARGES
This monthly bill will consist of the following charges, plus adjustments:
A.C.C.No. xxxx
Original
Rate Schedule R-2
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager, Regulation and Pricing
Page 1 of 4
76295DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 15 of 26
opsQ RATE SCHEDULE R-2
RESIDENTIAL SERVICE
Bundled Charges
$0.427 per dayBasic Service Charge:
__Winter
$8.40
$0.11017
$0.07798
Summer
$8.40
$013160
$0.07798
per kW
per kph
per kph
On-Peak Demand Charge:
On-Peak Energy Charge:
Off-Peak Energy Charge:
Unbundled Components of the Bundled Charges
Bundled Charges consist of the components shown below. These are not additional charges.
Basic Service Char e Com orients
$0.073
$0.201
$0.072
$0.081
per day
per day
per day
per day
Customer Accounts Charge:
Metering Charge
Meter Reading Charge
Billing Charge
per kW
per kW
Demand Char e Com orients
Delivery On-Peak kW Charge $4.000
Generation On-Peak kW Charge $4.400
3 Char eCo orients
$000276
$001097
per kph
per kph
Ener
System Benefits Charge:
Transmission Charge:
-_Winter
$001105
$008539
$005320
Summer
$0.01105
$010682
$0.05320
per kph
per kph
per kph
Delivery Charge for all kwh:
Generation On-Peak kph Charge:
Generation Off-Peak kph Charge:
l
i
l
A.C.C No. xxxx
Original
Rate ScheduleR2
Effective:xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 2 of 4
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 16 of 26 ll
1
Q ops RATE SCHEDULE R-2
RESIDENTIAL SERVICE
The kW used to determine the demand charge above will be the Customer's highest amount of
demand (kW) averaged in a one-hour On-Peak period for the billing month.
For full requirements Customers, billing demands are limited to a kW no higher than that
which would result in a 15% load factor, based on the Customer's kph usage during the
month. This limitation is not available to partial requirements Customers.
ADTUSTMENTS
The bill will include the following adjustments:
1. The Renewable Energy Adjustment Charge, Adjustment Schedule REAC-1 .
2. The Power Supply Adjustment charges, Adjustment Schedule PSA-1 .
3. The Transmission Cost Adjustment charge, Adjustment Schedule TCA-1 .
4. The Environmental Improvement Surcharge, Adjustment Schedule ElS.
5. The Demand Side Management Adjustment charge, Adjustment Schedule DSMAC-1.
6. The Lost Fixed Cost Recovery Adjustment charge, Adjustment Schedule LFCR.
7. The Tax Expense Adjustment charge, Adjustment Schedule TEAM.
8.Direct Access customers returning to Standard Offer service may be subject to Returning
Customer Direct Access Charge, Adjustment Schedule RCDAC-1.
9.Any applicable taxes and governmental fees that are assessed on APS's revenues, prices,
sales volume, or generation volume.
RATE RIDERS
Eligible rate riders for this rate schedule are:
Critical Peak Pricing (Residential)
Limited income discount
Limited income medical discount
Partial Requirements
Partial Requirements - Net Metering (Residential Non-Solar)
Resource Comparison Proxy
Green Power
CPP-RES
E-3
E-4
EPR-2
EPR-6
RCP
GPS-1, GPS-2, GPS-3
A.C.C. No xxxx
Original
Rate Schedule R2
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager, Regulation and Pricing
Page 3 of 4
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.Appendix F
Page 17 of 26
Q ops RATE SCHEDULE R-2
RESIDENTIAL SERVICE
SERVICE DETAILS
1.APS provides electric service under the Company's Service Schedules. These schedules
provide details about how the Company serves its Customers, and they have provisions
and charges that may affect the Customer's bill (for example, service connection
charges).
2.Electric service provided will be single-phase, 60 Hertz at APS's standard voltages
available at the Customer site. Three-phase service is required for motors of an
individual rated capacity of 7 1/2 HP or more.
3. Electric service is supplied at a single point of delivery and measured through a single
meter.
4.Direct Access Customers who purchase available electric services from a supplier other
than APS may take service under this schedule. The bill for these Customers will only
include the Unbundled Component charges for Customer Accounts, Delivery, System
Benefits, and any applicable Adjustments. If metering and billing services are not
available from another supplier, those services will be provided by APS and billed to
the Customer at the charges shown above.
5.Load factor is a relationship between how much energy (kph) a Customer uses over a
period of time and how much demand (kW) is used at one time during that same
period, expressed in percentage. The Company will calculate the Customer's load factor
for purposes of the billing demand limitation described earlier using the following
formula:
Monthly Load Factor = Billed kph/ (Billed kW * Billing Days * 24 hours)
A.C.C.No.xxxx
Original
Rate Schedule R2
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by:Charles A.Miessner
Title:Manager Regulation and Pricing
Pages of 4
76295DECISION no.
.I
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 18 of 26
Gaps RATE SCHEDULE R-3
RESIDENTIAL SERVICE
AVAILABILITY
This rate schedule is available to all residential Customers, including Partial Requirements
Customers with an on-site distributed generation system.
DESCRIPTION
This rate has dire parts: a basic service charge, a demand charge for the highest amount of
demand (kW) averaged in a one hour On-Peak period for the month, and an energy charge for
the total energy (kph) used for the entire month. The energy charge will vary by season
(summer or winter) and by the time of day that the energy is used (On-Peak or Off-Peak). The
demand charge also varies by season.
TIME PERIODS
The On-Peak time period for residential rate schedules is 3 p.m. to 8 p.m. Monday through
Friday. All other hours are Off-Peak hours.
The following holidays are also included in the Off-Peak hours:
u
•
•
•
•
•
•
I
•
•
I
New Year's Day - January 1*
Martin Luther King Day - Third Monday in January
Presidents Day - Third Monday in February
Cesar Chavez Day - March 31*
Memorial Day - Last Monday in May
Independence Day - ]fly 4*
Labor Day - First Monday in September
Veterans Day - November ll*
Thanksgiving - Fourth Thursday in November
Christmas Day - December 25*
*If these holidays fall on a Saturday, the preceding Friday will be Off-peak. If they fall on a
Sunday, the following Monday will be Off-Peak.
The rate also varies by summer and winter seasons. The summer season is the May through
October billing cycles and the winter season is the November through April billing cycles.
CHARGES
This monthly bill will consist of the following charges, plus adjustments:
A.C.C. No.xxxx
Original
Rate ScheduleR-3
Effective:xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizcna
Filed by:Charles A. Miessner
Title:Manager Regulation and Pricing
Page] of 4
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 19 of 26
I
Q ops RATE SCHEDULE R-3
RESIDENTIAL SERVICE
Bundled Charges
$0.427 per dayBasic Service Charge:
__Winter
$12239
$0.06376
50.05230
Summer
3417.438
$008683
$0.05230
per kW
per kph
per kph
On-Peak Demand Charge:
On-Peak Energy Charge:
Off-Peak Energy Charge:
Unbundled Components of the Bundled Charges
Bundled Charges consist of the components shown below. These are not additional charges.
Basic Service Char e Com orients
$0.073
$0.201
$0.072
$0.081
per day
per day
per day
per day
Customer Accounts Charge:
Metering Charge
Meter Reading Charge
Billing Charge
_
Demand Char e Com orients
Summer Winter
$4.000 $4.000
513.438 $8.239
per kW
per kW
Delivery On-Peak kW Charge
Generation On-Peak kW Charge
l•
per kph
per kph
Ever Char e Com orients
System Benefits Charge:$000276
Transmission Charge:$001097
1_Winter
$001105
$0.03898
$002752
Summer
$001105
$006205
$002752
per kph
per kph
per kph
Delivery Charge for all kwh:
Generation On-Peak kph Charge:
Generation Off-Peak kph Charge:
A.C.C. No.xxxx
Original
Rate ScheduleR-3
Effective; xxxx
ARIZONA PUBLICSERVICECOMPANY
Phoenix Arizona
Filedby: Charles A.Miessner
Title: Manager Regulation and Pncing
Page 2 of 4
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 20 of 26
Q ops RATE SCHEDULE R-3
RESIDENTIAL SERVICE
The kW used to determine the demand charge above will be the Customer's highest amount of
demand (kW) averaged in a one-hour On-Peak period for the billing month..
For full requirements Customers, billing demands are limited to a kW no higher than that
which would result in a 15% load factor, based on the Customer's kph usage during the
month. This limitation is not available to partial requirements Customers.
ADIUSTMENTS
The bill will include the following adjustments:
1. The Renewable Energy Adjustment Charge, Adjustment Schedule REAC-1 .
2. The Power Supply Adjustment charges, Adjustment Schedule PSA-1 .
3. The Transmission Cost Adjustment charge, Adjustment Schedule TCA-1.
4. The Environmental Improvement Surcharge, Adjustment Schedule ElS.
5. The Demand Side Management Adjustment charge, Adjustment Schedule DSMAC-1.
6. The Lost Fixed Cost Recovery Adjustment charge, Adjustment Schedule LFCR.
•7. The Tax Expense Adjustment charge, Adjustment Charge TEAM.
8.Direct Access customers returning to Standard Offer service may be subject to Returning
Customer Direct Access Charge, Adjustment Schedule RCDAC-1.
9.Any applicable taxes and governmental fees that are assessed on APS's revenues, prices,
sales volume, or generation volume.
RATE RIDERS
Eligible rate riders for this rate schedule are:
Critical Peak Pricing (Residential)
Partial requirements
Partial Requirements - Net Metering (Residential Non-Solar)
Resource Comparison Proxy
Limited income discount
Limited income medical discount
CCP- RES
EPR-2
EPR-6
RCP
E-3
E-4
A.C.C.No. xxxx
Original
Rate Schedule R3
Effective: xxxx
ARIZONA PUBLIC SERVICF COMPANY
Phoenix Arizona
Filedby:CharlesA.Miessner
Title: Manager Regulation and Pricing
Page 3 of 4
76295
DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.Appendix F
Page 21 of 26
Q ops RATE SCHEDULE R-3
RESIDENTIAL SERVICE
Green PowerGPS-1, GPS-2, GPS-3
SERVICE DETAILS
1.Customers that self-provide some of their electrical requirements from on-site
generation will be billed according to one of the Partial Requirements Service rate
riders.
2.APS provides electric service under the Company's Service Schedules. These schedules
provide details about how the Company serves its Customers, and they have provisions
and charges dirt may affect the Customer's bill (for example, service connection
charges).
3.Electric service provided will be single-phase, 60 Hertz at APS's standard voltages
available at the Customer site. Three-phase service is required for motors of an
individual rated capacity of 7 V2 HP or more.
4. Electric service is supplied at a single point of delivery and measured through a single
meter.
5.Direct Access Customers who purchase available electric services from a supplier other
than APS may take service under dies schedule. The bill for these Customers will only
include the Unbundled Component charges for Customer Accounts, Delivery, System
Benefits, and any applicable Adjustments. If metering and billing services are not
available from another supplier, those services will be provided by APS and billed to
the Customer at the charges shown above.
6.Load factor is a relationship between how much energy (kph) a Customer uses over a
period of time and how much demand (kW) is used at one time during that same
period, expressed in percentage. The Company will calculate the Customer's load factor
for purposes of the billing demand limitation described earlier using the following
formula:
Monthly Load Factor = Billed kph/ (Billed kW * Billing Days * 24 hours)
A.C.C. No. xxxx
Original
Rate ScheduleR3
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: CharlesA.Miessner
Title: Manager Regulation and Pricing
Page 4 of 4
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 22 of 26
Q ops RATE SCHEDULE R-TECH
RESIDENTIAL SERVICE
PILOT TECHNOLOGY RATE
AVAILABILITY
2.
This rate schedule is available to residential Customers with the following:
1.Two or more qualifying primary on-site technologies were purchased within 90
days of the customer enrolling in the rate; or
One qualifying primary on-site technology was purchased within 90 days of the
customer enrolling in the rate and two or more qualifying secondary on-site
technologies.
This is a pilot rate schedule. This means this rate is associated with a specific program
approved by the Arizona Corporation Commission, and is available only to those customers
eligible to participate in the program. The R-Tech pilot program will test the ability and desire
of participating residential customers to reduce On-Peak energy and demand usage through
multiple behind-the-meter technologies.
Qualifying technologies for the R-Tech pilot program are as follows:
1.
a.
b.
c.
Primary technologies:
A rooftop solar photovoltaic system.Thesize of the system cannot be
smaller than 2 kW-dc. For systems over 10 kW-dc, the facility's
nameplate capacity cannot be larger than 150% of the customer's
maximum one-hour peak demand measured in AC over the prior twelve
(12) months. (For example, if the customer's peak is 8kW-ac, the
maximum system size that could be installed would be 12kW-dc).
A chemical storage system. The size of the system cannot be smaller than
4 kph. There is no maximum limitation for this technology.
An electric vehicle. There are no limitations for this technology.
2.Secondary technologies:
a.A device with a variable speed motor (such as a variable speed pool
pump or a variable speed Heating, Ventilating, and Air Conditioning
(HVAC) system).
A grid-interactive water heating system.
A smart thermostat.
An automated load controller.
b.
c.
d.
This rate schedule is initially limited to a maximum of 10,000 residential customers as outlined
in Decision No. xxxxx.
DESCRIPTION
This rate has three parts: a basic service charge, a demand charge for the amount of demand
(kW) averaged in a one hour period for the month, and an energy charge for the total energy
(kph) used for the entire month. The energy charge will vary by season (summer or winter)
A.C.C.No.xxxx
Original
Rate Schedule RTech
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessncr
Title: Manager Regulation and Pricing
Page 1 of 5
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 23 of 26
Gaps RATE SCHEDULE R-TECH
RESIDENTIAL SERVICE
PILOT TECHNOLOGY RATE
and by the time of day that the energy is used (On-Peak or Off-Peak). The demand charge will
also vary by season (summer or winter) and time of day (On-Peak or Off-Peak).
TIME PERIODS
The On-Peak time period for residential rate schedules is 3 p.m. to 8 p.m. Monday through
Friday. All other hours are Off-Peak hours.
The following holidays are also included in the Off-Peak hours:
•
•
•
•
•
•
•
•
•
•
New Year's Day - ]january 1*
Martin Luther King Day - Third Monday in January
Presidents Day - Third Monday in February
Cesar Chavez Day - March 31*
Memorial Day - Last Monday in May
Independence Day - July 4*
Labor Day - First Monday in September
Veterans Day - November 11*
Thanksgiving - Fourth Thursday in November
Christmas Day - December 25*
*If these holidays fall on a Saturday, the preceding Friday will be Off-peak. If they fall on a
Sunday, the following Monday will be Off-Peak.
The rate also varies by summer and winter seasons. The summer season is the May through
October billing cycles and the winter season is the November through April billing cycles.
CHARGES
This monthly bill will consist of the following charges, plus adjustments:
Bundled Charges
$0.493 per dayBasicServiceCharge
__
per kWOn-Peak Demand Charge
per kWOff-Peak Demand Charge
Winter
$14.25
$0.00
$6.50
Summer
$20.25
$0.00
$6.50
First 5 kW
All remaining kW
A.C.C.No. xxxx
Original
Rate Schedule R-Tech
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A.Miessner
Title: Manager Regulation and Pricing
Page 2 of 5
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 24 of 26
opsQ RATE SCHEDULE R-TECH
RESIDENTIAL SERVICE
PILOT TECHNOLOGY RATE
$0.04750
$004750
$0.05750
$0.04750
per kph
per kph
On-Peak Energy Charge
Off-Peak Energy Charge
Unbundled Components of the Bundled Charges
Bundled Charges consist of the components shown below. These are not additional charges.
Basic Service Char e Com orients
$0.125
$0.215
$0.072
$0.081
per day
per day
per day
per day
Customer Accounts Charge
Metering Charge
Meter Reading Charge
Billing Charge
_
Off-Peak Generation
Charge
On-Peak Generation Charge
First 5 kW
All remaining kW•
per kW
per kW
per kW
per kWOn-Peak Delivery Charge
per kWOff-Peak Delivery Charge
Winter
$7.750
$0.000
$1.000
$6.500
$0.000
$5.500
Demand Char e Com orients
Summer
$13.750
$0.000
$1.000
$6.500
$0.000
$5.500
First 5 kW
All remaining kW
Ever Char eCon orients
$000276
5001097
$000210
per kph
per kph
per kph
System Benefits Charge
Transmission Charge
Delivery Charge for all kph
-_
1
Winter
$0.03167
$003167
Summer
$004167
$003167
per kph
per kph
Generation On-Peak kph Charge
Generation Off-Peak kph Charge
The kW used to determine the On-Peak demand charge above will be the Customer's highest
amount of demand (kW) averaged in a one hour On-Peak period for the month.I1
A.C.C. No.xxxx
Original
Rate ScheduleRTech
Effective:xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 3 of 5 76295DECISION no.
I
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 25 of 26
Q ops RATE SCHEDULE R-TECH
RESIDENTIAL SERVICE
PILOT TECHNOLOGY RATE
The kW used to determine the Off-Peak demand charge above will be the Customer's highest
amount of demand (kW) averaged in a one hour Off~Peak period during the weekday (Monday
through Friday), excluding holidays that may fall on a weekday.
ADIUSTMENTS
The bill will include the following adjustments:
1. The Renewable Energy Adjustmentcharge,Adjustment Schedule REAC-1 .
2. The Power Supply Adjustment charge, Adjustment Schedule PSA-1 .
3. The Transmission Cost Adjustment charge, Adjustment Schedule TCA-1.
4. The Environmental Improvement Surcharge, Adjustment Schedule ElS.
5. The Demand Side Management Adjustment charge, Adjustment Schedule DSMAC-1 .
6. The Lost Fixed Cost Recovery Adjustment charge, Adjustment Schedule LFCR.
7.The Tax Expense Adjustment charge, Adjustment Schedule TEAM.
a
8. Any applicable taxes and governmental fees that are assessed on APS's revenues, prices,
sales volume, or generation volume.
RATE RIDERS
Eligible rate riders for this rate schedule are:
Resource Comparison Proxy
Partial Requirements
Partial Requirements - Net Metering (Residential Non-Solar)
Limited income discount
Limited income medical discount
Green Power
RCP
EPR-2
EPR-6
E-3
E-4
GPS-1, GPS-2, GPS-3
SERVICE DETAILS
1. This pilot rate schedule requires the Customer to have a standard AMI meter in place.
A.C.C.No.xxxx
Original
Rate Schedule R-Tech
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 4 of 5
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix F
Page 26 of 26
Q ops RATE SCHEDULE R-TECH
RESIDENTIAL SERVICE
PILOT TECHNOLOGY RATE
2.Customers that self-provide some of their electrical requirements from on-site
generation will be billed according to one of the Partial Requirements Service rate
riders.
3.APS provides electric service under the Company's Service Schedules. These schedules
provide details about how the Company serves its Customers, and they have provisions
and charges that may affect the Customer's bill (for example, service connection
charges).
4.Electric service provided will be single-phase, 60 Hertz at APS's standard voltages
available at die Customer site. Three-phase service is required for motors of an
individual rated capacity of 7 VS HP or more.
5. Electric service is supplied at a single point of delivery and measured through a single
meter.
6. Direct Access customers are not eligible for this rate schedule.
A.C.C. No.xxxx
Original
Rate Schedule RTech
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 5 of 5
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix G
DECISION no.76295
DOCKET NO. E-01345A-16-0036 ET AL.Appendix G
Page 1 of 14
Settlement Rate Summary for Residential Rates
R T EC HR3R2TOUE
0.427
iii
ii
0.427
17438
0.08683
0.05230
0.427
8.400
0.13160
0.07798
0.24314
0.10873
0.493
20.250
6.500
0.05750
0.04750
0.427 0427
12.239
0.06376
0.05230
0.427
8.400
0.11017
0.07798
0.23068
0.10873
0.03200
Bundled Rates
Summer
BSC S/dav
On kW
Onpeak kph
Offpeak kph
Winter
BSC S/day
On kW
Onpeak kph
Offpeak kph
Super Offpeak kph
0.493
14.250
6.500
0.04750
0.04750
Bundled Rates
Summer
BSC 5/day
On kW
Offkw
Onpeak kph
Offpeak kph
Winter
BSC S/dav
On kW
Off kW
Onpeak kph
Offpeak kph
Super Offpeak kph
0.19829
0.06388
0.06205
0.02752
13.438
0.10682
0.05320
4.400 0.04167
0.03167
13.150
1.000
0.03B98
0.02752
0.08539
0.05320
0018583
0.06388
0.00722
8.239
0.01097
4.aw
0.010910.01097
0.03112
Unbundled Rates
Generation Summer
kph o n
kph . off
kW on
Generation . Winter
kph . on
kph . off
kph super off
kW on
Transmission . kph
Delivery Summer
kph
0.03167
0.03167
7.750
1.000
0.01097
Unbundled Rates
Generation . Summer
kph . on
kph . off
kW on
kW off
Generation Winter
kph on
kph . off
kW . on
kW off
Transmission . kph
0.01105
4.000
0.01105
4.000
0.01105 0.00210
6.500
s.so0
0.01105
4.000
0.00276
Delivery
kph
kW on
kW off
0.01105
4.000
0.002760.00276
0.002760073
0.201
0.081
0072
0.073
0.201
0.081
0.072
0.073
0.201
0.081
0.012
kW
Delivery . Winter
kph
kW
System Benefits kph
BSC S/dav
Customer accounts
Metering
Billing
Meter reading n
0.125
0.215
0.081
0.072
System Benefits . kph
BCS $Day
Customer accounts
Metering
Billing
Meter reading
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix G
Page 2 of 14
Settlement Rate Summary for Residential Rates
RBASIC LRBASICR X S
Transition
E12
Bundled Rates
0.658
0.13412
0.493
0.12393
0.329
0.11672
Bundled Rates
Summer & Winter
BSC S/day
kph
0.330
0.11161
0.15920
0.18627
0.19863
0.330
0.10851
Summer
BSC 5/day
0400 kph
401800 kph
8013000 kph
< 3000 kph
Winter
BSC $/dav
All kph
0.08927
0.01097
0.03112
0.00276
0.07908
0.01097
0.03112
0.00276
0.07187
0.01097
0.03112
0.00276
Unbundled Rates0.290
0.215
0.081
0.072
0.125
0.215
0.081
0.072
0.072
0.104
0.081
0.072
Unbundled Rates
Generation kph
Transmission kph
Delivery kph
System Benefits . kph
BSC S/day
Customer accounts
Metering
Billing
Meter reading
0.06676
0.11435
0.14142
0.15378
0.06366
0.01097
0.03112
0.00276
0.073
0.104
0.081
0.072
Generation . Summer
1st 400 kph
Next 400 kph
Next 2200 kph
All other kph
Generation Winter . kph
Transmission . kph
Delivery kph
System Benefits kph
BSC $/day
Customer accounts
Metering
Billing
Meter reading
s
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix G
Page 3 of 14
Settlement Rate Summary for Residential Rates
E C I 2EC T 1 R
Transition
T O U D
Bundled RatesE T 2E T 1
Transition
T O U E
Bundled Rates
0.643
0.28205
0.07105
0.643
0.20697
0.06697
0.643
15.61
0.10256
0.05109
0.643
15.69
0.08490
0.04730
0.643
0.22900
0.07005
0.643
0.16794
0.06397
Sum m e r
BSC $/day
O n P e a k k p h
O f f p e a k k p h
Ve n te r
BSC $/day
O n p e a k k p h
O f f p e a k k p h
0.643
10.76
0.06647
0.04750
0.643
10.89
0.06470
0.04594
Summer
BSC $/dav
kW
OnPeak kph
OffPeak kph
\Mnter
BSC S/daV
kW
Onpeak kph
Offpeak kphUnbundle d R ate s
Unbundled Rates0.23715
0.02615
0.16211
0.02211
0.05332
0.01572
11.17500
0.07264
0.02117
10.40900
0.18410
0.02515
0.01097
0.03117
0.00276
0.12308
0.01911
0.01097
0.03113
0.00276
0.03435
0.01538
7.98000
0.01097
0.03128
0.01252
8.22200
0.010970.27500
0.21500
0.08100
0.07200
0.27500
0.21500
0.08100
0.07200
Generation Summer
OnPeak kph
Offpeak kph
Generation Winter
Onpeak kph
Offpeak kph
Transmission kph
Delivery kph
System Benefits kph
BSC $/day
Customer accounts
Metering
Billing
Meter reading
0.01619
5.20500
0.01839
2.77600
0.00276
0.01785
4.51600
0.01969
2.66300
0.00276
0.27500
0.21500
0.08100
0.07200
0.27500
0.21500
0.08100
0.07200
0.02992
0.03212
0.03156
0.03342
Generation Summer
Onpeak kph
Offpeak kph
kW
Generation Vihnter
OnPeak kph
Offpeak kph
kW
Transmission kph
Delivery
Summer kph
Summer kW
Winter kph
Winter kW
System Benefits kph
BSC S/day
Customer accounts
Metering
Billing
Meter reading
Total Nontimed kph
Summer kph
Winter kph
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
9Appendix G
Page 4 of 14
Settlement Rate Summary for Residential Rates
E T 2E T 1
Solar Legacy
T O U E
Bundled Rates
Solar Legacy
E 1 2
Bundled Rates
0.643
0.28205
0.0710s
0.643
0.20697
0.06697
0.330
0.11161
0.15920
0.18627
0.19863 0.643
0.16794
0.06397
0.643
0.22900
0.07005
Summer
BSC S/dav
OnPeak kph
Offpeak kph
Winter
BSC $/day
Onpeak kph
Offpeak kph0.330
0.10851
Summer
esc S/aav
0400 kph
401800 kph
8013000 kph
< 3000 kph
Winter
BSC $/day
All kph
Unbundled Rates
Unbundled Rates
0.23715
0.02615
0.16211
0.02211
0.18410
0.02515
0.01097
0.03117
0.00276
0.12308
0.01911
0.01097
0.03113
0.00276
0.06676
0.11435
0.14142
0.15378
0.06366
0.01097
0.03112
0.00276
0.27500
0.21500
0.08100
0.07200
0.04490
0.27500
0.21500
0.08100
0.07200
0.04486
Generation Summer
OnPeak kph
Offpeak kph
Generation Winter
Onpeak kph
Offpeak kph
Transmission kph
Delivery kph
System Benefits kph
sec $/day
Customer accounts
Metering
Billing
Meter reading
Total untimed kph
0.07300
0.10400
0.08100
0.07200
Generation Summer
let 400 kph
Next 400 kph
Next 2200 kph
All other kph
Generation Winter kph
Transmission kph
Delivery kph
System Benefits kph
BSC $/day
Customer accounts
Metering
Billing
Meter reading
¢
76295DECISION no.
DOCKET NO. E-0i345A-16-0036 ET AL.
i
Appendix G
Page 5 of 14
Settlement Rate Summary for Residential Rates
ECT2ECTIR
Solar Legacy
T OUD
Bundled Rates
0.643
15.61
0.10256
0.05109
0.643
15.69
0.08490
0.04730
0.643
10.76
0.06647
0.04750
0.643
10.89
0.06470
0.04594
Summer
BSC $/day
kW
OnPeak kph
Offpeak kph
Winter
esc S/dav
kW
Onpeak kph
Offpeak kph
Unbundled Rates
0.07264
0.02117
10.40900
0.05332
0.01572
11.17500
0.03435
0.01538
7.98000
0.01097
0.03128
0.01252
8.22200
0.01097
0.01619
5.20500
0.01839
2.77600
0.00276
0.01785
4.51600
0.01969
2.66300
0.00276
0.27500
0.21500
0.08100
0.07200
0.27500
0.21500
0.08100
0.07200
Generation . Summer
Onpeak kph
Offpeak kph
kW
Generation Winter
OnPeak kph
Offpeak kph
kW
Transmission kph
Delivery
Summer kph
Summer kW
Winter kph
Winter kW
System Benefits . kph
BSC $/day
Customer accounts
Metering
Billing
Meter reading
Total Nontimed kph
0.02992
0.03212
0.03156
0.03342
Summer kph
winter kph
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Apaendnx G
page 6 of 14
Settlement Rate Summary for General Service Rates
E32 as D
Bundled Rates
E20 House d Warship
Bundled noes
0405
0.13791 x.1so
1.020
4.9470405
0.12443
zao Nonmetered
Bundled ones
Summer
BSC S/day
kp h
wi nter
BSC $/4W
kp h
2.020
3.800
2.400
0.15458
0.07519
Unbundled Rllti
6.900
4300
0. 10549
0.09951007972
2.020
3 . w0
2.4m
0.13626
0.06748 s o
MW
098631
008051
0.06624
0 . ® 7 9
00M749
0.00276
BSC S/W
Self oomained meter
Dnstrumnt rated meter
Primary meter
Summer
kW Secondary
kW Primary
kph secondary
kwh prrmary
M i n e r
kW Seeondaw
kW Pumary
kph secondary
kwh p n m i y
2020
3.101
Summer
asc 5/day
kW onpea k
kW excess
On p e a k kp h
Offp e a k kp h
vwmef
esc S/day
kW onpeak
kW excess
On p e a k kp h
Offp e a k kp h
Minimum
8SC(Davs)
KW
unnwul¢a Rates 0.375
0.030
Generation Summer
kp h
Generation . WlMer
kp h
Transmission
m m
Systems BendlB
esc $/day
Customer accounts
Bi!llng
0.08081
0.06181
0.01398
0.00800
6.900
4.300
0011390
0.03451
0.09558
0.02680
0.930
24oo
0.03792
2.870
0.00276
0.504
0.030
0.009
0001380
0.00800
6.500
4300
0.00794
0100276
1.477
Generation
kph summer . on
kph summer . off
kph winter . on
kp h wa t e r o f f
Ddivevy RW . on
Delivery kW . excess
Delivery kph
Transmission . kW . on
Systems Benefits . kph
BSC $/dW
Customer accounts
Sllling
Meter reading
Metering . eeK compared
Metering . nsuument rated
Metering . prrmarv
Metering . Transmission
0.504
0.030
0.009
0.617
1.477
4.404
Unhandled RIMS
Generation
Summer kph
Wa l e r kp h
Dellvevy Summer
kph secondary
kwh pnm ary
kW secondary
kW prl m In
Del i very Wl mer
kph secondary
kwlr primary
kW secondaw
kW primary
Transmission . KM
Systems Beneils . um
esc S/dav
Customer accounts
Billing
Meter reading
Metering . self contained
Metering . instrument razed
Meuenng primary
0.030
0.009
0.617
1 .477
4.404
Billing
Meter leading
Metering . self contained
Metering instrument rated
Metering primary
0.0024kph Schools discount
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appervdlx G
Page 7 d 14
Settlement Rate Summary for General Service Rates
E32 is E32 s
Bundled names
Solar billing determinants
E32 is
Bundled ReesBuiidkti Rt!!!
1.160
2020
4.947
1.160
2.020
4.947
BSC S/4w
Self untamed meter
Instrument rated meter
Primary met!!
u s e
2.020
4.947
Demand
11.360
s.soa
10.627
5875
0.13514
0.10762
0.13195
0.10414
0.13514
D007612
0.13195
0007264
BSC S/¢=v
Self contained meter
mszrumem rated meter
Prow meter
5 u mm1
kph secondary tier 1
kph secondary tnef 2
kph primary tier l
kph primary tier 2
esc s/av
Self contained meter
Inslrurneht rated meter
Primary meter
summer
kph secondary her 1
kph secondary her 2
kph primary tier 1
kph pnrnary tier 2
0.10828
0.06535
kW her] secondary
kW her Z secondary
kW Mr 1 primary
kW her 2 . primary
Summer
kph Se<ondary her 1
kph secondary tier 2
o. I 1797
0.09015
o. 11476
0.08696
0.11797
0.05864
0.11476
0.05545
W1 ntev
kph secondary (Kr 1
kph secondary her 2
kph primary tier 1
kph prmafv tier 2
wlmev
kph secondaw Ne: 1
kph secondary Uh: 2
kph primary tier 1
kph primary her 2 0.09126
0.04836
Winer
kph secondary lier I
kph secondary her 2
0.08390
0.08390
Unbundled names
Generlkion Summer
kph lier 1
kph tier 2
0.08390
0.05240
Unbundled RIIM
Genernlon Summer
kph her 1
kph Der 2 0.09658
0.05365
0.07956
0.03666
0.06580
0.06680
Generation . Wlntef
kph Ner 1
kph Der 2
0.06680
0.03529
Genefatlon . Warner
kph lief 1
kph tier 2
0.04054
0.01302
0.03735
0.00954
0.04054
0.01302
0.03735
0.00954
Ddlvery . Smnmev
kph tier 1 . secondary
kph her 2 secondary
kph tier I pnmarv
kph her 2 . primary
a.49o
3.738
7.757
3.005
onossn
2.870
0.00276
0.04047
0.01255
0.03726
0.00946
0.04047
0.01265
0.03726
0.00946
0.00794
0.00276
Delivery Wint¢v
kph l 1er 1 secondary
kph tier 2 secondary
kph her 1 . pnrnary
kph tier Z primary
0.504
0.030
0.009
0.617
1.477
4.404
unhumlea Rats
Generation . summer
kph 8¢l 1
kph [IH 7
Generation . Wlntef
kph Uer 1
kph Ber 2
oeltveq
kW Ner 1 . secondary
kW her 2 secondary
kW Uer 1 . primary
kW tIer 2 . primary
kph
Tmsrnksbn . kW
Systems eenerns noh
eSC s/dw
Customer accounts
Being
Meter reading
Metering . self contained
Metering . instrument rated
Meuertng . primary
0.0024kph Schnook discount
0.00794
0.00276
o.soa
0.030
0.009
0.617
1.477
4.404
Ddbvery . sunmev
kph her 1 . secondary
kph her 2 secondary
kph tier 1 . primary
kph tier 2 . primary
Delivery . Writer
kph tier 1 . secondary
kph tier 2 . secondary
kph tier 1 . primary
kph tier 2 . prmary
Transnlsslon kph
systems Benefits kph
esc 5/day
Customer accounts
Billing
Meter reading
Memenng self contained
Metering . instrument rated
Metering . primary
0.s04
0.030
0.009
0.617
1.477
4 404
Transmission . lwvh
Systems Benefits . ugh
esc 5/llay
Customer accounts
Bllling
Meter reading
Metering self contained
Metering . Instrument rated
Metering . perlman
76295
DECISION no.
DOCKET no. E-0I345A-16-0036 ET AL.Appendix G
page 8 of 14
Settlement Rate Summary for General Service Rates
E32 L E 34
Bundled R/I5Bundled R816
E32 M
Bundled Rees
4.262
s.122
B.049
39.897
3.060
3.920
6347
38.695
BSC S/day
self combined inner
Instmmnt rated Meter
Primary inter
Transmission emf
1.160
2.02o
4.947
36.795
BSC s/d=v
Self contained meter
Instrument rated meter
Primary meter
Transmission mol
DemandDemand
22.009
20.675
14.088
15.051
0.03972
BSC s/av
Self contained mNef
Instrument rated meter
Primary meter
Transmission meter
demand
Secondary
Primary
Iransmissmn
Milihry
k p h
25.372
17.605
23.049
16411
17.624
11.753
12.124
5.935
11.226
6.197
9.056
3.B69
0.055400.10532
0.06475 0.03696
10.4640.03712
kW her I secondary
kW her 2 . secondary
kW tier l . primary
kW tier 2 primary
kW tier l . transmission
kW tier 2 transmission
Summer
k ph
wimev
k ph
0008921
0.04863
kW tier 1 secondary
kW her 2 . secondary
kW tier 1 . pnmarv
kW her 2 . primary
kW tier 1 . transmission
kW tar 2 . transrmssaon
summer
kph secondary tier 1
kph secondaw (M 2
wmmev
kph secondary (Kr 1
kph secondary tier 2
0.05264
a.309
6.975
0.388
1.351
3.236
0000276
0009101
0.05044
0.07490
0.03432
3606
0.030
0.009
0617
1.477
4.404
0.03436
5.49600
136
17.00600
9.23900
14.68300
8.04500
9.25800
3.38700
96.252
unuunalea mazes
Genefnlon
k ph
kW
Delivery kW
Secondary
Primary
Transm1ssion
Military
Transmlssbn . kw
Systems Benefits . lrwh
esc $/dly
Customer accounts
Billing
Memoreading
Melerung . self contained
Metering . instrument rated
Metering . primary
Memling Transmission
287o
0.00276
9.25400
4.06500
8.35600
3.32700
6.18500
0.99900
0.01155
2.s70
0.00276
2.404
0.030
onus
0.617
U r /
4Aoa
36.252
unmnaled Rates
Generation Summer
k p h
Generation . Wlmer
k ph
Ge ne ration M
oelwefy
kw \her 1 . secondary
kW tier 2 secondary
IW tier] . primary
oWNer 2 . primary
kW tier I . transmission
kW tier 1 . !ransmiss4on
k p h
Tmsfnlssbn kW
Systems aendlcs . www
s e c Sla w
Customer accounts
Billing
Meter reading
Metering . self contained
Metering tnstmment rand
Metering primary
Metering Transmission
0.0024
00024
kph aqgrqalion dlsnaunl
kph S¢2hool$ discount
0.504
o.o3o
o.oo9
0.617
1.477
4.404
36.252
unmnal¢a Rates
Genefnion Summer
kph Kier 1
kph her 2
Generation . Wlmer
kph tier 1
kph tier 2
Ddlvery
kW tier 1 secondary
kW tier 2 . secondary
kW lier 1 primary
kW tier 2 . primary
kW tier 1 transmission
kW tier 2 transmission
k p h
Transmission . kW
systems Bandits . kph
sec $/day
Customer l€Guunl5
Billing
Meter reading
Metering Se!! contained
Metering . instrument rated
Metering . primary
Metering . Transmission
0.0624kph Schools discount
n
i
i
l
1
I 76295DECISION no.i
i
DOCKET no. E-01345A-16-0036 ET AL.Appendix G
page 9 of 14
Settlement Rate Summary for General Service Rates l
l
l
E121 E221 a T
Bundled axesBundled ans
e a s
au»4na Rates
1.160
2.020
4.947
1.160
2.020
4.947
BSC S/day
Set! contained meter
Instrument rated meter
Primary meter
Derrnnd
4.262
5.122
s.o49
39.897
BSC $/diV
Sell contained inner
Inslmment rated meter
Prinnvy meter
Transmission meter
4.754Demand 6.617
4.410
0.10640
0.07336
BSC 5/d*Y
Se" contained meter
Instrument rated meter
Primary meter
De m llli
kW secondary
k p h
Tsar 1
Tier 2 0.08967
0.04808
kW secondary onpeak
kW secondary offpeak
k p h
cmpeak
offpeak
unmmlm Rules
0.07675
0.05115
unmnanea names
Generation
kph Tsar 1
kph . Tier 2
0.08517
0.04358
2.20714
19.229
2.975
17.947
2.947
11323
2.1aa
13.103
2.351
0.04483
0.03550
Secondary on peak
O" peak
Pru raw on peak
off peak
Transmnssson on peak
oil peak
Militarv on peak
al! peak
kph on peak
kph off peak
0.99600
Unbundled maxes
Generation 0.88800
0.02689
0.00945
kW
Ddlvery
kW Secondary
kph Secondary Tier 1
kph Secondary Tler 2
1.54000
0.00174
2.870
0.00276
0.04207
0.03174
7.49800
2.12600 2.870
0.00276 0.504
0.030
0.009
0.617
1.417
4404
Generatlon
kph onpeak
ugh . offpeak
kW onpeak
kW oHpeak
DdlV¢\V
kW Secondary On and O11 peak
k p h
Tnnsmlssbn kw
Systems Bentflis . kph
e sc s/dw
Customer amounts
Billing
Meter reading
Metering . self contained
Metering Mslvumen! rated
MQ@ying primary
0.504
0.030
0.009
0.617
1.477
4.404
Trausmksbn ow
symms aeneflts km
e sc s/dw
Customer accounts
Billing
Meter reading
Memenng self untamed
Metering . lnslrumnx rated
Mekermg primary
kph on peak
kph off peak
kW on peak
kW off peak
Ddlvevy kW
Secondary on peak
dl peak
primary on peak
off peak
Transmission on peak
off peak
Mlllury on peak
off peak
Transfusion . kW
8.49500
0.a4900
7.21300
0.72100
0.58900
0.05700
2.36900
0.23500
3.236
0.00276
¢
3.6o6
0.030
0.009
0.617
1.477
4404
36.252
Systems Bendlts . kph
esc S/d=v
Customer accounts
Billing
Meter reading
Metering . Se!! contained
Metering instrument rated
Metering primary
Metering . Transmission
l
l1l
i
il
l
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix G
Page 10 d 14
Settlement Rate Summary for General Service Rates
E32 Tou M
Bundled names
saz TOU s
Bundled Rates
E32 TOU is
suna\¢¢ Rates
1.160
2.o2o
4.947
1.150
2.020
4.947
1.160
2.020
4.947
36.795
BSC S/day
Set! confined meter
lnsxmment rated meter
Primary meter
Transmission meter
esc S/day
Self contained meter
Instrument rated meter
Primary meter
Demand
BSC S/day
Self wnumed meter
Inslrumnt razed meter
Primary meter
Summer
remand19.977
10.225
7.879
2.715
19.904
10.081
6.657
2.s4s
0.13800
0.10321
0.13600
0.09700
4.546
2.599
3.951
1.565
kW tier 1 secondary . on
kW tier 2 . secondary . on
kW tier 1 . secondary . oN
kW her 2 . secondary . off
kW her 1 . primary on
kW Mr 2 . primary on
kW tier 1 primary off
kW tier 2 primary off
kph . secondary on
kph . secondary off
kph . primary . on
kph . primary of!
kW . secondary . on
kw . secondary off
kW . palmary an
kW . prinury . off
SummerWinter
0.07161
0054 a6
kph . on
kph . Off
W ine r
18.190
11.744
6.742
3327
17.546
11.647
5.934
3.216
16.394
11.250
5.022
3.065
kWtnerl secondary on
kW tier z . secondary . on
kW Net 1 secondary . off
kW lier 2 . secondary . off
kw!\er 1 primary on
kwtier 2 . primary on
kW lier 1 . primary . off
kW tier z . primary . off
kW\ier 1 . tnnsmlsséoh . on
kWtier 2 . transmission on
kW tiers transmission of
kW tier 2 . transmission off0.05601
0.04111
k p h o n
kph . Off
o .o m 0
0.05952
Summer
irWin on
k ph o ffUnb\m4led ones
e lm e r
o.1oaoo
0.08021
0.10600
0.07400
4.546
2.599
3.951
1.565
kph secondary on
kph . secondary . off
kph . primary . on
kph primary off
kW suzondavy on
kW . secondary . of
kW . primary an
kW . pdnnry off
0.057B3
0.04566
0.06885
U.05160
k p h o n
k ph o ffUnbundled Rates
0.05325
0.03845
0.05756
0.a4s3s
0.08100
0.06700
2.95100
1.51500 4.83700
1.84000
0.04369
0.03152
0.05100
0.0a400
2.951
1.515 4.91300
1.87000
•
12.27000
2.51800
6.03900
o.a1so0
11.29700
2.37400
4.81700
0070800
2.B70
0.00275
0005700
0.03621
oossoo
0.03000
1.595
1.084
1.000
0.050
0.00794
0.00276
0.504
0.030
0.009
0.617
1.477
4.404
Generitbon Mm
kph . on
k ph o ff
Genernlan . Mmes
kph . on
kph . off
Generation . kw
kW . on
kW . off
Delivery
kW lier 1 secondary . on
kW (ser 2 secondary . on
kW tier 1 secondary off
kW tier 2 secondary . off
kW \her 1 primary on
kW tier 2 primary on
kW tier 1 primary off
kW tier 2 . primary . off
Transmission kw
Synerns Benefits kph
e sc S/dw
Customer accounts
Billing
Meter reading
rearing . self contains!
Menenng lnslrument rated
Menerlng primary
0.0024kph Schools discount
1 o.4o7oo
as6xoo
4.872w
1.45700
9976300
3.86400
4.06400
1.34600
s.s1100
3.45700
3.15200
1.19600
0.01138
2870
0.00276
0.504
0.030
0.009
0.617
1477
4.404
Genemion . sum
kph . on
k ph o ff
kW . on
kW off
Genevltion Wirnef
kph . on
kph . off
kW . on
kW off
o d w v
kph . secondary . on
kph . secondary . oH
kph . pdmavy on
kph primary . oW
kW secondary on
kW . secondary . off
kW . primary . oh
kW . primary . off
Travulnlssion . um
systems Bene6ts . kph
eSC s/dw
CllsfGfl\€l xcounls
Billing
Meter reading
Metering . set! contained
Metering instrument rated
Memernng primary
0.0924kph Schools discount
0.504
0.030
0.009
0.617
1.477
4A04
36.252
Unburldled RIMS
Generation surnmef
kph . on
k ph O ff
Genentlon . wsmef
k p h o n
k p h o N
G e n e r a . m
kW on
kW . off
Defwevv
kW tier 1 secondary on
kw tier 2 . secondary . on
kW tier I . secondary off
kW tier 2 . secondary off
kW tier 1 . primary on
kW tier 2 . primary . on
kW tier 1 primary off
kW tier 2 . primary off
kW tier 1 transmission . on
kW tier 2 transmission . on
kW tier 1 . transmission off
kW tier 2 transmission . dl
k ph
Transmission . kW
Systems Benefits. kph
esc S/dlv
Customer accounts
Billing
Mewed reading
Metering . self contained
Metering instrument rated
Metering palmary
Meme mg . transmission
0.0024kph Schools dlscnunt
76295
DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.Appendix G
Page 11 d 14
Settlement Rate Summary for General Service Rates
E32 TOU L Gs$dwols L
Bundled mares
Gsschools M
sunama RatesBundled axes
3060
3.920
6.a17
3s.s9s
BSC $/day
Self contained meter
Instrument rated meter
Primary meter
Transmission Meier
1.160
2.020
4947
36.795
esc S/d=v
Se" contained aler
lnsrrument rated meter
Primarv meter
Transmussron meer
3.060
3.910
s.aa7
38.695
BSC S/day
Sell contained meter
Instrument rated meter
Primary meter
Transmission meter
DtmindDemandDemand 11.564
6.561
10.804
s9os
8.656
3761
11.816
s.ao2
11.044
6.028
8.853
3.839IIi
0.16704
0.12360
0.06809
0.18571
0.13746
0.06920
17.508
11.795
5.396
3.370
16.936
11.710
5.679
3.272
15916
10.478
4.s71
3.137
kW her 1 . secondary on
kW her 2 secondary . on
kWtier 1 . secondary . off
kW her 2 . secondary off
kW Uer I . pnmiry . on
kW her 2 . primary . on
kW her I primary oil
kW her 2 primary . off
kW Uer 1 . transmission . on
kW her 2 . transmission . on
kW Ues 1 . transmrsskm . dl
kW her 2 transmission off
Summer
0.14419
0.10667
0.05163
0.16032
0.11865
0.05952
kW her 1 secondary
kW !her Z secondary
kW her 1 . primary
kW tier 2 primary
kwlrer 1 . lransmissron
kW tier 2 . transmission
Summer Peak
kph . on
kph shoulder
kph . off
Sum Shwldev
kph . on
kph . shauld¢r
kph . of!0.07018
0.05730
kph on
kph . off
M m e 0.11163
0.08257
0.04541
kW tier 1 . secondary
kW tier 2 secondary
kW tier) primary
kW tier 2 . primary
kW Kiev! . transmission
kW (her 2 . (ransmnssion
Summer Pell:
kph on
kph shautder
kph . off
Summer Shoulder
kph on
kph . shoulder
kph . off
Wlrvlef
kph on
kph . shoulder
kph . Off
0.12415
0.09186
0.04617
Wlmer
kph on
kph . shoulder
kph . off
0.05552
0.04264
kph . on
kph . O"
0.05534
onazas
0.14913
0.10569
0.05018
0.16003
011178
0.04352
0.04068
0.02780
9
012628
0.08876
0.03372
0.12464
0.09297
003384 l5.98000
2.27500
0.09372
0.06466
0.02750
0.09847
0.06618
0.02049
8694
3.791
7.924
3.035
5.796
0.891
0101515
2.870
0.00276
8946
3.932
8.174
3.158
5.9B3
0.969
0.02292
2.870
0.00276
8.658
2.945
4.121
1.095
8.086
2.860
3404
0.997
7.066
1.628
2.596
0.861
0.01208
2.870
0000276
2.404
0.030
0.009
0.617
1477
0.soa
0.030
0.009
0.Gl7
1.477
4.404
36.252
4.404
36.252
unmndlm R815
Generation . Summa peak
kph . on
kph shouhier
kph . off
Gammon Summer Shoulder
kph on
kph . shoulder
kph off
Generation . Winer
kph on
kph . shoulder
kph . off
Generdon kW
kW
Delivery
kw tier 1 secondary
kW tier 2 . secondary
kW tier 1 . primary
kW tier 2 primary
kW her 1 transmission
kW lier 2 . transmission
kph
Transmission . kW
System Benefits . kph
BSC S/dlv
Customer accounts
Billing
Meter reading
Meierlng self contained
Metering instrument rated
Metering primary
Metering . transmission
Unbundled Rates
Generlilan . Summer Peak
kph on
kph . shauider
kph . off
Generalan . Summer Shoulder
kph on
kph . shoulder
kph . off
Generation . wiener
kph on
kph shoulder
kph . oW
Generailon kW
kW
Delivery
kW her 1 . secondary
kW tier 2 secondary
kW tier 1 . primary
kW thee 2 . primary
kW tier 1 iransmissnon
kW tier 2 . transmission
kph
Transmission kW
Systems Ben¢H\s . kph
sec 5/dly
Customer accounts
Billing
Meter reading
Metering . self contained
Metering . instrument rated
Metering primary
Metering . transmission
2.404
0.030
0009
0.617
1477
4.404
36.252
Unbunrlled R8128
Generation . Summer
kph . on
kph off
Genernlon . Wlmer
kph on
kph off
Generation kW
kW on
kw off
Delivery
kW tier l secondary . on
kW tier Z secondary on
kW Ber 1 secondary . off
kW tier 2 . secondary . of
kW her 1 . primary . on
kW lier 2 pnrnarv . on
kW her 1 primary . off
kW her 2 primary art
kW her 1 Kransmlssdon . on
kW her 2 rransmlsskm . on
kW tier 1 . transmission off
kW tier 2 . transmission of(
kph
Transmksbn kw
Systems aenems . kph
esc s/dw
Customer accounts
Bllhng
Meer reading
Meters self compared
Metering . instrument rated
Memnng . primary
Mending . transmission
000240.0024 kph Schools discountkph schools dlsnuunl
41.0024
0.0024
kph aggregation dis faun!
kph Schools disc run!
76295
DECISION no.
DOCKET NO. E-01345A-16_0036 ET AL.Appandux G
Page 12 of 14
Settlement Rate Summary for General Service Rates
E67
Bundled R885
SL Cmtran
Bundled Rates
E59
Bundled Rates
0.05594kphlamp
kph
17.73
0.09142
Delivery Point
lzWh
3.00
096563
s
DECISION NO.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix G
Page 13d 14
Settlement Rate Summary for General Service Rates
sas M (sudev)
Bundled ones
E36 XL
Bundled sans
XHLF Rate
Bundle Rates
7436s.122
aoa9
39.897
3.764
4.602
13.037
BSC S/day
E32XS option
Serf contained meter
Instrument need meter
Primary meter
5.584
5388
1.743
0.00061
Basic Service Charge
re Capacity Charge:
Secondary
Primary
Transmission
Hoods Proxy
Pow er Supply kph
17950
16.609
12.917
0.037610
asc 5/dgy
lrmrumem rated mn
Primary meter
Transmission meter
uemana (KW)
Secondary
Primary
Transmusslon
k p h
3.764
4.602
13.037
44.885
E 32L option
Serf contained meter
Instrumentrated meter
Primal meter
Transmission meter
9.27400
0.03485
9
3.14700
312500
B.63300
544000
4.09900
0.40700
3236
0.00276 0.61700
1.47700
4.40400
000900
0.03000
0.13514
0.11797
unwmlm mares
BSC (do)
E32X$ option
Customer iccounls:
Self con ned relief
Instrument rared meter
Primary meter
Metering:
Se" contained inter
Instrument med meter
Primary meter
Meter Reedit
Billln3
kph rare . summer
kph rate . w inter
3.606
0.030
0.009
1 .417
4.404
36.252
unuuralea Rates
Generitban . kph
kW
kph
Ddivevy . ow (Ww w )
Secondary
Primary
Transmission
Transmission . kW
Sysnms aenenzs . kg
esc NIV)
Customer accounts
Billing
Meter reading
Metering . nnsNumen
Metering . primary
Metering . Transmissi
3.14700
3.12500
8863300
¢
0061700
1 .47700
4 .4o4oo
36.25200
0.00900
0.03000
E 32L option
Customer xaoums:
Se!! conlahveé meter
Instrument rated meter
Primary meter
Metering;
Sell contained meter
lnsxrumem rated meter
Primary meter
Yransrnisnon meter
Meter Resdlrq
Billing
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
ll
Appendix G
Page 14 d 14
Settlement Rate Summary for General Service Rates
Rider PPRE56
Badbup Power Charges
0.647
0.131
Extra urge
Large . summer
Large timer
Medium summer
Medium vnnler
0.05141
0.06080
0.04480
0.06623
0.05220
Rate Schedule E34
Rare Schedule E32
txcus owe' charge
secondary
primary
lransmissron
054802
0.52019
0.38187
¢
76295
DECISION no.
I
DOCKET no. E-01345A-16-0036 ET AL.
Appendix H
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix H
Page 1 of 21
II
PLAN OF ADMINISTRATION
RESOURCE COMPARISON PROXYQ ops
Resource Comparison Proxy
Plan of Administration
Table of Contents
1. General 1
2. Customer 1
3. Resource Comparison Proxy Purchase 1
4 Definitions
5.System
6. Calculation ofResource Comparison Proxy Purchase Rate
7. Procedural
8. Confidential
9
1. General Description
This document describes the plan for administering the Resource Comparison Proxy purchase
rate (RCP) approved for Arizona Public Service Company (APS or Company) in Arizona
Corporation Commission (Commission) Decision No. 75859 (January 3, 2017), as modified by
Decision No. 75932 (January 13, 2017) and implemented in Decision No. xxxxx (xxx x, 2017). The
RCP is the price at which the Company purchases Exported Energy from residential Customers
with qualified on-site solar distributed generation facilities. This price is provided in Rate Rider
RCP.
¢The RCP is a proxy for the avoided cost of providing electrical service that results when a
distributed generator exports power to the grid. The RCP is calculated using: (i) a rolling
historical five-year weighted average cost of grid-scade solar photovoltaic facilities that the
Company owns or has rights to through a solar photovoltaic Purchased Power Agreement
(PPA); and (ii) applicable Avoided Transmission Capacity Cost, Avoided Distribution Capacity
Cost, and Line Losses.
2. Customer Billing
The Company will provide the Customer a monthly bill credit for the Export Energy based on
the applicable RCP.
Any bill credit in excess of the Customer's otherwise applicable monthly bill will be credited on
the next monthly bill, or subsequent bills if necessary. After the Customer's December bill, a
Customer may request a check for any outstanding credits from the prior year; if the outstanding
credits exceed $25 a check will automatically be issued; otherwise the bill credits will carry
forward to the following year.
3.Resource Comparison Proxy Purchase Rate
The RCP will be determined as follows:
Page 1 of 6Effective Date xx/xx/ xxx
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix H
Page 2 of 21
PLAN OF ADMINISTRATION
RESOURCE COMPARISON PROXYGaps
•An RCP will be determined for each tranche of new DG Customers, effective ]fly 1 each
year without proration. The RCP may not be reduced by more than 10% each year.
Each Customer's bill credit will initially be based on the RCP in effect at the time they
submit an interconnection application for their system before ]fly I provided that they
subsequently complete the installation and obtain approval by the appropriate Authority
Having Jurisdiction within 180 days of their interconnection application unless, through
no fault of the Customer or the Customer's installer, the interconnection is delayed by a
third party or APS. In that circumstance, the Customer will have 270 days to complete
their interconnection.
•Each Customer's initial RCP will be applicable for 10 years from the time of their
interconnection.
•After each Customer's initial 10-year period the bill credit will be based on the purchase
rate in effect at that time, and will change from year to year.
4. Definitions
Avoided Cost.In the context of this Plan of Administration, the additional cost APS would incur
to acquire electric energy to serve its customers if electricity was not available from on-site
distributed generation sources.
Avoided Distribution Capacitv Cost. In the context of this Plan of Administration, the net cost of
distribution grid equipment and facilities necessary to distribute electricity to APS customers if
electricity from on-site distributed generation sources was not available.
Avoided Transmission Capacitv Cost.In the context of this Plan of Administration, the
additional cost of transmission grid equipment and facilities necessary to transmit electricity to
APS customers if electricity from on-site distributed generation sources was not available.
BaseYear.For the initial RCP calculation (effective ]fly 1, 2017), the Company's most recent test
year, calendar year ending December 31, 2015. Each subsequent annual calculation will use the
immediately preceding calendar year as the Base Year. As an example, the RCP that will become
effective with the first billing cycle of ]fly 2018 will be calculated with the calendar year ending
December 31, 2017 as the Base Year.
Customer(sl.For purposes of this Plan of Administration, an APS Customer taking service under
a Residential rate schedule.
Export(edl Energy.Energy generated by an on-site interconnected solar photovoltaic distributed
generation source that is greater than the Customer's electric load at any single point in time and
flows into the Company's distribution grid.
Page 2 of 6Effective Date XX/XX/ XXX
76295IDECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix H
Page 3 of 21
PLAN OF ADMINISTRATION
RESOURCE COMPARISON PROXYGaps
Levelized Cost.For purposes of this Plan of Administration, the net present value of the overall
cost of building and operating a grid-scale solar photovoltaic generating plant, or the net present
value of the overall cost to APS of an executed solar photovoltaic PPA, over the economic life of
the asset and converted to equal annual amounts.
Line Losses.Electric energy lost as it is transmitted from a supply source (i.e., an electric
generation plant) to a delivery point (i.e., the Customer's residence or place of business).
Partial Requirements Service. Electric service provided to a Customer that has an on-site
distributed generation system interconnected to the Company's distribution grid that is
configured so that the energy generated first supplies its own electric requirements, and any
excess generation (over and above its own requirements at any point in time) is then exported to
the Company. The Company supplies the Customer's supplemental electric requirements (those
not met by their own generation facilities).
Production Tax Credit. The income tax credit available in the State of Arizona for taxpayers that
own a qualified renewable energy generator as defined in A.R.S. §43-1083.02 and §43-1164.03 that
produces energy after December 31, 2010 and before ]january 1, 2021. The amount of Production
Tax Credit available is limited by facility and by calendar year.
Revenue Requirement For purposes of this Plan of Administration, the amount of revenue
calculated to be recovered in rates for the APS-owned grid-scale solar facilities included in the
RCP calculation. Revenue Requirement expenses include depreciation expense, income taxes,
property taxes, deferred taxes and tax credits where appropriate, associated operation and
maintenance expense, and an approved debt and equity return..
5. System Eligibility
A distributed generation facility must meet all of the following qualifications to be eligible for
the RCP:
Electricity must be generated using solar photovoltaic panels;
The facility must be interconnected to the Company's distribution grid;
The generator must be on-site, installed behind the billing meter, and must serve the
Customer's load;
•The facility's nameplate capacity cannot be larger than the following electrical service
limits:
a. For 200 Amp service, a maximum of 15 kW-dc,
b. For 400 Amp service, a maximum of 30 kW-dc,
c.For 600 Amp service, a maximum of 45 kW-dc,
d. For 800 Amp service and above, a maximum of 60 kw-dc; and
Page3 of 6Effective Date XX/XX/ XXX
76295
DECISIONno.
DOCKET no. E-01345A-16-0036 ET AL.Appendix H
Page 4 of 21
PLAN OF ADMINISTRATION
RESOURCE COMPARISON PROXYQ ops
For systems over 10 kW-dc, the facility's nameplate capacity cannot be larger than 150% of
the customer's maximum one-hour peak demand measured in AC over the prior twelve
(12) months. (For example, if the customer's peak is 8kW-ac, the maximum system size
that could be installed would be 12kW-dc).
SPECIAL CASES
Switching from a grandfathered legacy solar rate.A Customer may switch from a grandfathered
solar Legacy rate and net metering rider to a new retail rate and the RCP rider. However, they
will lose their grandfathering status and may not subsequently switch back to the grandfathered
rate or net metering program. In addition, the Customer will not be eligible for an initial 10-year
lock in the purchase rate; rather their bill credits will be based on the annual RCP rate as it
changes from year to year.
Increasing Capadtv.If a Customer modifies their generation system to include a material increase
in capacity they will no longer be eligible for the initial RCP purchase rate they locked in for ten
years; rather their bill credits will be based on the current RCP rate locked in for a period of ten
years minus the number of years they received service under a prior RCP rate. For purposes of
this Plan of Administration, a material increase in capacity means increasing the capacity by 10%
or l kw, whichever is greater. Over the term of the Customer's ten year RCP lock, they may only
increase their system's capacity by a total of 10% or 1 kw, whichever is greater.
Transferring Service. If a Customer moves to a site that is currently being served under rate rider
RCP they will continue service under the rider with the same rate tranche. If a Customer moves
their solar system to another site they will no longer be eligible for the initial 10-year lock in the
RCP purchase rate; rather their bill credits will be based on the annual RCP rate as it changes
from year to year.
6.Calculation of Resource Comparison Proxy Purchase Rate
The RCP is calculated by developing a historical rolling five-year weighted average cost per kph
for all grid-scale renewable solar photovoltaic generating systems used by APS to serve its
customers, both APS-owned facilities and facilities from which APS purchases power through
an executed PPA. The calculation methodology is as follows:
The first RCP effective on ]fly 1, 2017 is $0.12900/ kph, using 2015 as the Base Year inclusive of
adjustments as provided for in Decision No. xxxxx. Subsequent RCPs derived from following the
calculations in Steps 1 through 8 below will diem be compared to the RCP in effect. If the
calculated RCP results in a reduction in the purchase rate from the previous RCP, any such
reduction will be no greater than 10% of the previous RCP.
1. Determine appropriate five-vear period.The RCP will be calculated using the 5-year period
with the Base Year as the final year of the five. Only those grid-scale solar facilities with an
in-service date within this 5-year period will be included in the annual RCP calculation.
Page 4 of 6Effective Date XX/XX/ XXX
76295DECISIONno.
DOCKET no. E-01345A-16-0036 ET AL.Appendix H
Page 5 of 21
9lPLAN OF ADMINISTRATION
RESOURCE COMPARISON PROXYQaps
If there are no grid-scale solar photovoltaic projects in any particular year of the rolling five-year
period described above, the rolling 5 year average will be calculated without a project for that
particular year. Calculating the RCP without a project for a particular year (i) is the product of
the settlement approved in Decision No. xxxx; (ii) is the product of compromise; (iii) does not
establish a precedent for how the RCP should be calculated; and (iv) will be revisited in APS's
next general rate case.
2. Develop/ update annual Revenue Requirement for each APS-owned facility.The Company
will calculate revenue requirements for each grid-scale solar photovoltaic generation facility
owned by the Company that qualifies for inclusion in the RCP calculation as determined in Step
1. The annual designed output of the facility, including degradation, will be used for this
calculation. This step provides an annual revenue requirement cost in dollars for each year of the
facility's depreciable life.
3. Incorporate applicable Production Tax Credit. All expected available annual Production Tax
Credit tax savings (in dollars) for the above APS facilities will be calculated based on expected
annual energy production and subtracted from the annual facility cost derived in Step 2 above
for each year.
4. Develop/ update annual cost of power from each PPA facility.The Company will calculate an
annual cost of purchased power for each facility from which APS purchases power under an
executed agreement that qualifies for inclusion in the RCP calculation as determined in Step 1.
The annual cost for each of these facilities will be calculated separately for the contract life of
each PPA using the contract price and the designed output, including degradation, of the
facilities, including contractual escalation factors, as appropriate.
5. Calculate individual facility Levelized Cost. The Levelized Cost for each of the facilities will
then be calculated using the data derived in Steps 2 through 4 above. The net present value
discount rate used in the Levelized Cost calculations will be calculated using the approved
after-tax weighted average cost of capital as determined in the Company's most recent rate case.
The result of this calculation step will be a Levelized Cost per MWh for each of the facilities.
6. Calculate weighted Levelized Cost for each facility.The weighted Levelized Cost is calculated
by multiplying the cost per MWh derived for each facility in Step 5 by the actual Base year
energy production in MWh for each Step 5 facility. The result of this step is an annual weighted
cost in dollars for each included facility.
7. Calculate weighted average Levelized Cost for all facilities.The annual weighted average
Levelized Cost is determined by dividing the total annual weighted costs for all included
facilities by the total Base year energy production Mwh. The result of this step is the rolling
historical five-year weighted average Levelized Cost per MWh for grid-scale solar photovoltaic
facilities on the APS system before any applicable adjustments.
8. Adjustments.An adjustment is then applied to the annual weighted average Levelized Cost
per MWh for avoided transmission capacity cost, avoided distribution capacity cost, and line
Effective Date XX/XX/ XXX Page 5 of 6
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix H
Page 6 of 21
Gaps PLAN OF ADMINISTRATION
RESOURCE COMPARISON PROXY
losses as required in Decision No. 75859. For purposes of this Plan of Administration, and subject
to future Commission proceedings, the combined adjustment for these three values is set at
$0.02/kWh as provided for in Decision No. xxxxx. This amount is negotiated, does not reflect
an actual calculation of system conditions, and establishes no precedent for any future RCP or
avoided cost calculations. While future Commission proceedings may establish methodologies
for calculation of the adjustments, no changes will be made to this value until the conclusion of
the next APS general rate case.
i
7.Procedural Timeline
The Company will provide Commission Staff and other intervening parties with its annual RCP
calculation no later than March 1 each year. Interested parties will file comments to the
Company's RCP calculation by April 1. Commission Staff will file its Report by May 15 and
request dirt Staff's Report be considered in the June Open Meeting and be approved so that the
new RCP calculation is effective on ]fly 1.
8. Confidential Data
Portions of the data used to calculate APS's annual RCP are competitively/highly confidential
and cannot be released to the public. Competitively/highly confidential information will be
made reasonably accessible to parties so that they may determine that such data supports the
RCP calculation and that the RCP calculation complies with Commission orders.
Competitively/highly confidential information includes cost and production data for facilities
from which APS purchases energy under a PPA agreement.
e
9. Schedules
Templates of the spreadsheet used to calculate the RCP are attached:
Schedule 1:
Schedule 2:
Schedule 3:
Schedule 4:
Schedule 5:
Schedule 6:
Annual Resource Comparison Proxy Calculation Summary
Solar Photovoltaic Grid-Scale Plant Data and Levelized Cost
Individual Plant Annual Cost ($/ Mwh)
Individual Plant Energy Production (Mwh)
Individual Plant Revenue Requirement/PPA Annual Cost ($000)
Individual Plant Revenue Requirement/PPA Annual Cost including Production
Tax Credits ($000)
Each of these schedules contains competitively/ highly confidential PPA data as indicated.
EffectiveDateXX/XX/ XXX Page 6 of 6
76295DECISION no.
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DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix H
Page 13 of 21
Gaps
RATE RIDER RCP
PARTIAL REQUIREMENTS SERVICE FOR
NEW ON-SITE SOLAR DISTRIBUTED GENERATION
RESOURCE COMPARISON PROXY EXPORT RATE
AVAILABILITY
This rate rider is available to partial requirements customers with qualified on-site solar
generation, served under an applicable residential rate. This rate rider may not be used in
conjunction with a grandfathered residential Legacy rate schedule or Legacy rate rider.
DESCRIPTION
A Customer with solar generation exports power to the grid from time to time when their
generation exceeds the load in their home. The Company will meter this export power on an
instantaneous basis and provide a monthly bill credit based on the purchase rate in this
schedule.
The purchase rates will be determined as follows:
a.An RCP rate will be determined for each annual tranche of new DG Customers, effective
]fly 1 each year without proration. The RCP rate may not be reduced by more than 10%
each year.
b.Each Customer's bill credit will initially be based on the RCP in effect at the time they
submit an interconnection application for their system before Idly 1 provided that they
subsequently complete the installation and obtain approval by the appropriate
Authority Having Jurisdiction within 180 days of their interconnection application
unless, through no fault of the Customer or the Customer's installer, the interconnection
is delayed by a third party or APS. In that circumstance, the Customer will have 270
days to complete their interconnection.
c. Each Customer's initial RCP rate will be applicable for 10 years from the time of their
interconnection.
d. After each Customer's initial 10 year period the bill credit will be based on the purchase
rate in effect at that time, and may change from year to year.
Further details are provided in the Resource Comparison Proxy Plan of Administration and
Arizona Corporation Commission Decisions No. 75859 and xxxxx.
A.C.C. No. xxxx
Rate Rider RCP
Original
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A.Miessner
Title: Manager Regulation and Pricing
Page 1 of 3
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix H
Page 14 of 21
Q ops
RATE RIDER RCP
PARTIAL REQUIREMENTS SERVICE FOR
NEW ON-SITE SOLAR DISTRIBUTED GENERATION
RESOURCE COMPARISON PROXY EXPORT RATE
PURCHASE RATES
The Company will provide a bill credit for the exported energy based on the following purchase
rates:
er kph$0.1290Tranche 2017 Ill 1, 2017 thou h ]ume 30, 2018
TBD er kphTranche 2018 Jul 1, 2018 thou h lune 30, 2019
Any bill credit in excess of the Customer's otherwise applicable monthly bill will be credited on
the next monthly bill, or subsequent bills if necessary. After the Customer's December bill, a
Customer may request a check for any outstanding credits from the prior year; however, if the
outstanding credits exceed $25, the Company will automatically issue a check to the Customer.
Otherwise, the bill credits will carry forward to the following year.
GENERATOR REQUIREMENTS
Distributed generators must meet all of the following qualifications:
1.Electricity must be generated using solar photovoltaic panels;
2.The generator must be interconnected to the Company's distribution grid;
3.The generator must be on-site, installed behind the billing meter, and must serve the
Customer's load,
4.The facility's nameplate capacity cannot be larger than the following electrical service
limits:
a.For 200 Amp service, a maximum of 15 kW-dc.
b. For 400 Amp service, a maximum of 30 kW-dc.
c.For 600 Amp service, a maximum of 45 kW-dc.
d. For 800 Amp service and above, a maximum of 60 kW-dc, and
5.For systems over 10 kw-dc, the face:ility's nameplate capacity cannot be larger than
150% of the customer's maximum one-hour peak demand measured in AC over the
prior twelve (12) months. (For example, if the c:ustomer's peak is 8kW-ac, the
maximum system size that could be installed would be 12kW-dc).
A.C.C.No.xxxx
Rate Rider RCP
Original
Effective:xxxx
ARlZONA PUBLIC SERVICECOMPANY
Phoenix Arizona
Filed by:Charles A. Miessncr
Title: Manager Regt lotion and Pricing
Page 2 of 3
76295DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.AppendixH
Page 15 of 21
¢ap RATE RIDER RCP
PARTIAL REQUIREMENTS SERVICE FOR
NEW ON-SITE SOLAR DISTRIBUTED GENERATION
RESOURCE COMPARISON PROXY EXPORT RATE
SPECIAL CASES
1.Switching from a grandfathered legacy solar rate.A Customer may switch from a
grandfathered solar Legacy rate and net metering rider to a new retail rate and the RCP rider.
However, they will lose dieir grandfathering status and may not subsequently switch back to
the grandfathered rate or net metering program. In addition, the Customer will not be
eligible for an initial 10-year lock in the purchase rate; rather their bill credit will be based on
the annual RCP rate as it changes from year to year.
2.Increasing Capacih/. If a Customer modifies their generation system to include a material
increase in capacity they will no longer be eligible for the initial RCP purchase rate they
locked in for ten years; rather their bill credits will be based on the current RCP rate locked in
for a period of ten years minus the number of years they received service under a prior RCP
rate. For purposes of this rate rider, a material increase in capacity means increasing the
capacity by 10% or 1 kw, whichever is greater. Over the term of the Customer's ten year RCP
lock, they may only increase their system's capacity by a total of 10% or 1 kw, whichever is
greater.
3.Transferring Service. If a Customer moves to a site dirt is currently being served under rate
rider RCP they will continue service under the rider with the same rate tranche. If a
Customer moves their solar system to another site they will no longer be eligible for the
initial 10-year lock in die RCP purchase rate; rather their bill credits will be based on the
annual RCP rate as it changes from year to year.
SERVICE DETAILS
l . All terms and charges in the Customer's retail rate schedule continue to apply.
2.The Customer must have a standard Advanced Metering Infrastructure (AMI) meter
installed to measure the production from their solar generation system as well as an AMI
meter for electrical service.
3.The Company provides service under this rider in accordance with its Interconnection
Requirements Manual. Service terms an conditions may be included in a Customer's
interconnection agreement.
4.Partial Requirements Service is electric service provided to a Customer that has an on-site
distributed generation system interconnected to the Company's distribution grid that is
configured so Mat the energy generated first supplies its own electric requirements, and any
excess generation (over and above its own requirements at any point in time) is then
exported to the Company. The Company supplies the Customer's supplemental electric
requirements (those not met by their own generation facilities).
A.C.C.No.xxxx
Rate Rider RCP
Original
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by:CharlesA.Miessner
Title: Manager Regulation and Pricing
Page 3 of 3
DECISION no.
DOCKET no. E-01345A-I6-0036 ET AL.
Appendix H
Page 16 of 21
Q ops RATE RIDER EPR-6
PARTIAL REQUIREMENTS SERVICE FOR
ON-SITE RENEWABLE DISTRIBUTED GENERATION
NET METERING
AVAILABILITY
This rate rider is available to qualifying residential and non-residential partial requirements
Customers with an on-site renewable distributed generation system. Residential Customers
with an interconnected on-site solar photovoltaic system are not eligible for this rate rider.
DESCRIPTION
This rate rider describes how the Company will bill a Customer who participates in the
Company's net metering program and exports energy through the Company's distribution grid.
Export energy occurs when the Customer's generation is greater than their electrical load in any
instant and this excess energy flows back to the Company's grid.
Under this rider, export energy (kph) will be netted against kph supplied by the Company
during the billing month, or banked and netted on a subsequent bill if necessary .
If a Customer is served under a time-of-use rate, the export energy will be netted according to
the on-peak and off-peak periods. On-peak export energy will be netted against on-peak energy
from the Company and off-peak export energy will be netted against off-peak energy, for all
unbundled components of the rate that have time-of-use charges.
PURCHASE RATES
After the December bill, any export energy that has not already been netted on a bill will be
acquired by the Company in exchange for a monetary bill credit based on the following
purchase rate:
$002895 per kph
The purchase rate is based on the Company's near-term avoided costs and is revised from time
to time.
BILLING DETAILS
1.All terms and charges in the customer's rate schedule continue to apply to electric service
provided under this rider.
2.If the Customer terminates electric service, the Company will issue a check for any
remaining export energy at the purchase price.
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager, Pricing and Regulation
Original Effective Date: July 7 2009
A.C.C.No. xxxx
Canc elling A.CC. N0.5866
Rat e Rider EPR6
Revision No.3
Effective:xxxx
Page I of 3
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix H
Page 17 of 21
Q ops RATE RIDER EPR-6
PARTIAL REQUIREMENTS SERVICE FOR
ON-SITE RENEWABLE DISTRIBUTED GENERATION
NET METERING
GENERATOR REQUIREMENTS
Distributed generators must meet all of the following qualifications:
1. The generator must be interconnected to the Company's distribution grid;
2. The generator must be on-site, installed behind the billing meter, and must serve the
Customer's load,
I
3. For qualifying residential facilities, the nameplate capacity cannot be larger than the
following electrical service limits:
a. For 200 Amp service, a maximum of 15 kW-dc.
b. For 400 Amp service, a maximum of 30 kW-dc.
c.For 600 Amp service, a maximum of 45 kW-dc.
d. For 800 Amp service and above, a maximum of 60 kW-dc; and
4.
l
For all qualifying residential and non-residential facilities over 10 kW-dc, the
facility's nameplate capacity cannot be larger than 150% of the customer's maximum
one-hour peak demand measured in AC over the prior twelve (12) months. (For
example, if the customer's peak is 8kW-ac, the maximum system size that could be
installed would be 12kW-dc).
a
SERVICE DETAILS
l . All terms and charges in the Customer's retail rate schedule continue to apply.
2.The Customer must have an Advanced Metering Infrastructure (AMI) meter, or equivalent,
installed to measure the production from their solar generation system as well as an AMI
meter for electrical service.
3.The Company provides service under this rider in accordance with its Interconnection
Requirements Manual. Service terms and conditions may be included in a customer
interconnection agreement.
4. A Net Metering Facility is an on-site distributed generation system that:
a.Provides part of the Customer's energy requirements at the site where the system is
installed;
b.Uses renewable resources, as defined by the Arizona Corporation Commission,
including a fuel cell with the chemical reaction derived from renewable resources
A.C.C. No. xxxx
Cancelling A.C.C. No.5866
Rate Rider EPR-6
RevisionNo. 3
Effective:xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix, Arizona
Filedby: Charles A. Miessner
Title: Manager PricingandRegulation
Original Effective Date: July7, 2009
Page 2of3
DECISION NO.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix H
Page 18 of 21
Q ops RATE RIDER EPR-6
PARTIAL REQUIREMENTS SERVICE FOR
ON-SITE RENEWABLE DISTRIBUTED GENERATION
NET METERING
or a combined heat and power (CHP) facility as defined by A.A.C. R14-2~2302, to
generate energy; and
c. Is interconnected to and can operate in parallel and in phase with the Company's
existing distribution system.
5.
ll
Partial Requirements Service is electric service provided to a Customer that has an on-site
distributed generation system interconnected to the Company's distribution grid that is
configured so that the energy generated first supplies its own electric requirements, and any
excess generation (over and above its own requirements at any point in time) is then
exported to the Company. The Company supplies the Customer's supplemental electric
requirements (those not met by their own generation facilities).
A.C.C.No. xxxx
CancellingA.C.C.No.5866
Rate Rider EPR-6
Revision No. 3
Effective:xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:CharlesA.Miessner
Title: Manager Pricing and Regulation
Original Effective Date: July 7 2009
Page 3of3
DECISION no.76295
DOCKET no. E-01345A_16-0036 ET AL.Appendix H
Page 19 of 21
i
l
llQ ops RATE RIDER LEGACY EPR-6
PARTIAL REQUIREMENTS SERVICE FOR
ON-SITE RENEWABLE DISTRIBUTED GENERATION
NET METERING
AVAILABILITY
This rate rider is available to Customers that qualify for the residential solar grand fathering
program. It may be used in conjunction with the residential Legacy rate schedules for
distributed generation systems.
This rate rider is frozen effective Idly 1, 2017. This means a residential Customer that is already
taking service under this rate rider by that date may continue service under the terms of the
grandfathering program. Other residential Customers must meet the qualification
requirements of the grandfathering program to take service under this schedule.
t solar
e. \\.1=ateOFflns~¥ate rider.
te of-theirghoiCe
\
A residential Customer may remain on this rate rider for up to 20 years from the da
generator was interconnected to the Company's distribution grid. After that time, th
residential Customer will not be eligible for a grandfathered solar Legacy
Instead, the residential Customer will be served under an applicable it
and Rate Rider RCP, or a subsequent replacement rider.\
DESCRIPTION
a
This rate rider describes how the Company wt
Export energy occurs v/fie the C st
s ex pts en f l
C sggnner o participates in the
quit meértS storer has on-site generation that
r Les the Company for additional electrical
e s generation is greater than their electrical
'/ i n to the Company's grid.
energy
during :MK ontlOr"bahked and netted on a subsequent bill if necessary.
on-peak export energy will be netted against on~peak
for all unbundled components of the rate that have
Company's net metering program. A
serves some of their electrical red
services.
load in any instant and
Under this rider,9 , will be netted against kph supplied by the Company
8
If a Customer is served under a time-of-use rate, the export energy will be netted according to
the on-Reak nd off-peak periods, i.e.
energy fre the Company and viceversa,
tiIT\€-of-l1s€ charges.
PURCHASE RATES
After the December billing cycle, any export energy that has not already been netted on a bill will
be acquired by the Company in exchange for a monetary bill credit based on the following
purchase rate:
$0.02895 per kph
The purchase rate is based on the Compally's near-term avoided costs and is revised from time
to time.
A.C.C. No. xxxx
Rate Rider EPR6 Legacy Frozen
Original
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Pricing and Regulation
Page l of 3
76295DECISION no.
DOCKET no. E-01345A-16_0036 ET AL.
Appendix H
Page 20 of 21
Q ops RATE RIDER LEGACY EPR-6
PARTIAL REQUIREMENTS SERVICE FOR
ON-SITE RENEWABLE DISTRIBUTED GENERATION
NET METERING
BILLING DETAILS
1.All terms and charges in the Customer's rate schedule, other than those specifically included
here, continue to apply to electric service provided under this rider.
2.If the Customer terminates electric service, the Company will issue a check for the
remaining export energy at the purchase price.
RESIDENTIAL GRANDFATHERING PROGRAM
The terms and conditions for the solar grandfathering program for residential Custrriers are as
follows:
ae
a
o
de
\
's us grid
Uh e under the
1. Existing solar customers with systems interconnected t th C
prior to ]fly 1, 2017 and otherwise qualify for this rate rt
grandfathering program.
onte co<
Aug-mity
34?sto
irinterco
2. Customers who (i) submit a complete appT for in to the Company by
]fly 1, 2017; (ii) include in their intercom o a l n fully executed sales or lease
contract for their rooftop solar sys ;(iii in Ir rooftop solar system and obtain
approval by the appropria in jurisdiction within 180 days of their
interconnection application,use u icy for this rate rider may take service under
the grandfather r our connection is delayed by a third party or APS
through no fa the Customer's installer, the Customer will have 270
days to c p te section.
\3.
4.e term of the grandfathering period, a Customer may not increase the capacity of
e gtg.nm;al£tl1ermg,period will be 20 years from the customer's initial interconnection date
a}~.dapplies to the site where the system is located.
Oven
their grandfathered solar generation unit by more than a total of 10% or 1 kw, whichever is
greater.
5.
6.
Customers may not move their solar generation unit to another site.
The grandfathering may be transferred to a new customer purchasing the home.
7.The Customer may remain on their current Legacy rate schedule but may not move between
alternate grandfathered Legacy rate schedules.
8.The Customer will be subject to changes in annual adjustor rates including the rate structure
and level.
A.C.C. No. xxxx
Rate Rider EPR6 Legacy Frozen
Original
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A Miessner
Title: Manager, Pricing and Regulation
Page 2 of3
76295DECISION no.
DOCKET no. E-01345A-l6-0036 ET AL.
Appendix H
Page 21 of 21
Gaps RATE RIDER LEGACY EPR-6
PARTIAL REQUIREMENTS SERVICE FOR
ON-SITE RENEWABLE DISTRIBUTED GENERATION
NET METERING
9. Frozen Rate Rider Legacy LFCR-DG will continue to apply.
10. A Customer may leave the grandfadwering program and be served under a non-Legacy rate
schedule.However, the Customer may not subsequently return to the grand fathering
program at a later date.
SERVICE DETAILS
I . All terms and charges in the Customer's retail rate schedule continue to apply.
divalent,
an MI
2. The Customer must have an Advanced Metering Infrastructure (AMI) meter, or e
installed to measure the production from their solar generation system as well
meter for electrical service.
3.I8ger¢<1Eai=m
\.
once
i ediin customer\ V
The Company provides service under this rider in accord
Requirements Manual. Service terms and conditions may
interconnection or purchase agreement.r
Jenn that4. A Net Metering Facility is an on-site district edfgtevatio
a.r events at the site where the system isomer's e rProvides part of the C
installed;
ices,defined by the Arizona Corporation Commission, tolet sb. Uses re
gen ate
\..
.\\
\,terconepted to and can operate in parallel and in phase with the Company's
listing d1stribution system.
ARIZONA PUBUC SERVICE COMPANY
Phoenix, Arizona
Filed by: Charles A. Miessner
Title: Manager Pricing and Regulation
A.C.C. No. xxxx
Rate Rider EPR6 Legacy Frozen
Original
Effective: xxxx
Page 3 of 3 76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix I
DECISION no.76295
DOCKET NO. E-01345A_16-0036 ET AL.
Appendix I
Page 1 of 15
RATE SCHEDULE E-32 L
LARGE GENERAL SERVICE (401 kW +)Q ops
AVAILABILITY
This rate schedule is available to non-residential Customers with monthly loads of 401 kW and
greater that do not qualify for Rate Schedules E-34 or E-35.
DESCRIPTION
This rate has three parts: a basic service charge, a demand charge for the highest amount of
demand (kW) averaged in a 15-minute period for the month, and an energy charge for the energy
(kph) used during the month. The energy charge will vary by season (summer or winter).
The Company will place the Customer on the applicable Rate Schedule E-32 XS, E-32 S, E-32 M,
or E-32 L based on the Customer's average monthly maximum demand, as determined by the
Company each year. This determination will be made annually.
TIME PERIOD
Summer season:
Winter season:
May through October billing cycles
November through April billing cycles
CHARGES
The monthly bill will consist of the following charges, plus adjustments:
Bundled Charges
Basic Service Charges (only one applies)
For service dlrough Self-Contained Meters $3.060
For service through inst:rument-Rated Meters $3.920
For service at Primary Voltage $6.847
For service at Transmission Voltage $38695
per day
per day
per day
per day
Secondary
Primary
Transmission
Demand Charges (only one set applies)
First 100 kW $25372
All additional kW $17.605
First 100 kW $23049
All additional kW 516411
First 100 kW $17624
All additional kW 9511.753
per kW
per kW
per kW
per kW
per kW
per kW
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title:Manager Regulation and Pricing
Original Effective Date: January 1 2010
A.C.C. No. xxxx
Canceling A.C.C. No. 5813
Rate Schedule E32 L
Revision No. 2
Effective: xxxx
Page 1 of 5 DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.
Appendix I
Page 2 of 15
1l
lRATE SCHEDULE E-32 L
LARGE GENERAL SERVICE (401 kW+)Q ops
__Summer
350.05540
Winter
$003712Energy Charge per kph
Unbundled Components of the Bundled Charges
Bundled Charges consist of the components shown below. These are not additional charges.
per day
per day
per day
Basic Service Char e Com orients
Customer Accounts Charge $2.404
Meter Reading $0.009
Billing $0.030
Metering* (only one applies)
Self Contained Meters $0.617
Instrument-Rated Meters $1.477
per day
per day
per day
per day
rs requesting
Primary $4.404
Transmission $36252
*These daily metering charges apply to typical installations. Custome
specialized facilities are subject to additional metering charges.
u
Transmission
Generation
Delivery - Secondary
Delivery - Primary
Delivery - Transmission
First 100 kW
All additional kW
First 100 kW
All additional kW
First 100 kW
AI1 additional kW
Demand Char e Com orients
$2.870
$5.496
$17006
$9.239
$14.68
$8.045
$9.258
$3.387
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
Ener C har e C o orients
$0.00276
$0.00000
System Benefits
Delivery
per kph
per kph
_!
Generation
Summer
$0.05264
Winter
$003436 per kph
A.C.C. No. xxxxARIZONAPUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: laniary 1 2010
Page 2 of 5
Canceling A.C.C. No. 5813
Rate Schedule E32 L
Revision No. 2
Effective: xxxx
D E C I S I O N no .76295
i
DOCKET no. E-01345A-16-0036 ET AL.
Appendix I
Page 3 of 15
RATE SCHEDULE E-32 L
LARGE GENERAL SERVICE (401 kW+)Q ops
For billing purposes, the kW used in this rate schedule will be the greater of the following:
1.The average kW supplied during the 15-minute period (or other period as specified by
an individual customer contract) of maximum use during the month, as determined
from readings of the Company's meter or in accordance with the Company's Service
Schedule 8.
2. 80% of the highest kW measured during the six (6) summer billing months (May-
October) of the twelve (12) months ending with the current month.
3. The minimum kW specified in the agreement for service or individual contract.
The monthly bill for service under this rate schedule will not be less than the Bundled Basic
Service Charge plus the Bundled Demand Charge for each kw.
AGGREGATION opTlon
Customers with multiple accounts served under Rate Schedule E-32 L or E-32TOU L that
together have a combined load of at least 5 MW are eligible for a discount of $0.0024 per kph
for the unbundled Generation charge in this rate schedule. AH other charges of this schedule
apply as shown. Customers must execute a contract with the Company specifying eligible
accounts prior to receiving this discount. Customer accounts served under Rate Rider PPR,
Rate Rider E-56, or Rate Rider E-56R or have on-site generation greater than 100 kW-PIC are not
eligible for this option.
ADTUSTMENTS
The bill will include the following adjustments:
1. The Renewable Energy Adjustment Charge, Adjustment Schedule REAC-1 .
2. The Power Supply Adjustment charges, Adjustment Schedule PSA-1.
3. The Transmission Cost Adjustment charge, Adjustment Schedule TCA-1 .
4. The Environmental Improvement Surcharge, Adjustment Schedule ElS.
5. The Demand Side Management Adjustment charge, Adjustment Schedule DSMAC-1 .
6. The Tax Expense Adjustment Charge, Adjustment Schedule TEAM.
7.Direct Access Customers returning to Standard Offer service may be subject to a Returning
Customer Direct Access Charge, Adjustment Schedule RCDAC-1.
A.C.C. No. xxxx
Canceling A.C.C. No. 5813
Rate Schedule E32 L
RevisionNo. 2
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager, Regulation and Pricing
Original Effective Date: January 1, 2010
Page 3 of 5 DECISION no.76295
DOCKET no. E-01345A-l6-0036 ET AL.Appendix I
Page 4 of 15
RATE SCHEDULE E-32L
LARGE GENERAL SERVICE (401 kW+)Q ops
8.Any applicable taxes and governmental fees that are assessed on APS's revenues, prices,
sales volume, or generation volume.
RATE RIDERS
Eligible rate riders for this rate schedule are:
PPR
CPP-GS
EPR-2
EPR-6
E-56
E-56R
GPS-1, GPS-2, GPS-3
SGSP (Frozen)
Preference Power
Critical Peak Pricing
Partial Requirements - Net Billing
Partial Requirements - Solar Net Metering
Partial Requirements Service
Partial Requirements - Renewable
Green Power
Schools and Government Solar Program
POWER FACTOR REQUIREMENTS
1. The Customer's load must not deviate from phase balance by more than 10%.
2. Customers receiving service at voltage levels below 69 kV must maintain a power factor of
90% lagging. The power factor cannot be leading unless the Company agrees.
l
l
3. Customers receiving service at voltage levels of 69 kV or above must maintain a power
factor of i 95%.
l
i
1l
4. The Company may install certain monitoring equipment to test the Customer's power
factor. If the load doesn't meet the requirements the Customer will pay the cost to install
and remove the equipment.
5.If the load does not meet the power factor requirements the Customer must resolve the
issue. Otherwise, the Customer must pay for any costs incurred by the Company for
investments on its system necessary to address die issue. Also, until the problem is
remedied, the Company may compute the Customer's monthly billing demand with kVA
instead of kw.
SERVICE DETAILS
1.APS provides electric service under the Company's Service Schedules. These schedules
provide details about how the Company serves its customers, and they have provisions and
charges that may affect the customer's bill (for example, service connection charges).
A.C.C. No. xxxx
Canceling A.C.C. No. 5813
Rate ScheduleE32L
Revision No. 2
Effective: xxxx
ARlZONA PUBLIC SERVICECOMPANY
Phoenix Arizona
Filed by:Charles A Miessncr
Title: Manager Regulation and Pricing
Original Effective Date: January 1, 2010
Page 4 of 5 DECISION NO.76295
DOCKET NO. E-01345A-16-0036 ET AL.Appendix I
Page 5 of 15
RATE SCHEDULE E-32 L
LARGE GENERAL SERVICE (401 kW +)Gaps
2.Electric service provided will be single-phase, 60 Hertz at APS's standard voltages available
at the customer site. Threephase service is required for motors of an individual rated
capacity of 7 V2 HP or more.
3.Electric service is supplied at a single point of delivery and measured dirough a single meter.
4.Direct Access customers who purchase available electric services from a supplier other than
APS may take service under this schedule. The bill for these customers will only include the
Unbundled Component charges for Customer Accounts, Delivery, System Benefits, and any
applicable Adjustments. If metering and billing services are not available from another
supplier, those services will be provided by APS and billed to the customer at the charges
shown above.
iI
I
ARIZONA PUBLIC SERVICE COMPANY
Phoenix,Anzona
Filed by: Charles A. Miessner
Title: Manager, Regulation and Pricing
Original Effective Date: January 1, 2010
Page 5 of 5
A.C.C. No. xxxx
CancelingA.C.C.No. 5813
Rate Schedule E32 L
Revision No. 2
Effective: xxxx
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix I
Page 6 of 15
Q ops RATE SCHEDULE E-32TOU L
LARGE GENERAL SERVICE (401 kW +)
TIME OF USE
AVAILABILITY
This rate schedule is available to non-residential Customers with monthly loads of 401 kW and
greater that do not qualify for Rate Schedule E-35.
DESCRIPTION
This rate has three parts: a basic service charge, a demand charge for the highest amount of
demand (kW) averaged in a 15-minute period for the month, and an energy charge for the energy
(kph) used during the month. The energy charge wit] vary by season (summer or winter) and
time of day (On-Peak and Off-Peak).
The Company will place the Customer on the applicable Rate Schedule Time-of-Use E-32 XS, E-
32 S, E-32 M, or E-32 L based on the Customer's average monthly maximum demand, as
determined by the Company each year. This determination will be made annually.
TIME PERIOD
On-Peak hours:
Off-Peak hours:
Summer season:
Winter season:
3:00 pm - 8:00 pm Monday through Friday
All remaining hours
May through October billing cycles
November through April billing cycles
CHARGES »
The monthly bill will consist of the following charges, plus adjustments:
Bundled Charges
per day
per day
per day
per day
Basic Service Charge (only one applies)
For service through Self-Contained Meters $3.060
For service through Instrument-Rated Meters $3.920
For service at Primary Voltage $6.847
For service at Transmission Voltage $38695
A.C.C. No.xxxx
Canceling A.C.C.No. xxxx
Rate Schedule E32TOU L
Revision No. 2
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager, Regulation and Pricing
Original Effective Date: ]january 1 2010
Page 1 of 6
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
opsQ
Appendix I
Page 7 of 15
RATE SCHEDULE E-32TOU L
LARGE GENERAL SERVICE (401 kW +)
TIME OF USE
Secondary
Primary
Transmission
Demand Charges (only one set applies)
First 100 On-Peak kW 508
All additional On-Peak kW $11.795
First 100 Off-Peak kW $6.396
All additional Off-Peak kW $3.370
First 100 On-Peak kW $16936
All additional On-Peak kW $11710
First 100 Off-Peak kW $5.679
All additional Off-Peak kW $3.272
First 100 On-Peak kW $15916
All additional On-Peak kW $10478
First 100 Off-Peak kW $4.871
All additional Off-Peak kW $3.137
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
__
Energy Charges
Summer
840.07018
$3.05730
On-Peak
Off-Peak
Winter
80.05552
$0.04264
per kph
per kph
Unbundled Components of the Bundled Charges
Bundled Charges consist of the components shown below. These are not additional charges.
per day
per day
per day
Basic Service Char e Com orients
Customer Accounts Charge $2.404
Meter Reading $0.009
Billing $0.030
A.C.C. No.xxxx
Canceling A.C.C.No.xxxx
RateSchedule E-32ToU L
RevisionNo.2
Effective:xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix, Arizona
Filedby:Charles A. Miessner
Title: Manager, Regulation and Pricing
Original Effective Date: January 1 2010
Page 2 of 6
76295DECISION no.
DOCKET no. E-01345A-16-0_36 ET AL.Appendix I
Page 8 of 15
Q ops RATE SCHEDULE E-32TOU L
LARGE GENERAL SERVICE (401 kW +)
TIME OF USE
Self Contained Meters
Instrument-Rated Meters
Primary
Transmission
Metering* (only one applies)
$0.617
$1.477
$4.404
$36.252
per day
per day
per day
per day
Customers requesting*These daily metering charges apply to typical installations.
specialized facilities are subject to additional metering charges.
Transmission
Generation On-Peak
Generation Off-Peak
Delivery -
Secondary
n
Delivery -
Primary
Delivery -
Transmission
First 100 On-Peak kW
A11 additional On-Peak kW
First 100 Off-Peak kW
All additional Off-Peak kW
First 100 On-Peak kW
All additional On-Peak kW
First 100 Off-Peak kW
All additional Off-Peak kW
First 100 On-Peak kW
All additional On-Peak kW
First 100 Off-Peak kW
All additional Off-Peak kW
Demand Char e Com orients
$2.870
$5.980
$2.275
$8.658
$2.945
$4.121
$1.095
$8.086
$2.860
$3.404
$0.997
$7.066
$1.628
$2.596
$0.862
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
per kW
c
•Enera
per kph
Per kph
Char eCo orients
$000276
$001208
System Benefits Charge:
Delivery Charge
A.C.C. No. xxxx
Canceling A.CC. No. xxxx
Rate Schedule E-32TOU L
RevisionNo.2
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager, Regulation and Pricing
Original Effective Date: January 1 2010
Page 3 of 6
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
G ops
Appendix I
Page 9 of 15
RATE SCHEDULE E-32TOU L
LARGE GENERAL SERVICE (401 kW +)
TIME OF USE
__Winter
$004068
$002780
Summer
$0.05534
$004246
Generation On-Peak
Generation Off-Peak
per kph
per kph
For billing purposes, the On-Peak kW used in this rate schedule will be the greater of the
following:
1.The average kW supplied during the 15-minute period of maximum use during the On-
Peak period during the billing period, as determined from readings of the Company's
meter or in accordance with the Company's Service Schedule 8.
2. 80% of the highest On-Peak kW measured during the six summer billing rondos (May-
October) of the twelve (12) months ending with the current month.
3. The minimum kW specified in the agreement for service or individual contract.
Off-peak kW will be based on the average kW supplied during the 15-minute period of
maximum use during the Off-peak hours of the billing period, as determined from readings
of the Company's meter.
The monthly bill for service under this rate schedule will not be less than the Bundled Basic
Service Charge plus the Bundled Demand Charge for each kw.
AGGREGATION OPTION
Customers with multiple accounts served under Rate Schedule E-32 L or E-32TOU L that
together have a combined load of at least 5 MW are eligible for a discount of $0.0024 per kph
for the unbundled Generation charge in this rate schedule. AH other charges of this schedule
apply as shown. Customers must execute a contract with the Company specifying eligible
accounts prior to receiving this discount. Customer accounts served under Rate Rider PPR,
Rate Rider E-56, or Rate Rider E-56R or have on-site generation greater than 100 kW-AC are not
eligible for this option.
ADTUSTMENTS
I
!I;The bill will include the following adjustments:
1. The Renewable Energy Adjustment Charge, Adjustment Schedule REAC-1.
2. The Power Supply Adjustment charges, Adjustment Schedule PSA-1.
A.C.C. No. xxxx
Canceling A.C.C. No.xxxx
Rate Schedule E-32TOU L
RevisionNo. 2
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 1, 2010
Page 4 of 6
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix I
Page 10 of 15
RATE SCHEDULE E-32TOU L
LARGE GENERAL SERVICE (401 kW +)
TIME OF USE
3. The Transmission Cost Adjustment charge, Adjustment Schedule TCA-1 .
4. The Environmental Improvement Surcharge, Adjustment Schedule ElS.
5. The Demand Side Management Adjustment charge, Adjustment Schedule DSMAC-1 .
6. The Tax Expense Adjustment Charge, Adjustment Schedule TEAM.
7.Direct Access Customers returning to Standard Offer service may be subject to a Returning
Customer Direct Access Charge, Adjustment Schedule RCDAC-1.
8.Any applicable taxes and governmental fees that are assessed on APS's revenues, prices,
sales volume, or generation volume.
RATE RIDERS
Eligible rate riders for this rate schedule are:
0
Preference Power
Critical Peak Pricing
Partial Requirements - Net Billing
Partial Requirements - Solar Net Metering
Partial Requirements
Partial Requirements - Renewable
Green Power
Schools and Government Solar Program
PPR
CPP-GS
EPR-2
EPR-6
E-56
E-56R
GPS-1, GPS-2, GPS-3
SGSP (Frozen)
POWER FACTOR REQUIREMENTS
1. The Customer's load must not deviate from phase balance by more than 10%.
2. Customers receiving service at voltage levels below 69 kV must maintain a power factor of
90% lagging. The power factor cannot be leading unless the Company agrees.
3. Customers receiving service at voltage levels of 69 kV or above must maintain a power
factor of i 95% .
A.C.C. No. xxxx
Canceling A.C.C No. xxxx
Rate Schedule E-32TOU L
Revision No. 2
Effective: xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 1, 2010
Page 5 of 6
76295DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix I
Page 11 of 15
RATE SCHEDULE E-32TOU L
LARGE GENERAL SERVICE (401 kW +)
TIME OF USE
4. The Company may install certain monitoring equipment to test the Customer's power
factor. If the load doesn't meet the requirements the Customer will pay the cost to install
and remove the equipment.
5.If the load does not meet the power factor requirements the Customer must resolve the
issue. Otherwise, the Customer must pay for any costs incurred by the Company for
investments on its system necessary to address the issue. Also, until the problem is
remedied, the Company may compute the Customer's monthly billing demand with kVA
instead of kw.
SERVICE DETAILS
1.APS provides electric service under the Company's Service Schedules. These schedules
provide details about how the Company serves its Customers, and they have provisions and
charges that may affect the Customer's bill (for example, service connection charges).
2.Electric service provided will be single-phase, 60 Hertz at APS's standard voltages available
at the Customer site. Threephase service is required for motors of an individual rated
capacity of 7 VS HP or more.
3. Electric service is supplied at a single point of delivery and measured through a single meter.
4.Direct Access Customers who purchase available electric services from a supplier other than
APS may take service under this schedule. The bill for these customers wilLonly include the
Unbundled Component charges for Customer Accounts, Delivery, System Benefits, and any
applicable Adjustments. If metering and billing services are not available from another
supplier, those services will be provided by APS and billed to the Customer at the charges
shown above.
A.C.C. No.xxxx
Canceling A.C.C. No. xxxx
Rate Schedule E32TOU L
RevisionNo.2
Effective:xxxx
ARlZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:Charles A. Miessner
Title: Manager Regulation and Priding
Original Effective Date: ]january 1, 2010
Page 6 of 6
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Gaps
Appendix I
Page 12 of 15
RATE SCHEDULE XHLF
GENERAL SERVICE
EXTRA HIGH LOAD FACTOR
AVAILABILITY
This rate schedule is available to Customers whose monthly maximum demand is 5,000 kW or
more with a load factor of 92% or more for a minimum of nine months of the prior 12 month
period.
Customers will be required to execute a service agreement or contract that specifies certain
provisions of their electric: service, such as a contract length, minimum and maximum monthly
loads, special charges, and other service details.
Qualifying Customers with monthly demands of 15,000 kW and greater may choose to be
served with transmission level service by providing the Company with a contribution in aid of
construction (CIAC) in lieu of purchasing transmission level facilities. The Customer will be
required to execute a maintenance contract and share in the cost of replacement facilities.
Under this option, the Company may also finance the CIAC at the Company's weighted
average cost of capital established in its most recent rate case. This financing period will not
exceed 10 years.
DESCRIPTION
This rate has three parts: a basic service charge, a demand (kW) charge consisting of the average
kW supplied during the 15-minute period of maximum use during the billing period, and an
energy (kph) charge for the energy used for the entire month.
Monthly load factor will be established using the formula:
Monday Load Factor = Billed kph/ (billed kW * Billing Days * 24 hours)
CHARGES
The monthly bill will be calculated at the following rates or t.he minimum rates, whichever is
greater, plus any adjustments incorporated in this rate schedule:
Bundled Service
Customers Served at Secondary Voltage
$5.122
$17950
$003761
per day
per kW
perkph
Basic Service Charge
Demand Charge
Energy Charge
A.C.C.No xxxx
Rate Schedule XHLFOriginal
Effective: xxxx
AR1ZONA PUBLIC SERVICE COMPANY
Phoenix, Arizona
Filedby:Charles A. Miessner
Title: Manager Regulation and Pridn8
Page 1 of 4
76295DECISIONno.
DOCKET NO. E-01345A-16-0036 ET AL.
Q ops
Appendix I
Page 13 of 15
RATE SCHEDULE XHLF
GENERAL SERVICE
EXTRA HIGH LOAD FACTOR
Customers Served at Primary Voltage
$8.049
$16609
$003761
per day
per kW
per kph
Basic Service Charge
Demand Charge
Energy Charge
Customers Served at Transmission Voltage
$39897 per day
$12917 per kW
$003761 per kph
Basic Serviee Charge
Demand Charge
Energy Charge
Unbundled Standard Offer Service
Bundled Charges consists of the Components shown below. These are not additional charges.
per day
per day
per day
Customer Accounts
Meter Reading
Billing
Instrument-Rated Meter
Primary Meter
Transmission Meter
per day
per day
per day
per kW
per kW
Transmission Charge
Generation - Capacity
Secondary Service
Primary Service
Transmission Service
per kW
per kW
per kW
Basic Service Charge Components
$3.606
$0.009
$0.030
Meter (only one applies)
$1.477
$4.404
$36252
Demand Charge Components
$3.236
$9.274
Delivery (only one applies)
$5.440
$4.099
$0.407
Energy Charge Components
$003485
$000276
per kph
per kph
Generation - Fuel
System Benefits
A.C.C. No. xxxx
Rate Schedule XHLF
Original
Effective: xxxx
ARIZONA PUBLIC SERVICECOMPANY
Phoenix Arizona
Filed by: Charles A. Miessncr
Title: Manager Regulation and Priding
Page 2 of 4
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix I
Page 14 of 15
RATE SCHEDULE XHLF
GENERAL SERVICE
EXTRA HIGH LOAD FACTOR
The kW for billing will be the greater of:
a.The average kW supplied during the 15-rninute period of maximum use during the
monthly billing period; or
b. The minimum kW specified in a service agreement.
MINIMUM BILL
The bill will not be less than the minimum amount specified in the Customer's service
agreement or contract.
ADIUSTMENTS
The bill will include the following adjustments:
1. The Renewable Energy Adjustment Charge, Adjustment Schedule REAC-1.
2. The Power Supply Adjustment charges, Adjustment Schedule PSA-1.
3. The Transmission Cost Adjustment charge, Adjustment Schedule TCA-1.
4. The Environmental Improvement Surcharge, Adjustment Schedule ElS.
5.Direct Access CUstomers returning to Standard Offer service may be subject to a Returning
Customer Direct Access Charge, Adjustment Schedule RCDAC-1.
6. The Demand Side Management Adjustment charge, Adjustment Schedule DSMAC-1 .
I 7. The Tax Expense Adjustment charge, Adjustment Schedule TEAM.
8.Any applicable taxes and governmental fees that are assessed on APS's revenue, prices,
sales volume, or generation volume.
RATE RIDERS
Eligible rate riders for thisrate schedule are:
Green PowerGPS-1, GPS-2, GPS-3
POWER FACTOR REQUIREMENTS
1. The Customer's load must not deviate from phase balance by more than 10%.
A.C.C. No. xxxx
Rate Schedule XHLF
Original
Effective; xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix,Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 3 of 4
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix I
Page 15 of 15
RATE SCHEDULE XHLF
GENERAL SERVICE
EXTRA HIGH LOAD FACTOR
2.Customers receiving service at voltage levels below 69 kV must maintain a power factor of
90% lagging. The power factor cannot be leading unless the Company agrees.
3. Customers receiving service at voltage levels of 69 kV or above must maintain a power
factor of i 95%.
II
4. The Company may install certain monitoring equipment to test the Customer's power
factor. If the load doesn't meet the requirements the Customer will pay the cost to install
and remove the equipment.
5.If the load does not meet the power factor requirements the Customer must resolve the
issue. Otherwise, the Customer must pay for any costs incurred by the Company for
investments on its system necessary to address die issue. Also, until the problem is
remedied, the Company may compute the Customer's monthly billing demand with kVA
instead of kw.
SERVICE DETAILS
1.The type of service provided under this schedule will be three phase, 60 Hertz, at the
Company's standard voltages that are available within the vicinity of the Customer site.
2.Daily metering charges apply to typical installations. Customers requiring specialized
Equipment may incur additional metering charges that reflect the additional cost.
.3.Customers that self-provide some of their electrical requirements from on-site generation
will be billed according to one of the partial requirement rate riders.
4.Electrical service must be supplied at one point of delivery and measured through one
meter unless otherwise specified in a service agreement.
5. This schedule is not applicable to breakdown, standby, supplernentad, residential or rescale
service.
6.Direct Access Customers who purchase available electric services from a supplier other than
APS may take service under this schedule. The bill for these Customers will only include
die Unbundled Component charges for Customer Accounts, Delivery, System Benefits, and
any applicable Adjustments. If metering and billing services are not available from another
supplier, those services will be provided by the Company and billed to the Customer at the
charges shown above.
7.APS provides electric service under the Company's Service Schedules. These schedules
provide details about how the Company serves its Customers, and they have provisions and
charges that may affect the Customer's bill (for example, service connection charges).
A.C.C.No. xxxx
Rate Schedule XHLF
Original
Effective:xxxx
AR17ONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:Charles A.Miessner
Title: Manager Regulation and Pricing
Page 4 of 4
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix J
I
II
I
II
76295DECISIONno.
DOCKET NO. E-01345A-16-0036 ET AL.
Appendix J
Page 1 of 5
Q ops SERVICE SCHEDULE 9
CONDITIONS GOVERNING ECONOMIC INCENTIVES FOR THE
INDUSTRIAL DEVELOPMENT PLAN
General Description
This Service Schedule provides the Terms and Conditions under which Arizona Public Service
Company (APS or Company) may offer financial incentives to potential new commercial or
industrial Customers or to existing commercial and industrial Customers who are adding
significant new load.
Availability of this schedule is limited to the lesser of 100 MW of new and additional load or 50
new Customers.
The Customer must provide all requested information to die Company in order to demonstrate
eligibility. The Company will evaluate all relevant information and will determine whether to
offer the Customer an incentive.
Consistent with the Schedule, when the Company determines that it is appropriate to offer an
incentive to an eligible Customer, an agreement will be executed with the Customer. The
agreement will specify the incentive and other terms where different from the Companys other
Service Schedules.
APS will file each agreement, along with a complete Customer Characteristics Report with
Arizona Corporation Commission (Commission) Staff as a compliance filing. Each agreement
filed with the Commission Staff will become effective 30 days after filing.
Any Customer information that the Company provides to Commission Staff on a confidential
basis will be returned to the Company no later than 60 days after an application under this
Schedule is filed.
1.Eligibility Criteria
The Company will evaluate the following Customer characteristics prior to offering service
under this Schedule to determine if the Customer is eligible for a financial incentive:
1.1 Availability of Alternative Locations
(A) Incentives are available only to Customers who have not located or expanded in Me
Company's service area before the Commission's review of the application and who
would not locate or expand in the Company's service area without this Schedule's
incentive.
(B) The Customer must provide the Company with evidence that additional locations,
outside the Company's service area, have been considered for location or
expansion. This evidence must consist of written documentation including, but not
Acc.No. XXXX
Original
ServiceSchedule9
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 1 of 5
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix J
Page 2 of 5
Gaps SERVICE SCHEDULE 9
CONDITIONS GOVERNING ECONOMIC INCENTIVES FOR THE
INDUSTRIAL DEVELOPMENT PLAN
limited to, detailed quantitative analyses performed by the Customer or consultants
regarding the suitability of alternative locations.
(C) Based on the information provided, the Company will determine whether the
Customer would reasonably locate elsewhere in the absence of the incentive. If so,
the Customer will be deemed to have met this requirement.
1.2 Effects on Competitors
(A) Incentives will be available to the Customer only when e>dsting Customers in the
same line of business and market are not adversely impacted by the discounted
rates.
(B) The Customer must provide a detailed description of goods and services
produced, the technology employed, and the market(s) the Customer serves.
(C) Based on the provided information, along with knowledge of its customer base,
the Company must reasonably verify that this requirement is satisfied for the
Customer to be eligible for an incentive.
1.3 Customer Load Requirements
(A) To qualify for this Schedule, electric requirements for a new Customer must be at
least 2 MW and existing Customers must add at least 1 MW of load. To determine
Customer load, APS will consider both energy purchased from the Company and
any energy generated by the Customer using cogeneration or small power °
production facilities.
(B) The Customer's monthly average load factor must be 55% or greater. This load
factor criteria may be waived if one of the following apply:
1. The Customer's daily off-peak energy usage in kph is greater than 50% of total
monthly energy usage in kph (off-peak hours will be defined using the
applicable General Service Rate Schedule); or
2. The Customer's new or added load is interruptible and the Customer's peak
load is at least 3 MW.
(C) Loads that do not operate in the summer months of ]ume through September will
be given special consideration when determining an applicable incentive.
(D) APS will assist the Customer to consider and employ state-of-the-art, cost-effective
energy conservation and demand response measures at its facility. These
measures may include efficiency motors, motor control systems, and other general
measures such as efficient lighting, space heating and cooling, and insulation.
A.C.C. No.xxxx
Original
Service Schedule 9
Effective:XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 2 of 5
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.I
Appendix J
Page 3 of 5
Q ops SERVICE SCHEDULE 9
CONDITIONS GOVERNING ECONOMIC INCENTWES FOR THE
INDUSTRIAL DEVELOPMENT PLAN
1.4 Economic Requirements
(A) The load must be economic, as calculated under the Company's current extension
policy using standard rates.
(B) To be eligible for incentives under this schedule, a potential load must bring a
significant number of jobs or ancillary business into Arizona. In conjunction with
this criterion, capital investment by the Customer may also be considered.
(C) The Company will give particular consideration to Customers whose electric bills
exceed 5% of their operating expenses.
2.Conflict of Interest.
2.1 In order to limit any potential conflict of interest, APS is required to submit an affidavit
to Commission Staff for each Customer under consideration for service under this
Service Schedule. This affidavit will include:
(A) A statement that no current officer or director of Pinnacle West Capital Corporation
or any of its subsidiaries, or one who has filled such role within the three-years prior
to the effective date of the Customer's agreement, has or had any interest, direct or
indirect, with any entity which has provided substantial services, including real
estate broker services, to the Customer in connection with a proposed agreement
under this Schedule; and °
(B) A statement that no current officer or director of Pinnacle West Capital Corporation
or any of its subsidiaries or affiliates has or had any direct or indirect interest in any
property owned in whole or in part by the Customer.
2.2 If the affidavit provided by APS is shown to be inaccurate, the Commission will, in
future APS rate cases, impute as revenue the difference been/een the discounted rate and
the tariffed rate which would otherwise apply to the Customer for the period during
which the discount was in effect.
3.Rate ProvisionsI
3.1 A Customer satisfying the requirements above may receive an incentive to locate in the
Company's service territory. The incentive will be a discount from the Customer's
otherwise applicable base electric bill (excluding taxes and adjustments).
|3.2 The discounted charges will not be below the Company's marginal cost.
A.C.C. No.XXXX
Original
Service Schedule 9
Effective; XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix,Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 3 of 5
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
Appendix J
Page 4 of 5
Gaps SERVICE SCHEDULE 9
CONDITIONS GOVERNING ECONOMIC INCENTIVES FOR THE
INDUSTRIAL DEVELOPMENT PLAN
3.3 The discount may vary over the term of the Customer agreement.
3.4 The discount will not be larger than 25% of the Customer's total energy bill from the
Company.
3.5 No discount will be provided from the minimum bill as computed under the Customer's
otherwise applicable rate.
3.6 For current Customers adding load, the discount will apply only to the added load.
3.7 Any incentive available under this schedule will be limited to a specific period of six
years or less.
3.8 The specific discount and the period over which the discount is applied will be
determined after full evaluation of the Customer information as determined by the
Company.
4.Customer Characteristic Report
Each agreement must be accompanied by a Customer Characteristic Report. The following
information will be included in the Customer Characteristics Report
»4.1 General Information
(A) Customer name
(B) Customer contact name and address
(C) Dates of Customer application and Company decision
(D) New or existing Customer
(E) Proposed effective date of agreement
4.2 LocationDecision
(A) Customer location
(B) Description of other locations considered
(C) Other locations of Customer's operations
(D) An affidavit from Customer demonstrating that the Customer would not locate or
expand in Arizona absent the discounts
(E) Within ninety (90) days of the effective date of any agreement under this Schedule,
the Customer must supply written documentation and analyses substantiating the
affidavit provided under 4.2 (D)
(F) If the requirements of 4.2 (E) are not met within ninety (90) days of approval of the
agreement, the agreement will be void
A.C.C. No. XXXX
Original
Service Schedule 9
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Page 4 of 5
DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
Appendix J
Page 5 of 5
Gaps SERVICE SCHEDULE 9
CONDITIONS GOVERNING ECONOMIC INCENTIVES FOR THE
INDUSTRIAL DEVELOPMENT PLAN
(G) Proportion of Customer's production and distribution expenses accounted for by
electricity, by natural gas and by other energy sources (specify)
4.3 Effects on Competitors
(A) Nature of business, description and North American Industry Classification System
(NAICS) code
(B) Number of other Customers in same business
(C) Market area served by Customer
(D) Description of effects on other Customers
4.4 Load Characteristics
(A) Size of load
(B) Annual load factor
(C) Off-peak operation
(D) Description of daily load shape
(E) Seasonality
(F) Interruptibility
(G) Permanency of load
(H) Estimated impact on system peak demand from the new load
:I 4.5 Energy Service Mix
(A) Use of natural gas and other energy sources
(B) Description of energy efficiency measures including building design, processing and
other 6
(C) Feasibility of cogeneration
4.6 Rates
(A) Applicable rate schedule
(B) Years discount will be in effect
(C) Percentage discount by year
(D) Estimated annual revenues
(E) Estimated annual incremental electricity production costs
(F) Support that the agreement meets the terms described in Rate Provisions Section 3.2
and 3.4
4.7 Special Agreement Provisions
(A) List of special provisions
(B) Reasons for special provisions
A.C.C. No. XXXX
Original
Service Schedule 9
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by:Charles A.Miessner
Title: Manager, Regulation and Pricing
l
Page 5 of 5
l
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
ll
Appendix K
»
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix K
Page 1 of 6
'Jaws RATE RIDER AG-X
GENERAL SERVICE
ALTERNATIVE GENERATION
AVAILABILITY
This rate rider schedule is available in all territories served by die Company at all points where
facilities of adequate capacity and the required phase and suitable voltage are adjacent to the
sites served.
APPLICATION
This rate rider schedule is available for Standard Offer customers who have an Aggregated
Peak Load of 10 MW or more and are served under Rate Schedules E-34, E-35, E32-L, or E-32
TOU L. An aggregated group may also include metered accounts that are served under Rate
Schedules E-32 M or E-32 TOU M, if the accounts are located on the same premises and served
under the same name as an otherwise eligible Customer.
Customers must have interval metering, Advanced Metering Infrastructure, or an alternative in
place at all times of service under this schedule. If the Customer does not have such metering,
the Company will install the metering equipment at no additional charge.However, die
customer will be responsible for providing and paying for any communication requirements
associated with the meter, such as a phone line.
a
All provisions of the customer's applicable rate schedule will apply in addition to this Schedule
AG-X, except as modified herein. Total program participation will be limited to 200 MW of
customer load, 100 MW of which will be initially reserved for Customers with single-site peak
demands of 20 MW or greater and with monthly average load factors above 70% unless not
fully subscribed during the solicitation process.
DEFINITIONS
Aggregated Peak Load: The sum of the maximum metered kW for each of the Customer's
aggregated metered accounts over the previous 12 months, as determined by the Company and
measured at the Customer's meter(s) at the time of application for service under this rate rider
schedule.
Standard Generation Service:Power provided by the Company to a retail customer in
conjunction with transmission and delivery services, at terms and prices according to a retail
rate schedule other than Schedule AG-X.
Customer: A metered account or set of aggregated metered accounts that meet the eligibility
requirements for service and enrollment as an aggregated load for service, under this rate rider
schedule.
Generation Service Provider: A third party entity that provides wholesale power to the
Company on behalf of a Customer. This entity must be legally capable of selling and delivering
wholesale power to the Company.
Acc No.XXXXX
Rate Rider AGX
Original
Effective; XXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby CharlesA Miessner
Title: Manager. RegulationandPricing
Original EffectiveDate; XXXX
Page I ol7
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix K
Page 2 of 6
Q ops RATE RIDER AG-X
GENERAL SERVICE
ALTERNATIVE GENERATION
Generation Service: Wholesale power delivered to APS by a Generation Service Provider.
Imbalance Energy: For each Generation Service Provider, imbalance Energy will be calculated
by the Company as the difference between the hourly delivered energy from the Generation
Service Provider and the aggregated actual hourly metered load for all Customers that have
selected the Generation Service Provider under this rate rider schedule.
Calculating and managing the hourly deviations in energy supply forImbalance Service:
imbalance energy.
Total Load Requirements: The Customer's hourly load including losses from the point of
delivery to die Company's transmission system to the Customer's sites for the duration of the
CoI1lI3ct.
CUSTOMER ENROLLMENT
The Company will establish an initial enrollment period during which Customers can apply for
service under this rate rider schedule. If the applications for service are greater than the
program maximum amount, then Customers will be selected for enrollment dirough a lottery
process as detailed in the program guidelines, which may be revised from time-to-time during
the term of this rate rider schedule. Otherwise, customers may enroll on a first come first serve
basis. After the initial lottery, if necessary, customers who enter the program will not be
required to participate in a subsequent lottery to remain in the program.
AGGREGATION
Eligible customers may be aggregated if they have the same corporate name, ownership, and
identity. In addition, (1) an eligible franchisor customer may be aggregated with eligible
franchisees or associated corporate accounts, and (2) eligible affiliate customers may be
aggregated if they are under the same corporate ownership, even if they are operating under
multiple trade names.
DESCRIPTION OF SERVICES AND OBLIGATIONS
The Customer must apply for service under this rate rider schedule.
The Company will conduct the enrollment process i.n accordance wide the provisions of this rate
rider schedule.
The Customer must select a Generation Service Provider to provide Generation Service in
accordance with the timeline specified in the program guidelines
The Company must enter into a contract with the Generation Service Provider to receive
delivery and title to the power on the Customer's behalf.
A c c No XXXXX
Rate Rider AGX
Original
Effective;XXXXX
ARIZONA PUBLIC SFRVICE COMPANY
Phoenix. Arizona
Filed by: Charles A Micssner
Title: Manager Regulation andPricing
OriginalEffectiveDale;XXXX
Page 2 of 7
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix K
Page 3 of 6
Q ops RATE RIDER AG-X
GENERAL SERVICE
ALTERNATIVE GENERATION
The Generation Service Provider must provide to the Company on behalf of the Customer firm
power sufficient to meet the Customer's Total Load Requirements for each of the specified
metered accounts, and will attest in its contract with the Company that this condition is met.
For the purposes of this rate schedule, "firm power" refers to generation resources identified in
Western System Power Pool Schedule C or a reasonable equivalent as determined by the
Company.
The Company will provide transmission, delivery and network services to the Customer
according to normal retail electric service.
The Company will settle with the Generation Service Provider for Imbalance Service and other
relevant costs on a monthly basis according to the program guidelines.
The Generation Service Provider must bill the Company the monthly billed amounts for each
customer for Generation Service and Imbalance Service according to the program guidelines.
The Company will bill the customer for the Generation Service Provider's charged amounts and
remit the amounts to the Generation Service provider.
The customer will be responsible for paying for the cost of the power provided by the
Generation Service Provider, as specified in the contract and this rate rider schedule.
APS will not propose a deferral of unmitigated costs resulting from AG-X, if any, and APS will
not request recovery of any unmitigated costs resulting from AG-X, if any, in its next rate case.
DELIVERY GF POWER TOTHE COMPANY'S SYSTEM
Power provided by the Generation Service Provider must be firm power as defined above and
delivered to the Company at the Palo Verde network delivery point, or other point of delivery
as agreed to by the Company. The Generation Service Provider is responsible for the cost of
transmission service to deliver the power to the Company's delivery point.
SCHEDULING
The Company will serve as the scheduling coordinator. The Generation Service Provider must
provide monthly schedules of hourly loads along with day-ahead hourly load deviations from
the monthly schedule to the Company according to the program guidelines. Line losses, in the
amount of 7%, from the point of delivery to the Customer's sites will be either scheduled or
financially settled. Line losses will be modified to reflect transmission voltage service when
applicable.
IMBALANCE SERVICE
The Company will provide Imbalance Service according to the terms and provisions below:
A.c c No. XXXXX
Rate Rider AG-X
Original
Effective; XXXXX
ARIZONA PUBLIC SFRVICECOMPANY
Phoenix. Arizona
Filed by: Charles A Miessner
Title: Manager Regulation and Pricing
Original Effective Date: XXXX
Page 3of7 76295
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix K
Page 4 of 6
Q ops RATE RIDER AG-X
GENERAL SERVICE
ALTERNATIVE GENERATION
i.Within the range of +/ - 15% each hour or +/ - 2 MW, whichever is greater, GSPs
would pay based on Schedule 4 of APS's OATT which now reflects the terms of
the CAISO imbalance charges.
ii.Greater than 15 % each hour or +/- 2 MW, whichever is greater, in addition to
the charges in ii) GSPs would pay a penalty of $3 per Mwh.
iii.In addition to the imbalance provisions described above, GSPs with 20% of
hourly deviations greater than 20% of the scheduled amount occurring in a
calendar month will receive a notice of intent to terminate the GSP's eligibility in
the program unless remedied. Imbalances of this magnitude and frequency will
be deemed "Excessive." Should Excessive imbalances occur again in a subsequent
month, within 12 months from the date of the notice, the GSP's eligibility may be
terminated. To avoid termination, a GSP must demonstrate to APS that it is
operating in good faith to match its resources to its load. In the event of GSP
termination, the Customer will be required to secure a replacement GSP within
60 days, and will be subject to the terms listed in "Default of the third party
generation provider" .
DEFAULT OF THE THIRD PARTY GENERATION PROVIDER
In the event that the Generation Service Provider is unable to meet its contractual obligations,
the customer must notify the Company and select another Generation Service Provider within
60 days. Prior to execution of any new power contract, the Company will provide the required
power to the customer, which will be charged at the Palo Verde Peak or Off-peak ICE
("Intercontinental Exchange") Day Ahead Power prices or its successor for the power delivery
date plus $10 per MWh not to be less than $0 per MWh or at the applicable retail rate at the
company's option. In addition, all other provisions of this rate rider schedule will continue to
apply.
If the Customer is unable to select another Generation Service Provider within sixty days, the
customer will automatically return to Standard Generation Service, and be subject to the
conditions below.
RETURN TO COMPANY'S STANDARD GENERATION SERVICE
I|
Customer may return to the Company's Standard Generation Service under their applicable
retail rate schedule if: (1) they provide one or more years notice to the Company; or (2) if the
Commission terminates the program.Absent one of these conditions, the Company will
provide generation service to the Customers under the following conditions. The Company
may elect to provide the customer with generation service at the Palo Verde Peak or Off-peak
ICE ("Intercontinental Exchange") Day Ahead Power prices or its successor for the power
delivery date plus $10 per MWh for a period of time for the Customer to attain 1 year notice, at
which time the Customer returns to the Company's Standard Generation Service under their
A c C No XXXXX
Rate Rider AGX
Original
Effective. XXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A Miessner
Title: Manager. Regulation and Pricing
Original Efleclive Date: XXXX
Page 4 of 7
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.Appendix K
Page 5 of 6
Q ops RATE RIDER AG-X
GENERAL SERVICE
ALTERNATIVE GENERATION
applicable retail rate schedule. The returning customer must remain with the Company's
Standard Generation Service for at least 1 year.
RATES
All provisions, charges and adjustments in the customer's applicable retail rate schedule will
continue to apply except as follows:
1. The generation charges will not apply;
2. Adjustment Schedule PSA-1 will not apply;
3. Adjustment Schedule ElS will not apply; and
4. The applicable proportionate part of any taxes or governmental impositions which are
or may in the future be assessed on the basis of gross revenues of the Company and/or
the price or revenue from the electric energy or service sold and/ or the volume of
energy generated or purchased for sale and/ or sold hereunder will be applied to the
customer's bill.
Schedule AG-X charges determined and billed by the Company include:
1. A monthly administrative management fee of $0.00180 per kph applied to the
customer's billed kph;
2. A monthly reserve capacity charge of $5.540 per kW applied to 100% of the customer's
billed kW (on-peak for Rate Schedules E-35 and E-32 TOU L);
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l3. Returning Customer charge, where applicable, as described herein;
4. Generation Service Provider Default charge, where applicable, as described herein.
These charges and other parameters will be re-evaluated in APS's next rate case, including
whether AG-X should be evaluated as a separate customer class in the cost of service study.
Schedule AG-X Generation Service and Imbalance Service charges billed by the Company
include:
1. Generation Service charges will be charged at a rate within the minimum and maximum
limits as follows:
a.When the contract provides for pricing that reflects a specific index price, the
minimum price will be the specified index minus 35% and the maximum price
will be the specified index plus 35%. The determination that a contract is
consistent with this provision will be based on the specified index price
applicable on the date the contract is executed.
Acc.No XXXXX
Rate Rider AGX
Original
Effective; XXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by:CharlesA Miessner
Title:Manager. Regulation and Pricing
Original Effective Dale: XXXX
Page 5 of 7 76295
DECISION no.
4
DOCKET no. E-01345A-16-0036 ET AL.Appendix K
Page 6 of 6
9 ops RATE RIDER AG-X
GENERAL SERVICE
ALTERNATIVE GENERATICN
b. When die contract provides for a fixed price supply for the term of the contract,
the minimum price will be the generation rate of the Customer's applicable retail
rate schedule minus 35%, and the maximum price will be the generation rate of
the Customers applicable retail schedule plus 35%. If the Customer has more
than one otherwise applicable retail rate schedule, the highest applicable retail
rate schedule will be used for purposes of the consistency determination. The
determination that a contract is consistent with this provision will be based on
the Customer's otherwise applicable retail rate schedule in effect on the date the
contract is executed.
c. Losses from the delivery point to the Customer's meters and charges for
transmission and distribution will not be included in the Generation Service
charge for purposes of determining whether the contract is consistent with the
minimum and maximum price provisions of this rate rider schedule, while
Capacity Reservation Charge,the Management Fee, and Imbalance Service
charges will be included in the Generation Service charge for purposes of
determining whether the contract is consistent with the minimum and maximum
price provisions of this rate rider schedule.
2. Imbalance Service charges will be charged at a rate greater than $0.00 per kph and less
than or equal to the rate that the Company charges the Generation Service Provider for
Imbalance Service as specified herein.
CONTRACT TERM AND REQUIREMENTS
¢
The term of the contract with the Generation Service Provider must be for not less than one year
and must include termination provisions to comply with Section W under imbalance services,
as well as general termination provisions should the program be discontinued at some point in
the future.
The Generation Service Provider and Customer will enter into a contract or contracts with the
Company, stating the pertinent details of the transaction with the Generation Service Provider,
including but not limited to the scheduling of power, location of delivery and other terms
related to the Company's management of the generation resource.
CREDIT REQUIREMENTS
A Generation Service Provider or its parent company must have at least an investment grade
credit rating or demonstrate creditworthiness in the form of either a 3rd-party guarantee from
an investment grade rated company, surety bond, letter of credit, or cash in accordance with the
Company's standard credit support rules.
A C C No XXXXX
Rate Rider AGX
Original
Effective;XXXXX
ARIZONA PUBLIC SERVICECOMPANY
Phoenix Arizona
Filed by Charles A Miessner
Title Manager. Regulation and Pricing
OriginalEffectiveData XXXX
Page 6 of 7
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix L
76295
DECISION NO.
DOCKET NO. E-01345A-16-0036 ET AL.
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76295DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix M
76295DECISIONno.i
DOCKET NO. E-01345A-16-0036 ET AL.Appendix M
Page 1 of 20
Gaps SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
Terms and Conditions l
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The following Terms and Conditions and any changes authorized by law will apply to
Standard Offer and Direct Access services made available by Arizona Public Service
Company (APS or Company). These Terms and Conditions are considered a part of all rate
schedules, except where specifically excluded or changed by a written agreement. For a
Customer whose service requirements are of unusual size or characteristics, additional or
special contract arrangements may be required. If there is a conflict between any provision
of a rate schedule and these Terms and Conditions, the provisions of the rate schedule
apply.
1.Application for Service
Before supplying service APS will verify the identity of Applicant. Applicants may be
required to appear at Company's place of business to produce proof of identity, sign
an application, or execute a contract for service before APS supplies service. If there is
no signed application or contract for service, APS's standard contract terms apply and
the supplying of Standard Offer or Direct Access services and Customer's acceptance
of service forms a service agreement between APS and the Customer for delivery,
acceptance, and payment for services.
1.1 Grounds for Refusal of Service- APS may refuse service if any of the following
conditions exist:
(A)The Applicant has an outstanding amount due with APS for the same class of
service and is unwilling to make payment arrangements that are acceptable to
Company.
(B) A condition exists that in Company's judgment is unsafe or hazardous.
(C) The Applicant has failed to meet APS's security-deposit requirements outlined
in Section 3.
(D) The Applicant is known to be in violation of a Company Tariff.
(E) The Applicant fails to furnish the funds, service, equipment, rights-of-way or
Easements required to serve die Applicant and that have been specified by APS
as a condition for providing service.
(F) The Applicant falsifies his or her identity for the purpose of obtaining service.
(G) Service is already being provided at the address for which the Applicant is
requesting service.
(H) Service is requested by an Applicant, and a prior Customer, who will reside at,
or benefit from service at the premises, owes APS a delinquent bill for the same
class of service, from the same or a prior service address.
(I) The Applicant has failed to obtain any required permit or inspection indicating
that the Applicant's facilities comply with current local construction and safety
codes.
A.C.C. No.xxxx
Canceling A.C.C. No. 5804
Service Schedulel
Revision No. 36
Effective:xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix,Arizona
Filed by: Charles A. Micssner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 1 of 20
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.Appendix M
Page 2 of 20
E Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
2.
n
Service-Establishment Charges
A ServiceEstablishment Charge of $8.00 for residential or $33.00 non-residential plus
applicable adjustments will be assessed each time APS is asked to establish or
re-establish electric service, or to make a special read without a disconnect and
calculate a bill for a partial month.
2.1Multiple Connects - If multiple connects are performed during the same site visit,
in the same Applicant name, at the same address, and for the same class of service,
APS will assess the Service-Establishment Charge once for every two Delivery
Points.
2.2 After-hours Charge -The Customer must also pay an after-hours charge plus
applicable adjustments if the Customer requests service, as defined in A.A.C. R14-
2-203.D.3, be established or re-established after 5:00 p.m. on a day other than the
day of request. The after-hours charge will be $8.00 for residential with standard
metering, $137.00 plus applicable adjustments for residential with non-standard
metering or $164000 plus applicable adjustments for non-residential.
2.3 Same-DayConnect Charge - The Customer must also pay a same-day connect
charge of $87.00 plus applicable adjustments if the Customer requests service, as
defined in A.A.C. R14-2-203.D.3, be established or re-established on the same
business day the request is being made, and APS agrees to work the request on the
same day of the request. This will be charged regardless of the time the order may
be worked by APS on that day. APS may, where no additional costs are incurred
by Company, waive the same-day fee.
2.4 Non-Standard Service Request Charge -The Customer must also pay $164.00 plus
applicable adjustments per crew-person per hour when Customer requests services
that do not meet the definition of Service-Establishment as defined in A.A.C. R14-
2-203.D.2> and that require the availability of Company representatives after-hours,
on a weekend day, or on a Company holiday. Examples of non-standard service
requests are Customer-requested outages for maintenance and metering-
equipment installations that include instrument transformers. The number of
representatives used by APS to fulfill a request is in the Company's sole discretion.
Customers will be given notice of estimated charges before the work is performed.
2.5Waiving of Service Establishment Charge - Company may waive the Service-
Establishment Charge if:
(A) The establishment of service is effective with the last Meter read date billed
and a field trip is not required because Applicant accepts responsibility for
energy billed and not yet paid.
(B) Applicant has an active Landlord Automatic Transfer of Service Agreement on
file with Company.
A.C.C. No. xxxx
Canceling A.C.C. No. 5804
Service Schedule 1
Revision No. 36
Effective: xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:CharlesA.Miessner
Title: Manager, Regulation and Pricing
Original Effective Date: December 1951
Page 2 of 20
76295DECISION no.
DOCKET no. E-01345A_16-0036 ET AL.Appendix M
Page 3 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
3.
8i
Establishing Credit, Security Deposits and other forms of Credit Assurance
When credit cannot be established as provided for in Section 3.1 and 3.2 or when it is
determined that the Applicant left an unpaid final bill owed to another utility
company, the Applicant will be required to place a security deposit to secure payment
of bills for service.
3.1Residential Establishment of Credit - APS will not require a security deposit from
a new Applicant for service at a primary or secondary residence if the Applicant
can meet any of the following requirements:
(A) The Applicant has had service of a comparable nature with APS within the
past two years and was not delinquent in payment more than twice during the
last 12 consecutive months or been disconnected for nonpayment.
(B) Company receives an acceptable credit rating, as determined by Company, for
the Applicant from a credit-rating agency used by Company.
(C) The Applicant can produce a letter regarding verification of credit from an
electric utility where service of a comparable nature was last received within
six months of the current date, and the utility states that the Applicant had a
timely payment history for the prior 12 consecutive months.
(D)If in lieu of a security deposit, Company receives an acceptable deposit-
guarantee notification from a social or governmental agency or a surety bond
in a sum equal to the required deposit.e
3.2 Nonresidential Establishment of Credit - All nonresidential Applicants will be
required to place a cash deposit to secure payment of bills for service, unless:
(A) The Applicant had service of a comparable nature with Company within the
past two years and was not delinquent in payment more than twice during the
last 12 consecutive months and was not disconnected for nonpayment.
(B) The Applicant provides a noncash security deposit in the form of a surety
bond, irrevocable letter of credit, or assignment of monies in an amount equal
to the required security deposit.
3.3 General Deposits Guidelines- If a security deposit is required, a separate deposit
may be required for each service location.
(A) Customer's security deposits will not preclude Company from terminating an
agreement for service or suspending service if Customer fails to meet service-
agreement obligations.
(B) Company may choose to accept less than the full deposit required at time of
service establishment based on Customer's financial condition.
(C) A security deposit may increase or decrease if the Customer's average
consumption increases or decreases by more than 10% for residential accounts
A.C.C.No. xxxx
Canceling A.C.C. No. 5804
Service Schedule 1
Revision No.36
Effective: xxxxxx xxxx
ARIZONA putIc SERVICE COMPANY
Phoenix, Arizona
Filed by: Charles A.Miessner
Title:Manager Regulation and Pricing
Original Effective Date: December 1951
Page 3 of 20
76295
DECISION no.
DOCKET no. E-01345A-I6-0036 ET AL.Appendix M
Page 4 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
or 5% for nonresidential accounts within 12 consecutive months and credit has
not been established.
(D) Where three or more additional residential services are requested, Company
may require Customer to establish or reestablish a security deposit.
3.4 Residential Security Deposits- Residential security deposits will not exceed two
times the Customer's average monthly bill as estimated by Company. APS may
require a residential Customer to establish or reestablish a security deposit if the
Customer becomes delinquent in the payment of two or more bills widiin a 12
consecutive month period or has been disconnected for non-payment during the
last 12 months.
3.5 Nonresidential Security Deposits- Nonresidential security deposits will not
exceed two and one-half times the Customer's maximum monthly billing as
estimated by Company. APS may require a nonresidential Customer to establish
or reestablish a security deposit if the Customer becomes delinquent in die
payment of two or more bills within 12 consecutive rondos or if the Customer has
been disconnected for nonpayment during the last 12 months, or when the
Customer's financial condition may jeopardize the payment of the bill, as
determined by Company based on the results of using a credit-scoring worksheet.
Company will inform all Customers of the Arizona Corporation Commission's
complaint process should the Customer dispute the deposit based on the financial
data.
3.6 Deposit Interest - Cash deposits held by APSsix months (183 days or longer)
earn interest from the date the deposit was collected at the established one-year
Treasury Constant Maturities rate, effective on the first business day of each year,
as published on the Federal Reserve Website.
3.7 Deposit Refunds - If the Customer terminates all service with Company, their
security deposit may be credited to any remaining final bills. Any remaining
credit balance will be refunded to the Customer of record within 30 days.
3.8 Residential security deposits or other instruments of credit will automatically
expire or be credited or returned to the Customers account after 12 consecutive
months of service, if the Customer has not been delinquent in payments more
than twice and the Customer has not filed bankruptcy in the last 12 months.
(A) Nonresidential security deposits and noncash deposits on file with Company
will be reviewed after 24 months of service and will be returned if:
(1) The Customer has not been delinquent in payments more than twice, has
not been disconnected for non-payment, and has not filed for bankruptcy
during the previous 12 consecutive months; and
(2) Customer's financial condition does not warrant an extension of the
security deposit.
A.C.C. No. xxxx
Canceling A.C.C. No. 5804
Service Schedule1
RevisionNo.36
Effective: xxxxxx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Micssncr
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 4 of 20
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix M
Page 5 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
4.Rates
The Customer's service characteristics and service requirements determine the
selection of the applicable rate schedule.
4.1Rate Selection - APS will use reasonable care in initially establishing service to the
Customer under the most advantageous rate schedule applicable to the Customer.
Because of varying Customer usage patterns and other reasons beyond APSs
reasonable knowledge or control, Company cannot guarantee that the most
economic applicable rate will be applied. APS will not make any refunds in any
instance where it is determined that the Customer would have paid less for service
had the Customer been billed on an alternate rate or provision of that rate.
4.2 Rate Information - APS will provide, in accordance with A.A.C. R14-2-204, a copy
of any rate schedule applicable to the Customer for the requested type of service.
In addition, APS will notify its Customers of any changes in Company Tariff
affecting those Customers.
4.3 Optional Rates - Optional rate schedules are available for certain classes of service.
After establishing service a Customer may choose an alternate rate schedule
effective from the next regularly scheduled Meter reading, after the appropriate
metering equipment is deprogramed or installed. No further rate schedule changes
may be made within the succeeding 12 month period. If the rate schedule or
contract under which the Customer is provided service specifies a term, the
Customer may not exercise its option to select an alternate rate schedule until
expiration of that term.'
5.Billing
Billing Periods for service normally consist of approximately 30 days unless otherwise
designated under rate schedules, through contractual agreement, or at Company
option.
5.1 Payment of Bills - The Customer is responsible for paying bills until service is
ordered discontinued and Company has had reasonable time to secure a final
Meter reading for those services involving energy usage, or, if nonmetered services
are involved, until Company has had reasonable time to process the disconnect
request.
5.2Failure to Receive Billsor Notices (including notices of disconnection) which have
been properly placed in the United States mail or sent through alternative billing
forms, such as electronic mail, will not prevent such bills from becoming
delinquent or prevent the notices from being effective, or relieve the customer of
their obligations.
5.3 Incentive for Electronic Payments- A monthly incentive of $0.48 per Customer
will be given to Customers who elect to pay their bills using the Company's
electronically transmitted payment options AutoPay, PrePay or similar programs.
A.C.C. No. xxxx
Canceling A.C.C. No. 5804
ServiceSchedule 1
Revision No. 36
Effective: xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page5of 20
76295
DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.Appendix M
Page 6 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
5.6
5.4 BillingErrors - When an error is found in the billing sent to the Customer, APS
will correct the error to recover or refund the difference between the original
billing and the correct billing. Adjusted billings will not be sent for periods beyond
the applicable statute of limitations from the date the error is discovered.
5.5 CorrectedCharges for Overbilling- Refunds or credits to Customers resulting
from overbillings will be made promptly upon discovery by Company.
Corrected Charges for Underbilling- Except as specified below, corrected
charges for underbillings will be limited to three months for residential accounts
and six months for nonresidential accounts. Customers will be given an equal
length of time, such as the number of months underbilled, to pay the backfill
without late-payment penalties. Where the account is billed on a special contract
or nonmetered rate, corrected charges for underbillings will be billed in
accordance with the contract or rate-schedule requirements and is not limited to
three or six months as applicable.
(A) Where service has been established but no bills have been rendered, corrected
charges for underbillings will go back to the date service was established.
(B) Where there is evidence of Meter Tampering or energy diversions, corrected
charges for underbillings will go back to the date Meter Tampering or energy
diversions began, as determined by Company, and APS is not required to give
an equal length of time, such as the number of months underbilled, to pay the
backfill. APS will work with Customer to establish a payment plan that is
acceptable to Company.
(C) Where lack of access to the Meter (caused by the Customer) has resulted in
estimated bills, corrected charges for underbillings will go back to the Billing
Month of the last Company-obtained Meter-read date.
(D) Where actual Customer usage can be determined without estimating reads,
corrected charges for underbillings are not limited to three or six months, as
applicable. In no event may such rebilling exceed the applicable statute of
limitations.
5.7 Company may forgo correcting a billing error if the amount over or under billed is
de minims and the cost of rebilling does not justify the cost and time required to
refill.
6.Collection Policy
The following collection policies apply to all Customer accounts:
6.1 Delinquent Bills- All bills rendered by Company are due and payable no later
than 15 calendar days from the billing date. Any payment not received within this
time frame are delinquent. All delinquent accounts, for which payment has not
been received, are subject to the provisions of Companys termination procedure.
A.C.C.No.xxxx
CancelingA.C.C. No.5804
Service Schedule 1
Revision No. 36
Effective: xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 6 of 20
76295
DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
I Appendix M
Page 7 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
Q
Company may suspend or terminate a Customer's service for nonpayment of any
Arizona Corporation Commission approved charges.
6.2 LateCharges - All delinquent charges, including past due security deposits, are
subject to a late charge at the rate of 18% per annum (1.5% per month) plus
applicable adjustments.
6.3 Transfer of Outstanding Bills- If a Customer has two or more services with APS
and one or more services are terminated for any reason leaving an outstanding bill,
and the Customer is unwilling to make payment arrangements that are acceptable
to Company, Company may transfer the balance due on the terminated service to
any other active account of the Customer for the same class of service. The
Customer's failure to pay the active account will result in the suspension or
termination of service. If service is requested by two or more individuals,
Company has the right to collect the full amount owed from any one of the
Customers.
6.4Dishonored Payments- If Company is notified by the Customer's financial
institution that it will not honor a payment tendered by the Customer for payment
of any bill, Company may require the Customer to make payment in cash, or by
money order, certified or cashier's check, or other means that guarantee the
Customer's payment to Company.
(A) The Customer will be charged a fee of $15.00 plus applicable adjustments for
each instance where the Customer's payment is not honored by the Customer's
financial institution.
(B) The tender of a dishonored payment in no way relieves the Customer of the
obligation to pay Company under the original terms of the bill, or defers the
Company's right to terminate service for nonpayment of bills.
(C) Where the Customer has tendered two or more dishonored payments in the
past 12 consecutive months, Company may require the Customer to make
payment in cash, or money order or cashier's check for the next 12 consecutive
months.
6.5 CollectionAgency Referrals All unpaid delinquent final bills may be referred to
a collection agency for collection. If collection-agency referral is warranted,
Customer may be responsible for the associated collection-agency fees incurred.
7.Termination ofService
7.1 To avoid termination of service, the Customer will make payment in full, including
any necessary deposit as outlined in Section 3, or make payment arrangements that
are satisfactory to Company.
7.2 If service is terminated, APS will not restore service until the conditions which
resulted in the termination have been corrected to the satisfaction of Company.
A.C.C.No. xxxx
CancelingA.C.C.No. 5804
Service Schedule 1
RevisionNo.36
Effective: xxxx xx,xxxx
AR12ONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 7 of 20
76295DECISION no.
DOCKET no. E-01345A-l6-0036 ET AL.Appendix M
Page 8 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
APS may also require payment of Same-Day and After-Hours charges prior to
restoring service
7.3 Termination of ServiceWithNotice - APS may, without liability for injury or
damage, and without making a personal visit to the site, disconnect service to any
Customer for any of the reasons stated below, if Company has met the notice
requirements established by the Arizona Corporation Commission:
(A) Customer's violation of any applicable rules of the Arizona Corporation
Commission or Company Tariff.
(B) A Customer's failure to pay a Delinquent Bill for services provided by
Company.
(C) The Customer's breach of a written contract for service.
(D) The Customer's failure to comply with Company's deposit requirements.
(E) The Customer's failure to provide Company with satisfactory and unassisted
access to Company's equipment.
(F) When necessary to comply with an order of any governmental agency having
jurisdiction.
(G) A prior Customer's failure to pay a Delinquent Bill for utility services where
the prior Customer continues to reside on the premises.
(H) Failure to provide or retain rights-of-way or Easements necessary to serve the
Customer.
(I) Company leads of the existence of any condition in Section 1.1 - Grounds For
Refusal of Service.
7.4Terminationof ServiceWithoutNotice - Company may, without liability for
injury or damage, disconnect service to any Customer without advance notice
under any of the following conditions:
(A) If Company observes, or has evidence of, a hazard to the health or safety of
persons or property;
(B) If Company has evidence of Meter Tampering or fraud.
(C) If Company has evidence of unauthorized resale or use of electric service.
(D)The Customer fails to comply with the curtailment procedures imposed by
Company during a supply shortage.
7.5 Termination of Service for Dishonored Payment- Before reconnecting service,
payment of funds resulting from a dishonored payment and all other delinquent
amounts will be required in cash, money order, or certified funds. If Customer has
already received a notice of disconnection at the time the bill became past due, APS
may, without liability for injury or damage, disconnect service without additional
notice under any of the following conditions:
(A)When Customer makes payments to avoid or stop disconnection with a
dishonored payment and has already received a notice at the time the bill
became past due.
A.C.C. No. xxxx
Canceling A.C.C.No. 5804
Service Schedule1
Revision No. 36
Effective: xxxx xx, xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 8 of 20
76295DECISION no.
DOCKET no. E-0i345A-16-0036 ET AL.AppendixM
Page 9 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
(B)When Customer pays to reconnect service with a dishonored payment and has
already received a notice at the time the bill became past due.
7.6 TerminationProcess Charges- Company will require payment of a Field Call
Charge of $10.00 plus applicable adjustments when an authorized Company
representative travels to the Customer's site to accept payment on a delinquent
account, notify of service termination, make payment arrangements, or terminate
the service. This charge only applies for field calls resulting from the termination
process.
(A) If a termination is required at the pole the reconnection charge will be $89.00
plus applicable adjustments.
(B) If a termination is in underground equipment the reconnection charge will be
$135.00 plus applicable adjustments.
8.Metering & Metering Equipment
8.1 Standard Metering - The Company's standard method of measuring energy usage
is through the use of Automated Metering Infrastructure (AMI) metering
equipment. All customers will be served using the Company's standard metering
equipment unless:
(A) the customer is in a remote location where wireless technology is not available
or AMI equipment cannot otherwise be used; or
(B) the customer meets all eligibility requirements for non-standard metering and
voluntarily requests non-standard metering.
8.2 Non-Standard Metering - The Company's non-standard billing meter is the digital
meter. A digital meter records energy electronically and displays the usage
measurements. This meter does not employ any communications technology and
must be read manually each month. Certain optional rates may not be available to
customers who select a non-standard meter.
8.3Non-Standard Metering Eligibility- Only residential customers, in whose name
service is being provided, may request non-standard metering. Customers who
have an existing, purchased or leased rooftop solar distributed generation (DG)
system, or customers with newly installed rooftop solar, are not eligible for non-
standard metering.
8.4 Non-Standard Metering Charges -The following charges will apply when a
customer voluntarily requests, and is granted, non-standard metering as described
in Section 8.1(B):
(A) Monthly Meter Reading Charge: $5.00
(B) Non-Standard Metering Set-up Fee: A $50.00 one-time charge for customerswith
existing AMI meter.
A.C.C.No. xxxx
CancelingA.C.C. No.5804
Service Schedule 1
RevisionNo.36
Effective:xxxx xx, xxxx
ARIZONA PUBLIC SERVICF COMPANY
Phoenix Arizona
Filedby:CharlesA.Miessner
Title: Manager Regulation and Pricing
Original EffectiveDate: December1951
Page 9 of 20
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix M
Page 10 of 20
Gaps SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
¢
(C) Customers in a remote location where wireless technology is not available or
AMI equipment cannot otherwise be used [see 8.1(A)] will not be billed a non-
standard meter reading charge.
8.5Discontinuation of Non-Standard Metering- The Company may replace a non-
standard meter with a standard meter, without notifying the customer prior to
replacement, under any of the following conditions:
(A) Company employees observe or have evidence of a safety hazard to
employees, customers, or Company or customer property.
(B) Company employees observe or have evidence of meter tampering, energy
diversion, or fraud.
(C) Company has evidence of unauthorized resale of electricity.
(D) Company employees have received verbal or physical threats, including, but
not limited to, verbal threats while installing meters or performing
maintenance to Company equipment, and physical threats such as weapons or
dogs.
(E) All terms and conditions in Section 7, regarding termination of service, will
also apply.
8.6 Measuring Customer Service - All energy sold to the Customer by Company will
be measured by commercially acceptable measuring devices. Where it is
impractical to meter loads, such as street lighting, security lighting, or special
installations, consumption will be determined by Company. The readings of the
Meter will be conclusive as to the amount of electric power supplied to the
Customer unless there is evidence of Meter Tampering or energy diversion or
unless a test reveals the Meter is in error by more than 3%, either fast or slow.
8.7Meter Rereads- When requested by Customer, APS will reread the customer's
Meter within 10 working days after die request. The cost of each reread is $14.00
plus applicable adjustments if the original reading was not in error.
8.8 Meter Testing - APS tests its Meters regularly in accordance with a Meter testing
and maintenance program approved by the Arizona Corporation Commission.
APS will individually test a Company owned and maintained Meter upon
Customer request.
If after testing, a Meter is found to be more than 3% in error, either fast or slow,
correction will be made of previous readings and adjusted bills will be rendered.
8.9 Meter Test Charge- If the Meter is found to be within the plus or minus 3% limit,
Company may charge the Customer $44.00 plus applicable adjustments for Meter
test if the Meter is removed from the site and tested in the meter shop, or $93.00
plus applicable adjustments if the Meter remains on site andistested in the field.
8.10 Meter Tampering- If there is evidence of Meter Tampering or energy diversion,
the Customer, person, or entity demonstrated to have tampered with the Meter,
or benefited from the tampering or diversion will be billed for the estimated
A.C.C. No. xxxx
CancelingA.C.C. No.5804
ServiceSchedule 1
Revision No. 36
Effective: xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 10 of 20
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.Appendix M
Page 11 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
energy and, if applicable, Demand, for the period in which the energy diversion
took place. Additionally, where there is evidence of Meter Tampering, energy
diversion, or by-passing the Meter, the Customer, person or entity demonstrated
to have tampered with the Meter or diverted energy will also be charged the cost
of the investigation as determined by Company.
9.Service Installations & Metering- The Custolner's service installation will normally
be arranged to accept only one type of service at one Point of Delivery to enable
service measurement through one Meter. If the Customer requires more than one type
of service, or total service cannot be measured through one Meter according to
Company's regular practice, separate Meters will be used and separate billing
rendered for the service measured by each Meter.
9.1 Customer Equipment - The Customer must install and maintain all wiring and
equipment beyond the Point of Delivery except for Company's Meters and special
equipment. The Customer's entire installation must conform to all applicable
construction standards and safety codes, and the Customer must furnish an
inspection or permit if required by law or by Company. In circumstances where a
clearance is not required by law, Company may require Customer to execute a
Letter In-Lieu of Electrical Clearance. The Customer must also provide, in
accordance with APS's current service standards and Electric Service Requirements
Manual, at no expense to Company, and close to the Point of Delivery, a space that
is, in the Company's opinion, both suitable and sufficient for installing, accessing
and maintaining Company's metering equipment. A current version of the Electric
Service Requirements Manual is available on-line on the Company's website.
9.2Special Meter-ReadingDevice - Where a Customer requests, and Company
approves, a special Meter-reading device or communications services or devices to
accommodate the Customers needs, the cost for the additional equipment and
usage fees are the Customer's responsibility.
9.3 Totalized Metering and Billing- Company normally meters and bills each site
separately. But, at Customer's request, adjacent and contiguous sites (not
separated by private or public property or right of way), operated as one integral
unit under the same name and as a part of the same business, may at Company's
option, be considered a single site as specified in Companys Schedule 4, Totalized
Metering of Multiple Service Entrance Sections at a Single Site for Standard Offer
and Direct Access Service.
9.4 ServiceConnections- Company is not required to install or maintain any lines
and equipment on the Customer's side of the Point of Delivery except its Meter.
(A) For overhead service, the Point of Delivery is where Company's service
conductors terminate at the Customer's weadrerhead or bus rider.
A.C.C. No xxxx
Canceling A.C.C. No. 5804
Service Schedulel
RevisionNo.36
Effective:xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix,Arizona
Filed by:CharlesA.Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 11 of 20
76295
DECISION no.
DOCKET no. E-01345A-l6-0036 ET AL.Appendix M
Page 12 of 20
G ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
(B)For underground service, the Point of Delivery is where Company's service
conductors terminate in the Customer's or development's service equipment.
The Customer must furnish, install, and maintain any risers, raceways, or
termination cabinet necessary for installing Company's underground service
conductors.
(C) For special Applications where service is provided at voltages higher than the
standard voltages specified in the Electric Service Requirements Manual, the
designated Point of Delivery must be mutually agreed on by the parties.
(D) For the mutual protection of the Customer and Company, only authorized
employees or agents of Company or the Load Sewing ESP are permitted to
make and energize the connection between Company's service wires and the
Customer's service entrance conductors. APS employees mustcarry Company-
issued identification that they will show on request.
10.Customer Obligations .
10.1 Load Characteristics - The Customer must exercise reasonable care to ensure that
the electrical characteristics of its load, such as deviation from sine-wave form (a
minimum standard is IEEE 519) or unusual short interval fluctuations in Demand,
do not impair service to other Customers or interfere with operating any
telephone, television, or other communication facilities. Customer must meet
power factor requirements as specified in the applicable rate schedules.
10.2 Easements - All suitable Easements or rights-of-way required by Company for
any portion of an extension to serve a Customer, which is either on sites owned,
leased, or otherwise controlled by the Customer or developer, or other property
required for the extension, will be furnished in Company's name by the Customer
without cost to or condemnation by Company and in reasonable time to meet
proposed service requirements. All Easements or rights-of-way granted to, or
obtained on behalf of Company will contain terms and conditions that are
acceptable to Company. When Company discovers that the Customer or the
Customer's agent is performing work, has constructed facilities, or has allowed
vegetation to grow,adjacent to or within an Easement or right-of-way or
Company-owned equipment, and the work, construction, vegetation, or facility
poses a hazard, or violates federal, state, or local laws, ordinances, statutes, rules,
or regulations, or significantly interferes with Company's safe use, operation, or
maintenance of, or access to, equipment, or facilities, Company will notify the
Customer or the Customer's agent and take whatever actions are necessary to
eliminate the hazard, obstruction, interference, or violation at the Customer's
expense. Company will notify the Customer in writing of the violations.
10.3 Access for Repair, Maintenance and Service Restoration- Company's audiorized
agents must have satisfactory unassisted 24 hour a day, seven days a week access
A.C.C.No. xxxx
CancelingA.C.C.No. 5804
ServiceSchedule 1
RevisionNo.36
Effective: xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 12 of 20
76295DECISIONno.
DOCKET NO. E-01345A-l6-0036 ET AL.Appendix M
Page 13 of 20
\lQ ops 1
SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
I
to Company's equipment located on Customer's sites for the purpose of repair,
maintenance, and service-restoration work that Company may need to perform.
10.4Access for Install, Inspect, Read, or Remove - Company's authorized agents
must have satisfactory unassisted access to the Customer's sites at all reasonable
hours to install, inspect, read, or remove its Meters or to install, operate, or
maintain other Company property, to verify that Customer is in compliance with
its obligations, or to inspect and determine the connected electrical load.
10.5Trip Charge - A trip charge of $22.00 for residential or $26.00 for non-residential,
plus applicable adjustments will be assessed each time an authorized Company
representative travels to a site and is unable to complete a Customer's service
request because of lack of access to die Point of Delivery.
10.6 Six Months No Access - If Company, in its opinion, does not have satisfactory
unassisted access to the Meter after six months (not necessarily consecutive) of
good-faith efforts to work with the Customer, then Company has sufficient cause
to terminate service or deny any rate options where, in Company's opinion, access
is required.
10.7 Remedies - The remedy for unassisted access will be at APS's discretion and may
include the installation by Company of a specialized Meter. If a specialized Meter
is installed, the Customer will be billed the difference between the otherwise
applicable Meter for Customer's rate and the specialized Meter plus the cost
incurred to install the specialized Meter as a one-time charge and any reoccurring
incremental costs. If service is terminated as a result of failure to provide
unassisted access, APS verification of unassisted access will be required before
service is restored. Written termination notice is required before disconnecting
service under this section.
11.Company Obligations
11.1 Customer-Specific Information - Customer-specific information will not be
released without Customer's specific prior written authorization unless the
information is requested by a law-enforcement or other public agency, or is
requested by the Arizona Corporation Commission or its staff, or is reasonably
required for legitimate account-collection activities, or is necessary to provide
efficient, effective, safe, or reliable service to the Customer. Customer-specific
information may be provided to suppliers of goods or services under contract
with Company if the goods or services will help Company to provide efficient,
effective, safe, or reliable service; and the contract includes a requirement that
the information be kept confidential and be used only to fulfill the suppliers
obligations to Company.
11.2 Service Voltage -Company will deliver electric service to the designated Point of
Delivery, as specified in Section 9.4 of this Schedule, at the standard voltages
A.C.C. No. xxxx
Canceling A.C.C. No. 5804
Service Schedule1
Rvision No. 36
Effective:xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:Charles A.Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 13 of 20
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.Appendix M
Page 14 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
specified in the Company's Electric Service Requirements Manual and as
specified in A.A.C. R14-2-208.F. Company may deliver service for special
applications at higher voltages, with prior approval from Company's
Engineering Department and in accordance with Company's Schedule 3,
Conditions Governing Extensions of Electric Distribution Lines and Services
approved by the Arizona Corporation Commission.
12.Limitations on Liability of Company
12.1Service Interruptions - Company is not liable to the Customer for any damages
caused by Load Serving Electric Service Provider's equipment or failure to
perform, fluctuations, interruptions, or curtailment of electric service, except
where caused by Company's willful misconduct or gross negligence.
(A) Company may, without incurring any liability, suspend the Customer's
electric service for periods reasonably required to permit Company to
accomplish repairs to, or changes in, any Company's facilities.
(B) The Customer is responsible for protecting Customer's own sensitive
equipment from harm caused by variations or interruptions in power supply.
(C) If a national emergency or local disaster results in disruption of normal
service, Company may, in the public interest and on behalf of Electric Service
Providers or Company, interrupt service to other Customers to provide
necessary service to civil-defense or odder emergency-service agencies on a
temporary basis until normal service to these agencies can be restored.
12.2 Useof Service or Apparatus - The Customer will save Company harmless from
and against all claims for injury or damage to persons or property occasioned by
or in any way resulting from the services being provided by Company or their
use on the Customer's side of the Point of Delivery. Company has the right to
suspend or terminate service if Company leads of service use by the Customer
under hazardous conditions.
(A) The Customer will exercise all reasonable care to prevent loss or damage to
Company property installed on the Customer's site for the purpose of
supplying service to the Customer. The Customer is responsible for payment
for loss or damage to Company property on the Customer's site arising from
neglect, carelessness, or misuse, and will reimburse Company for the cost of
necessary repairs or replacements.
(B) The Customer is responsible for payment of any equipment damage or
estimated unmetered usage resulting from unauthorized brealdng of seals,
interfering with, tampering with, or by-passing the Meter.
(C) The Customer is responsible for notifying APS of any failure in Company's
equipment.
A.C.C. No. xxxx
Canceling A.C.C. No. 5804
Service Schedule 1
Revision No. 36
Effective: xxxx xx, xxxx
ARIZONA l'UBLlC SERVICE COMPANY
Phoenix,Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 14 of 20
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix M
Page 15 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
12.3 Removal of Facilities- Upon termination of service, Company may, without
liability for injury or damage, dismantle and remove its facilities, installed for the
purpose of supplying service to the Customer, and Company will have no
further obligation to serve the Customer.
13.Successors and Assigns - Agreements for Service are binding on and for the benefit of
the successors and assigns of the Customer and Company, but no assignments by the
Customer are effective until the Customer's assignee agrees in writing to be bound and
until the assignment is accepted in writing by Company.
14.Warranty - There are no understanding, agreements, representations, or warranties ,
expressed or implied (including warranties regarding merchantability or fitness for a
particular purpose), not specified here or in the applicable rules of the Arizona
Corporation Commission concerning the sale and delivery of services by Company to
the Customer. These Terms and Conditions and the applicable rules of the Arizona
Corporation Commission state the entire obligation of Company in connection with
sales and deliveries.
15.
n
Direct Access Service - NOTE:Retail Electric Competition is currently on hold in APS
Senfice Territory.
15.1 Direct Access Service Request (DASR)- A Direct Access Service Request charge
of $10.00 plus any applicable adjustments will be assessed to the Electric Service
Provider (ESP) submitting the DASR each time Company processes a Request
(RQ) type DASR as specified in Company's Schedule 10, Terms and Conditions
for Direct Access.
15.2 Direct Access Service - Direct Access Service will be effective upon the next Meter
read date if DASR is processed 15 calendar days before that read date and the
appropriate metering equipment is in place. If a DASR is made less than 15
calendar days before the next regular read date, the effective date will be at the
next Meter read date. The above timeframes are applicable for Customers
changing their selection of ESP or for Customers returning to Standard Offer
service.
(A) Any Customer that selects Direct Access service may return to Standard Offer
service in accordance with the rules, regulations, and orders of the Arizona
Corporation Commission. The Customer will not be eligible for Direct Access
service for the succeeding 12 months.
(B) If a Customer returning to Standard Offer, in accordance with the rules,
regulations and orders of the Commission, was not given the required
notification in accordance with the rules and regulations of the Commission
by their Load Serving ESP of its intent to cease providing competitive services
A.C.C. No. xxxx
CancelingA.C.C. No.5804
ServiceSchedule 1
Revision No. 36
Effective: xxxxxx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:Charles A. Micssncr
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 15 of 20
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix M
Page 16 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
1
l
then the above provision will apply only if the Customer fails to select another
ESP within 60 days of returning to Standard Offer service.
(C) Unpaid charges incurred before the Customer selects Direct Access will not
delay the Customer's request for Direct Access. These charges remain the
responsibility of the Customer to pay. Normal collection activity, including
discontinuing service, may result from failure to pay.
(D) Where the ESP is the MSP or MRSP, and the ESP or its' agent fails to provide
Me Meter data to Company under Company's Schedule 10 Section 8.16, Meter
Reading Data Obligations, Company may, at its option, obtain the data or
estimate the billing determinants.
(E) Where Company is the MRSP, Company will, at the request of the Customer
or the ESP, reread or test the Customer's Meter within 10 working days after
the request. The cost of each reread or test may be applied to the Customer or
ESP when applicable.
(F) All energy sold to the Customer by MRSP will be measured by commercially
acceptable measuring devices and under the terms and conditions of
Company's Schedule 10 - Terms and Conditions for Direct Access.
15.3 Direct Access Deposits - If the Customer chooses to change from Standard Offer
to Direct Access services, the deposit may be decreased by an amount that reflects
the portion of the Customer's service being provided by a Load Serving ESP. If
the Load Serving FSP is providing ESP Consolidated Billing under Company's
Schedule 10 Section 7, the entire deposit will be credited to the Customer's
account; or, if the Customer chooses to change from Direct Access to Standard
Offer service, the requested deposit amount may be increased by an amount
under Section 3.3 which reflects that Company is providing bundled electric
service.
15.4 Direct Access and Company Equipment
(A) Meters - A Meter Service Provider (MSP) or its authorized agents may remove
Company's metering equipment under Company's Schedule 10 Terms and
Conditions for Direct Access. Meters not returned to Company or returned
damaged will result in charge to the MSP of the replacement costs, plus an
administration fee of 15%, less five year's depreciation.
(B) Lock-rings - Company will lease lock-ring keys to MSP'sor their agents who
are authorized to remove Company Meters under the terms and conditions of
Company's Schedule 10 at a refundable charge of $70.00 plus applicable
adjustments per key. The charge will not be refunded if a key is lost, stolen, or
damaged. If Company must replace 10% of the issued keys within any 12
month period because of loss by the MSP'sagent, Company may, rather than
leasing additional lock ring keys, require the MSP to arrange for a joint
A.C.C. No. xxxx
Canceling A.C.C. No. 5804
Service Schedule 1
RevisionNo.36
Effective: xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 16 of 20
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix M
Page 17 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
meeting. All lock-ring keys must be returned to Company within five
working days if the MSP or its authorized agents are:
No longer permitted to remove Company Meters under the conditions of
Company's Schedule 10;
(1)No longer authorized by the Arizona Corporation Commission to provide
services; or
(2)The ESP Agreement has been terminated.
(C) Site Meetings - If the MSP, the Customer, or the Customers agent requests a
joint site meeting for removal of Company metering and associated
equipment or lock ring, a base charge of $62.00 plus applicable adjustments
per site will be assessed. Company may assess an additional charge of $53.00
plus applicable adjustments per hour for joint site meetings that exceed 30
minutes. If Company must temporarily replace the MSP's Meter or associated
metering equipment during emergency situations or to restore power to a
Customer, the above charges may apply.
DEFINITIONS
¢
Applicant means a person requesting the utility to supply electric service. [A.A.C. R14-2-
201-(2)]
Application means a request to the utility for electric service, as distinguished from an
inquiry as to the availability or charges for such service. [A.A.C. R14-2-201-(3)]
Billing Month means the period between any two regular readings of the utility's Meters
at approximately 30 day intervals. [A.A.C. R14-2-201-(5)]
Billing Periodmeans the time interval between two consecutive Meter readings that are
taken for billing purposes. [A.A.C. R14-2-201-(6)]
Companyholidays(as referred to in section 2.4) are New Year's Day, Martin Luther King
Jr. Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day,
the day after Thanksgiving, and Christmas Day.
Customermeans the person or entity in whose name service is rendered, as evidenced by
the signature on the Application or contract for that service, or by the receipt and/ or
payment of bills regularly issued m his name regardless of the identity of the actual user of
the service. [A.A.C. R14-2-201-(9)]l
l
l
A.C.C. No.xxxx
CancelingA.C.C. No.5804
ServiceSchedule 1
RevisionNo.36
Effective: xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 17 of 20
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix M
Page 18 of 20
Q ops SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
Delinquent Billmeans a bill in which current electric charges are considered pastdue (15
calendar days after the statement date).
Demand means the rate at which power is delivered during any specified period of time.
Demand may be expressed in kilowatts, kilovolt-amperes, or other suitable units. [A.A.C.
R14-2-201-(12)]
DistributionLines means the utility lines operated at distribution voltages which are
constructed along public roadways or other bona fide rights-of-way, including Easements
on Customer's property. [A.A.C. R-14-2-201-(13)]
Easement means a property owner ("Grantor") grants the right to use Me owner's land to
another party. An easement gives Company the right to have Company lines on property
not owned by the Company. This allows Company to build, replace, repair, operate and
maintain electrical equipment for the safe transmission and distribution of electricity. The
Grantor may continue to use the land along the easement within certain limitations.
LandlordAutomatic Transfer of Service Agreementis a legal contract established
between the customer (" Landlord") and Company, that provides continuous and
uninterrupted service to the Landlord during intervals when a Landlord has no tenants. A
Service Establishment Charge will not apply and service will automatically be transferred
into the Landlord's name. Landlord Automatic Transfer of Service Agreements are
available to property owners that have established credit with Company.
Master metermeans a meter used for measuring or recording the flow of electricity that
has passed through it at a single location where said electricity is distributed to tenants or
occupants for their individual usage. [A.A.C. R14-2-201(23)]
Meter means the instrument used for measuring and indicating or recording the flow of
electricity that has passed through it. [A.A.C. Rl4»2-201(25)]
Meter tampering means a situation where a meter has been altered or bypassed without
prior written authorization from Company. Common examples are meter bypassing, use of
magnets to slow the meter recording, and broken meter seals. [A.A.C. R14-2-201(26)]
Minimum chargemeans the amount the customer must pay for the availability of electric
service, including an amount of usage, as specified in the uti.lity's tariffs. [A.A.C. Rl4-2-
201(27)]
A.C.C.No xxxx
CancelingA.C.C. No.5804
Service Schedule1
Revision No. 36
Effective: xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Page 18 of 20
76295DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.Appendix M
Page 19 of 20
Gaps SERVICE SCHEDULE 1
TERMS AND CONDITICNS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
Point of delivery or delivery point means the point where facilities owned, leased, or
under license by a customer connects to the utility's facilities. [A.A.C. R14-2-201(31)]
Tariffs mean the documents filed with the Arizona Corporation Commission which list the
services and products offered by the utility and which set forth the terms and conditions
and a schedule of the rates and charges, for those services and products. [A.A.C. Rl4-2-
201(42)]
Statement of Char es
Char elDescri son
Residential Service Establishment Charge
Reference
2
2Nonresidential Service Establishment Charge
2.2
$8.00
$33.00
$8.00
2.2$137.00
After hours Charge -Residential Standard
Meterin
After hours Charge -Residential Non-Standard
Meterin
After hours Charge -Nonresidential 2.2
2.3
2.4
$164.00
$87.00
$164.00
| -| -
Same Day Connect Charge
Non-Standard Service Request Charge (per crew
son,r hour
Electronically Transmitted Payment Discount
Dishonored Payment Fee
Field Call Charge
5.3
6.4
7.6
7.6
7.6
8.4
-$0.48
$15.00
$10.00
$89.00
$135.00
$5.00
$50.00
8.7
Overhead Reconnection Charge
Underground Reconnection Charge
Non-Standard Metering- Monthly Meter Reading
I\ on-Standard Metering Set-up fee for customer
with existing AMI meter
Meter Reread $14.00
$44.00
$93.00
Meter test in shop
Meter test at site
A.C.C. No. xxxx
Canceling A.C.C.No. 5804
ServiceSchedule 1
RevisionNo.36
Effective: xxxx xx xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:Charles A.Miessner
Title:Manager, Regulation and Pricing
Original EffectiveDate:December 1951
Page 19 of 20
76295
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix M
Page 20 of 20
I Gaps SERVICE SCHEDULE 1
TERMS AND CONDITIONS FOR
STANDARD OFFER AND DIRECT ACCESS SERVICES
10.5
10.5
$22.00
$26.00
Trip Charge - Residential
Trip Charge - Nonresidential
e
A.C.C. No. xxxx
Canceling A.C.C. No. 5804
Service Schedule 1
Revision No. 36
Effective:xxxx xx, xxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: December 1951
Pa Ge 20 of 20
DECISION no.76295
DOCKET NO. E-01345A-16-0_36 ET AL.
1l
l
ll
l
l
\
Appendix N
l
76295DECISION no.
DOCKET NO. E-01345A-I 6-0036 ET AL.
Gaps
Appendix N
sERvicE SCHEDULE page 1 of 26
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
General Description
This schedule establishes the Terms and Conditions under which Company will extend, relocate,
and upgrade its facilities in order to provide service. Provision of electric service from Arizona
Public Service Company (APS or Company) may require construction of new facilities or the
relocation or upgrade of existing facilities. Costs for construction depend on the applicant's
location, scope of project, load size, and load characteristics. Costs include, but are not limited to,
project management, coordination, engineering, design, surveys, permits, construction inspection,
and support services.
AH facility installations and upgrades will be made in accordance with good utility construction
practices, as determined by Company, and are subject to the availability of adequate capacity,
voltage and Company facilities at the beginning point of an extension as determined by
Company.
The following provisions govern the installation of overhead and underground electric
distribution facilities to applicants whose requirements are deemed by Company to be usual and
reasonable in nature.
1.Definitions
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
APS ApprovedElectricalDistributionContractor means an electrical contractor who is
licensed in the State of Arizona and properly qualified to install electric distribution
facilities in accordance with Company standards and good utility construction practices
as determined by Company.
Backbone Infrastructure means the electrical distribution facilities typically consisting
of main three-phase feeder lines and/or cables, conduit, duct banks, manholes,
switching cabinets and capacitor banks.
Conduit Only Design means the conduit layout design for the installation of
underground Extension Facilities that will be required when the Extension Facilities are
to be installed at a later date.
Conversionmeans converting overhead distribution facilities to underground facilities.
Corporate Business and Industrial Park Developmentmeans a tract of land which has
been divided into contiguous lots in which a developer offers improved lots for sale and
the purchaser of the lot is responsible for construction of buildings for commercial or
industrial use.
Doubtful Permanency means a customer who in the opinion of the Company is neither
Permanent nor Temporary. Service which, in the opinion of the Company, is for
operations of a speculative character is considered Doubtfully Permanent.
Economic Feasibility means a determination by Company that the estimated annual
revenue based on Company's then currently effective rate for delivery service (excluding
taxes, regulatory assessment and other adjustments) less the cost of service provides an
adequate rate of return on the investment made by Company to serve the applicant.
Execution Date means the date Company signs the agreement after the applicant has
A.C.C.No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No.13
Effective:XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:Charles A.Miessner
Title: Manager Regulation and Pricing
Original Effective Date:january 31 1954
Page 1 of 26
76295DECISIONno.
DOCKET no. E-01345A-16-0036 ET AL.
Gaps
Appendix N
Page 2 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
signed the agreement and money has been collected by company.
1.9
I
n
1.11
1.12
1.14
1.16
Extension Facilities means the electrical facilities, including conductors, cables,
transformers, and related equipment installed solely to serve an individual applicant, or
groups of applicants. For example, the Extension Facilities to serve a Residential
Subdivision would consist of the line extension required to connect die subdivision to
Company's existing system, as well as Company's electrical facilities constructed within
the subdivision which would include primary and service lines, and transformers.
1.10 High Rise Developmentmeans a building built with four or more floors (usually using
elevators for accessing floors) that may consist of residential or non-residential use, or a
combination of both residential and non-residential uses.
Irrigation means water pumping service.
Line Extension Agreement means the contractual agreement between Company and
applicant that defines applicant payment requirements, terms of refund, scope of
project, estimated costs, and construction responsibilities for Company and the
applicant. Line Extension Agreements may be assigned to applicants successors in
interest with Company approval, which approval will not be unreasonably withheld.
1.13 Master Planned Community Developmentmeans a development dirt consists of a
number of separately subdivided parcels for different Residential Subdivisions. The
development may also incorporate a variety of uses including multi-family, non-
residential, and public use facilities.
Master Meter means a meter for measuring or recording the flow of electricity that has
passed through it at a single location where said electricity is distributed to tenants or
occupants for their individual usage.
1.15 Metro Area means a city with a population of 750,000 or more and its contiguous and
surrounding communities.
Mixed-Use Development means a development that consists of both residential and
non-residential uses, such as a building with three stories or less, where the first level is
for commercial purposes and the upper floors are for residential units, or a development
that includes an apartment complex and a commercial center, or a development that
includes a subdivision and a water treatment plant.
1.17 Permanentmeans a customer who is a tenant or owner of a service location who applies
for and receives electric service, which, in the opinion of the Company, is of a permanent
and established character. The use of electricity may be continuous, intermittent, or
seasonal in nature. Permanency at die service location may be established by such things
as city/county/ state permits, a permanent water system, an approved sewer/ septic
system, or other permanent structures.
1.18 Project-Specific Cost Estimate means cost estimates that are developed recognizing
the unique characteristics of large or special projects to which the Schedule of Charges
is not applicable. A Project-Specific Cost Estimate provided to an applicant is valid for
a period of up to six months from the date the estimate is provided to the applicant.
1.19 Relocationmeans moving a distribution line or facilities from its current location to a
new location.
A.C.C.No.XXXX
CancelingA.C.C. No.5801
Service Schedule 3
Revision No. 13
Effective:XXXXXXXX
ARIZONA PUBLIC suwlcu COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager, Regulation and Pricing
Original Effective Date: January 31 1954
Page 2 of 26
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
AppendixN
Page 3 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
1.20 Residential "Lot Sale"Development means a tract of land that has been divided into
four or more contiguous lots in which a developer offers improved lots for sale and the
purchaser of the lot is responsible for construction of a residential home and the costs to
provide service, which may include backbone, transformer and service.
1.21 Residential Multi-Family Development means a development consisting of
apartments, condominiums, or townhouses with less than four floors.
1.22 Residential Single Family means a house, or a manufactured or mobile home
Permanently affixed to a lot or site.
1.23 Residential Subdivision means a tract of land, which has been divided into four or
more contiguous lots with an average size of one acre or less, in which the developer is
responsible for the costs to provide service, including backbone, transformers and
services for the residential homes or permanent manufactured or mobile home sites.
1.24 Residual Value means the remaining in-depredated original cost of the existing
facilities to be removed
1.25 Rural Arizona Municipality means Arizona incorporated cities and towns with
populations of less than 150,000 (based on U.S. Census Bureau 2010 population data) not
contiguous with or situated within a Metro Area.
1.26 Rural Municipal Business Development means a tract of land which has been divided
into contiguous lots, is owned and developed by an Rural Arizona Municipality, and
where the Rural Arizona Municipality will be the leaseholder for future permanent
applicants.
1.27 Schedule of Charges means the list of charges that is used to determine the applicant's
cost responsibility for the Extension Facilities.
1.28 Service Entrance Upgrade means the replacement of t.he customer's electric panel to one
with larger load capacity. This includes panels that are upgraded to a larger amperage
rating, greater voltage or additional phases (1 phase to 3 phase).
1.29 Temporary means premises or enterprises which are temporary in character, or where
it is known in advance that the Extension Facilities will be of limited duration.
2.General Provisions for Service
2.1 Applicant Classification - For the purposes of this Service Schedule 3, applications for
Extension Facilities will be classified as "Residential" or "General Service" as listed
below, and further described in the referenced sections.
(A) Residential classifications are: "Residential Single Family Home" (Section 3),
"Residential Subdivision Developments" (Section 4), "Residential "Lot Sale"
Developments (Section 5), "Master Planned Community Developments" (Section
6) or "Residential Multi-Family Developments" (Section 7).
(B) General Service classifications are: "Basic General Service" (Section 9), "High Rise
Developments" (Section 10), Mixed-Use Developments (Section 11), "Corporate
Business & Industrial Park Developments" (Section 12), "Temporary Applicants"
(Section 13), and "Doubtful Permanency Customers" (Section 14).
A.C.C. No.XXXX
Canceling A.C.C. No. 5801
Service Schedule3
Revision No.13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix, Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31, 1954
Page 3 of 26
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Gaps
Appendix N
SERVICE SCHEDULE 3P 8Q€ 4of 26
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
2.2
l
1l
i
Schedule of Charges -An applicant requesting an extension will be provided a sketch
showing the Extension Facilities and an itemized cost quote based on the Schedule of
Charges or other applicable details. The Schedule of Charges is attached to this Service
Schedule as Attachment 1. When the Schedule of Charges is not applicable, charges for
Extension Facilities will be determined by the Company based on Project-Specific Cost
Estimates. The Schedule of Charges is not applicable for the following:
(A) Extension Facilities requiring modifications, removal, relocations or conversions of
existing facilities in conjunction with a new extension or existing customer
requested upgrade. The removal, replacement, conversion, and new Extension
Facilities charges will be determined by a combination of Schedule of Charges and
a Project-Specific Cost Estimate depending on the scope of the project and may
include residual value costs as computed in accordance with the method described
in A.R.S 40-347.
(B) Extension Facilities required for modifications, relocations or conversions of
existing facilities not in conjunction with a new extension or existing customer
upgrade.
(C) Extension Facilities for General Service applicants with estimated demand loads of
three megawatts or greater, or that require in aggregate 3,000 kVA of transformer
capacity or greater.
(D) Extension Facilities that require three-phase transformer installations greater than
the sizes noted in the Schedule of Charges.
(E) Extension Facilities required for High Rise Developments, Mixed-Use
Developments, Master Planned Developments or Temporary service.
(F) Extension Facilities involving spot networks, vault installations, primary metering,
or specialized or additional equipment for enhanced reliability.
(G) Special studies, leases or permits required by the city, county, state or federal
governmental agency for installing electric facilities on private, government or
public lands.
2.3 General Underground Construction Policy - With respect to all underground
installations under a Line Extension Agreement, Company will install underground
facilities only if all of the following conditions are met:
(A) The Extension Facilities meet aLIa requirements as specified in "Residential" or
"General Service" Sections 2.1 (A) & (B) of this Service Schedule 3.
(B) The applicant signs a trench agreement and provides all earth-work including, but
not limited to, trenching, boring or punching, backfill, compaction, and surface
restoration in accordance with Company specifications.
(C) The applicant provides installation of equipment pads, pull-boxes, manholes,
conduits, and appurtenances as required and in accordance with Company
specifications.
(D) In lieu of applicant providing these services and equipment, the applicant may pay
Company to provide these services and equipment as a non-refundable contribution
in aid of construction. The payment will equal the cost of such work plus any
A.C.C. No.XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by:Charles A.Miessner
Title: Manager Regulation and Pricing
Original EffectiveDate:January 31, 1954
Page 4 of 26
76295DECISION no.
DOCKET no. E-01345A-16-0_36 ET AL.
Q ops
Appendix N
Page 5 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
administrative or inspection fees incurred by Company. Applicants electing this
option will be required to sign an agreement indemnifying and holding Company
harmless against claims, liabilities, losses or damage (Claims) asserted by a person or
entity other than Company's contractors, which Claims arise out of the trenching
and conduit placement, provided the Claims are not attributable to the Company's
gross negligence or intentional misconduct.
2.4 Refunds - The following general refund conditions will apply:
(A) No refund will be made to any applicant for an amount more than the unrefunded
balance of the applicant's refundable advance.
(B) Company reserves the right to withhold refunds to any applicant who is delinquent
on any account, agreement, or invoice, including the payment of electric service, and
may apply these refund amounts to past due bills.
(C) The refund eligibility period for Basic General Service and High Rise Development
will be five years from the date Company executes the Line Extension Agreement
with the applicant. Any unrefunded advance balance will become a non-refundable
contribution in aid of construction five years from the Execution Date of the
agreement.
(D) The refund eligibility period for Residential Subdivisions and Multi-Family
Developments will be five years and will start three months from the date Company
executes the Line Extension Agreement with die applicant Any unrefunded
advance balance will become a non-refundable contribution in aid of construction
five years from the Execution Date of the agreement.
(E) Refunds will be mailed to die applicant of record noted on the executed agreement
no later than 60-days from the annual review date.
2.5 Interest - All refundable advances made by the applicant to the Company will be non-
interest bearing.
2.6 Ownership - Except for applicant owned facilities, all Extension Facilities installed in
accordance with this Service Schedule 3 will be owned, operated, and maintained by
Company.
RESIDENTIAL
3.Residential Single Family Homes
3.1 Extension Facilities will be installed to new Permanent residential applicants or groups
of new Permanent residential applicants on a free footage basis under the following
conditions:
(A) A Line Extension Agreement signed by the applicant and construction costs in
excess of the allowances, as described in 3.1(C) and 3.2 will be paid by the applicant
before the Company begins installing facilities. Payment is due at the time the Line
A.C.C. No. XXXX
CancelingA.C.C. No.5801
ServiceSchedule3
Revision No. 13
Effective:XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31 1954
Page 5 of 26
76295
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
AppendixN
Page 6 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
Extension Agreement is signed by the applicant.
(B) The site plan has been approved and recorded in the county having jurisdiction.
(C) The total footage of the Extension Facilities (primary, secondary, service) does not
exceed 750 feet per applicant or $10,000; or
(D) The total cost of the Extension Facilities, as determined by Company, is less than
$10,000 per applicant.
3.2 All additional construction costs over $10,000 per applicant will be paid by applicant as
a non-refundable contribution in aid of construction.
3.3 Applicants who combine to form a group may also combine their allowance as specified
in Sections 3.1(C) and 3.2.
3.4 The cost of extending service to applicant will be determined in accordance with the
Schedule of Charges or combination of Schedule of Charges and a Project-Specific Cost
Estimate depending on the scope of the project which will exclude the cost of one single
phase transformer.
3.5 The footage allowance of 750 feet and the cap of $10,000 will be reviewed from time to
time with the Arizona Corporation Commission.
3.6 Examples of the application of Section 3.1 can be found in Attachment 2 - Free Footage
Illustrative Example.
s4. Residential Subdivision Developments
4.1 Extension Facilities will be installed to Residential Subdivision Developments of four or
more homes in advance of application for service by Permanent customers under the
following conditions:
(A) A Line Extension Agreement signed by the applicant and advance payment of all
project costs is required before the start of construction by the Company. Payment is
due at the time the Line Extension Agreement is signed by the applicant.
(B) The subdivision development plat has been approved and recorded in the county
having jurisdiction. Applicant is responsible for providing Company an approved
subdivision plat prior to project design. If final approved plat is different from what
was originally submitted to Company it may cause delays and additional cost for
redesign.
4.2 The cost of extending service to applicant will be determined in accordance with the
Schedule of Charges or combination of Schedule of Charges and a Project-Specific Cost
Estimate depending on the scope of the project.
A.C.C. No.XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
RevisionNo.13
Effective:XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix,Arizona
Filedby:Charles A.Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31, 1954
Page 6 of 26
76295
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
AppendixN
Page 7 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
4.3 A portion of the project cost will be designated as a refundable advance and will be
eligible for refund based on the "per lot" allowance provisions of Section 4.6 and in
accordance with Section 2.4.
4.4 In lieu of a cash payment for the refundable advance amount, the Company will reserve
the right to accept an alternative financial instrument, such as a Letter of Credit or
Surety Bond based on the financial condition, or organizational structure of developer.
4.5 That portion of Me project cost in excess of the remindable advance will be non-
refundable m addition to any other non-standard construction charges such as street
lights.
4.6 The refundable advance will be eligible for refund based on a "per lot" allowance of
$3,500 for each Permanently connected residential customer over a five year period.
Refunds of refundable advances will be governed by Section 2.4. The refund eligibility
period will be five years which will start three months from the date Company executes
the Line Extension Agreement with the applicant. A review of the project will be
conducted annually to determine subdivision buildout, and if the qualifications have
been met for any refunds.
4.7 Examples of the application of Section 4 can be found in Attachment 3 - Residential
Subdivision Illustrative Example.
5.Residential "Lot Sale" Developments
u
5.1 Extension Facilities will be installed to Residential "Lot Sale" Developments in advance
of application for service by Permanent applicants under Ute following conditions:
(A) A Line Extension Agreement signed by the applicant and advance payment of all
project costs is required before the start of Company construction. Payment is due at
the time the Line Extension Agreement is signed by the applicant.
(B) The development plat has been approved and recorded in the county having
jurisdiction.
5.2 The cost of extending service to applicant will be determined in accordance with the
Schedule of Charges or combination of Schedule of Charges and a Project-Specific Cost
Estimate depending on the scope of the project.
5.3 The applicant will pay the total project estimated cost as a non-refundable contribution
in aid of construction in addition to costs for street lights and other non-standard
construction charges.
5.4 Company will provide a "Conduit Only Design" provided applicant makes a payment
in the amount equal to the estimated cost of the preparation of the design, in addition to
A.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule3
RevisionNo.13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date; January 31, 1954
Page 7 of 26
76295DECISION no.
i
DOCKET no. E-01345A-16-0036 ET AL.
G ops
AppendixN
Page 8 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
the costs for any materials, Held survey and inspections that may be required. Future
extensions in the development will be required to follow the original design plan.
5.5 Extension Facilities will be installed to individual applicants in accordance with
provisions listed in Section 3.
6. Master Planned Community Developments
6.1 Extension Facilities will be installed to Master Planned Community Developments in
advance of application for service by Permanent applicants under the following
conditions:
(A) A Line Extension Agreement signed by die applicant and advance payment of all
project costs is required before the start of Company construction. Payment is due at
the time the Line Extension Agreement is signed by the applicant.
(B) The site development plan has been approved and recorded in the county having
jurisdiction.
6.2 The cost of extending service to applicant will be determined by a Project-Specific Cost
Estimate based on the scope of the project.
6.3 The applicant will pay the total project estimated cost as a non-refundable contribution
in aid of construction in addition to costs for street lights and other non-standard
construction charges.
6.4 Extension Facilities will be installed to each subdivided tract within the planned
development in accordance with the applicable sections of this Service Schedule 3.
7. Residential Multi-Family Developments
7.1 Extension Facilities will be installed to Residential Multi-Family Developments in
advance of application for service by Permanent customers under the following
conditions:
(A) A Line Extension Agreement signed by the applicant and advance payment of all
project costs is required before the start of Company construction. Payment is due at
the time the Line Extension Agreement is signed by the applicant.
(B) The site development plan has been approved and recorded in the county having
jurisdiction.
7.2 The cost of extending service to applicant will be determined in accordance with the
Schedule of Charges or combination of Schedule of Charges and a Project-Specific Cost
estimate depending on the scope of the project.
A.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Micssncr
Title: Manager Regulation and Pricing
Original Effective Dale: January 31 1954
Page 8 of 26
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix N
Page 9 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
7.3 A portion of the project cost will be designated as a refundable advance and will be
eligible for refund based on the "per unit" refundable allowance provisions of Section
7.6 and in accordance wide Section 2.4.
7.4 In lieu of a cash payment for the refundable advance amount, the Company will reserve
the right to accept an alternative financial instrument, such as a letter of Credit or
Surety Bond based on the financial condition, or organizational structure of applicant.
7.5 That portion of the project cost in excess of the refundable advance will be non-
refundable in addition to any other non-standard construction charges such as street
lights etc.
7.6 The refundable advance will be eligible for refund based on a "per unit" allowance of
$1,000 for each new meter, installed for a permanent residential structure, over a five
year period. Refunds of refundable advances will be governed by Section 2.4. The
refund eligibility period will be five years which will start three months from the date
Company executes the Line Extension Agreement. A review of the project will be
conducted annually to determine buildout and if the qualifications have been met for
any refunds.
GENERAL SERVICE
8 General Service Provisions
8.1 Extension Facilities that do not meet the requirements under Residential Sections 3, 4, 5,
6, or 7 will be considered General Service and will be installed to all applicants who
meet the qualifications under Sections 9, 10, 11, 12, 13, or 14 of dies Service Schedule 3.
9 Basic General Service
9.1 Extension Facilities will be installed to Basic General Service in advance of application
for service by Permanent applicants under the following conditions:
(A) A Line Extension Agreement signed by the applicant and advance payment of all
project costs is required before the start of Company construction. Payment is due at
the dine the Line Extension Agreement is signed by the applicant.
(B) The site development plan for the project for which the Line Extension has been
requested has been approved and recorded in the county having jurisdiction.
9.2 The project costs for Basic General Service installations will be determined in
accordance with the Schedule of Charges, a Project-Specific Cost Estimate, or a
combination of Schedule of Charges and Project-Specific Cost Estimate depending on
the scope of the project.
A.c.c. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31 1954
Page 9 of 26
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
o ops
AppendixN
Page 10 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
9.3 The cost for Extension Facilities installed for applicants with estimated demand loads of
less than three megawatts or less than 3,000 kV of transformer capacity, will be
determined in accordance with the Schedule of Charges or combination of Schedule of
Charges and a Project-Specific Cost Estimate depending on the scope of the project.
9.4 The cost for Extension Facilities installed for applicants with projected loads of three
megawatts or greater, requiring transformer capacity of 3,000 kVA and greater, special
requests involving primary metering, or specialized/additional equipment for
enhanced reliability will be determined by the Company based on Project-Specific
Cost Estimates.
9.5
a
Economic Feasibility Analysis for Basic General Service Applicants - Applicants who's
Extension Facilities are installed on the basis of an Economic Feasibility analysis which
determines that the estimated installation cost of the Extension Facilities is not
supported by the applicant's estimated delivery service revenue may be required to
advance sufficient funds to make installation of the Extension Facilities economically
feasible. Company reserves the right to collect a hill advance from the applicant based
on the project scope, location, applicant's financial condition or organizational structure
of the applicant. The following conditions will apply to Economic Feasibility projects:
(A) Project Cost $25,000 or less - Economic Feasibility for projects where the applicant's
Fxtension Facilities cost (excluding non-refundable applicant contributions such as
street lights and other non-standard construction charges) is $25,000 or less will be
established where the estimated annual revenue based on Company's then currently
effective rate for delivery service (excluding taxes, regulatory assessment and other
adjustments) multiplied by six is equal to or greater than the cost of the applicant's
Extension Facilities.
(B) Project Cost greater than $25,000 - Economic Feasibility for projects where the
applicant's Extension Facilities cost (excluding non-refundable applicant
contributions such as street lights and other non-standard construction charges) is
greater than $25,000 will be established where the estimated annual revenue based
on Company's then currency effective rate for delivery service (excluding taxes,
regulatory assessment and other adjustments), less the cost of service, provides an
adequate rate of return on the investment made by Company to serve the applicant.
(C) Applicants whose Economic Feasibility analysis results in the requirement for a
payment in advance of construction may be eligible for a refund of such advance
over the term of the Line Extension Agreement's five-year period if the actual annual
delivery service revenue for the applicant's project exceeds the estimated delivery
service revenue used in the Economic Feasibility analysis.
(D) The Economic Feasibility analysis for the Extension Facilities will be reviewed at the
end of the third and fifth year of the Line Extension Agreement based on actual
delivery service revenue for the preceding year and to the degree that actual revenue
supports the Extension Facilities cost, all or a portion of the applicant's construction
advance may be refunded. In no case will refunds exceed the unrefunded balance of
A.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No.13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPAN Y
Phoenix Arizona
Filed by: Charles A. Micssner
Title: Manager Regulation and Pricing
Original Effective Date: ]january 31, 1954
Page 10 of 26
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix N
Page 11 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
the applicant's advance. Any unrefunded balance remaining five years from the
date of the Company's executed Line Extension Agreement will become a non-
refundable contribution in aid of construction.
(E) Company may include a capacity factor component, as determined by Company, to
the Economic Feasibility Analysis for applicants that request excess or redundant
system capacity.
10 High Rise Developments
10.1 Extension Facilities will be installed to High Rise Developments in advance of
application for service by Permanent applicants under the following conditions:
(A) A Line Extension Agreement is signed by the applicant and advance payment of all
project costs is required before the start of Company construction. Payment is due at
the time the Line Extension Agreement is signed by the applicant.
(B) The site development plan has been approved and recorded in the county or city
having jurisdiction.
(C) The residential units are individually metered or master metered in accordance with
Section 21 .
(D) Extension Facilities will be installed to designated points of delivery in accordance
with APS's Electric Service Requirements Manual (ESRM). It is the applicant's
responsibility to provide and maintain the electrical facilities within the building.
10.2 The charges for Extension Facilities will be determined based on a Project-Specific Cost
Estimate, and will be paid by die applicant before Company installing facilities.
10.3 Economic Feasibility Analysis for High Rise Developments - Applicants who's
Extension Facilities are installed on the basis of an Economic Feasibility analysis which
determines that the estimated installation cost of the Extension Facilities is not
supported by the applicant's estimated delivery service revenue may be required to
advance sufficient funds to make installation of the Extension Facilities economically
feasible. Company reserves the right to collect a full advance from the applicant based
on the project scope, location, applicant's financial condition or organizational structure
of the applicant. The following conditions will apply to Economic Feasibility projects:
(A) Economic Feasibility for projects where the applicant's Extension Facilities cost
(excluding non-refundable applicant contributions such as street lights and other
non-standard construction charges) is greater than $25,000 will be established where
the estimated annual revenue based on Company's then currently effective rate for
delivery service (excluding taxes, regulatory assessment and other adjustment), less
the cost of service, provides an adequate rate of return on the investment made by
Company to serve the applicant.
(B) Applicants whose Economic Feasibility analysis results in the requirement for a
payment in advance of construction may be eligible for a refund of such advance
over the term of the Line Extension Agreement's five-year period if the actual annual
A.c.c. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:CharlesA.Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31 1954
Page 11 of 26
76295
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
i
Q ops
Appendix N
Page 12 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
delivery service revenue for the applicant's project exceeds the estimated delivery
service revenue used in the Economic Feasibility analysis.
(C) The Economic Feasibility analysis for the Extension Facilities will be reviewed at the
end of the third and fifth year of the Line Extension Agreement based on actual
delivery service revenue for the preceding year and to the degree that actual revenue
supports t;he Extension Facilities cost, all or a portion of the applicant's construction
advance may be refunded. In no case will refunds exceed the unrefunded balance of
the applicant's advance. Any unrefunded balance remaining five years from the date
of the Company's executed Line Extension Agreement will become a non-refundable
contribution in aid of construction.
(D) Company may include a capacity factor component, as determined by Company, to
the Economic Feasibility Analysis for applicants that request excess or redundant
system capacity.
10.4 Before Company orders specialized materials or equipment required to provide service,
applicant will be required to make an advance payment to the Company for the
estimated cost of the material or equipment in accordance with Section 27.2.
11 Mixed-Use Developments
a
11.1 Extension Facilities will be installed to Mixed-Use Developments in advance of
application for service by Permanent applicants under the following conditions:
(A) A Line Extension Agreement is signed by the applicant and advance payment of all
project costs is required before the start of Company construction. Payment is due at
the time the Line Extension Agreement is signed by the applicant.
(B) The site development plan has been approved and recorded in the county or dry
having jurisdiction.
(C) The residential units are individually metered or master metered in accordance with
Section 21 .
11.2 The charges for Extension Facilities will be determined based on a Project-Specific Cost
Estimate, and will be paid by the applicant before Company installing facilities.
11.3 Economic Feasibility Analysis for Mixed-Use Developments - Applicants who's
Extension Facilities are installed on the basis of an Economic Feasibility analysis which
determines that the estimated installation cost of the Extension Facilities is not
supported by the applicant's estimated delivery service revenue may be required to
advance sufficient funds to make installation of the Extension Facilities economically
feasible. Company reserves the right to collect a full advance from the applicant based
on the project scope, location, applicant's financial condition or organizational structure
of the applicant. The following conditions will apply to Economic Feasibility projects:
(A) Economic Feasibility for projects where the applicant's Extension Facilities cost
(excluding non-refundable applicant contributions such as street lights and other
A.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
RevisionNo 13
Effective:XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by:Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: january 31, 1954
Page 12 of 26
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
Gaps
Appendix N
Page 13 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
non-standard construction charges) is greater than $25,000 will be established where
the estimated annual revenue based on Company's then currently effective rate for
delivery service (excluding taxes, regulatory assessment and other adjustments), less
the cost of service, provides an adequate rate of return on the investment made by
Company to serve the applicant.
(B) Applicants whose Economic Feasibility analysis results in the requirement for a
payment in advance of construction may be eligible for a refund of such advance
over the term of the Line Extension Agreement's five-year period if die actual annual
delivery service revenue for the applicant's project exceeds the estimated delivery
service revenue used in the Economic Feasibility analysis.
(C) The Economic Feasibility analysis for the Extension Facilities will be reviewed at the
end of the third and fifi year of die Line Extension Agreement based on actual
delivery service revenue for the preceding year and to the degree that actual revenue
supports the Extension Facilities cost, all or a portion of the applicant's construction
advance may be refunded. In no case will refunds exceed the unrefunded balance of
the applicant's advance. Any unrefunded balance remaining five years from the date
of the Company's executed Line Extension Agreement will become a non-refundable
contribution in aid of construction.
(D) Company may include a capacity factor component, as determined by Company, to
the Economic Feasibility Analysis for applicants that request excess or redundant
system capacity.
11.4 Before Company orders specialized materials or equipment required to provide service
applicant will be required to make an advance payment to the Company for the
estimated cost of the material or equipment in accordance with Section 27.2.
12 Corporate Business 8: Industrial Park Developments
12.1 Extension Facilities will be made to Corporate Business and Industrial Park
Developments in advance of application for service by Permanent customer under the
following conditions:
(A) A Line Extension Agreement signed by the applicant and advance payment of all
project costs is required before the start of Company construction. Payment is due at
the time the Line Extension Agreement is signed by the applicant.
(B) The site development plan has been approved and recorded in the county or city
having jurisdiction.
12.2 The cost of installing Extension Facilities will be determined in accordance with the
Schedule of Charges, a Project-Specific Cost Estimate, or combination of Schedule of
Charges and a project-specific cost estimate depending on the scope of the project.
12.3 The cost for Extension Facilities installed for applicants with estimated demand loads of
less than three megawatts or less than 3,000 kVA of Transformer capacity, will be
A.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: laniary 31 1954
Page 13 of 26
76295DECISION no.
DOCKET no. E-01345A_16-0036 ET AL.
Q ops
Appendix N
Page 14 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
determined in accordance with the Schedule of Charges or combination of Schedule of
Charges and a Project-Specific Cost Estimate depending on the scope of the project.
12.4 The cost for Extension Facilities installed for applicants with projected loads of three
megawatts or greater, requiring transformer capacity of 3,000 kV and greater, special
requests involving primary metering, or specialized/additional equipment for
enhanced reliability will be determined by the Company based on Project-Specific
Cost Estimates.
12.5 The applicant will pay the total project estimated cost as a non-refundable contribution
in aid of construction in addition to costs for street lights and other non-standard
construction charges.
12.6 Company will provide a "Conduit Only Design" provided applicant makes a payment
in the amount equal to the estimated cost of the preparation of the design, in addition to
the costs for any materials, field survey and inspections that may be required. Future
extensions in the development will be required to follow the original design plan.
12.7 Extension Facilities will be installed to individual lots (at the request of an applicant)
within the Corporate Business and Industrial Park Development in accordance with the
applicable sections of this Service Schedule 3.
13 Temporary Applicants
13.1 Where Temporary Extension Facilities are required to provide service to the applicant,
the applicant will make a non-refundable payment in advance of installation or
construction equal to the cost of installing and removing of the facilities required in
providing Temporary service, less the salvage value of such facilities. Charges will be
determined by Company based on a Project-Specific Cost Estimate.
13.2 A Line Extension Agreement signed by the applicant and advance payment of all project
costs is required before the start of Company construction. Payment is due at the time
the Line Extension Agreement is signed by the applicant.
13.3 When use of the Temporary service is discontinued or service is terminated, Company
may dismantle and remove its facilities and the materials and equipment provided by
Company will remain Company property.
14 Doubtful Permanency Customers
14.1 When, in the opinion of Company, Permanency of the applicant's residence or operation
is doubtful, the applicant will be required to pay the total cost of the Extension Facilities.
The cost of extending service to applicant will be determined in accordance with the
A.c.c. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by:Charles A.Miessner
Title: Manager Regulation and Pricing
Original Effective Date: ]january 31 1954
I Page 14 of 26
76295DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix N
Page 15 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
Schedule of Charges or combination of Schedule of Charges and a Project-Specific Cost
Estimate. The applicant will pay the total project estimated cost as a non-refundable
contribution in aid of construction in addition to costs for street lights and other non-
standard construction charges.
14.2 A Line Extension Agreement signed by the applicant and advance payment of all project
costs is required before the start of Company construction. Payment is due at the time
the Line Extension Agreement is signed by die applicant
OTHERCONDITIONS
15 Municipalities and Other Governmental Agencies
15.1 Extension Facility installations, relocations, or conversions of existing facilities required
to serve loads of municipalities or other governmental agencies may be constructed
before the receipt of a signed Line Extension Agreement. However, this does not relieve
the municipality or governmental agency of the responsibility for payment of the
Extension Facilities costs in accordance with the applicable sections of Mis Service
Schedule 3.
15.2 The effective date for projects enacted under this provision for purposes of refunds
(Section 2.4) will be the date the municipality or agency provided written approval to
the Company to proceed with construction.
16 Change in Applicant's Service Requirements
16.1 Company will rebuild, modify, or upgrade its existing facilities to meet the applicant's
added load, service entrance upgrade, or change in service requirements on die basis
specified in Sections 3, 4, 5, 6,7,8, 9, 10, 11, 12, 13, or 14. Charges for such changes will
be in accordance with the Schedule of Charges, a Project-Specific Cost Estimate, or
combination of Schedule of Charges and a Project-Specific Cost Estimate determined by
the Company based on project-specific requirements.
17 Relocations, Conversions and Upgrades of Company Facilities
17.1 Relocations - Company will relocate its facilities at the applicant's request. The cost of
relocations not in conjunction with a new extension or existing customer upgrade will
be determined by a Project-Specific Cost Estimate.
(A) When the relocation of Company facilities involves "prior rights" conditions, the
applicant will be required to make payment equal to the estimated cost of relocation
as a non-rehindable contribution in aid of construction. in addition, applicant will
be required to provide similar "rights" for the relocated facilities.
(B) Payment of all project costs is required prior to the start of Company construction.
A.C.C.No.XXXX
Canceling A.C.C. No. 5801
ServiceSchedule 3
RevisionNo.13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31, 1954
Page 15 of 26
DECISION no.76295
I
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix N
a e 6 o 6SERVICE SCHEDULEr g 1 f2
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
Payment is due at the time the Line Extension Agreement is signed by applicant.
Ili
17.2 Conversions - Company will convert from overhead to underground its facilities at
applicant request. The cost of conversions not in conjunction with a new extension or
existing customer upgrade will be determined by a Project-Specific Cost Estimate and
may include residual value costs as computed in accordance with the method described
in A.R.S. Section 40-347.
(A) The applicant will be required to make a payment equal to the estimated cost of
conversion as a non-refundable contribution in aid of construction.
(B) Payment of adj project costs is required prior to the start of Company construction.
Payment is due at the time the Line Extension Agreement is signed by the applicant.
17.3 Upgrades - Company will upgrade its facilities at applicant request. The cost of
Company facility upgrades not in conjunction with a new extension or existing
customer upgrade will be determined by a Project-Specific Cost Estimate.
(A) The applicant will be required to make a payment equal to the estimated cost of the
upgrade as a non-refundable contribution in aid of construction.
(B) Payment of all project costs is required prior to the start of Company construction.
Payment is due at the time the Line Extension Agreement is signed by the applicant.
18 Additional Primary Feed or Specialized Equipment
¢
18.1 When specifically requested by an applicant to provide an alternate primary feed or
specialized equipment (excluding transformation), Company will perform a special
study to determine the feasibility of the request. The applicant will be required to pay
for the cost of the additional feed requested as a non-refundable contribution in aid of
construction. Installation cost will be based on a Project-Specific Cost Estimate. Payment
for the installation of Extension Facilities is due at the time the Line Extension
Agreement is signed by the applicant.
19 Unusual Circumstances
19.1 In unusual circumstances as determined by Company, when the application and
provisions of this Service Schedule 3 appear impractical, or in case of extension of lines
to be operated on voltages other than specified in the applicable rate schedule, or when
applicant's estimated demand load will exceed 3,000 kw, Company may make a special
study of the conditions to determine the basis on which service may be provided.
Additionally, Company may require special contract arrangements as provided for in
the Company's Service Schedule 1, Terms and Conditions for Standard Offer and Direct
Access Service.1
l
1A.C.C. No.XXXX
Canceling A.C.C. No. 5801
Service Schedule3
RevisionNo.13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A.Miessner
Title: Manager Regulation and Pricing
Original Effective Date: ]january 31 1954
Page 16 of 26
76295
DECISION NO.
DOCKET no. E-01345A-16_0036 ET AL.
Gaps
Appendix N
Page 17 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
20 Abnormal Loads
20.1 Company, at its option, may install Extension Facilities to serve certain abnormal loads
(such as: transformer type welders, x-ray machines, wind machines, excess capacity for
test purposes and loads of unusual characteristics) and the costs of any distribution
system modifications or enhancements required to serve the applicant will be included
in the payment described in previous sections of this Service Schedule 3.
21 Master Metering
21.1 Mobile Home Parks - Company will refuse service to all new construction or
expansion of existing Permanent residential mobile home parks unless the
construction or expansion are individually metered by Company.
21.2 Residential Apartment Complexes, Condominiums .. Company will refuse service to
all new construction of apartment complexes and condominiums which are master
metered unless the builder or developer can demonstrate that the installation meets
the provisions of R14-2-205 of the Arizona Administrative Code and the requirements
discussed in 21.3 below. This section is not applicable to Senior Care/ Nursing Centers
registered with the State of Arizona with independent living units which provide
packaged services such as housing, food, and nursing care.
>
21.3 Multi-Unit High Rise Residential Developments - Company will allow master
metering for high rise residential units under the following conditions:
(A) The building will be served by a centralized heating, ventilation or air
conditioning system
(B) Each residential unit will be individually sub-metered and responsible for energy
consumption of that unit.
(C) Sub-metering will be provided and maintained by the builder or homeowners
association.
(D) Responsibility and methodology for determining each unit's energy billing will be
clearly specified in the original bylaws of the homeowners association, a copy of
which must be provided to Company before Company installing Extension
Facilities.
21.4 Conversion from Master Meter to Individually Metered System - Company will
convert its facilities from a master metered system to a Permanent individually metered
system at the applicant's request provided the applicant makes a non-refundable
contribution in aid of construction equal to the residual value plus the removal costs less
salvage of the master meter facilities to be removed. The new facilities to serve the
lA.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule3
Revision No.13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby:Charles A.Miessncr
Title: Manager Regulation and Pricing
Original Effective Date: January 31 1954 lilPage 17 of 26
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
e ops
Appendix N
Page 18 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
individual meters will be extended in accordance with the applicable sections of this
Service Schedule 3. Applicant is responsible for all costs related to the installation of new
service entrance equipment.
22 Voltage
22.1 AH Extension Facility installations will be designed and constructed for operation at
standard voltages used by Company in the area in which the Extension Facilities are
located. At die request of applicant, Company may, at its option, deliver service for
special applications of non-standard or higher voltages with prior approval from
Company's Engineering Department. Applicant will be required to pay the costs of any
required studies as a non-refundable payment.
22.2 Extension Facilities installed at higher voltages will be limited to serving an applicant
operating as one integral unit under die same name and as part of the same business on
adjacent and contiguous sites not separated by private property owned by another party
or separated by public property or public right-of- way.
23 Point of Delivery
23.1 For overhead service, the point of delivery will be where Companv's service
conductors terminate at the applicant's leatherhead or bus riser.
23.2 For underground service, the point of delivery will be where Company's service
conductors terminate in the applicant's or development's service equipment. The
applicant will furnish, install and maintain any risers, raceways and termination
cabinets necessary for the installation of Companv's underground service conductors.
23.3 For special applications where service is provided at voltages higher than the standard
voltages specified in the APS Electric Service Requirements Manual, Company and
applicant will mutually agree upon the designated point of delivery.
24 Easements
24.1 Before Company begins construction of Extension Facilities, all suitable easements and
rights-of-way required for any portion of the extension, will be obtained by applicant
and provided to Company in Company's name without cost to, or condemnation by
Company. AH easements and rights-of-way obtained on behalf of Company will be on
Company's standard easement form which contains the terms and conditions that are
acceptable to Company.
25 Grade Modifications
A.C.C.No. XXXX
Canceling A.C.C.No. 5801
Service Schedule3
RevisionNo. 13
Effective:xxxxxxxx
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31, 1954
Page 18 of 26
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
Q ops
AppendixN
Page 19 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
25.1 If after construction of Extension Facilities, the final grade of the property established by
the applicant is changed m such a way as to require relocation of Company facilities, or
the applicant's actions or those of his contractor results in damage to such facilities, the
cost of replacement, relocation, or any resulting repairs will be borne by applicant as a
non-refundable contribution in aid of construction.
26 Measurement and Location
26.1 Measurement must be along the proposed route of construction.
26.2 Construction will be on public streets, roadways, highways, or easements acceptable to
Company.
26.3 Extension Facilities must be a branch from, the continuation of, or an addition to,
Company's existing distribution faciliUes .
27 Agreements
¢
27.1 Study and Design Agreements-Any applicant requesting Company to prepare special
studies or detailed plans, specifications, or cost estimates will be required to make a
payment to Company in an amount equal to the estimated cost of preparation. When the
applicant authorizes Company to proceed with construction of the Extension Facilities,
the payment will be credited to the cost of the Extension Facilities otherwise the
payment will be non-refundable. Company will prepare, without charge, a preliminary
sketch and rough estimate of the cost to be paid by the applicant upon request.
27.2 Material Order Agreements - Any applicant requesting Company to enter into a Line
Extension Agreement, or relocation agreement which requires either large quantities of
material or material and equipment which the Company does not keep in stock will be
required to make a payment to Company before the material being ordered in an
amount equal to the material/equipment's estimated cost. When the applicant
authorizes Company to proceed with construction of the extension, the payment will be
credited to the cost of the extension; otherwise the payment will be non-refundable.
27.3 Line Extension Agreements - All facility installations or equipment upgrades requiring
payment by an applicant will be in writing and signed by both the applicant and
Company.
28 Applicant Construction of Company DistributionFacilityies
A.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No. 13
Effective:XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: CharlesA.Miessner
Title:Manager Regulation and Pricing
Original Effective Date: ]january 31 1954
Page 19 of 26
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
AppendixN
a eSERVICE SCHEDULE g g 20 of 26
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
28.1 Applicant may provide construction related labor only services associated with the
installation of new distribution line facilities (21 kV and below) to serve the applicant's
new or added load provided the applicant receives written approval from Company
before performing any such services and uses electrical contractors who are qualified
and licensed in the State of Arizona to construct such facilities and designated as an APS
Approved Electrical Distribution Contractor.
28.2 This option is not available for the following:
(A) Replacement, modifications, upgrades, relocation, or conversions of existing
systems.
(B) Where all or a portion of the distribution line facilities are to be constructed on or
installed on existing distribution line or transmission lines.
28.3 All construction services provided by die applicant will be subject to inspection by a
duly authorized Company representative and will comply with Company designs,
construction standards, and other requirements which may be in effect at the time of
construction. Any work found to be substandard in the sole opinion of the Company
must be corrected by applicant before energizatjon by Company.
28.4 Applicant will reimburse Company for all inspection and project coordination costs as a
non-refundable contribution in aid of construction. Estimated costs for inspection and
project coordination will be identified in the construction agreement executed by
Company and applicant.
28.5 Costs for Extension Facilities for applicants who provide construction of Company°
distribution facilities will be based on a Project-Specific Cost Estimate.
28.6 A signed agreement and payment of all project costs minus labor are required before the
start of applicant construction. Payment is due at the time the agreement is signed by the
applicant.
28.7 For applicants that are not served by the terms in General Service Sections of this
document, Company will provide a Project-Specific Cost Estimate. Applicants may
submit an invoice detailing costs of Extension Facilities and apply any allowance
provided in Residential Sections 3, 4, or 7 to these costs. At no point will these costs
exceed the Company's Project-Specific Cost Estimate.
28.8 Applicants served by the terms in General Service Sections 9, 10, 11, 12, 13, or 14 of this
document will be subject to the rules set forth in the respective section and Refund
Section 2.4.
29 Settlement of Disputes
A.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule3
RevisionNo.13
Effective: XXXXXXXX
ARIZONA PUBI IC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original EffectiveDale: January 31 1954
Page 20 of 26
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Gaps
Appendix N
Page 21 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
I
29.1 Any dispute between the applicant or prospective applicant and Company regarding
the interpretation of these "Conditions Governing Extensions of Electric Distribution
Lines and Services" may be referred to the Arizona Corporation Commission or a
designated representative or employee for determination by either party.
30 Policy Exceptions
(B)
(C)
(D)
(E)
(F)
30.1 This Schedule 3 is applicable to all applicants unless specific exceptions are approved by
the Arizona Corporation Commission. The following exceptions have been approved
for Rural Municipality applicants:
(A) Extension Facilities will be installed to Rural Municipal Business Developments on
the basis of an Economic Feasibility analysis in advance of application for service
by Permanent applicants.
The cost of installing Extension Facilities to Rural Municipal Business
Developments will be determined in accordance with the Schedule of Charges, a
Project-Specific Cost Estimate, or combination of Schedule of Charges and a
Project-Specific Cost Estimate depending on the scope of the project.
The refund eligibility period for Rural Municipal Business Developments will be
seven years from the date the Company executes the Line Extension Agreement
with the Rural Municipality applicant.
Rural Municipal Business Development applicants will be required to advance
payment of one-half of the project costs at the time the Line Extension Agreement
is signed and before the start of Company construction. The balance of the project
cost will be required seven years from the Execution Date of the agreement if the
project has not become economically feasible by the end of the seven year
refundable period. Any unrefunded advance balance paid at the start of the
project, plus the balance of project costs due at the end of refund period, will
become a non-refundable contribution in aid of construction seven years from the
Execution Date of the agreement.
Company may require a Surety Bond, Irrevocable Letter of Credit or Assignment
of Monies in amount equal to any Advance not collected at the start of
construction.
The Economic Feasibility analysis for the Rural Municipal Business Development's
Extension Facilities will be reviewed at die end of the third, fifth and seventh year
of the Line Extension Agreement based on the average monthly demand within
the Rural Municipal Business Development for the preceding year and to the
degree that the average monthly demand supports the Extension Facilities cost, all
or a portion of the applicant's construction advance may be refunded. In no case
will refunds exceed the unrefunded balance of the applicant's advance.
A.C.C. No. XXXX
Canceling A.C.C. No. 5801
ServiceSchedule 3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PU BLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31 1954
Page 21 of 26
76295DECISION no.
DOCKET NO. E-01345A-l6-0036 ET AL.
i Q ops
Appendix N
e o 6sERvicE SCHEDULE §aQ 22 ft
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
(G)Company may include a capacity factor component, as determined by Company,
to the Economic Feasibility Analysis for applicants that request excess or
redundant system capacity.
A.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31, 1954
Page 22 of 26
76295DECISION NO.
DOCKET no. E-01345A-16_0036 ET AL.
Gaps
Appendix N
a e 3 oSERVICE SCHEDULE 8 g 2 f 26
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
Attachment 1
Schedule of Charges - Single Phase
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A.C.C. No.XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31 1954
Page 23 of 26
76295
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix N
Page 24 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
Attachment 1
Schedule of Charges - Tree Phase
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A.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessner
Title: Manager Regulation and Pricing
Original Effective Date: January 31, 1954
Page 24 of 26
DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix N
SERVICE SCHEDULE page 25 of 26
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
Attachment 2
Examples to Section 3* - Free Footage Illustrative Example
Customer
Pawned
S¢l\lC8
Footage C est
S 4.89
Total
Footage
550
Primal
FOOIR2€Cost500S15.00 Cost
7.744.50sScenario 1 H
APS $7744.50**C customer Payment $0-
Cusroumer
PawneurCost
PrimaryF00¥;\!€Cost ServiceFooraszeCost Total
Foorasze
755 sScenario 2 9,960.15 Q
APS $9960.15"Customer Payment So
Cast
S€I\lC8
Footage Cost
Sceuairio 3 s 4.89
Pxiuuuv
Footage Cost
675 s 15.00
Total
Poomsze
725
Customer
Pavmem
s 10.369.s0 s 369.50
•APS $10,00000**Customer Payment
$369.501 -
Scenario 4
PrixnawFooraszeCostS15.00 Service
Footage Cos:
S 4.89
Total
F oota 2e
750
Cllsloll1€1
Cost Pavmeut
s 10,340.10 s 340.10
APS S10,000.00**Customer Payment
$340.10
Total
FOOIZ\2€
Service
Footage Cosx
PlWwn
Footage Cost
700 s 15.00 800Scenario 5
Cwtoulel
Cos:Payment
s 10,989.00 s 989.00
Total 800'APS $1o,ooo.w**Customer Payment
$989.00
"APS portion does not include cos! of transformer*Scenarios do not reflect all components required for a complete protect
A.C.C. No. XXXX
Canceling A.C.C. No. 5801
Service Schedule 3
Revision No. 13
Effective: XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filed by: Charles A. Miessncr
Title: Manager, Regulation and Pricing
Original Effective Date: January 31 1954
Page 25 of 26
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Q ops
Appendix N
Page 26 of 26SERVICE SCHEDULE 3
CONDITIONS GOVERNING EXTENSIONS OF
ELECTRIC DISTRIBUTION LINES AND SERVICES
Attachment 3
Residential Subdivision Illustrative Example
100
$ 350.000
$ 350 000
l 100
$ 350000
Scenario 1
Number ofPlanned Homes
Estimated Construction Cos
Total Potential Refimdable Allowanc
Non-Refundable Contribution
Number of Homes Com fete
Credited Allowance
Potential Rem airing Allowanc
.
I0
Number ofPlanned Homes 100
Estimated Construction Cost $ 400 000
Total Potential Refundable Allowance S 350 000
Non-Refundable Contribution $50,000
Number off-Iomes Com fete 100
Credited Allowance S 350,000
Potential Rem airing Allowance
l !
II
Scenario 3
Number of Planned Homes
Estimated Construction Cost $ 350,000
Total Potential RefUndable Allowanc $ 350 000
Non-RefUndable Contribution
Number off-Iomes Com fete 45
Credited Allowance $ 157 500
Potential Remainin Allowanc S l 92500
II
Scenario 4
Number of Pl8nned Homes
Eslimated Construction Co $ 400000
Total Potential Refundable Allowanc $ 350 000
Non-Refundable Contribution $50 000
Number of Homes Com fete 45
Credited Allowance $ 157500
Potential Remainin Allowance $ 192,500Io
A.C.C. No.XXXX
Canceling A.C.C. No. 5801
Service Schedule3
Revision No. 13
Effective:XXXXXXXX
ARIZONA PUBLIC SERVICE COMPANY
Phoenix Arizona
Filedby: Charles A. Miessncr
Title: Manager Regulation and Pricing
Original Effective Date: January 31 1954
Page26 of26
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
II
l..
II!II
I.
Appendi 0
6
I
I
I
DECISION no.76295
DOCKET no. E-01345A-16_0036 ET AL.Appendix o
PLAN OF ADMINISTRATION Page 1 of 11
LOST FIXED COST RECOVERY
Lost Fixed CostRecovery
Plan of Administration
Effective Date: XXXX
Table of Contents
1.
2.
3.
4.
5.
6.
General I
1
LFCR Annual Incremental 3
Historical 3
Filing and Procedural 3
Compliance Reports 3
1. General Description
This document describes the plan of administration for the Lost Fixed Cost Recovery (LFCR)
mechanism approved for Arizona Public Service Company (APS or Company) by the Arizona
Corporation Commission (ACC or Commission) on XX/ XX/XXX in Decision No. XXXXX. The
LFCR mechanism provides for the recovery of lost fixed costs authorized by the Commission,
as measured by revenue, associated with the amount of energy efficiency (EE) savings and
distributed generation (DG) determined to have occurred. Costs to be recovered through the
LFCR include the portion of distribution costs included in base rates, less what is already
recovered by 50% of demand revenues associated with distribution.
¢2. Definitions
Applicable Companv Revenues- The amount of revenue generated by sales to retail customers,
for all applicable rate schedules.
Current Period- The most recent adjustment year.
DG Savings - The amount of MWh sales reduced by DG. APS will use meter data to calculate
DG system savings where available. Each year, APS will use actual data from January through
September and forecast data for the remainder of the calendar year (October through
December) to calculate the savings. The calculation of DG Savings will consist of the following
by class:
a.I
I Current Period:The annual energy production (Mwh) produced by the
cumulative total of DG installations since the effective date of APS's most recent
general rate case.
b.Excluded MWh Production: The reduction of recoverable DG Savings calculated
for commercial and industrial customers, by subtracting the amount of DG
produced by customers on Excluded Rate Schedules.
c.True-Up Prior Period: The reconciliation of APS's forecast data of DG sales
reductions for the dire months in the Prior Period to verified DG sales
reductions in the Prior Period.
76295 lDECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix O
PLAN OF ADMINISTRATION Page 2 of 11
LOST FIXED COST RECOVERY
EE Programs- Any program approved in APS's annual implementation plan.
EE Savings - The amount of MWh sales reduced by EE as demonstrated by the Measurement,
Evaluation, and Research (MER) conducted for EE Programs. The calculation of EE Savings will
consist of the following by class:
a.Cumulative Verified: The cumulative total MWh reduction as determined by the
MER using the effective date of APS's most recent general rate case as a starting
point.
l
b. Current Period: The annual EE related sales reductions (MWh). Each year, APS
will use actual prefER verified data through November and forecast data for
December to calculate annual savings.
c.Excluded MWh reduction: The reduction of recoverable EE Savings calculated
for commercial and industrial customers, by subtracting the amount of EE
Savings actually achieved by customers on Excluded Rate Schedules.
d. True-Up Prior Period: The reconciliation of APS's forecast data of annual EE
sales reductions for the Prior Period to the MER verified EE sales reductions in
the Prior Period.
Excluded Delive Revenue - 50% of any delivery demand (kW) revenue as determined in
Decision No.XXXXX and calculated on Schedules 6 and 7.
Excluded Rate Schedules - The LFCR mechanism will not apply to large general service
customers taking service under rate schedules E-32 L, E-32 L TOU, E-34, E-35, XHLF and E-36
XL, or to unmetered General Service customers under E-30 and lighting schedules, Contract 12.
LFCR Adjustment - Total Lost Fixed Cost Revenue as calculated on Schedule 2, divided by
forecast retail kph sales for the proposed adjustor period. For customers on a demand rate the
adjustment will be applied as a kW charge. For customers on an energy only rate the
adjustment will be applied as kph charge. This adjustment will be applied to all customer bills,
with the exception of those customers on Excluded Rate Schedules, or if the customer's current
rate has alternate provisions.
Lost Fixed Cost Rate - A rate determined at the conclusion of APS's most recent general rate
case by taking the sum of allowed Distribution Revenue for each General Service & Residential
rate class and dividing each by their respective class adjusted test year kph billing
determinants.
Lost Fixed Cost Revenue - The amount of fixed costs not recovered by the utility because of EE
and DG during the calendar year. This amount is calculated by multiplying the Lost Fixed Cost
Rate by Recoverable MWh Savings, by rate class.
Prior Period- The 12 months preceding the Current Period.
Recoverable MWh Savings- The sum of EE Savings and DG Savings by rate class.
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix O
PLAN OF ADMINISTRATION Page 3 of 11
LOST FIXED COST RECOVERY
Transition Balance- The Lost Fixed Cost Revenue balance as calculated in compliance with the
LFCR Plan of Administration applicable during that time period per Decision No. 73183 and
modified in Decision No. 74202.
3.LFCR Annual Incremental Cap
The LFCR Adjustment will be subject to an annual 1% year-over-year cap based on Applicable
Company Revenues. If the annual LFCR Adjustment results in a surcharge and the annual
incremental increase exceeds 1 % of Applicable Company Revenues, any amount in excess of the
1% cap will be deferred for collection until the first future adjustment period in which including
such costs would not cause the annual increase to exceed the 1% cap. The one-year Treasury
Constant Maturities, effective on the first business day each year, as published on the Federal
Reserve website or its successor publication will be applied annually to any deferred balance.
4.Historical Transition
Upon implementation of the revised LFCR Plan of Administration in Decision No. XXXXX, the
Transition balance will be calculated on Schedule 4 (LFCR Historical Transition) and reported
on Schedule 2 (LFCR Annual Incremental Cap Calculation).
5. Filing and Procedural Deadlines
APS will file the calculated LFCR Adjustment, including all Compliance Reports, with the
Commission for the previous year by February 15"'. The new LFCR Adjustment will not go into
effect until approved by the Commission. If approved, the new rate will take effect with the first
billing cycle in May, unless otherwise specified by the Commission.
¢
l
l
l
6. Compliance Reports
APS will provide comprehensive Compliance Reports to Staff and the Residential Utility
Consumer Office. The information contained in the Compliance Reports will consist of the
following schedules:
l
•
•
•
•
•
•
•
•
Schedule 1: LFCR Annual Adjustment
Schedule 2: LFCR Annual Incremental Cap Calculation
Schedule 3: LFCR Calculation
Schedule 4: LFCR Historical Transition
Schedule 5: LFCR Test Year Rate Calculation
Schedule 6: Distribution Revenue Calculation - General Service
Schedule 7: Distribution Revenue Calculation - Residential
Schedule 8: Annual DG Installation Report
Schedules 1 through 8, attached hereto, will be submitted with APS's annual compliance filing.
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix O
Page 4 of 11
(C)
Total
(B)
Reference
Schedule 2. Line 15
(A)
Line No.Annual Percentage Adjustment
I.Total Lost FixedCost Revenue for Current Period $
2.Applicable Company MWh
3.S/kwh Line l / Line 2 $
4.Applicable Company MWh for customer billed demand
5.$ for Customers Billed Demand Line 3 * Line 4 s
6.ApplicableCompany MW for customer billed demand
7.$/kW Line 5 / Line 6 s
4
i
ii
DECISION no.76295
DOCKET no. E-01345A-16-0_36 ET AL.
Appendix O
Page 5 of 11
(A)(B)
Line No.Reference
(C)
TotalsLFCR Annual Incremental Cap Calculation
s
1.00%
l.
2.
3.
Applicable Company Revenues
Allowed Cap %
Maximum Allowed Incremental Recovery $(Line l * Line 2)
4.
4a
Total Lost Fixed Cost Revenue
Historical Transition
$
$
%
Schedule 3,Line33. Column C
Schedule 4. Line 33, Column C
Previous Filing, Schedule2,Line 13
Column C 3*
a l
"z
»1¢ .
.4" 4 0.00%
5.
6.
7.
8.
Total Deferred Balance from Previous Period
Annual interest Rate
Interest Accrued on Deferred Balance
Total Lost Fixed Cost Revenue Current Period $
(Line 5 * Line 6)
(Line 4 + Line 4a + Line 5 + Line 7)
9.Lost Fixed Cost Revenue from Prior Period
Previous Filing, Schedule 2 Line 15,
Column C .r
ii
I
iI
y
. . . .
¢.
loa
lob
loc
Lost Fixed Cost Revenue- Billedl
Rate Rider LFCR DG - Billed"2
Grid Access - Billed'8 us
I 1.LFCR Balancing Account $(Line 9 Line l 0)
12.Total Incremental Lost Fixed Cost Revenue for Current Year $(Line 8 Line 9 +Line l I)
13.Amount in Excess of Cap to Defer $(Line 12 - Line 3)
14.Incremental Period Adjustment as %0.00%[(Line 12 - Line 13)/Line 1]
15.Total Lost Fixed Cost Revenue for Current Period $(Line 8 +Line II Line 13)
'Amount billed to customers for the 12 calendar months of20XX.
Excludes amount billed to customers with DG installations prior to 2016.
l
l
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix o
Page 6 of 11
(B)(C)
Line No.
(A)
Lost Fixed (Yost Revenue Calculation Reference lotals
(D)
linins
Residential
Energy Efficiency Savings
I Current Period MWh
Previous Filing Schedule 3. Lmc l
Column C2.
3.
4.
Mwh
"MWh
MWh
Prior Period
Verified Prior Period
TrueUp Prior Period
,}.:4 .
fi
r . .....".a\;..w .
5
6.
Mwh
MWh
(Line 3 Line 2)
(Previous Filing Schedule 3 Line 5
Column C + Line 6)
(Line I + Line 4 + Lune 5)
Cumulative Verified
Total Recoverable EE Savings
Distributed Generation Savings
7.Current Period MWh:s>4854
Previous Filing Schedule 3 Line 7
Column C MWh
..hl5289".4384.
. "M ..'MWh
8.
9
10 MWh(Line 9 Line 8)
Prlor Period
Vcrificd Prior Period
TrueUp Prior Period
I I MWh(Line 7 + Line l0)Total Recoverable DG Savings
MWh
$/kwh
Total Recoverable MWh Savings
Residential Lost Fixed Cost Rate
Residential Lost Fixed Cost Revenue
12.
13.
14.
s
s
(Llnc6+Llne ll)
Schedule 5. Line 3 Column C
(Linc 12 ' Line 13)
C&l
Energy Efficiency Savings " v9 14I
Current Period
Excluded MWh reduction
Net Currcni Period
.Mwh
MWh
Mwh
15.
16.
17 (Lune 15 Line I 6)
<2
Previous Filing Schedule 3. Line 17
Column C "4§c, .49-44MWh
MWh
MWh
18.
19.
20.(Linc 19 Linc I 8)
Prior Period
Verified Prior Period
TrueUp Prior Period
MWh
MWh
21
22.
(Previous Filing Schedule 3. Line 21
Column C + Lune 24)
(Line 17 + Line 20 + Line al)
Cumulative Verified
Total Recoverable EE Savings
Distributed Generation Savings
Current Period MWh23.¢..4=
a m<' ? %
1:1 .........
.Mwh
MWh
MWh DG Savings from Rate Schedules [Excluded Hom LFCR
Net . Current Period
24.
25.(Line 23 Line 24)
Previous Filing Schedule 3. Line 25
Column C MWh
MWh
MWh
26
27.
28.(Line 27 Line 26)
Prior Period
Verified Prior Period
TrueUp Prior Period
MWh29.(Line 25 + Line 28)Total Recoverable DG Savings
iMWh
$/kwhs
s
Total Recoverable MWh Savings
C&l lost Fixed Cost Rate
C&l - Lost Fixed Cost Revenue
30
31.
32.
(Lune 22 + Line 29)
Schedule 5. Lune 6. Column C
(Line 30 ' Line 3 l)
llsTotal Lost Fixed Cost Revenue33.(Line 14 + Line 32)
DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.
Appendix O
Page 7 of 11
(Al (Bl (C)(D)LineNo.Lost Fixed Cost Revenue Calculation Reference Totals l'nits
Residential
Energy Efficiency Savings
1.Current Period MWhI
I
~.»1.. .
. i v..... . . ;
: . £ ~ / =Ii ..
2.
3.
4.(Line 3 Line 2)
MW h
MW h
MW h
.,5.
6.
MWh
MWh
Prior Period
Verified Prior Period
TrueUp Prior Period
Cumulative Verified
Total Recoverable EE Savings (Line l + Line 4 + Line 5)
Distributed Generation Savings
7.Current Period M W h.m*je
8.
9.
IO.
Prior Period
Verified Prior Period
True-Up Prior Period (Line 9 Linc 8)
mph
MWh
MWh
l l .Total Recoverable DG Savings MWh(Linc 7 + Line l 0)
-MWh
0.031111 S/kwh
12.
13.
14.
Total Recoverable MWh Savings
Residential - Lost Fixed Cost Rate
Residential - Lost Fixcd Cost Revenue
s
$
(Line 6 + Line ll)
Decision No. 73183
(Line 12 * Line 13)
C&l
Energy Efficiency Savings
.*.Q
?{§r»i
y 1Yvn
i15.
16.
17.
C urgent Period
Excluded MWh reduction
Net Currcnt Period
MWh
MWh
MWh(Line 15 Line I 6)l
l
il
18.
19.
20.
Prior Period
Verified - Prior Pcriod
True-Up Prior Period
MWh
MWh
MWh(Line 19 Line I 8)
21.
22.
MWh
MWh(Line 17 * Line 20 4 Linc 21 )
Cumulative Verified
Total Recoverable EE Savings
Distributed Generation Savings
23.*W MWh. 593\.~.45'?4
24.
25.
Current Period
MWh DG Savings from Rate Schedules Excluded from
L F C R
Net Currenl Period
MWh
MWh(Line 23 Line 24)
26.
27.
28.
Mwh
Mwh
MWh
Prior Period
Verified - Prior Period
Truc-Up Prior Period (Line 27 Line 26)
29.MWh(Line 25 + Line 28)Total Recovcrablc DG Savings
-MWh
0.023190 $/kwh
30.
31.
32.
Total Recoverablc MWh Savings
C&1 Lost Fixed Cos! Ratc
C&1 Lost Fixed Cost Revenue
s
s
(Line 22 + Line 29)
Decision No. 73183
(Line 30 * Line 31)
33.Total Lost Fixed Cost Revenue s(Line 14 + Line32)
76295DECISIONn o.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix O
Page 8 of 11
(A)
Line No.Lost Fixed Cost Rate Calculation
Residential Customers
(B)
Reference
l
/
(C)
Total
2.
3.
Residential FixedRevenue Schedule7,Line 18.ColumnG $
Schedule7, Line 17. Column B
MWh Billed l000
Lost Fixed Cost Rate (Line I / Line 2)s
4.
5.
6.
C & I Customers
Total FixedRevenue Schedule 6, Line 18 Column G S
Schedule 6. Line 17. Column B /
MWh Billed 1.000
Lost Fixed Cost Rate (Line 8 / Line 9)S
v
i
l
l
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix oPage 9 of 11
(Al <B>(lI IFrD»(G)
( "EllF 1
De 1mld
(C)
Tool
Din ii bl lion
Rrv- ut1 nrifl (on\l"on¢11
Adilxlui Test Year
Biting Dclerminlu
Dcivcry
Charge
Sub Total
Sub Tool
kW
kph
Line Na.Rllc Scbdulc
I (ialerll Scwoc Ralf X
2
3
4
5
6.Grail Savlec Rllc X
7
s
9
10
ll Galaul Suvuec Ralf X
12
13
14.Sub Tool
ms.
U mils
kW x
kph s
kW
kph
LW s
LWe s
kW
kWh
s
s
kW
kWI
kWkWI
Tmnl kW
Tnlal LWI\
Total
16
17
18
Subililv Fxmr
50% s
0% s
s
s
vs. s
mc.s
s
s
so; s
0% S
s
s
s
s
s
l
l
»
DECISION no.76295
DOCKET no.E-01345A-16-0036 ET AL.Aaoendvx o
Page 10 of 11
m(B)(0 (DIIA)(E)
Tariff Cumponenl
(G)
( " F . ( 1 H
Total
DiNribulion
Revenue
Adjusted Test Year .
Billing Delerminanls Units
Delivery
(Il ar' e
s
s
Demand
Sla billlv Facer
sum.. s
0 % s
x
s
Sib Tata I
Rcsndenual Ralf x
50% x
0 % s
s
s
Sub Ton I
Rcsdunual Ran:X
50% s
0%. s
Sub Total
Line No.Rate Sdueduk
I Rcsdcnual Rate x
3
4
5
6
1
x
v
IO
I I
12
18
14
15
To W kW
kW
kph
kW
kph
kW s
k p h S
o w
k p h
kW s
kWh s
k W
k p h
kW
kph
16
17
III
To l al kwh
TolaI .
s
s
s
s
s
u
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix O
Page 11 of 11
Annual DGStatistics
20XX
IIIIII
Cummulative
beeinnina 2016
Total Number of lnstallation
<5kW
5kw to 6.5kW
6.5kW to low
> lokw
Total Installed kW
IIIIIIIIIIIIIIII
IIII
I
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.
Appendix P
ill
DECISION no.76295
DOCKET NO. E-01345A-16-0036 ET AL.Appendix P
Page 1 of 6PLAN OF ADMINISTRATION
ENVIRONMENTAL IMPROVEMENT
SURCHARGEGaps
Environmental Improvement Surcharge
Plan of Administration
Table of Contents
I
I
.2
3
3
3
1. General
2..
3. Qualified FERC Accounts...
4. Calculation of Annual ElS
5. ElS Balancing
6. Filing and Procedural
7 Compliance
1. General Description
This document describes the plan for administering the Environmental Improvement Surcharge
(ElS) approved for Arizona Public Service Company (APS or Company) by the Arizona
Corporation Commission (ACC or Commission) on [insert date] in Decision No. XXXXX. The
ElS provides for the recovery of the capital carrying costs effect of actual environmental
investments made by APS and not already recovered in base rates approved in Decision No.
XXXXX or recovered through another Commission approved adjustment. The ElS will be
calculated annually based on the ElS Qualified Investments closed to plant-in-service during the
preceding calendar year.
u 2. Definitions
Annual ElS Adjustment - The Annual ElS Adjustment represents the ElS Capital Carrying Costs
on the Qualified Net Plant to be recovered in the subsequent twelve month period and is
assessed to customer bills via the ElS $/ kph rate.
!
ElS Capital Carrying Costs - ElS Capital Carrying Costs consists of (1) Return on the Qualified
Net Plant calculated based on the Company's Weighted Average Cost of Capital (WACC)
approved by the Commission in Decision No. XXXXX plus a return on the fair value increment
(if any) for the Qualified Net Plant; (2) depredation expense; (3) income taxes; (4) property taxes
and (5) associated operations and maintenance expenses (O&M).
ElS Qualified Investments - Investments in Qualified Environmental Improvement Projects.
Each ElS Qualified Investment must: (1) be classified in one or more of the FERC plant accounts
as listed in Section 3 of this document, or any other successor FERC account, upon going into
service and (2) be tracked by a specific project number.
Fair Value Increment - For purposes of the ElS, the difference between the Fair Value of the ElS
Qualified Investments and Qualified Net Plant shall be deemed to be zero.
Qualified Environmental Improvement Projects - Projects designed to comply with established
environmental standards required by federal, state, tribal, or local laws and regulations. These
standards and criteria for water, waste, and air include but are not limited to limits for carbon
dioxide (COZ), sulfur oxide (SOx), nitrogen oxide (NOx), particulate matter (PM), volatile
Effective Date XX/XX/XXX Page 1of 3
76295DECISION no.li
ll
DOCKET no. E-01345A-16-0036 ET AL.Appendix P
PLAN OF ADMINISTRATION Page 2 of 6
ENVIRONMENTAL IMPROVEMENT
SURCHARGEQ ops
organic compounds (VOC), and topics such as mercury (Hg), coal ash management, and
requirements under the clean and safe drinking water acts.
Qualified Net Plant- The Qualified Net Plant consists of the ElS Qualified Investments and their
associated accumulated depreciation, accumulated deferred income taxes, tax credits and in the
event of federal corporate tax reform any related unamortized excess deferred taxes, where
applicable.
Total kph Sales- The total prior calendar year energy (kph) sales served under applicable ACC
jurisdictional electric rate schedules, except Rate Schedules E-36 XL and AG-X as reported in the
Company's FERC Form No. 1.
•
•
•
•
•
•
•
3. Qualified FERC Accounts
1. Steam Production
FERC Account 310 - Land and Land Rights
FERC Account 311 - Structures and Improvements
FERC Account 312 - Boiler Plant Equipment
FERC Account 313 - Engines and Engine-Driven Generators
FERC Account 314 - Turbogenerator Units
FERC Account 315 - Accessory Electric Equipment
FERC Account 316 - Miscellaneous Power Plant Equipment
2.Nuclear Production
•FERC Account 320 - Land and Land Rights
•FERC Account 321 - Structures and Improvements
•FERC Account 322 - Reactor Plant Equipment
•FERC Account 323 - Turbogenerator Units
•FERC Account 324 - Accessory Electric Equipment
•FERC Account 325 - Miscellaneous Power Plant Equipment
3. Other Production
•
•
l
•
•
•
•
FERC Account 340 -
FERC Account 341 -
FERC Account 342 -
FERC Account 343 -
FERC Account 344 -
FERC Account 345 -
FERC Account 346 -
Land and Land Rights
Structures and Improvements
Fuel Holders, Products, and Accessories
Prime Movers
Generators
Accessory Electric Equipment
Miscellaneous Power Plant Equipment
Please note this list may expand to include other accounts approved by the ACC in the future.
4.Calculation of Annual ElS Adjustment
The Annual ElS Adjustment is calculated utilizing the accumulation of Qualified Net Plant and
calculated ElS Capital Carrying Costs, as defined above and is applied to applicable customers'
total bill via a $/ kph rate over the twelve month period begirding in April of the year following
the filing described in Section 6. below. The ElS '8/ kph rate is calculated by dividing the
Effective Date XX/XX/XXX Page 2 of 3
ll
76295DECISIONno.
DOCKET no. E-01345A-16-0036 ET AL.Appendix P
PLAN OF ADMINISTRATION Page 3 of 6
ENVIRONMENTAL IMPROVEMENT
SURCHARGEQar>s
Annual ElS Adjustment by Total kph Sales as determined in Schedule 3 of the filing. The ElS
rate will not exceed $0.00050 per kph.
5. ElS Balancing Account
APS will maintain accounting records that accumulate the difference between the actual
allowable Annual ElS Adjustment as compared to the actual revenues received by the Company
through die ElS surcharge during the recovery period (April through March). The difference
will be recorded to the ElS Balancing Account each month and will be provided annually in
Schedule 3 of the filing. In the event that Annual ElS Adjustments are more or less than the
revenues collected as of the last billing cycle of March, the over or under collection will be
subtracted from or added to the ElS calculation in the subsequent period subject to the overall
cap of $000050 per kph.
6. Filing and Procedural Deadlines
ElS Qualified Projects and the Annual ElS Adjustment calculation will be submitted by the
Company to the ACC in the form of Schedules 1 through 3 as attached to this document and
described in Section 7.Compliance Reports.APS will file the calculated ElS S/ kph rate including
all supporting data, with the Commission for the previous year on or before February 1st
s
The Commission Staff and interested parties shall have the opportunity to review the ElS filing
and supporting data in the adjustor calculation. Unless the Commission has otherwise acted or
Staff has filed an objection by April 151, the new ElS $/ kph rate proposed by APS will go into
effect with the first billing cycle in April (without proration) and will remain in effect for the
following 12-month period.
I
7.Compliance Reports
APS will provide an annual report to Staff and the Residential Utility Consumer Office detailing
all calculations related to the ElS $/ kph rate. The reports will include the following Schedules
1 through 3 as attached to this document:
Schedule 1:Qualified Investments for ElS Electric Plant in Service
Schedule 2:Annual ElS Adjustment Calculation
Schedule 3:Current Year ElS Cap Calculation and Adjustment
Effective Date XX/XX/XXX Page 3 of 3
76295DECISION no.
DOCKET NO. E-01345A-16-0036 ET AL.D . ®.§6Evwean2 "D.
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76295DECISION no.
DOCKET NO. E-01345A-I6-0036 ET AL.
Appendix Q
6295DECISION no.7
DOCKET no. E-0I 345A-16-0036 ET AL.Appendix Q
Page 1 of 35
Gaps
PLAN OF ADMINISTRATION
AD]USTMENT SCHEDULE TCA
TRANSMISSION COST
TransmissionCost Adjustment
Plan of Administration
Table of Contents
I
I
2
1. General
2.
3. TCA Balancing 2
4. Filing and Procedural 2
5. Compliance
1. General Description
The purpose of the Transmission Cost Adjustment (TCA) is to provide a mechanism to recover
transmission costs associated with serving retail customers at the level approved by the Federal
Energy Regulatory Commission (FERC) and at the same time as new transmission rates become
effective for Arizona Public Service (APS or Company) wholesale customers. APS shall file a
notice with Docket Control that includes its revised TCA tariff, along with a copy of its FERC
information filing of its annual update of transmission service rates pursuant to its Open Access
Transmission Tariff (OATT). This notice shall be filed with the Commission at the same time
that APS makes its FERC filing.
The TCA applies to APS's Retail Electric Rate Schedules. For Standard Offer customers, the
TCA is applied to the bill as a monthly kph charge for Residential Service Customers and
General Service Customers less than or equal to 20 kw. For all other Standard Offer customers,
the TCA is applied to the bill as a monthly kW charge. The charge and modifications to it will
take effect in billing cycle 1 of die lune revenue month without proration.
I
I APS's Network Integration Transmission Service (NITS) is calculated and filed annually wide the
FERC in accordance with APS's formula rate. The formula rate calculation is specified within
the Company's OATT as filed and approved by the FERC.
2.Calculations
The calculated NITS Retail Transmission Rates are shown in Appendix A of the Company's
FERC Informational Filing of its Annual Update of transmission service.NITS rates as
determined for the following classes:
Residential Service Customers
General Service Customers less Man or equal to 20 kW
General Service Customers over 20 kW and less than 3 MW
General Service Customers equal to and greater than 3 MW
In addition to NITS, APS charges retail customers for other transmission services in accordance
with its OATT. These additional ancillary services include:
Schedule 1 - Scheduling, System Control and Dispatch Service
Schedule 3 - Regulation and Frequency Response Service
Schedule 4 - Energy Imbalance Service
EffectiveDate XX/XX/ XXX
l
lPage 1 of 3
76295DECISION no.
DOCKET no. E-01345A-I6-0036 ET AL.Appendix Q
Page 2 of 35
Q ops
PLAN OF ADMINISTRATION
ADIUSTMENT SCHEDULE TCA
TRANSMISSION COST
Schedule 5 - Operating Reserve-Spinning Reserve Service
Schedule 6 - Operating Reserve - Supplemental Reserve Service
APS's NITS rates will change annually, where ancillary service charges will change only through
a separate filing when made by the Company to FERC.
The total APS OATT rate is the sum of the rates for providing these services. The revenue
requirement resulting from the FERC APS OATT rate are collected by APS from its retail
customers, partly in base rates and the remaining through the TCA rate.
3.TCA Balancing Account
APS will maintain accounting records that accumulate the difference in revenues anticipated to
be recovered by the TCA, as compared to the actual revenues received by the Company through
the TCA during the recovery period (lune through May). The difference will be recorded to the
TCA Balancing Account each month and will be provided annually in Attachment C of die
filing. In the event the actual TCA revenues for the recovery period (June dirough the last billing
cycle of May) are more or less than the anticipated revenues for that same period, the over or
under collection will be subtracted from or added to the TCA balancing account calculation for
the subsequent period.
4.Filing and Procedural Deadlines
APS will file the calculated TCA rates with the Commission each year no later than May 15**', in
the form of Attachments A through H as attached to this document and described in Section 5.
ComplianceReports.9
The Commission Staff and interested parties shall have the opportunity to review APS's FERC
Informational Filing of its Annual Update of transmission service rates pursuant to the APS
OATT Attachment H-2, Formula Rate Implementation Protocols. The calculated NITS Retail
Transmission Rates are shown in Appendix A of the Company's FERC filing. The new TCA
rates proposed by APS will go into effect with the first billing cycle in ]ume (without proration),
unless Staff requests Commission review or otherwise ordered by the Commission, and will
remain in effect for the following 12-month period.
5. Compliance Reports
APS will provide an annual report to Staff detailing all calculations related to the calculated TCA
rates. The reports will include the following Attachments A through H as attached to this
document:
i
ll
Attachment A:
Attachment B:
Attachment C:
Attachment D:
Attachment E:
Non-redlined version of the new Adjustment Schedule TCA-1 Revision
Redlined version of the new Adjustment Schedule TCA-1 Revision
Numerical inputs used to develop the new TCA-1 rates
Estimated monthly bill impacts of the new TCA-1 rates
Table illustrating the percentage demand of each of the classes for the
20XX OATT and 20XX OATT as filed with FERC
Effective Date XX/XX/ XXX Page 2 of 3
DECISION no.76295
DOCKET NO. E-01345A-16-0036 ET AL.Appendix Q
Page 3 of 35
Q ops
PLAN OF ADMINISTRATION
ADIUSTMENT SCHEDULE TCA
TRANSMISSION COST
Attachment F:
Attachment G:
Attachment H:
Table illustrating the transmission cost embedded in base rates, the
current and proposed TCA rates, and the differences in the current and
new rates
Actual and estimated transmission additions, dollars and estimated O&M
for calendar years 20XX through 20XX (1 year actual and 2 years forecast)
APS's Annual Update of transmission service rates pursuant to the APS
OATT as filed with FERC
Effective Date XX/XX/XXX Page 3 of 3
DECISION no.76295
DOCKET no. E-01345A-16-0036 ET AL.Appendix Q
Page 4 of 35
Attachment A
APPLICATION
The Transmission Cost Adjustment ("TCA") charge shall apply to all Standard Offer retail electric schedules. All
provisions of the customers current applicable rate schedule will apply in addition to this charge.
ANNUAL ADJUSTMENT
Standard Offer rate schedules covered by this charge include a transmission component of base rates that was
originally established at $000000 per kilowatt-hour in accordance with A.C.C. Decision No. 67744. Decision No.
67744 also established the TCA. Decision No. 69663 modified the collection of transmission costs in retail rates to
tie to the costs found in the FERC approved Open Access Transmission Tariffs
RATE
The charge shall be applied as follows:
Customer Class
Residential
General Service 20 kW or less
General Service over 20 kw under 3000 kW
General Service 3.000 kW and over
TCA Char e
$0.000000/kWh
$0.000000/kWh
$0.000/kW
$0.000/kW
9
I
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix Q
P 5 of 35Attachmer8g§
APPLICATION
The Transmission Cost Adjustment ("TCA") charge shall apply to all Standard Offer retail electric schedules. All
provisions of the customers current applicable rate schedule will apply in addition to this charge.
ANNUAL ADJUSTMENT
Standard Offer rate schedules covered by this charge include a transmission component of base rates that was
originallyestablished at $0.00000 per kilowatt-hour in accordance with A.C.C. Decision No. 67744. Decision No.
67744 also established the TCA. Decision No. 69663 modified the collection of transmission costs in retail rates to
tie to the costs found in the FERC approved Open Access Transmission Tariff
RATE
The charge shall be applied as follows:
TCA Char e»
$0.000000/kWh
$0.000000/kWh
$0.000/kW
$0.000/kW
CustomerClass
Residential
General Service 20 kW or less
General Service over 20 kw. under 3.000 kW
General Service 3.000 kW and over
o
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix Q
Page 6 of 35
Attachment C
TCA Rate Calculation - Plan of Administration
ResidentialLine GS520 kWService Type
Rem ii Transmission Rates
GS_>3 MW
$/kw
(D)
$/kwh
<B)
GS > 20 kW
and < MW
$/kW
(C)
$/kwh
(A)
0.0000.000000 0.0000.0000001.nITs (A)
2.
3.
4.
0.000
0.000
0.000
0.000
0.000
0.000000
0.000000
0.000000
0.000000
0.000000
0.000
0.000
0.000
0.000
0.000
0.000000
0.000000
0.000000
0.000000
0.000000
5.
6.
Scheduling (B)
Regulation & Frequency (B)
Spinning Reserve (B)
Operating Reserve (B)
Energy imbalance (B)
0.000000 0.000000 0.000 0.0007.Total (Lines 1 thru 7)
0.000 0.0000.000000 0.000000Included In Retail Base Rates (C)
0.000000 0.000000 0.000 0.000Balancing Account (D)
9
0.0000.0000.0000000.00000010.TCA (Line 7 - Line 8 + Line 9) (E)
(A) Source: Attachment H, Appendix A of Attachment H-1, Lines 161-164 - (Aps's FERC Formula Rate
Annual Update of transmission service rates pursuant to the APS OATH)
Source: Ancillary Services as defined in Schedule 11 of the APS OATT
Source: Base Transmission Rates as approved in Decision No.XXXXX
Source; TCA Balancing Account Workpaper Detail (to be provided with TCA filing)
Amounts presented in Attachment A and Attachment B
(B)
(C)
(D)
(E)
76295DECISION no.
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76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix Q
Page 10 of 35
Attachment E
Class Coincident Peak Demand
Class
20XX
%of Colnddent Demand %on!Colncldent Demand
0.00%Residential 0000.0 0000.0 0.00%
General Service < MW 0000.0 0.00%0000.0 0.00%
0.00%General Service > 3 MW 0000.0 0000.0 0.00%
0.00%Total 0000.0 0000.0 0.00%
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DOCKET NO. E-01345A-16-0036 ET AL.Ansanovq g us d i
AUICYIYBHK PP
Arizona Public Service Company
YEAR
FERC Fo l mi Pa g e 1 9 /
ln n mcd a nN u t sFormula Rate - A nix A
Shaded cells are input cells
W a g - I Sl a y Al l o u d o n F a ci a l
Tnunsmvsmon Wages Expense 0oasis 21 n
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Attachment 5
( L u a u )
(Lne 5)
(19 . 20)
22 TOTAL put In Service (L m¢ 1 1 2 n o
Accumulnod Depreenhan
INTO B\Tn - mm4 e n Aa a lmllm¢ Dwvn ca n o n
A:u»rv\um»a Dcwocmon for Tnnsmvssnon Pam Addllam lov Cxnreni Rate v l a
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AUNIMTIGIK 5
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(Line 28 Line 24)
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30
31
32
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Tom Acannulnua Dcuocsauon
Whee 6 Snlarv Allaauan Fncio
Go vn r d Al l o cl d n o T n - mh si o n
TOTAL Au u md le d De p ve e iNo n
TOTAL Na t Pra o u rW. p m a Eq mn me n !
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76295DECISION no.
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76295
DECISION no.
A¢gta GvqnnuéDOCKET no. E-01345A-16-0036 ET AL.
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nu Raw nuo nomuornom rm mo Bus pop mcruu n ROE
net Tnnsmsuon pun:
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salary mnua ulv nltsulg minted n Aocoul 9301
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elected an use nmomzamn al ax cr\4l!s lgansl uxabie ncomt. rllhtl Min hook he creels lo Account No 255 Ind reduce
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mulhv hu by (IIIT) A uhlny mud pal rnduae my umm at e redudmn m rule base and as m amorlzlhen ague! Iax lble income
n IM ax nuts change arr ng I cuenau y ear. in lv erige Nu me w t be Mn cakrhled beau w Me number or Aly s eur w as Mlecnv e Mme altnaar na
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P Changes m aepv eemmm or emannnen tex must he Md w lh in Common. as w et as lay new aepfeclmn or amonnenon Mn
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76295DECISION NO.
DOCKET no. E-01345A-16-0036 ET AL.Appendix O
Page 22 of 35
Arizona Public Service Company
Attachment2 Taxes OtherThan IncomeWorksheet
Allocator
Albclfed
Amour!Other Taxes
Page 263
Col ro
Gro s s plant AllocalorP la n!Relalad
Transmission Personal Property Tax (directly assigned to Trarlsmusslon)
2 Capital Stock Tax
3 Gross Premuun (unsumoe) Tax
4 P U R T A
5 Com License
100%
o 0000%
00000%
0.000096
0.000094
0000096
s
s
s
s
s
s
00Total Plan! Related
LaborRelneu Wages a Salary Allocator
6 Federal FICA s. Unemdoyment & state unemployment
00000940 0Tore/Labor Related
Gro s s Plan!Allo ca te /
0
Otherlncluded
7 Miscellaneous
0o 0000%0Total Omer lnclwed
0TotalInclude d
v
CurrentlyEx clud'ad
0
0
8 Use 8 Sales Tax
9 Adlusl state and local tax leseve
10 Other Sales & Use Tax
11 Other Personal Property Tax (excluded)
12
13
14
i s
16
17
LB
19
2 0
021 Teal Other" Taxes (included on p 263)
22 Total Taxes Other Than come Taxes acct 40810 (p 114 14)
23 Difference
B
c
D
E
Cntaia la Allocation:
A Otter taxes that are incurred through ownership d plot rrrcludlng tratsmlssion plant will be allocated based on the Gross Platt
Allocator n the taxes ah 100% recovered al retail they will not be inckided
Other taxes fret are lr\cured through ownership d only general a lmangble plmtwill be allocated based on the Wages and Salary
Nloca tor 11 the taxes ah 100% recovered al retail they will not oh included
Otter taxes mal are assessed based on labor will be allocated based on the Wages and Stay Allocator
Other taxes except as provided for n A B and C above that are rnmrred and (1) ah not fully recovered at retail a (2) ah
erectly or indirectly related to transmission service will be allocated based on tie Gross Platt Nlocator; provided however. that
overheads shall be treated as n footnote B above
Excludes prior period edlustments in tM fist year of the 1brmulas operation Sid reconciliation for the first yea
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.AppenCax o
page 23 of 35
Arizona Public Service Company
Attachment 3 Revenue Credit Workpaper
Account 454 Rem from Electric Property
1 Ran from Electric Property Transmsssum Related (Note 3)
2 Total Rem Revenues (Sun Lanes 1)
Accomt 456 . O01er Electric Reveres (Mic 1)
Paso Ine 1 column g3 Scneduing Swtem Com rd a Dispatch (Anal Samoa)
4 Net revenues asoclatm with Network IntegratIon Tmmmissnn Mum (NWS) for whim
me load us nM included in the drvusa (Note 4)
5 Porno to Point Mime revenues for mm the load ms not mlmm In the divusa leoerved by TrammIwnn Owner (Mte 4)
6 Transmcnal Review nwmny (Note 1)
7 Transmonal Maki Expanse (Note 1)
8 Prdessronal Services (Note 3)
9 Revenues from Dnredly Assigned Trawsmusswn Feculity Charges (Note 2)
10 Ran or Attachment Fees associated with Trmsmnsslon Feciliies (Note 3)
(Sun Lines 210)11 Gross Revive Credits
12 Lure 17g
13 Total Revenue Credits
1 1A l 1 k U I l l Ulll I .L
14 Note 1 All reveres rdaled to rransmusswn the are recervad as a trmsmnsseon owner (| e.
nor received as a LSE) for which me cost d the service us recovered meer thus famu\a
except as speciflcaliy provIded for elsewhere n thus Attachment a elsewhere an me formUla
vIII be nduaed as a revenue cfedn a included n lM peak on lane 171 d Appendlx A.
15 Note 2 K ere costs associated w 1ih the D 1ectty Assigned Transmnsslon Facility Charges are
nduaed an me Roes. the associated revenues are uncluaed in me Rates n the costs
associated with the Deedly Assigned Transmission Facllrty Qharges are nd tncluaed nn Me
Rates. me associated revenues are nd included m the Rates
16 Nate 3 Ratemakng treatment for me ldlowng spedued seccndsry uses of trmsmnsstm
assets (1) rightolway leases and leases fa space on trawsmrssron facilities for
telecommunications; (2) transmission lower Incenses for wireless antennas (3) rightdway
property leases fa farming grazing or nurseries (4) licenses d umetleaual property
(tncludrng a pnnane Ola degasmcatam process and sdtedulng software); and (5)
tratsmvssuon mantenmce aid consulting services (Including enaglzed crcurt maintenance.
hlg1vdtage substaum maintenance. salety tea»nlng translormer oil testing. ad clrwrt
breaks testing) to War Llrhttes and loge custcmas (oollearvely produas) Company will
relate 50% d net revenues oonsnstent wNh Pacifnc Gas Md Electric Company. 9) FERC 11
61.314 note rn order to use Ines 17a . 17g tie \JtIIIty must trade n separate smeecounts
the revenues and costs associated nth each secondary use (except for the cost at Tm
associated income taxes)
17a Reva1Les Included nn ones 111 whit are select to so/so sharing
17b Costs assoaaed with revenues nn one 17a
17c net Revenues (17a . 17b)
17a 50% Share d Net Revelues (17c I 2)
17e Costs associated with revenues an line 17a that are included in FERC acoourns recovered
through me formula times me allocator used lo iunctuonehze me anounls n the FERC
accord! to the ¢ra1smlsslon servloe at issue
17f new Revenue Credit (we + 17e)
17g Lune 17f less me 17a
18 Note 4: If the lacilites associated with the revenues are nm mciuried n TM formula. :re
revenue ms shown hoe but no included n me total above and as exptalned n me Cos\
Support; for example revenues associated wllh dustrbuncn facilities.
19 menu d'fset in Ire 4 above
2o TeaalA¢¢oum454ar\a45e
000%Composure Tax Rate
76295DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix Q
Page 24 of 35
Arizona Public Service Company
Attachment 4 Calculation of 100 Basis Point Increase in ROE
A 100 Basis Point increase nn ROE and Income Taxes Line 12 + Line 23
100 Basis Point increase in ROEB 1.00%
Return Calculation
1 Rate Base Appendix A Lune 51
2
3
4
Debt °/o
Preferred %
Common °/o
0.0%
0.0%
0.0%
Appendix A Line 99
Appendix A Line 100
Appendix A Line 101
5
6
7
Debt Cost
Preferred Cost
Common Cost
0.00%
0.00%
11.75%Appendix A % plus 100 Basis Pts
Appendix A. Line 102
Appendix A Line 103
Appendix A Line 104 + 1%
8
9
10
11
Appendix A Line 105
Appendix A Line 106
Line 4 Line 7
Sum Lines 8 no 10
0.0000
0.0000
Weighted Cost of Debt
Weighted Cost of Preferred
Weighted Cost of Common
Total Recur ( R )
Investment Return = Rate Base Rate of Return12 Line 11 Line 1 0
Composite Income Taxes
13
14
15
16
17
000%
000%
0.00%
0.00%
0.00%
Income Tax Rates
FIT=FederaI Income Tax Rate
SIT=State Income Tax Rate or Composite
p (percent of federal income tax deductible for state purposes)
T =1 . ([(1 SIT)(1 . FIT)]/(1 SIT FIT P)) =
T/ (1T)
Appendix A Llne 110
Appendix A Line 111
Appendix A Llne 112
Appendix A Line 113
Appendux A Line 114
ITC Adjustment
0.0000%
0.oooo%
18
19
20
21 o
Amortized Investment Tax Credit
1/(1T)9
Net Plant Allocation Factor
ITC Adjustment Allocated to Transmission
Appendix A. Line 115
Appendix A Line 116
Appendix A Line 117
Appendix A Line 118
22 Income Tax Component = C1T=(Tl1T) ' Investment Return (1 (WCLTD/R)) =Line 17Line 12(1(Lane a/Line 111)
Total Income Taxes23 Line 21 4 22"
I
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DECISION no.
DOCKET no. E-01345A-16-0036 ET AL.Appendix Q
Page 35 of 35
Arizona Public Service Company
Attachment 8 - Depreciation Rates
L Plant Account |Rates |
1.84°/o
2.14%
1.34%
2.21%
2.10%
1.87%
1.55%
1.33%
352.01 - Structures
353 - Station Equipment
354 - Towers and Fixtures
355.01 - Poles and Fixtures - Wood
355.02 - Poles and Fixtures - Steel
356 - Overhead Conductors and Devices
357 - Underground Conduit
358 - Underground Conductors and Devices
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DECISION NO.
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Appendix R
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