PINNACLE WEST CAPITAL CORP - FORM 10-Q - EX-10.1 - EXHIBIT 10.1

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - PINNACLE WEST CAPITAL CORP	a033117exhibit322.htm
EX-32.1 - EXHIBIT 32.1 - PINNACLE WEST CAPITAL CORP	a033117exhibit321.htm
EX-31.4 - EXHIBIT 31.4 - PINNACLE WEST CAPITAL CORP	a033117exhibit314.htm
EX-31.3 - EXHIBIT 31.3 - PINNACLE WEST CAPITAL CORP	a033117exhibit313.htm
EX-31.2 - EXHIBIT 31.2 - PINNACLE WEST CAPITAL CORP	a033117exhibit312.htm
EX-31.1 - EXHIBIT 31.1 - PINNACLE WEST CAPITAL CORP	a033117exhibit311.htm
EX-12.3 - EXHIBIT 12.3 - PINNACLE WEST CAPITAL CORP	exhibit123-33117.htm
EX-12.2 - EXHIBIT 12.2 - PINNACLE WEST CAPITAL CORP	exhibit122-33117.htm
EX-12.1 - EXHIBIT 12.1 - PINNACLE WEST CAPITAL CORP	exhibit121-33117.htm
10-Q - 10-Q - PINNACLE WEST CAPITAL CORP	pnw-3311710q.htm

Exhibit 10.1

ARIZONA PUBLIC SERVICE COMPANY

DOCKET NOS. E-01345A-16-0036 and E-01345A-16-0123

SETTLEMENT AGREEMENT

MARCH 27 2017

TABLE OF CONTENTS


I.	RECITALS 5


II.	RATE CASE STABILITY PROVISION 8


III.	RATE INCREASE 8


IV.	BILL IMPACT 8


V.	COST OF CAPITAL 9


VI.	DEPRECIATION/AMORTIZATION AND DECOMMISSIONING 9


VII.	FUEL AND POWER SUPPLY ADJUSTMENT PROVISIONS 10


VIII.	TRANSFER OF ITEMS FROM ADJUSTMENT MECHANISMS TO BASE RATES 11


IX.	RATE TREATMENT RELATED TO THE INSTALLATION OF SELECTIVEATALYTIC REDUCTION EQUIPMENT AT FOUR CORNERS UNITS 4 AND 5 12


X.	COST DEFERRAL RELATED TO THE OCOTILLO MODERNIZATION PROJECT 13


XI.	COST DEFFERAL RELATED TO CHANGES IN ARIZONA PROPERTY TAX RATE 13


XII.	COST OF SERVICE STUDY 14


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 DESIGN 17


XVIII.	RESIDENTIAL RATE DESIGN FOR DISTRIBUTED GENERATION CUSTOMERS 19


XIX.	RESIDENTIAL RATE AVAILABILITY 20


XX.	COMMERCIAL AND INDUSTRIAL RATE DESIGN 21


XXI.	E-32L RATE DESIGN 21


XXII.	SCHOOLS DISCOUNT RATE RIDER 21


XXIII.	AG-X 21


XXIV.	MILITARY CUSTOMERS 23


XXV.	REVENUE SPREAD 23


XXVI.	EFFECTIVE DATE OF RATE PLANS AND TRANSITION PLAN 24


XXVII.	FIVE MILLION DSMAC ALLOCATION 24


XXVIII.	AZ SUN II 24


XXIX.	LIMITED INCOME PROGRAMS 26


XXX.	AMI OPT-OUT/SCHEDULE 1 27


XXXI.	SCHEDULE 3 27


XXXII.	LOST FIXED COST RECOVERY MECHANISM 27


XXXIII.	ENVIRONMENTAL IMPROVEMENT SURCHARGE 28


XXXIV.	TRANSMISSION COST ADJUSTMENT MECHANISM 28


XXXV.	CHALLENGES TO DECISION NOS. 75859 AND 75932 28


XXXVI.	POWER SUPPLY ADJUSTOR AUDIT 29


XXXVII.	COMPLIANCE MATTERS 29


XXXVIII.	FORCE MAJEURE PROVISION 29


XXXIX.	COMMISSION EVALUATION OF PROPOSED SETTLEMENT 29


XL.	MISCELLANEOUS PROVISIONS 30

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-16-0123)

The purpose of this Settlement Agreement (“Agreement”) is to settle disputed issues related to Arizona Public Service Company’s (“APS” or “Company”) application to increase its rates (Docket No. E-01345A-16-0036) and the fuel and purchased power procurement audit of APS (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/a ConservAmerica

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.


I.	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

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

Exhibit 10.1

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); Aguila Irrigation District (“AID”); Tonopah Irrigation District (“TID”); Harquahala Valley Power District (“HVPD”); and Maricopa County Municipal Water Conservation District Number One (“MWD”) (collectively, Districts); SunRun; 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”); and Granite Creek Power & Gas and Granite Creek Farms LLC (collectively, “Granite Creek”). SunRun 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, 2017; 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.

1.4

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:

Exhibit 10.1


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 1, 2019;


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;

g. Continuation of crisis bill assistance for low income customers;

h. More off-peak hours and holidays for time-differentiated rates;


i.	A moratorium on new self-build generation until January 1, 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.


l.	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;

Exhibit 10.1


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.

Exhibit 10.1

TERMS AND CONDITIONS


II.	RATE CASE STABILITY PROVISION


2.1.	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.


II.	RATE INCREASE


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 “2015 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 $9,990,561,000. 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.


III.	BILL IMPACT


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.


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.


V.	COST OF CAPITAL


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 or 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 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 143” 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 $0.032071 per kWh as set in the Decision No. 73183 to $0.030168 per kWh. 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 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.


VIII.	TRANSFER OF ITEMS FROM ADJUSTMENT MECHANISMS TO 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 (“EIS”), 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 EIS; 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 Staff’s revenue conversion factor.


8.3	On the effective date of the new rates contained in this Agreement, the REAC, DSMAC, LFCR, TCA, EIS, FCRR and SBC rates shall be reduced to reflect the removal of the amounts identified in Appendix D.


IX.	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 adjustment request such that any resulting rate adjustment becomes effective no later than January 1, 2019, pursuant to Section 9.1.


9.4	The Signing Parties shall not present any issues in the rate adjustment proceeding other than those specifically described in this Section.


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, 1 CA-CC-15-0001.


X.	COST DEFERRAL RELATED TO THE OCOTILLO MODERNIZATION PROJECT

10.1

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 APS’s 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 of OMP 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.


XI.	COST DEFERRAL RELATED TO CHANGES IN ARIZONA 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 property 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 property tax rate deferral that has a positive balance will be recovered from customers over 10 years, with a return at APS’s 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.


XII.	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 4CP. 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.


II.	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 31st, until the conclusion 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.


III.	SELF-BUILD MORATORIUM


15.1	APS will not pursue any new self-build generation option having an in-service date prior to January 1, 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: (1) 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) uprates 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.


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.


IV.	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;


iii.	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.


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 1^st 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 kWh charge.


iii.	The adjustor mechanism will include a balancing account such that any under- or over-collected balance will be 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.


V.	RESIDENTIAL RATE DESIGN


17.1	R-XS: Rate Schedule “R-XS” is available to customers without distributed generation using 600 or less kWh 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 kWh but less than 1,000 kWh 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.


17.3	R-Basic Large: Rate Schedule “R-Basic Large” is available to customers without distributed generation using 1,000 kWh 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.

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 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.

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.


VI.	RESIDENTIAL RATE DESIGN FOR DISTRIBUTED 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 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.


VII.	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 1, 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 1, 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.


VIII.	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.


IX.	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.


X.	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.


XI.	AG-X


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.


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.

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 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.


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.

23.11

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 kWh. 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.


XII.	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.


XIII.	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 customers proportionally to the original revenue spread. Attached as Appendix L is the revenue spread/targets summary.


XIV.	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 1, 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.


XV.	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.


XVI.	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.


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.

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.

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 Adjustment 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 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.


XVII.	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.


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.


XVIII.	AMI OPT-OUT/SCHEDULE 1


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 1, attached as Appendix M.


30.2	Changes to Schedule 1 are attached in Appendix M.


XIX.	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 (1) 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.


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 kWh charge for customers with a two-part rate without demand.


32.3	APS shall submit its LFCR compliance filings on February 15^th 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.	MODIFICATION TO ENVIRONMENTAL IMPROVEMENT SURCHARGE


33.1	APS shall be permitted to increase the cumulative per kWh cap rate for the Environmental Improvement Surcharge (“EIS”) from the current $0.00016 to a new rate of $0.00050 and include a balancing account.


33.2	A copy of the revised EIS Plan of Administration is attached as Appendix P.


XXXIII.	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 1 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 all appeals that will suspend the filing of all pleadings, motions, briefings, or other court 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	Staff’s 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

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 Party 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.


39.3	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 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.


40.3	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.

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	ARIZONA CORPORATION COMMISSION

	By: /s/ Elijah Abinah
	Name: Elijah Abinah
	Title: Acting Director, Utilities Division
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Arizona Public Service Company

	By: /s/ Barbara Lockwood
	Name: Barbara Lockwood
	Title: Vice President, Regulation
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Residential Utlity Consumer Office

	By: /s/ David Tenney
	Name: David Tenney
	Title: Director
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Arizona Utility Ratepayer Alliance

	By: /s/ Patrick J. Quinn
	Name: Patrick J. Quinn
	Title: Managing Partner
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Federal Executive Agencies

	By: /s/ Lanny L. Zieman, Captain, USAF
	Name: Lanny L. Zieman, Captain, USAF
	Title: Utilities Litigation Attorney
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Arizona Solar Deployment Alliance

	By: /s/ Sean M. Seitz
	Name: Sean M. Seitz
	Title: President
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	AriSEIA

	By: /s/ Thomas A. Harris
	Name: Thomas A. Harris
	Title: Treasurer, AriSEIA
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Vote Solar

	By: /s/ Adam Browning
	Name: Adam Browning
	Title: Executive Director
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Solar Energy Industries Association

	By: /s/ Sean Gallagher
	Name: Sean Gallagher
	Title: Vice-President State Affairs
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Energy Freedom Coalition of America

	By: /s/ Court S. Rich
	Name: Court S. Rich
	Title: Attorney for Energy Freedom Coalition of America, LLC
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Arizona School Board Association and the Arizona Association of School Business Officials

	By: /s/ Timothy M. Hogan
	Name: Timothy M. Hogan
	Title: Attorney
	Date: March 23, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Arizonans for Electric Choice and Competition

	By: /s/ Stan Barnes
	Name: Stan Barnes
	Title: President
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Western resource Advocates

	By: /s/ John Nielsen
	Name: John Nielsen
	Title: Clean Energy Program Director
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Wal-Mart Stores, Inc. and Sam's West, Inc.

	By: /s/ Scott Wakefield
	Name: Scott Wakefield
	Title: Attorney
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Lubin & Enoch, P.C.

	By: /s/ Nicholas J. Enoch, Esq.
	Name: Nicholas J. Enoch, Esq.
	Title: Attorney for Intervenors, IBEW Locals 387 & 769
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Freeport Minerals Corporation

	By: /s/ Michael McElrath
	Name: Michael McElrath
	Title: Director Energy
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Arizona Community Action Assoc.

	By: /s/ Cynthia Zwick
	Name: Cynthia Zwick
	Title: Executive Director
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	The Kroger Co.

	By: /s/ Kurt Boehm
	Name: Kurt Boehm
	Title: Attorney
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Arizona Investment Council

	By: /s/ Gary Yaquinto
	Name: Gary Yaqunito
	Title: President & CEO
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Property Owners & Residents Association (PORA) Sun City West

	By: /s/ Al Gervenack
	Name: Al Gervenack
	Title: Director, Board of Directors
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Sun City Home Owners Association (SCHOA)

	By: /s/ Greg Eisert
	Name: Greg Eisert
	Title: Director, Chairman of Government Affairs
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	REP America d/b/a ConservAmerica

	By: /s/ Timothy J. Sabe
	Name: Timothy J. Sabe
	Title: Attorney for ConservAmerica
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Constellation New Energy, LLC

	By: /s/ Lawrence V. Robertson Jr.
	Name: Lawrence V. Robertson Jr.
	Title: Attorney
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Direct Energy Business, LLC

	By: /s/ Lawrence V. Robertson Jr.
	Name: Lawrence V. Robertson Jr.
	Title: Attorney
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Calpine Energy Solutions, LLC

	By: /s/ Lawrence V. Robertson Jr.
	Name: Lawrence V. Robertson Jr.
	Title: Attorney
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Arizona Competitive Power Alliance

	By: /s/ Greg Patterson
	Name: Greg Patterson
	Title: AzCPA Director
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	City of Coolidge

	By: /s/ Denis M. Fitzgibbons
	Name: Denis M. Fitzgibbons
	Title: City of Coolidge Attorney
	Date: March 24, 2017

Arizona Public Service Company

Proposed Settlement Agreement

Docket Nos. E-01345A-16-0036 and E-01345A-16-0123

SIGNATURE PAGE



	Granite Creek Farms LLC Granite Creek Power & Gas LLC

	By: /s/ Thomas E. Stewart
	Name: Thomas E. Stewart
	Title: General Manager
	Date: March 24, 2017

Appendix F \ Wl

Appendix F Page 1 of 6 Q ops RATE SCHEDULE R-TECHRESIDENTIAL SERVICE PILOT TECHNOLOGY RATE AVAILABILITY I i 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 die R-Tech pilot program are as follows: 1. K I I i I b. c. Primary technologies: a. A rooftop solar photovoltaic system. The size 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. 1 2. b. c . d . 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. 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) ARIZONA PUBLIC SERVICE COMPANY Phoenix Arizona Filed by: Charles A. Miessner Title: Manager Regulation and Pricing AC.(. No. xxxx Original Rate Schedule RTech Effective: xxxx Page 1 of 5

Appendix F Page 2 of 6 Q ops RATE SCHEDULE R-TECHRESIDENTIAL 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 - ]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, 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 moodily bill will consist of the following charges, plus adjustments: Bundled Charges Basic Service Charge $0.493 per day _ _ On-Peak Demand Charge per kW Off-Peak Demand Charge per kW Summer $20.25 $0.00 $6.50 Winter $14.25 $0.00 $6.50 First 5 kW All remaining kW ARIZONA PUBLIC SERVICE COMPANY Phoenix, Arizona Filed by: Charles A. Miessncr Title: Manager Regulation and Pricing A.C.C. No. xxxx Original Rate Schedule RTech Effective: xxxx Page 2 of 5

1 Appendix F Page 3 of 6 I I 2 i I Gaps RATE SCHEDULE R-TECHRESIDENTIAL SERVICE PILOT TECHNOLOGY RATE l On-Peak Energy Charge Off-Peak Energy Charge $0.05750 $004750 $0.04750 $004750 per kph per kph 1 l: I. I ! Unbundled Components of the Bundled Charges Bundled Charges consist of the components shown below. These are not additional charges. l 3 l l l lBasic Service Char e Com orients l l l l I| i . I I Customer Accounts Charge Metering Charge Meter Reading Charge Billing Charge $0.125 $0.215 $0.072 $0.081 per day per day per day per day Q Off-Peak Generation Charge On-Peak Generation Charge First 5 kW A11 remaining kW On-Peak Delivery Charge per kW per kW per kW per kW Off-Peak Delivery Charge per kW Demand Char e Com orients Summer $13.750 $0.000 $1.000 $6.500 $0.000 $5.500 Winter $7.750 $0.000 $1.000 $6.500 $0.000 $5.500 First 5 kW All remaining kW Ener Char eCo orients System Benefits Charge Transmission Charge Delivery Charge for all kph $0.00276 580.01097 $000210 per kph per kph per kph _Summer 350.04167 $0.03167 Winter $0.03167 $003167 Generation On-Peak kph Charge Generation Off-Peak kph Charge per kph per kph 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. AR17ONA PUBLIC SERVICE COMPANY Phoenix Arizona Filed by: Charles A. Miessner Title: Manager Regulation and Pricing A.C.C No. xxxx Original Rate Schedule R-Tech Effective: xxxx Page 3 of 5

Appendix F Page 4 of 6 Q ops RATE SCHEDULE R-TECHRESIDENTIAL 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 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. l l Any applicable taxes and governmental fees that are assessed on APS's revenues, prices, sales volume, or generation volume. RATE RIDERS i I : Eligible rate riders for this rate schedule are: I l I i I RCP EPR-2 EPR-6 E-3 E-4 GPS-1, GPS-2, GPS-3 Resource Comparison Proxy Partial Requirements Partial Requirements - Net Metering (Residential Non-Solar) Limited income discount Limited income medical discount Green Power SERVICE DETAILS 1. This pilot rate schedule requires the Customer to have a standard AMI meter in place. ARIZONA PUBLIC SERVICE COMPANY Phoenix Arizona Filed by: Charles A. Miessner Title: Manager Regulation and Pricing AC.C. No. xxxx Original Rate ScheduleRTech Fffective: xxxx Page 4 of 5

Appendix F Page 5 of 6 Q ops RATE SCHEDULE R-TECHRESIDENTIAL 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 singlephase, 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. 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. l I I I I i I I I ARI/ONA PUBLIC SFRVlClzCOMPANY Phloxnix Arizona Filed by: Charles A.Miessner Title: Manager Regulation and Pricing A.C.C.No.xxxx Original Rate Schedule RTtxh Effective:xxxx Page 5 of 5

Appendix F Page 6 of 6 Please note Appendix F also includes R-XS, R-Basic, R-Basic Large, TOU-E, R-2, and R-3 Rate Schedules which will be filed later. l l I I

Appendix H

i I Appendix H Page 1 of 21 Q ops 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. l DESCR1PT1ON l l l l l n. I l i I i 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 July l 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. ARIYONA I'UBI.l( SERVICF COMPANY Phoenix Arizona Filed by: Charles A. Miessner Title: Manager Regulation and Pricing A.C.C No. xxxx Rate Rider RCP Original liffectivc: xxxx Page l of 3

Appendix H Page 2 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: Tranche 2017 .$0.1290]up 1, 2017 thou h June 30, 2018 rkWh s • Tranche 2018 TBD Er kphJul 1, 2018 thou h June 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 willcarry 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 l i l5. 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). i ll l 1 ARIZONA PUBLIC SERVICE COMPANY Phoenix, Arizona Filed by: CharlesA. Miessner Title: Manager Regulation and Pricing AC.C No xxxx Rate Rider RCP Original Effective: xxxx Page 2 of 3 I

Appendix H Page 3 of 21 Q ops RATE RIDER RCP PARTIAL REQUIREMENTS SERVICE FOR NEW ON-SITE SOLAR DISTRIBUTED GENERATION RESOURCE COMPARISON PROXY EXPORT RATE SPECIAL CASES I. 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 grand fathering 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. 2. Increasing Capacity. 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 l kw, whichever is greater. 3. 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. 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 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). ARIZONA PUBLIC SERVICE COMPANY Phoenix Arizona Filed by: Charles A. Miessner Title: Manager, Regulation and Pricing A.C.C No. xxxx Rate Rider RCI' Original Effective: xxxx Page 3 of 3

Appendix H Page 4 of 21Q ops PLAN OF ADMINISTRATION RESOURCE COMPARISON PROXY Resource Comparison Proxy Plan of Administration Table of Contents 1. General l 3. Resource Comparison Proxy Purchase I 6. Calculation of Resource Comparison Proxy Purchase Rate 7. Procedural 6 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~scale 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: EffectiveDate XX/XX/XXX Page l of 6

Appendix H Page 5 of 21Q ops PLAN OF ADMINISTRATION RESOURCE COMPARISON PROXY • An RCP will be determined for each tranche of new DG Customers, effective July 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 July 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. I l • 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. I 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 Capacity 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 Capacih/ 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. Base Year. For the initial RCP calculation (effective July 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(s).For purposes of this Plan of Administration, an APS Customer taking service under a Residential rate schedule. Export(ed) Energv.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. Effective Date XX/XX/XXX Page 2 of 6

Appendix H Page 6 of 21Gaps PLAN OF ADMINISTRATIONRESOURCE COMPARISON PROXY 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. l 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 liffectivc Date XX/XX/XXX Page 3 of 6

Appendix H Page 7 of 21Q ops iil i i PLAN OF ADMINISTRATION RESOURCE COMPARISON PROXY l i 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). l I Ii. I SPECIAL CASES l l l l l l l I I IiI I I I I 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 grand fathering 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. I I I I Increasing Capacity. 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 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. 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 Idly 1, 2017 is $012900/kWh, 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 then 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. Effective Date XX/XX/XXX Page 4 of 6

Appendix H Page 8 of 21Q ops PLAN OF ADMINISTRATION RESOURCE COMPARISON PROXY 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 cont:ract 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

Appendix H Page 9 of 21Gaps PLAN OF ADMINISTRATIONRESOURCE 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 $0.02/ kph as provided for M Decision No. xxxxx. This amount is negotiated, does not reflect an actual calculation of system conditions, and establishes no precedent for any future RCP or avoided cost calculations. While future Commission proceedings may establish methodologies for calculation of the adjustments, no changes will be made to this value until the conclusion of the next APS general rate case. 7. Procedural Timeline The Company will provide Commission Staff and other intervening parties with its annual RCP calculation no later than March 1 each year. Interested parties will f i le comments to the Company's RCP calculation by April 1. Commission Staff will fi le its Report by May 15 and request that Staff's Report be considered in the June Open Meeting and be approved so that the new RCP calculation is effective on July 1. 8. Confidential Data Portions of the data used to calculate APS's annual RCP are competitively/highly confidential and cannot be released to the public. Competitively/highly confidential information will be made reasonably accessible to parties so that they may determine that such data supports the RCP calculation and that the RCP calculation complies with Commission orders. Competitively/highly confidential information includes cost and production data for facilities from which APS purchases energy under a PPA agreement. 9. Schedules l i Templates of the spreadsheet used to calculate the RCP are attached: 1 1 Schedule 1: Schedule 2: Schedule 3: Schedule 4: Schedule 5: Schedule 6:I I Annual Resource Comparison Proxy Calculation Summary Solar Photovoltaic Grid-Scale Plant Data and Levelized Cost Individual Plant Annual Cost ($/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 (95000) Each of these schedules contains competitively/highly confidential PPA data as indicated. effective Dale XX/XX/XXX Page 6 of 6

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Appendix H Page 16 of 21 Q ops RATE RIDER EPR-6PARTIAL 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 par ticipates 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: $0.02895 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 l'Ul3llC SliRVlCl5 COMPANY Phoenix Arizona Filed by: Charles A. Miessner Title: Manager Pricingand Regulation Original Effective Date: Idly 7 2(X)9 A.C.C. No. xxxx Cancelling A.C.C. N0.5866 Rate Rider FPR-6 Revision No. 3 Effec t ive: xxxx Page I of 3 l i l

Appendix H Page 17 of 21 Gaps 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; l l 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 II| 4. 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). SERVICE DETAILS I . 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 ARIZONA PUBLIC SERVICIQ COMPANY Phoenix Arizona Filed by: Charles A.Micssner Title: Manager Pricingand Regulation Original Effective Date: July 7, 2009 A.C.C. No. xxxx Cancelling A.C.C. N0.5866 Rate Rider EPR6 Revision No.3 Effective: xxxx Page 2 ola

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. 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). ARIZONA PUBLIC al=l<vlcuCOMPANY Phoenix, Arizona Filed by: Charles A. Miessner Title: Manager Pricing and Regulation Original Effective Date: July 7 2009 A.C.C. No. xxxx Cancelling A.C.C. No.5866 Rate Rider EPR-6 Revision No.3 Effective: XXXX Page 3 of 3

Appendix H Page 19 of 21 Q ops RATE RIDER LEGACY EPR-6PARTIAL 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 grand fathering program. Other residential Customers must meet the qualification requirements of the grandfathering program to take service under this schedule. Ir solar lear te o e ate c Der. e 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, residential Customer will not be eligible for a grandfathered solar Legacy Instead, the residential Customer will be served under an applicable l . and Rate Rider RCP, or a subsequent replacement rider. DESCRIPTION I I I W s » . . ; e ee e s ex e s en This rate rider describes how the Company wt Company's net metering program. A a quit serves some of their electrical red an r services. Export energy occurs st load in any instant and fl sto o participates in the storer has on-site generation that the Company for additional electrical e s generation is greater than their electrical s back to the Company's grid. .: : \ 5. Under this ii during I r, po energy ) will be netted against kph supplied by the Company g on or need and netted on a subsequent bill if necessary. 8 If a C r is served under a time-of-use rate, the export energy will be netted according to the on- d off-peak periods, i.e. on-peak export energy will be netted against on-peak energy the Company and vice-versa, for all unbundled components of the rate that have time-of-use 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 Company's near-term avoided costs and is revised from time to time. ARIZONA PUBLIC SERVICE COMPANY Phoenix Arizona Filedby: Charles A. Micssncr Title: Manager Pricing and Regulation A.C.C. No. xxxx Rate Rider EPR-6 Legacy Frozen Original Effective: xxxx Page l ot3

l I i Appendix H Page 20 of 21 Q opsi I I I l I I RATE RIDER LEGACY EPR-6 PARTIAL REQUIREMENTS SERVICE FOR ON-SITE RENEWABLE DISTRIBUTED GENERATION NET METERING I I II BILLING DETAILS I 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 . s are as The terms and conditions for the solar grand fathering program for residential Cust follows: • 9 0 | a n grid ice under the 1. Existing solar customers with systems interconnected to the C prior to Idly 1, 2017 and otherwise qualify for this rate rider grand fathering program. e l f ante o ap Ii (iii in in Ir urisdi f onto the Company by n fully executed sales or lease ; a rooftop solar system and obtain tty action within 180 days of their is u icy for this rate rider may take service under in connection is delayed by a third party or APS the Customer's installer, the Customer will have 270 our ' 3 9 sto ret Ir intercom 2. Customers who (i) submit a complete app Idly l, 2017; (ii) include in their intercom contract for their rooftop solar sys approval by the appropriate A interconnection application, nd the grandfatherin If through no fa days to c p section. • ; u f c • • I 3. a Er rid will be 20 years from the customer's initial interconnection date Les to the site where the system is located. 4. Ove e term of the grand fathering period, a Customer may not increase the capacity of 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 grand fathering 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. ARI/ONA PUBLIC SERVICF COMPANY Phoenix Arizona Filed by: Charles A. Miessner Title: Manager Pricing and Regulation A.C.C. No. xxxx Rate Rider FPR-6 Legacy Frozen Original Effective: xxxx Page2of 3

l l l Appendix H Page 21 of 21 l ll Q ops 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. \ W W l l l I A Customer may leave the grand fathering program and be served under a non-Legacy rate However, the Customer may not subsequently return to the grand fathering l 10. schedule. program at a later date. I SERVICE DETAILSn r I . 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 e divalent, installed to measure the production from their solar generation system as well an MI meter for electrical service. i 3. . I e c o ec . n Na u mer The Company provides service under this rider in accordance Requirements Manual. Service terms and conditions may interconnection or purchase agreement. tie s that:4. A Net Metering Facility is an on-site district omer's e r events at the site where the system isa. Provides part of the C installed; Iices, a defined by the Arizona Corporation Commission, to . O I 8 1 9 sb. Uses re gen ate .Q : te on Ted to and can operate in parallel and in phase with the Company's listing attribution system. ARIZONA PUBLIC SERVICE COMPANY Phoenix Arizona Filed by: Charles A. Miexsner Title: Manager Pricing and Regulation A.C.C.No. xxxx Rate Rider ll'R-6 Legacy Frozen Original Effective: xxxx Page 3 off

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