Exhibit 10.17

ARIZONA PUBLIC SERVICE COMPANY

PROPOSED SETTLEMENT AGREEMENT

DOCKET NO. E-01345A-11-0224

January 6, 2012

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TABLE OF CONTENTS

I.	RECITALS	5
II.	RATE CASE STABILITY PROVISION	6
III.	RATE INCREASE	6
IV.	BILL IMPACT	7
V.	COST OF CAPITAL	7
VI.	DEPRECIATION/AMORTIZATION AND DECOMMISSIONING	8
VII.	FUEL AND POWER SUPPLY ADJUSTMENT PROVISIONS	8
VIII.	RENEWABLE ENERGY	9
IX.	ENERGY EFFICIENCY/LOST FIXED COST RECOVERY/OPT-OUT RESIDENTIAL RATE/LARGE GENERAL SERVICE CUSTOMER EXCLUSION	10
X.	RATE TREATMENT RELATED TO ANY ACQUISITION BY APS OF SOUTHERN CALIFORNIA EDISON’S SHARE OF FOUR CORNERS UNITS 4-5	15
XI.	MODIFICATION TO ENVIRONMENTAL IMPROVEMENT SURCHARGE	16
XII.	COST DEFERRAL RELATED TO CHANGES IN ARIZONA PROPERTY TAX RATE	16
XIII.	TRANSMISSION COST ADJUSTMENT MECHANISM	17
XIV.	LOW INCOME PROGRAMS	18
XV.	SERVICE SCHEDULE 3 (LINE EXTENSIONS)	18
XVI.	BILL PRESENTATION	18
XVII.	RATE DESIGN	18
XVIII.	COMPLIANCE MATTERS	19
XIX.	FORCE MAJEURE PROVISION	20

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XX.	COMMISSION EVALUATION OF PROPOSED SETTLEMENT	20
XXI.	MISCELLANEOUS PROVISIONS	21

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PROPOSED SETTLEMENT AGREEMENT OF DOCKET NO.

E-01345-A-11-0224 ARIZONA PUBLIC SERVICE COMPANY REQUEST
FOR RATE ADJUSTMENT

The purpose of this Settlement Agreement (“Agreement”) is to settle disputed issues related to Docket No. E-01345A-11-0224, Arizona Public Service Company’s (“APS” or “Company”) application to increase rates.  This Agreement is entered into by the following entities:

Arizona Corporation Commission Utilities Division (“Staff”)

Arizona Public Service Company (“APS”)

Residential Utility Consumer Office (“RUCO”)

Cynthia Zwick

Federal Executive Agencies (“FEA”)

Kroger Co. (“Kroger”)

Freeport-McMoRan Copper & Gold Inc. (“Freeport-McMoRan”)

Arizonans for Electric Choice and Competition (“AECC”)

Wal-Mart Stores, Inc. and Sam’s West, Inc. (“Wal-Mart”)

IBEW Locals 387, 640, 769 (“IBEW”)

AzAg Group (“AzAG”)

Arizona Competitive Power Alliance (“AzCPA”)

AARP (“AARP”)

Arizona Association of Realtors (“AAR”)

Barbara Wyllie-Pecora (“Wyllie-Pecora”)

Arizona Investment Council (“AIC”)

Southwestern Power Group II, LLC (“SWPG”)

Bowie Power Station, LLC (“Bowie”)

Noble Americas Energy Solutions LLC (“Noble”)

Constellation NewEnergy, Inc. (“Constellation”)

Direct Energy, LLC (“Direct”)

Shell Energy North America (US), L.P. (“Shell”)

These entities shall be referred to collectively as “Signatories;” a single entity shall be referred to individually as a “Signatory.”

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I.RECITALS

1.1APS filed the rate application underlying Docket No. E-01345A-11-0224 on June 1, 2011.  Staff found the application sufficient on July 1, 2011.

1.2Subsequently, the Arizona Corporation Commission (“Commission”) approved applications to intervene filed by AARP, Arizona Association of Realtors, AzCPA, AIC, ASBA, Association of School Business Officials, AZAg Group, Barbara Wyllie-Pecora, Cynthia Zwick, FEA, Freeport-McMoRan and AECC (collectively “AECC”), IBEW Locals 387, 640 and 769, Interwest, Kroger, Mel Beard, Noble et al, NRDC, RUCO, SWEEP, SWPG, Bowie, TEP, the Town of Gilbert, the Town of Wickenburg, Wal-Mart and Sam’s Club,   and WRA.  Mel Beard subsequently withdrew as an intervenor in the case.

1.3APS filed a notice of settlement discussions on November 18, 2011.  Settlement discussions began on November 30, 2011.  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.  Commission Staff filed a Preliminary Term Sheet regarding this matter on December 9, 2011, which was discussed in a Special Open Meeting held on December 16, 2011.

1.4The 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 convenience, comfort and safety, and the preservation of health, of the employees and patrons of APS; resolve the issues arising from this Docket; and avoid unnecessary litigation expense and delay.

1.5The Signatories believe that this Agreement balances the interests of both APS and its customers.  These benefits include:

·an overall zero dollar base rate increase;

·a zero percent bill impact for the remainder of 2012 (Commission-approved adjustors (including the possibility of a Four Corners rider pursuant to paragraph 10.3) may increase customer bills after December 31, 2012);

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·a four year rate case stay out, in which APS agrees not to raise base rates as a result of any new general rate case filing prior to July 1, 2016;

·a buy-through rate for industrial and large commercial customers;

·a narrowly-tailored Lost Fixed Cost Recovery (“LFCR”) mechanism that supports energy efficiency (“EE”) and distributed generation (“DG”) at any level or pace set by this Commission;

·an opt-out rate design for residential customers who choose not to participate in the LFCR;

·a process for simplifying customers’ bill format; and

·bill assistance for additional low income customers, at shareholder expense.

1.6The Signatories agree to ask the Commission (1) to find that the terms and conditions of this Agreement are just and reasonable and in the public interest, along with any and all other necessary findings, and (2) to approve the Agreement and order that it and the rates contained herein become effective on July 1, 2012.

TERMS AND CONDITIONS

II.RATE CASE STABILITY PROVISION

2.1APS agrees not to file its next general rate case prior to May 31, 2015.  The test year end date for the base rate increase filing contemplated in this section shall be no earlier than December 31, 2014 but need not coincide with the end of a calendar year.  No new base rates resulting from APS’s next general rate case will be effective before July 1, 2016.

III.RATE INCREASE

3.1APS shall receive a base rate increase of zero dollars (“revenue requirement”).  This amount is comprised of: (1) a non-fuel base rate increase of $116.3 million, which includes providing for a return on and of plant that is in service as of March 31, 2012 (“Post-Test Year Plant”); (2) a fuel base rate decrease of

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$153.1 million; and (3) a transfer of cost recovery from the Renewable Energy Surcharge (“RES”) to base rates described in Paragraph VIII herein.

3.2The Company’s jurisdictional fair value rate base used to establish the rates agreed to herein is $8,167,126,000. The Company’s total adjusted Test Year revenue is $2,868,858,000.

IV.BILL IMPACT

4.1When new rates become effective, customers will have on average a 0.0% bill impact or less.  This zero percent or slightly negative bill impact will be achieved by allowing the negative credit that exists in the Company’s Power Supply Adjustor (“PSA”) to continue until February 1, 2013, at which time it will reset.  The annual 4 mill cap will be applied after the impact of the expiration of the then-current PSA credit.

4.2Subsequent to the PSA reset for General Service customers in February 2013, the percentage bill impact spread resulting from this Settlement among the various segments of that customer class shall be equal.  This shall be accomplished as set forth in Attachment A.

4.3A zero percent bill impact will continue for the remainder of 2012 (Commission-approved adjustors (including the possibility of a Four Corners rider pursuant to paragraph 10.3) may increase customer bills after December 31, 2012).

V.COST OF CAPITAL

5.1A capital structure comprised of 46.06% debt and 53.94% common equity shall be adopted.

5.2A return on common equity of 10.0% and an embedded cost of debt of 6.38% shall be adopted.

5.3A fair value rate of return of 6.09%, which includes a return on the fair value rate base increment of 1.0%, shall be adopted.

5.4The provisions set forth herein regarding the quantification of cost of capital, 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.

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VI.DEPRECIATION/AMORTIZATION AND DECOMMISSIONING

6.1With the exception of Uniform System of Accounts 370.01 (electronic meters), 370.02 (electro-mechanical meters), and 370.03 (AMI meters), the depreciation and amortization rates proposed by APS and contained in Attachment REW-2 to Dr. Ron White’s Pre-filed Direct Testimony shall be adopted until further order of the Commission.  For Accounts 370.01, 370.02 and 370.03, the current depreciation rates will be retained, as proposed by Commission Staff Witness Ralph Smith.

6.2The annual nuclear decommissioning amounts reflected in the rates agreed to herein are those shown in APS Witness Jason LaBenz workpaper JCL_WP22, page 4, attached hereto as Attachment B.

6.3APS shall file a request that the Commission adjust the Company’s System Benefit Charge (“SBC”) and reduce such charge to reflect a corresponding reduction of the decommissioning trust funding obligations collected through the SBC related to the full funding of Palo Verde Unit 2.  Such filing shall be made in sufficient time for the reduction to occur by January 2016.

VII.FUEL AND POWER SUPPLY ADJUSTMENT PROVISIONS

7.1The base fuel rate shall be lowered from $0.037571 per kWh as set in Commission Decision No. 71448 to $0.032071 per kWh.  This change shall take effect on the effective date of the new rates contained in this Agreement, in accordance with the current approved Plan of Administration for the Power Supply Adjustor (“PSA”).

7.2For purposes of this case, APS will withdraw its request to recover through the PSA the cost of chemicals required for environmental compliance at APS’s power plants, and APS shall not raise this request before its next general rate case.

7.3The 90/10 sharing provision in APS’s PSA will be eliminated.  The PSA shall be modified to require APS to apply interest on the PSA balance annually, rather than monthly, at the following rates:  any over-collection existing at the end of the PSA year will accrue interest at a rate equal to the Company’s authorized ROE or APS’s then-existing short term borrowing rate, whichever is greater, and will be refunded to customers over the following 12 months; any under-collection existing at the end of the PSA year will accrue interest at a rate

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equal to the Company’s authorized ROE or APS’s then-existing short term borrowing rate, whichever is less, and will be recovered from customers over the following 12 months.  APS may, at any time during the PSA year, request to reduce the PSA rate through the Transition Component.  Any such request shall become effective beginning with the first billing cycle of the month following the filing date of the request.

7.4To incent prudent fuel and power procurement and use, APS shall be subject to periodic audits.  The first audit shall be for calendar year 2014.  Commission Staff shall select a consultant to perform this audit and subsequent audits.  Each audit shall be funded by APS in an amount not to exceed $100,000 per audit.

7.5The PSA Plan of Administration shall be amended as set forth in Attachment C.

VIII.RENEWABLE ENERGY

8.1APS currently collects the costs associated with certain APS-owned renewable energy projects through the RES.  Consistent with the treatment of other Post-Test Year Plant adopted in this Agreement, the portion of those renewable projects that have been closed to plant in service as of March 31, 2012, shall be rate based and recovery of those costs shall be accomplished through base rates.  The specific projects to be rate based pursuant to this Section are identified in Attachment D.

8.2Effective with the date of the Commission’s order in this matter, the capital carrying costs(1) for any APS renewable energy-related capital investments shall not be recovered through the RES adjustor, except that capital carrying costs for renewable energy-related capital investments that APS makes in compliance with Commission Decision No. 71448 shall be recovered in the RES adjustor unless and until specifically authorized for recovery in another adjustor or in base rates.

8.3On the effective date of the new rates contained in this Agreement, the RES adjustor rate established for 2012 in Docket No. E-01345A-11-0264 shall be reduced to reflect the removal of the projects identified in Attachment D.  At the same time, the renewable energy-related purchased power agreement costs that were moved from the RES to the PSA pursuant to the Commission’s

(1) Capital carrying costs include (1) a return at the Company’s Weighted Average Cost of Capital approved by the Commission in this rate case; (2) depreciation expense; (3) income taxes; (4) property taxes; (5) deferred taxes and tax credits where appropriate; and (6) associated O&M.

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Decision in Docket No. E-01345A-11-0264, shall be transferred back to the RES.

8.4To provide the Commission with greater flexibility in setting RES adjustor rates and related caps, the requirement established in Decision No. 67744 that any changes to RES charges and caps must be allocated between customer classes according to certain set proportions shall be eliminated.

IX.ENERGY EFFICIENCY/LOST FIXED COST RECOVERY/OPT-OUT RESIDENTIAL RATE/LARGE GENERAL SERVICE CUSTOMER EXCLUSION

9.1The Signatories support energy efficiency as a low cost energy resource.  The Signatories also recognize that, under APS’s current volumetric rate design, the Company recovers a significant portion of its fixed costs of service through kilowatt-hour (“kWh”) sales.  Commission rules related to EE and Distributed Generation (“DG”) require APS to sell fewer kWh, which, in turn, prevents the Company from being able to recover a portion of the fixed costs of service embedded in its energy rates.

9.2The Signatories also recognize the Commission’s interest in directing EE and DG policy.  In signing this Agreement, the Signatories intend that a Lost Fixed Cost Recovery (“LFCR”) mechanism with residential opt-out rates shall be adopted that allows APS relief from the financial impact of verified lost kWh sales attributable to Commission requirements regarding EE and DG while preserving maximum flexibility for the Commission to adjust EE and DG requirements, either upward or downward, as the Commission may deem appropriate as a matter of policy.  Nothing in this Agreement is intended to bind the Commission to any specific EE or DG policy or standard.

9.3To address the goals of Sections 9.1 and 9.2, the Signatories propose that the Commission adopt for APS an LFCR, similar to that recommended by Staff in this proceeding.  The LFCR shall recover a portion of distribution and transmission costs associated with residential, commercial and industrial customers when sales levels are reduced by EE and DG. It shall not recover lost fixed costs attributable to other potential factors, such as weather or general economic conditions.  The LFCR mechanism shall exclude the portion of distribution and transmission costs that is recovered through the Basic Service Charge (“BSC”) and fifty (50) percent of such costs recovered through non-generation/non-TCA demand charges.

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9.4The LFCR shall be adjusted annually to account for the unrecovered costs associated with a portion of distribution and transmission costs resulting from EE programs as demonstrated by the Measurement, Evaluation and Reporting (“MER”) conducted for EE programs and from DG as demonstrated pursuant to the means described in Section 9.5 below.  An annual 1% year over year cap based on Total Company revenues will be applied to the adjustment.  Any amount in excess of the 1% cap will be deferred (with interest at the nominal one-year Treasury Constant Maturities rate contained in the Federal Reserve Statistical Release H-15 or its successor publication) for collection until the first future adjustment period in which including such costs, would not cause the annual increase to exceed the 1% cap.  The amount of any cap level set herein shall be evaluated in APS’s next rate case.

9.5For the purpose of the LFCR mechanism, APS shall be allowed to use statistical verification, output profile, or meter data for DG systems until December 31, 2014.  Beginning January of 2015, APS shall only use meter data to calculate DG system savings

9.6APS will file with the Commission to adjust its LFCR by January 15 of each year, and Staff will use its best efforts to process the matter by March 1 of each year.  Each annual LFCR adjustment will not go into effect unless approved by the Commission. The annual adjustment will use actual data for the period through September and forecast data for the remainder of the year. The following year’s adjustment shall be trued-up for verified EE MER and metered or otherwise verified DG results.  The first adjustment will not occur before March 1, 2013.  The March 1, 2013 adjustment shall include reduced sales from EE and DG for 2012 and will be pro-rated from the date rates become effective pursuant to a Commission decision on this Agreement. Subsequent adjustments shall reflect the full impact of reduced sales in the prior year plus the cumulative impact from previous adjustments, subject to the cap described in Section 9.4 herein.

9.7The LFCR mechanism shall not apply to large General Service customers taking service under rate schedules E-32 L, E-32 L TOU, E-34, E-35 and E-36 XL, or to unmetered General Service customers under E-30 and lighting schedules. These rate schedules shall be modified in accordance with Attachment K to address unrecovered fixed costs through changes in rate design with enhanced distribution demand and BSC charges and a corresponding adjustment to energy charges.

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9.8Residential customers shall have a rate schedule choice to opt out of the LFCR by electing an optional BSC, graduated by kWh monthly usage.  That option is attached hereto as Attachment E.  The optional BSC will be incorporated into each residential rate schedule to provide customers with the maximum flexibility to opt out without requiring a shift to a different rate schedule. The purpose of this opt out rate is to replicate, on average, the effects of the LFCR.

9.9APS shall seek stakeholder input regarding the development of a customer outreach program to inform and educate customers about both the LFCR and voluntary opt-out rates and shall implement this outreach program.

9.10On January 15 of each year, APS shall file compliance reports with the Commission consistent with the schedules attached to the LFCR Plan of Administration. These reports shall include a comparison of the revenues recovered through the LFCR to those that would have been recovered had the Company’s revenue per customer decoupling (full decoupling) proposal been adopted.

9.11The LFCR shall be subject to Commission review at any time, the first to occur no later than APS’s next general rate case.  If the Commission decides to suspend, terminate, or materially modify the LFCR mechanism prior to the Company’s next general rate case, and does not provide alternative relief that adequately addresses fixed cost revenue erosion, the moratorium for filing general rate case applications shall terminate.

9.12The LFCR Plan of Administration is attached hereto as Attachment F.

9.13The LFCR was designed to be a flexible means to maximize the policy options available to the Commissioners and to customers, allowing the pursuit of EE and DG programs at any level or pace directed by the Commission.  The Signatories agree that if the Commission declines to adopt the LFCR or an alternative mechanism that adequately addresses fixed cost revenue erosion in this case, APS shall be granted relief from either the relevant EE and DG requirements or the financial impacts of EE and DG during that time.

9.14For future Demand-Side Management (“DSM”) Implementation Plan filings:

(a)Beginning with APS’s 2013 DSM Implementation Plan (filed in 2012), and excluding DSM-related capital investments already authorized by the

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Commission, carrying costs for DSM-related capital investments shall not be recovered through the DSM Adjustment Clause.

(b)APS’s performance incentive shall be modified (1) to eliminate the top two tiers of percentages to be applied to Net Benefits or Percent of Program Costs based on APS’s achievement relative to the EE Standard, and (2) to change the fourth tier to include any achievement greater than 105%.  The first three tiers remain unchanged.

Achievement Relative to the Energy Efficiency  Standard	Performance Incentive as % of Energy Efficiency Net Benefits		Performance Incentive Capped at % of Energy Efficiency  Program Costs		Proposed  Change from  Current
<85%	0	%	0	%	No Change
85% to 95%	6	%	12	%	No Change
96% to 105%	7	%	14	%	No Change
>105%	8	%	16	%	New
106% to 115%	8	%	16	%	Eliminated
116% to 125%	9	%	18	%	Eliminated
>125%	10	%	20	%	Eliminated

(c)APS shall use the inputs and methodology that Commission Staff uses when calculating the present value of benefits and costs for DSM measures in its Societal Cost test.  Commission Staff will regularly re-evaluate such inputs

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and methodologies, considering comments from APS and other stakeholders.

(d)APS will work with stakeholders and Staff to develop and file for Commission consideration a new performance incentive structure by December 31, 2012 that optimizes the connection between energy efficiency, rates and utility business incentives and that creates a clear connection between the level of performance incentive and achievement of cost-effective energy savings.  This rate case shall be held open to allow for Commission approval of including the new performance incentive structure in the DSM Adjustment Clause.  At that time, the Commission should determine the plan year to which the new performance incentive structure shall apply.  The Signatories shall recommend that any new performance incentive structure adopted should apply to the first plan year filed after its adoption.

(e)APS’s DSM programs and associated energy savings shall be independently reviewed every five years by an evaluator selected by Staff and paid for by APS in an amount not to exceed $100,000.  The first review shall occur in APS’s next general rate case or within five (5) years of a Commission order in this case, whichever is sooner.

9.15APS shall compile and make available to all parties of the docket a technical reference manual documenting program and measure saving assumptions and incremental costs no later than December 31, 2013.  This manual would be updated on an annual basis as part of the DSM implementation plan process and would serve as a reference tool for the LFCR analysis.

9.16APS currently collects $10 million of DSM costs in base rates, which level will be retained.

9.17The DSM Adjustment Clause Plan of Administration shall be modified to reflect the terms of this Agreement as set forth in Attachment G.

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X.RATE TREATMENT RELATED TO ANY ACQUISITION BY APS OF SOUTHERN CALIFORNIA EDISON’S SHARE OF FOUR CORNERS UNITS 4-5.

10.1In Docket No. E-01345A-10-0474, APS has sought Commission permission to pursue acquisition of Southern California Edison’s (“SCE”) current ownership interest in Four Corners Units 4 and 5 and to retire Four Corners Units 1-3 (the “proposed Four Corners transaction”).

10.2Except as provided in Section 9.14(d), this rate case shall remain open for the sole purpose of allowing APS to file a request, no later than December 31, 2013, that its rates be adjusted to reflect the proposed Four Corners transaction, should the Commission allow APS to pursue the acquisition and should the transaction thereafter close. Specifically, APS may within ten (10) business days after any Closing Date but no later than December 31, 2013, file an application with the Commission seeking to reflect in rates the rate base and expense effects associated with the acquisition of SCE’s share of Units 4 and 5, the rate base and expense effects associated with the retirement of Units 1-3, and any cost deferral authorized in Docket No. E-01345A-10-0474.  APS shall also be permitted to seek authorization to amend the PSA Plan of Administration to include in the PSA the post-acquisition Operations and Maintenance expense associated with Four Corners Units 1-3 as a cost of producing off-system sales until closure of Units 1-3, provided that such costs do not exceed off-system sales revenue in any given year.  APS’s rates shall be adjusted only if the Commission finds the Four Corners transaction to be prudent.

10.3Any filing seeking a rate adjustment pursuant to Section 10.2 shall include at a minimum 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 adjustment rider that recovers the rate base and non-PSA related expenses associated with any Four Corners acquisition on an equal percentage basis across all rate schedules which shall not become effective before July 1, 2013; (6) an adjusted rate base schedule; and (7) a typical bill analysis under present and filed rates.

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10.4The Signatories shall not raise any issues in the rate adjustment proceeding other than those specifically described in Section 10.2.  The Signatories shall use good faith efforts to process this rate adjustment request within a reasonable time.

10.5If, at any time, APS determines that the Four Corners Transaction will not close, it shall so inform the Commission and the Signatories by filing a Notice to that effect in this Docket.

XI.MODIFICATION TO ENVIRONMENTAL IMPROVEMENT SURCHARGE

11.1For purposes of this proceeding, APS shall withdraw its request for approval of the proposed Environmental and Reliability Account (“ERA”) mechanism, and APS shall not raise this request before its next general rate case.

11.2APS shall implement a revised version of the existing Environmental Improvement Surcharge (“EIS”).  As amended, APS shall no longer receive customer dollars through the EIS to pay for government-mandated environmental controls.  However, when APS invests capital to fund any government-mandated environmental controls, the EIS will recover the associated capital carrying costs, subject to a cap equal to the charge currently in place for the EIS.  Adjustments to the EIS shall become effective each April 1st unless Staff requests Commission review or unless otherwise ordered by the Commission.  APS will not request a change in the rate cap prior to its next general rate case.

11.3APS will be held responsible for demonstrating that the environmental controls were government-mandated and represented a reasonable and prudent option available to the Company at that time sufficient to meet the environmental requirements.

11.4The EIS Plan of Administration shall be revised as set forth in Attachment H.

11.5The existing EIS will be reset to zero on the effective date of the new rates contained in this Agreement.

XII.COST DEFERRAL RELATED TO CHANGES IN ARIZONA PROPERTY TAX RATE

12.1APS shall be allowed to defer for future recovery, in accordance with the provisions of Accounting Standards Codification (“ASC”) 980 (formerly SFAS

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No. 71), the following portions of Arizona property tax expense above or below the test year level of $141.5 million caused by changes to the applicable Arizona composite property tax rate (not changes in the assessed value of property).

(a)When the property tax rate increases:

·For 2012: 25% (prorated with an assumed July 1 rate effective date);

·For 2013: 50%; and

·For 2014 and all subsequent years: 75%.

(b)When the property tax rate decreases: 100% in all years.

No interest shall be applied to the deferred balance.

12.2Beginning 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 and any deferral that has a negative balance will be refunded to customers over 3 years.

12.3The Signatories reserve the right to review APS’s property tax deferrals for reasonableness and prudence such that the deferrals can be recognized in accordance with the provisions of ASC-980 (formerly SFAS No. 71).

XIII.TRANSMISSION COST ADJUSTMENT MECHANISM

13.1The level of transmission costs presently in APS’s base rates will remain in base rates until further order of the Commission.

13.2The annual TCA adjustment will become effective June 1 of each year without the need for affirmative Commission approval, unless Staff requests Commission review or unless otherwise ordered by the Commission.

13.3APS shall file a notice with Docket Control that includes its revised TCA tariff, along with a copy of its FERC information filing of its annual update of transmission service rates pursuant to its Open Access Transmission tariff (“OATT”).  This notice shall be filed with the Commission by May 15 of each year.

13.4The TCA Plan of Administration shall be modified as set forth in Attachment I.

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XIV.LOW INCOME PROGRAMS

14.1In Section 16.3 of the 2009 Settlement, APS committed to augment the bill assistance program approved in Decision No. 69663 by funding $5 million to assist customers whose incomes exceed 150% of the Federal Poverty Income Guidelines but are less than or equal to 200% of the Federal Poverty Income Guidelines.  This Agreement provides that any funds remaining of that $5 million funding requirement may be used to so assist customers whose incomes are less than or equal to 200% of the Federal Poverty Income Guidelines.

14.2PSA and DSMAC adjustor rates shall apply to low-income customers.  The billing method for low income customers shall be simplified by transferring customers to their corresponding non-low income rate schedule and applying the PSA and DSMAC rate schedules to those bills, but then applying a discount to the total bill such that low income customers, like other APS customers, will have no bill impact in this case as a result of the billing method change.

XV.SERVICE SCHEDULE 3 (LINE EXTENSIONS)

15.1Version 12 of Service Schedule 3, as approved in Decision No. 72684 (November 18, 2011), shall become effective on the date that rates from this case become effective.

XVI.BILL PRESENTATION

16.1Within 90 days following approval of this Agreement, APS will initiate stakeholder meetings to address issues related to the APS bill presentation with a goal of making the bill easier for customers to understand.  APS shall thereafter file an application with the Commission for any authorization needed to modify its bill presentation. Such application shall explain how the APS bill presentation proposal reflects the input of stakeholders during the stakeholder meeting process.

XVII.RATE DESIGN

17.1The Company’s proposed Experimental Rate Schedule AG-1, a buy through rate for large commercial and industrial customers, should be capped at 200 MW and should be approved as modified herein, as should corresponding changes to the PSA.  Proposed Experimental Rate Schedule AG-1 is set forth in Attachment J.  Proposed Experimental Rate Schedule AG-1 does not address the subject of retail electric competition.

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17.2APS shall make commercially reasonable efforts to eliminate or mitigate all unrecovered costs resulting from the AG-1 experimental program established in this docket.  If there are any lost fixed generation costs related to the AG-1 experimental rate, in its next general rate case, APS shall provide testimony that explains why it was unable to eliminate all lost fixed generation costs.  Because AG-1 is an experimental program that may benefit certain General Service customers, and because residential customers cannot participate in the program, any APS proposal in APS’s next general rate case that seeks to collect lost fixed generation costs related to the AG-1 experimental rate shall not propose to recover such costs from residential customers.

17.3As recommended by Staff Witness McGarry, APS shall file a study in its next General Rate Case Application to support the cost basis of the various charges in Service Schedule 1,  taking into account the impact Smart Grid technology may have on these costs.

17.4APS shall withdraw its request to establish Service Schedule 9, an economic development service schedule.  In its place, APS is authorized to pursue economic development opportunities through the use of Commission-approved special contracts.

17.5The remaining rate design issues presented by this case shall be resolved as set forth in Attachment K.

XVIII.COMPLIANCE MATTERS

18.1Within ten days after the Commission issues a written 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.

18.2APS shall report to the Commission identifying the extent of the challenges regarding workforce planning, the specific actions that APS is taking to address the issue, and the progress APS is making toward meeting those goals.  The workforce planning report, which shall be filed on an annual basis in this docket on or before May 31, 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:  (1) the number of employees then currently holding these positions; (2) the present mean and median ages of APS’s workforce with respect to those job

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classifications; (3) the share of retirement-eligible employees, both as a percentage and in absolute terms, in each of these job classifications; and (4) anticipated hiring and attrition levels for each of these job classifications.

18.3Decision No. 70667, as a compliance item, requires APS to periodically file with the Commission certain communications with rating agencies.  It is appropriate to eliminate this filing requirement at this time.

XIX.FORCE MAJEURE PROVISION

19.1Nothing 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 APS from seeking rate relief or any Signatory from petitioning the Commission to examine the reasonableness of APS’s rates pursuant to this Section in the event of significant developments that materially impact the financial results expected under the terms of this Agreement.  This provision is not intended to preclude any party, including any Signatory 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.

XX.COMMISSION EVALUATION OF PROPOSED SETTLEMENT

20.1All currently filed testimony and exhibits shall be offered into the Commission’s record as evidence.

20.2The Signatories 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.

20.3This Agreement shall serve as a procedural device by which the Signatories will submit their proposed settlement of APS’s pending rate case, Docket No. E-01345A-11-0224, to the Commission.

20.4The Signatories 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

20

Commission approval of the Agreement.  Thereafter, the Signatories shall abide by the terms as approved by the Commission.

20.5If the Commission fails to issue an order adopting all material terms of this Agreement, any or all of the Signatories may withdraw from this Agreement, and such Signatory or Signatories may pursue without prejudice their respective remedies at law.  For purposes of this Agreement, whether a term is material shall be left to the discretion of the Signatory choosing to withdraw from the Agreement.  If a Signatory withdraws from the Agreement pursuant to this paragraph and files an application for rehearing, the other Signatories, except for Staff, shall support the application for rehearing by filing a document with the Commission that supports approval of the Agreement in its entirety. Staff shall not be obligated to file any document or take any position regarding the withdrawing Signatory’s application for rehearing.

XXI.MISCELLANEOUS PROVISIONS

21.1This 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 their long-term interests and with the broad public interest. The acceptance by any Signatory of a specific element of this Agreement shall not be considered as precedent for acceptance of that element in any other context.

21.2No Signatory is bound by any position asserted in negotiations, except as expressly stated in this Agreement. No Signatory 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.

21.3Neither this Agreement nor any of the positions taken in this Agreement by any of the Signatories 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.

21.4To the extent any provision of this Agreement is inconsistent with any existing Commission order, rule, or regulation, this Agreement shall control.

21.5Each of the terms of this Agreement is in consideration of all other terms of this Agreement. Accordingly, the terms are not severable.

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21.6The Signatories shall make reasonable and good faith efforts necessary to obtain a Commission order approving this Agreement. The Signatories shall support and defend this Agreement before the Commission. Subject to paragraph 20.5, if the Commission adopts an order approving all material terms of the Agreement, the Signatories will support and defend the Commission’s order before any court or regulatory agency in which it may be at issue.

21.7This Agreement may be executed in any number of counterparts and by each Signatory 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.

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Docket No. E-0134SA-ll-0224 ARIZONA CORPORATION COMMISSION By ARIZONA PUBLIC SERVICE COMPANY RESIDENTIAL UTILITY CONSUMER OFFICE By By

Docket No. E-01345A-II-0224 DATED: January 5, 2012 By Cynthra Zwick

Docket No. E-01345A-ll-0224 By Karen S. White Karen S. White Federal Executive Agencies DATED: January 6, 2012

Docket No. E-01345A-11-0224 Kurt J. Boehm, Esq. Attorney for Kroger Co. DATED: 1-6-12, 2012

Docket No. E-01345A-11-0224 By C. Webb Crockett C. Webb Crockett Patrick J. Black Fennemore Craig, P. C. Attorneys for Freeport-McMoRan Copper & Gold Inc. DATED: January 6, 2012

Docket No. E-01345A-11-0224 By C. Webb Crockett Patrick J. Black Fennemore Craig, P.C. Attorneys for Arizonans for Electric Choice and Competition DATED: January 6, 2012

WAL-MART STORES, INC. and SAM'S WEST, INC. By: Scott S. Wakefield Ridenour, Hienton & Lewis, PLLC 201 N. Central Ave., Suite 3300 Phoenix, AZ 85004 Attorneys for Wal-Mart Stores, Inc. and Sam's West, Inc. Dated: January 6, 2012

.By: Nicholas J. Enoch, Esq. Docket No. E-0134SA-ll-0224 Attorney for Intervenors IBEW Locals 387, 640 & 769 DATED: January .6, 2012.

Docket No. E-01345A-11-0224 AZAG GROUP By: Jay I. Moyes Moyes Sellers & Hendricks 1850 N. Central Ave., Suite 1100 Phoenix, AZ 85004 jimoyes@1aw-msh.com 602-604-2106 602-274-9135 - fax DATED: January 6, 2012

Docket No. E-01345A-11-0224 By Greg Patterson Arizona Competitive Power Alliance Director: DATED: January 6, 2012

Docket No. E-01345A-11-0224 DATED: 1/6, 2012 By Craig A. Martes Craig A. Martes AARP

Docket No. E-01345A-11-0224 ARIZONA ASSOCIATION OF REALTORS, INC. By: Tom Farley, Chief Executive Officer DATED: January 6, 2012

Docket No. E-01345A-l1-0224 By Barbara wyllie Pecora Barbara wyllie - Pecora DATED: 1-6-12, 2012

Docket No. E-01345A-11-0224 By Gary Yaquinto Gary Yaquinto, its President Arizona Investment Council DATED: January 5, 2012

Docket No. E-01345A-11-0224 Lawrence V. Robertson, Jr. On behalf of Southwestern Power Group II, L.L.C. DATED: January 6, 2012

Docket No. E-01345A-11-0224 Lawrence V. Robertson, Jr. On behalf of Bowie Power Station, L.L.C. DATED: January 6, 2012 By

Docket No. E-01345A-ll-0224 Lawrence V. Robertson, Jr. On behalf of Noble Americas Energy Solutions LLC DATED: January 6, 2012 By

Docket No. E-01345A-l1-0224 By Lawrence V. Robertson, Jr. On behalf of Constellation NewEnergy, Inc. DATED: January 6, 2012

Docket No. E-01345A-11-0224 By Lawrence V. Robertson, Lawrence V. Robertson, Jr. On behalf of Direct Energy, LLC DATED: January 6, 2012

Docket No. E-01345A-11-0224 Lawrence V. Robertson, Jr. On behalf of Shell Energy North America (US), L.P. DATED: January 6, 2012 By

153,087,000 27,689,606,547 0.00553 Adjusted kWh 1. 2. E-20 36,664,060 E-32 XS 1,418,941,092 E-32 S 2,551,982,755 E-32 M 3,279,541,910 E-32 L 3,647,138,613 E-32 TOU XS 4,608,869 E-32 TOU S 41,567,188 E-32 TOU M 69,936,556 E-32 TOU L 295,613,941 E-34 1,086,047,211 E-35 1,673,368,627 14,105,410,822 Arizona Public Service Company Equalize Impact of Transferring Fuel from Base Rates to PSA Across General Service Rate Classes Fuel transfer to PSA Test Year Retail kWh PSA impact /kWh Adjusted Equal % Equal % Present PSA PSA PSA PSA PSA Revenue Impact Impact Impact Impact Delta ($) ($) (%) (%) ($) ($) 3. 4. 5. 6. 7. 8. $ 3,885,908 $ 202,752 5.218% 5.82% $ 226,004 $ 23,252 199,176,817 7,846,744 3.940% 5.82% 11,584,124 3,737,380 290,020,650 14,112,465 4.866% 5.82% 16,867,601 2,755,136 317,315,278 18,135,867 5.715% 5.82% 18,454,236 318,369 303,798,301 20,168,677 6.639% 5.82% 17,668,909 (2,499,768) 632,665 25,487 4.029% 5.82% 36,796 11,309 4,454,447 229,867 5.160% 5.82% 259,071 29,204 6,385,132 386,749 6.057% 5.82% 371,359 (15,390) 22,916,517 1,634,745 7.133% 5.82% 1,332,825 (301,920) 80,597,093 6,005,841 7.452% 5.82% 4,687,527 (1,318,314) 112,009,467 9,253,729 8.262% 5.82% 6,514,471 (2,739,258) $ 1,341,192,275 $ 78,002,923 5.816% 5.82% $ 78,002,923 $ - Attachment A Base Equalization Rate Charge Increase $/kWh (%) 9. 10. 0.00063 0.60% 0.00263 1.88% 0.00108 0.95% 0.00010 0.10% (0.00069) -0.82% 0.00245 1.79% 0.00067 0.66% (0.00022) -0.24% (0.00103) -1.32% (0.00121) -1.64% (0.00163) -2.45% Page 1 of 1

Attachment B ARIZONA PUBLIC SERVICE COMPANY Palo Verde Decommissioning/ISFSI Trust Amounts Test Year 12 Months Ended 12/31/10 (Dollars in Thousands) ACC 6/1/2045 4/24/2046 11/25/2047 Jurisdictional YEAR UNITl UNIT2 UNIT3 TOTAL Amount(1) 2011 $ 4,558 $ 6,047 $ 5,414 $ 16,019 $ 15,630 2012 449 14,968 1,832 17,249 16,830 2013 449 14,968 1,832 17,249 16,830 2014 449 14,968 1,832 17,249 16,830 2015 449 14,968 1,832 17,249 16,830 2016 449 1,832 2,281 2,226 2017 449 1,832 2,281 2,226 2018 449 1,832 2,281 2,226 2019 449 1,832 2,281 2,226 2020 449 1,832 2,281 2,226 2021 449 1,832 2,281 2,226 2022 449 1,832 2,281 2,226 2023 449 1,832 2,281 2,226 2024 449 1,832 2,281 2,226 2025 449 1,832 2,281 2,226 2026 449 1,832 2,281 2,226 2027 449 1,832 2,281 2,226 2028 449 1,832 2,281 2,226 2029 449 1,832 2,281 2,226 2030 449 1,832 2,281 2,226 2031 449 1,832 2,281 2,226 2032 449 1,832 2,281 2,226 2033 449 1,832 2,281 2,226 2034 449 1,832 2,281 2,226 2035 449 1,832 2,281 2,226 2036 449 1,832 2,281 2,226 2037 449 1,832 2,281 2,226 2038 449 1,832 2,281 2,226 2039 449 1,832 2,281 2,226 2040 449 1,832 2,281 2,226 2041 449 1,832 2,281 2,226 2042 449 1,832 2,281 2,226 2043 449 1,832 2,281 2,226 2044 449 1,832 2,281 2,226 2045 225 1,832 2,056 2,006 2046 1,832 1,832 1,787 2047 1,832 1,832 1,787 $ 19,604 $ 65,919 $ 71,360 $ 156,883 $ 153,071 (1) ACC Jurisdictional share is approximately 97.57% Page 1 of 1 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

Arizona Corporation Commission Docket No. E-01345A-ll-0224 Table of Contents Power Supply Adjustment Plan of Administration Proposed Plan of Administration Power Supply Adjustor Mechanism 1. General Description 1 2. PSA Components 2 3. Calculation of the PSA Rate 4 4. Filing and Procedural Deadlines 5 5. Verification and Audit 6 6. Definitions 6 7. Schedules 8 8. Compliance Reports 9 9. Allowable Costs 10 1. General Description This document describes the plan for administering the Power Supply Adjustment mechanism ("PSA") approved for Arizona Public Service Company ("APS") by the Commission on June 28, 2007 in Decision No. 69663, amended by the Commission on December 30, 2009 in Decision No. 71448, and as further amended by the Commission on [insert date] in Decision No. xxxxx. The PSA provides for the recovery of fuel and purchased power costs, to the extent that actual fuel and purchased power costs deviate from the amount recovered through APS' Base Cost of Fuel and Purchased Power ($0.032071 per kWh) authorized in Decision No. XXXXX, from [insert date]. It also provides for refund or recovery of the net margins from sales of emission allowances, to the extent the actual sales margins deviate from the base rate amount of ($0.000001) per kWhl . The PSA described in this Plan of Administration ("POA") uses a forward-looking estimate of fuel and purchased power costs and margins on the sales of emission allowances ("PSA Costs") to set a rate that is then reconciled to actual costs experienced. This PSA includes a limit of $0.004 per kilowatt-hour (kWh) on the amount the PSA rate may change in any one year absent express approval of the Commission. This PSA also provides a mechanism for mid-year rate adjustment in the event that conditions change sufficiently to cause extraordinarily high balances to accrue under application of this PSA. 1 ($0.000001) per kWh is the result of the following: (2010 net gains from sales of S02 allowances of $21,178)/(2010 test year native load sales of 28,075,248 MWh)/1000. Effective Date XX/XX/XXXX Page 1 Attachment C Page 1 of 20

Arizona Corporation Commission Docket No. E-01345A-11-0224 2. PSA Components Proposed Plan of Administration Power Supply Adjustor Mechanism The PSA Rate will consist of three components designed to provide for the recovery of actual, prudently incurred PSA Costs. Those components are: 1. The Forward Component, which recovers or refunds differences between expected PSA Year (each February 1 through January 31 period shall constitute a PSA Year) PSA Costs and those embedded in base rates. 2. The Historical Component, which tracks the differences between the PSA Year's actual fuel and purchased power costs and those recovered through the combination of base rates and the Forward Component, and which provides for their recovery during the next PSA Year. 3. The Transition Component, which provides for: a. The opportunity to seek mid-year changes in the PSA rate in cases where variances between the anticipated recovery of fuel and purchased power costs for the PSA Year under the combination of base rates and the Forward Component become so large as to warrant recovery/refund, should the Commission deem such an adjustment to be appropriate. b. The tracking of balances resulting from the application of the Transition Components, in order to provide a basis for the refund or recovery of any such balances. Except for circumstances when the Commission approves new base rates, a PSA Year begins on February 1 and ends on the ensuing January 31. In the event that new base rates become effective on a date other than February 1, the Commission may, at its discretion, adjust any or all of the PSA components to reflect the new base rates. On or before September 30 of each year, APS will submit a PSA Rate filing, which shall include a calculation of the three components of the proposed PSA Rate. This filing shall be accompanied by such supporting information as Staff determines to be required. APS will supplement this filing with Historical Component and Transition Component filings on or before December 31 in order to replace estimated balances with actual balances, as explained below. a. Forward Component Description The Forward Component is intended to refund or recover the difference between: (1) PSA Costs embedded in base rates and (2) the forecast PSA Costs over a PSA Year that begins on February 1 and ends on the ensuing January 31. APS will submit, on or before September 30 of each year, a forecast for the upcoming calendar year (January I-December 31) of its PSA Costs. It will also submit a forecast of kWh sales for the same calendar year, and divide the forecast costs by the forecast sales to produce the cents/kWh unit rate required to collect those costs over those sales. The result of subtracting the Base PSA Costs from this unit rate shall be the Forward Component. APS shall maintain and report monthly the balances in a Forward Component Tracking Account, which will record APS' over/under-recovery of its actual PSA Costs as compared to the Base PSA Costs recovered in revenue. The balance calculated as a result of these steps is then reduced Effective Date XX/XX/XXXX Page 2 Attachment C Page 2 of 20

Arizona Corporation Commission Docket No. E-01345A-ll-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism by the current month's collection of Forward Component revenue. This account will operate on a PSA Year basis (i.e.; February to January), and its balances will be used to administer this PSA's Historical Component, which is described immediately below. b. Historical Component Description The Historical Component in any current PSA Year is intended to refund or recover the balances accumulated in the Forward Component Tracking Account (described above) and Historical Component Tracking Account (described below) during the immediately preceding PSA Year. The sum of the projected Forward Component Tracking Account balance on January 31 of the following calendar year and the projected Historical Component Tracking Account balance on January 31 of the following calendar year is divided by the forecast kWh sales used to set the Forward Component for the coming PSA Year. That result comprises the proposed Historical Component for the coming PSA year. APS shall maintain and report monthly the balances in a Historical Component Tracking Account, which will reflect monthly collections under the Historical Component and the amounts approved for use in calculating the Historical Component. Each annual September 30 APS filing will include an accumulation of Forward Component Tracking Account balances and Historical Component Tracking Account balances for the preceding February through August and an estimate of the balances for September through January (the remaining five months of the current PSA Year). The APS filing shall use these balances to calculate a preliminary Historical Component for the coming PSA Year2. On or before December 31, APS will submit a supplemental filing that recalculates the preliminary Historical Component. This recalculation shall replace estimated monthly balances with those actual monthly balances that have become available since the September 30 filing. The September 30 filing's use of estimated balances for September through January (with supporting workpapers) is required to allow the PSA review process to begin in a way that will support its completion and a Commission decision, if necessary, prior to February 1. The December 31 updating will allow for the use of the most current balance information available prior to the time when a Commission decision, if necessary, is expected. In addition to the December 31 update filing, APS monthly filings (for the months of September through December) of Forward Component Tracking Account balance information and Historical Component Tracking Account balance information will include a recalculation (replacing estimated balances with actual balances as they become known) of the projected Historical Component unit rate required for the next PSA Year.3 The Historical Component Tracking Account will measure the changes each month in the Historical Component balance used to establish the current Historical Component as a result of collections under the Historical Component in effect. It will subtract each month's Historical 2 For example, the September 30, 2008 filing would include actual balances for February through August of 2008 and estimated balances for September 2008 through January 2009. 3 This updating to replace estimated with actual information will allow for the Commission to use the latest available balance information in determining what Historical Component is appropriate to establish for the coming PSA Year. Effective Date XX/XX/XXXX Page 3 Attachment C Page 3 of 20

Arizona Corporation Commission Docket No. E-01345A-ll-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism Component collections from the Historical Component balance. The Historical Component Account will also include Applicable Interest on any balances. APS shall file the amounts and supporting calculations and workpapers for this account each month. c. Transition Component Description The Transition Component will be used as the method for incorporating any future, approved mid-year changes to the PSA rate. APS or Staff may request at any timea change in the PSA rate through an adjustment to the Transition Component to address a significant imbalance between anticipated collections and costs for the PSA Year under the Forward Component element of this PSA. After the review of such request, the Commission may provide for the refund or collection of such balance (through a change to the Transition Component Balance) over such period as the Commission determines appropriate through a unit rate ($/kWh) imposed as part of the Transition Component. The Commission on its own motion may also change the PSA rate as described above. Notwithstanding the preceding paragraph, APS may at any time during the PSA Year request to reduce the PSA through the Transition Component, which request shall become effective beginning with the first billing cycle of the month following the filing of such a request, provided APS files the request within the first 15 days of a month and Staff does not file opposition to the request. A Transition Component Tracking Account will measure the changes each month in the Transition Component balance. APS, Staff, or the Commission on its own motion may request that the balance in any Transition Component Tracking Account at the end of the period set for recovery be included in the establishment of the Transition Component for the coming PSA Year. The Transition Component Account will also include Applicable Interest as determined by the Commission. APS shall file the amounts and supporting calculations and workpapers for this account each month. As it must do for the Historical Component filing, APS shall file on or before September 30 of each year an accumulation of Transition Component Tracking Account balances for the preceding February through August and an estimate of the balances for September through January (the remaining five months of the prior PSA Year). Those balances will form the basis for setting the preliminary Transition Component for the coming PSA Year. On or before December 31, APS will submit a supplemental filing to update the Transition Component calculation in the same manner as required for the Historical Component. 3. Calculation of the PSA Rate The PSA rate is the sum of the three components; i.e., Forward Component, Historical Component, and Transition Component. The PSA rate shall be applied to customer bills. Unless the Commission has otherwise acted on a new PSA rate by February 1, the proposed PSA rate (as amended by the updated December 31 filing) shall go into effect. However, the PSA rate may Effective Date XX/XX/XXXX Page 4 Attachment C Page 4 of 20

Arizona Corporation Commission Docket No. E-01345A-ll-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism not change from the prior year's PSA rate by more than plus or minus $0.004 per kWh without an offsetting change in the Base Cost of Fuel and Purchased Power. The PSA rate shall be applicable to APS' retail electric rate schedules (with the exception of E-36 XL, AG-l, Direct Access service and any other rate that is exempt from the PSA) and is adjusted annually. The PSA Rate shall be applied to the customer's bill as a monthly kWh charge that is the same for all customer classes. The PSA rate shall be reset on February 1 of each year, and shall be effective with the first February billing cycle unless suspended by the Commission. It is not prorated. 4. Filing and Procedural Deadlines a. September 30 Filing APS shall file the PSA rate with all Component calculations for the PSA year beginning on the next February 1, including all supporting data, with the Commission on or before September 30 of each year. That calculation shall use a forecast of kWh sales and ofPSA Costs for the coming calendar year, with all inputs and assumptions being the most current available for the Forward Component. The filing will also include the Historical Component calculation for the year beginning on the next February 1, with all supporting data. That calculation shall use the same forecast of sales used for the Forward Component calculation. The Transition Component filing shall also include a proposed method for addressing the over or under recovery of any Transition Component balances that result from changes in the sales forecasts or recovery periods set or any additions to or subtractions from Transition Component balances reviewed or approved by the Commission since the last February 1 resetting ofthe new PSA.4 b. December 31 Filing APS shall by December 31 update the September 30 filing. This update shall replace estimated Forward Component Tracking Account balances, the Historical Component Tracking Account balances, and the Transition Component Tracking Account balances with actual balances and with more current estimates for those months (December and January) for which actual data are not available. Unless the Commission has otherwise acted on the APS calculation by February 1, the PSA rate proposed by APS shall go into effect with the first February billing cycle.5 c. Additional Filings APS shall also file with the Commission any additional information that the Staff determines it requires to verify the component calculations, account balances, and any other matter pertinent to the PSA. 4 This method assumes that the Commission defers the recovery of any approved Transition Component Balance changes until the next February 1 PSA resetting. The Commission may also, as part of the approval of any such Transition Component Balance change, make a PSA change effective on dates and across periods as it determines to be appropriate when it approves such a Transition Component Balance change. 5 No reference in this plan to effectiveness in the absence of Commission action shall be interpreted as precluding the normal application ofthe balance reconciliation provisions generally established for the PSA. Effective Date XX/XX/XXXX Page 5 Attachment C Page 5 of 20

Arizona Corporation Commission Docket No. E-01345A-ll-0224 d. Review Process Proposed Plan of Administration Power Supply Adjustor Mechanism The Commission Staff and interested parties shall have an opportunity to review the September 30 and December 31 forecast, balances, and supporting data on which the calculations of the three PSA components have been based. Any objections to the September 30 calculations shall be filed within 45 days of the APS filing. Any objections to the December 31 calculations shall be filed within 15 days of the APS filing. 5. Verification and Audit The amounts charged through the PSA shall be subject to periodic audit to assure their completeness and accuracy and to assure that all fuel and purchased power costs were incurred reasonably and prudently. The Commission may, after notice and opportunity for hearing, make such adjustments to existing balances or to already recovered amounts as it finds necessary to correct any accounting or calculation errors or to address any costs found to be unreasonable or imprudent. Such adjustments, with appropriate interest, shall be recovered or refunded through the Transition Component. 6. Definitions Applicable Interest - Interest is applied on the PSA balance annually at the following rates: any over-collection existing at the end of the PSA year will be credited an amount equal to interest at a rate equal to the Company's authorized Return on Equity ("ROE") or APS's then-existing short term borrowing rate, whichever is greater, and will be refunded to customers over the following 12 months; any under-collection existing at the end of the PSA Year will be debited an amount equal to interest at a rate equal to the Company's authorized ROE or APS'S then-existing short term borrowing rate, whichever is less, and will be recovered from customers over the following 12 months. Base Cost of Fuel and Purchased Power - An amount generally expressed as a rate per kWh, which reflects the fuel and purchased power cost embedded in the base rates as approved by the Commission in APS's most recent rate case. The Base Cost of Fuel and Purchased Power recovered in base revenue is the approved rate per kWh times the applicable sales volumes. Decision No. xxxxx set the base cost at $0.0.032071 per kWh effective on [insert date]. Base Net Margins on the Sale of Emission Allowances - An amount generally expressed as a rate per kWh, which reflects the net margins on sales of S02 emission allowances embedded in the base rates as approved by the Commission in APS' s most recent rate case. The Base Net Margins on the Sale of Emission Allowances is set at ($0.000001) per kWh effective on [insert date]. Base PSA Costs - A rate equal to the sum of Base Cost of Fuel and Purchased Power and the Base Net Margins on the Sale of Emission Allowances. Forward Component - An amount generally expressed as a rate per kWh charge that is updated annually on February 1 of each year and effective with the first billing cycle in February. The Forward Component for the PSA Year will adjust for the difference between the forecast PSA Effective Date XX/XX/XXXX Page 6 Attachment C Page 6 of 20

Arizona Corporation Commission Docket No. E-01345A-ll-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism Costs generally expressed as a rate per kWh less the Base PSA Costs generally expressed as a rate per kWh embedded in APS's base rates. The result of this calculation will equal the Forward Component, generally expressed as a rate per kWh. Forward Component Tracking Account - An account that records on a monthly basis APS's over/under-recovery of its actual PSA Costs as compared to the actual Base PSA Costs recovered in revenue and Forward Component revenue, plus Applicable Interest. The balance of this account as of the end of each PSA Year is, subject to periodic audit, reflected in the next Historical Component calculation. APS files the balances and supporting details underlying this Account with the Commission on a monthly basis. Historical Component - An amount generally expressed as a rate per kWh charge that is updated annually on February 1 of each year and effective with the first billing cycle in February unless suspended by the Commission. The purpose of this charge is to provide for a true-up mechanism to reconcile any over or under-recovered amounts from the preceding PSA Year tracking account balances to be refunded/collected from customers in the coming year's PSA rate. Historical Component Tracking Account - An account that records on a monthly basis the account balance to be collected via the Historical Component rate as compared to the actual Historical Component revenues; plus Applicable Interest; The balance of which at the close of the preceding PSA Year is, subject to periodic audit, then reflected in the next Historical Component calculation. APS files the balances and supporting details underlying this Account with the Commission on a monthly basis. ISFSI - Costs associated with the Independent Spent Fuel Storage Installation that stores spent nuclear fuel. Mark-to-Market Accounting - Recording the value of qualifying commodity contracts to reflect their current market value relative to their actual cost. Native Load - Native load includes customer load in the APS control area for which APS has a generation service obligation and PacifiCorp Supplemental Sales. Net Margins on the Sale of Emission Allowances - Revenues incurred from the sale of emission allowances net of the costs incurred to produce the excess allowances. PacifiCorp Supplemental Sales - The PacifiCorp Supplemental Sales agreement is a long-term contract from 1990 which requires APS to offer a certain amount of energy to PacifiCorp each year. It is a component of the set of agreements that led to the sale of Cholla Unit 4 to PacifiCorp and the establishment of the seasonal diversity exchange with PacifiCorp. Preference Power - Power allocated to APS wholesale customers by federal power agencies such as the Western Area Power Administration. PSA - The Power Supply Adjustment mechanism approved by the Commission in Decision No. 69663, amended by the Commission in Decision No. 71448, and further amended by the Effective Date XX/XX/XXXX Page 7 Attachment C Page 7 of 20

Arizona Corporation Commission Docket No. E-01345A-ll-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism Commission in Decision No. xxxxx, which is a combination of three rate components that track changes in the cost of obtaining power supplies based upon forward-looking estimates of PSA Costs that are eventually reconciled to actual costs experienced. This PSA allows for special Commission consideration of extreme volatility in costs or recovery by means of a mid-year rate correction, and provides for a reconciliation between actual and estimated costs of the last two months of estimated costs used in Historical Component calculations. PSA Costs - The combination of System Book Fuel and Purchased Power Costs net of the System Book Off-System Sales Revenues as adjusted herein for Rate Schedule AG-l plus the Net Margins on the Sales of Emission Allowances. PSA Year - A consecutive 12-month period generally beginning each February 1. Rate Schedule AG-l - Experimental Alternative Generation Rate Schedule approved by the Commission in Decision No. XXXXX. Resale of capacity and energy displaced by Rate Schedule AG-l shall be excluded from the PSA on a pro-rata basis, by dividing the amount of monthly metered sales to AG-l customers by the net monthly total of off-system sales and multiplying that result by total off-system sales margins. The portion of capacity and energy sales margins that is not the result of displacement from Rate Schedule AG-l will continue to be a credit to the PSA. System Book Fuel and Purchased Power Costs - The costs recorded for the fuel and purchased power used by APS to serve both Native Load and off-system sales, less the costs associated with applicable special contracts, E-36 XL, AG-l, RCDAC-l, ISFSI, and Mark-to-Market Accounting adjustments. Wheeling costs are included; broker fees are included up to the level in the Base Cost of Fuel and Purchased Power authorized in Decision No.xxxxx. System Book Off-System Sales Revenue - The revenue recorded from sales made to non-Native Load customers, for the purpose of optimizing the APS system, using APS-owned or contracted generation and purchased power, less Mark-to-Market Accounting adjustments. Traditional Sales-for-Resale - The portion of load from Native Load wholesale customers that is served by APS, excluding the load served with Preference Power. Transition Component - An amount generally expressed as a rate per kWh charge to be applied when necessary to provide for significant changes between estimated and actual costs under the Forward Component. Transition Component Tracking Account - An account that records on a monthly basis the account balance to be collected via the Transition Component as compared to the actual Transition Component revenues, plus applicable interest; the balance of which upon Commission consideration may then be reflected in the next Transition Component calculation. APS files the balances and supporting details underlying this Account with the Commission on a monthly basis. Effective Date XX/XX/XXXX Page 8 Attachment C Page 8 of 20

Arizona Corporation Commission Docket No. E-01345A-11-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism Wheeling Costs (FERC Account 565, Transmission of Electricity by Others) - Amounts payable to others for the transmission of APS’s electricity over transmission facilities owned by others. 7. Schedules Samples of the following schedules are attached to this Plan of Administration Schedule 1 Schedule 2 Schedule 3 Schedule 4 Schedule 5 Schedule 6 Schedule 7 Power Supply Adjustment (PSA) Rate Calculation PSA Forward Component Rate Calculation PSA Year Forward Component Tracking Account PSA Historical Component Rate Calculation Historical Component Tracking Account PSA Transition Component Rate Calculation PSA Transition Tracking Account 8. Compliance Reports APS shall provide monthly reports to Staffs Compliance Section and to the Residential Utility Consumer Office detailing all calculations related to the PSA. An APS Principal Officer, as listed in the Company's annual report filed with the Commission's Corporations Division, shall certify under oath that all information provided in the reports itemized below is true and accurate to the best of his or her information and belief. These monthly reports shall be due within 30 days of the end of the reporting period. The publicly available reports will include at a minimum: 1. The PSA Rate Calculation (Schedule 1); Forward Component, Historical Component, and Transition Component Calculations (Schedules 2, 4, and 6); Annual Forward Component, Historical Component, and Transition Component Tracking Account Balances (Schedules 3, 5, and 7). Additional information will provide other relative inputs and outputs such as: a. Total power and fuel costs. b. Margins on the sale of excess emission allowances. c. Off-system sales margins attributable to capacity freed up due to Rate Schedule AG-l. d. Customer sales in both MWh and thousands of dollars by customer class. e. Number of customers by customer class. f. A detailed listing of all items excluded from the PSA calculations. g. A detailed listing of any adjustments to the adjustor reports. h. Total off-system sales revenues. i. System losses in MW and MWh. j. Monthly maximum retail demand in MW. 2. Identification of a contact person and phone number from APS for questions. Effective Date XX/XX/XXXX Page 9 Attachment C Page 9 of 20

Arizona Corporation Commission Docket No. E-01345A-11-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism APS shall provide to Commission Staff monthly reports containing the information listed below. These reports shall be due within 30 days of the end of the reporting period. All of these additional reports will be provided confidentially. A. Information for each generating unit shall include the following items: 1. Net generation, in MWh per month, and 12 months cumulatively. 2. Average heat rate, both monthly and 12-month average. 3. Equivalent forced-outage rate, both monthly and 12-month average. 4. Outage information for each month including, but not limited to, event type, start date and time, end date and time, and a description. 5. Total fuel costs per month. 6. The fuel cost per kWh per month. B. Information on power purchases shall include the following items per seller (information on economy interchange purchases may be aggregated): 1. The quantity purchased in MWh. 2. The demand purchased in MW to the extent specified in the contract. 3. The total cost for demand to the extent specified in the contract. 4. The total cost of energy. C. Information on off-system sales shall include the following items: 1. An itemization of off-system sales margins per buyer. 2. Details on negative off-system sales margins. D. Fuel purchase information shall include the following items: 1. Natural gas interstate pipeline costs, itemized by pipeline and by individual cost components, such as reservation charge, usage, surcharges and fuel. 2. Natural gas commodity costs, categorized by short-term purchases (one month or less) and longer term purchases, including price per therm, total cost, supply basin, and volume by contract. E. APS will also provide: 1. Monthly projections for the next 12-month period showing estimated (Over)/under-collected amounts. 2. A summary of unplanned outage costs by resource type. 3. A summary of the net margins on the sale of emission allowances. 4. The data necessary to arrive at the System and Off-System Book Fuel and Purchased Power cost reflected in the non-confidential filing. 5. The data necessary to arrive at the Native Load Energy Sales MWh reflected in the non-confidential filing. Work papers and other documents that contain proprietary or confidential information will be provided to the Commission Staff under an appropriate confidentiality agreement. APS will keep fuel and purchased power invoices and contracts available for Commission review. The Commission has the right to review the prudence of fuel and power purchases and any Effective Date XX/XX/XXXX Page 10 Attachment C Page 10 of 20

Arizona Corporation Commission Docket No. E-01345A-11-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism calculations associated with the PSA at any time. Any costs flowed through the PSA are subject to refund if those costs are found to be imprudently incurred. 9. Allowable Costs a. Accounts The allowable PSA costs include fuel and purchased power costs incurred to provide service to retail customers. And, the prudent direct costs of contracts used for hedging system fuel and purchased power will be recovered under the PSA. Additionally, the net margins on the sale of emission allowances will also be refunded or recovered through the PSA. The allowable cost components include the following Federal Energy Regulatory Commission (“FERC”) accounts: • 501 Fuel (Steam) • 518 Fuel (Nuclear) less ISFSI regulatory amortization • 547 Fuel (Other Production) • 555 Purchased Power • 565 Wheeling (Transmission of Electricity by Others) • 411 O&M (Margins on the Sale of Emission Allowances) Additionally, broker fees recorded in FERC account 557 are allowable up to the limit set in Decision  No. xxxxx. These accounts are subject to change if the Federal Energy Regulatory Commission alters its accounting requirements or definitions. b. Directly Assignable Power Supply Costs Excluded Decision No. 66567 provides APS the ability to recover reasonable and prudent costs associated with customers who have left APS standard offer service, including special contract rates, for a competitive generation supplier and then return to standard offer service. For administrative purposes, customers who were direct access customers since origination of service and request standard offer service would be considered to be returning customers. A direct assignment or special adjustment may be applied that recognizes the cost differential between the power purchases needed to accommodate the returning customer and the power supply cost component of the otherwise applicable standard offer service rate. This process is described in the Returning Customer Direct Access Charge rate schedule and associated Plan for Administration filed with the Commission. In addition, if APS purchases power under specific terms on behalf of a standard offer special contract customer, the costs of that power may be directly assigned. In both cases, where specific power supply costs are identified and directly assigned to a large returning customer or standard offer special contract customer or group of customers, these costs will be excluded from the Adjustor Rate calculations. Schedule E-36 XL, and AG-l customers are directly assigned power supply costs based on the APS system incremental cost at the time the customer is consuming power from the APS system so their power supply costs and kWh usage are excluded from the PSA. Effective Date XX/XX/XXXX Page 11 Attachment C Page 11 of 20

ARIZONA PUBLIC SERVICE COMPANY Schedule 1 Power Supply Adjustment (PSA) Rate Calculation ($/kWh) Attachment C Page 12 of 20 Line Current Proposed Increase/(Decrease) No. PSA Rate Calculation February 1, XXXX February 1, XXXX 1 1 Forward Component Rate - FC (Schedule 2, L13) $- $- 2 Historical Component Rate - HC (Schedule 4, L5) 2 #.###### $- 3 PSA Transition Component Rate (Schedule 6, L3) 3 $- $- 4 PSA Rate (L1+ L2 + L3) #.###### $- Notes: 1 Proposed levels of the PSA rate components are provided in the September 30 filing and updated in the December 31 filing of each year. 2 A Historical Component is a true up related to respective prior period PSA activity. 3 Provides for Mid-Period Corrections when necessary. $/kWh % N/A N/A N/A N/A N/A N/A N/A N/A Page 1 of 9

ARIZONA PUBLIC SERVICE COMPANY Schedule 2 PSA Forward Component Rate Calculation ($ in thousands; Forward Component Rate in $/kWh) Line No. PSA Forward Component Rate - Calculation 1 Projected Fuel and Purchased Power Costs 2 Projected Off-System Sales Revenue 3 PSA Adjustments to Fuel and Purchased Power Costs 2 4 Net Fuel and Purchased Power Cost (L1 through L3) 5 Projected Net Margins on the Sale of Emission Allowances 6 Projected Billed Native Load Sales, excluding E-36XL, AG-1 (MWhs) 3 7 Projected Average Net Fuel Cost $/kWh (L4/ L6) 8 Projected Average Margin on Emission Allowances $/kWh (L5/ L6) 9 Total Projected Average PSA Cost $/kWh (L7+L8) 10 Authorized Base Cost of Fuel and Purchased Power Rate $/kWh 4 11 Authorized Base Net Margins on the Sale of Emission Allowances Rate $/kWh 12 Total Authorized Base Cost $/kWh 13 Forward Component Rate $/kWh (L9 - L12) Notes: $ $ $ $ Current February 15 XXXX $ #,###,### $ #,###,### $ (#,###,###) $ #,###,###- ##,###,### #.###### #.###### 0.032071 (0.000001) 0.032070 #.###### 1 Proposed levels are provided in the September 30 filing and updated in the December 31 filing of each year. Proposed February 15 XXXX 1 $ $ $ $ $ $ $ $ $ Attachment C Page 13 of 20 Increase/(Decrease) $ Values % N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 2 Includes costs associated with E-36XL, AG-1 and other direct assignment customers, ISFSI, and mark-to-market accounting adjustments. 3 The Projected Billed Native Load Sales of X,XXX,XXX MWhs for the Current Rate represent forecast sales for XXXX as of December 30th, XXXX. They exclude ED 3 and City of Williams wholesale contracts that are excluded from the Proposed sales and fuel costs. 4 Base Cost of Fuel and Purchased Power established in Decision No . Schedule presentation will appear to round up to $000s and MWh; however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh. Page 2 of 9 $- - - $- - - $- $- $- $- $- $- $-

Attachment C

Page 14 of 20

ARIZONA PUBLIC SERVICE COMPANY

Schedule 3

XXXX PSA Year Forward Component Tracking Account - in Effect from February 1, XXXX to Jan 31, XXXX

($ in thousands; Forward Component Rate and Base Rate in $/kWh)

		Feb-XX			Mar-XX		Apr-XX		May-XX		Jun-XX		Jul-XX		Aug-XX		Sept-XX		Oct-XX		Nov-XX		Dec-XX		Jan-XX		XXXX Total
1Prior Month’s Balance	From L26
Energy Sales
2PSA Retail Energy Sales(1)
3Wholesale Native Load Energy Sales (2)
4Total Native Load Energy Sales	L2 + L3	—			—		—		—		—		—		—		—		—		—		—		—
5Retail Energy Sales as a % of Total	L2 / L4
6Retail Billed Sales Excluding E-36XL, AG-1 Sales (MWh)(3)
7Metered Sales to AG-1 Customers
8Total Off-System Energy Sales
9Ratio of AG-1 sales to Total Off-System Sales	L7 / L8
PSA Costs
10Fuel and Purchased Power Costs (4),(5)
11Off System Revenue (Credit)(6)
12Off System Margin Displaced by AG-1 (Debit)
13Net Margins on Sale of Emission Allowances
14Net PSA Costs	sum(L10 to L13)	$	—		$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Retail PSA Costs
15Fuel and Purchased Power Costs	L5 * L10
16Off System Revenue (Credit)	L5 * L11
17Off System Margin Displaced by AG-1 (Debit)	L5 * L12
18Net Margins on Sale of Emission Allowances	L5 * L13
19Net Retail PSA Costs	sum(L15 to L18)	$	—		$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Base Rate Power Supply Recovery
20Fuel and Purchased Power Recovery	L28 * L2
21Net Margins on Sale of Emission Allowances	L29 * L2
(Over) Under Recovery From Base Rate
22Fuel and Purchased Power (Over) Under Recovery	(L15 + L16 + L17) - L20
23Net Margins on Sale of Emission Allowances (Over) Under Recovery	L18 - L2I
24Total (Over) Under Recovery	sum(L22 to L23)	—			—		—		—		—		—		—		—		—		—		—		—
25Forward Component Collections(7)	-L30 * L6
26Tracking Account Balance	L1 + L24 - L25	$	—		$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
27Annual Interest (Calculated only in January)																									$	—
28Total Base Fuel Rate - ¢ per kWh		3.2071
29Base Net Margin on the Sale of Emission Allowances - ¢ per kWh		(0.0001		)
30Forward Component Rate - ¢ per kWh		#.####

Notes:

(1)PSA Retail Energy Sales are the calendar month’s MWh sales. XXXX PSA Year Cumulative Retail Energy Sales of XX,XXX MWhs under rate schedule E-36XL, AG-1 were excluded from the PSA Calculations.

(2)Includes traditional sales for resale. PacifiCorp supplemental sales, and other non-ACC jurisdictional sales. ED 3 and City of Williams energy sales are excluded from the PSA Calculation.

(3)Retail Billed Sales on Line 6 relate specifically to the Forward Component Collections. Due to billing adjustments and timing, this amount will differ from other components’ Retail Billed Sales.

(4)Renewables costs exclude $X,XXX,XXX of XXXX PSA Year year-to-date costs that are currently being recovered through the RES rate schedule.

(5)Includes native load and off-system fuel and purchased power costs less those costs associated with E-36XL, AG-1 and other direct assignment customers, amortization of previously deferred ISFSI, Four Comers Coal Reclamation, and mark-to-market accounting adjustments.

(6)Includes off-system revenue less mark-to-market accounting adjustments.

(7)Generally, Line 30 * Line 6 = Line 25; however, differences may occur due to billing adjustments.

Schedule presentation will appear to round up to $000s: however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh

Page 3 of 9

ARIZONA PUBLIC SERVICE COMPANY Schedule 4 PSA Historical Component Rate Calculation ($ in thousands; Historical Component Rate in $/kWh) Line No. PSA Historical Component Rate Calculation 1 Forward Component Tracking Account Balance (Schedule 3, L26 + L27) 2 Historical Component Tracking Account Balance (Schedule 5, L9 + L10) 2 3 Total Historical Amount to be (Refunded)/Collected Balance (L1+L2) 4 Projected Billed Retail Energy Sales without E-36 XL, AG-1 (MWh) 5 Applicable Historical Component Rate (L3/ L4) Notes: Current February 1, XXXX #,### #,### #,### ##,###,### #.###### 1 Proposed levels are provided in the September 30 filing and updated in the December 31 filing of each year. 2 The Current Rate Projected Billed Retail Energy Sales are for February XXXX through January XXXX. Proposed February 1, XXXX 1 $ $ $ Attachment C Page 15 of 20 Increase/(Decrease) $ Values % N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Schedule presentation will appear to round up to $000s; however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh. Page 4 of 9

Attachment C

Page 16 of 20

ARIZONA PUBLIC SERVICE COMPANY

Schedule 5

Historical Component Tracking Account in Effect Feb 1, XXXX through Jan. 31, XXXX

($ in thousands Historical Component Rate in $/kWh)

Line

XXXX Data

XXXX

No.

January

February

March

April

May

June

July

August

September

October

November

December

January

1

Projected HC Tracking Account Balance at Dec. 31, XXXX

2

Projected FC Tracking Account Balance at Dec. 31, XXXX

3

True-up from December - January Estimate(1)

4

Prior Month’s Ending Balance

5

HC Adjusted Beginning Balance (L1+ L2 + L3 + L4)

6

Applicable Historical Component Rate ($/kWh)(2)

7

Retail Billed Sales Excluding E-36XL, AG-1 Sales (MWhs)(3)

8

Less Revenue from Applicable HC (L6 x L7)(4)

9

HC Ending Balance (L5 - L8)

$

—

10

Annual Interest (Calculated only in January)

Notes:

(1) True-up is the result of using estimated revenue and deferral for December and January since the actual amount was not available at the time of prior period PSA filing.

(2) Historical Component, Schedule 4, Line 5

(3) Sales amounts are for energy billed each period.

(4) Generally, Line 7 x Line 6 = Line 8; however, differences may occur due to billing adjustments.

Schedule presentation will appear to round up to $000s and MWh: however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh.

Page 5 of 9

Line No. ARIZONA PUBLIC SERVICE COMPANY Schedule 6 PSA Transition Component Rate Calculation ($ in thousands; Transition Component Rate(s) in $/kWh) Current February 1, XXXX 1 1 PSA Transition - Approved (Refundable)/Collection Amount 1 N/A 2 Projected Energy Sales without E-36XL, AG-1 (MWh) XXX. X, XX to XXX. X,XX N/A 3 PSA Transition Component (Refundable)/Collection Rate (L1 / L2) N/A Notes: 1 Commission Decision No. XXXXXXXXXX Proposed February 1, XXXX 1 N/A N/A N/A Attachment C Page 17 of 20 Increase/(Decrease) $ Values % N/A 0.00% N/A 0.00% N/A 0.00% Schedule presentation will appear to round up to $000s and MWh; however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh. Page 6 of 9

Attachment C

Page 18 of 20

ARIZONA PUBLIC SERVICE COMPANY

Schedule 7

PSA Transition Tracking Account in Effect XX 1, 20XX through XX 31, 20XX

($ in thousands; Transition Component Rate in $/kWh)

Line		20XX Data																								20XX
No.		January		February		March		April		May		June		July		August		September		October		November		December		January
1	Transferred balance from FC Tracking Acct Per Decision No. XXXXX					$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
2	Prior Month’s Ending Balance					$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
3	Transition Component TA Adjusted Beginning Balance (L1+ L2)					$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
4	Applicable Transition TA Component Rate ($/kWh) (1)					$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
5	Retail Billed Sales Excluding E-36XL, AG-1 Sales (MWhs) (2)					—		—		—		—		—		—		—		—		—		—		—
6	Less Revenue from Applicable Transition Component (L4 x L5)(3)					$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
7	Ending Balance; (L3 - L6)	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Notes:

(1) Transition Component, Schedule 6, Line 3

(2) Sales amounts are for energy billed each period.

(3) Generally, Line 4 x Line 5 = Line 6; however, differences may occur due to billing adjustments.

Schedule presentation will appear to round up to $000s and MWh: however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh.

Page 7 of 9

Attachment C

Page 19 of 20

ARIZONA PUBLIC SERVICE COMPANY

Schedule 8

Summary of Monthly Calculations

Mo YYYY

($ in thousands)

Line

XXXX Data

XXXX

No.

January

February

March

April

May

June

July

August

September

October

November

December

January

XXXX Forward Component Tracking Account

1

Beginning Balance

2

Transfers to XXXX Historical Component Tracking Account

3

Post-Sharing (Over)/Under Collection

4

Less Revenue from Applicable Forward Component Rate

5

Annual Interest (Calculated only in January)

6

Ending Balance (Line 1 + Line 2 + Line 3 - Line 4 + Line 5)

XXXX Historical Component Tracking Account

7

Beginning Balance

8

Transfers from XXXX Forward Component Tracking Account

9

Less Revenue from Applicable Historical Component Rate

10

Annual Interest (Calculated only in January)

11

Ending Balance (Line 7 + Line 8 - Line 9 + Line 10)

12

Combined Balance ([Line 6 + Line 11])(1)

13

Annual Interest Rate

#.##

%

Schedule presentation will appear to round up to $000s and MWh: however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh.

Page 8 of 9

Attachment C

Page 20 of 20

ARIZONA PUBLIC SERVICE COMPANY

Schedule 9

YYYY Native Load Customer Counts, Sales and Revenue

Mo YYYY

Line
No.	Class	January	February	March	April	May	June	July	August	September	October	November	December	Total(1)
	Customers
1	Residential													#DIV/0!
2	Commercial													#DIV/0!
3	Industrial													#DIV/0!
4	Irrigation													#DlV/0!
5	Sales for Resale(2)													#DIV/0!
6	Streetlights & Other Public Authority													#DIV/0!
7	Less E-36XL, AG-1, ED 3 and CoW (includes adj. to prior mth)													#DIV/0!
8	Total													#DIV/0!
	Sales (MWh)
9	Residential													—
10	Commercial													—
11	Industrial													—
12	Irrigation													—
13	Sales for Resale(2)													—
14	Streetlights & Other Public Authority													—
15	Less E-36XL, AG-1, ED 3 and CoW (includes adj. to prior mth)													—
16	Total													—
	Revenue($000)
17														$	—
18	Commercial													$	—
19	Industrial													$	—
20	Irrigation													$	—
21	Sales for Resale(2)													$	—
22	Streetlights & Other Public Authority													$	—
23	Less E-36XL, AG-1, ED 3 and CoW (includes adj. to prior mth)													$	—
24	Total													$	—
	Est. System Losses and Peak
25	Est. Native Load Sys. Losses (MWh)
26	Est. Native Load Sys. Losses (MW)
27	Est. Native Load Sys. Peak (MW)(3)

(1)The Customers total is the average of the customer class’ monthly totals.

(2)Includes traditional sales for resale, PacifiCorp supplemental sales, ED 3, City of Williams (CoW), and other non-ACC jurisdictional sales. Off-System Interchange customers, sales and revenue are excluded from Sales for Resale.

(3)The Preliminary Native Load System Peak totals will be updated each month.

Page 9 of 9

Attachment D Renewable Energy Projects Transferred from the Renewable Energy Surcharge (“RES”) to Base Rates Project In-Service Project Name Description Date 17 MW photovoltaic utility-scale solar generating September Paloma facility pursuant to AZ Sun Program approved in Decision No. 71502 2011 Phase I or 11 MW of a 16 MW photovoltaic utility- October Hyder I scale solar generating facility pursuant to AZ Sun 2011 Program approved in Decision No. 71502 Phase II or 5 MW of a 16 MW photovoltaic utility- March Hyder II scale solar generating facility pursuant to AZ Sun 2012 Program approved in Decision No. 71502 17 MW photovoltaic utility-scale solar generating October Cottion Center facility pursuant toAZ Sun Program approved in 2011 Decision No. 71502 Schools & 0.7 MW of small solar systems on schools and Government government facilities pursuant to program approved As Built Program in Decision No. 72174 Community 1.35 MW of distributed renewable energy systems Power Project - pursuant to the program approved in Decision No. As Built Flagstaff 71646 ACC Jurisdiction of 15-Months of Solar Generation Post-Test Year Plant Additions: Gross Utility Plant in Service Less: Accumulated Depreciation & Amortization Net Utility Plant in Service Less: Total Deductions Total Additions Total Rate Base $ 232.573M 3.391M 229.182M 2.476M $ 226.706M Page 1 of 1

Attachment E Settlement BSC for Residential Rates kWh Total BSC BSC Total per Month $ Bill Standard Opt-Out Delta % Bill Rate E-12 (Non-Time of Use) 0-400 49.70 8.55 9.15 0.60 1.21% 401-800 96.55 8.55 9.75 1.20 1.24% 801-2000 252.37 8.55 11.30 2.75 1.09% 2001+ 652.67 8.55 15.05 6.50 1.00% Rate ET-l & ET-2 (Time of Use) 0-400 58.06 16.68 17.28 0.60 1.03% 401-800 97.07 16.68 17.88 1.20 1.24% 801-2000 214.07 16.68 19.43 2.75 1.28% 2001+ 506.49 16.68 23.18 6.50 1.28% Rate ECT-1R & ECT-2 (Time of use with Demand Charge) 0-400 71.12 16.68 17.28 0.60 0.84% 401-800 100.60 16.68 17.88 1.20 1.19% 801-2000 177.81 16.68 19.43 2.75 1.55% 2001+ 337.05 16.68 23.18 6.50 1.93% These Opt-Out BSCs will remain fixed throughout the four-year rate period and until new rates are set. Page 1 of 1

Oaps Table of Contents PLAN OF ADMINISTRATION LOST FIXED COST RECOVERY Lost Fixed Cost Recovery (“LFCR”) Plan of Administration Attachment F Page 1 of 10 1. General Description 1 2. Definitions 1 3. LFCR Annual Incremental Cap 3 4. Filing and Procedural Deadlines 3 5. Compliance Reports 3 1. General Description This document describes the plan of administration for the LFCR mechanism approved for Arizona Public Service Company (“APS” or “Company”) by the Arizona Corporation Commission (“ACC”) on [insert date] in Decision No. XXXXX. The LFCR mechanism provides for the recovery of lost fixed costs, as measured by revenue, associated with the amount of energy efficiency (“EE”) savings and distributed generation (“DG”) that is authorized by the Commission and determined to have occurred. Costs to be recovered through the LFCR include the portion of transmission costs included in base rates and a portion of distribution costs, other than what is already recovered by (1) the Basic Service Charge and (2) 50% of demand revenues associated with distribution and the base rate portion of transmission. 2. Definitions Applicable Company Revenues - The amount of revenue generated by sales to retail customers, for all applicable rate schedules, less the amount of revenue attributable to sales to Opt-Out residential customers. Current Period - The most recent adjustment year. Demand Stability Factor - Fifty percent of distribution and transmission demand-based revenue produced by base rates. DG Savings - The amount of MWh sales reduced by DG. APS shall use statistical verification, output profile, or meter data for DG systems until December 31, 2014. Beginning January 2015, APS shall only use meter data to calculate DG system savings. Each year, APS will use actual data through September and forecast data for the remainder of the calendar year to calculate the savings. The calculation of DG Savings will consist of the following by class: 1. Current Period: The annual energy production (MWh) produced by the cumulative total of DG installations since the effective date of APS’s most recent general rate case. 2. Excluded MWh Production: The reduction of recoverable DG Savings calculated as follows: (1) for residential Opt-Out customers by either, dividing the number of Opt-Out residential customers by the total number of residential customers and multiplying that result by total residential DG Savings or using actual metered production, and (2) for commercial and industrial customers, by subtracting the amount ofDG produced by customers on Excluded Rate Schedules. Page 1 of 4

aps PLAN OF ADMINISTRATION LOST FIXED COST RECOVERY Attachment F Page 2 of 10 3. True-Up Prior Period: The reconciliation of APS’s forecast data of DG sales sreductions for the three months in the Prior Period to verified DG sales reductions in the Prior Period. Distribution Revenue - The amount determined at the conclusion of a rate case by multiplying both residential and general service adjusted test year billing determinants (kW and kWh) by their approved delivery charges. Any demand (kW) based delivery revenue will be reduced by the Demand Stability Factor. EE Programs - Any program approved in APS’s annual implementation plan. EE Savings - The amount of sales, expressed in MWh, reduced by EE as demonstrated by the Measurement, Evaluation, and Reporting (“MER”) conducted for EE programs. EE Savings shall be pro-rated for the number of days that new base rates are in effect during the initial implementation of the LFCR. The calculation of EE Savings will consist of the following by class: 1. Cumulative Verified: The cumulative total MWh reduction as determined by the MER using the effective date of APS’ s most recent general rate case as a starting point. 2. Current Period: The annual EE related sales reductions (MWh). Each year, APS will use actual MER data through September and forecast data for the remainder of the year to calculate savings. 3. Excluded MWh reduction: The reduction of recoverable EE Savings calculated as follows: (1) for residential Opt-Out customers by, dividing the number of Opt-Out residential customers by the total number of residential customers and multiplying that result by Current Period Savings, and (2) for commercial and industrial customers, by subtracting the amount of EE Savings actually achieved by customers on Excluded Rate Schedules. 4. True-Up Prior Period: The reconciliation of APS’s forecast data of EE sales reductions for the three months in the Prior Period to verified EE sales reductions in the Prior Period. Excluded Rate Schedules - The LFCR mechanism shall not apply to large general service customers taking service under rate schedules E-32 L, E-32 L TOU, E-34, E-35 and E-36 XL, or to unmetered General Service customers under E-30 and lighting schedules. LFCR Adjustment - An amount calculated by dividing Lost Fixed Cost Revenue by the Applicable Company Revenues. This adjustment percentage will be applied to all customer bills, excluding both those that have chosen to Opt-Out and those on Excluded Rate Schedules. Lost Fixed Cost Rate - A rate determined at the conclusion of a rate case by taking the sum of allowed Distribution Revenue and base rate Transmission Revenue for each rate class and dividing each by their respective class adjusted test year kWh billing determinants. Page 2 of4

Oaps PLAN OF ADMINISTRATION LOST FIXED COST RECOVERY Attachment F Page 3 of 10 Lost Fixed Cost Revenue - The amount of fixed costs not recovered by the utility because of EE and DG during the period. This amount is calculated by multiplying the Lost Fixed Cost Rate by Recoverable MWh Savings, by rate class. Opt-Out - The rate schedule choice for residential customers to opt out of the LFCR in the form of an optional BSC. The number of Opt-Out customers will be expressed as the annual average number of customers “Opting-Out” over the Current Period. The LFCR mechanism shall not be applied to residential customers who choose the Opt-Out provision. This rate will be made available to customers at the time of the first LFCR adjustment. Prior Period - The 12 months preceding the Current Period. Recoverable MWh Savings - The sum of EE Savings and DG Savings by rate class. Total Fixed Revenue - The total of Transmission Revenue and Distribution Revenue by Class. Transmission Revenue - The amount of revenue determined at the conclusion of a general rate case by multiplying both residential and general service adjusted test year billing determinants (kW and kWh) by the approved base rate transmission charge within their respective rate schedules. Any demand (kW) base rate Transmission Revenue will be reduced by the Demand Stability Factor. 3. LFCR Annual Incremental Cap The LFCR Adjustment will be subject to an annual 1 % year over year cap based on Applicable Company Revenues. If the annual LFCR Adjustment results in a surcharge and the annual incremental increase exceeds 1 % of Applicable Company Revenues, any amount in excess of the 1 % cap will be deferred for collection until the first future adjustment period in which including such costs would not cause the annual increase to exceed the 1 % cap. The one-year Nominal Treasury Constant Maturities rate contained in the Federal Reserve Statistical Release H-15 or its successor publication will be applied annually to any deferred balance. The interest rate shall be adjusted annually and shall be that annual rate applicable to the first business day of the calendar year. 4. Filing and Procedural Deadlines APS will file the calculated Annual LFCR Adjustment, including all Compliance Reports, with the Commission for the previous year by January 15th. The new LFCR Adjustment will not go into effect until approved by theCommission . 5. Compliance Reports APS will provide comprehensive compliance reports to Staff and the Residential Utility Consumer Office. The information contained in the Compliance Reports will consist of the following schedules: • Schedule 1: LFCR Annual Adjustment Percentage • Schedule 2: LFCR Annual Incremental Cap Calculation • Schedule 3: LFCR Calculation Page 3 of 4

aps PLAN OF ADMINISTRATION LOST FIXED COST RECOVERY • Schedule 4: LFCR Test Year Rate Calculation • Schedule 5: Distribution and Transmission Revenue Calculation - General Service • Schedule 6: Distribution and Transmission Revenue Calculation - Residential Attachment F Page 4 of 10 Schedules 1 through 6, attached hereto, will be submitted with APS’s annual compliance filing. Page 4 of 4

Line No. 1. 2. 3. Arizona Public Service Company Lost Fixed Cost Recovery Mechanism Schedule 1: LFCR Annual Adjustment Percentage ($000) (A) (B) Annual Percentage Adjustment Reference Total Lost Fixed Cost Revenue for Current Period Schedule 2, Line 13 Applicable Company Revenues Schedule 2, Line 1 % Applied to Customer's Bills (Line 1 / Line 2) $ (C) Total Attachment F Page 5 of 10 0.0000% Note: For the Current Period, the full revenue per customer decoupling mechanism that was proposed in APS’s June 1,2011 rate application (including all customers and offering no residential Opt-Out alternative) would have resulted in a total revenue adjustment of $X and average customer bill impact of Y%. Page 1 of 6 - -

Line No. l. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. Arizona Public Service Company Lost Fixed Cost Recovery Mechanism Schedule 2: LFCR Annual Incremental Cap Calculation ($000) (A) (B) LFCR Annual Incremental Cap Calculation Reference Applicable Company Revenues Allowed Cap % Maximum Allowed Incremental Recovery (Line 1 * Line 2) Total Lost Fixed Cost Revenue Schedule 3, Line 38, Column C Previous Filing, Schedule 2, Line Total Deferred Balance from Previous Period 11, Column C Annual Interest Rate Interest Accrued on Deferred Balance (Line 5 * Line 6) Total Lost Fixed Cost Revenue Current Period (Line 4 + Line 5 + Line 7) Previous Filing, Schedule 2, Line Lost Fixed Cost Revenue from Prior Period 13, Column C Total Incremental Lost Fixed Cost Revenue for Current Year (Line 8 - Line 9) Amount in Excess of Cap to Defer (Line 10 - Line 3) Incremental Period Adjustment as % [(Line 10 - Line 11)/ Line 1] Total Lost Fixed Cost Revenue for Current Period (Line 8 - Line 11) $ $ $ $ $ $ $ $ Attachment F Page 6 of 10 (C) Totals 1.00'% 0.00% 0.00% Page 2 of 6 - - - - - - - - -

Line No. 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. II. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. Arizona Public Service Company Lost Fixed Cost Recovery Mechamsm Schedule 3: LFCR Calculation ($000) (A) (B) Lost Fixed Cost Revenue Calculation Reference Residential Energy Efficency Savings Current Period % of Residential Customers on Opt-Out Excluded MWh reduction (Line 1 * Line 2) Net - Current Period (Line 1 - Line 3) Previous Filing, Schedule 3, Line 4, Prior Period Column C Verified - Prior Period True-Up Prior Period (Line 6 - Line 5) (Previous Filing, Schedule 3, Line 8, Cumulative Verified Column C + Line 6) Total Recoverable EE Savings (Line 4 + Line 7 + Line 8) Distributed Generation Savings Current Period Excluded MWh Production Net - Current Period (Line 10 - Line 11) Previous Filing, Schedule 3, Line 12, Prior Period ColumnC Verified - Prior Period True-Up Prior Period (Line 14 - Line 13) Total Recoverable DG Savings (Line 12 + Line 15) Total Recoverable MWh Savings (Line 9 + Line 16) Residential - Lost Fixed Cost Rate Schedule 4, Line 5, Column C Residential - Lost Fixed Cost Revenue (Line 17 * Line 18) C&I Energy Efficency Savings Current Period Excluded MWh reduction Net - Current Period (Line 20 - Line 21) Previous Filing, Schedule 3, Line 22, Prior Period Column C Verified - Prior Period True-Up Prior Period (Line 24 - Line 23) (Previous Filing, Schedule 3, Line 26, Cumulative Verified Column C + Line 24 l Total Recoverable EE Savings (Line 22 + Line 25 + Line 26) Distributed Generation Savings Current Period MWh DG Savings from Rate Scedules Excluded from LFCR Net - Current Period (Line 28 - Line 29) Previous Filing, Schedule 3, Line 30, Prior Period Column C Verified - Prior Period True-Up Prior Period (Line 32 - Line 31) Total Recoverable DG Savings (Line 30 + Line 33) Total Recoverable MWh Savings (Line 27 + Line 34) C&I - Lost Fixed Cost Rate Schedule 4, Line 10, Column C C&I - Lost Fixed Cost Revenue (Line 35 * Line 36) Total Lost Fixed Cost Revenue (Line 19 + Line 37) (C) Totals 0.0% $ $ $ $ $ (D) Units MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh $/kWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh MWh $/kWh Attachment F Page 7 of 10 Page 3 of 6 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

Line No. 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. Arizona Public Service Company Lost Fixed Cost Recovery Mechanism Schedule 4: LFCR Test Year Rate Calculation ($000) (A) (B) Lost Fixed Cost Rate Calculation Reference Residential Customers Distribution Revenue Schedule 6, Line 13, Column H Transmission Revenue Schedule 6, Line 13, Column I Total Fixed Revenue (Line 1 + Line 2) Schedule 6, Line 12, Column C / MWh Billed 1,000 Lost Fixed Cost Rate (Line 3 / Line 4) C & I Customers Distribution Revenue Schedule 5, Line 13, Column H Transmission Revenue Schedule 5, Line 13, Column I Total Fixed Revenue (Line 6 + Line 7) Schedule 5, Line 12, Column C / MWh Billed 1,000 Lost Fixed Cost Rate (Line 8/ Line 9) $ $ $ $ $ $ $ $ (C) Total Attachment F Page 8 of 10 Page 4 of 6

Attachment F

Page 9 of 10

Arizona Public Service Company

Lost Fixed Cost Recovery Mechanism

Schedule 5: Distribution and Transmission Revenue Calculation

General Service

			(C)		(E)		(F)		(G)		(H)		(I)		(J)
	(A)	(B)	Adjusted Test Year Billing	(D)	Delivery		Transmission		Demand Stability		C*E*(1-G)		C*F*(1-G)		H+I
Line No.	Rate Schedule	Tariff Component	Determinants	Units	Charge		Charge		Factor		Distribution Revenue		Transmission Revenue		Total Revenue
1.	General Service Rate Schedule 1
2.				kW	$	—	$	—	50	%	$	—	$	—	$	—
3.			—	kWh	$	—	$	—	0	%	$	—	$	—	$	—
4.	Sub Total		—	kW							$	—	$	—	$	—
5.			—	kWh							$	—	$	—	$	—
6.	General Service Rate Schedule 2		—
7.			—	kW	$	—	$	—	50	%	$	—	$	—	$	—
8.			—	kWh	$	—	$	—	0	%	$	—	$	—	$	—
9.	Sub Total		—	kW							$	—	$	—	$	—
10.			—	kWh							$	—	$	—	$	—
11.	Total kW		—	kW							$	—	$	—	$	—
12.	Total kWh		—	kWh							$	—	$	—	$	—
13.	Total										$	—	$	—	$	—

Page 5 of 6

Attachment F

Page 10 of 10

Arizona Public Service Company

Lost Fixed Cost Recovery Mechanism

Schedule 6: Distribution and Transmission Revenue Calculation

Residential

			(C)				(F)		(G)		(H)		(I)		(J)
	(A)	(B)	Adjusted Test Year Billing	(D)	(E)		Transmission		Demand Stability		C*E*(1-G)		C*F*(1-G)		H+I
Line No.	Rate Schedule	Tariff Component	Determinants	Units	Delivery Charge		Charge		Factor		Distribution Revenue		Transmission Revenue		Total Revenue
1.	Residential Rate Schedule 1
2.			—	kW	$	—	$	—	50	%	$	—	$	—	$	—
3.			—	kWh	$	—	$	—	0	%	$	—	$	—	$	—
4.	Sub Total		—	kW							$	—	$	—	$	—
5.			—	kWh							$	—	$	—	$	—
6.	Residential Rate Schedule 2
7.			—	kW	$	—	$	—	50	%	$	—	$	—	$	—
8.			—	kWh	$	—	$	—	0	%	$	—	$	—	$	—
9.	Subtotal		—	kW							$	—	$	—	$	—
10.			—	kWh							$	—	$	—	$	—
11.	Total kW		—	kW							$	—	$	—	$	—
12.	Total kWh		—	kWh							$	—	$	—	$	—
13.	Total										$	—	$	—	$	—

Page 6 of 6

Attachment G Page 1 of 7 aps DEMAND SIDE MANAGEMENT ADJUSTMENT CHARGE PLAN OF ADMINISTRATION XXXX-XX-XX 1. GENERAL DESCRIPTION: This document describes the plan for administering the Demand Side Management Adjustment Charge (“DSMAC”) approved for Arizona Public Service Company (“APS”) by the Arizona Corporation Commission (“Commission”) in Decision No. 67744, and later revised by the Commission in Decision Nos. 71448 and XXXXXX. The DSMAC provides for the recovery of Demand Side Management (“DSM”) program costs, including energy efficiency and demand response programs, and energy efficiency performance incentives. The DSMAC is applied to Standard Offer or Direct Access customer's bills as a monthly kilowatt-hour charge (for Residential customers and General Service customers served in accordance with non-demand billed rate schedules) or kilowatt demand charge (for General Service customers served in accordance with demand billed rate schedules). The charge will be filed with the Commission annually when APS submits the Energy Efficiency Implementation Plan (“EEIP”) for approval. This will occur July 15,2009 for the 2010 program year, and on June 1st of all subsequent years. If approved by the Commission, the charge will be effective each year beginning with billing cycle 1 of the March revenue month and will not be prorated. Recovery of all applicable programs costs and incentives will be allowed for all programs that have been approved by the Commission. 2. RATE SCHEDULE APPLICABILITY: The DSMAC shall be applied monthly to every retail Standard Offer or Direct Access service. 3. ALLOWABLE COSTS: The types of allowable costs are as follows: A. Program Costs (PC) Allowable expenses include, but are not limited to: Program development, implementation, promotion, administrative and general, training and technical assistance, marketing and communications, evaluation costs, monitoring and metering costs, advertising, educational expenditures, customer incentives, research and development, data collection (such as end-use), tracking systems, self direction costs, measurement evaluation and research (MER), demonstration facilities and all other activities required to design and implement cost-effective DSM programs (energy efficiency and demand response) that are approved by the Commission in the EEIP. For those DSM programs that generate revenue, the revenue, if any, will be credited back to the DSMAC. Unrecovered fixed costs will not be recoverable through the DSMAC. B. Performance Incentives (PI) Represents a percentage share of the net economic benefits (benefits minus costs) from approved energy-efficiency programs based on a graduated scale that is capped at a percentage of EE PC. Performance Incentive Performance Incentive Achievement Relative as % of Energy Capped at % of Energy to the Energy Efficiency Efficiency Program Efficiency Standard Net Benefits Costs < 85% 0% 0% 85% to 95% 6% 12% 96% to 105% 7% 14% >105% 8% 16% 4. DETERMINATION OF TRUE-UP: The actual allowable cost recovered for approved DSM programs will be compared to the actual revenues received by the Company through the DSMAC. The True-Up (TU) will be based on the amount in the TU balancing account. This balance will include past period PC, PI and DSMAC revenue collection accruals as of April 30th of the filing year. Past period PC and PI are found on Schedule 2 of the DSMAC Page 1 of 3

Attachment G Page 2 of 7 DEMAND SIDE MANAGEMENT ADJUSTMENT CHARGE PLAN OF ADMINISTRATION XXXX-XX-XX aps calculations. Past period DSMAC revenue is found in Schedule 1 of the DSMAC calculations. The TU balancing account computation will be provided annually in Schedule 3 of the DSMAC calculations. In the event that PC or PI are more or less than DSMAC revenues collected as of the last billing cycle of February, the over or under collection will be subtracted from or added to the DSMAC calculation in the subsequent period. Any over collection will accrue interest charges. Under collections will not accrue interest. Illustrative Table of Events Date Included Items 7/15/2009 File 2010 EEIP with 2010 DSMAC DSMAC includes: 2010 forecast of PC and PI 2009 forecast of PC and PI TU balancing account as of the last billing cycle of February 3/1/2010 DSMAC start from 2010 EEIP 6/1/2010 File 2011 EEIP with 2011 DSMAC DSMAC includes: 2011 forecast of PC and PI TU balancing account as of the last billing cycle of February 3/1/2011 DSMAC start from 2011 EEIP 6/1/2011 File 2012 EEIP with 2012 DSMAC DSMAC includes: 2012 forecast of PC and PI TU balancing account as of the last billing cycle of February 5. DETERMINATION OF THE ADJUSTOR CHARGE: By July 15,2009 and on June 1st of each subsequent year, APS will file a revised DSMAC with supporting documentation in the EEIP. The DSMAC will be calculated by projecting PC and PI for the upcoming year, adjusted by the over or under collection of previous periods. This calculation will be provided in the annual DSMAC calculation on Schedule 4. The DSMAC for purposes of recovering PC and PI under the DSM Program will be developed based on the following formula: Where: DSMAC = PC PI TU Sales Adjustor Period PC + PI + TU +1 Sales Program Costs as defined in section 3 forecast for the upcoming year. Performance Incentives as defined in section 3 forecast for the upcoming year. Any “true-up” balance as defined in section 4. Interest associated on any over recovery of DSMAC costs for the prior period. The interest rate is based on the one-year Nominal Treasury Maturities rate from the Federal Reserve H-15 or its successor publication. The interest rate shall be adjusted annually on the first business day of the calendar year. Forecast energy (kWh) sales under applicable electric rate schedules during the Adjustor Period in which this adjustor will be effective. The 12 month period beginning with the first billing cycle during March of the current year and ending with the last billing cycle of February of the next year. Page 2 of3

aps Attachment G Page 3 of 7 DEMAND SIDE MANAGEMENT ADJUSTMENT CHARGE PLAN OF ADMINISTRATION XXXX-XX-XX The DSMAC for General Service customers that are billed on demand will be calculated as a per kWh charge. The DSMAC for General Service customers that are not billed on demand will be calculated as a per kWh charge. To calculate the per kW charge, the recoverable costs shall first be allocated to the General Service class based upon the number of kWh consumed by that class. The remainder of the recoverable costs allocated to the General Service class shall then be divided by the kW billing determinants for the demand billed customers in that class to determine the per kW DSMAC. For residential billing purposes, the DSMAC and the Renewable Energy Surcharge (“RES”) are combined and will appear on customer bills as the “Environmental Benefits Surcharge”. For the billing of general service and other non-residential customers, the Company may, but is not required to, provide for such combined billing of the RES and DSMAC. In any event, each adjustor shall have separate rate schedules and will be kept separate in the Company's books, records, and reports to the Commission. 6. REVIEW PROCESS: The proposed DSMAC for use during a specific Adjustor Period will be calculated as shown in Section 4. APS will file an updated adjustor charge each year with its EEIP. The first filing will be July 15,2009, and June 1st each year thereafter. If approved by the Commission, changes in the DSMAC will go into effect on the first billing cycle of March in the Adjustor Period. Page 3 of 3

ATTACHMENT 1 ESTIMATED ARIZONA PUBLIC SERVICE COMPANY DEMAND SIDE MANAGEMENT PROGRAM JUNE 20XX FILING (A) True-Up Period Line DSMAC Revenue for March 20XX - No. February 20XX 1 Total 1 Recovery period is March 20XX-February 20XX for costs associated with the 20XX program year. Attachment G Page 4 of 7 Schedule 1 DSMAC REVENUE Page 1 of 4

Line No. Program 1 Energy Efficiency (EE) Program Costs (PC) 2 Performance Incentives (PI) 3 Sub Total 4 Demand Response (DR) PC 5 Total ATTACHMENT 1 ESTIMATED ARIZONA PUBLIC SERVICE COMPANY DEMAND SIDE MANAGEMENT PROGRAM JUNE 20XX FILING $ $ $ $ $ (A) True-Up Period 20XX1 $ $ (8) Forecast Period 20XX2 1 Total 20XX EE and DR costs of $XX,XXX,XXX less $10,000,000 recovered in base rates 2 Projected costs of 20XX Implementation Plan less $10,000,000 recovered in base rates. Attachment G Page 5 of 7 Schedule 2 DSMAC REVENUE Page 2 of 4

Line No. 1 2 3a 3b 4 5 Date Period March 20XX -February 20XX January 20XX - December 20XX ATTACHMENT 1 ESTIMATED ARIZONA PUBLIC SERVICE COMPANY DEMAND SIDE MANAGEMENT PROGRAM JUNE 20XX FILING Cost, Collection and Interest DSMAC Revenue - TU DSMAC Program Costs - TU Sub Total Reference Schedule 1, Line 1, Column A Schedule 2, Line 5, Column A (Line 1 - Line 2) Treasury constant maturities rate January 20XX 1 Interest Rate Interest Amount Total TU Balance Account 1 Interest is only applied to over-collections (Line 3a * 3b) (Line 3a + Line 4) $ $ $ $ $ Attachment G Page 6 of 7 Schedule 3 DSMAC REVENUE Page 3 of 4 Amount 0.00%

Line No. 1 2A 2B 3 4 5 6 DSMAC Calculations Program forecast costs for adjustor period in 20XX Recovery of True-Up Account (over) under collection Credit for Gains from Asset Sales (over) under collection Total amount to be collected Forecast retail kWh sales for adjustor period Proposed kWh adjustor charge for adjustor period1 Forecast General Service kWh sales for adjustor period 2 ATTACHMENT 1 ESTIMATED ARIZONA PUBLIC SERVICE COMPANY DEMAND SIDE MANAGEMENT PROGRAM JUNE 20XX FILING Reference Schedule 2, Line 5, Column B Schedule 3, Line 5 (Line 1 + Line 2) (Line 3/ Line 4) 7 Amount to be collected from General Service demand metered customers for adjustor period (Line 5 * Line 6) 8 Forecast General Service demand billed customer kW 9 Proposed kW adjustor charge for forecast period 3 (Line 7/ Line 8) 1 $/kWh charge for all Residential customers and General Service customers with no demand charge 2 Forecast General Service kWh for customers with demand charges 3 $/kW charge for General Service customers with demand charges Amount $ $ $ $ 0 $ 0 $ 0 $ Units Attachment G Page 7 of 7 Schedule 4 DSMAC REVENUE Page 4 of 4 Total Revenue Requirements kWh per kWh kWh kW per kW -------

aps Table of Contents PLAN OF ADMINISTRATION ENVIRONMENTAL IMPROVEMENT SURCHARGE Environmental Improvement Surcharge Plan of Administration Attachment H Page 1 of 5 1. General Description 1 2. Definitions 1 3. Qualified FERC Accounts 2 4. Calculation of EIS Capital Carrying Costs 2 5. Calculation of EIS $ per kWh rate 3 6. Filing and Procedural Deadlines 3 1. General Description This document describes the plan for administering the Environmental Improvement Surcharge ("EIS") approved for the Arizona Public Service Company ("APS") by the Arizona Corporation Commission ("ACC" or "Commission") on [insert date] in Decision No. XXXXX. The EIS provides for the recovery of the capital carrying costs effect of actual environmental investments made by APS and not already recovered in base rates approved in Decision No. xxxxx or recovered through another Commission approved adjustment. The EIS will be calculated annually based on the EIS Qualified Investments closed to plant-in-service during the preceding calendar year. 2. Definitions EIS Qualified Investments - Investments in Qualified Environmental Improvement Projects. Each EIS Qualified Investments must: (1) be classified in one or more of the FERC plant accounts as listed in Section 3 of this document, or any other successor FERC account, upon going into service, (2) be tracked by a specific project number. Qualified Environmental Improvement Projects - Projects designed to comply with established environmental standards required by federal, state, tribal, or local laws and regulations. These standards and criteria for water, waste, and air include but are not limited to limits for carbon dioxide (C02), sulfur oxide (SOx), nitrogen oxide (NOx) , particulate matter (PM), volatile organic compounds (VOC), and toxics such as mercury (Hg), coal ash management, and requirements under the clean and safe drinking water acts. Total kWh Sales - The total prior calendar year energy (kWh) sales served under applicable ACC jurisdictional electric rate schedules, except Rate Schedules E-36 XL andAG-l, as reported in the Company's FERC Form No.1. Effective Date: XX/XX/XXXX Page 1 of 3

aps 3. Qualified FERC Accounts 1. Steam Production PLAN OF ADMINISTRATION ENVIRONMENTAL IMPROVEMENT SURCHARGE • FERC Account 310 – Land and Land Rights • FERC Account 311 – Structures and Improvements • FERC Account 312 – Boiler Plant Equipment • FERC Account 313 – Engines and Engine–Driven Generators • FERC Account 314 – Turbogenerator Units • FERC Account 315 – Accessory Electric Equipment • FERC Account 316 – Miscellaneous Power Plant Equipment 2. Nuclear Production • FERC Account 320 – Land and Land Rights • FERC Account 321 – Structures and Improvements • FERC Account 322 – Reactor Plant Equipment • FERC Account 323 – Turbogenerator Units • FERC Account 324 – Accessory Electric Equipment • FERC Account 325 – Miscellaneous Power Plant Equipment 3. Other Production • FERC Account 340 – Land and Land Rights • FERC Account 341 – Structures and Improvements • FERC Account 342 – Fuel Holders, Products, and Accessories • FERC Account 343 – Prime Movers • FERC Account 344 – Generators • FERC Account 345 – Accessory Electric Equipment • FERC Account 346 – Miscellaneous Power Plant Equipment Attachment H Page 2 of 5 Please note this list may expand to include other accounts approved by the ACC in the future. 4. Calculation of EIS Capital Carrying Costs EIS capital carrying costs used in calculating the EIS $ per kWh rate will include: (1) Return on EIS Qualified Investments based on the Company's Weighted Average Cost of Capital ("W ACC") approved by the Commission in Decision No. XXXXX; (2) depreciation expense; (3) income taxes; (4) property taxes; (5) deferred income taxes and tax credits where appropriate; and (6) associated O&M. EIS Qualified Projects and the EIS capital carrying costs calculation will be submitted by the Company to the ACC in the fonn of Schedule 1 and Schedule 2 as attached to this document. Effective Date: XX/XX/XXXX Page 2 of 3

Attachment H Page 3 of 5 aps PLAN OF ADMINISTRATION ENVIRONMENTAL IMPROVEMENT SURCHARGE 5. Calculation of EIS $ per kWh rate The EIS rate to be applied to customers' bills will be calculated by dividing the total EIS Capital Carrying Costs by Total kWh Sales. The EIS rate will not exceed $0.00016 per kWh. The initial EIS rate will be set to zero. 6. Filing and Procedural Deadlines APS will file the calculated EIS rate including all supporting data, with the Commission for the previous year on or before February 1 st. See Schedules 1 and 2, attached. The Commission Staff and interested parties shall have the opportunity to review the EIS filing and supporting data in the adjustor calculation. Unless the Commission has otherwise acted or Staff has filed an objection by April 1 st, the new EIS rate proposed by APS will go into effect with the first billing cycle in April (without proration) and will remain in effect for the following 12-month period. Effective Date: XX/XX/XXXX Page 3 of 3

Line No. 1. 2. 3. 4. (A) Project Tracking Number (B) Schedule 1: Qualified Investments for EIS Electric Plant in Service for Calendar Year 20XX (C) (D) Project Name Purpose In-Service Date Environmental Improvement Projects XXXXX Project A Project A Purpose Description MM/YY XXXXX Project B Project B Purpose Description MM/YY XXXXX Project C Project C Purpose Description MM/YY Total (E) Total Cost S $ (F) Attachment H Page 4 of 5 ACC Jurisdictional Total Cost $ $ Page 1 of 2 - - - - - - - -

Line No. 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. Schedule 2: Capital Carrying Costs and Adjustor Calculation Plant in Service for Calendar Year 20XX Billing Period 4/1/20XX-3/30/XX EIS Rate Calculation Qualified Net Plant Environmental Improvement Projects (Schedule 1 - Total Line Column F) Accumulated Depreciation Cumulative Deferred Tax/Tax Credits Qualified Net Plant (Line 1- Line 2 - Line 3) Pre-tax Weighted Average Cost of Capital Capital Carrying Costs Composite Return on EIS Net Plant (Line 4 * Line 5) Annual Depreciation of Plant In Service Applicable Property Tax Associated O&M Expense Total EIS Capital Carrying Costs (Line 6 + Line 7 + Line 8 + Line 9) 11. Total Company Retail Sales (kWh) 12. Calculated EIS Adjustment ($/kWh) (Line 10 / Line 11) 13. EIS Rate Cap ($/kWh) 14. EIS Rate ($/kWh) (lesser of Line 12 and Line 13) $ $ $ $ $ $ $ $ $ $ $ $ 0.00% 0.00016 Attachment H Page 5 of 5 Page 2 of 2 - - - - - - - - - - - -

aps Table of Contents Attachment I Page 1 of 3 PLAN OF ADMINISTRATION ADJUSTMENT SCHEDULE TCA-l TRANSMISSION COST ADJUSTMENT Transmission Cost Adjustment Plan of Administration 1. General Description 1 2. Calculations 1 3. Filing and Procedural Deadlines 3 1. General Description The purpose of the Transmission Cost Adjustment ("TCA") is to provide a mechanism to recover transmission costs associated with serving retail customers at the level approved by the Federal Energy Regulatory Commission ("FERC") and at the same time as new transmission rates become effective for APS wholesale customers. APS shall file a notice with Docket Control that includes its revised TCA tariff, along with a copy of its FERC information filing of its annual update of transmission service rates pursuant to its Open Access Transmission Tariff ("OATT"). This notice shall be filed with the Commission at the same time that APS makes its FERC filing. The TCA applies to Arizona Public Service Company's ("Company") Retail Electric Rate Schedules. For Standard Offer customers that are not demand billed, the TCA is applied to the bill as a monthly kWh charge. For Standard Offer customers that are demand billed, it is applied to the TCA as a kW charge. The charge and modifications to it will take effect in billing cycle 1 of the June revenue month without proration. APS's Network Integration Transmission Service ("NITS") is calculated and filed annually with the FERC in accordance with APS's formula rate. The formula rate calculation is specified within the Company's OATT as filed and approved by the FERC. 2. Calculations The calculated NITS Retail Transmission Rates are shown in Appendix A of the Company's FERC Informational Filing of its Annual Update of transmission service. NITS rates as determined for the following classes: Residential Service Customers General Service Customers less than or equal to 20 kW not demand billed General Service Customers over 20 kW and less than 3 MW demand billed General Service Customers equal to and greater than 3 MW Effective Date: XX/XX/XXXX Page 1 of 3

aps Attachment I Page 2 of 3 PLAN OF ADMINISTRATION ADJUSTMENT SCHEDULE TCA-l TRANSMISSION COST ADJUSTMENT In addition to NITS, APS charges retail customers for other transmission services in accordance with its OATT. These additional ancillary services include: Schedule 1 – Scheduling, System Control and Dispatch Service Schedule 3 – Regulation and Frequency Response Service Schedule 4 – Energy Imbalance Service Schedule 5 – Operating Reserve-Spinning Reserve Service Schedule 6 – Operating Reserve – Supplemental Reserve Service The total APS OATT rate is the sum of the rates for providing these services. The revenue requirement resulting from FERC APS OATT rate are collected by APS from its retail customers, partly in base rates and the remaining through the TCA rate. The table shown below is an illustrative example of the TCA calculation using the rates in effect as of December 20,2011. GS < 20kW Line Service Type Residential GS < 20 kW and < 3MW GS > 3MW $/kWh $/kWh $/kW $/kW (A) (B) (C) (D) 1. NITS 0.008381 0.005864 2.108 2.036 2. Scheduling 0.000069 0.000056 0.0208 0.0236 3. Regulation & Frequency 0.000267 0.000217 0.0813 0.0919 4. Spinning Reserve 0.000618 0.000502 0.1879 0.2124 5. Operating Reserve 0.000078 0.000064 0.0238 0.0269 6. Energy Imbalance - - - - 7. Total 0.009413 0.006703 2.4218 2.3908 8. Included In Retail Base 0.005202 0.004239 1.5848 1.7758 Rates per OATT 9. I TCA (Line 7) - (Line 8) 0.004211 0.002464 0.837 0.615 APS's NITS rates shown on line 1 will change annually, where ancillary service charges shown on lines 2 through 6 will change only through a separate filing when made by the Company to FERC. Effective Date: XX/XX/XXXX Page 2 of 3

aps 3. Filing and Procedural Deadlines Attachment I Page 3 of 3 PLAN OF ADMINISTRATION ADJUSTMENT SCHEDULE TCA-! TRANSMISSION COST ADJUSTMENT APS will file the calculated TCA rates, including all supporting data, with the Commission each year no later than May 15th of each year. The Commission Staff and interested parties shall have the opportunity to review APS' s FERC Informational Filing of its Annual Update of transmission service rates pursuant to the APS OATT Attachment H-2, Formula Rate Implementation Protocols. The calculated NITS Retail Transmission Rates are shown in Appendix A of the Company's FERC filing. The new TCA rates proposed by APS will go into effect with the fIrst billing cycle in June (without proration), unless Staff requests Commission review or otherwise ordered by the Commission, and will remain in effect for the following 12-month period. Effective Date: XX/XX/XXXX Page 3 of 3

aps AVAILABILITY Attachment J EXPERIMENTAL RATE RIDER SCHEDULE AG-l Page 1 of 5 ALTERNATIVE GENERATION GENERAL SERVICE This experimental rate rider schedule is available in all territories served by the Company at all points where facilities of adequate capacity and the required phase and suitable voltage are adjacent to the sites served. APPLICATION This rate rider schedule is available for Standard Offer customers who have an Aggregated Peak Load of 10 MW or more and are served under Rate Schedules E-34, E-35, E32-L, or E-32 TOU L. An aggregated group may also include metered accounts that are served under Rate Schedules E-32 M or E-32 TOU M, if the accounts are located on the same premises and served under the same name as an otherwise eligible Customer. Customers must have interval metering, Advanced Metering Infrastructure, or an alternative in place at all times of service under this schedule. If the Customer does not have such metering, the Company will install the metering equipment at no additional charge. However, the customer will be responsible for providing and paying for any communication requirements associated with the meter, such as a phone line. All provisions of the customer's applicable rate schedule will apply in addition to this Schedule AG-l, except as modified herein. This rate rider schedule shall be available for four years from the effective date of Schedule AG-l, unless extended by the Commission. Total program participation shall be limited to 200 MW of customer load, 100 MW of which shall be initially reserved for Customers served under Rate Schedule E-32 L. DEFINITIONS Aggregated Peak Load: The sum of the maximum metered kW for each of the Customer's aggregated metered accounts over the previous 12 months, as determined by the Company and measured at the Customer's meter(s) at the time of application for service under this rate rider schedule. Standard Generation Service: Power provided by the Company to a retail customer in conjunction with transmission and delivery services, at terms and prices according toa retail rate schedule other than Schedule AG-l. Customer: A metered account or set of aggregated metered accounts that meet the eligibility requirements for service and enrollment as an aggregated load for service, under this rate rider schedule. Generation Service Provider: A third party entity that provides wholesale power to the Company on behalf of a Customer. This entity must be legally capable of selling and delivering wholesale power to the Company. Generation Service: Wholesale power delivered to APS by a Generation Service Provider. Imbalance Energy: For each Generation Service Provider, Imbalance Energy will be calculated by the Company as the difference between the hourly delivered energy from the Generation Service Provider and the actual hourly metered load for each Customer for all Customers that have selected the Generation Service Provider under this rate rider schedule. Imbalance Service: Calculating and managing the hourly deviations in energy supply for imbalance energy. Total Load Requirements: The Customer's hourly load including losses from the point of delivery to the Company's transmission system to the Customer's sites for the duration of the contract. ARIZONA PUBLIC SERVICE COMPANY Phoenix, Arizona Filed by: David J. Rumolo Title: Manager, Regulation and Pricing Page l of 5 A.C.C. No. XXXX Rate Schedule AG-I Original Effective: XXXX

aps CUSTOMER ENROLLMENT Attachment J EXPERIMENTAL RATE RIDER SCHEDULE AG-l Page 2 of 5 ALTERNATIVE GENERATION GENERAL SERVICE The Company shall establish an initial enrollment period during which Customers can apply for service under this rate rider schedule. If the applications for service are greater than the program maximum amount, then Customers shall be selected for enrollment through a lottery process as detailed in the program guidelines, which may be revised from time-to-time during the term ofthis rate rider schedule. AGGREGATION Eligible customers may be aggregated if they have the same corporate name, ownership, and identity. In addition, (1) an eligible franchisor customer may be aggregated with eligible franchisees or associated corporate accounts, and (2) eligible affiliate customers may be aggregated if they are under the same corporate ownership, even if they are operating under multiple trade names. DESCRIPTION OF SERVICES AND OBLIGATIONS The Customer shall apply for service under this rate rider schedule. The Company shall conduct the enrollment process in accordance with the provisions of this rate rider schedule. The Customer shall select a Generation Service Provider to provide Generation Service in accordance with the timeline specified in the program guidelines The Company shall enter into a contract with the Generation Service Provider to receive delivery and title to the power on the Customer's behalf. The Generation Service Provider shall provide to the Company on behalf of the Customer firm power sufficient to meet the Customer's Total Load Requirements for each of the specified metered accounts, and will attest in its contract with the Company that this condition is met. For the purposes of this rate schedule, "firm power" refers to generation resources identified in Western System Power Pool Schedule C or a reasonable equivalent as determined by the Company. The Company shall provide transmission, delivery and network services to the Customer according to normal retail electric service. The Company will settle with the Generation Service Provider for Imbalance Service and other relevant costs on a monthly basis according to the program guidelines. The Generation Service Provider shall bill the Company the monthly billed amounts for each customer for Generation Service and Imbalance Service according to the program guidelines. The Company shall bill the customer for the Generation Service Provider's charged amounts and remit the amounts to the Generation Service provider. The customer will be responsible for paying for the cost of the power provided by the Generation Service Provider, as specified in the contract and this rate rider schedule. ARIZONA PUBLIC SERVICE COMPANY Phoenix, Arizona Filed by: David 1. Rumolo Title: Manager, Regulation and Pricing Page 2 of 5 A.C.C. No. XXXX Rate Schedule AG-I Original Effective: XXXX

laps Attachment J EXPERIMENTAL RATE RIDER SCHEDULE AG-l Page 3 of 5 ALTERNATIVE GENERATION GENERAL SERVICE DELIVERY OF POWER TO THE COMPANY'S SYSTEM Power provided by the Generation Service Provider must be firm power as defined above and delivered to the Company at the Palo Verde network delivery point, or other point of delivery as agreed to by the Company. The Generation Service Provider is responsible for the cost of transmission service to deliver the power to the Company's delivery point. SCHEDULING The Company shall serve as the scheduling coordinator. The Generation Service Provider shall provide monthly schedules of hourly loads along with day-ahead hourly load deviations from the monthly schedule to the Company according to the program guidelines. Line losses, in the amount of 7%, from the point of delivery to the Customer's sites shall be either scheduled or financially settled. IMBALANCE SERVICE The Company will provide Imbalance Service according to the terms and provisions in the Company's Open Access Transmission Tariff, Schedule 4. Imbalance Energy will be based on the Generation Service Provider's portfolio of Customer loads. POWER SUPPLY ADJUSTER AND HEDGE COST TRUE-UP The customer will be subject to the power supply adjustment – historical component for the first twelve months of service under this rate rider schedule. The customer will also pay for the hedge cost associated with the customer's Standard Generation Service at the time the customer takes service under this rate rider schedule. For the purpose of this rate rider schedule, the Company will determine the applicable pro rata hedge cost based on the market price for hedge costs at the time the customer takes service under this rate rider schedule. DEFAULT OF THE THIRD PARTY GENERATION PROVIDER In the event that the Generation Service Provider is unable to meet its contractual obligations, the customer must notify the Company and select another Generation Service Provider within 60 days. Prior to execution of any new power contract, the Company shall provide the required power to the customer, which will be charged at the Dow Jones Electricity Palo Verde Hourly Index price for the power delivery date plus $10 per MWh. In addition, all other provisions of this rate rider schedule will continue to apply. If the Customer is unable to select another Generation Service Provider within sixty days, the customer will automatically return to Standard Generation Service, and be subject to the conditions below. RETURN TO COMPANY'S STANDARD GENERATION SERVICE Customer may return to the Company's Standard Generation Service under their applicable retail rate schedule without charge if: (1) they provide one year notice (or longer) to the Company; or (2) if this rate rider schedule is discontinued at the end of the 4 year experimental period; or (3) if the Commission terminates the program prior to the initial four year experimental period. Absent one of these three conditions, the Company will provide the customer with generation service at the market index rate provided in the Company's Open Access Transmission Tariff until the Company is reasonably able to integrate the customer back into their generation planning and provide power at the applicable retail rate schedule. This transition will be at the Company's determination but no longer than 1 year. The returning customer must remain with the Company's Standard Generation Service for at least 1 year. ARIZONA PUBLIC SERVICE COMPANY Phoenix, Arizona Filed by: David J. Rumolo Title: Manager, Regulation and Pricing Page 3 of 5 A.C.C. No. XXXX Rate Schedule AG-l Original Effective: XXXX

laps Attachment J EXPERIMENTAL RATE RIDER SCHEDULE AG-l Page 4 of 5 ALTERNATIVE GENERATION GENERAL SERVICE All provisions, charges and adjustments in the customer's applicable retail rate schedule will continue to apply except as follows: 1. The generation charges will not apply; 2. Adjustment Schedule PSA-1will not apply, except that the Historical Component will apply for the first twelve months of service under this rate rider schedule; 3. Adjustment Schedule EIS will not apply; and 4. The applicable proportionate part of any taxes or governmental impositions which are or may in the future be assessed on the basis of gross revenues of the Company and/or the price or revenue from the electric energy or service sold and/or the volume of energy generated or purchased for sale and/or sold hereunder shall be applied to the customer's bill. Schedule AG-1 charges determined and billed by the Company include: 1. A monthly management fee of $0.00060 per kWh applied to the customer's metered kWh; 2. A monthly reserve capacity charge applied to 15% of the customer's billed kW (on-peak for Rate Schedules E-35 and E-32 TOU L) at the Company's applicable cost-based rate filed at the Federal Energy Regulatory Commission and revised from time to time, which is currently $6.985 per kW month; 3. An initial charge or credit for fuel hedging costs, as described herein; 4. Returning Customer charge, where applicable, as described herein; 5. Generation Service Provider Default charge, where applicable, as described herein. Schedule AG-1 Generation Service and Imbalance Service charges billed by the Company include: 1. Generation Service charges shall be charged at a rate within the minimum and maximum limits as follows: a. When the contract provides for pricing that reflects a specific index price, the minimum price will be the specified index minus 35% and the maximum price will be the specified index plus 35%. The determination that a contract is consistent with this provision will be based on the specified index price applicable on the date the contract is executed. b. When the contract provides for a fixed price supply for the term of the contract, the minimum price will be the generation rate of the Customer's applicable retail rate schedule minus 35%, and the maximum price shall be the generation rate of the Customers applicable retail schedule plus 35%. If the Customer has more than one otherwise applicable retail rate schedule, the highest applicable retail rate schedule will be used for purposes of the consistency determination. The determination that a contract is consistent with this provision will be based on the Customer's otherwise applicable retail rate schedule in effect on the date the contract is executed. c. Losses from the delivery point to the Customer's meters and any charges assessed by the Company on the Customer, including charges for transmission and distribution, Capacity Reservation Charge, the Management Fee, Imbalance Service charges, PSA balance and hedging costs, and Returning Customer Charges, shall not be included in the Generation Service charge for purposes of determining whether the contract is consistent with the minimum and maximum price provisions of this rate rider schedule. 2. Imbalance Service charges shall be charged at a rate greater than $0.00 per kWh and less than or equal to the rate that the Company charges the Generation Service Provider for Imbalance Service as specified herein. ARIZONA PUBLIC SERVICE COMPANY Phoenix, Arizona Filed by: David J. Rumolo Title: Manager, Regulation and Pricing Page 4 of 5 A.C.C. No. XXXX Rate Schedule AG-I Original Effective: XXXX

aps Attachment J EXPERIMENTAL RATE RIDER SCHEDULE AG-l Page 5 of 5 ALTERNATIVE GENERATION GENERAL SERVICE CONTRACT TERM AND REOUIREMENTS The term of the contract with the Generation Service Provider shall be for not less than one year and shall not exceed four years. The Generation Service Provider and Customer will enter into a contract or contracts with the Company, stating the pertinent details of the transaction with the Generation Service Provider, including but not limited to the scheduling of power, location of delivery and other terms related to the Company's management of the generation resource. CREDIT REQUIREMENTS A Generation Service Provider or its parent company must have at least an investment grade credit rating or demonstrate creditworthiness in the form of either a 3rd-party guarantee from an investment grade rated company, surety bond, letter of credit, or cash in accordance with the Company's standard credit support rules ARIZONA PUBLIC SERVICE COMPANY Phoenix, Arizona Filed by: David J. Rumolo Title: Manager, Regulation and Pricing Page 5 of 5 A.C.C. No. XXXX Rate Schedule AG- I Original Effective: XXXX

Base Rate Increase Arizona Public Service Company Summary of Rate Design Provisions Rate Case Settlement (Test Year 2010) Attachment K Page 1 of 16 • Settlement base rates shall reflect an overall retail revenue increase of $0.00 which is a %0.0 increase over test year revenues from base rates. • This includes a general non-fuel increase of $116,280,000, an additional non-fuel increase of $36,807,000 from transferring revenue requirements for the Renewable Energy Standard (“RES") to base rates, and a decrease in fuel costs recovered through base rates of $153,087,000. Rate Spread • The base rate impact for participating low-income customers will reflect a $1,535,000 reduction to compensate for the expected impact of removing their exemption to the Power Supply Adjustor (“PSA") and Demand Side Management Adjustor Clause (“DSMAC"). • This reduction in base rate revenue will be recovered from all other rate classes, allocated proportional to each class' present revenue. Street Lighting and Dusk to Dawn Lighting rate classes are excluded from this allocation. • The base rate impact for general service rate classes shall reflect a re-allocation of fuel costs within the general service revenue class, designed to better equalize the combined fuel impact on base rates and the PSA adjustor rate within the general service revenue class. This adjustment will not impact any other revenue class. General Issues • The unbundled transmission charge shall remain in base rates and not be transferred to the TCA adjustor rate. • The System Benefit Charge will be set at $0.002970 per kWh to reflect the cost of service, which includes the transfer of $36,807,000 in revenue requirements associated with Renewable Energy projects (see Attachment D of the proposed Settlement Agreement) from the RES to base rates. • APS shall prepare and file a rate plan as proposed by Staff to provide information on such issues as tiered conservation rates, time-of-use and other demand response rates, plans for cancelling rates, ideas for new rate offerings, and other relevant rate design issues. The timing of the plan will be revised in the Settlement. In addition, APS and Staff will identify current rate related compliance reports that can be consolidated into this rate plan. Residential Rates • Basic service charges shall be retained at their current rate levels. • Unbundled delivery charges for all residential rates shall be set at class cost of service level. • All other charges will be set to the level necessary to achieve the targeted base rate change for each rate class reflected in the Settlement Schedule H-2, attached to the Settlement Testimony of Charles A. Miessner. • Time of use rates shall maintain a similar ratio of on-peak to off-peak prices as approved by the Commission in the last general rate case, Decision No. 71448. • The existing optional Rate schedule ET-EV for off-peak charging of electric vehicles will be revised consistent with the revised time-of-use Rate Schedule ET-2.

Arizona Public Service Company Summary of Rate Design Provisions Rate Case Settlement (Test Year 2010) Attachment K Page 2 of 16 • Rate schedule PTR-RES, which is a new optional peak-time rebate program will be offered as proposed by APS. Low-Income Rates • The existing low-income rates will be consolidated with the corresponding non-low-income rate schedules. The low-income discounts will be increased to hold customers harmless (on-average) from this provision. • The low-income exemption from the PSA and the DSMAC will be cancelled. The low-income discounts will be increased to hold customers harmless (on-average) from this provision. • The current low income discount tier structure will be retained; the discount levels will be increased as provided above. General Service Rates • Basic service charges shall be retained at their current rate levels. • All other charges will be set to the level necessary to achieve the targeted base rate change for each rate class reflected in the Settlement Schedule H-2. • Contract minimum charges (or minimum bill provisions) shall be eliminated for general service Rate Schedules E-32 XS, E-32 S, E-32 M, E-32TOU XS, E-32 TOU S and E-32 TOU M. • Minimum bill provisions for Rate schedules E-32 L and E-32 TOU L will be revised to be more consistent with the corresponding provisions in extra-large general service Rate Schedules E-34 and E-3S, including a "ratchet" provision for the determination of monthly billing kW. • The bundled demand and energy charges for Rate Schedules E-32 L, E-34, and E-35 shall be revised from the levels provided in APS's Application in this matter to better reflect cost of service. Specifically, the demand charges shall be increased and the energy charges decreased from the initial proposed levels, but at a level that achieves the overall targeted revenue change for each of these rate classes. • Rate Rider Schedule E-54 for seasonal use shall continue to be available for customers served under "parent" Rate Schedules E-32 L and E-32 TOU L, but cancelled for other rates. • Rate Schedule E-30 for non- metered usage shall be revised to reflect the language clarification proposed by APS. • The new optional Rate Schedule IRR, interruptible service for extra-large general service customers, shall be offered as proposed by APS. • The new optional Experimental Rate Schedule AG-l, which offers a generation buy-through provision for a limited number of large and extra general service customers, shall be offered as developed by a collaborative group of interested parties, with concurrence by the parties to the Rate Settlement. Classified Rates • Charges will be set to the level necessary to achieve the targeted base rate change for each rate class reflected in the Settlement Schedule H-2. • Rate Rider Schedule SC-S (E-56R) for renewable partial requirement service shall be revised as proposed by APS.

Arizona Public Service Company Summary of Rate Design Provisions Rate Case Settlement (Test Year 2010) Attachment K Page 3 of 16 • The new optional Rate Rider Schedule E-36 M for medium size station use customers shall be offered as proposed by APS, except that it will be subject to the PSA adjustor rate. • Rate Schedules E-221 and E-221 8-T for water pumping service shall be revised as proposed by APS. • E-20 (house of worship) shall be unfrozen for one year from the effective date of new rates in this matter. • Area lighting rates shall be revised to reflect the new provisions as proposed by APS. • GPS riders (green power) shall be revised to eliminate the exemption to adjustor rates. Canceled Rates • The following rates and rate options will be canceled because they are no longer necessary or appropriate given other proposed rate design charges, or because they have very low (or no) participation. Cancellations include: E-40 (wind machine), Solar -2 (off grid), Solar -3, Share the lights area lighting rates E-114, E-1l6, E-145, E-129, E-53 (sports field lighting), and E-221 TOW option (time-of-week pricing option for water pumping). Service Schedules • Service Schedule 1 shall be revised as proposed by APS • The proposed optional Service Schedule 9 for economic development is withdrawn. Plans of Administration • The plans of administration for the PSA, DSMAC, Transmission Cost Adjustor ("TCA") and Environmental Improvement Surcharge ("EIS") will be revised to reflect the terms of the Settlement Agreement. • A new Lost Fixed Cost Recovery ("LFCR") plan of administration will be developed to reflect the terms of the Settlement Agreement. • The RES plan of administration will not be revised in this proceeding.

Attachment K

Page 4 of 16

Settlement Rate Summary for Residential Rates

	E-12			ET-1		ET-2			ECT-1R		ECT-2
Bundled Rates	Proposed		Bundled Rates	Proposed		Proposed		Bundled Rates	Proposed		Proposed
BSC $/day	$	0.285	BSC $/day	$	0.556	$	0.556	BSC $/day	$	0.556	$	0.556
Summer			Summer					Summer
First 400 kWh	$	0.09687	On-Peak kWh	$	0.17892	$	0.24477	On-Peak kW	$	13.550	$	13.500
Next 400 kWh	$	0.13817	Off-Peak kWh	$	0.05770	$	0.06118
Next 2200 kWh	$	0.16167	Winter					On-Peak kWh	$	0.07330	$	0.08867
Remaining kWh	$	0.17257	On-Peak kWh	$	0.14533	$	0.19847	Off-Peak kWh	$	0.04083	$	0.04417
Winter			Off-Peak kWh	$	0.05561	$	0.06116	Winter
All kWh	$	0.09417						On-Peak kW	$	9.400	$	9.300
Unbundled Rates			Unbundled Rates					On-Peak kWh	$	0.05587	$	0.05747
Generation Charge			Generation Charge					Off-Peak kWh	$	0.03967	$	0.04107
Summer			Summer
1st 400 kWh	$	0.06170	On-Peak kWh	$	0.14375	$	0.20960	Unbundled Rates
Next 400 kWh	$	0.10300	Off-Peak kWh	$	0.02253	$	0.02601	Generation Charge
Next 2200 kWh	$	0.12650	Winter					Summer
Additional kWh	$	0.13740	On-Peak kWh	$	0.11016	$	0.16330	On-Peak kW	$	9.650	9.000
Winter			Off-Peak kWh	$	0.02044	$	0.02599	On-Peak kWh	$	0.04973	0.06650
All kWh	$	0.05900						Off-Peak kWh	$	0.01726	0.02200
			Transmission Charge					Winter
Transmission Charge			kWh	$	0.00520	$	0.00520	On-Peak kW	$	7.100	6.900
kWh	$	0.00520						On-Peak kWh	$	0.03070	0.03340
			Delivery Charge					Off-Peak kWh	$	0.01450	0.01700
Delivery Charge			kWh	$	0.02700	$	0.02700
kWh	0.02700							Transmission Charge
			System Benefits Charge					kWh	$	0.00520	$	0.00520
System Benefits Charge			kWh	$	0.00297	$	0.00297
kWh	$	0.00297						Delivery Charge
			BSC $/day					Summer
BSC $/day			Customer Accounts	$	0.238	$	0.238	On-Peak kW	3.900		4.500
Customer Accounts	$	0.063	Metering	$	0.186	$	0.186	On-Peak kWh	0.01540		0.01400
Metering	$	0.090	Billing	$	0.070	$	0.070	Winter
Billing	$	0.070	Meter Reading	$	0.062	$	0.062	On-Peak kW	2.300		2.400
Meter Reading	$	0.062	BCS Total	$	0.556	$	0.556	On-Peak kWh	0.01700		0.01590
BCS Total	$	0.285
								System Benefits Charge
								kWh	$	0.00297	$	0.00297
								BSC $/day
								Customer Accounts	$	0.238	0.238
								Metering	$	0.186	0.186
								Billing	$	0.070	0.070
								Meter Reading	$	0.062	0.062
								BCS Total	$	0.556	0.556

Attachment K

Page 5 of 16

Settlement Rate Summary for Residential Rates

	ET-SP			ET-EV		CPP-RES				PTR-RES
Bundled Rates	Proposed		Bundled Rates	Proposed		Proposed				Proposed
BSC $/day	$	0.556	BSC $/day	0.556	kWh charge	$	0.250000		kWh Rebate	$	0.25000
Summer Peak			Summer		kWh discount	$	(0.012143	)
Super Peak kWh	$	0.46517	Super Off-Peak kWh	0.04195
On-Peak kWh	$	0.24477	On-Peak kWh	0.24784
Off-Peak kWh	$	0.05517	Off-Peak kWh	0.06460
Summer			Winter
On-Peak kWh	$	0.24477	Super Off-Peak kWh	0.04195
Off-Peak kWh	$	0.05517	On-Peak kWh	0.20165
Winter			Off-Peak kWh	0.06460
On-Peak kWh	$	0.19847
Off-Peak kWh	$	0.05517
Unbundled Rates
Generation Charge
Summer Peak
Super Peak kWh	0.43000
On-Peak kWh	0.20960
Off-Peak kWh	0.02000
Summer
On-Peak kWh	0.20960
Off-Peak kWh	0.02000
Winter
On-Peak kWh	0.16330
Off-Peak kWh	0.02000
Transmission Charge
kWh	$	0.00520
Delivery Charge
Super Peak
kWh	0.02700
Summer
kWh	0.02700
Winter
kWh	0.02700
System Benefits Charge
Summer kWh	$	0.00297
BCS $/day
Customer Accounts	0.238
Metering	0.186
Billing	0.070
Meter Reading	0.062
BCS Total	0.556

Attachment K

Page 6 of 16

Settlement Rate Summary for General Service Rates

	E-30			E-32 XS			E-32 S		E-32 M
	Proposed		Bundled Rates	Proposed		Bundled Rates	Proposed		Proposed
Bundled Rates			BSC $/day			BSC $/day
Summer			Self-Contained	$	0.672	Self-Contained	$	0.672	$	0.672
BSC $/day	$	0.311	Instrument-Rated	$	1.324	Instrument-Rated	$	1.324	$	1.324
Energy Charge	$	0.14455	Primary Voltage	$	3.415	Primary Voltage	$	3.415	$	3.415
Winter			Transmission Voltage	$	26.163	Transmission Voltage	$	26.163	$	26.163
BSC $/day	$	0.311
Energy Charge	$	0.12984	Energy Charge			Demand Charge
			Summer			1st 100 kW (Secondary)	$	9.828	$	10.235
Unbundled Rates			KWh (1st 5000 / mo.) (Secondary)	$	0.13537	Over 100 kW (Secondary)	$	5.214	$	5.385
Summer			KWh (over 5000 / mo.) (Secondary)	$	0.07427	lst 100 kW (Primary)	$	9.116	$	9.488
BSC $/day	$	0.243	kWh (1st 5000 / mo.) (Primary)	$	0.13209	Over kW (Primary)	$	4.502	$	4.695
Billing	$	0.068	kWh (over 5000 / mo.) (Primary)	$	0.07100	lst 100 kW (Transmission)	$	7.101	$	7.368
Systems Benefits	$	0.00297	Winter			Over kW (Transmission)	$	2.487	$	2.519
Transmission	$	0.00424	kWh (1st 5000 / mo.) (Secondary)	$	0.11769
Delivery	$	0.05032	kWh (over 5000/ mo.) (Secondary)	$	0.05658	Energy Charge
Generation kWh	$	0.08702	kWh (1st 5000 /mo.) (Primary)	$	0.11438	Summer
Winter			kWh (over 5000 / mo.) (Primary)	$	0.05329	1st 200 kWh/kW	$	0.10337	$	0.09884
BSC $/day	$	0.243				over 200 kWh/kW	$	0.06257	$	0.06091
Billing	$	0.068	Unbundled Rates			Winter
Systems Benefits	$	0.00297	Generation Charge			1st 200 kWh/kW	$	0.08718	$	0.08378
Transmission	$	0.00424	Summer			over 200 kWh/kW	$	0.04638	$	0.04586
Delivery	$	0.05032	kWh (1st 5000 / mo.)	$	0.08641
Generation kWh	$	0.07231	kWh (over 5000/ mo.)	$	0.05396	Unbundled Rates
			Winter			Generation Charge
			kWh (1st 5000 / mo.)	$	0.06880	Summer
			kWh (over 5000 / mo.)	$	0.03634	1st 200 kWh/kW	$	0.09617	$	0.08938
						over 200 kWh/kW	$	0.05537	$	0.05145
			System Benefits Charge			Winter
			kWh	$	0.00297	1st 200 kWh/kW	$	0.07998	$	0.07432
						over 200 kWh/kW	$	0.03918	$	0.03640
			Transmission Charge
			kWh	$	0.00424	System Benefits Charge
						kWh	$	0.00297	$	0.00297
			Delivery Charge
			Summer			Transmission Charge
			Delivery (1st 5000 kWh per mo.) (Secondary)	$	0.04175	kW	$	1.585	$	1.585
			Delivery (over 5000 kWh per mo.) (Secondary)	$	0.01310
			Delivery (1st 5000 kWh per mo.) (Primary)	$	0.03847	Delivery Charge
			Delivery (over 5000 kWh per mo.) (Primary)	$	0.00983	Delivery 1st 100 kW (Secondary)	$	8.243	$	8.650
			Winter			Delivery All Addl kW (Secondary)	$	3.629	$	3.800
			Delivery (1st 5000 kWh per mo.) (Secondary)	$	0.04168
			Delivery (over 5000 kWh per mo.) (Secondary)	$	0.01303	Delivery 1st 100 kW (primary)	$	7.531	$	7.903
			Delivery (1st 5000 kWh per mo.) (Primary)	$	0.03837	Delivery All Addl kW (Primary)	$	2.917	$	3.110
			Delivery (over 5000 kWh per mo.) (Primary)	$	0.00974
						Delivery 1st 100 kW (Transmission)	$	5.516	$	5.783
			BSC $/day			Delivery All Addl kW (Transmission)	$	0.902	$	0.934
			BSC Self-Contained	$	0.126
			BSC Instrument-Rated	$	0.126	Delivery - All kWh	0.00423		0.00649
			BSC Primary Voltage	$	0.126
			BSC Transmission Voltage	$	0.126	BSC $/day
						BSC Self-Contained	$	0.126	$	0.126
			Revenue Cycle $/day			BSC Instrument-Rated	$	0.126	$	0.126
			Metering Self-Contained	$	0.403	BSC Primary Voltage	$	0.126	$	0.126
			Metering Instrument-Rated	$	1.055	BSC Transmission Voltage	$	0.126	$	0.126
			Metering Primary	$	3.146
			Metering (Transmission)	$	25.894	Revenue Cycle $/day
			Billing	$	0.075	Metering Self-Contained	$	0.403	$	0.403
			Meter Reading	$	0.068	Metering Instrument-Rated	$	1.055	$	1.055
						Metering Primary	$	3.146	$	3.146
						Metering (Transmission)	$	25.894	$	25.894
						Billing	$	0.075	$	0.075
						Meter Reading	$	0.068	$	0.068

Attachment K

Page 7 of 16

Settlement Rate Summary for General Service Rates

	E-32 L			E-32 XS TOU
Bundled Rates	Proposed		Bundled Rates	Proposed
BSC $/day			BSC $/day
Self-Contained	$	1.068	Self-Contained	$	0.710
Instrument-Rated	$	1.627	Instrument-Rated	$	1.324
Primary Voltage	$	3.419	Primary Voltage	$	3.415
Transmission Voltage	$	22.915	Transmission Voltage	$	26.163
Demand Charge			Energy Charge - Summer
1st 100 kW (Secondary)	$	21.149	Secondary Service
Over 100 kW (Secondary)	$	14.267	On Peak kWh (1st 5000 / mo.)	$	0.17033
1st 100 kW (Primary)	$	19.091	All additional kWh	$	0.08564
Over kW (Primary)	$	13.209	OffPeak kWh (1st 5000 / mo.)	$	0.12686
1st 100 kW (Transmission)	$	14.284	All additional kWh	$	0.04755
Over kW (Transmission)	$	9.105	Primary Service
			On Peak kWh (1st 5000 / mo.)	$	0.16698
Energy Charge			All additional kWh	$	0.08150
Summer			Off Peak kWh (1st 5000 / mo.)	$	0.12350
kWh	$	0.05517	All additional kWh	$	0.04420
			Energy Charge - Winter
Winter			Secondary Service
kWh	$	0.03804	On Pk kWh (1st 5000 / mo.)	$	0.15310
			All additional kWh	$	0.06837
Unbundled Rates			Off Peak kWh (1st 5000 / mo.)	$	0.10959
Generation Charge			All additional kWh	$	0.03496
Summer			Primary Service
kWh	$	0.05209	On Peak kWh (1st 5000/ mo.)	$	0.14974
			All additional kWh	$	0.06423
Winter			Off Peak kWh (1st 5000/ mo.)	$	0.10624
kWh	$	0.03496	All additional kWh	$	0.03160
kW	$	4.496
			Unbundled Rates
System Benefits Charge			Basic Service Charge	$	0.126
kWh	$	0.00297	Self Contained (per day)	$	0.441
			Instrument-Rated	$	1.055
Transmission Charge			Primary Voltage	$	3.146
kW	$	1.585	Transmission Voltage	$	25.894
			Meter Reading	$	0.068
Delivery Charge			Billing	$	0.075
Delivery 1st 100 kW (Secondary)	$	15.068
Delivery All Addl kW (Secondary)	$	8.186	System Benefits Charge
			kWh	$	0.00297
Delivery 1st 100 kW (Primary)	$	13.010
Delivery All Addl kW (Primary)	$	7.128	Transmission Charge
			kWh	$	0.00424
Delivery 1st 100 kW (Transmission)	$	8.203
Delivery All Addl kW (Transmission)	$	3.024	Delivery Charge
			Secondary Service
Delivery - All kWh	$	0.00011	Delivery On Peak (1st 5000 kWh per mo.)	$	0.05065
			Delivery all additional kWh	$	0.01316
BSC $/day			Delivery Off Peak (1st 5000 kWh per mo.)	$	0.04174
BSC Self-Contained	$	0.601	Delivery all additional kWh	$	0.00962
BSC Instrument-Rated	$	0.601	Primary
BSC Primary Voltage	$	0.601	Delivery On Peak (1st 5000 kWh per mo.)	$	0.04730
BSC Transmission Voltage	$	0.601	Delivery all additional kWh	$	0.00902
			Delivery Off Peak (1st 5000 kWh per mo.)	$	0.03838
Revenue Cycle $/day			Delivery all additional kWh	$	0.00627
Metering (self-contained)	$	0.345	Winter
Metering (instrument-rated)	$	0.904	Secondary
Metering (primary)	$	2.696	Delivery On Peak (1st 5000 kWh per mo.)	$	0.05057
Metering (transmission)	$	22.192	Delivery all additional kWh	$	0.01304
Billing	$	0.064	Delivery Off Peak (1st 5000 kWh per mo.)	$	0.04164
Meter Reading	$	0.058	Delivery all additional kWh	$	0.00954
			Primary
			Delivery On Peak (1st 5000 kWh per mo.)	$	0.04721
			Delivery all additional kWh	$	0.00890
			Delivery Off Peak (1st 5000 kWh per mo.)	$	0.03829
			Delivery all additional kWh	$	0.00618
			Generation Charge
			Summer
			On Peak (1st 5000 kWh per mo.)	$	0.11247
			On Peak all additional kWh	$	0.06527
			Off Peak (1st 5000 kWh per mo.)	$	0.07791
			Off Peak all additional kWh	$	0.03072
			Winter
			On Peak (1st 5000 kWh per mo.)	$	0.09532
			On Peak all additional kWh	$	0.04812
			Off Peak (1st 5000 kWh per mo.)	$	0.06074
			Off Peak all additional kWh	$	0.01821

Attachment K

Page 8 of 16

Settlement Rate Summary for General Service Rates

	E-32 S TOU		E-32 M TOU		E-32 L TOU			E-34
Bundled Rates	Proposed		Proposed		Proposed		Bundled Rates	Proposed
BSC $/day							BSC $/day
Self-Contained	$	0.710	$	0.710	$	0.710	Self-Contained	$	1.135
Instrument-Rated	$	1.324	$	1.324	$	1.324	Instrument-Rated	$	1.776
Primary Voltage	$	3.415	$	3.415	$	3.415	Primary Voltage	$	3.828
Transmission Voltage	$	26.163	$	26.163	$	26.163	Transmission Voltage	$	26.161
Demand Charge							Demand Charge
Secondary Service							Secondary Service	$	19.930
On Peak 1st 100 kW	$	14.303	$	15.166	$	14.915	Primary Service	$	18.649
On Peak all additional kW	$	9.713	$	10.013	$	9.784	Transmission Service	$	12.278
Off Peak 1st 100 kW	$	5.484	$	5.897	$	5.814	Primary Substation - Military Base	$	13.392
Off Peak all additional kW	$	3.054	$	3.168	$	3.097
Primary Service							Energy Charge	$	0.03665
On Peak 1st 100 kW	$	13.845	$	14.651	$	14.402
On Peak all additional kW	$	9.645	$	9.936	$	9.708	Unbundled Rates
Off Peak 1st 100 kW	$	4.909	$	5.251	$	5.170	BSC $/day	$	0.601
Off Peak all additional kW	$	2.975	$	3.079	$	3.008
Transmission Service							Metering per day
On Peak 1st 100 kW	$	12.208	$	13.730	$	13.486	Self-Contained	$	0.395
On Peak all additional kW	$	9.038	$	9.619	$	8.601	Instrument-Rated	$	1.036
Off Peak 1st 100 kW	$	4.042	$	4.522	$	4.444	Primary Voltage	$	3.088
Off Peak all additional kW	$	2.837	$	2.959	$	2.888	Transmission Voltage	$	25.421
							Meter Reading	$	0.066
Energy Charge - Summer							Billing	$	0.073
On Peak kWh	$	0.07367	$	0.06566	$	0.06555
Off Peak kWh	$	0.05873	$	0.05432	$	0.05359	System Benefits Charge
Energy Cbarge - Winter							kWh	$	0.00297
On Peak kWh	$	0.05665	$	0.05275	$	0.05193
Off Peak kWh	$	0.04170	$	0.04142	$	0.03997	Transmission Charge
							kW	$	1.776
Unbundled Rates
Basic Service Charge	$	0.126	$	0.126	$	0.126	Delivery Charge
Self-Contained	$	0.441	$	0.441	$	0.441	Secondary Service	$	8.027
Instrument-Rated	$	1.055	$	1.055	$	1.055	Primary Service	$	6.746
Primary Voltage	$	3.146	$	3.146	$	3.146	Transmission Service	$	0.375
Transmission Voltage	$	25.894	$	25.894	$	25.894	Primary Substation -Military Base	$	1.489
Meter Reading	$	0.068	$	0.068	$	0.068
Billing	$	0.075	$	0.075	$	0.075	Generation Charge
							kW	$	10.127
System Benefits Charge							kWh	$	0.03368
kWh	$	0.00297	$	0.00297	$	0.00297
Transmission Charge
kW	$	1.585	$	1.585	$	1.585
Delivery Charge
Secondary Service
On Peak 1st 100 kW	$	5.775	$	8.318	$	7.776
On Peak all additional kW	$	1.185	$	3.165	$	2.645
Off Peak 1st 100 kW	$	2.842	$	3.894	$	3.701
Off Peak all additional kW	$	0.412	$	1.165	$	0.984
per kWh	$	—	$	0.00910	$	0.00607
Primary
On Peak 1st 100 kW	$	5.317	$	7.803	$	7.263
On Peak all additional kW	$	1.117	$	3.088	$	2.569
Off Peak 1st 100 kW	$	2.267	$	3.248	$	3.057
Off Peak all additional kW	$	0.333	$	1.076	$	0.895
per kWh	$	—	$	0.00910	$	0.00607
Transmission
On Peak 1st 100 kW	$	3.680	$	6.882	$	6.347
On Peak all additional kW	$	0.510	$	2.771	$	1.462
Off Peak 1st 100 kW	$	1.400	$	2.519	$	2.331
Off Peak all additional kW	$	0.195	$	0.956	$	0.775
per kWh	$	—	$	0.00910	$	0.00607
Generation Charge
Summer
On Peak kW	$	6.943	$	5.263	$	5.554
Off Peak kW	$	2.642	$	2.003	$	2.113
On Peak kWh	$	0.07070	$	0.05359	$	0.05651
Off Peak kWh	$	0.05576	$	0.04225	$	0.04455
Winter
On Peak kW	$	6.943	$	5.263	$	5.554
Off Peak kW	$	2.642	$	2.003	$	2.113
On Peak kWh	$	0.05368	$	0.04068	$	0.04289
Off Peak kWh	$	0.03873	$	0.02935	$	0.03093

Attachment K

Page 9 of 16

Settlement Rate Summary for General Service Rates

	E-35						Interruptible Rate Ride (IRR)
Bundled Rates	Proposed			E-54			Proposed
BSC $/day			Minimum 12-Month Charge	$	603.49	1 Yr Agreement
Self-Contained	$	1.183				Option 1	30 Minute ($/kW-Yr)	$	7.975
Instrument-Rated	$	1.795				(4 hrs)	30 Minute ($/kWh)	$	0.09969
Primary Voltage	$	3.881					2 Hour ($/kW-Yr)	$	7.178
Transmission Voltage	$	26.574					2 Hour ($/kWh)	$	0.08972
						Option 2	30 Minute ($/kW-Yr)	$	5.995
Demand Charge						(8 hrs)	30 Minute ($/kWh)	$	0.07493
Secondary Service							2 Hour ($/kW-Yr)	$	5.395
On-Peak	$	16.768					2 Hour ($/kWh)	$	0.06745
Off-Peak	$	3.064
Primary Service						5 Yr Agreement
On-Peak	$	15.792				Option1	30 Minute ($/kW-Yr)	$	9.882
Off-Peak	$	2.966				(4 hrs)	30 Minute ($/kWh)	$	0.12353
Transmission Service							2 Hour ($/kW-Yr)	$	8.894
On-Peak	$	10.755					2 Hour ($/kWh)	$	0.11117
Off-Peak	$	2.462				Option 2	30 Minute ($/kW-Yr)	$	7.428
Primary Substation - Military Base						(8 hrs)	30 Minute ($/kWh)	$	0.09285
On-Peak	$	12.108					2 Hour ($/kW-Yr)	$	6.685
Off-Peak	$	2.597					2 Hour ($/kWh)	$	0.08356
Energy Charge
On-Peak	$	0.04076
Off-Peak	$	0.03219
Unbundled Rates
BSC $/day	$	0.601
Revenue Cycle Service Charges
Self-Contained	$	0.440
Instrument-Rated	$	1.052
Primary Voltage	$	3.138
Transmission Voltage	$	25.831
Meter Reading	$	0.068
Billing	$	0.074
System Benefits Charge
kWh	$	0.00297
Transmission Charge
On-Peak kW	$	1.776
Delivery Charge
Secondary Service
On-Peak	$	6.461
Off-Peak	$	0.646
Primary Service
On-Peak	$	5.485
Off-Peak	$	0.548
Transmission Service
On-Peak	$	0.448
Off-Peak	$	0.044
Primary Substation - Military Base
On-Peak	$	1.801
Off-Peak	$	0.179
Generation Charge
On-Peak kW	$	8.531
Off-Peak kW	$	2.418
On-Peak kWh	$	0.03779
Off-Peak kWh	$	0.02922

Attachment K

Page 10 of 16

Settlement Rate Summary for Classified Rates

	E-20			E-36 M				E-36 XL
	Proposed			Proposed				Proposed
Bundled Rates			Unbundled Basic Service Charge:
Summer			For E-32 M and E-32L				BSC	$	6.912	monthly
BSC $/day	$	1.065	Self-Contained Meters	$	1.344	per day, or	Secondary	$	3.605	$/kW
On-peak Demand	$	2.391	Instrument-Rated Meters	$	1.322	per day, or	Primary	$	3.423	$/kW
Excess Demand	$	1.196	Primary Voltage Meters	$	6.830	per day	Transmission	$	0.035	$/kW
On-peak kWh	$	0.14457
Off-peak kWh	$	0.07014	Revenue Cycle Service Charges:				Power Supply
Winter			Metering:				Uplift Charge	$	0.00057	kWh
BSC $/day	$	1.065	E-32 XS				(plus hourly pricing proxy)
On-peak Demand	$	2.156	Self-Contained Meters	$	0.403	per day, or
Excess Demand	$	1.078	Instrument-Rated Meters	$	1.055	per day, or
On-peak kWh	$	0.12719	Primary Voltage Meters:	$	3.146	per day
Off-peak kWh	$	0.06294	Meter Reading	$	0.068	per day
			Billing	$	0.075	per day
			E-32 L
			Self-Contained Meters	$	0.345	per day, or
			Instrument-Rated Meters	$	0.904	per day, or
			Primary Voltage Meters	$	2.696	per day, or
			Transmission	$	22.192	per day
			Meter Reading	$	0.058	per day
			Billing	$	0.064	per day

Attachment K

Page 11 of 16

Settlement Rate Summary for Classified Rates

Company Owned	E-47		Customer Owned	E-47		Company Owned	E-47
Fixture Type	Proposed		Lamp Type	Proposed		Pole Type	Proposed
9500 HPS ACORN	$	27.06	9500 HPS ACORN	$	9.22	Anchor Flush, Round, 1X, 12ft	$	12.17
16,000 HPS ACORN	$	30.04	16,000 HPS ACORN	$	11.65	Anchor Flush, Round, 1X, 22ft	$	13.70
9500 HPS ARCHITECTURAL	$	15.38	9500 HPS ARCHITECTURAL	$	7.34	Anchor Flush, Round, 1X, 25ft	$	14.82
16,000 HPS ARCHITECTURAL	$	17.96	16,000 HPS ARCHITECTURAL	$	9.82	Anchor Flush, Round, 1X, 30ft	$	17.03
30,000 HPS ARCHITECTURAL	$	21.31	30,000 HPS ARCHITECTURAL	$	12.60	Anchor Flush, Round, 1X, 32ft	$	17.89
50,000 HPS ARCHITECTURAL	$	26.29	50,000 HPS ARCHITECTURAL	$	18.13	Anchor Flush, Round, 2X, 12ft	$	12.98
14,000 MH ARCHITECTURAL	$	21.51	14,000 MH ARCHITECTURAL	$	11.79	Anchor Flush, Round, 2X, 22ft	$	14.91
21,000 MH ARCHITECTURAL	$	24.42	21,000 MH ARCHITECTURAL	$	14.54	Anchor Flush, Round, 2X, 25ft	$	15.55
36,000 MH ARCHITECTURAL	$	30.54	36,000 MH ARCHITECTURAL	$	20.00	Anchor Flush, Round, 2X, 30ft	$	18.07
8,000 LPS ARCHITECTURAL	$	22.35	8,000 LPS ARCHITECTURAL	$	9.82	Anchor Flush, Round, 2X, 32ft	$	19.28
13500 LPS ARCHITECTURAL	$	26.36	13500 LPS ARCHITECTURAL	$	11.84	Anchor Flush, Square, 5”, 13ft	$	13.95
22,500 LPS ARCHITECTURAL	$	30.11	22,500 LPS ARCHITECTURAL	$	14.45	Anchor Flush, Square, 5”, 15ft	$	12.47
33,000 LPS ARCHITECTURAL	$	36.22	33,000 LPS ARCHITECTURAL	$	17.02	Anchor Flush, Square, 5”, 23ft	$	14.79
5800 HPS COBRA/ROADWAY	$	8.73	5800 HPS COBRA/ROADWAY	$	5.16	Anchor Flush, Square, 5”, 25ft	$	16.26
9500 HPS COBRA/ROADWAY	$	10.28	9500 HPS COBRA/ROADWAY	$	6.32	Anchor Flush, Square, 5”, 28ft	$	18.05
16,000 HPS COBRA/ROADWAY	$	12.87	16,000 HPS COBRA/ROADWAY	$	8.82	Anchor Flush, Square, 5”, 32ft	$	17.95
30,000 HPS COBRA/ROADWAY	$	15.52	30,000 HPS COBRA/ROADWAY	$	11.46	Anchor Flush, Concrete, 12ft	$	41.58
50,000 HPS COBRA/ROADWAY	$	21.06	50,000 HPS COBRA/ROADWAY	$	16.37	Anchor Flush, Fiberglass, 12ft	$	35.21
14,000 MH COBRA/ROADWAY	$	14.97	14,000 MH COBRA/ROADWAY	$	10.20	Anchor Flush, Dec Transit Ped, 4”, 16ft	$	34.33
21,000 MH COBRA/ROADWAY	$	17.49	21,000 MH COBRA/ROADWAY	$	12.69	Anchor Flush, Dec Transit, 6”, 30ft	$	66.28
36,000 MH COBRA/ROADWAY	$	23.03	36,000 MH COBRA/ROADWAY	$	17.63	Anchor Pedstl, Round, 1X,12ft	$	11.71
8,000 FL COBRA/ROADWAY	$	17.20	8,000 FL COBRA/ROADWAY	$	5.04	Anchor Pedstl, Round, 1X,22ft	$	13.24
9500 HPS DECORATIVE TRANSIT	$	37.09	9500 HPS DECORATIVE TRANSIT	$	11.11	Anchor Pedstl, Round, 1X, 25ft	$	14.35
16,000 HPS DECORATIVE TRANSIT	$	36.88	16,000 HPS DECORATIVE TRANSIT	$	6.31	Anchor Pedstl, Round, 1X, 30ft	$	16.58
30,000 HPS DECORATIVE TRANSIT	$	42.46	30,000 HPS DECORATIVE TRANSIT	$	16.02	Anchor Pedstl, Round, 1X, 32ft	$	17.41
30,000 HPS FLOOD	$	20.61	30,000 HPS FLOOD	$	12.81	Anchor Pedstl, Round, 2X, 12ft	$	12.51
50,000 HPS FLOOD	$	25.56	50,000 HPS FLOOD	$	17.77	Anchor Pedstl, Round, 2X, 22ft	$	13.97
21,000 MH FLOOD	$	22.00	21,000 MH FLOOD	$	13.53	Anchor Pedstl, Round, 2X, 25ft	$	15.08
36,000 MH FLOOD	$	26.82	36,000 MH FLOOD	$	18.35	Anchor Pedstl, Round, 2X, 30ft	$	17.61
8,000 FL COLONIAL GRAY POST TOP	$	18.54	8,000 FL COLONIAL GRAY POST TOP	$	5.23	Anchor Pedstl, Round, 2X,32ft	$	18.81
9500 HPS COLONIAL GRAY POST TOP	$	10.60	9500 HPS COLONIAL GRAY POST TOP	$	6.65	Anchor Pedstl, Round, 3 Bolt, 32ft	$	21.62
9500 HPS COLONIAL BLACK POST TOP	$	12.21	9500 HPS COLONIAL BLACK POST TOP	$	6.88	Anchor Pedstl, Square, 5”, 13ft	$	13.50
9500 HPS DECORATIVE POST TOP	$	32.47	9500 HPS DECORATIVE POST TOP	$	10.24	Anchor Pedstl, Square, 5”, 15ft	$	13.80
4,000 INC FROZEN	$	9.78	4,000 INC FROZEN	$	5.47	Anchor Pedstl, Square, 5”, 23ft	$	14.32
7,000 MV FROZEN	$	12.67	7,000 MV FROZEN	$	7.27	Anchor Pedstl, Square, 5”, 25ft	$	15.80
20,000 MV FROZEN	$	24.92	20,000 MV FROZEN	$	14.12	Anchor Pedstl, Square, 5”, 28ft	$	17.56
BRACKETS FROZEN	$	1.72	BRACKETS FROZEN	$	—	Anchor Pedstl, Square, 5”, 32ft	$	18.23
						Direct Bury, Round, 19ft	$	18.42
Trip Charge per Lamp	$	100.00	Trip Charge per Lamp	$	100.00	Direct Bury, Round, 30ft	$	14.38
						Direct Bury, Round, 38ft	$	17.55
						Direct Bury, Self-Support, 40ft	$	21.62
						Direct Bury, Stepped, 49ft	$	64.99
						Direct Bury, Square, 4”, 34ft	$	15.87
						Direct Bury, Square, 5”, 20ft	$	15.07
						Direct Bury, Square, 5” 30ft	$	15.71
						Direct Bury, Square, 5” 38ft	$	17.05
						Deecorative Transit 41-6	$	20.47
						Deecorative Transit 47	$	25.50
						Direct Bury, Steel Dist Pole, 35ft	$	23.54
						Post Top, Dec Transit, 16ft	$	35.07
						Post Top, Gray Steel/Fiberglass, 23ft	$	12.16
						Post Top, Black Steel, 23ft	$	13.41
						FROZEN, Wood Poles, 30ft	$	8.95
						FROZEN, Wood Poles, 35ft	$	8.95
						FROZEN, Wood Poles, 40ft	$	12.73
						Flush, 4ft	$	9.91
						Flush, 6ft	$	11.82
						Pedestal, 8ft	$	13.54
						Pedestal, 32’ round steel pole, 4ft 6”	$	9.39
						1. 100’ OH, UG if conduit by customer	$	3.50
						2. HPS not accessible by bucket	$	2.80
						3. MH not accessible by bucket	$	6.04

Attachment K

Page 12 of 16

Settlement Rate Summary for Classified Rates

	E-56			Company Owned	E-58		Customer Owned	E-58
	Proposed			Lamp Type	Proposed		Lamp Type	Proposed
Back-up Power				9500 HPS ACORN	$	27.06	9500 HPS ACORN	$	9.22
Rate Schedule E-34 Customer	$	0.590	Per kW day	16,000 HPS ACORN	$	30.04	16,000 HPS ACORN	$	11.65
Rate Schedule E-32 L Customer	$	0.120	per kW day	9500 HPS ARCHITECTURAL	$	15.38	9500 HPS ARCHITECTURAL	$	7.34
				16,000 HPS ARCHITECTURAL	$	17.96	16,000 HPS ARCHITECTURAL	$	9.82
Excess Power Charges				30,000 HPS ARCHITECTURAL	$	21.31	30,000 HPS ARCHITECTURAL	$	12.60
Secondary Service:	$	54.802	per kW	50,000 HPS ARCHITECTURAL	$	26.29	50,000 HPS ARCHITECTURAL	$	18.13
Primary Service:	$	52.019	per kW	14,000 MH ARCHITECTURAL	$	21.51	14,000 MH ARCHITECTURAL	$	11.79
Transmission Service:	$	38.187	per kW	21,000 MH ARCHITECTURAL	$	24.42	21,000 MH ARCHITECTURAL	$	14.54
				36,000 MH ARCHITECTURAL	$	30.54	36,000 MH ARCHITECTURAL	$	20.00
				8,000 LPS ARCHITECTURAL	$	22.35	8,000 LPS ARCHITECTURAL	$	9.82
				13500 LPS ARCHITECTURAL	$	26.36	13500 LPS ARCHITECTURAL	$	11.84
				22,500 LPS ARCHITECTURAL	$	30.11	22,500 LPS ARCHITECTURAL	$	14.45
				33,000 LPS ARCHITECTURAL	$	36.22	33,000 LPS ARCHITECTURAL	$	17.02
				5800 HPS COBRA/ROADWAY	$	8.73	5800 HPS COBRA/ROADWAY	$	5.16
				9500 HPS COBRA/ROADWAY	$	10.28	9500 HPS COBRA/ROADWAY	$	6.32
				16,000 HPS COBRA/ROADWAY	$	12.87	16,000 HPS COBRA/ROADWAY	$	8.82
				30,000 HPS COBRA/ROADWAY	$	15.52	30,000 HPS COBRA/ROADWAY	$	11.46
				50,000 HPS COBRA/ROADWAY	$	21.06	50,000 HPS COBRA/ROADWAY	$	16.37
				14,000 MH COBRA/ROADWAY	$	14.97	14,000 MH COBRA/ROADWAY	$	10.20
				21,000 MH COBRA/ROADWAY	$	17.49	21,000 MH COBRA/ROADWAY	$	12.69
				36,000 MH COBRA/ROADWAY	$	23.03	36,000 MH COBRA/ROADWAY	$	17.63
				8,000 FL COBRA/ROADWAY	$	17.20	8,000 FL COBRA/ROADWAY	$	5.04
				9500 HPS DECORATIVE TRANSIT	$	37.09	9500 HPS DECORATIVE TRANSIT	$	11.11
				16,000 HPS DECORATIVE TRANSIT	$	36.88	16,000 HPS DECORATIVE TRANSIT	$	12.41
				30,000 HPS DECORATIVE TRANSIT	$	42.46	30,000 HPS DECORATIVE TRANSIT	$	16.02
				30,000 HPS FLOOD	$	20.61	30,000 HPS FLOOD	$	12.81
				50,000 HPS FLOOD	$	25.56	50,000 HPS FLOOD	$	17.77
				21,000 MH FLOOD	$	22.00	21,000 MH FLOOD	$	13.53
				36,000 MH FLOOD	$	26.82	36,000 MH FLOOD	$	18.35
				8,000 FL COLONIAL GRAY POST TOP	$	18.54	8,000 FL COLONIAL GRAY POST TOP	$	5.23
				9500 HPS COLONIAL GRAY POST TOP	$	10.60	9500 HPS COLONIAL GRAY POST TOP	$	6.65
				9500 HPS COLONIAL BLACK POST TOP	$	12.21	9500 HPS COLONIAL BLACK POST TOP	$	6.88
				9500 HPS DECORATIVE POST TOP	$	32.47	9500 HPS DECORATIVE POST TOP	$	10.24
				4,000 INC FROZEN	$	9.78	4,000 INC FROZEN	$	5.47
				7,000 MV FROZEN	$	12.67	7,000 MV FROZEN	$	7.27
				11,000 MV FROZEN	$	15.87	11,000 MV FROZEN	$	9.68
				20,000 MV FROZEN	$	24.92	20,000 MV FROZEN	$	14.12
				Trip Charge per Lamp	$	100.00	Trip Charge per Lamp	$	100.00

Attachment K

Page 13 of 16

Settlement Rate Summary for Classified Rates

Company Owned	E-58		Customer Owned	E-58			Proposed		Transmission
Pole Type	Proposed		Pole Type	Proposed		E-59	Service		Proposed
Anchor Flush, Round, 1X, 12ft	$	12.17	Anchor Flush, Round, 1X, 12ft	$	1.68		Charge		Charge
Anchor Flush, Round, 1X, 22ft	$	13.70	Anchor Flush, Round, 1X, 22ft	$	1.88	TYPE	Per Lamp		Per kWh
Anchor Flush, Round, 1X, 25ft	$	14.82	Anchor Flush, Round, 1X, 25ft	$	2.05	1000 INC	$	2.79	$	0.06088
Anchor Flush. Round, 1X, 30ft	$	17.03	Anchor Flush, Round, 1X, 30ft	$	2.34	11000 MV	$	2.79	$	0.06088
Anchor Flush, Round, 1X, 32ft	$	17.89	Anchor Flush, Round, 1X, 32ft	$	2.37	13500L LPS ARCH	$	2.79	$	0.06088
Anchor Flush, Round, 2X, 12ft	$	12.98	Anchor Flush, Round, 2X, 12ft	$	1.79	14000L MH ARCH	$	2.79	$	0.06088
Anchor Flush, Round, 2X, 22ft	$	14.91	Anchor Flush, Round, 2X, 22ft	$	2.06	14000L MH ROADWAY	$	2.79	$	0.06088
Anchor Flush, Round, 2X, 25ft	$	15.55	Anchor Flush, Round. 2X, 25ft	$	2.14	16000L ACORN	$	2.79	$	0.06088
Anchor Flush, Round, 2X, 30ft	$	18.07	Anchor Flush, Round, 2X, 30ft	$	2.49	16000L HPS ARCH	$	2.79	$	0.06088
Anchor Flush. Round, 2X, 32ft	$	19.28	Anchor Flush, Round, 2X, 32ft	$	2.66	16000L HPS ROADWAY	$	2.79	$	0.06088
Anchor Flush, Square, 5”, 13ft	$	13.95	Anchor Flush, Square, 5”, 13ft	$	1.92	16000 HPS DECORATIVE TRANSIT	$	2.79	$	0.06088
Anchor Flush, Square, 5”, 15ft	$	12.47	Anchor Flush, Square, 5”, 15ft	$	1.72	20000L MV	$	2.79	$	0.06088
Anchor Flush, Square, 5”, 23ft	$	14.79	Anchor Flush, Square, 5”, 23ft	$	2.03	21000L MH ARCH	$	2.79	$	0.06088
Anchor Flush, Square, 5”, 25ft	$	16.26	Anchor Flush, Square, 5”, 25ft	$	2.23	21000L MH FLOOD	$	2.79	$	0.06088
Anchor Flush. Square, 5”, 28ft	$	18.05	Anchor Flush, Square, 5”, 28ft	$	2.48	21000L MH ROADWAY	$	2.79	$	0.06088
Anchor Flush, Square, 5”, 32ft	$	17.95	Anchor Flush, Square, 5”, 32ft	$	2.47	22500L LPS ARCH	$	2.79	$	0.06088
Anchor Flush, Concrete, 12ft	$	41.58	Anchor Flush, Concrete, 12ft	$	5.73	2500 INC	$	2.79	$	0.06088
Anchor Flush, Fiberglass, 12ft	$	35.21	Anchor Flush, Fiberglass, 12ft	$	4.85	30000L HPS ARCH	$	2.79	$	0.06088
Anchor Flush, Dec Transit Ped, 4”, 16ft	$	34.33	Anchor Flush, Dec Transit Ped, 4”, 16ft	$	4.73	30000L HPS FLOOD	$	2.79	$	0.06088
Anchor Flush, Dec Transit, 6”, 30ft	$	66.28	Anchor Flush, Dec Transit, 6”, 30ft	$	9.13	30000L HPS ROADWAY	$	2.79	$	0.06088
Anchor Pedstl, Round, 1X, 12ft	$	11.71	Anchor Pedstl, Round, 1X, 12ft	$	1.61	33000L LPS ARCH	$	2.79	$	0.06088
Anchor Pedstl, Round, 1X, 22ft	$	13.24	Anchor Pedstl, Round, 1X, 22ft	$	1.82	36000L MH ARCH	$	2.79	$	0.06088
Anchor Pedstl. Round, 1X, 25ft	$	14.35	Anchor Pedstl, Round, 1X, 25ft	$	1.98	36000L MH FLOOD	$	2.79	$	0.06088
Anchor Pedstl, Round, 1X, 30ft	$	16.58	Anchor Pedstl, Round, 1X, 30ft	$	2.29	36000L MH ROADWAY	$	2.79	$	0.06088
Anchor Pedstl, Round, 1X, 32ft	$	17.41	Anchor Pedstl, Round, 1X, 32ft	$	2.40	4000 INC	$	2.79	$	0.06088
Anchor Pedstl, Round, 2X, 12ft	$	12.51	Anchor Pedstl, Round, 2X, 12ft	$	1.72	50000L HPS ARCH	$	2.79	$	0.06088
Anchor Pedstl, Round, 2X, 22ft	$	13.97	Anchor Pedstl, Round, 2X, 22ft	$	1.92	50000L HPS FLOOD	$	2.79	$	0.06088
Anchor Pedstl, Round, 2X, 25ft	$	15.08	Anchor Pedstl, Round, 2X, 25ft	$	2.07	50000L HPS ROADWAY	$	2,79	$	0.06088
Anchor Pedstl, Round, 2X, 30ft	$	17.61	Anchor Pedstl, Round, 2X, 30ft	$	2.42	5800 HPS ROADWAY	$	2.79	$	0.06088
Anchor Pedstl, Round, 2X, 32ft	$	18.81	Anchor Pedstl, Round, 2X, 32ft	$	2.59	6000 INC	$	2.79	$	0.06088
Anchor Pedstl, Round, 3 Bolt, 32ft	$	21.62	Anchor Pedstl, Round, 3 Bolt, 32ft	$	2.97	7000 MV	$	2.79	$	0.06088
Anchor Pedstl, Square, 5”, 13ft	$	13.50	Anchor Pedstl, Square, 5”, 13ft	$	1.86	8000L LPS ARCH	$	2.79	$	0.06088
Anchor Pedstl, Square, 5”, 15ft	$	13.80	Anchor Pedstl, Square, 5”, 15ft	$	1.89	9500L HPS ACORN	$	2.79	$	0.06088
Anchor Pedstl, Square, 5”, 23ft	$	14.32	Anchor Pedsd, Square, 5”, 23ft	$	1.98	9500L HPS ARCH	$	2.79	$	0.06088
Anchor Pedstl, Square, 5”, 25ft	$	15.80	Anchor Pedstl, Square, 5”, 25ft	$	2.19	9500L HPS COBRA/ROADWAY	$	2.79	$	0.06088
Anchor Pedstl, Square, 5”, 28ft	$	17.56	Anchor Pedstl, Square, 5”, 28ft	$	2.42	9500L HPS POST TOP BLACK	$	2.79	$	0.06088
Anchor Pedstl, Square, 5”, 32ft	$	18.23	Anchor Pedstl, Square, 5”, 32ft	$	2.50	9500L HPS POST TOP GRAY	$	2.79	$	0.06088
Direct Bury, Round, 19ft	$	18.42	Direct Bury, Round, 19ft	$	2.54	2300 LED COBRA	$	2.79	$	0.06088
Direct Bury, Round, 30ft	$	14.38	Direct Bury, Round, 30ft	$	2.66
Direct Bury, Round, 38ft	$	17.55	Direct Bury, Round, 38ft	$	2.73	Trip Charge per Lamp	$	100.00
Direct Bury, Self-Support, 40ft	$	21.62	Direct Bury, Self-Support, 40ft	$	3.42
Direct Bury, Stepped, 49ft	$	64.99	Direct Bury, Stepped, 49ft	$	8.96
Direct Bury, Square, 4”, 34ft	$	15.87	Direct Bury, Square, 4”, 34ft	$	2.75
Direct Bury, Square, 5”, 20ft	$	15.07	Direct Bury, Square, 5”, 20ft	$	2.49
Direct Bury, Square, 5” 30ft	$	15.71	Direct Bury, Square, 5” 30ft	$	2.59
Direct Bury, Square, 5” 38ft	$	17.05	Direct Bury, Square, 5” 38ft	$	2.96
Deecorative Transit 41-6	$	20.47	Deecorative Transit 41-6	$	3.01
Deecorative Transit 47	$	25.50	Deecorative Transit 47	$	3.75
Direct Bury, Steel Dist Pole, 35ft	$	23.54	Direct Bury, Steel Dist Pole, 35ft	$	3.10
Post Top, Dec Transit, 16ft	$	35.07	Post Top, Dec Transit, 16ft	$	4.82
Post Top, Gray Steel/Fiberglass, 23ft	$	12.16	Post Top, Gray Steel/Fiberglass, 23ft	$	2.00
Post Top, Black Steel, 23ft	$	13.41	Post Top, Black Steel, 23ft	$	2.21
FROZEN, Wood Poles, 30ft	$	8.95	FROZEN, Wood Poles, 30ft	$	1.55
FROZEN, Wood Poles, 35ft	$	8.95	FROZEN, Wood Poles, 35ft	$	1.48
Existing distribution pole	$	1.48	Existing distribution pole	$	—
Flush, 4ft	$	9.91	Flush, 4ft	$	1.36
Flush, 6ft	$	11.82	Flush, 6ft	$	2.05
Pedestal, 8ft	$	13.54	Pedestal, 8ft	$	2.36
Pedestal, 32’ round steel pole, 4ft 6”	$	9.39	Pedestal, 32’ round steel pole, 4ft 6”	$	1.63

Attachment K

Page 14 of 16

Settlement Rate Summary for Classified Rates

	E-67				E-221			GS-SCHOOLS M		GS-SCHOOLS L
	Proposed				Proposed			Proposed		Proposed
				Bundled Rates			Bundled Rates
$/kWh	$	0.05193	E-221	BSC $/day	$	0.588	BSC $/day
				kW	$	2.357	Self-Contained	$	0.672	$	1.068
				kWh Block 1	$	0.11228	Instrument-Rated	$	1.324	$	1.627
				kWh Block 2	$	0.07633	Primary Voltage	$	3.415	$	3.419
				kWh Block 3	$	0.06270	Transmission Voltage	$	26.163	$	22.915
			Minimum	BSC $/day	$	0.558	Demand Charge
				kW	$	2.357	1st 100 kW(Secondary)	$	9.612	$	9.311
							Over 100 kW (Secondary)	$	5.113	$	4.954
			E-221-8T	BSC $/day	$	0.964
				On-Peak kW	$	5.608	1st 100 kW (Primary)	$	8.919	$	8.636
				Off-Peak kW	$	3.351	Over kW (Primary)	$	4.419	$	4.282
				On-Peak kWh	$	0.09205
							1st 100 kW (Transmission)	$	6.953	$	6.736
				Off-Peak kWh	$	0.04952	Over kW (Transmission)	$	2.454	$	2.377
			Minimum	BSC $/day	$	0.964	Energy Charge
				kW	$	3.351	Summer Peak (Jun-Aug)
							On-Pk kWh	$	0.17343	$	0.15355
							Should-Pk kWh	$	0.12847	$	0.11374
							Off-Pk kWh	$	0.06487	$	0.06285
							Summer Shoulder (May, Sep & Oct)
							On-Pk kWh	$	0.14977	$	0.13260
							Should-Pk kWh	$	0.11095	$	0.09821
							Off-Pk kWh	$	0.05602	$	0.05428
							Winter (Nov-Apr)
							On-Pk kWh	$	0.11607	$	0.10276
							Should-Pk kWh	$	0.08599	$	0.07612
							Off-Pk kWh	$	0.04342	$	0.04206

Attachment K

Page 15 of 16

Settlement Rate Summary for Classified Rates

Community Power-Flagstaff (CMPW-01)			Rural School Solar Program (RSSP)			E-56 R	Contract 12
Solar Charge $/kWh			Solar Charge $/kWh			SC-S renamed		Proposed
Applicable Rate Schedules			Applicable Rate Schedules			Charges are per special contract
E-12	$	0.11242	E-32 S, E-32 M, E-32 L	$	0.09293		Per Delivery Point	$	16.44
ET-2	$	0.13480	E-32TOU S, E-32TOU M, E-32TOU L	$	0.05855		$/kWh	$	0.08479
E-32 S, E-32 M, E-32 L	$	0.09293	GS-SCHOOLS M, GS-SCHOOLS L	$	0.07158
E-32TOU S, E-32TOU M, E-32TOU L	$	0.05855

Attachment K

Page 16 of 16

Settlement Rate Summary for Low Income Discounts

E-3 Discount	Proposed
block1 (0-400 kWh)	65.0		%
block2 (400-800 kWh)	45.0		%
block3 (800-1200 kWh)	26.0		%
block4 (over 1200 kWh) $/bill	31.75
E-4 Discount
block1 (0-800 kWh)	65.0		%
block2 (800-1400 kWh)	45.0		%
block3 (1400-2000 kWh)	26.0		%
block4 (over 2000 kWh) $/bill	$	60.00