Exhibit 99.1

TABLE OF CONTENTS


PURPOSE OF AGREEMENT AND LIST OF SIGNATORIES			4

I. RECITALS			5

II. RATE CASE STABLILITY PROVISIONS			10

A. General Rate Case Filing Plan			10

B. Accelerated PSA Reset			11

III. RATE INCREASE			12

IV. COST OF CAPITAL			14

V. DEPRECIATION			14

VI. FUEL AND POWER SUPPLY ADJUSTMENT PROVISIONS			15

VII. APS EXPENSE REDUCTION COMMITMENT			15

VIII. EQUITY INFUSIONS TO BE MADE BY APS			16

IX. PENSION AND OPEB DEFFERALS			17

X. TREATMENT OF SCHEDULE 3			17

XI. ADJUSTMENT OF DEPRECIATION RATES FOR PALO VERDE LICENSE EXTENSION			19

XII. LIMIT ON RECOVERY OF ANNUAL CASH INCENTIVE COMPENSATION FOR APS EXECUTIVES			20

XIII. PERIODIC EVALUATION			21

A. Performance Measurements			21


B. Reporting Requirements			23

C. Benchmarking Study of APS Operations and Cost Performance			25

XIV. DEMAND SIDE MANAGEMENT			27

XV. RENEWABLE ENERGY			31

XVI. LOW INCOME PROGRAMS			34

XVII. REVENUE SPREAD			35

XVIII. RATE DESIGN			35

XIX. INTERRUPTIBLE RATE SCHEDULES AND OTHER DEMAND REDUCTION PROGRAMS			36

XX. DEMAND RESPONSE			36

XXI. OTHER RATE SCHEDULE MATTERS			37

XXII. FORCE MAJEURE PROVISION			38

XXIII. COMMISSION EVALUATION OF PROPOSED SETTLEMENT			38

XXIV. MISCELLANEOUS PROVISIONS			39

PROPOSED SETTLEMENT OF DOCKET NO. E-01345-A-08-0172
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-08-0172, Arizona Public Service Company’s (“APS” or “Company”) application to increase rates. This Agreement is entered into by the following entities:

AzAg Group
Arizona Association of School Business Officials (“AASBO”)
Arizona Corporation Commission Utilities Division (“Staff”)
Arizona Investment Council (“AIC”)
Arizona Public Service Company (“APS”)
Arizona School Boards Association (“ASBA”)
Arizonans for Electric Choice and Competition (“AECC”)
Bowie Power Station, LLC (“Bowie”)
Cynthia Zwick
Federal Executive Agencies (“FEA”)
Freeport-McMoRan Copper & Gold Inc. (“Freeport-McMoRan”)
IBEW Locals 387, 640, 769
Interwest Energy Alliance (“Interwest”)
Kroger Co. (“Kroger”)
Mesquite Power, LLC (“Mesquite”)
Residential Utility Consumer Office (“RUCO”)
Southwest Energy Efficiency Project (“SWEEP”)
Southwestern Power Group II, LLC (“SWPG”)
Town of Wickenburg
Western Resource Advocates (“WRA”)

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

The following numbered paragraphs comprise the Signatories’ Agreement.

I. RECITALS.

1.1. The purpose of this Agreement is to settle all issues presented by Docket No. E-01345A-08-0172 in a manner that will promote the public interest.

1.2 Docket No. E-01345A-08-0172 was commenced by the filing of a rate application by APS on March 24, 2008. The Company filed an amended application on June 2, 2008. On June 6, 2008, the Company filed a Motion for Approval of Interim Rates and Preliminary Order. The Company requested an Interim Base Rate Surcharge of $.003987 per kWh (or interim rates in an amount of $115 million), which would offset the fall off of the 2007 Power Supply Adjustor (“PSA”) surcharge.

1.3 The Commission approved the applications to intervene filed by Kroger, Freeport-McMoRan and AECC (collectively “AECC”), Mesquite, SWPG, Bowie, the Town of Wickenburg, WRA, SWEEP, RUCO, AIC, AZ-Ag Group, FEA, AASBO, ASBA, IBEW Locals 387, 640 and 769, Interwest, Cynthia Zwick, Catalyst Paper, the Hopi Tribe, SCA Tissue North America, and Barbara Wyllie-Pecora.

1.4 In its Motion, APS asserted that its earnings and cash flow are inadequate to finance its capital needs and so it “must borrow huge sums to keep up with the needs of APS customers.” APS asserted that its distribution, transmission, generation plant improvements, and new environmental control systems infrastructure investment requirements have increased and that the underlying cost of material, commodities and land for construction of this infrastructure has also increased. APS testified that its net cash flow for the past five years shows that APS’ financial health has weakened considerably. APS also testified that its credit ratings on its outstanding debt are currently among the lowest that they can possibly be without being regarded as “junk.” APS also testified that a downgrade to “junk” status was imminent without interim relief and that the effects of a downgrade might cause APS to lose all access to the credit markets, and jeopardize its ability to obtain credit on reasonable terms. APS also testified that the consequences of a downgrade would be dramatic and enduring and

would likely cause APS to incur higher interest rates resulting in increased costs to the Company of $1 billion over the next 10 years.

1.5 Staff and Intervenors filed testimony on APS’ request for interim rates on August 29, 2008, and APS filed rebuttal on September 8, 2008. An evidentiary hearing was held on the Company’s request for interim rates on September 15 through September 20, 2008.

1.6 Staff and RUCO opposed the Company’s request for interim rates on different grounds. Staff believed that the Company’s filings did not provide a basis under Arizona law in which to grant the Company interim relief. Nonetheless, Staff recognized that given the extraordinary financial market crisis occurring at the time, the Commission may desire to award some interim relief to the Company, and as an alternative Staff proposed an amount of approximately $65 million, based upon increased investment in net plant using the most recently approved cost of capital.

1.7 In the fall of 2008, pre-existing difficulties in the subprime mortgage market escalated, resulting in one of the most severe financial crises in the debt and equity markets this country has seen. That crisis underscored the importance for companies like APS to maintain a financial condition that (i) allows access to the volatile and uncertain financial markets in order to secure necessary financing at reasonable rates, and (ii) allows APS to obtain credit from vendors and lenders on reasonable terms. That financial crisis continues today. In part as a result of that crisis, Arizona and the rest of the nation have also entered into a severe recession which is negatively impacting APS, its customers, and other interested parties.

1.8 On December 24, 2008, the Commission granted APS interim rates in the amount of $65.2 million in Decision No. 70667. The increase was implemented through an interim base rate surcharge of $0.00226 per kWh effective with bills issued after December 31, 2008. The interim rates remain in effect until a final order is issued by the Commission in APS’ pending permanent case.

1.9 The procedural schedule on the Company’s permanent case set the deadline for Staff and Intervenor non-rate design direct testimony on December 19, 2008. On that date, testimony was filed by Staff, RUCO, AECC, IBEW 387, 640 and 769, Cynthia Zwick, SWEEP, WRA, AASBO

and ASBA. Staff and Intervenor direct testimony on rate design issues was filed on January 9, 2009.

1.10 APS proposed, and IBEW Locals 387, 640 and 769 supported, a total rate increase of approximately $448 million. Staff proposed a total rate increase of approximately $307 million. RUCO proposed a total rate increase of approximately $157 million. AECC’s testimony would have resulted in a total rate increase of approximately $347 million.

1.11 APS filed a notice of settlement discussions on January 23, 2009. The parties to the proceeding subsequently held settlement discussions. On January 30, 2009, APS filed a Motion to Suspend Procedural Schedule. The Hearing Division granted a similar request made by the Company on March 5, 2009. A procedural conference was held on April 7, 2009 and again on April 21, 2009.

1.12 At a procedural conference held on April 21, 2009, APS, Staff and the other participating Intervenors indicated that they had reached an agreement in principle on revenue requirement issues and that substantial agreement had been reached on other issues. The Settling Parties agreed to file a Term Sheet containing the major provisions of the Agreement on May 4, 2009. On May 4, 2009, the Settling Parties filed a Term Sheet outlining the agreement in principle reached with APS. A bill impact analysis statement was filed by the Settling Parties on May 15, 2009.

1.13 A procedural order was issued on May 11, 2009 establishing deadlines for the filing of testimony on the Settlement Agreement and an evidentiary hearing commencing on August 19, 2009.

1.14 The settlement discussions were open, transparent, and inclusive of all parties to this Docket who desired to participate. All parties to this Docket were notified of the settlement discussion process, were encouraged to participate in the negotiations, and were provided with an equal opportunity to participate.

1.15 The purpose of this Agreement is to settle all issues presented by Docket No. E-01345-08-0172 in a manner that will promote the public interest. The Signatories believe that this Agreement creates a rate and financial stability program for APS that appropriately balances the risks of

APS, its employees, its customers, and other interested parties. In addition, this Agreement creates a framework that the Signatories agree could ultimately improve APS’ financial metrics and bond ratings, which over the long term would benefit customers by allowing APS to borrow at more attractive rates, and also improve its vendor and lender creditworthiness, thereby increasing operational flexibility. Additionally, the terms of this Agreement are just, reasonable, fair and in the public interest in that they, among other things, (i) establish just and reasonable rates for APS’ customers; (ii) promote the convenience, comfort and safety, and the preservation of the health, of the employees and patrons of APS; (iii) resolve the issues arising from this Docket; and (iv) avoid unnecessary litigation expense and delay.

1.16 The Signatories believe that they have developed a settlement package that balances APS’ rate increase with benefits for customers. These benefits include:

a) Investments in Arizona’s Energy Future.

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establishment of energy efficiency goals and the creation of tiered performance incentives to encourage meeting those goals;

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at least 100 schools served by DSM programs and at least 1,000 customers in existing homes served by the Home Performance enhanced program element by December 31, 2010;

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placement of renewable energy projects at Arizona schools and government institutions;

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a plan for utility scale photovoltaic generation and an RFP for in-state wind generation;

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additional renewable energy projects to be in place by 2015 which, in combination with existing renewable commitments, will result in approximately 10% of APS’ retail sales coming from renewable resources; and,

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construction of one or more renewable energy transmission facilities.

b) Commitments Benefiting Low-Income Customers.

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continued rate discounts for low income ratepayers, holding these ratepayers harmless from the rate increase;

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creation of a new bill assistance program to benefit 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, funded by APS; and,

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waiving additional security deposits for low income ratepayers.

c) Rate Stability Plan.

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an increase in rate stability, including an extended period without base rate increases and a scheduled plan for future rate cases, resulting in greater administrative efficiency and reduced uncertainty for both APS and ratepayers.

d) Rate Related Benefits.

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an improvement in APS’ ability to attract capital, maintain reliability and sustain growth;

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a limit on recovery through rates of executive incentive compensation based upon performance;

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a sustained reduction of expenses of at least $30 million per year, which will reduce the need for future rate increases;

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an infusion of at least $700 million of additional equity and an improvement in APS’ financial metrics, strengthening its bond rating and reducing future debt costs;

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a plan to be prepared by APS to maintain investment grade financial ratios and improve APS’ financial metrics;

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an acceleration of the refund of any over-collected amounts in the PSA account, resulting in a lower adjustor rate that will partially offset the base rate increase;

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a reduced Systems Benefits Charge in 2012 if a Palo Verde license extension is approved before the conclusion of the next rate case; and,

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continued 90/10 sharing of the PSA.

e) Creation of Performance Measures for APS.

f) New Rate Design Options.

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creation of an optional super-peak tariff for residential customers and other critical peak pricing rates;

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twelve month reopening of the E-20 House of Worship tariff;

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development of Interruptible Rate Schedules and other Demand Response Programs for large customers; and,

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a new optional time of use rate for schools.

1.17 The Signatories desire that the Commission issue an order (i) finding that the terms and conditions of this Agreement are just and reasonable, together with any and all other necessary findings; (ii) concluding that the Agreement is in the public interest; (iii) granting approval of the Agreement; and (iv) ordering that the Agreement and its terms be effective upon Commission approval.

TERMS AND CONDITIONS.

II. RATE CASE STABILITY PROVISIONS.

A. General Rate Case Filing Plan.

2.1 The Signatories agree to two scheduled general base rate cases for APS to address plant additions and other rate matters which schedule shall cover the period of January 1, 2010 through December 31, 2014 (“Plan Term”). APS is prohibited from filing its next two general rate cases until on or after June 1, 2011 and June 1, 2013 respectively. No new base rates resulting from APS’ next general rate case will be effective before July 1, 2012.

2.2 The test year end (TYE) date for each of the base rate increase filings contemplated herein shall be:

6/1/2011 filing: TYE no earlier than 12-31-2010

6/1/2013 filing: TYE no earlier than 12-31-2012

2.3 The Signatories agree to use good faith efforts to process APS’ case(s) within 12 months of a sufficiency finding. The Company shall provide a one hundred twenty (120) day notice to the Commission and the Signatories of its intent prior to filing a new rate case. The notice shall at a minimum specify the following:

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That an application for a general rate change is planned;

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The anticipated date of the filing;

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The proposed effective date of the general rate change;

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Any major issues which the utility, at the time of filing the notice of intent, expects to raise in conjunction with the application.

2.4 In recognition of resource constraints and to assist the Commission in processing the case(s), within 60 days after the notification filing, APS, Staff and the other Signatories will meet and confer prior to the filing of such case(s) in an effort to narrow issues, to streamline the processing of the case and to identify an initial set of standard data requests to which APS will respond as part of its rate application.

2.5 The Signatories recognize the desirability of maintaining an appropriate interval between the filing of rate applications. If the Commission has not issued a final order in APS’ first rate case (the “on or after June 1, 2011” filing) by July 1, 2012, the parties will meet and confer in order to determine an appropriate date for filing APS’ next rate case and an appropriate test year ending date. If the parties are unable to agree to such dates, the matter shall be referred to the Commission for determination.

B. Accelerated PSA Reset.

2.6 If, at the time new rates are implemented, the PSA account has an over-collected balance, the PSA reset would be accelerated from February 1, 2010, so that the reduction in the PSA level would partially offset the increase to higher base rates.

III. RATE INCREASE.

3.1 The Commission granted APS an interim increase of $65.2 million in 2008. The Signatories agree that the interim surcharge shall be confirmed without any refund obligation.

3.2 The Signatories agree that APS will receive an additional non-fuel Base Rate Increase as a result of this Agreement of approximately $131.1 million over the interim increase (“revenue deficiency”).

3.3 The total non-fuel Base Rate Increase granted in this case (interim plus settlement) will be $196.3 million. When adjusted for both the interim increase and an additional $11.2 million of revenue associated with establishing new base fuel levels, this settlement represents an approximate 7.9% increase in base rate revenue.

3.4 The rationale for the $196.3 million Base Rate Increase includes, in addition to other items contained in Staff’s direct case, providing for a return on and of post-test year plant through June 30, 2009, eighteen (18) months beyond the test year ending December 31, 2007, as well as the Signatories’ desire to enhance APS’ ability to retain and improve its current investment-grade credit rating, thereby enabling APS to attract capital at reasonable cost, and to also optimize its operational flexibility, in order to be better positioned to meet its customers’ future energy service needs.

3.5 For ratemaking purposes and for the purposes of this Agreement, the Signatories agree that the fair value of APS’ jurisdictional rate base for the test year ending December 31, 2007 (the “test year”) is $7,665,727,000.

3.6 In addition, under this Agreement, APS is allowed to recover an increase in base fuel costs of $137.2 million, for a total rate increase of $344.7 million.

3.7 The Signatories agree that the opportunity to recover the revenue deficiency results in just and reasonable rates for APS’ customers. The agreements set forth herein regarding the quantification of fair value rate base, fair value rate of return, and the revenue deficiency are made for

purposes of settlement only and should not be construed as admissions against interest or waivers of litigation positions related to other cases.

3.8 A comparison of various of the Signatories’ initial proposed increases compared to that resulting from the Agreement is contained in the following table:


Comparison of APS, Staff, RUCO and Settlement	APS			Staff			RUCO			AECC
Summary of Base Rate Increase	Proposed			Proposed			Proposed			Proposed			Settlement
(Thousands of Dollars)
Components of Total Rate Increase
Base Rate Increase	$	264,341		$	155,062		$	(27,281	)	$	205,444		$	196,300
Fuel Related Increase in Base Rates	$	13,876		$	11,436		$	13,876		$	10,695		$	11,203
Total Base Rate Increase	$	278,217		$	166,498		$	(13,405	)	$	216,139		$	207,503
Adjusted Base Cost of Fuel Related Increase	$	169,977		$	140,088		$	169,977		$	130,527		$	137,235
Total Rate Increase Requested	$	448,194		$	306,586		$	156,572		$	346,666		$	344,738

Percentage Increase Over Current Rates
Revenue from Sales to Ultimate Retail Customers
2007 Test Year Adjusted	$	2,637,447		$	2,637,447		$	2,748,697		$	2,637,447		$	2,637,447
Percentage Increase — Net of PSA		10.55	%		6.31	%		-0.49	%		8.20	%		7.87	%
Percentage Increase — Total		16.99	%		11.62	%		5.70	%		13.14	%		13.07	%

Revenue from Sales to Ultimate Retail Customers
2010 Base Rate Revenue per APS	$	2,654,236		$	2,654,236		$	2,654,236		$	2,654,236		$	2,654,236
Percentage Increase — Net of PSA		10.48	%		6.27	%		-0.51	%		8.14	%		7.82	%
Percentage Increase — Total		16.89	%		11.55	%		5.90	%		13.06	%		12.99	%

3.9 In addition to the base rate increase provided herein, various of the Agreement’s provisions relating to fuel and purchased power costs, renewable energy, and energy efficiency may have the impact of increasing or decreasing the amounts collected from customers under the Company’s already established adjustment mechanisms (specifically, the Demand Side Management Adjustor Clause (“DSMAC”), the Renewable Energy Surcharge (“RES”), and Power Supply Adjustor (“PSA”). The presently estimated impact of this Agreement on the amount to be collected from the DSMAC and RES in 2010 is approximately an additional $15 million and $2 million respectively. Although the Signatories agree that the amounts collected under the DSMAC and RES will likely increase after 2010, there is not consensus as to the level of such increase.

3.10 In addition, the Signatories acknowledge that certain provisions of the Agreement do not have a rate impact in the present case, but they will have an impact in future APS rate cases. Specifically, the rate impacts shown

above do not include the increased cost to customers in a future APS rate case resulting from the treatments specified in this Agreement for recording Schedule 3 receipts as revenue (as opposed to Contributions-in-Aid-of Construction (“CIAC”)), for limited pension and other post-retirement benefits (“OPEB”) deferrals, and for an anticipated Palo Verde depreciation rate change. Nor do the rate impacts shown above reflect the Agreement’s requirement that APS reduce future costs by $30 million annually (or $150 million over the next five years), which will reduce future revenue requirements.

3.11 The Term Sheet, filed with the Commission on May 4, 2009, noted that the Signatories were looking at transitioning the $10 million of DSM costs currently recovered in base rates into the DSMAC so that all DSM costs would be recovered through a single source. In this Settlement, the Signatories agree that it is appropriate to retain the $10 million in base rates and address this issue in APS’ next general rate case. At that time, parties and the Commission can analyze whether it is appropriate to move all DSM costs to the DSMAC, whether to retain some or all DSM costs in base rates, and if so what portion of DSM costs should be in base rates, or whether other treatment would be appropriate.

IV. COST OF CAPITAL.

4.1 The Signatories agree that a capital structure comprised of 46.21% debt and 53.79% common equity shall be adopted for ratemaking purposes for this case.

4.2 The Signatories agree that a return on common equity of 11.0%, which is less than the return on common equity requested by APS, and an embedded cost of debt of 5.77% are appropriate and shall be adopted for ratemaking purposes for this Docket.

4.3 The Signatories agree to a fair value rate of return of 6.65% as shown on Attachment A, which includes a fair value increment.

V. DEPRECIATION.

5.1 For ratemaking purposes, upon the effective date of a Commission order approving this Agreement, APS’ proposed depreciation and

amortization rates are appropriate in this case and should be adopted with the exception of the Company’s proposed change to Account No. 370.01 (electronic meters), which should be rejected and the current depreciation rate of 3.68% for such Account retained. The depreciation rates adopted herein (with the exception of Account No. 370.01 (electronic meters)) are contained in the filed direct testimony of Dr. Ronald E. White, submitted on June 2, 2008 in this Docket as Attachment REW-1 and incorporated herein.

5.2 Special provision is made herein for depreciation rates associated with a Palo Verde License Extension in Section XI of this Agreement.

VI. FUEL AND POWER SUPPLY ADJUSTMENT PROVISIONS.

6.1 The Signatories agree that the 90/10 sharing provision in the current PSA will be continued for purposes of the resolution of this rate case.

6.2 The Signatories agree that the Base Cost of Fuel and Purchased Power is $0.037571 per kWh. This base fuel amount shall be reflected in APS’ base rates.

6.3 Gains on SO2 Allowances over or under the normalized jurisdictional test year amount reflected in base rates of $7.045 million shall be recovered and/or refunded through the PSA mechanism.

6.4 The PSA Plan of Administration shall be amended as necessary to reflect the terms of this Agreement and shall be approved concurrent with the approval of this Agreement.

VII. APS EXPENSE REDUCTION COMMITMENT.

7.1 Decision No. 70667 required APS to reduce its operational expenses by $20 million for 2009. This Agreement renews APS’ commitment to reduce its expenses on an annual basis and increases the amount of the annual reduction to an average of $30 million per year beginning in 2010. The $30 million average annual expense reduction by APS will continue through the Plan Term. The total expense reduction by APS for the Plan Term shall be at least $150 million.

7.2 The $30 million annual expense reduction by APS represents an average annual reduction over the five year period. In some years, it may exceed $30 million. However, in no year will the expense reduction be less than $25 million.

7.3 APS shall report annually on its expense reductions in similar detail and format to APS’ March 18, 2009 filing Re: Compliance Filing of Arizona Public Service Company Regarding Cost Management Efforts, Docket No. E-01345A-08-0172 (Interim Rate Proceeding).

7.4 As in Decision No. 70667, the Company is not required to make the expense reductions required in this Agreement from any specific area, but shall consider making them in the areas identified by the Commission in that Decision. See Decision No. 70667 at 42, 44. APS shall not make any expense reductions in costs necessary to preserve safe and reliable electric service.

VIII. EQUITY INFUSIONS TO BE MADE BY APS.

8.1 APS agrees to complete equity infusions of at least $700 million during the period beginning June 1, 2009 through December 31, 2014. The Opinion and Order approving the Agreement shall constitute authorization to infuse $700 million into APS through December 31, 2014. This amount includes the “up to $400 million” which was previously authorized by the Commission in Decision No. 70454, which authorization expires on December 31, 2009.

8.2 In accordance with its management responsibilities, the Company agrees to use its best efforts to maintain investment grade financial ratios and a balanced capital structure that optimizes benefits to ratepayers, and to work to improve its existing ratings with the financial rating agency community.

8.3 APS will use its best efforts to improve its financial metrics and bond ratings, by completing timely equity infusions and taking other measures to strive to achieve a capital structure with no more than 52% debt/total capital, as calculated by the credit rating agencies, by December 31, 2012.

8.4 APS shall prepare and submit to the Commission and Signatories within 120 days of approval of the Agreement, a plan detailing steps it intends to take to maintain and improve its financial ratings with the credit rating agencies.

IX. PENSION AND OPEB DEFERRALS.

9.1 APS shall be allowed to defer for future recovery, in accordance with the provisions of SFAS No. 71, a portion of its annual Pension and OPEB costs above or below the test year level in years 2011 and 2012, subject to the following maximum amounts for such deferrals in each year:

2011: deferral cannot exceed the lower of $13.5 million or 50% of the cost above the test year level;

2012: deferral cannot exceed $29 million of the cost above the test year level.

9.2 If APS’ annual Pension and OPEB costs are below the test year level in either 2011 or 2012, the full amount of such annual savings will be credited to the Pension/OPEB deferral account.

9.3 For purposes of this Agreement, the test year level of Pension and OPEB expense is $23.949 million on a total Company basis.

9.4 APS’ ability to record Pension and OPEB deferrals shall expire at the earlier of December 31, 2012 or the conclusion of its next general rate case.

9.5 The Signatories reserve the right to review APS’ Pension/OPEB deferrals in APS’ next rate case for reasonableness, prudence and the appropriate amortization period, such that the deferrals can be recognized in accordance with the provisions of SFAS No. 71.

X. TREATMENT OF SCHEDULE 3.

10.1 Following approval of this Agreement, APS shall be authorized to record proceeds from its line extension policy (“Schedule 3”) as revenue during the period from January 1, 2010 through either the earlier of December 31, 2012 or the conclusion of the Company’s next general rate

case. Thereafter, Schedule 3 receipts will be recorded as CIAC, unless otherwise ordered by the Commission.

10.2 The income resulting from the revenue treatment to Schedule 3 proceeds provided in Section 10.1 above is material to this Agreement. APS estimates that its Schedule 3 revenues would be $23 million in 2010, $25 million in 2011 and $49 million in 2012.

10.3 The Agreement proposes to maintain the Commission’s current policy regarding customer payments for line extensions, subject to the modifications described in this Section X. The Signatories acknowledge the letters filed in this Docket from several Commissioners regarding Schedule 3, and agree that, should the Commission decide in this proceeding to modify Schedule 3, offsetting revenue changes should also be ordered that would make any such modification(s) revenue neutral to the provisions of this Agreement.

10.4 Nothing in this Section or the Agreement is intended to prevent any Signatory from proposing a different treatment for Schedule 3 proceeds in APS’ next rate case, or from addressing any changes to Schedule 3 proposed by others in this rate case.

10.5 APS’ Impact Fee proposal in this case shall be withdrawn. However, this shall not act to limit APS’ ability to discuss impact or hook-up fees in the context of the generic docket on hook-up fees for future consideration by the Commission.

10.6 The System Facilities Charge proposed by APS shall be withdrawn.

10.7 APS shall submit a revised Schedule 3 to reflect the following modifications before the hearing in this case:

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A clarified definition of Local Facilities;

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A Schedule of Charges;

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A statement that quotes provided to customers will be itemized; and,

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Procedures for refunding amounts to customers when additional customers connect to the line extension.

Such Schedule 3 shall expressly permit customers to hire contractors for trenching, conduit, and backfill necessary for the extension, as is currently permitted.

XI. ADJUSTMENT OF DEPRECIATION RATES FOR PALO VERDE LICENSE EXTENSION.

11.1 Upon the later date of (1) receiving Nuclear Regulatory Commission (“NRC”) approval for the Palo Verde license extension or (2) 1/1/2012, APS is authorized to adjust depreciation rates used for recording depreciation expense on the Palo Verde generating unit to reflect such license extension, in accordance with the 2008 Depreciation Study results attached hereto as Attachment B. In addition, APS 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 and related to the Palo Verde license extension. Such request shall be filed in sufficient time to allow the Commission to make the reduction to the SBC simultaneous with the implementation of the depreciation rate change. APS shall also reduce the PSA amount to reflect a reduction in the independent spent fuel storage installation costs.

11.2 APS estimates that the change in depreciation rates due to the approved license extension will result in a reduction to APS’ depreciation expense in the approximate amount of $34 million annually on an ACC jurisdictional basis. Once the reduced depreciation expense is recognized as an expense reduction in the context of the reestablishment of new base rates in APS’ next base rate case, it would begin to provide a benefit to customers.

11.3 The changes in the recorded depreciation expense resulting from the Palo Verde depreciation rate change that would occur before the Company’s base rates are reestablished in the Company’s next rate case are intended to represent a benefit to APS. During that period, the lower recorded depreciation expense amounts mean that Accumulated Depreciation (a rate base offset) would be lower and APS rate base would be higher. The benefit to the Company associated with recording the new depreciation rates prior to their recognition in rates will be offset (in part) by the SBC and PSA reductions discussed in 11.1 above and 11.4 following.

11.4 APS’ approved annual level of nuclear decommissioning funding, on a jurisdictional basis, and as reflected in the Agreement’s proposed revenue requirement is as set forth in Attachment A to Decision No. 69663. Pursuant to the terms of this Settlement, if and when license extension is granted, APS shall file with the Commission a revised nuclear decommissioning funding requirement and a commensurate downward adjustment to the decommissioning component of the Company’s SBC and a reduction to the PSA as discussed above to be effective upon the later of the grant of license extension or January 1, 2012. The revenue requirement, income, expenses, fair value rate base and fair value rate of return utilized by the Signatories fully took into consideration the provisions of this Section 11.

11.5 APS will provide a depreciation rate study in its next rate case that includes a review of all of APS’ depreciation rates, including but not limited to the impact of the Palo Verde license extension.

XII. LIMIT ON RECOVERY OF ANNUAL CASH INCENTIVE COMPENSATION FOR APS EXECUTIVES.

12.1 The Signatories contemplate that the Commission will continue to review and evaluate costs associated with Executive compensation as it has in the past. The Signatories, including APS, recognize that the Commission will continue to review such costs to determine to what extent such costs should be borne by the Company’s customers. The Signatories also recognize the need for the Company to attract qualified persons and to reward exemplary work performance.

12.2 The Signatories agree that Annual Cash Incentive Compensation for APS Executives paid for 2010, 2011 and 2012 shall not exceed the test year level unless the Company:

has met all the components of the Performance Measurements described in Section 13(a) below for that particular year, to the extent such Performance Measurements apply to the year in question;

receives a Hardship Waiver from the Commission for failure to meet one or more of the Performance Measures; or

issues Annual Cash Incentive Compensation in excess of the test year levels that are absorbed by the shareholders and not recovered from ratepayers.

12.3 For the purposes of this Settlement, “Executive” is defined as any APS employee with a job title of Vice President, its equivalent or higher, or a Pinnacle West employee with a job title of Vice President, its equivalent or higher, that devotes a substantial portion of his or her time to APS matters. For purposes of this Agreement, “substantial portion” shall mean an executive who devotes 25% or more of his or her time to APS matters.

XIII. PERIODIC EVALUATION.

A. Performance Measurements.

13.1 The Signatories agree that the Company should exert its best efforts on an ongoing basis to maximize opportunities for financial soundness provided by virtue of this Agreement and that such efforts by the Company should be subject to periodic evaluation through the use of Performance Measurements and Reporting Requirements.

13.2 APS will be subject to periodic evaluation based upon the following measures, which include both Performance Measurements and Reporting Requirements. The Commission shall decide the appropriateness of any waivers of limits on Annual Cash Incentive Compensation recoverability for APS Executives based upon failure to meet these Performance Measurements and Reporting Requirements. APS shall meet the following Performance Measurements:

APS shall initiate and implement the schools renewable program in accordance with the terms set forth in Section XV. For purposes of specific performance goals, the program shall result in 50,000 MWhs of annual energy generation or savings at Arizona schools within 36 months of program approval;

The Company shall comply with the terms of its Commission — approved Implementation Plan designed to meet the energy efficiency goals set forth in Section XIV;

APS shall comply with the terms of its Commission-approved Implementation Plan designed to meet the goals set forth in the

Renewable Energy Standard and Tariff (“REST”) Rules by deriving a portion of the energy it sells from renewable technologies;

APS shall comply with the renewable energy goals in accordance with the terms set forth in Section XV of this Agreement;

APS shall reduce its expenses by at least $30 million per year, on average, in accordance with the terms set forth in Section VII of this Agreement;

The Company will strive to achieve a Capital Structure with no more than 52% total debt, as calculated by the credit rating agencies, by December 31, 2012;

APS shall submit a plan to the Commission to maintain investment grade financial ratios and to improve its financial metrics;

APS shall complete equity infusions of $700 million in accordance with the terms set forth in Section VIII;

The Company shall comply with the Annual Reporting of Financial and Customer Service Criteria as set forth in XIII.B, following; and,

APS shall cooperate with the Commission Staff in its conduct of the Benchmarking Study comparing APS with other similarly situated utilities.

13.3 If APS believes that its failure to comply with any measure listed in the Performance Measures set forth in Section XIII.A above is due to factors it believes are beyond its control or would result in an inequitable hardship, the Company may request from the Commission a waiver of such specific measure(s) for that particular year. APS’ ability to request a waiver does not guarantee that such a request will be granted by the Commission, or that the Signatories to this Agreement will not oppose such a waiver.

B. Reporting Requirements.

13.4. The Signatories agree that APS shall file a report with the Commission that contains the information set forth in this Section, and will provide such report to the other Signatories to this Agreement. Except where otherwise provided herein, the Company shall provide such report annually each April 30^th during the Plan Term, with information relevant to the preceding year, and to include changes from a 2007 base year. Reported information shall include a detailed list of customer service, reliability, safety and financial items including but not limited to:

a. Customer Service, Reliability and Safety Reporting.

The frequency and duration of unplanned outages (generation, transmission and distribution) as measured by the industry-used System Average Interruption Duration Index, System Average Interruption Frequency Index, and Customer Average Interruption Duration Index;

ii.

Information regarding major unplanned equipment outages or downtime for maintenance, repair and/or replacement, and distribution system outages consistent with the 1000 Hour Report currently filed with the Commission;

iii.

Number of calls from customers and level of customer satisfaction (based upon feedback surveys) regarding the way calls were handled;

iv.

Information regarding the levels of enrollment in DSM, Demand Response, Low-Income and RES programs;

Information regarding the frequency and severity of employee injuries using All Incident Injury Rate (“AIIR”); and,

vi.

Information addressing changes to APS’ employee counts, including changes to the counts of the employees represented by the two labor unions with whom APS has entered into collective bargaining agreements.

b. Financial Reporting.

Information regarding the Company’s earned return on equity (“ROE”) for the preceding 12 months, including supporting calculation detail and identification of the major factors impacting that ROE. Such reports shall be filed within 60 days following the end of each quarter throughout the Plan Term;

ii.

Information regarding the Company’s Funds from Operations (“FFO”) to Debt ratio, FFO/Interest ratio, and Total Debt/Capital ratio for the preceding 12 months, including supporting calculation detail and identification of the major factors impacting those metrics. Such reports shall be filed within 60 days following the end of each quarter throughout the Plan Term;

iii.

Information regarding Pinnacle West Capital Corporation’s (“PNW’) stock price, net book value and the relationship of PNW’s stock price to net book value. Such reports shall be filed within 60 days following the end of each quarter throughout the Plan Term;

iv.

Information regarding the status of all shelf registrations for debt and equity issuance(s) of APS and PNW;

Information regarding any long-term debt issuances and their impact on APS’ capital structure and FFO/Debt ratio within 60 days of such issuance;

vi.

Information regarding any equity infusions made in accordance with the terms set forth in Section VIII herein, their impact upon APS’ capital structure, the price per share at the time of issuance, any dilution to existing share, and the estimated impact upon APS’ FFO/Debt ratio. Such reports shall be filed within 60 days of such infusion;

vii.

Information regarding the criteria used to measure achieved performance under its Annual Cash Incentive Compensation Plan. The reporting of this information to the Commission will coincide with when it has been

made publicly available and reviewed and approved by the Board of Directors for the purpose of approving Annual Cash Incentive Compensation awards;

viii.

Information pertaining to Management Expenses;

ix.

Information pertaining to the Company’s Dividend Payout Ratio and changes from earlier years;

Information pertaining to Operation and Maintenance Expense and any significant changes from year to year;

xi.

Information pertaining to Customer and Sales Expense per Customer and any significant changes from year to year; and,

xii.

Information regarding the Company’s level of major capital expenditures, and its consideration of available alternatives in connection with such capital expenditures for generation facilities.

13.5 APS shall annually file a report with the Commission documenting its performance for the preceding year in relation to the Performance Measures set forth in the “Performance Measures” and “Reporting Requirements” Sections set forth above. Such annual report shall be filed no later than April 30th in the years 2011, 2012, 2013 and 2014, and shall be used for determining whether the Company has met the Performance Measures for the preceding year.

C. Benchmarking Study of APS Operations and Cost Performance.

13.6 The Signatories agree that by March 31, 2010, Staff shall select a benchmarking firm to conduct a benchmarking analysis of APS’ operational and cost performance relative to a peer group of at least 30 other investor-owned electric-only utility operating companies, to the extent available and practicable. To the extent practicable, the peer group shall reflect business characteristics comparable to that of APS, including, but not limited to, total revenue, number of customers, nuclear generation, ownership of generation, customer density, customer growth and fuel and resource mix.

13.7 Such analysis shall focus on the following areas at a minimum:

a) Operational Performance

•

Safety

•

All Safety Incident Injury Rate (AIIR)

•

Customer Satisfaction

•

Delivery Reliability

•

System Average Interruption Frequency Index (SAIFI)

•

Momentary Average Interruption Frequency Index (MAIFI)

•

System Average Interruption Duration Index (SAIDI)

•

Customer Average Interruption Duration Index (CAIDI)

•

Base Load Power Plant Performance

•

Sustainability Performance

b) Cost Performance

•

Non-Fuel Operating Expense per Customer

•

Distribution Additions to Plant per New Customer

•

Capital Expenditures

•

Hedging

•

Management Expense

c) Financial Health of Company

•

Debt/Equity Ratio

•

Dividend Payout Ratio

•

Return on Average Assets (ROAA)

•

Return on Average Equity (ROAE)

•

FFO/Debt

•

Debt Ratings

•

Earnings per Share (Pinnacle West)

•

Stock Performance (Pinnacle West)

13.8 The Company shall incur all costs paid to the benchmarking firm related to the study, which costs will be capped at $500,000. No such costs associated with the study shall be recoverable in rates.

13.9 The Benchmark Study Report shall be filed with the Commission no later than December 31, 2010. Such benchmark report shall include the benchmarking firm’s conclusions regarding the Company’s performance and any significant differences in performance on the benchmarks selected between APS and other utilities analyzed and the likely reasons for those differences. The report shall also identify areas where performance appears to be significantly above or below the norm.

XIV. DEMAND SIDE MANAGEMENT.

14.1 Energy Efficiency goals shall be established, defined as annual energy savings of 1.0% in 2010, 1.25% in 2011, and 1.5% in 2012, expressed as a percent of total energy resources needed to meet retail load. Cumulative annualized energy savings from the programs in 2010-2012 would be approximately 3.75% (1.00% + 1.25% + 1.50%) of total energy resources needed to meet retail load in 2012. If higher goals are adopted by the Commission for 2010, 2011 or 2012 in another docket, then those higher goals will supersede the goals listed above, as will any higher performance incentives.

14.2 The existing performance incentive for energy efficiency programs shall be modified to be a tiered performance incentive as a % of net benefits, capped at a tiered % of program costs.


				Performance
Achievement Relative	Performance			Incentive Capped
to the Energy	Incentive as % of			at % of Program
Efficiency Goals	Net Benefits			Costs
Less than 85%		0	%		0	%
85% to 95%		6	%		12	%
96% to 105%		7	%		14	%
106% to 115%		8	%		16	%
116% to 125%		9	%		18	%
Above 125%		10	%		20	%

14.3 Self Direction” of DSM charges will be allowed for large commercial or large industrial customers who use more than 40 million kWh per calendar year, based on an aggregation of all of the customer’s accounts. After a customer notifies APS of its intent to Self-Direct, 85% of the customer’s DSM contribution will be reserved for tracking purposes for the customer’s future energy efficiency project(s). The remaining 15% will be retained to cover the self direction program administration, management and verification, measurement and evaluation, and low-income program costs.

14.4 Self Direction funds will be paid once a year in December beginning in the year that the DSM project is completed and verified by the APS Solutions for Business team. If project costs exceed the credited amount in one year, then funding will continue to be paid in December of each year until the project is 100% funded or on the tenth year of funding, which ever comes sooner. If the energy efficiency project is not completed within two years of the Self Direction election date, then the Self Direction funds from the first calendar year from the Self Direction election will not be available to the Customer and will revert to the program account.

14.5 Self Direction provisions defining the specific parameters for Self Direction are summarized in Attachment C.

14.6 The Signatories agree that it is reasonable for APS’ DSMAC to be modified to achieve more current recovery of program costs, similar to the DSMAC approved for Tucson Electric Power Company (“TEP”) in Decision No. 70628. New DSMAC rates for the upcoming year will be set by the Commission as part of its consideration of the Implementation Plan. The Implementation Plan shall also include a bill impact analysis. If approved, such rates would become effective with the first billing cycle in March. This will supersede existing DSMAC reset filing dates. The total amount to be recovered by the DSMAC shall be calculated by projecting DSM costs for the next year, adjusted by the previous year’s over- or under-collection, and adding revenue to be recovered from the DSMAC performance incentive. The DSM Plan of Administration shall be amended as necessary to reflect the terms of this Agreement and shall be approved concurrent with this Agreement.

14.7 APS shall apply interest whenever an over-collected balance results in a refund to customers. The interest rate shall be based on the one-year Nominal Treasury Constant maturities rate contained in the Federal Reserve Statistical Release H-15 or its successor publication. The interest rate should be adjusted annually on the first business day of the calendar year. There will be no interest applied to an under-recovered balance.

14.8 APS shall not request recovery of unrecovered fixed costs (“UFC”) as a component of DSM program costs until its next general rate case. APS agrees to an explicit exclusion of UFC from the definition of program costs. This provision will not preclude APS from seeking such recovery in other proceedings.

14.9 APS shall file for the Commission’s approval an annual Energy Efficiency Implementation Plan for 2010, 2011, and 2012, with new and/or expanded programs or program elements necessary to achieve the energy efficiency goals. Each Implementation Plan shall include estimated energy savings by program and a range of estimated program costs by program necessary to meet the goal. Staff will review each Plan and provide its recommendations to the Commission. For any new programs, the Company and Staff will perform the cost effectiveness tests considering criteria and parameters reviewed by the DSM Collaborative. However, modifications to program elements of existing Commission-approved programs or adjustments to spending levels by program from year to year may not

require an updated cost effectiveness test. The Company will file implementation plans on June 1, 2010 and June 1, 2011 for the 2011 and 2012 goals respectively.

14.10 By July 15, 2009, APS shall file for the Commission’s approval in this Docket the 2010 Energy Efficiency Implementation Plan with new and/or expanded programs or program elements necessary to achieve the 2010 energy efficiency goal, including the enhancements and program elements set forth below. Staff shall review the Plan and provide its recommendations to the Commission in sufficient time so that the Commission may consider the matter at its regular November Open Meeting. In an effort to achieve timely approval of the Plan, the Signatories urge the Commission to take action on the Implementation Plan on or before the date it takes action on the Agreement. Such Implementation Plan will make clear that its obligations therein are contingent upon Commission approval of the Agreement.

14.11 The Signatories agree that the 2010 Implementation Plan shall include at a minimum:

A customer repayment/financing program element for schools, municipalities and small businesses fully integrated in the non-residential programs. This customer repayment element must be fully integrated from the perspective of the customer and not a separate offering. APS may use an actual on-the-bill or a parallel bill approach to implement this provision. Financing costs (including any default or guarantee cost) will be fully recoverable as a program cost. Any financing provided directly by APS will be at its weighted average cost of capital (if APS buys down the financing rate for the end-using customer, the differential between APS’ cost of capital and such reduced rate will also be recovered as a program cost);

A goal for APS to serve, meaning the installation of measures, through its existing DSM programs or enhanced program elements, at least 100 schools by December 31, 2010;

A review of the APS low income weatherization program for possible enhancement;

APS will have a Residential Existing Homes Program, which will include both a new Home Performance element and the existing HVAC element. The goal of the Home Performance element will be to serve at least 1,000 existing homes by December 31, 2010. These customers will be served by conducting an on-site energy assessment, direct installation of some energy saving measures (e.g. lighting, air sealing), and delivering information and incentive offers on a comprehensive set of recommended measures for consideration by the customer. The customized list of recommended measures shall include items such as insulation, duct repair and HVAC improvements to save energy, consistent with the national EPA/DOE Home Performance with ENERGY STAR program;

A non-residential high performance new construction program element with a second tier of performance and a higher financial incentive; and

A residential high performance new home program element with a second tier of performance and a higher financial incentive, which APS will file with the Commission on or before June 30, 2009 as part of its zero-net energy home filing. In an effort to achieve timely approval of the program element, the Signatories urge the Commission to take action on the program element on or before the date it takes action on the Agreement.

XV. RENEWABLE ENERGY.

15.1 APS shall make its best efforts to acquire new renewable energy resources with annual generation or savings of 1,700,000 MWh to be in-service by December 31, 2015, consistent with APS’ Resource Plan report, dated January 29, 2009, Appendix 1, Table 1 (Selected Resource Plan: Loads and Resources Table), Docket No. E-01345A-09-0037. These new resources shall be in addition to existing resources or commitments as of the end of 2008, as identified in APS’ 2008 RES Compliance Report dated April 1, 2009, Docket No. E-01345A-07-0468. These new renewable acquisitions, in combination with existing renewable commitments, are

currently estimated to be approximately 10% of retail sales by the end of 2015. Renewable resources are those defined in A.A.C. R14-2-1802. APS shall obtain a mix of new distributed and non-distributed renewable energy resources. APS shall report to the Commission on its plans for and progress towards acquiring the new resources, including any delays or shortfalls, in its Renewable Energy Standard Implementation Plans and RES Compliance Reports, and in future resource planning filings.

15.2 APS shall issue a new request for proposals for in-state wind generation within 90 days of Commission approval of the Agreement. After evaluating potential projects, APS will file a request for Commission approval of one or more such projects, within 180 days of issuance of the RFP.

15.3 APS shall, within 120 days of the Commission’s Order approving the Agreement, file in this Docket for Commission consideration a plan for implementing a utility scale photovoltaic generation project, which shall have a construction initiation date not later than 18 months from the date of filing. This requirement is in addition to the Concentrated Solar Power (“CSP”) projects already under consideration or previously approved by the Commission. In selecting a project for this filing, APS shall initiate a competitive procurement that complies with its certified Renewable Energy Competitive Procurement Procedure dated April 10, 2007. Any Signatory may file comments in response to APS’ filing with the Commission. The Commission shall not be obligated to act on APS’ filing. Any Commission inaction shall not indicate Commission approval of APS’ proposal.

15.4 Following the Biennial Transmission Assessment report (as required by Decision No. 70635) prioritizing transmission projects that will facilitate interconnection of renewable resources to Arizona’s transmission system, APS shall commence permitting, design, engineering, right of way acquisition, regulatory authorization (which may include a request to FERC for applicable transmission incentives and other cost recovery provisions), and line siting for one or more new transmission lines or upgrades designed to facilitate delivery of solar and other renewable resources to the APS system. APS shall expeditiously pursue permitting and authorizations and shall construct such transmission line(s) or upgrade(s) after satisfactory permitting and authorizations are obtained.

15.5 APS shall file within 120 days of the Commission’s Order approving the Settlement Agreement a new program for on-site solar energy including photovoltaics, solar water heating and daylighting, at grades K through 12 public (including charter) schools in its service territory that eliminates up-front customer costs. The program goal shall be installation of projects resulting in 50,000 MWh of annual energy generation or savings within 36 months of program approval by the Commission. APS shall collaborate with the School Facilities Board in determining the priority of projects giving consideration to the assessed valuation of the school district, participation in the National School Lunch Program, geographic diversity and need for the project. The program proposal shall describe options considered by APS for acquiring the necessary energy. In designing its program, APS shall consider among its options, a request for proposals by developers to implement and install solar energy systems on multiple schools such that the schools pay no up-front costs. APS’ proposal shall include its estimate of APS’ costs associated with the program, APS’ proposed method for cost recovery, and APS’ proposal for counting the energy produced or saved by the school solar energy systems toward APS’ REST requirements. APS shall file its program proposal under a new docket number and shall provide an opportunity for interested stakeholders, including school representatives and solar industry representatives, to provide input prior to preparing its proposal. School programs executed with stimulus funding leveraging REST funds would qualify toward the program goal.

15.6 APS shall file within 120 days of the Commission’s Order approving the Settlement Agreement a new program for governmental institutions for distributed solar energy, including photovoltaics, solar water heating and daylighting, to substantially reduce or eliminate up-front customer cost. APS shall file its program proposal under a new docket number and shall provide an opportunity for interested stakeholders to provide input on its proposal. This program may be proposed concurrently with the schools program described in Paragraph 15.6

15.7 All reasonable and prudent expenses incurred by APS pursuant to this Section of the Agreement shall be recoverable through the Power Supply Adjustor, a renewable energy adjustment mechanism, or the Transmission Cost Adjustor, as appropriate. To encourage least cost renewable resources to benefit customers, these expenses would also include the capital carrying costs of any capital investments by APS in renewable energy projects

(depreciation expenses at rates established by the Commission, property taxes, and return on both debt and equity at the pre-tax weighted average cost of capital). In consideration of this Paragraph 15.7, APS shall not seek to recover Construction-Work-In-Progress (“CWIP”) related to any of the renewable projects required by this Section 15.

15.8 APS agrees to abide by the commitments set forth in paragraphs 15.1 through 15.7 of this Section regardless of the outcome of any judicial challenge to the current REST rules. Through this Agreement, APS reiterates and renews its support of the current REST rules.

XVI. LOW INCOME PROGRAMS.

16.1 The increase in base rate revenue will not apply to the existing low income schedules (E-3 and E-4). As a result, all rate schedules except for the low income schedules will receive an equal percentage of base rate increase. This holds low income customers harmless from the rate increase and applies to both existing customers and those to be enrolled in the low income rate.

16.2 Eligibility for low-income schedule shall be set at 150% of the Federal Poverty Income Guidelines.

16.3 APS shall augment its current bill assistance program, which was approved in Decision No. 69663, to offer identical assistance to 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 additional program is to be funded by APS to be used by qualifying customers to assist them in their payment of customer electric bills. The level of the funding requirement during the Plan Term shall be established at $5 million. If any funding remains at the end of the Plan Term, such funds shall be carried forward until expended.

16.4 APS will waive the collection of an additional security deposit from customers on low-income rate schedules (E-3 and E-4) under the following circumstances: (1) the customer has had more than two late payments in the previous 12 months, or (2) the customer has been disconnected for non-payment.

16.5 Treatment of qualifying low-income customers by exempting them from the DSMAC is consistent with Decision No. 70961. The under-recovery of DSM costs attributable to the Commission’s exemption of low-income E-3 and E-4 customers from the DSMAC increase is addressed through the regular balancing account provisions of the DSMAC and thus will be collected from all other APS customers.

XVII. REVENUE SPREAD.

17.1 Each retail rate schedule will receive an equal percentage total base rate increase, inclusive of the interim rate increase, and inclusive of fuel and purchased power costs that are incorporated into base rates.

17.2 Within E-32, the percentage increase will be differentiated such that:

E-32 (401 + kW) receives an increase that is 2.5% below average for the group;

E-32 (101-400 kW) receives the group average increase;

E-32 (21-100 kW) receives an increase that is 1% above the average for the group; and

E-32 (0-20 kW) receives an increase that is above the average for the group by the necessary residual amount (approximately 2.8%).

XVIII. RATE DESIGN.

18.1 The voltage discount for E-35 customers taking service at transmission voltage will be equal to the current discount adjusted by the overall E-35 percentage increase.

18.2 The third-party transmission charge for Rates E-34 and E-35 proposed by APS is not adopted.

18.3 The rate increase for Rates E-34, E-35 and E-32 (401+ kW) will be implemented by adopting APS’ proposed changes in the customer charge with an equal percentage increase in the demand and energy charges.


XIX. INTERRUPTIBLE RATE SCHEDULES AND OTHER DEMAND REDUCTION PROGRAMS.

19.1 Within 180 days of Commission approval of the Settlement Agreement, APS, in consultation with Staff and interested stakeholders, will file an Interruptible Rate Rider (“IRR”) for customers with loads over three megawatts (Rate Schedules E-34 and E-35). The IRR will provide a range of options with respect to notice requirements, duration, and frequency, and will provide credits to participating customers based on avoided capacity costs. The IRR may consist of two rate elements: a short term customer commitment, (e.g. one year for customers who are willing to commit to the interruption option for a short term), and a long term customer commitment, (e.g. for customers willing to commit for a five year period). In addition to the IRR, APS may offer Demand Response Programs applicable to these customers.

XX. DEMAND RESPONSE.

20.1 Broadly defined, APS’ demand response programs include time-of-use rates, super peak and critical peak pricing rates, and other programs which influence the timing of a customer’s energy usage.

20.2 To provide prospective customers that may participate in any demand response program with clear and complete information about all of their demand side management options and to improve the efficiency with which energy is used, APS shall offer and market its demand response programs jointly with its energy efficiency programs. These marketing materials shall be submitted to Staff for its review.

20.3 A new demand response super peak time-of-use rate for residential customers, as proposed by APS in the direct testimony of Charles Miessner, should be approved.

20.4 The proposed critical peak pricing rate CPP-GS will be implemented on a pilot basis, specifying a minimum number of called critical days during the program. The Company will make a good faith effort to attain participation levels of at least 200 customers in this pilot.

20.5 A residential critical peak pricing rate pilot program will be implemented on a pilot basis, and APS shall make good faith efforts to attain participation levels of at least 300 residential customers in such pilot. This program will be designed to provide participating customers with strong, clear price signals that are narrowly focused on a limited number of specific hours of each year. APS will provide participating customers with notice of each critical peak period, via email, text message or telephone message, at least 6 hours in advance of the commencement of each critical peak period.

20.6 APS shall prepare a study on the impact of its super peak and critical peak pricing programs on:

The mix of power generation resources, including the use of coal-fired power resources;

Air emissions including carbon dioxide, sulfur dioxide, nitrogen oxides, particulate matter, and mercury; and

Energy use by program participants.

The study shall also identify methods to better integrate demand response programs and energy efficiency programs and shall analyze the benefits of demand response programs. Benefits of the demand response program include avoided or deferred generating capacity costs and fuel and other variable cost savings. The study shall examine actual experience with APS’ demand response programs and shall be filed in Docket Control within two years of the Commission’s decision in this Docket.

XXI. OTHER RATE SCHEDULE MATTERS.

21.1 The Signatories agree that APS shall unfreeze the existing Rate Schedule E-20 (House of Worship) tariff for a period of 12 months to allow for additional customer participation.

21.2 Within 90 days of approval of the Settlement Agreement, APS will file a new optional TOU rate applicable to K-12 schools designed to provide daily and seasonal price signals to encourage load reductions during peak periods.

XXII. FORCE MAJEURE PROVISION.

22.1 Notwithstanding anything contained herein to the contrary, APS shall not be prevented 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 is beyond APS’ control and 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 pursuant to this Section in the event of the imposition of a federal carbon tax or related federal “cap and trade” system. 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.

XXIII. COMMISSION EVALUATION OF PROPOSED SETTLEMENT.

23.1 The Signatories agree that all currently filed testimony and exhibits shall be offered into the Commission’s record as evidence.

23.2 The 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.

23.3 This Agreement shall serve as a procedural device by which the Signatories will submit their proposed settlement of APS’ pending rate case, Docket No. E-01345A-08-0172, to the Commission.

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

23.5 If 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 the 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 to that effect 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.

23.6 Within ten days after the Commission issues an order in this matter, if not sooner, APS shall file compliance schedules for Staff review. Subject to Staff review, such compliance schedules will become effective January 1, 2010.

XXIV. MISCELLANEOUS PROVISIONS.

24.1 This Agreement represents the Signatories’ mutual desire to compromise and settle disputed issues in a manner consistent with the public interest. The terms and provisions of this Agreement apply solely to and are binding only in the context of the purposes and results of this Agreement.

24.2 This case has attracted a large number of participants with widely diverse interests. To achieve consensus for settlement, many participants are accepting positions that, in any other circumstances, they would be unwilling to accept. They are doing so because this Agreement, as a whole, with its various provisions for settling the issues presented by this case, 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.

24.3 Nothing in this Agreement shall be construed as an admission by any Signatory as to the reasonableness or unreasonableness or lawfulness or unlawfulness of any position previously taken by any other Signatory in this proceeding.

24.4 No 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.

24.5 Neither this Agreement or 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 in furtherance of securing the approval and enforcement of this Agreement.

24.6 To the extent any provision of this Agreement is inconsistent with any existing Commission order, rule, or regulation, this Agreement shall control. Nothing contained in this Agreement is intended to interfere with the Commission’s authority to exercise any regulatory authority by the issuance of orders, rules or regulations.

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

24.8 The 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 23.5, 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.

24.9 This 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.


	ARIZONA CORPORATION COMMISSION
	By:	/s/ Ernest G. Johnson
		Ernest G. Johnson
		Director, Utilities Division


	ARIZONA PUBLIC SERVICE COMPANY
	By:	/s/ Jeffrey B. Guldner
		Jeffrey B. Guldner


	RESIDENTIAL UTILITY CONSUMER OFFICE
	By:	/s/ Jodi A. Jerich
		Jodi A. Jerich, Esq.
		Residential Utility Consumer Office Attorneys for Residential Utility Consumer Office


	ARIZONA ASSOCIATION OF SCHOOL BUSINESS OFFICIALS
	By:	/s/ Timothy M. Hogan
		Timothy M. Hogan


	ARIZONA SCHOOL BOARDS ASSOCIATION
	By:	/s/ Timothy M. Hogan
		Timothy M. Hogan


	SOUTHWEST ENERGY EFFICIENCY PROJECT
	By:	/s/ Timothy M. Hogan
		Timothy M. Hogan


	WESTERN RESOURCE ADVOCATES
	By:	/s/ Timothy M. Hogan
		Timothy M. Hogan


	FREEPORT-MCMORAN COPPER & GOLD INC.
	By:	/s/ C. Webb Crockett
		C. Webb Crockett
		Patrick J. Black Fennemore Craig, P.C. Attorneys for Freeport-McMoRan Copper & Gold Inc.


	ARIZONANS FOR ELECTRIC CHOICE AND COMPETITION
	By:	/s/ C. Webb Crockett
		C. Webb Crockett
		Patrick J. Black Fennemore Craig, P.C. Attorneys for Arizonans for Electric Choice and Competition


	THE KROGER CO.
	By:	Kurt M. Boehm
		Kurt M. Boehm, Esq.
		Boehm, Kurtz & Lowry Attorneys for The Kroger Co.


	BOWIE POWER STATION, L.L.C.
	By:	/s/ Lawrence V. Robertson, Jr.
		Lawrence V. Robertson, Jr.


	MESQUITE POWER L.L.C.
	By:	/s/ Lawrence V. Robertson, Jr.
		Lawrence V. Robertson, Jr.


	SOUTHWESTERN POWER GROUP II, L.L.C.
	By:	/s/ Lawrence V. Robertson, Jr.
		Lawrence V. Robertson, Jr.


	INTERWEST ENERGY ALLIANCE
	By:	Douglas V. Fant
		Douglas V. Fant, Esq.
		Law Office of Douglas V. Fant Attorneys for Interwest Energy Alliance


	IBEW LOCALS 387, 640 AND 769
	By:	/s/ Jarrett J. Haskovec, Esq.
		for Nicholas J. Enoch, Esq.
		Lubin & Enoch, P.C. Attorneys for IBEW Locals 387, 640 and 769


	AzAg Group
	By:	/s/ Jay I. Moyes, Esq.
		Jay I. Moyes, Esq.
		Moyes Sellers & Sims, Ltd. Attorneys for AzAg Group


	ARIZONA INVESTMENT COUNCIL
	By:	/s/ Michael M. Grant, Esq.
		Michael M. Grant, Esq.
		Gallagher & Kennedy, P.A. Attorneys for Arizona Investment Council


	FEDERAL EXECUTIVE AGENCIES
	By:	Karen S. White
		Karen S. White, Esq.
		Air Force Utility Litigation & Negotiation Team Attorneys for Federal Executive Agencies


	TOWN OF WICKENBURG
	By:	/s/ William P. Sullivan
		Michael A. Curtis, Esq.
		William P. Sullivan, Esq. Curtis, Goodwin, Sullivan Udall & Schwab, P.L.C. Attorneys for Town of Wickenburg