Document:

Exhibit 10.11.6a

 

EXECUTION COPY

 

AMENDMENT NO. 1

 

This AMENDMENT NO. 1 (this “Amendment”), dated as of December 22, 2011, is entered into by and among Arizona Public Service Company (“APS”), the Banks signatory hereto (the “Banks”) and JPMorgan Chase Bank, N.A., as a Bank, as Issuing Bank (in such capacity, the “Issuing Bank”), and as Administrative Agent (in such capacity, the “Administrative Agent”).

 

W I T N E S S E T H:

 

WHEREAS, APS, the Banks, the Issuing Bank and the Administrative Agent have entered into that certain Reimbursement Agreement dated as of April 16, 2010 (as amended, restated, supplemented or otherwise modified from time to time, the “Reimbursement Agreement”), in connection with which the Issuing Bank issued its Amended and Restated Irrevocable Transferable Letter of Credit No. P-010152 (the “Letter of Credit”); and

 

WHEREAS, the parties hereto desire to amend the Reimbursement Agreement as set forth below and to extend the Letter of Credit until December 31, 2015;

 

NOW THEREFORE, in consideration of the premises herein contained, and for other good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto hereby agree as follows:

 

Section 1.1             Defined Terms.  Capitalized terms used and not otherwise defined herein shall have the meanings assigned to such terms in the Reimbursement Agreement.

 

Section 1.2             Amendments to the Reimbursement Agreement.  Subject to the satisfaction of the conditions precedent set forth in Section 1.4  below, the Reimbursement Agreement is hereby amended as follows:

 

(a)   Section 1 of the Reimbursement Agreement is hereby amended by deleting Schedule I, referenced in the definition of “Base Rate Margin” and “Letter of Credit Commission Rate” in its entirety and replacing it with Amended Schedule I attached hereto.

 

(b)   Section 1 of the Reimbursement Agreement is hereby amended by adding the definition of “FATCA” in proper alphabetical order to read as follows:

 

““FATCA” means Sections 1471 through 1474 of the Code, as of the date of this Amendment, and any regulations or official interpretations thereof.”

 

(c)   Section 1 of the Reimbursement Agreement is hereby amended by deleting the definition of “Financial Information” set forth therein and replacing it with the following:

 

““Financial Information” means (i) the annual report of the Company on Form 10-K for the year ended December 31, 2010, as filed with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, (ii) the Company’s Form 10-Q reports for the quarters ended March 31,

 

 

2011, June 30, 2011 and September 30, 2011 and (iii) the Company’s current reports on Form 8-K filed on February 18, February 22, April 22, June 1, August 24, and November 4 of 2011, as so filed.”

 

(d)   Section 1 of the Reimbursement Agreement is hereby amended by adding the definition of “Four Corners Acquisition” in proper alphabetical order to read as follows:

 

““Four Corners Acquisition” means the acquisition by the Company from Southern California Edison Company (“SCE”) of SCE’s interest in Units 4 and 5, together with any other property, assets, interests or rights related thereto, of the Four Corners Power Plant near Farmington, New Mexico, pursuant to the Purchase and Sale Agreement, dated as of November 8, 2010, by and between SCE and the Company.”

 

(e)   Section 1 of the Reimbursement Agreement is hereby amended by deleting the definition of “Material Subsidiary” set forth therein and replacing it with the following:

 

““Material Subsidiary” means, at any time, a Subsidiary of the Company which as of such time meets the definition of a “significant subsidiary” included as of December 22, 2011 in Regulation S-X of the Securities and Exchange Commission or whose assets at such time exceed 10% of the assets of the Company and its Subsidiaries (on a consolidated basis).”

 

(f)    Section 1 of the Reimbursement Agreement is hereby amended by deleting the definition of “Stated Termination Date” set forth therein and replacing it with the following:

 

““Stated Termination Date” means December 31, 2015, or such later date to which such Stated Termination Date shall have been extended pursuant to Section 17.”

 

(g)   Section 2(d)(i) of the Reimbursement Agreement is hereby amended to add the following after the words: “or the Letter of Credit or its Participation therein” appearing in the 10th line thereof:

 

“(each, a “Change in Law”).”

 

(h)   Section 2(d)(iii) of the Reimbursement Agreement is hereby amended to add the following at the end thereof:

 

“Notwithstanding anything in this Section 2(d) to the contrary, for all purposes of this Agreement, (x) all requests, rules, guidelines, directives, interpretations or guidance in connection with the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, as enacted by the United States Congress, and signed into law on July 21, 2010, shall be deemed to be a change in law, regardless of the date enacted, adopted or issued, and (y) all requests, rules, guidelines, directives, interpretations or guidance promulgated by the Bank for International Settlements, the Basel Committee on Banking Regulations and Supervisory Practices (or any successor or similar authority) or any Governmental Authority

 

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shall be deemed to be a Change in Law, regardless of the date enacted, adopted or issued.”

 

(i)    Section 2(e) of the Reimbursement Agreement is hereby amended by deleting the definition of “Taxes” set forth therein and replacing it with the following:

 

““Taxes” means any and all present or future taxes, duties, levies, imposts, deductions, charges or withholdings with respect to any payment by the Company pursuant to this Agreement, and all liabilities with respect thereto, excluding (i) in the case of each Bank and the Administrative Agent, taxes imposed on or measured by its net income, and franchise or similar taxes imposed on it, by the United States, or by the jurisdiction (or any political subdivision thereof) under the laws of which such Bank or the Administrative Agent (as the case may be) is organized or does business or in which its principal executive office is located or, in the case of each Bank, in which its Applicable Booking Office is located, (ii) any branch profits taxes imposed by the United States or any similar tax imposed by any other jurisdiction in which the Company is located, (iii) any backup withholding that is required by the Internal Revenue Code to be withheld from amounts payable to a Bank that has failed to comply with Section 2(e)(iii)(2)(A), (iv) in the case of each Bank, any United States withholding tax imposed with respect to any payment by the Company pursuant to this Agreement, but only up to the rate (if any) at which United States withholding tax would apply to such payments to such Bank at the time such Bank first becomes a party to this Agreement and (v) any United States withholding tax imposed by FATCA.”

 

(j)    Sections 6(a), 6(e), 6(f), 6(h), 6(i), 7(a), 7(b) and 7(c) of the Reimbursement Agreement are hereby amended to replace each occurrence of the phrase “financial condition or financial prospects” with a phrase “financial condition, operations, business or property”.

 

(k)   Section 8(a) of the Reimbursement Agreement is hereby amended to add the following to the end thereof:

 

“and (vii) at any time following the consummation of the Four Corners Acquisition and the closure by the Company of Units 1, 2 and 3 of the Four Corners Power Plant near Farmington, New Mexico, as described in the Financial Information, disposition of all or any portion of the Company’s interests in such Units 1, 2 and 3.”

 

(l)    The address for notices and other communications to the Issuing Bank, set forth in Section 11(a)(iii) of the Reimbursement Agreement, is hereby replaced with the following:

 

JPMorgan Chase Bank, N.A.

131 S. Dearborn, 5th Floor

Mail Code IL1-0236

Standby Letter of Credit Unit

Chicago, IL 60603-5506

Facsimile No.: (312) 954-6163

 

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Telephone No.: (800) 634-1969, Option 1

Attention:  Standby Service Unit

 

(m)  The Reimbursement Agreement is hereby amended by adding a new Section 31 to read as follows:

 

“Section 31.  FATCA Certification.

 

“If a payment made to the Issuing Bank or a Bank hereunder would be subject to U.S. federal withholding tax imposed by FATCA if the Issuing Bank or such Bank were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), the Issuing Bank or such Bank shall deliver to each of the Company and the Administrative Agent, at the time or times prescribed by law and at such time or times reasonably requested by the Company or the Administrative Agent, such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Company or the Administrative Agent as may be necessary for the Company and the Administrative Agent to comply with its obligations under FATCA, to determine that the Issuing Bank or such Bank has or has not complied with the Issuing Bank’s or such Bank’s obligations under FATCA and, as necessary, to determine the amount to deduct and withhold from such payment.  Solely for purposes of this Section 31, “FATCA” shall include any amendments made to FATCA after the date of this Agreement.”

 

(n)   Each of the parties hereto hereby acknowledges and agrees, and directs the Issuing Bank, to amend the Letter of Credit as set forth on Exhibit A attached hereto.

 

Section 1.3             Representations and Warranties.  APS represents and warrants to the Administrative Agent and each Bank that:

 

(a)   After giving effect to the amendments contemplated herein, the representations and warranties of APS set forth in Section 6 of the Reimbursement Agreement are true, correct and complete in all material respects on the date hereof as if made on and as of the date hereof and there exists no Reimbursement Default or Default or Event Default under the Facility Lease on the date hereof; provided that in the case of any representation or warranty in Section 6 of the Reimbursement Agreement that expressly relates to facts in existence on an earlier date, the reaffirmation thereof under this Section 1.3(a) shall be made as of such earlier date.

 

(b)   The execution and delivery by APS of this Amendment have been duly authorized by proper corporate proceedings of APS and this Amendment and the Reimbursement Agreement constitute the legal, valid and binding obligation of APS enforceable against APS in accordance with their respective terms, except as such enforcement may be limited by applicable bankruptcy, insolvency, reorganization, moratorium or other similar laws of general applicability affecting the enforcement of creditors’ rights generally.

 

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Section 1.4             Conditions Precedent.  This Amendment shall become effective (the “Effective Date”) as of December 22, 2011, upon the receipt by the Administrative Agent of (i) an opinion of in-house counsel of APS in form and substance reasonably satisfactory to the Administrative Agent, (ii) a certificate of the secretary or the associate secretary of APS certifying (a) that there have been no changes in the certificate of incorporation or bylaws of APS since April 16, 2010, (b) resolutions of its Board of Directors authorizing the execution, delivery and performance of the Reimbursement Agreement, as modified by this Amendment, and (c) the incumbency and specimen signature of each of its officers authorized to sign this Amendment, (iii) duly executed copies of this Amendment from each of APS, the Banks, the Issuing Bank and the Administrative Agent and (iv) payment of the fees and expenses of Agent’s Counsel and all other expenses required to be paid on the Effective Date.

 

Section 1.5             Continuing Effectiveness, Etc.

 

(a)           Upon the effectiveness of this Amendment, each reference in the Reimbursement Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” “hereby” or words of like import shall mean and be a reference to the Reimbursement Agreement as modified hereby and each reference to the Reimbursement Agreement in any other document, instrument or agreement executed and/or delivered in connection with the Reimbursement Agreement shall mean and be a reference to the Reimbursement Agreement as modified hereby.

 

(b)           Except as specifically modified hereby, the Reimbursement Agreement and the instruments and agreements executed and/or delivered in connection therewith shall remain in full force and effect and are hereby ratified and confirmed.

 

Section 1.6             CHOICE OF LAW.  THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK (INCLUDING SECTIONS 5-1401 AND 5-1402 OF THE GENERAL OBLIGATIONS LAW BUT OTHERWISE WITHOUT REGARD TO CONFLICT OF LAW PRINCIPLES).

 

Section 1.7             Execution in Counterparts.  This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.

 

Section 1.8             Successors and Assigns.  This Amendment shall be binding upon APS, the Issuing Bank, the Banks and the Administrative Agent and their respective successors and assigns, and shall inure to the benefit of APS, the Issuing Bank, the Banks and the Administrative Agent and their respective successors and assigns.

 

Section 1.9             Integration.  This Amendment contains the final and complete integration of all prior expressions by the parties hereto with respect to the subject matter hereof and shall constitute the entire agreement among the parties hereto with respect to the subject matter hereof superseding all prior oral or written understandings.

 

Section 1.10           Headings.  Section headings in this Amendment are included herein for convenience or reference only and shall not constitute a part of this Amendment for any other purpose.

 

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[signature pages follow]

 

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IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed and delivered by their duly authorized officers as of the date hereof.

 

 

	
 
    	
ARIZONA   PUBLIC SERVICE COMPANY
    
	
 
    	
 
    
	
 
    	
 
    
	
 
    	
By: 
    	
/s/ Lee   R. Nickloy
    
	
 
    	
Name: 
    	
Lee R.   Nickloy
    
	
 
    	
Title: 
    	
Vice   President and Treasurer
    

 

 

	
 
    	
JPMORGAN   CHASE BANK, N.A., as Administrative
    
	
 
    	
Agent,   as Issuing Bank and as a Bank
    
	
 
    	
 
    
	
 
    	
 
    
	
 
    	
By: 
    	
/s/   Nancy R. Barwig
    
	
 
    	
Name: 
    	
Nancy R.   Barwig
    
	
 
    	
Title: 
    	
Credit   Executive
    

 

 

	
 
    	
UNION   BANK, N.A., as a Bank
    
	
 
    	
 
    
	
 
    	
By: 
    	
/s/   Efrain Soto
    
	
 
    	
Name: 
    	
Efrain   Soto
    
	
 
    	
Title: 
    	
Vice   PresidentExhibit 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

 

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

 

1.2          Subsequently, 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.

 

1.3          APS 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.

 

1.4          The terms of this Agreement are just, reasonable, fair, and in the public interest in that they, among other things, establish just and reasonable rates for APS customers; promote the 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.

 

1.5          The 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.

 

1.6          The 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

 

2.1          APS 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

 

3.1          APS 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.

 

3.2          The 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

 

4.1          When 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.

 

4.2          Subsequent 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.

 

4.3          A 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

 

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

 

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

 

5.3          A 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.

 

5.4          The 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

 

6.1          With 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.

 

6.2          The 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.

 

6.3          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 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

 

7.1          The 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”).

 

7.2          For 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.

 

7.3          The 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.

 

7.4          To 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.

 

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

 

VIII.       RENEWABLE ENERGY

 

8.1          APS 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.

 

8.2          Effective 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.

 

8.3          On 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.

 

8.4          To 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

 

9.1          The 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.

 

9.2          The 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.

 

9.3          To 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.

 

10

 

9.4          The 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.

 

9.5          For 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

 

9.6          APS 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.

 

9.7          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. 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.

 

11

 

9.8           Residential 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.

 

9.9           APS 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.

 

9.10         On 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.

 

9.11         The 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.

 

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

 

9.13         The 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.

 

9.14         For 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

 

12

 

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 

 

13

 

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.

 

9.15         APS 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.

 

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

 

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

 

14

 

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

 

10.1         In 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”).

 

10.2        Except 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.

 

10.3         Any 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.

 

15

 

10.4         The 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.

 

10.5         If, 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

 

11.1         For 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.

 

11.2         APS 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.

 

11.3         APS 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.

 

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

 

11.5         The 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

 

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

 

16

 

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.

 

12.2         Beginning with the effective date of the Commission decision resulting from APS’s next general rate case, any final property tax rate deferral that has a positive balance will be recovered from customers over 10 years and any deferral that has a negative balance will be refunded to customers over 3 years.

 

12.3         The 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

 

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

 

13.2         The 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.

 

13.3         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 by May 15 of each year.

 

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

 

17

 

XIV.       LOW INCOME PROGRAMS

 

14.1         In 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.

 

14.2         PSA 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)

 

15.1         Version 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

 

16.1         Within 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

 

17.1         The 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.

 

18

 

17.2         APS 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.

 

17.3         As 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.

 

17.4         APS 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.

 

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

 

XVIII.    COMPLIANCE MATTERS

 

18.1         Within 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.

 

18.2         APS 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

 

19

 

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.

 

18.3         Decision 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

 

19.1         Nothing in this Agreement shall prevent APS from requesting a change to its base rates in the event of conditions or circumstances that constitute an emergency.  For the purposes of this Agreement, the term “emergency” is limited to an extraordinary event that, in the Commission’s judgment, requires base rate relief in order to protect the public interest.  This provision is not intended to preclude 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

 

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

 

20.2         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.

 

20.3         This 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.

 

20.4         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

 

20

 

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

 

20.5         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 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

 

21.1         This case has attracted a large number of participants with widely diverse interests. To achieve consensus for settlement, many participants are accepting positions that, in any other circumstances, they would be unwilling to accept.  They are doing so because this Agreement, as a whole, is consistent with 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.

 

21.2         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.

 

21.3         Neither 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.

 

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

 

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

 

21

 

21.6         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 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.

 

21.7         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.

 

22

	
  

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

Source: [{"source": "alea-institute/alea-institute/kl3m-data-edgar-agreements/train-00199-of-00352.parquet"}, [{"source": "alea-institute/alea-institute/kl3m-data-edgar-agreements/train-00199-of-00352.parquet"}]]