Exhibit 10.17

 

ARIZONA PUBLIC SERVICE COMPANY

 

 

PROPOSED SETTLEMENT AGREEMENT

 

 

DOCKET NO. E-01345A-11-0224

 

 

January 6, 2012

 

1

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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

 

2

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XX.

COMMISSION EVALUATION OF PROPOSED SETTLEMENT

20

 

 

 

XXI.

MISCELLANEOUS PROVISIONS

21

 

3

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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

 

8

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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

 

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(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.

 

9

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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

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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.

 

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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

 

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

 

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

 

Achievement Relative to
the Energy Efficiency 
Standard

 

Performance
Incentive as % of
Energy Efficiency
Net Benefits

 

Performance
Incentive Capped
at % of Energy
Efficiency 
Program Costs

 

Proposed 
Change from 
Current

 

 

 

 

 

 

 

 

 

<85%

 

0

%

0

%

No Change

 

 

 

 

 

 

 

 

 

85% to 95%

 

6

%

12

%

No Change

 

 

 

 

 

 

 

 

 

96% to 105%

 

7

%

14

%

No Change

 

 

 

 

 

 

 

 

 

>105%

 

8

%

16

%

New

 

 

 

 

 

 

 

 

 

106% to 115%

 

8

%

16

%

Eliminated

 

 

 

 

 

 

 

 

 

116% to 125%

 

9

%

18

%

Eliminated

 

 

 

 

 

 

 

 

 

>125%

 

10

%

20

%

Eliminated

 

 

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

 

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and methodologies, considering comments from APS and other stakeholders.

 

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

 

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

 

9.15         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.

 

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

 

10.1         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.

 

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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

 

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

 

(a)   When the property tax rate increases:

 

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

·      For 2013: 50%; and

·      For 2014 and all subsequent years: 75%.

 

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

 

No interest shall be applied to the deferred balance.

 

12.2         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.

 

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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.

 

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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

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

 

18.3         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

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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

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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.

 

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

 

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

 

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

 

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

 

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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

 

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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

 

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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

 

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

 

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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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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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

 

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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

 

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

 

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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

 

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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

 

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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

 

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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

 

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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

 

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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

 

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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

 

 

[g36704ku07i001.gif]

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

 

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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

 

[g36704ku07i003.gif]

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

 

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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

 

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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

--------------------------------------------------------------------------------

 

 

[g36704ku08i001.gif]

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

--------------------------------------------------------------------------------

 

[g36704ku10i001.gif]

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

--------------------------------------------------------------------------------

 

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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

 

[g36704ku17i002.gif]

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

 

[g36704ku17i003.gif]

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

 

[g36704ku17i004.gif]

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

 

[g36704ku17i005.gif]

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

 

[g36704ku17i006.gif]

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

 

[g36704ku17i007.gif]

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 - -

 

[g36704ku17i008.gif]

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 - - - - - - - - -

 

[g36704ku17i009.gif]

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 - - - - - - - - - - - - - - - - - - - - - - - - - - - -
- - - - - -

 

[g36704ku17i010.gif]

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

--------------------------------------------------------------------------------

 

[g36704ku23i001.gif]

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

 

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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

 

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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

 

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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

 

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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

 

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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%

 

 

 

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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 -------

 

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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

 

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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

 

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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

 

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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 - - - - - - - -

 

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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 - - -
- - - - - - - - -

 

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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

 

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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

 

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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

 

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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

 

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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

 

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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

 

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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

 

[g36704ku25i014.gif]

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

 

[g36704ku25i015.gif]

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.

 

[g36704ku25i016.gif]

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.

 

[g36704ku25i017.gif]

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

 

 

--------------------------------------------------------------------------------