Arkansas Public Service Commission Tariff ("TF") Docket Summary Cover Sheet

Transcription

APSC FILED Time: 4/8/2013 11:08:44 AM: Recvd 4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
Arkansas Public Service Commission
Tariff ("TF") Docket Summary Cover Sheet
Must be filed with each new TF docket filed at the Commission
STYLE OF DOCKET: (Style may be changed by Secretary of Commission)
IN THE MATTER OF THE APPLICATION OF ENTERGY ARKANSAS,
INC. FOR APPROVAL OF ENERGY EFFICIENCY PROGRAMS AND
COST RATE RIDER
DOCKET DESIGNATOR:
TF
LAST RATE CASE DOCKET:
Docket Number:
07-085-TF
09-084-U
Does this change company name:
Yes
No
PETITIONER
Entergy Arkansas, Inc.
ATTORNEY(S’) NAME, ADDRESS, PHONE, FAX AND E-MAIL
Mr. Matthew R. Suffern, Entergy Services, Inc., 425 W. Capitol Ave.,
P. O. Box 551, Little Rock, AR 72203, 501-377-5855, fax 501-3775426, [email protected]
Write a brief statement, limited to the space provided herein describing the case that you are filing. Please provide
enough information to assure that the nature of your docket is clear.
EAI requests APSC approval of the revisions to Rate Schedule No. 40, Energy Efficiency Cost Rate Rider (Rider
EECR) Attachments A, B and C including the 2013 update to the Rider EECR Rates and Rate Calculation. EAI is also
filing the supporting testimonies of Jeremy W. Champlin, Charles E. DeGeorge, and Margaret L. McCloskey.
Pursuant to Rule 2.03(b), of the Commission's Rules of Practice and Procedure, please provide name, address,
phone, fax, e-mail of at least one person, but not more than two, to appear on the Service List for this docket
Mr. Matthew R. Suffern, Entergy Services, Inc., 425 W. Capitol Ave., P. O. Box 551, Little Rock, AR 72203, 501377-5855, fax 501-377-5426, [email protected]; Steven K. Strickland, Entergy Arkansas, Inc., 425 W. Capitol
Ave., P. O. Box 551, Little Rock, AR 72203, 501-377-4457, fax 501-377-4415, [email protected]
1. Number of customers by class affected by this tariff change: Residential 583,968
,Commercial 89,404 Industrial 20,609 Public Agencies, institutions or others 677
2. Company's current authorized retail revenue requirement: $38.6M current Rider EECR
Revenue Requirement for 2012
3. Estimated annual retail revenue impact if proposal is approved, both in dollars and as a
percentage of current retail revenue requirement: $24.5M or 63%
4. Estimated monthly impact on an average residential customer in both dollars and
percentage increase: $1.44 increase for 1,000 kWh avg residential usage or 68.2%
5. Proposed effective date: June 1, 2013 or, if necessary, the first billing cycle of the month following
APSC approval of EAI's Rider EECR Attachments A, B, and C.
Form completed by: Matthew R. Suffern
Representing: Entergy Arkansas, Inc.
Date: 4-8-13
Entergy Arkansas, Inc.
425 West Capitol Avenue
P. O. Box 551
Little Rock, AR 72203-0551
Tel 501 377 4457
Fax 501 377 4415
Steven K. Strickland
Vice President
Regulatory Affairs
April 8, 2013
Ms. Kristi Rhude, Secretary
Arkansas Public Service Commission
P. O. Box 400
1000 Center Street
Little Rock, AR 72203
Re:
Docket No. 07-085-TF
In the Matter of the Application of Entergy Arkansas, Inc.
For Approval of Energy Efficiency Programs and Energy
Efficiency Cost Rate Rider
Dear Ms. Rhude:
Please find attached for filing with the Arkansas Public Service Commission
(APSC), Entergy Arkansas, Inc.’s (EAI or the Company) request for approval of
the revised Rate Schedule No. 40, Energy Efficiency Cost Rate Rider (Rider
EECR) Attachments A, B, and C reflecting the revised Rider EECR Rates and
Rate Calculation.
EAI has calculated its 2013 Rider EECR Rate using the estimated 2013 program
costs as included in EAI’s Energy Efficiency Three-Year Plan approved by the
Commission in Order No. 39 of the above referenced docket and adjusted as
described in the Direct Testimony of Jeremy E. Champlin submitted in support of
this filing.
As explained by Mr. Champlin, EAI’s budget adjustments are within the APSC’s
budget flexibility guidelines, with one exception. EAI has proposed to remove 17
percent of the original approved budget from the Energy Star New Homes
Program and add the amount to the Multi-family Home Program. In accordance
with the Order No. 39 budget flexibility directives, EAI requests Commission
approval to remove more than 10 percent of the budget for the Energy Star New
Homes Program.
Additionally, Mr. Champlin describes the calculation of the Lost Contribution to
Fixed Costs (LCFC) to be recovered through Rider EECR in accordance with the
Commission’s Order No. 14 issued December 10, 2010 in Docket No. 08-137-U
APSC FILED Time:
Ms. Kristi Rhude
April 8, 2013
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and the calculation of EAI’s incentive based on EAI’s 2012 program results in
accordance with Order No. 15 issued December 10 in Docket No. 08-137-U.
Additional details regarding the 2012 actual program costs and the calculation of
LCFC and incentives is provided in the Company’s 2012 Energy Efficiency
Program Portfolio Annual Report filed concurrently in this docket.
Also submitted is the Direct Testimony of Charles E. DeGeorge, which describes
the avoided energy and capacity costs used in the economic evaluation of EAI’s
energy efficiency programs.
Finally, EAI also submits the Direct Testimony of Margaret L. McCloskey, which
supports the calculation of the Rider EECR rates. The revised Attachments A, B,
and C are attached to Ms. McCloskey’s direct testimony as EAI Exhibit MLM-3.
The monthly bill of a typical residential customer using 1,000 kWh per month
would increase by $1.44 or 68.2 percent if the revised Rider EECR rates are
approved.
EAI respectfully requests Commission approval of the revised Rider EECR,
Attachments A, B, and C and approval of the request to reduce the budget for the
Energy Star New Homes Program by more than 10 percent. The terms of Rider
EECR specify an effective date of the first billing cycle of June for redetermined
rates.
If the Rider EECR rates are not resolved in time for a June
implementation, EAI requests APSC approval for an effective date of the first
billing cycle of the month following approval of the Rider EECR. If you have any
questions or need anything additional concerning this filing, please call me at
(501) 377-4457 or Susan Davidson at (501) 377-5720.
Work papers supporting the revised calculation of the tariff rates will be provided
to parties in this docket via electronic mail and CDs.
Sincerely,
/s/ Steven K. Strickland
SS/sd
Attachments
c:
All parties of record w/ attachments
BEFORE THE
ARKANSAS PUBLIC SERVICE COMMISSION
IN THE MATTER OF THE APPLICATION
OF ENTERGY ARKANSAS, INC. FOR
APPROVAL OF ENERGY EFFICIENCY
PROGRAMS AND ENERGY EFFICIENCY
COST RATE RIDER
)
)
)
)
)
DOCKET NO. 07-085-TF
DIRECT TESTIMONY
OF
JEREMY W. CHAMPLIN
PROJECT MANAGER
ON BEHALF OF
ENTERGY ARKANSAS, INC.
APRIL 8, 2013
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Direct Testimony of Jeremy W. Champlin
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1
I.
INTRODUCTION AND BACKGROUND
2
Q.
PLEASE STATE YOUR NAME, BUSINESS ADDRESS, EMPLOYER AND
JOB TITLE.
3
4
A.
My name is Jeremy W. Champlin. I am employed by Entergy Arkansas,
5
Inc. (“EAI” or the “Company”) as a Project Manager. My business address
6
is 425 West Capitol Avenue, Little Rock, Arkansas 72201.
7
8
Q.
ON WHOSE BEHALF ARE YOU TESTIFYING?
9
A.
I am submitting this direct testimony to the Arkansas Public Service
Commission (“APSC” or the “Commission”) on behalf of EAI.
10
11
12
Q.
DESCRIBE
YOUR
WORK
EXPERIENCES
AND
EDUCATIONAL BACKGROUND.
13
14
PLEASE
A.
I have a Bachelor of Science with an emphasis in Business Administration
15
from Arkansas State University and a Master of Business Administration
16
from Webster University. I am a certified Business Energy Professional.
17
Since 2003 I have worked in various areas within EAI and Entergy
18
Services, Inc. (“ESI”),1 including Customer Service, Work Force
19
Management, and Energy Efficiency. I have held numerous positions
20
including Customer Service Agent, Account Sales Associate, Senior
21
Customer
Service
Specialist
and
1
Supervisor
over
Work
Force
ESI is a subsidiary of Entergy Corporation that provides technical and administrative services to
the Entergy Operating Companies. The Entergy Operating Companies include EAI.; Entergy Gulf
States Louisiana, L.L.C.; Entergy Louisiana, LLC (“ELL”); Entergy Mississippi, Inc.; Entergy New
Orleans, Inc.; and Entergy Texas, Inc.
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Management.
2
Integrated Resource Planning Group.
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My current position is Project Manager within the
3
4
Q.
WHAT ARE YOUR CURRENT DUTIES AS PROJECT MANAGER?
5
A.
My current duties include identifying, developing, and implementing
energy efficiency programs for EAI customers.
6
7
8
Q.
WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY?
9
A.
The purpose of my direct testimony is to support EAI’s 2013 Energy
10
Efficiency Cost Rate Rider (“Rider EECR”) annual rate redetermination. In
11
my testimony, I provide a summary of the Company’s projected 2013
12
budget utilized in the rate redetermination calculation. I also provide a
13
summary of the actual costs for the program year 2012, which EAI
14
incorporated into its Rider EECR over/under recovery true-up calculation.
15
In addition, I explain the calculation of the estimated Lost
16
Contribution to Fixed Costs (“LCFC”) associated with EAI’s cumulative
17
2013 projected energy savings for its Energy Efficiency Programs and the
18
true-up of the 2012 LCFC estimate, consistent with the direction provided
19
by the Commission in Order No. 14 in Docket No. 08-137-U.
20
explain the calculation of EAI’s incentive amount associated with its 2012
21
program results in accordance with Order No. 15 in Docket No. 08-137-U.
I also
22
In addition to my testimony, Margaret L. McCloskey, Manager, Fuel
23
and Special Riders for ESI, explains the calculation of the Rider EECR
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rates that the Company is filing in the 2013 update. The revised Rider
2
EECR with Attachments A, B, and C is attached to Ms. McCloskey’s direct
3
testimony as EAI Exhibit MLM-3.
4
Manager, Supply Planning and Analysis for ESI’s System Planning and
5
Operations (“SPO”) organization,2 provides direct testimony describing the
6
avoided cost amounts used in the benefit-cost analyses.
Additionally, Charles E. DeGeorge,
7
8
II.
2013 PROGRAM BUDGETS
9
Q.
WHAT DOES THE PROJECTED 2013 PROGRAM BUDGET INCLUDE?
10
A.
The Company’s 2013 budget utilized in the Rider EECR rate
11
redetermination calculation includes the estimated 2013 program costs for
12
the programs contemplated under EAI’s Three-Year Plan for the 2011-
13
2013
14
Commission in Order No. 39 issued in this docket on June 30, 2011, as
15
revised to reflect adjustments to program budgets based upon further
16
program design and third party implementer contract negotiations. The
17
2013 budget also includes EAI’s share of the Arkansas Weatherization
18
Program (“AWP”) funding amount for 2013 in accordance with EAI
19
program budget filed on March 1, 2011 and approved by the Commission
20
on June 30, 2011.
21
million plus all projections of additional allocated cost associated with EAI
Program Years (the
“Three-Year Plan”) approved by the
This filing includes a projected AWP cost of $1.2
2
SPO provides various technical and administrative services to the Entergy Operating
Companies, including procuring fuel and purchased power for the Entergy Operating Companies
and operating and dispatching the generation resources of the Operating Companies.
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administration; AWP database; projected evaluation, measurement, and
2
verification (“EM&V”) consultant cost; and allocation of the Independent
3
Evaluation Monitor (“IEM”) cost.
4
Arkansas (“EEA”) Program funding amount for 2013 is included in
5
accordance with the Third Amended Memorandum of Understanding filed
6
December 4, 2012 in Docket No. 07-083-TF and approved by the
7
Commission in Order No. 31 issued on December 31, 2012, including an
8
allocation of projected EAI administration and IEM cost based upon
9
allocation methodology directions provided in the Arkansas Energy
Furthermore, the Energy Efficiency
Efficiency Program.3
10
11
12
Q.
WHAT IS THE PROJECTED SPENDING IN THE BUDGET FOR EACH
13
PROGRAM COMPARED TO THE BUDGET FOR 2013 INCLUDED IN
14
THE THREE YEAR PLAN?
15
A.
Table 1 below shows the revised 2013 Annual Budget and the variance by
program compared to the March 1, 2011 Three-Year Plan.
16
17
18
3
Arkansas Energy Efficiency Program Portfolio Annual Report Instructions, Section II. - EE
Program Cost, subsection H. - Allocation Methodology.
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Table 1
2013 Program Plan Final Budget Compared to Filed Budget
1
2
2013
Filed
Budgets
(ThreeYear Plan)
($000)
EAI Programs
2013
Final
Budget
($000)
Difference
($000)
Percent
Difference
to Overall
Cost
Residential Lighting and Appliances
Residential & Small Commercial
Cooling Solutions
4,319
4,447
128
2.96%
1,939
2,406
467
24.1%
Home Energy Solutions
4,255
4,330
75
1.76%
Energy Efficiency Arkansas
1,000
232
(768)
(76.8%)
AR Weatherization
1,200
1,279
79
6.58%
Benchmarking
1,992
1,487
(505)
(25.35%)
640
531
(109)
(17.03%)
2,588
3,417
829
32%
Mobile Homes
869
836
(33)
(3.80%)
Multifamily Direct Install
349
426
77
22.06%
12,694
12,956
262
2.06%
2,719
2,902
183
6.73%
12,006
11,333
(673)
(5.61%)
Agricultural Irrigation Load Control
4,006
4,131
125
3.12%
Small Commercial Direct Install
1,401
1,677
276
19.7%
589
642
53
9%
52,566
53,032
466
0.89%
ENERGY STAR Homes
Direct Load Control
C&I Prescriptive
City Smart
C&I Custom
Agricultural Energy Solutions
Total Portfolio
3
4
Q.
PROGRAM BUDGET BY PROGRAM.
5
6
PLEASE EXPLAIN THE REASONS FOR THE VARIATION IN THE 2013
A.
The 2013 budget variance is based upon final contract negotiations with
7
implementing contractors, EM&V contractors, database contractors, and
8
third-party auditors.
9
contractor support for the Technical Reference Manual (“TRM”) V3.0
In addition, the budget is increased to reflect
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update that is required to be filed in 2013.
The budgets also reflect
2
changes associated with revisions necessary to reflect the EEA revised
3
budgets reflected in the Third Memorandum of Understanding.
4
All program budgets were adjusted for additional EM&V cost, based
5
upon the final contract with Cadmus and ADM Associates for direct
6
program evaluation cost.
7
cost, and EAI’s share of the EM&V cost from Cadmus (EAI and
8
Southwestern Electric Power Company both contracted with Cadmus)
9
were allocated to each program based upon the ratio of each program’s
The final contracted database cost, the IEM
budget to the sum of the total budget.
10
11
12
Q.
IS EAI REQUESTING A REVISION IN ANY PROGRAM BUDGETS?
13
A.
Yes.
EAI is requesting additional budget amounts in 2013 to
14
accommodate more robust EM&V for the Residential Load Control
15
Program at the request of independent evaluator, Cadmus.
16
Further, EAI is requesting to increase administration budgets by
17
$200,000 to initiate more awareness for all programs.
18
continue to grow within EAI’s service territory, the 2012 independent
19
evaluation report from Cadmus indicated that additional awareness efforts
20
of all programs, and especially the residential and small business
21
programs would be beneficial, and is needed to drive more market activity,
22
provide support for the trade allies, and help customers differentiate
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As programs
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1
between EAI energy efficiency programs and possible efforts to defraud
2
customers by scammers.
3
EAI’s final budget adjustments are within the budget variance
4
directives in Order No. 39 in Docket No. 07-085-TF4 with the exception of
5
the Energy Star New Homes Program. This is due to the anticipation of
6
poor new home construction projects that was also experienced in 2012.
7
EAI has proposed to remove 17 percent of the original approved budget
8
from that program and increase the Multi-family Home Program by 22
9
percent. In accordance with the Order No. 39 budget flexibility directives,
10
EAI requests Commission approval to remove more than 10 percent of the
11
budget for the Energy Star New Homes Program to the Multi-family Home
12
Program.
13
14
Q
CAPITAL COSTS?
15
16
WHAT PORTION OF THE 2013 PROJECTED PROGRAM COSTS ARE
A.
The 2013 projected program costs include $2,417,415 of capital costs
17
associated with the development of software and installation of the
18
equipment and facilities for EAI’s Agricultural Irrigation Load Control
19
(“AILC”) Program.
20
4
The APSC issued Order No. 72 in this docket on November 16, 2012, approving EAI’s request
to extend the budget flexibility provided by Order No. 39 to the 2013 program year.
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III.
2012 ACTUAL PROGRAM COSTS
2
Q.
WHAT WERE THE ACTUAL AND BUDGETED EXPENDITURES FOR
THE 2012 PROGRAM YEAR?
3
4
A.
The actual incremental expenditures recoverable through Rider EECR for
5
the 2012 program year totaled $28,515,019.
The 2012 budget was
6
$39,609,138. EAI’s Energy Efficiency Program Portfolio Annual Report for
7
the 2012 program year filed concurrently in this docket provides a detailed
8
description of the 2012 program year results.
9
10
Q
COSTS?
11
12
WHAT PORTION OF THE 2012 PROGRAM COSTS WERE CAPITAL
A.
The 2012 actual costs include $2,845,809 of capital expenditures
13
associated with the installation of the equipment and facilities for EAI’s
14
AILC Program.
15
16
Q.
EXPENDITURES FOR ITS ENERGY EFFICIENCY PROGRAMS?
17
18
WHAT PROCESSES DID EAI UTILIZE TO TRACK THE ACTUAL
A.
EAI developed project codes to capture both the non-incremental and the
19
incremental5 costs associated with each program. These project codes
20
were shared with departments that are involved with a particular
21
program’s development and implementation so that program costs could
5
Section 7 of the Rules for Conservation and Energy Efficiency Programs provides that cost
recovery shall be limited to the incremental costs which represent the direct program costs that
are not already included in the then current rates of the utility.
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be charged to the appropriate code. The project codes established for the
2
AILC Program included a separate project code to accumulate the
3
incremental capital expenditures.
4
5
IV.
BENEFIT-COST TEST RESULTS
6
Q.
WHAT WERE THE PROJECTED BENEFIT-COST ANALYSIS RESULTS
FOR THE 2013 PROGRAM YEAR?
7
8
A.
The 2013 program year with the updated budgets described above,
results in a projected portfolio net benefit of $24,758,065 and a benefit-
9
cost ratio of 1.27 based upon Total Resource Cost (“TRC”) Test.
10
11
12
Q
WHAT WERE THE BENEFIT-COST ANALYSIS RESULTS FOR 2012?
13
A.
EAI performed a benefit-cost test on the evaluated savings for the 2012
14
program year. The TRC Test remained positive with a TRC net present
15
value of $9,975,512 and a TRC ratio of 1.23. Of the 15 programs, 9
16
programs achieved a TRC ratio above 1.0 with 6 programs falling below.
17
As discussed last year, the primary concern for these benefit-cost analysis
18
results are due to low avoided cost. Further, the TRC Test results for
19
three programs, Energy Star New Homes, Residential Benchmarking and
20
Agricultural Energy Solutions, were below due to market conditions and/or
21
a late start in the market due to the length of time required to conduct
22
thorough due diligence prior to completing contracts with third-party
23
implementers to ensure that customer information is protected. The cost
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effectiveness of the Energy Solutions Manufactured Homes Program was
2
greatly affected by the change in avoided cost, as well as a lower than
3
expected net-to-gross (“NTG”) ratio.
4
changes to this program so that it can achieve more cost effective results.
In any case, EAI is considering
5
The AILC Program had a TRC ratio of 0.98 due to unexpected
6
customers opting out due to severe drought. Commercial & Industrial
7
(“C&I”) Custom Solutions Program received evaluation results that did not
8
capture all of the savings associated with EAI’s costs for that program, a
9
result that was not and could not have been anticipated.
EAI’s 2012 Annual Report filed concurrently in this docket provides
10
more details on each program
11
12
13
V.
CALCULATION OF LCFC
14
Q.
HOW DID EAI CALCULATE THE LCFC FOR EACH PROGRAM YEAR?
15
A.
LCFC is a cumulative amount based on the LCFC for individual program
16
years, which are accumulated until the Company implements new base
17
rates as a result of a general rate case decision. Upon the implementation
18
of new base rates the cumulative portion of the LCFC calculation is reset.
19
With EAI’s base rate filing made March 1, 2013 (Docket No. 13-028-U),
20
this effectively means that, from a cumulative perspective, EAI’s LCFC
21
calculation will reset.
22
Each year, the LCFC for the current program year is based on the
23
projected energy savings targets approved in the Company’s energy
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efficiency program plan (“Projected LCFC”). The target is adjusted based
2
upon the First Year Monthly Curve Ratio to reflect the timing of measures
3
installed throughout a calendar year from industry best practice
4
programs.6 The adjustment based upon the First Year Monthly Curve
5
Ratio then is used to reduce the potential for over-collection of LCFC
6
associated with all energy efficiency program measures being installed
7
throughout the first calendar year. The adjusted projected energy savings
8
are then multiplied by the average rate class annualized Lost Contribution
9
Rate (“Average LCR”). The Average LCR is the base rate revenues less
10
customer charge revenues calculated on a dollar per kWh basis, using the
11
Company’s most recently approved base rates.
12
The current program year LCFC also includes the prior years’ full
13
year LCFC amounts for each program year accumulated since base rates
14
were last set. The prior years’ LCFC amounts are calculated based on the
15
actual evaluated energy savings achieved, on a measure by measure
16
basis, multiplied by the seasonal rate schedule base rates less customer
17
charges (“Seasonal LCR”). The prior years’ measures are reviewed and
18
adjusted if the efficiency measures installed have reached the end of their
19
lives.
20
Also, each year, the prior year’s LCFC amount is trued-up. The
21
projected portion of the prior year’s LCFC is recalculated based on actual
6
The First Year Monthly Curve Ratio is a ratio developed by ICF International specifically for EAI
to adjust the projected annual energy savings to reflect the number of months the measures are
installed during the first year of the life of the measures. The last year of the life of the measures
will be adjusted during the annual true-up process.
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evaluated energy savings achieved adjusted to reflect the measure
2
installed date, multiplied by the Seasonal LCR.
3
4
Q.
WHAT IS THE 2013 LCFC?
5
A.
As I explained above, the 2013 LCFC includes the projected 2013 LCFC
6
and the full year trued-up LCFC for 2011 and 2012. The 2013 first year
7
estimated LCFC is $2,530,087. The 2011 full year LCFC is $1,917,064.
8
The 2012 full year LCFC is $4,952,694. The cumulative total 2013 LCFC
9
is $9,399,844.
10
11
Q.
WHAT IS THE 2012 TRUED-UP LCFC ?
12
A.
As I explained above, the 2012 LCFC includes the true-up of the projected
13
2012 program year LCFC and the full year trued-up LCFC for 2011. The
14
2012 prorated trued-up LCFC is $1,410,888. The 2011 full year LCFC is
15
$1,917,064. The cumulative total LCFC for 2012 is $3,327,951.
16
The 2012 true-up prorated LCFC is less than the projected 2012
17
prorated amount because some programs were implemented later than
18
planned due to the length of time required to conduct thorough due
19
diligence prior to completing contracts with third-party implementers to
20
ensure that customer information is protected. Further, the timing of the
21
2012 actual measure installations were different than the installation
22
curves projected. More of the energy efficiency measures were installed
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later in the year than originally planned. The 2012 Annual Report contains
2
a more detailed discussion of the 2012 program results.
3
4
VI.
INCENTIVE CALCULATION
5
Q.
DID EAI’S 2012 PROGRAM YEAR ENERGY SAVINGS PERFORMANCE
6
TOWARD THE COMMISSION’S ENERGY SAVINGS TARGETS ALLOW
7
THE COMPANY TO EARN A UTILITY PERFORMANCE INCENTIVE
8
AWARD?
9
A.
Yes.
Q
PLEASE DESCRIBE EAI’S CALCULATION OF THE PERFORMANCE
10
11
12
INCENTIVE INCLUDED IN ITS REQUEST FOR RECOVERY THROUGH
13
RIDER EECR.
14
A.
In Order No. 15 of Docket No. 08-137-U, the APSC provided directives as
15
to both the qualification and calculation of incentives. Under that order,
16
the program year evaluated savings results must meet at least 80 percent
17
of the goal established by the Commission for a utility to qualify for an
18
incentive. The calculation includes a shared savings amount based upon
19
10 percent of the portfolio Net Present Value of the TRC Test, but not to
20
exceed 5 percent of portfolio budget if evaluated goal achievement is at
21
least 80 percent up to 100 percent and not to exceed 7 percent of portfolio
22
budget for evaluated goal achievement at 100 percent up to 110 percent.
- 14 -
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
EAI’s target for 2012 was 96,694 MWh of energy reductions.7 EAI’s
2
evaluated energy savings for 2012 is 107,627 MWh before line loss
3
adjustments.8 This result of 111 percent of target qualifies EAI to obtain
4
incentives. Because EAI achieved over 100 percent target, the Company
5
qualifies at the program cost cap of 7 percent. The 7 percent cap is
6
applied to the final 2012 program budget of $39,609,138 resulting in a
7
maximum possible incentive of $2,772,640. The program portfolio Net
8
Benefits based on Total Resource Cost analysis for 2012 was $9,975,512
9
and the shared savings of 10 percent is $997,551. Because the shared
10
saving amount is the less than the 7 percent cost cap, EAI’s incentive
11
amount is $997,551. EAI included this incentive amount in the total costs
12
to be included in the EECR recovery amount.
13
14
Q.
DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
15
A.
Yes, it does.
7
EAI’s energy savings target for 2012 of 105,413 MWh as reported in EAI’s Three-Year Plan is
reduced to reflect the impact of the Self-Direct customer’s exempted usage as provided by the
APSC’s Rules for Conservation and Energy Efficiency Programs, Section 11, subsection O.
8
EAI’s evaluated energy savings results reflect the application of NTG adjustments as directed
by the Commission. See Docket No. 07-152-U, Order No. 7; Docket No. 08-137-U, Order No. 16;
Docket No. 08-144-U, Order No. 18; Docket No. 10-010-U, Order No. 13; Docket No. 10-100-R,
Order No. 1; Docket No. 10-101-R, Order No. 2 at 16-17 (collectively December 10, 2010).
- 15 -
CERTIFICATE OF SERVICE
I, Steven K. Strickland, do hereby certify that a copy of the foregoing has
been served upon all parties of record by forwarding the same by electronic mail
and/or first class mail, postage prepaid this 8th day of April 2013.
BEFORE THE
COST RATE RIDER
)
)
)
)
)
DIRECT TESTIMONY
OF
MARGARET L. MCCLOSKEY
MANAGER, FUEL & SPECIAL RIDERS
ENTERGY SERVICES, INC.
ON BEHALF OF
APRIL 8, 2013
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
Direct Testimony of Margaret L. McCloskey
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
I.
INTRODUCTION
2
Q.
PLEASE STATE YOUR NAME.
3
A.
My name is Margaret L. McCloskey.
Q.
ARE YOU THE SAME MARGARET L. MCCLOSKEY WHO FILED
4
5
TESTIMONY PREVIOUSLY IN THIS DOCKET?
6
A.
Yes, I am
9
Q.
10
A.
I am submitting this direct testimony to the Arkansas Public Service
7
8
11
Commission (“APSC” or the “Commission”) on behalf of Entergy
12
Arkansas, Inc. (“EAI” or the “Company”).
13
14
Q.
15
A.
My direct testimony describes the calculation of the rates that the
16
Company is filing in the 2013 update to EAI’s Rate Schedule No. 40,
17
Energy Efficiency Cost Rate Rider (“Rider EECR”), including EAI’s rate
18
class recovery allocation methodology as well as the Lost Contribution to
19
Fixed Costs (“LCFC”) and incentives. Attached as EAI Exhibit MLM-3 are
20
proposed Attachments A, B, and C, which reflect the Rider EECR Rates
21
and rate calculation for the billing period June 2013 through May 2014.
22
23
-2-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
II.
RIDER EECR TARIFF REVISION
2
Q.
WHAT METHOD DOES THE COMPANY PROPOSE TO USE TO
3
ALLOCATE THE COSTS OF
4
PROGRAMS AND LCFC TO THE RATE CLASSES?
5
A.
ITS 2013
ENERGY EFFICIENCY
EAI proposes to allocate the costs of its 2013 Energy Efficiency Programs
6
and the LCFC using the production demand allocation factor (“PDAF”)
7
approved in the Company’s most recent rate case adjusted to remove the
8
customer accounts that are exempt from the Rider EECR charge for the
9
Filing Year based on the Certificates of Exemption currently approved by
the Commission pursuant to the Self-Direct Option.
10
11
12
Q.
WAS
THE
PDAF
SELECTED
AS
THE
ALLOCATION
METHODOLOGY FOR RIDER EECR?
13
14
WHY
A.
EAI’s Energy Efficiency Programs and the related LCFC provide
15
significant benefits, including the reduction in demand-related production
16
costs. Production costs are allocated based on either demand or energy,
17
and because these costs are demand-related, it is appropriate to use the
18
PDAF to allocate these costs.
19
methodology used to allocate costs in the prior year’s Rider EECR rate
20
calculation including the adjustment for the Self-Direct Option as
21
described above.
This is consistent with the allocation
22
-3-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
1
Q.
DOES THE REVENUE REQUIREMENT INCLUDE RECOVERY OF
CAPITAL COSTS?
2
3
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
A.
Yes.
In EAI Exhibit MLM-3, EAI has included a revenue requirement
4
calculation associated with incremental capital costs incurred in
5
connection with EAI’s Agricultural Irrigation Load Control (“AILC”)
6
Program1 and included that revenue requirement within the total revenue
7
requirement for EAI’s energy efficiency programs to be recovered through
8
the redetermined Rider EECR rate for 2013.
9
Consistent with the methodology used in prior years’ Rider EECR
10
updates, the AILC revenue requirement is the sum of the return on rate
11
base calculated by applying the before-tax rate-of-return on rate base as
12
approved in Docket No. 09-084-U to the average rate base and the
13
projected average amortization of the AILC rate base for 2013.
14
15
Q.
RIDER EECR RATE.
16
17
PLEASE DESCRIBE THE CALCULATION OF THE REDETERMINED
A.
The redetermined Rider EECR rate is calculated by summing the 2013
projected Energy Efficiency Program costs, cumulative LCFC, and energy
18
1
The APSC issued Order No. 8 on December 28, 2010 in Docket No. 08-072-TF, approving
EAI’s Irrigation Load Control Program budgets for capital and expenses for the program years
2011 and 2012. In Order No. 39, issued in Docket No. 07-085-TF on June 30, 2011, the APSC
approved EAI’s AILC Program and budgets for program years 2011-2013 which incorporated the
2011 and 2012 AILC budgets approved in Docket No. 08-072-TF. In addition, the APSC
approved the transfer of the AILC Program to Docket No. 07-085-TF and the closing of Docket
No. 08-072-TF.
-4-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
efficiency program incentives, plus or minus an over/under recovery true-
2
up adjustment, and then multiplying this total by the rate class allocation
3
factor PDAF including the adjustment for the Self-Direct Option as
4
described above. These amounts by rate class are then divided by the
5
projected energy sales for each rate class adjusted to remove the
6
customer accounts that are currently exempt from the Rider EECR charge
7
in order to determine the rate adjustment by rate class.
8
9
Q.
THE REDETERMINED RIDER EECR RATE?
10
11
WHAT IS THE CUSTOMER IMPACT OF THE PROPOSED CHANGE IN
A.
A typical monthly residential bill for a 1,000 kWh energy usage would
12
increase by $1.44. The impact on the rate for each rate class is shown in
13
Table 1 below.
14
Table 1
15
2013 Rider EECR Update Rate Class Impact
16
Rate Class
2013
2012
Change
Residential
$0.00355/kWh
$0.00211/kWh
$0.00144/kWh
Small General Service
$0.00355/kWh
$0.00209/kWh
$0.00146/kWh
Large General Service
$0.00287/kWh
$0.00178/kWh
$0.00109/kWh
Lighting
$0.00186/kWh
$0.00110/kWh
$0.00076/kWh
-5-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
Q.
HOW MANY CUSTOMERS WILL BE AFFECTED BY THIS CHANGE?
2
A.
The number of EAI customers affected by this rate change at the end of
3
February 2013 was 694,658. This number excludes those customers that
4
are currently exempt under the Self-Direct Option as explained above.
5
6
Q.
WHAT IS THE TOTAL REVENUE IMPACT OF THIS REVISION?
7
A.
The total projected amount to be collected over the period June 2012
8
through May 2013 by the previously approved Rider EECR was
9
$38,592,488. The redetermined revenue requirement amount proposed
10
to be collected during the period June 2013 through May 2014 is
11
$63,086,302. This is an increase in the requested Rider EECR recovery
12
amount of $24,493,814 or 63 percent.
13
14
Q.
WILL THE REDETERMINATION RESULT IN ANY CHANGE IN RATE
15
DESIGN WHICH WILL RESULT IN ANY CHANGE IN REVENUE
16
ALLOCATION WITHIN A CLASS OR BETWEEN CLASSES?
A.
No.
19
Q.
DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
20
A.
Yes, it does.
17
18
-6-
and/or first class mail, postage prepaid this 8th day of April 2013.
BEFORE THE
COST RATE RIDER
)
)
)
)
)
EAI EXHIBIT MLM-3
REVISED ENERGY EFFICIENCY COST RATE RIDER AND
ATTACHMENTS A, B, AND C
APSC FILED Time: 4/8/2013 11:08:44 AM: Recvd 4/8/2013 11:02:39 AM:
DocketNo.:
07-085-TF-Doc.
380
Docket
07-085-TF
Order No.:
Effective:
5/30/13
Attachment A to
Rate Schedule No. 40
Page 1 of 2: Schedule Sheet 4 of 7
ATTACHMENT A
ENERGY EFFICIENCY COST RECOVERY TARIFF (RIDER EECR)
Line
Recoverable Costs
Program Costs
Set forth in workpapers
1 Projected Energy Efficiency Program Costs (PEEC)
$52,092,646
2 Projected Lost Contribution to Fixed Costs (LCFC)
$9,399,844
(RT, CR)
(CR)
3 EE Program Incentives (EEPI)
$997,551
4 Prior Period Over/Under Amount (TUA)*
$596,261
(CR)
$63,086,302
(CR)
5 Recoverable Costs (PCRC)** (1+2 + 3 + 4)
6 Billing Units (PES)***
See Attachment C
7 Rider EECR Rate (5/6)
See Attachment C
* The prior period true-up adjustment (TUA) includes carrying costs as
approved by the Commission.
** Projected Costs by Rate Class or “PCRC” includes the total of (1) the
projected EECR Incremental Program Costs for the Filing Year (PEEC); (2)
the projected LCFC for the Filing Year (LCFC); (3) the incentive earned
during the Reporting Year (EEPI) ; and (4) the prior period true-up adjustment
(TUA). This total is allocated to the rate classes using PDAF (see Note 4
below).
*** Projected Energy Sales by kWh or “PES” includes the projected sales by
rate class (see Note 6 below).
(AT)
DocketNo.:
07-085-TF-Doc.
380
Docket
07-085-TF
Order No.:
Effective:
5/30/13
Attachment A to
ENERGY EFFICIENCY COST RECOVERY TARIFF (CONT'D)
NOTES:
1) The Company’s work papers shall provide the rationale for the particular
billing units selected and for the assignment of the Recoverable Costs to the
rate classes.
2) The Projected Energy Efficiency Cost Period is the twelve-month period
commencing on January 1 of the Filing Year.
3) The Energy Efficiency Cost Period is the calendar year immediately
preceding the Filing Year.
4) The Production Demand Allocation Factor (“PDAF”) represents each rate
class allocation relative to the retail jurisdiction total and shall be the most
recently approved for EAI by the Commission in a non-appealable final order,
adjusted to remove the customer accounts that are exempt from the Rider
EECR charge for the Filing Year based on Certificates of Exemption currently
approved by the Commission pursuant to the Self-Direct Option.
5) The Carrying Charge Rate shall be the authorized rate of return on rate base
most recently approved for EAI by the Commission in a non-appealable final
order.
6) The Projected Energy Sales by kWh billed for each rate class (PESi) for the
Projected Energy Efficiency Cost Period, adjusted to remove the customer
accounts that are exempt from the Rider EECR charge for the Filing Year
based on the Certificates of Exemption currently approved by the
Commission pursuant to the Self-Direct Option.
THIS SPACE FOR PSC USE ONLY
(AT)
DocketNo.:
07-085-TF-Doc.
380
Docket
07-085-TF
Order No.:
Effective:
5/30/13
Attachment B to
ATTACHMENT B
RIDER EECR RATES
Applicable through May 2014
(CT)
The Net Monthly Rates set forth in EAI’s schedules identified below will be adjusted by the
following Rate Adjustment amounts:
Rate Class
Rate Schedules
Rate Adjustment
Residential
RS, RT, REMT
$0.00355 per kWh
(CR)
Small General
Service
SGS,GFS, TSS,
MP, AP, CGS
CTV, SMWHR
$0.00355 per kWh
(CR)
Large General
Service
LGS, LPS, GST
PST, SSR
$0.00287 per kWh
(CR)
Lighting
L1, L1SH, L4
$0.00186 per kWh
(CR)
THIS SPACE FOR PSC USE ONLY
DocketNo.:
07-085-TF-Doc.
380
Docket
07-085-TF
Order No.:
Effective:
5/30/13
Attachment C to
ATTACHMENT C
Rider EECR Rate Calculation
Rate Class
PCRCi1
PESi2
Rate Adjustments3
Residential
$28,212,510
7,954,833,502
$0.00355 per kWh
(CR)
Small General Service
$16,196,524
4,567,809,919
$0.00355 per kWh
(CR)
Large General Service
$18,195,730
6,346,030,839
$0.00287 per kWh
(CR)
$481,538
258,967,366
$0.00186 per kWh
(CR)
$63,086,302
19,127,641,626
Lighting
Total
(CR)
Notes:
(1) Projected Energy Efficiency Cost by Rate Class (PCRCi).
(2) Projected Energy Sales by kWh billed for each rate class (PESi) for the Projected Energy
Efficiency Cost Period, adjusted to remove the customer accounts that are exempt from the
Rider EECR charge for the Filing Year based on the Certificates of Exemption currently
approved by the Commission pursuant to the Self-Direct Option.
(3) The Rider EECR Rate is PCRCi / PESi.
(CT)
BEFORE THE
COST RATE RIDER
)
)
)
)
)
DIRECT TESTIMONY
OF
CHARLES E. DEGEORGE
MANAGER, SUPPLY PLANNING & ANALYSIS
ENTERGY SERVICES, INC
ON BEHALF OF
APRIL 8, 2013
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
Direct Testimony of Charles E. DeGeorge
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
I.
INTRODUCTION AND BACKGROUND
2
Q.
PLEASE STATE YOUR NAME, TITLE, AND BUSINESS ADDRESS.
3
A.
My name is Charles E. DeGeorge. I am employed by Entergy Services,
4
Inc. (“ESI”),1 as Manager, Supply Planning and Analysis for the System
5
Planning and Operations (“SPO”) organization.2 My business address is
6
10055 Grogans Mill Road, Parkwood II Building, Suite 150, The
7
Woodlands, Texas, 77380.
8
9
Q.
10
A.
I am testifying on behalf of Entergy Arkansas, Inc. (“EAI” or the
“Company”).
11
12
13
Q.
PLANNING AND ANALYSIS?
14
15
WHAT ARE YOUR RESPONSIBILITIES AS MANAGER, SUPPLY
A.
My current job responsibilities include long-term supply-side resource
16
planning for the Entergy Operating Companies, including EAI.
17
function I manage a staff that performs engineering and economic
18
analyses of the capacity and energy supply requirements of the Entergy
1
In this
ESI is a subsidiary of Entergy Corporation that provides technical and administrative services to
all the Entergy Operating Companies, which, in addition to Entergy Arkansas, Inc., include:
Entergy Gulf States Louisiana, L.L.C. (“EGS”); Entergy Louisiana, LLC (“ELL”); Entergy
Mississippi, Inc. (“EMI”); Entergy New Orleans, Inc. (“ENO”); and Entergy Texas, Inc. (“ETI”).
2
SPO provides various technical and administrative services to the Entergy Operating
Companies, including procuring fuel and purchased power for the Entergy Operating Companies
and operating and dispatching the generation resources of the Operating Companies.
-2-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
Electric System3 in order to provide a reliable and economical resource
2
portfolio.
3
proposals for supply-side resources (“RFPs”) issued on behalf of the
4
Entergy Operating Companies since 2002 and have managed the
5
evaluation process for numerous RFPs since 2004. I participated in the
6
Summer 2009 Request For Proposals for Long-Term Supply-Side
7
Resources (“Summer 2009 RFP”) as a member of the Summer 2009 RFP
8
Economic Evaluation Team (“EET”), which led to the selection of the
9
KGen Hot Spring Energy Facility. I have been involved in each Integrated
10
Resource Plan developed for the Entergy Electric System and the
11
Operating Companies since 2006, as well as the 2012 EAI Integrated
12
Resource Plan.
I have been involved in the evaluation of each request for
13
14
Q.
DESCRIBE
YOUR
BUSINESS
EXPERIENCE
AND
EDUCATION.
15
16
PLEASE
A.
Over the last 26 years, I have worked for ESI in various planning
17
positions, including regional planning, long-term generation planning,
18
operational generation planning, long-term transmission planning, and
19
operational transmission planning. I became Manager, Supply Planning &
20
Analysis in October 2004.
I have a Master’s Degree in Business
3
The Entergy Electric System is comprised of the generation and bulk transmission facilities of
the Operating Companies, which facilities are operated as a single, integrated electric system.
EAI’s participation in the System Agreement will terminate effective December 18, 2013.
-3-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
Administration from Texas A&M University and a Bachelor of Science
2
Degree in Electrical Engineering from the University of New Orleans. I am
3
a registered Professional Engineer in Arkansas, Louisiana, Mississippi,
4
and Texas.
5
6
Q.
COMMISSION?
7
8
HAVE YOU PREVIOUSLY TESTIFIED BEFORE A REGULATORY
A.
Yes.
I have testified before the Arkansas Public Service Commission
9
(“APSC” or the “Commission”), the Council of the City of New Orleans, the
10
Louisiana Public Service Commission, and the Public Service Commission
11
of Texas.
12
CED-1.
A listing of my prior testimonies is included in EAI Exhibit
13
14
Q.
15
A.
My direct testimony provides estimates of avoided energy and capacity
16
costs that were requested by EAI to support the economic evaluation of
17
the Company’s energy efficiency Programs.
18
assumptions, models, and processes used to develop these avoided cost
19
estimates.
20
-4-
I will describe the
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
II.
AVOIDED COSTS
2
Q.
WHAT ANALYSES AND ESTIMATES DID EAI REQUEST FROM ESI?
3
A.
EAI requested estimates of avoided costs of energy and capacity for 2012
4
– 2035 for the express purpose of performing the economic evaluation of
5
the energy efficiency programs proposed by EAI for deployment in 2012 –
6
2013.
7
8
Q.
ENERGY COSTS?
9
10
WHAT ANALYSES WERE PERFORMED TO ESTIMATE THE AVOIDED
A.
The analyses were divided into two time frames to estimate the avoided
11
energy cost. The first time frame, 2012 and 2013, represents the period
12
when EAI is still a participant in the Entergy System Agreement and is not
13
yet a participant in a Regional Transmission Organization (“RTO”). The
14
second time frame, 2014 and beyond, represents the period when EAI no
15
longer participates in the Entergy System Agreement and is assumed to
16
be a participant in the Midwest Independent Transmission System
17
Operator, Inc. (“MISO”) RTO.
18
19
Q.
TIME FRAME, THE 2012 AND 2013 PERIOD.
20
21
PLEASE DESCRIBE THE ANALYSIS PERFORMED FOR THE FIRST
A.
The avoided energy cost for this time period is based on the SPO hourly
22
spot market, economy purchase price curve because it is representative of
23
the price of power available for purchase by the Entergy System during
-5-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
this time period.
The analysis uses the hourly Market Clearing Price
2
forecast for the SERC Delta Region from the Ventyx Spring 2012 SE
3
Region Reference Case.
4
developed SPO June 2012 Henry Hub Forecast of natural gas prices.
5
This resulting economy purchase price curve is used in production costing
6
simulations as representative of the hourly spot market available for
7
purchase by the Entergy Electric System and, in practice; economy
8
energy purchases that are made or that are rejected determine the
9
avoided cost of energy in many hours.
This forecast is calibrated to the internally
10
11
Q.
COST FOR 2014 AND BEYOND?
12
13
WHAT ANALYSIS WAS USED TO ESTIMATE THE AVOIDED ENERGY
A.
The AURORAxmp Electric Market Model (“AURORA”) model was used to
14
simulate market operations and produce a long-term forecast of the
15
Locational Marginal Price (“LMP”) for the EAI commercial pricing zone as
16
part of operating in the MISO Day 2 Market.4 AURORA estimates price
17
and dispatch using hourly demands and individual resource-operating
18
characteristics in a transmission-constrained, chronological dispatch
19
algorithm.
4
Day 2 Markets are centralized region-wide markets operated by RTOs that include day ahead
unit commitments, a real time balancing market, and an integrated ancillary services market. In a
Day 2 Market, generators are required to schedule or bid into the market, locational marginal
prices are used to price the use of the transmission grid, congestion charges replace “first come,
first served” transmission service, and financial transmission rights are used to hedge congestion.
The “Day 2” label arose because these are things that RTOs began to implement after they
initially began to operate, or in Day 2 of their creation.
-6-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
2
Q.
WHAT IS MEANT BY LOCATIONAL MARGINAL PRICE?
3
A.
If EAI’s application to transfer control of its transmission assets to the
4
MISO RTO is approved, the MISO will determine the amount of energy
5
generated by each of EAI’s units.
6
commitment and dispatch for the other generating units that participate in
7
the MISO Day 2 Market.
8
generating unit in the market.
9
market commitment and dispatch, AURORA forecasts both unit-level
MISO will, similarly, determine the
MISO will then calculate a LMP for each
Through the simulation of centralized
operation and LMPs.
10
11
12
Q.
ENERGY COST?
13
14
HOW ARE LMPs USED TO DEVELOP ESTIMATES OF AVOIDED
A.
The Aurora model estimates the hourly LMP for each commercial pricing
15
zone of the MISO South footprint. EAI is divided into two load zones
16
representing EAI North Arkansas and EAI Central. A composite LMP for
17
the EAI load zones is determined by taking the load weighted share of the
18
EAI North Arkansas hourly LMP and the EAI Central hourly LMP. The
19
resulting EAI zone LMP is representative of the avoided cost of energy
20
available to EAI each hour based on participation in the MISO Day 2
21
Market.
22
-7-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
1
Q.
WHAT OTHER STEPS WERE DONE TO DETERMINE THE AVOIDED
ENERGY COST ESTIMATES?
2
3
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
A.
For both time periods, 2012 – 2013 and 2014 - 2035, once the hourly
4
avoided energy cost is determined, an avoided energy cost by time period
5
for each year is calculated by averaging all of the hourly prices within each
6
time period. The results of these analyses are the avoided energy cost
7
estimates, which are provided in highly sensitive EAI Exhibit CED-2.
8
9
Q.
ESTIMATE?
10
11
WHAT IS THE BASIS FOR THE AVOIDED CAPACITY COST
A.
The avoided capacity cost is based on the installed cost of a new
12
combustion turbine (“CT”), which is assumed to be the lowest cost long-
13
term alternative for new capacity that is under the control of EAI. SPO
14
estimated the installed cost of a CT based on the Technology Assessment
15
Guide, which is licensed from the Electric Power Research Institute. To
16
adjust the CT cost for commencing commercial operations in future years,
17
SPO used the CT Capital Cost Real Escalation Rate from IHS CERA
18
Capital Cost Analysis Forum – Power, “Power Capital Cost Index
19
Projection – North America” November 2012 and SPO’s macroeconomic
20
forecast of Gross Domestic Product. Using this approach, the installed
21
cost of a CT is determined for each year of the period 2012 – 2035 and an
22
annual levelized CT revenue requirement is determined by applying a
23
levelized fixed charge rate that is calculated for a CT.
-8-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
1
2
Q.
WHAT OTHER ADJUSTMENTS TO THE ANNUAL LEVELIZED CT
3
COST ARE INCLUDED FOR PURPOSES OF ASSESSING ENERGY
4
EFFICIENCY PROGRAMS?
5
A.
In addition to the installed cost of a CT, the reduction of demand through
6
energy efficiency programs may also potentially avoid transmission and
7
distribution line losses and capacity needed to meet reliability reserve
8
margins.
9
installed CT cost was grossed up by a line loss percentage determined for
10
residential, commercial, industrial, and total retail customer classes.
11
Similarly, to adjust for capacity needed to meet reliability reserve margins,
12
the installed CT cost was grossed up by the reserve margin assumed to
13
be needed by time period. For 2012 – 2013, the reserve margin is 16.85
14
percent based on EAI’s participation in the System Agreement, which is
15
the reserve margin target established for the Entergy Electric System.
16
Beginning with 2014, assuming participation in the MISO RTO, the
17
reserve margin is 12 percent based on historical reserve margin
18
requirements determined by MISO. The result of these adjustments is to
19
increase the installed CT cost by an amount needed to offset the cost of
20
line losses and reliability reserve margins.
To adjust for transmission and distribution line losses, the
21
-9-
APSC FILED
Entergy Arkansas,
Inc. Time: 4/8/2013 11:08:44 AM: Recvd
1
Q.
4/8/2013 11:02:39 AM: Docket 07-085-TF-Doc. 380
ARE OTHER COSTS POTENTIALLY AVOIDED BY REDUCTION IN
2
DEMAND THROUGH ENERGY EFFICIENCY PROGRAMS THAT ARE
3
REFLECTED IN THE AVOIDED CAPACITY COST ESTIMATE?
4
A.
Yes. In addition to the installed CT cost grossed up for line losses and
5
reserve margin requirements, transmission and distribution investment
6
may be avoided. An estimate of avoided transmission and distribution
7
investment was developed by Utility Operations based on the average
8
cost of actual expenditures over the prior five years, expressed as a
9
levelized annual revenue requirement in terms of $/kW-yr. Therefore, the
10
avoided capacity cost is estimated based on the installed CT cost grossed
11
up for line losses and reserve margin requirements plus an estimate of
12
avoided transmission and distribution investment. The results of these
13
analyses are the avoided levelized capacity cost estimates, which are
14
provided in highly sensitive EAI Exhibit CED-3.
15
16
Q.
DOES THIS CONCLUDE YOUR TESTIMONY?
17
A.
Yes.
- 10 -
and/or first class mail, postage prepaid, this 8th day of April 2013.
BEFORE THE
COST RATE RIDER
)
)
)
)
)
EAI EXHIBIT CED-1
LIST OF PRIOR TESTIMONY
APSC FILED Time: 4/8/2013 11:08:44 AM: Recvd 4/8/2013 11:02:39 AM: Docket
07-085-TF-Doc.
EAI Exhibit
CED-1380
Page 1 of 2
Testimony Filed by Charles E. DeGeorge
1. Public Utility Commission of Texas, Docket 37482, Application of ETI for
Approval of Power Cost Recovery Factor (EAI WBL Contract)
2. Louisiana Public Service Commission (“LPSC”), Docket U-29955, Joint
Application of ELL and EGS for Authorization to Participate in Contracts for
the Purchase of Electric Power for 2007 and for Timely Treatment (Frontier,
Block Energy Purchases, SRW, Dow, and Cottonwood Contracts)
3. LPSC, Docket U-30422, Application of EGS for Approval to Enter into
Contract for the Purchase of Electric Power from EAI Sourced from the
Ouachita CCGT Facility and Request for Timely Treatment
4. LPSC, Docket U-30192, Application of ELL for Approval to Repower the Little
Gypsy Unit 3 Electric Generating Facility and for Authority to Commence
Construction and for Certain Cost Protection and Cost Recovery
5. LPSC, Docket U-31147, Application of EGS and ELL for Approval to Enter
Into Contracts for the Purchase of Electric Power and for Timely Treatment
(EAI Wholesale Baseload (“WBL”) Contract)
6. LPSC, Docket U-31284, Joint Application of ELL and EGS for Approval to
Participate in Contracts for the Purchase of Electric Power for 2010 and for
Cost Recovery (Exelon-Frontier Contract)
7. LPSC, Docket U-31971, Joint Application of ELL for approval to construct Unit
6 at Ninemile Point Station and of EGSL for approval to participate in a
related contract for the purchase of capacity and energy and for cost recovery
APSC FILED Time: 4/8/2013 11:08:44 AM: Recvd 4/8/2013 11:02:39 AM: Docket
07-085-TF-Doc.
EAI Exhibit
CED-1380
Page 2 of 2
8. City of New Orleans (“CNO”), Docket UD-11-03, Application of Entergy New
Orleans, Inc. (“ENO”) to enter into a contract for the purchase of capacity and
energy from Unit 6 at Ninemile Point Station and for cost recovery
9. Arkansas Public Service Commission, Docket 11-069-U, Application of EAI
for approval of the acquisition of the Hot Spring Plant to serve its retail
customers
10. Arkansas Public Service Commission, Docket 12-038-U, Approval of certain
Wholesale Base Load Capacity to serve EAI customers.
BEFORE THE
COST RATE RIDER
)
)
)
)
)
EAI EXHIBIT CED-2
AVOIDED ENERGY COST ESTIMATES
THIS EXHIBIT CONTAINS HIGHLY SENSITIVE PROTECTED INFORMATION
PROVIDED PURSUANT TO THE INTERIM PROTECTIVE ORDER NO. 43 IN
APSC DOCKET 07-085-TF.
BEFORE THE
COST RATE RIDER
)
)
)
)
)
EAI EXHIBIT CED-3
AVOIDED CAPACITY COST ESTIMATES
THIS EXHIBIT CONTAINS HIGHLY SENSITIVE PROTECTED INFORMATION
PROVIDED PURSUANT TO THE INTERIM PROTECTIVE ORDER NO. 43 IN
APSC DOCKET 07-085-TF.

Arkansas Public Service Commission Tariff ("TF") Docket Summary Cover Sheet

Transcription

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