Resolution No. 100051
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RESOLUTION NO. 101005
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF
VERNON ADOPTING A NEW TRANSMISSION REVENUE
REQUIREMENT ASSOCIATED WITH VERNON'S HIGH VOLTAGE
(OVER 200 KV) ENTITLEMENTS LOCATED OUTSIDE OF THE
CITY AND ADOPTING AN AMENDED TRANSMISSION OWNER
TARIFF FOR PURPOSES OF THE CITY'S PARTICIPATION IN
THE CALIFORNIA INDEPENDENT SYSTEM OPERATOR
WHEREAS, the City of Vernon ("City") is a chartered
municipal corporation of the State of California that owns and
operates a system for the generation, purchase, transmission,
distribution and sale of electric capacity and energy; and
WHEREAS, the City is a Participating Transmission Owner
("PTO") with the California Independent System Operator ("ISO") and
the Federal Energy Regulatory Commission ("FERC") has approved its
existing Transmission Owner Tariff ("TO Tariff"); and
WHEREAS, the ISO reimburses the City according to the City's
current Transmission Revenue Requirement ("TRR") in return for the
City turning over to the ISO the operation and control of the City's
transmission entitlements; and
WHEREAS, the City's transmission entitlements include rights
under certain contracts (each an "ETC") including (i) an agreement
with the City of Los Angeles Department of Water and Power entitled
"Los Angeles -Vernon Adelanto-Victorville-Lugo Firm Transmission
Service Agreement" (the "LAWDP ETC"); (ii) an agreement with Southern
California Edison Company ("SCE") entitled "Amended and Restated
Edison -Vernon Victorville-Lugo Firm Transmission Service Agreement
(the "SCE Victorville-Lugo ETC"); and (iii) an agreement with SCE
entitled "Amended and Restated Edison -Vernon Mead Firm Transmission
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Services Agreement" (the "SCE Mead ETC"); and
WHEREAS, the City's costs under the LADWP ETC, the SCE
Victorville-Lugo ETC, and the SCE .Mead ETC have traditionally been
based upon a negotiated fixed "path -specific" rate charged by LADWP or
SCE, based on the actual costs of the specific transmission lines made
available under each ETC, multiplied by the amount of transmission
capacity guaranteed to the City under each ETC; and
WHEREAS, the City's costs under the LADWP ETC, the SCE
Victorville-Lugo ETC, and the SCE Mead ETC are reflected in the City's
current TRR and TO Tariff; and
WHEREAS, on August 4, 2008, SCE filed a petition with the
Federal Energy Regulatory Commission ("FERC") seeking to amend the
pricing structure under the SCE Victorville-Lugo ETC and the SCE Mead
ETC to replace the negotiated path -specific rates set forth in those
ETCs with a "postage -stamp" rate which reflects the blended rate SCE
charges to the ISO for the actual usage of all of SCE's transmission
lines by customers of the ISO; and
WHEREAS, the postage -stamp rate which SCE charges to the ISO
is derived from SCE's TRR and, therefore, will change each time SCE
amends its TRR; and
WHEREAS, if SCE is successful in ,amending the SCE
Victorville-Lugo ETC and the SCE Mead ETC to replace the negotiated
path. -specific rates set forth in those ETCs with.a postage -stamp rate,
the City's costs under the SCE Victorville-Lugo ETC and the SCE Mead
ETC will vary proportionately with any changes in SCE's TRR; and
WHEREAS, as part of settlement proceedings conducted before
FERC, the City has reached agreement (the "SCE Settlement") withSCE
to amend the SCE Victorville-Lugo ETC and the SCE, Mead ETC to replace
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the path -specific rates set forth in those ETCs with SCE's postage -
stamp rate, after a phase -in period beginning on August 1, 2009,
during which the City's path -specific rates in those ETCs will be
gradually stepped -up over the next three years (the "Phase -In Rates")
until the path -specific rates are equal to SCE's postage -stamp rate as
of January 1, 2013; and
WHEREAS, under the SCE Settlement, the City's costs for the
SCE Victorville-Lugo ETC and the SCE Mead ETC will be equal to (i)
from August 1, 2009, until December 31, 2012, the Phase -In Rates, and
beginning on January 1, 2013, the SCE postage -stamp rate, in each case
multiplied by (ii) the amount of transmission capacity guaranteed to
the City under each ETC; and
WHEREAS, under the City's existing TO Tariff, the City does
not have a means to recover any increases in the City's costs under
the SCE Victorville-Lugo ETC and the SCE Mead ETC through the City's
TRR unless the City amends its TRR each time that SCE amends its own
TRR; and
WHEREAS, should the SCE Settlement be approved by FERC, the
City's current TRR will no longer be accurate as of August 1, 2009,
because the costs incurred by the City under the SCE Victorville-Lugo
ETC and the SCE Mead ETC will no longer be fully reflected in the
City's TRR; and
WHEREAS, it is appropriate for the City to file a new TRR to
reflect the City's increased costs under the SCE Victorville-Lugo ETC
and the SCE Mead ETC beginning on August 1, 2009; and
WHEREAS, it is appropriate for the City to file an amended
TO Tariff with the FERC and the ISO will include a mechanism for the
City's TRR ,to be adjusted when the City's costs under the SCE,
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1 Victorville-Lugo ETC and the SCE Mead ETC change as a result of a
2 change in SCE's TRR; and
3 WHEREAS, the City's outside counsel has recommended that the
4 City submit a single filing to the FERC and the ISO that provides for
5 a new TRR to be effective as of August 1, 2009, and an amended TO
6 Tariff which will include a tracking mechanism for the City's TRR
7 ("TRR Tracking Mechanism") to be thereafter adjusted when the City's
8 costs under the SCE Victorville-Lugo ETC and the SCE Mead ETC change
9 as a result of (i) the stepped -up rates implemented between August 1,
10 2009 and December 31, 2012; or (ii) any change in SCE's TRR on or
11 after January 1, 2013; and
12 WHEREAS, the City's staff has determined that it is possible
13 to submit a single filing to the FERC and the ISO that provides for a
14 new TRR to be effective as of August 1, 2009, and an amended TO Tariff
15 which will include a TRR Tracking Mechanism for the-City's TRR to be
16 thereafter adjusted when the City's costs under the SCE Victorville-
17 Lugo ETC, and the SCE Mead ETC change as a result of (i) the stepped -up
18 rates implemented between August 1, 2009 and December 31, 2012 or
19 (ii) any change in SCE's TRR on or after January 1, 2013; and
20 WHEREAS, The Brattle Group, an experienced utilities
21 consulting firm, has developed a TRR Tracking Mechanism that will
22 allow the City's TRR to be adjusted annually to be effective January
23 1st of each year to reflect changes in the City's costs under the SCE
24 Victorville-Lugo ETC and the SCE Mead ETC that change as a result of
25 (i) the stepped. -up rates implemented between August 1, 2009 and
26 December 31, 2012; or (ii) any change in SCE's TRR on or after
27 January 1, 2013; and
28 WHEREAS, The Brattle Group has prepared, and the City's
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1 staff has reviewed, a new TRR and amended TO Tariff, so as to account
2 for (i) the increase in the City's costs under the SCE Victorville-
3 Lugo ETC and the SCE Mead ETC beginning on August 1, 2009, and (ii)
4 the inclusion in the City's TO Tariff of the TRR Tracking Mechanism to
5 adjust the City's TRR whenever the costs under the SCE Victorville
6 Lugo ETC and the SCE Mead ETC change; and
7 WHEREAS, The Brattle Group has prepared testimony with
8 included exhibits, a dopy of which is attached hereto as "Exhibit 2"
9 and made part hereof, recommending that the City Council adopt the new
10 TRR and amended TO Tariff including the TRR Tracking Mechanism; and
11- WHEREAS, The Brattle Group has prepared, and the City's
12 staff has reviewed, calculations for the new TRR which would take
13 effect as of August 1, 2009, provided that FERC approves the SCE
14 Settlement, a copy of which is attached hereto as "Exhibit 2-C" and
15 made a part hereof, and which will be implemented by the tariff sheet
16 included as Appendix I of the amended TO Tariff attached hereto as
17 "Exhibit 3" and made a part hereof; and
18 WHEREAS, The Brattle Group has prepared, and the City's
19 staff has reviewed, calculations for the new TRR which would take
20 effect as of January 1, 2010,_provided that FERC approves the SCE
21 Settlement, a copy of which is attached hereto as "Exhibit 2-F" and
22 made a part hereof, and which will be implemented by the tariff sheet
23 included as Appendix I of the amended TO Tariff attached hereto as
24 "Exhibit 4 and made a part hereof; and
25 WHEREAS, The Brattle Group has prepared, and the City's
26 staff has reviewed, calculations for the new TRR which would take
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27 effect as of January 1, 2011, provided that FERC approves the SCE
28 Settlement, a copy of which is attached hereto as "Exhibit 2-F" and
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made a part hereof, and which will be implemented by the tariff sheet
included as Appendix I of the amended TO Tariff attached hereto as
"Exhibit 5" and made a part hereof; and
WHEREAS, The Brattle Group has prepared, and the City's
staff has reviewed, calculations for the new TRR which would take
effect as of January 1, 2012, provided that FERC approves the SCE
Settlement, a copy of which is attached hereto as "Exhibit 2-F" and
made a part hereof, and which will be implemented by the tariff sheet
included as Appendix I of the amended TO Tariff attached hereto as
"Exhibit 6" and made a part hereof; and
WHEREAS, at the direction of the City's staff, outside
counsel has prepared, and the City's staff has reviewed, an amended TO
Tariff, attached hereto as "Exhibit 7" and made a part hereof, which
will include the TRR Tracking Mechanism for the City's TRR to be
thereafter adjusted when the City's costs under the SCE Victorville
Lugo ETC and the SCE Mead ETC change as a result of (i) the stepped -up
rates implemented between August 1, 2009 and December 31, 2012; or
(ii) any change in SCE's TRR on"or after January 1, 2013; and
WHEREAS, a Notice of Public Hearing was published on June
25, 2009, notifying all interested parties that a hearing to consider
evidence to establish the City's new TRR and amended TO Tariff was
scheduled for July 6, 2009, at approximately 9:00 a.m., subject to the
hearing being continued to a stated time and place without further
notice; and
WHEREAS, on July 6, 2009, the City Council continued the
Public Hearing to July 13, 2009 and
WHEREAS, on July 13, 2009, the City Council held a Public
Hearing in which the City Council took evidence from staff and those,
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other persons in attendance who wished to be heard on the
establishment of the City's new TRR and adoption of the City's amended
TO Tariff; and
WHEREAS,.the Light & Power Department has prepared a Staff
Report, dated July 6, 2009, with exhibits, a copy of which is attached
hereto as "Exhibit 1" and made a part hereof, which finds the TRR
recommended by The Brattle Group and the amended TO Tariff prepared by
outside counsel to be reasonable; and
WHEREAS, the Light & Power Department has recommended the
City adopt the new TRR recommended by The Brattle Group and the
amended TO Tariff prepared by outside counsel, to be effective on
August 1, 2009, provided that the SCE Settlement is accepted by FERC;
and
WHEREAS, the City Council has heard and considered all
evidence, written and oral, presented in consideration of the adoption
of the City's new TRR and amended TO Tariff.
NOW, THEREFORE, BE IT RESOLVED BY THE CITY COUNCIL OF THE
CITY OF VERNON AS FOLLOWS:
SECTION 1: The City Council of the City of Vernon hereby
finds and determines that the recitals contained hereinabove are true
and correct.
SECTION 2: The City Council of the City of Vernon hereby
further finds .and determines that all persons have had the opportunity
to.be heard or to file written comments to the proposed adoption of the
City's new TRR and amended TO Tariff to include the TRR Tracking
Mechanism, and after due consideration of any and all evidence
submitted at the Public Hearing, determines there, are compelling
reasons to justify the 'adoption of the City's new, TRR and amended TO
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Tariff that includes the TRR Tracking Mechanism, to be effective
August 1, 2009, provided that FERC approves the SCE Settlement.
SECTION 3: The City Council of the City of Vernon hereby
declares that:
(a) any determination made pursuant to this Resolution
regarding the validity or reasonableness of any portion of any TRR or
TO Tariff shall apply only prospectively from the date of this
Resolution; and
(b) in no way shall this Resolution affect the City
Council's adoption or determination of any previous TRR or TO Tariff.
SECTION 4: The City Council of the City of Vernon hereby
finds that the City's new TRR, including such future adjustments as
shall be made pursuant to the TRR Tracking Mechanism, as described in
the Staff Report and the testimony of The Brattle Group and attached
hereto as "Exhibit 3", is just and reasonable, and approves the
adoption of the same to be effective as of August 1, 2009, provided,
however, that such new TRR shall only go into effect if FERC approves
the SCE Settlement.
SECTION 5: The City Council of the City of Vernon hereby
finds that the City's new TRR, including such future adjustments as
shall be made pursuant to the TRR Tracking Mechanism, as described in
the Staff Report and the testimony of The Brattle Group and attached,
hereto as "Exhibit 4" is just and reasonable, and approves the
adoption of the same to be effective as of January 1, 2010, provided,
however, that such new TRR shall only go into effect if FERC approves
the SCE Settlement.
SECTION,6: The City Council of the City of Vernon hereby
finds that ,the City's new TRR, including such future adjustments as
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shall be made pursuant to the TRR Tracking Mechanism, as described in
the Staff Report and the testimony of The Brattle Group and attached
hereto as "Exhibit 5 is just and reasonable, and approves the
,adoption of the' same to be effective as of January 1, 2011, provided,
however, that such new TRR shall only go into effect if FECR approves
the SCE Settlement
SECTION 7: The City Council of the City of Vernon hereby
finds that the City's new TRR, including such future adjustments as
shall be made pursuant.to the TRR Tracking Mechanism, as described in
the Staff Report and the testimony of The Brattle Group and attached
hereto as "Exhibit 6", is just and reasonable, and approves the
adoption of the same to be effective as of January 1, 2012, provided,
however, that such new TRR shall only go into effect if FERC approves
the SCE Settlement.
SECTION 8: The City Council of the City of Vernon hereby
finds that the City's amended TO Tariff that includes the TRR Tracking
Mechanism, as described in the Staff Report and attached hereto as
"Exhibit 7", is just and reasonable and hereby approves the adoption
of the same to be effective as of August 1, 2009, provided, however,
that such amended TO Tariff shall only go into effect if FERC approves
the SCE Settlement
SECTION 9 The City Council of the City of Vernon hereby
directs and authorizes the Director of Light & Power, or his designee,
to direct outside counsel, on behalf of the City to:
(a) file with the FERC and the ISO the new TRR and amended
TO Tariff that includes the TRR Tracking Mechanism, in substantially
the form presented in the exhibits attached hereto, as and when it is
deemed appropriate and
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1 (b) submit to the FERC and the ISO appropriate supporting
2 documentation,such as this City Council Resolution approving the TRR
3 and amended TO Tariff, the Staff Report, and the testimony of The
4 Brattle Group in substantially the form presented in "Exhibit 2" and
5 with exhibits submitted according to the advice of counsel
6 SECTION 10: The City Clerk of the City of Vernon shall
7 certify to the passage of this resolution, and thereupon and thereafter
8 the same shall be in full force and effect.
9 APPROVED AND ADOPTED this 13th day of July, 2009.
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Name: Hilario Gonzales
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Title: Mayor /- "rt_•. r r^
15 ATTEST:
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17 nANUELA GIRO ,` ity Clerk
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1 STATE OF CALIFORNIA )
2 ) ss
COUNTY OF LOS ANGELES )
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4 I, MANUELA GIRON, City Clerk of the City of Vernon, do hereby
5 certify that the foregoing Resolution, being Resolution No. 10,005, was
6 duly adopted by the City Councilofthe City of Vernon at a regular
7 meeting of the City Council duly held on Monday, July 13, 2009, and
8 thereafter was duly signed by the Mayor or Mayor Pro-Tem of the City of
9 Vernon.
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12 ANUELA GIRO , -C' y Clerk
13 (SEAL)
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Exhibit 1
SCE Offer of Settlement
OFFER OF SETTLEMENT
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Southern California Edison Company ) Docket Nos. ER08-1343-000
:ER08-1353-000
ER09-187-000
ER09-187-001
EL09=19-000
ER09-446-000
(consolidated)
OFFER OF SETTLEMENT
Southern California Edison Company ("SCE") hereby offers, to each of the Parties
to the above -captioned proceeding (collectively, "Parties," and individually, a 'Tarty"r
and FERC Trial Staff, the following terms and conditions of a Settlement thereof
("Settlement"): If approved by the Federal Energy Regulatory Commission ("FERC" or
"Commission" ), this ' Settlement will resolve all disputes and controversies among SCE
i The entities that intervened in these proceedings are: Arizona Electric Power Cooperative, Inc.
and Southwest Transmission Cooperative, Inc. ("AEPCO/SWTC"); California Department of Water
Resources State Water Project ("State Water Project" or "SWP"); California Public Utilities Commission
("CPUC"); Cities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside, California; Cities of
Redding and Santa Clara, California; City of Vernon, California ("City of Vernon"); Energy Producers
and Users Coalition; Golden State Water Company; Los Angeles Department of Water and Power
("LADWP"); The Metropolitan Water District of Southern California; Modesto Irrigation District; M-S-
R Public Power Agency; Northern California Power Agency; Pacific Gas and Electric Company; San
Diego Gas &Electric Company; State Water Contractors; The Transmission Agency of Northern
California; and Atlantic Path 15, LLC. For purposes of this Settlement, the term "Party" or "Party to the
proceedings" shall refer to SCE and the entities above.
and the Parties in Docket Nos. ER08-1343-000, ER08-1353-000, ER09-187-000, ER09-
187-001, EL09-19-000 and ER09-446-000 The Settlement, providesas. follows.
I. SETTLEMENT RATES4
A. SCE's T04 Retail Base Transmission Revenue Requirement ("TRR")
without the :CWIP Retail Revenue Requirement shall be $449,000,000. The Retail'
Base TRR with the CWIP Retail Revenue Requirement of $38,617,000 -shall be
$486,617,000. The Retail TRBAA shall be-$92,159,709. The total Retail TRR
shall be $394,457,291
B. The components of SCE's Wholesale TRR shall be as follows.
2 On September 30, 2008, the Commission issued an order consolidating the T04 Rate Case
proceeding and ETC filings, accepting and suspending the filings until March 1, 2009, subject to refund,
and establishing settlement procedures. Southern California Edison Co., 124 FERC ¶ 61,308 (2008)
("704 Order"). On December 19, 2008, the Commission also consolidated SCE's 2009 Construction
Work in Progress ("CWIP") filing, Docket No. ER09-187, with SCE's previously -consolidated T04 Rate
Case proceeding, and the ETC proceeding. Southern California Edison Co., 125 FERC :¶ 61,329 (2008).
However, the Commission severed the Return on Equity ("ROE") portion of that filing and ordered that
ROE would be determined. by the paper hearing procedures that were pending in Docket No. ER08-375.
In addition, the Commission's December 19 Order initiated a Section 206 investigation into the justness
and reasonableness of the proposed CWIP rate reduction. Finally, on December 22, 2008, in Docket No.
ER09-446, SCE filed revisions to its TO Tariff rate sheets to reflect annual updates and rate adjustments,
effective January 1, 2009, previously accepted by the Commission in Docket Nos. ER09-187 and ER09-
167. On February 19, 2009, the Commission issued an order accepting the rate sheets, suspending them
until March 1, 2009, subject to refund, and consolidating that proceeding with the previously -
consolidated dockets discussed above. Southern California Edison Co., 126 FERC ¶ 61,126 (2009).
3 Revised pages of the TO Tariff, both redlined and clean versions reflecting modifications in
accordance with the terms of the Settlement, are attached hereto as Attachment B.
a For purposes of the Settlement, the rates agreed to under the Settlement will be referred to -as the
"Settlement Rates"'
2
Wholesale
TRR
All High
Existing
New High
Low
Component
Total
Voltage
High Voltage
Volta` e
Volta e ;
Base TRR
$443,000,000
$412,342,628
$234,281,436
$178,061,192
$30,657,372
w/O CWIP
CWIP
$38,530,000
$38,530,000
$0
$38,530,000
$0
Base TRR
$481,530,000
$450,872,628-
$234,281,436
1216,591,192
$30,657,372
w/CWIP
TRBAA '
491,950,476
-$89,9829764 `
-$68,708,139
-$21,274,625
-$1,967,7.12
Standby
Revenues
-$51495 610
45,115,292'
-$2,906,364
42;208,927
-$380,318
Total TRR
$384,083,914
$355,774,572
$162,666,933
$193,107,640
$28,309,342
C. SCE's Gross Load shall be 92,450,710 MWh. SCE's sum of"12 monthly
peak demands shall be-185,942 MW.
D. SCE's wholesale rates shall be as follows:
Low Voltage Access Charge
$0.00031 per kWh
Low Voltage Wheeling Access Charge
$0.00031 per kWh
High Voltage Utility Specific Rate
$0.0038483 per kWh
High Voltage Existing Contracts Access
Charge
$1.91 per kW of Billing Demand
Low Voltage Existing Contracts Access
Char e
$0.15 per kW of Billing Demand
E. For purposes of CPUC-jurisdictional retail ratemaking, the Base TRR
resulting from this Settlement reflects a $5.0 million credit for transmission -related
incremental ratepayer revenues associated with'the CPUC-adopted Gross Revenue
Sharing Mechanism ("GRSM"). This credit shall be non -precedent and shall
-not waive any Party's rights in any future CPUC or FERC proceeding with. respect
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a
to the propriety of including GRSM in FERC rates or the appropriate. level of
GRSM or Non -Tariff Products and Services.
F. For ratemaking purposes, SCE shall amortize the cost of the Four Corners
vegetation management expense over a.period of three years. In the event that
SCE makes ;future Section 205 filings to change rates, no Party shall oppose SCE
including in its transmission cost of service the unamortized amounts of the
vegetation management expense, equal to $:1,126,333 in each of 2010 and 2011.
G. SCE shall apply the following transmission plant depreciation rates during
the period the T04 rates are in effect (which equate to a composite total
depreciation rate of 2.76% when applied to 2009 forecasted transmission plant
balances):
TO4 Transmission Plant Depreciation Rates
FERC
Plant Less
Removal
Account
Salvage
Cost
Total
350.2
1.66%
0.00%
1.66%
352
1.84%
0.73%
2.57%
353
2.49%
0.13%'
.2.62%
354
1.23%
1.30%
2.53%
355
1.64%
2.18%
3.82%
356
1.07%
2.43%
3.50%
357
1.65%
0.00%
1.65%
358
2.68%
1.19%
3.87%
359
1.56%
0.00%
1.56%
H. SCE will• continue to maintain
a subsidiary record for Account 108
(Accumulated Depreciation) that separately accounts for the TO4 depreciation
accrual for plant less gross salvage and the depreciation accrual for removal cost,
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by FERCplant account; based. on the depreciation rate segregation shown above.
During the period the T04 rates are in effect, SCE will recognize the differences
between electric network transmission facility removal cost depreciation for
external financial reporting and ratemaking purposes as a regulatory liability and
SCE will record the accumulated depreciation arriounts as with removal
costs in such subsidiary records as a regulatory, liability, consistent with`FERC
Order No. 631. The accumulated depreciation amounts may only be reduced by
-the incurred costs associated with the removal and disposal of electric network
transmission facilities. Any regulatory liability amounts for such depreciation
accruals for removal costs associated with electric network transmission facilities.
remaining at the end of the T04 period shall be carried forward.
I. The Parties agree to, or do not oppose, a TRR without identification or
attribution of costs or adjustments for any particular component of the TRR other
than those specified herein.
I The appropriate standard of review governing this Settlement is the just and
reasonable standard, unless specifically noted in the Existing Transmission
Contracts section of the Settlement. Settlement ¶ IL
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H. EXISTING TRANSMISSION CONTRACTS C'ETCs"). The following terms
and conditions applyto the ETCs below.
A. ETC -Specific Terms -
1. M-S-'R - FERC Rate Schedule No. 339
A. Rates: With respect to M-S-R's ETC, the Settlement rates shall be
as follows:
March 1, 2009: $0.65 per kW -month
January 1, 2010: $0.65 per kW -month
January 1, 2011; $0.65 per kW -month
January 1, 2012:. $ l .10 per kW -month
January 1, 2013 : $1,60 per kW -month
January 1, 2014-on: Then -Effective HVECAC Rate
b. Additional Point of Receipt and Delivery: , Commission Trial Staff
( TERC Trial:Staff') will not oppose, and SCE. agrees to support, with
California Independent ,System Operator Corporation ("CAISO") and at
FERC, the approval by CAISO and FERC of an additional Point of
Receipt and Delivery under the M-S-R contract at Vincent Substation to
become effective, no earlier than January 1, 2014.. In the event that, after
this additional Point of Receipt and Delivery.has been approved, M-S-R
s Revised pages of the ETCs, both:redlined and clean versions reflecting modifications in
accordance with the terms of the Settlement, are attached hereto as Attachment C.
on
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and'SCE'mutually agree that the point at Vincent Substation should be
replaced by another additional Point of Receipt and Delivery along M-S-
Ts existing contract path, then SCE and M-S-R shall cooperate in
i seeking CAISO..and FERC-approvall for such a replacement, and the
establishment of a different additional Point of Receiptand Delivery
along the existing M-S-R contract path to become effective no earlier
than January 1, 2014.
C. Contract Amendment: SCE shall file with the'Commission an
amendment to the M-S-R contract requesting the approval of Vincent
Substation as an additional Point of Receipt and additional Point.of
Delivery, to be effective no earlier than J'anuary`1, 2014. SCE shall file
this contract amendment as part of the Settlement filing. At no time
shall M-S=R schedule under` the contract an amount of capacity at either
a Point of Receipt or Point of Delivery that: exceeds its Contract
Demand. Beginning on January '1, 2014 Vinceni Substation shall be an
additional'Point of Receipt`and Point of Delivery for the firm
transmission service provided by SCE"to M-S-R under the M-S-R ETC.
The transmission service provided under the M-S-R ETC shall be
subj Oct to the 'following conditions:
1. M-S-R shall comply with all`CAISO`Tariff provisions
regarding scheduling the use of its existing transmission
7
contract rights under the M-S-RETC.and settlement of those
schedules, including the provisions of CAISO Tariff Section
16.
2 Schedules submitted under the -M-S-R ETC must consist of a
physical source (generation or import) balanced with a
physical sink (load or export) under the same CAISO contract
reference number in accordance with CAISO Tariff Sections
16.4.5 and 16.6.
3. For schedules using Vincent Substation,' when Vincent
Substation is not the location of the physical source or sink,
Vincent Substation would be designated as one of the end
points for "perfect hedge" treatment of congestion charges
applied throughSections 11.2.1.5 and 11.5.7.1 of the CAISO
Tariff.
4. The schedule at any Point of Receipt or Point of Delivery
under the M-S-R ETC may not exceed 150 MW.
These conditions are set forth in Section 6.1.1 of the M-S-R ETC.
d. TRTC Instructions: SCE shall coordinate with M-S-R in advance
of 2014 to develop and submit to the CAISO Transmission Rights and
Transmission Curtailment ("TRTC") instructions (or any replacement
8
mechanism created by the CAISO)-for scheduling at the Additional
Points of Receipt and Delivery in a manner that is consistent with the
TRTC instructions and scheduling parameters for the currently existing
Points of Delivery and_Receipt under the contract. SCE will provide a
copy of the TRTC instructions to M-S-R simultaneously upon its
subnussion to the CAISO.
e.. No Other Changes: Except as provided in Settlement ¶ II, this
Settlement will make no changes to this contract.
2. , AEPCO/SWTC — FERC Rate Schedule No.131
,a. Rates: With:respect to.Arizona -Electric Power Cooperative Inc.'s
("AEPCO") and Southwest Transmission Cooperative, Inc.'s ("SWTC") .
-(collectively; "AEPCO/SWTC") ETC for service to Anza Electric
Cooperative, Inc. ("AnzaETC"),.the Settlement rates for the CAISO
Controlled Grid portion of the contract shall be as follows:
March 1, 2009: $1.00 per kW -month
January.1, 2010: $1,25 per kW -month
January 1, 2011: $1.50 per kW -month
January 1, 2012: $1.75, per kW -month
January 1, 2013-on: Then -Effective HVECAC Rate
9
b. Non-CAISO Controlled Grid Service: The non-CAISO
Controlled Grid portion of this ETC is unaffected by this Settlement.
c. No Other Changes: Except as provided in Settlement ¶ II, this
Settlement will make no changes to this contract.
3. SWP — FERC Rate Schedule No.113. (Contracts-534431.
a. Rates: With respect to State Water Project's (" SWP's") Contract B-
53443, FERC Rate Schedule No. 113, the Settlement rates shall be as
follows:
March 1, 2009; $0.75 per kW -month
January 1, 2010: $1.00 per W-month
January 1, 2011: $1.50 per. kW -month
January 'l, 2012: $1.91 per kW -month
January 1, 2013-on: Then-Effective:HVECAC Rate
b. Substitution of Pastoria as a Point of Delivery:. SCE shall file
with the Commission an amendment -to the SWP contract requesting
approval of a change in Point of Delivery currently reflected in Section
5.4 of the contract from Vincent Substation to Pastoria Substation
("Revised Point of Delivery"). The Point of Delivery identified as
EldoradoSubstation in Section 5.4 of this contract shall remain, and the
Points of Receipt identified in Section 5.5. of this contract shall remain
10
Vincent Substation and Eldorado Substation, respectively. SCE shall
file this contract amendment as part of the Settlement filing.
e:' TRTC Instructions: SCE shall coordinate with SWP to develop
and submit to the CAISO, no later than five days after the Commission's
acceptance of the -Settlement, including the contract amendment
addressed in Settlement ¶ II.3.b. above, :Transmission Rights and
Transmission Curtailment ("TRTC").instructions (or any replacement
mechanism created by the CAISO) for scheduling at the Revised Point
of Delivery- in a manner that is consistent with the TRTC instructions
and scheduling parameters for the currently existing Point of Delivery
under the contract. ` SCE will provide a copy of the, TRTC instructions to
SVJP simultaneously upon its submission to the CAISO.
d: Other CAISO Approvals: SCE agrees to coordinate with SWP to
submit any other applicable request for CAISO approval or notifications
as may be required relative to the Revised Point of Delivery, and to
comply with.CAISO procedures necessary to effectuate the change in
Point of Delivery from Vincent Substation to Pastoria Substation.
e. Termination: This contract shall terminate no later than July 25,
2011
f.: No Other Changes: Except as provided in Settlement ¶ II, this
Settlement will make no changes to this contract.
11
4. SWP'- FERC Rate Schedule No. 342 (Contract -B-59387).
a. Termination of CAISO Controlled Grid Service: The Mojave
Siphon Agreement (SWP Contract B-593 87, FERC Rate Schedule No.
342), 'shali be aiuended to terminate SWP's rights and payment
obligations for firm transmission service on the CAISO Controlled Grid
over the Vista -Mira Loma 220 kV and Mira Loma -Lugo -Vincent 500
kV lines ("Amendment"). SCE shall file this amendment with the
Commission as part of the filing of this Settlement. For the period from
March 1, 2009 until the date the Commission issues its order accepting
the Settlement, SWP shall compensate SCE at the path -specific rate
level that was in effect on February 28, 2009.
b. Continuance of Non-CAISO Service:. Provisions relating to the
non-CAISO service in this contract, including but not limited to pricing
methodology provisions, will not change as a result of this Settlement.
SWP's right to non-CAISO service over SCE's Arrowhead -Devil
Canyon -Mojave Siphon-Shandin 115 kV, Shandin-Calectric 115 kV,
and Calectric-Vista 115kV distribution lines under the Mojave Siphon
Agreement shall continue and shall not be affected by this Settlement.
5. Vernon—'Victorville-Lugo (FERC Rate Schedule No. 360) and
Mead (FERC Rate Schedule No. 207)
a. Rates: With respect to the City of Vernon's (Vernon's) Victorville-
Lugo ETC, the Settlement rates shall be as follows:
12
March 1, .2009:
$0.51 per 1cW-month
August 1, 2009:
$1.00 per kW -month
January 1, 2010:
$1.70 per.kW-month
January 1, 2011:
. $1.75 per kW -month
January 1, 2012:
$1.91 .per kW -month
January 1, 2013-on:
Then -Effective HVECAC Rate
With respect to Vernon's Vernon -Mead 230 kV ETC, the Settlement
rates shall be as follows:
March 1., 2009;
$1.04 per kW -month
August 1, 2009:
$1.25 per kW -month
January 1, 2010:
$1.5.9 per kW -month -
January 1, 2011:
$1.75 per kW -month
January 1,, 2012:.
$1.91 per kW -month
January 1, 2013-on:
Then -Effective HVECAC Rate
b. SCE's ETC Costs To Belncluded.in Vernon's Base TRR:
The Parties and FERC. Trial
Staff have agreed not to oppose the
inclusion of all revenues paid .by Vernon to SCE with respect to
Vernon's Affected ETCs in
the calculation of Vernon's Base TRR, and
13
not in Vernon's TRBAA during the phase -in periods set forth in
Settlement ¶ II.A.5.a.
c. Vernon Cost ReeoverYPetition: 'Within ten. (10) business days
after this Settlement is filed with the Commission, Vernon has indicated
that it intends to file a petition with the Commission to reflect a change
in Verno' Ws currently effective TRR ("TRR Petition" ), effective August
1, 2009, to include the. proposed Settlement rates set forth above in
Settlement ¶ II.A.5.a. Vernon's TRR Petition will be made contingent
upon the Commission approving this Settlement. All Parties agree not
to oppose the inclusion 'in Vernon's TRR of the costs incurred by
Vernon under the rates set forth above in Settlement ¶ II.A.5.a. Parties
and FERC Trial Staff retain all rights to challenge any other costs not
related to the rates set forth above in Settlement ¶ II.A.5.a. -and the
inclusion of these costs in Vernon's TM and retain all other rights
pertaining to Vernon's filing.
d. No Other Changes: Except as provided in Settlement ¶ II, this
Settlement will make no changes to the Vernon ETCs.
14
B. Additional ETC Settlement Provisions
1. Contract Termination
Each Affected. ETO will be modified as part of this Settlement to allow
the ETC customer to terminate. its ETCs, or to reduce the contract
demand in its ETC, upon eight months notice, or if SCE agrees, on
lesser notice. This supplements; but does not,replace, the termination
and other provisions included in the currently -effective contracts.
2. ETC.Revenue Credits
All Parties and FERC Trial Staff agree that until January 1, 2014, with
respect to any Affected ETC at issue in this proceeding or any other
ETC for which SCE assesses the HVECAC rate: (a) in developing its
transmission cost of service and TRR, SCE is to credit against its TRR
the ETC revenues consistent with the rate and contract demands actually
reflected in the ETCs, and (b) no Party or FERC Trial Staff will
propose, during this period in any proceeding, a level of revenue credit
against SCE's TRR that is inconsistent with the foregoing. This
provision shall not be used to argue that FERC Trial Staff or any Party
has waived its rights with respect to the appropriate level of revenue
credit against SCE's TRR for the City of Pasadena's ETC with SCE. .
¢ For proposes of this Settlement, the "Affected ETCs" are the six ETCs addressed in this
Settlement ¶ If between SCE and, respectively, the State Water Project; AEPCO/SWTC, City of Vernon,
and the M-S-R Public Power Agency.
15
3. TRBAA
For the TRR agreed to under this Settlement, ETC revenues shall be
reflected asp a forecast credit to the Base TRR, rather than in the TRBAA
as proposed by SCE in this proceeding. In addition, during the phase -in
period, SCE shall not request a modification to the TRBAA to flow
through any ETC revenues, including revenues under the Pasadena ETC.
4. Section 205 ,and 206 Rigghts
a. The rates for the Affected ETCs shall be in effect for the periods
specified above. After the expiration o f the phase -in period for each
Affected ETC; the rate for each: Affected. ETC customer shall
continue, for the duration of each contract, to be calculated using the
methodology used by SCE for calculating the HVECAC rate in its
filing in this consolidated proceeding (including, but not limited to,
the use of the retail 12 monthly coincident � system peak demands
("12-CP")2 method to determine the denominator of the HVECAC
postage stamp rate and the use of a contract -demand based rate).
Except as provided in Settlement:¶ II.B.4.b and Settlement ¶
II.B.4.c below, any'proposal to unilaterally modify the Affected
ETC rates during 'the phase -in period or to unilaterally modify the
z The. term "12-CP has the meaning that it has in SCE's initial rate filing in this
consolidated proceeding.
16
methodology for calculating the HVECAC rate from that used in
SCE's filing inthis consolidated proceeding shall be subject to the
public interest standard as set forth in Morgan Stanley Capital
Group, Inc. v. Public Util. Dist. No. 1 of Snohomish, Washington,
20N U.S. Lexis 7520 provided that the standard for review of any
such modification that is proposed by an entity that is not a Party to
these proceedings, or by the Commission: acting sua sponte, shall be
the most stringent standard permissible under then. -applicable law.
b. Nothing herein shall prevent: i) SCE from making a unilateral filing
under Section 205,of the Federal Power Act (a) to modify its TRR
or, (b) for ETCs not subject to the phase -in pursuant to this
Settlement to modify the HVECAC rate resulting. from such TRR
modification, or (c) after the phase -in period for each Affected ETC,
to modify the HVECAC rate for that ETC resulting from such TRR
modification (or any, Party from opposing such filing); or ii) any
Party. from unilaterallyfiling under Section 206 of the Federal Power
Act (a) to modify SCE's TRR or, (b) for ETCs not subject to the
phase -in pursuant to this Settlement, to modify the HVECAC rates
resulting from such TRR modification, or, (c) after the phase -in
period for each Affected ETC, to modify the HVECAC rate for that
ETC resulting from such TRR modification (or any Party from
17
opposing such filing); provided that in any such proceeding no Party
may argue for an HVECAC rate level that is -calculated using a
different methodology than used by SCE in this consolidated
proceeding:
c. Notwithstanding Settlement ¶.H.B.4.a. above, if a Commission order
establishing SCE's TRR after the phase -in period adopts a level of
ETC revenue for one or more of the Affected ETCs that is higher
than SCE is entitled to collect under the provisions of this Settlement
and the then -effective HVECAC rate., SCE shall have the right to file
with the Commission under Section 205 of the Federal Power Act to
modify the rate applicable to such Affected ETC(s) to recover the
amount of revenue adopted by the Commission for that contract, and
such Affected ETC customer shall have the right to oppose SCE's
filing. Also, notwithstanding Settlement ¶ H.B.4.a. above, if a
Commission order establishing SCE's TRR after the phase -in period
adopts a level of ETC revenue for one or more of the Affected ETCs
that is lower,than SCE is entitled to collect under the'provisions of
this Settlement and the then -effective HVECAC rate, such Affected
ETC customer shall have the right to file with the Commission under
Section 206 of the Federal Power Act to modify the rate applicable
to such Affected ETC to recover the amount of revenue adopted by
18
the Commission for that contract, and SCE shall have the right to
oppose, such Party's filing.
d. Except as modified in this Settlement ¶ II, the Section 205 and 206
rights contained in the currently -effective ETCs remain unchanged.
e. This Settlement ¶,ILBA.:.does not modify, supplement, or otherwise
affect ETC agreements between SCE and the Six Cities, and SCE
and LADVdP. Notwithstanding,any other provision of this
Settlement, the Six Cities .and LADWP shall retain their respective
Section 205 and 206 rights, as such rights may exist in their
Commission -approved agreements with SCE; to challenge the
EVECAC rate and the methodology -for. calculating such rate.
III. RETAIL RATE DESIGN
A. SCE shall design retail standby rates consistent with the standby rate
settlement adopted in SCE's 2009 General Rate Case at the CPUC. The
standby customers' backup load will be separated into four voltage
differentiated sub -groups whose revenue responsibility will be based upon
each sub-group's contribution to the 12-CP. This revenue responsibility
will be divided by the associated backup load kW demands, yielding a $/kW
backup rate. Any revenue deficiency that results from this allocation or
standbgload exemptions are reflected in rates and recovered from all
customers in the affected groups. An illustrative calculation of the revised
19
standby rate methodology included herein, based on the TRR proposed by
SCE in the December 2008 filing, is provided in Attachment to this
Settlement.
B. For purposes of calculating the Settlement rates for Schedule GS-2, SCE
shall replace the Demand Billing Determinant for GS-2 of.52,449.083 MW
reflected in the August 2009 filing (WP-BG-2 of 23) with 50,118.0 MW.
IV. NON -RATE TERMS
A. Transmission Capital Additions Reporting: In. SCE's T05 filing, SCE
will provide its Adjusted Capital Budget (see T04 filing, Volume 7
Statement AD workpapers, pages 83 to 158), showing annual capital
expenditures at the forecast project/work order level by in-service date,
CAISO percentage, and year of expenditure (prior years collectively,
forecast year, test year) sorted to group CAISO projects that close in the test
period (similar to the table shown in the T04 filing; Volume 11, Statement
BK workpapers, pages 42 to 45)..
B. Future TRR Filing Structure and Organization: In the T05 filing, SCE
shall provide a Table of Contents for each volume of testimony, exhibits,
statements, and workpapers. If requested, SCE shall provide a version of
all testimony and statements with cross-references to the workpapers no
later than ten (10) business days after the date of a Commission order
establishing hearing and/or settlement procedures for the T05 filing.
20
V. OTHER
A. Effective Dates of Rates: The rates adopted pursuant to the Settlement
will be made effective on March 1, 2009, except as otherwise provided in
Settlement ¶ II.A. above.
B. Refunds
1. TO Tariff Wholesale: Once the Commission approves the Settlement,
SCE will notify the CAISO and request that it make the wholesale TO
Tariff customer refunds, including applicable interest calculated at the
rate(s) established pursuant to 18 C.F.R. § 3 5.19a, necessary to
implement the rates and TRR provided herein as of the refund effective
date. Specifically, within thirty (30) business days of the date on which
the Commission issues its order approving the Settlement, SCE will
request that the CAISO calculate and make refunds to Utility
Distribution Companies, metered Subsystems, and Scheduling v
Coordinators for Access Charges and Wheeling Access Charges, as
appropriate, under the CAISO Tariff. SCE will also request that the
CAISO adjust the Wheeling Access Charge revenues allocable to each
Participating TO to reflect the refunds for Wheeling Access Charge
service. Such adjustments to Wheeling Access Charge revenues shall be
debited to each Participating TO's TRBA in the first restatement of
21
SCE's and the other Participating TO's TRBAs following all approvals
of this Settlement.
2. TO Tariff Retail: The CPUC shall determine the treatment of retail
refunds.
Is` ETC Customers: Within thirty (30)-business days of the date on which
the Commission issues its order approving the Settlement, SCE will
provide the refunds to its ETC customers, including applicable interest
calculated at the rate(s) established pursuant to 18 C.F.R.
§ 35.19a, necessary to implement the rates and TRR provided herein as
of the refund effective date. SCE shall subsequently file with -the
Commission a refund report within thirty (30) days of the date on which
SCE has provided refunds to such ETC customers.
C. No Precedential Effect: ' Except as expressly provided for in this
Settlement, it is specifically intended that the'.Settlernent represents a
negotiated agreement for the purpose of settling Docket Nos. ER08-1343-
000, ER08-1353-000 ER09-187-000, ER09-187.001 EL09-19-000, and
ER09-446-000, and no Party, participant or affiliate thereof shall be deemed
to have approved, accepted, agreed or consented to any fact, concept,
theory, rate methodology, principle or method relating to jurisdiction,
prudence, reasonable cost of service, rate of return, 'cost classification, cost
allocation, rate design, tariff provisions or other matters underlying or
22'
purported to underlie any of the resolutions of the issues provided herein.
With respect to Docket No. ER09-187, this Settlement does not resolve the
Return on Equity filed in that docket, which is subject to resolution by a
Commission order in Docket No. ER08-375. This Settlement shall not
constitute, approve, or establish any precedent regarding any principle or
issue in these dockets and shallnot relieve -any Party, participant or affiliate
thereof, of the burden, under Sections 205 or 206 of the Federal Power Act,
to establish the justness and reasonableness of any aspect of any
superseding rate. The Settlement shall not be deemed a "settled practice,"
as that term was interpreted in Public Servici,Comm'n of New York v.
FERC, 642 F.2d 1335 (D.C. Cir. 1980).
D. Approval of Settlement and Privileged Nature of Settlement: The
. Settlement is submitted pursuant to Rule 602 of the Commission's Rules of
Practice and Procedure and,is offered solely as a compromise in order to
settle this proceeding. The Settlement and all related documents and
discussions are privileged. The Settlement is submitted on the condition
that _in the event it does not become effective in accordance_with its terms, it
shall not constitute any part of the record in this proceeding or be used for
any other purposes
E. Rejection or Modification: This Settlement shall become effective when
and if approved by the Commission in its entirety without material
23
modification or condition, or, if approved in part or subject to material
modification or condition, if no Party files notice of its objection to such
partial approval or condition or modification with the Commission in
accordance with this Paragraph. If the Commission approves the
Settlement in part or approves the Settlement subject to a material
modification or condition, and a Party files notice with the Commission
within twenty (20) business days of the Commission's order that it objects
to such partial approval or modification or condition, the Settlement shall be
of no force and effect and the Parties shall have all rights to continue to
pursue their legal remedies before the Commission in the pending dockets.
F. Integration: This Settlement supersedes all previous representations,
understandings, negotiations, and agreements, either written or oral,
j between the Parties or their representatives with respect to matters at issue
in these consolidated proceedings, and constitutes the entire agreement of
the Parties with respect to matters at issue in these consolidated
proceedings.
r
24
Exhibit 2
Prepared Testimony of
The Brattle Group
(with Attached Exhibits)
1 I. INTRODUCTION, QUALIFICATIONS AND SUMMARY
2 Q. Please state your names, titles, place of employment, and business address.
3 A. My name is Philip Q Hanser. My name is Judy W. Chang; We are Principals of
4 The Brattle Group, an economic consulting firm with offices in Cambridge,
5 Massachusetts; Washington, D.C.; San Francisco, California; London, England;
6 and Brussels, Belgium. Our business address is 44 Brattle Street, Cambridge, MA
7 02138.
8
9 Q. Please describe your background and employment experience.
10 A. I (Philip) have been a Principal at The Brattle Group since 1998. I have appeared
11 as an expert witness before the Federal Energy Regulatory Commission ("FERC"
12 or "Commission"), various state public utility commissions, and in federal and
13 state courts. I have been an instructor on cost of service studies and rate design at
14 the Edison Electric Institute's Introductory and Advanced Rate Schools. Prior to
15 joining The Brattle Group, I was the Project Manager for Rates and Rate Design
16 at the Electric Power Research Institute ("EPRI") and, later, was the Manager of
17 the Demand -Side Management Program. While at EPRI, I also was the project
18 manager for the Electric Utility Rate Design Study, the industry -sponsored multi-
19 volume study to support utilities and commissions in implementing the Public
20 Utilities Regulatory Policies Act of 1978. I have also held various academic
21 positions. The statements of my qualifications are attached to this testimony as
22 Exhibit AL
23
24 1 (Judy) have been a Principal of The Brattle Group since 2008. I have been
25 involved in electric power market issues, particularly transmission -related topics
26 for over a decade and have submitted prepared expert testimonies before the
27 FERC in proceedings relating to electric wholesale market design issues and
28 market -based rate submission. I have a Masters' degree in Public Policy from
29 Harvard Kennedy School and a Bachelor of Science in Electrical Engineering
30 from the University of California, Davis. My resume is attached to this testimony
31 as Exhibit A2.
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Q. On whose behalf are you testifying?
A. We are testifying on behalf of the City of Vernon, California ("Vernon" or "the
city').
Q. What is the purpose of your testimony?
A. The purpose of our testimony- is ahreefold. First, Vernon has asked us to calculate
its revised transmission revenue requirement {'TRR") for 2009. The California
Independent System Operator ("CAISO") collects the transmission revenues for
all Participating Transmission Owners ("PTO"), including Vernon, pursuant to
each PTO's TRR, which in turn reflects expenses and capital costs incurred by the
PTOs for providing transmission services. The 2009 TRR calculations that we
present in this testimony incorporates the agreed upon rates for Vernon's existing
transmission contracts ("ETCs") with Southern California Edison Company
("SCE" or "Edison") set forth in the Offer of Settlement ("Settlement") filed in
Docket Nos. ER08-1343-000; et al. Second, we describe an adjustment clause
("ETC Adjustment Clause") that Vernon proposes to use to track changes in
SCE's transmission rates for the ETCs starting from August 1, 2009 and beyond.
The ETC Adjustment Clause would provide a cost-effective and stable
mechanism for determining Vernon's TRR and would be adjusted only once per
year to true -up the differences between the projected and the actual SCE ETC
costs for the prior year. Third, we calculate the TRR for 2010 through 2012 based
on SCE's rates negotiated in the Settlement that Vernon seeks to put in place if
the Commission does not accept the proposed ETC Adjustment Clause.
Our testimony and exhibits, as well as Vernon's 2009 through 2012 TRR and the
ETC Adjustment Clause, have been adopted by the Vernon City Council. The
Vernon City Council is Vernon's official rate setting body.
Q. Why is Vernon filing a revised TRR?
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On August 1, 2008, SCE proposed to increase its TRR and associated rates in
Docket No. ER08-1343-000. In a relatedfiling submitted, in Docket No. ER08-
1353-0001 SCE proposed to transition Vernon's ETCs from path -specific pricing
to a postage stamp rate methodology based on SCE's High Voltage Existing
Contracts Access Charge ("HVECAC"), with Vernon's allocated capacity for
each ETC remaining unchanged.: Vernon protested SCE's proposed- changes,
which were accepted by the Commission effective March 1, 2009 subject to
refund, hearing, and settlement judge proceedings.
On July 1, 2009, SCE filed a Settlement between SCE and the parties in Docket
Nos., ER08-1343-000 and ER08=1353-000. The Settlement calls"for essentially no
change in the SCE ETC rates until August 1, 2009 during which the rate for the
Victorville-Lugo ETC contract will increase to $1.00 per kW -month and the
Mead -Laguna contract to $1.25 per kW -month. Accordingly, Vernon is revising
its TRR to reflect the increase in its transmission. costs due to the changes in
SCE's rate structure and we are using these rates in our calculations of Vernon's
revised, TM proposed to be effective on August 1, 2009
In addition, Vernon is proposing to use an ETC Adjustment Clause, starting on
August 1, 2009, to provide a transparent mechanism for adjusting Vernon's future
TRR to reflect changes in SCE's ETC charges. The ETC Adjustment Clause has
an annual true -up for any difference between projected and actual transmission
charges associated with SCE's ETCs (with interest on the balances). We describe
the details of the ETC Adjustment Clause below.
Since the Settlement includes an agreed -upon rate schedule for Vernon's SCE
ETCs for the years 2010 to 2012, we are able to project with certainty Vernon's
TRR during this period and expect that the amount of true.. -up in these years will
be zero. If the Commission does not accept Vernon's proposed ETC Adjustment
Clause, Vernon's TRR for those years will include the same SCE rates in the
Settlement. In subsequent years (2013 and beyond), the ETC Adjustment Clause
3
1 will reflect the differences arising from Vernon's' projected 'ETC charges and the
2 actual, costs incurred by Vernon (including interest on the balances).
3
4 H. OVERVIEW OF VERNON'S TRANSMISSION ENTITLEMENTS
5
6 Q. When did Vernon become a member of the CAISO?
7 A. Vernon became a PTO in the CAISO effective January 1, 2001
8
9 Q. Please describe Vernon's transmission faeilities and entitlements which are
10 under the operational, controlof the CAISO:'
11 A. Vernon sold all of its ownership interests in transmission facilities in 2008. Those
12 sold assets include interests- in portions of the California -Oregon Transmission
13 Project ("COTP"), Mead=Adelanto Project ("MAP"), and Mead=Phoenix Project
14 ("MPP"). Additional information on these facilities is found in testimony on
15 behalf of Vernon in Docket No. EL08-54. Subsequent to the sale of those
16 transmission assets, all of Vernon's remaining transmission costs are associated
17 with using SCE's and the Los Angeles Department of Water and Power's
18 ("LADWP") transmission under three ETCs that continue to remain in effect.
19
20 Q. Please describe. Vernon's ETCs with SCE.
21 A. Vernon has two ETCs with SCE. Under the first ETC, Vernon uses 11 MW of
22 firm, bi-directional transmission service from the midpoint of the Victorville-
23 Lugo 500 kV line (the "Victorville-Lugo ETC"), where SCE accepts schedules of
24 energy for Vernon, to the Vernon City Gate (the interconnection of Vernon and
25 Edison's systems). Under a second agreement, Vernon receives up to 26 MW of
26 firm transmission service from the Mead substation (the "Mead -Laguna ETC")
27 where . SCE accepts energy from the Western Area Power Administration for
28 Vernon's account, to the Vernon City Gate. This second contract enables Vernon
29 to transmit its allocation of energy and capacity from the Hoover Dam to
30 Vernon's local customers.
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Q. Please describe Vernon's ETC with LADWP.
A. Vernon's ETC with LADWP provides .Vernon with 81 MW of firm, long-term
transmission service between the mid -point of the 500 kV Victorville-Lugo
transmission line (a point of interconnection between LADWP's and SCE's
respective control areas) and the 500 kV bus at Adelanto (the "LADWP ETC").
III. CALCULATION OF VERNON'S 2009 TRR
Q. What are the components of Vernon's 2009 TRR?
A. Vernon's TRR consists of three components: (1) the cost of transmission services
purchased under the three, long-term ETCs; (2) administrative and general
("A&G' expenses allocable to these agreements; and '(3) regulatory expenses
allocable to these agreements.
Q. How does the Settlement relate to Vernon's 2009 TRR?
A. The Settlement provides negotiated rates for Vernon's ETCs with SCE effective
on August 1, 2009. By incorporating these negotiated rates, we can calculate
Vernon's 2009 TRR.
Q. How did you calculate Vernon's transmission service expenses for 2009?
A. Vernon's transmission service expenses are the costs that Vernon incurs with
Vernon's three ETCs, described above. For the SCE ETCs, we use the historical
January and February 2009 invoices (for the amount that Vernon paid) and the
negotiated rates from the Settlement for March 2009 through December 2009.
According to the Settlement, rates from March 1, 2009 through July 31, 2009 will
remain approximately the same as January and February. This means that the rate
for the Victorville-Lugo ETC is $1.04756 per kW -month from January 1, 2009
.through February 28, 2009 and $1.04 per kW -month for the period March 1, 2009
through July 31, 2009. However, effective August 1, 2009, the Victorville-Lugo
ETC rate will be $1.25 per kW -month through December 31, 2009. Similarly, the
Mead -Laguna ETC rate is $0.51 per kW -month from January 1, 2009 through
5
I July 31, =2009 and , will be $1.00 per kW -month '' on August 1, 2009 through
2 December 31, 2009. On an annualized basis, 'Vernon will pay $352,173 for the
3 Victorville-Lugo ETC and $94,270 for the Mead-Lagum ETC, for a total of
4 $446,443 for 2009. Exhibit B contains these calculations based on payments
5 recorded:in the -historical invoices.
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7 For'the ETC with-LADWP, we reviewed the 2008and year-to-date 2009 invoices
8 paid by Vernon for transmission services and found that the total monthly expense
9 associated with this contract is $23,020 -in every month except one. We assume
10 that with the exception of that one month, $23,020 is the monthly cost for the rest
11 of 2009 resulting in an annualized cost of $275,665. Columns [B], [C], and [D]
12 of Exhibit C summarize Vernon's 2009 ETC costs'.
13
14 Q. How were Vernon's 2009 A&G expenses determined?
15 A. The A&G element -of a transmission company's TRR generally includes an
16 allocation of all expenses charged (or chargeable) to FERC Accounts 920 through
17 935. As a non jurisdictional entity, `Vernon is not required to maintain FERC
18 accounts. However, Vernon has provided us an estimate of the administrative
19 personnel time and costs associated with transmission -related activities, such as
20 contract administration, monitoring CAISO activities, and providing general
21 regulatory support. According to Vernon, three. of the City's employees will
22 devote a small portion of, their time to these activities, the Resource Planning
23 Manager will devote 36 hours per year to such activities, and a Scheduler and
24 Associate Scheduler will devote 12 and 6 hours per year, respectively, to such
25 activities. The total salary and overhead costs .associated with these personnel is
26 .$5,040 per year. This information is included in our workpapers. Vernon
27 anticipates that these A&G costs' will remain unchanged and will not flow through
28 the ETC Adjustment Clause.
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Q. How were Vernon's 2009 regulatory expenses .determined?
A. Regulatory expenses are the expenses that Vernon incurs for .legal and expert
advisory services .associated with federal regulatory activities and litigation (such
as.the filing of a revised; TRR at FERC).. We have reviewed Vernon's historical
legal expenses associated with the transmission -related i federal regulatory
activities in 2006, 2007, and April through December 2008. These expenses were
$579,268 ; in 2006, $473,222 in 2007, and. $328,282 in 2008. We have also
reviewed Vernon's anticipated future annual regulatory expenses for 2009 and
thereafter, which, is approximately $217;200 per year. This, budget appears
conservative. in light of historical experience. Vernon anticipates that the
regulatorycost will remain unchanged in the future and will not flow through the
ETC Adjustment Clause:
Q. Given the three components of the 2009 :TM what is Vernon's 2009 TRR?
A. As shown in Exhibit C, Vernon's 2009 TRR is $944,348..
IV. THE ETC ADJUSTMENT CLAUSE
Q. Please explain the need for the proposed ETC Adjustment Clause.
A. Vernon's TRR is composed solely of costs associated with the three ETCs.
Assumingi the Settlement is accepted by the Commission, the cost of the two
ETCs with SCE will depend exclusively on SCE's TRR and will change
whenever SCE's TRR or rates change. SCE's TRR can, and often does, change
several timesduringthe course of a year due to changes in SCE's Transmission
Revenue Balancing Account Adjustment ("TRBAA") or Base TRR. If SCE files
a request to. modify its Base TRR- to address an increase in transmission
investments or some other issue, it could create additional cost uncertainty for
Vernon as did the case in Docket No. ER08-1343-000'.- Moreover, since Vernon
does not own transmission facilities, all of its transmission, .A&G, and regulatory
expenses are related to administering its ETCs. It is our understanding that
Vernon's A&G and regulatory expenses are expected to remain constant in the
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foreseeable future, thus Vernon's TRR would change only if the cost of the SCE
ETCs changes. Requiring Vernon to continuously change its TRR each time SCE
changes its TRR would create an additional A&G and regulatory expense burden
for Vernon which would need to be `included in Vernon's future TRRs. Thus,
using an ETC Adjustment Clause to appropriately and automatically adjust
Vernon's TRR would be more transparent and efficient than to require additional
rate filings everytime that SCE's TRR changes in the future.
Q Please explain how the ETC Adjustment Clause will work.
A. The ETC Adjustment Clausefor Vernon's SCE ETCs is based on the mechanics
of the TRBAA as specified in Appendix F, Schedule 3` of the CAISO Open
Access Transmission Tariff ("OATT'). The ETC ' Adjustment Clause is
composed of three parts- (1) a projection of transmission expenses associated with
SCE ETCs for the subsequent year; (2) a true -up for the difference between the
actual and projected transmission expenses from the prior period; and (3) interest
on, the average monthly true -up balance calculated pursuant to the Commission -
approved rate under 18 C.F.R. §35.19a and compounded "quarterly. The true -up
balance and interest would be calculated for a 12-month period beginning on
October 1 of the previous year and ending on September 30 of the current year.
The true -up balance and interest are then added to the projection of transmission
expenses from the SCE ETCs to yield the ETC Adjustment Clause which would
become effective January 1 of the following year.
Q. Please explain the effect of the Settlement on the ETC Adjustment Clause.
A. The Settlement provides the agreed upon ETC rates between Vernon and SCE
through December 31, 2012.= These rates will remain as they were specified and
will not change regardless of any changes to SCE's TRR or HVECAC. Assuming
that the Settlement is accepted by the Commission, the ETC Adjustment Clause
would` implement these Settlement rates from August 1, 2009 through to
December 31, 2012. Since these rates are fixed in advance, we anticipate the
true -up amount for 2009 through 2012 (years in which the Settlement rates are in
I effect) to be zero. However, starting January 1, 2013,.the negotiated rates for the
2 two SCE ETCs will default to SCE's then -effective HVECAC, which is not a rate
3 that has been determined -at this .time. Thus, : when SCE's rate is determined, the
4 ETC Adjustment Clause-. will be used to flow through the changes in Vernon's
5 ETC .costs caused by changes in SCE's HVECAC
6
7 Q. Please provide an example of a true -up via the ETC Adjustment Clause.
8 A. As we mentioned above; 'the Settlement will fix the rates for the SCE ETCs up
9 through 2012.. Exhibits D1, D2, D3, and D4 show the ETC Adjustment Clause
10 for 20,10 (including the true -up for August and September of 2009), 2011
11 (including the true -up for 2010), 2012 (including the true -up for 2011), and 2013
12 (including the true -up for 2012), respectively. As shown in these Exhibits, in
13 each of these four years, the, magnitude of the true -up from the relevant prior year
14 is zero because the rates are set by;the Settlement -and the projected and the actual
15 rates for each year is the same., It is not until 2013 when the Settlement defaults
16 to SCE's then effective HVECAC that a divergence between the actual and
17 projected rates can arise. Thus, for 2013 and 2014, we have used illustrative
18 forecast rates and illustrative actual rates to. demonstrate how the ETC Adjustment
19 Clause would., work for the period beyond the Settlement dates of 2009-2012.
20
21 Q. Please describe the mechanics of Vernon's ETC Adjustment Clause for 2014.
22 A. Exhibit D5 provides an illustrative example of how the. ETC Adjustment Clause
23 would work and the related expenses for 2014. Specifically, the illustrative
24 projection for the SCE -related transmission expenses (first component) for 2014
25 in the illustrative example (Exhibit D5) is $2. 1 O&W-month or a total annualized
26 cost of $9325400. The second: component is, the true -up of the difference between
27 2013 projected and 2013 actual rates. As mentioned before the balance is
28 calculated at the close of September 30 for the 12 months prior. Again, the
29 illustrative example in Exhibit D5 shows the true-upof expenses for October
30 2012 through September 2013. This example shows that it is possible to over- or,
31 under -collect the ETC expenses as the illustrative `actual' rate fluctuates from
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$1.93/kW-month to $2 05/kW-month through the 12 month period and deviates
from the illustrative `projected' rate of $1.95/kW-m6nth for 2013. The
cumulative difference shown in the illustrative example over the 12 month period
is $12,210. The third component is the interest on this cumulative difference
compounded quarterly pursuant to the Commission -approved rate and. is $177 for
the 12 month period. The over/under-collection continues to earn compounded
interest up to December 31 2013. These last two components are added to the
projected 2014 SCE ETC expense and is effective January 1, 2014. In total, the
illustrative ETC Adjustment Clause projected for 2014 is $944,787.
Q. How is the ETC Adjustment Clause related to Vernon's TRR?
A. Note that the ETC Adjustment Clause only covers Vernon's expenses for the two
ETCs with SCE. The City of Vernon has indicated' that all other expenses
(LADWP ETC, A&G. and, regulatory expenses) are anticipated to remain
unchanged. For the illustrative example of 2014 TRR, the ETC Adjustment
Clause plus the other expenses that are unchanged, is $1,443,267 as shown in
Exhibit E.
V. CALCULATION OF VERNON'S 2010-2012 TRR
Q. What happens if the ETC Adjustment Clause is not approved by the
Commission?
A. In the event that the ETC Adjustment Clause is not approved, we have calculated
Vernon's TRRs for 2010 through 2012 based on the rates negotiated in the
Settlement. The TRRs for 2010 through 2012 have the same components as the
TRR calculated for 2009.
Q. How did you calculate Vernon's transmission service expense for 2010-2012?
A. We base our calculations for the SCE ETCs on the negotiated Settlement rates for
2010 through 2012. The combined annualized expense for both SCE ETCs is
$720A80, $777,000, and $848,040, for 2010, 2011, and 2012, respectively, where
10
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each SCE ETC is listed in Exhibit F. For, the LADWP ETC, we assume that
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transmission service costs remain constant at $23,020 per month resulting in an
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annualized , cost; of $276,240. Overall, the annual expenses from these three
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contracts, are,$996,720, $1,053,240, and $1J24,280 for 2010, 2011, and 2012,
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Q.
How were Vernon's A&G expenses determined for 2010-2012?
8
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The A&G expenses for. 2010-2012 are not expected to change from 2009's
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estimate of $5,040 per year, shown in Exhibit B. This assumption is shown in
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Exhibit F.
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Q.
How were Vernon's regulatory expenses determined for 2010=2012?
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The regulatory expenses for 2010-2012 are not expected to change from 2009's
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estimate of $217,200 per year, shown in Exhibit C. This assumption is shown in
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Exhibit F.
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Q.
What is Vernon's total TRR for each year from 2010-2012?
18
A.
In the event that the ETC Adjustment Clause is not approved, Exhibit F shows
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Vernon's TRR for each year from 2010 :through 2012. These amounts are
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$1,218,960, $1,275,480, and $1,346,520 for 2010, 2011, and 2012, respectively.
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22
Q.
Does this conclude your direct testimony?
23
A.
Yes.
11
The' Brattle Group Testimony #List of Attachments
Exhibit A: Qualifications
Exhibit A1: Philip Q Hanser, Principal
Exhibit A2: Judy W. Chang, Principal
Exhibit B: Historical and Offer of Settlement ETC Rates and Costs
Exhibit C: 2009 Transmission Revenue Requirements
Exhibit D: ETC Adjustment Clause Calculations
Exhibit D1: 2010 ETC Adjustment Clause
Exhibit D2: 2011 ETC Adjustment Clause
Exhibit D3: 2012 ETC Adjustment Clause
Exhibit D4: 2013 Illustrative ETC Adjustment Clause
Exhibit D5: Illustrative 2014 ETC Adjustment Clause
Exhibit E: Actual 2010-2012 and Illustrative 2013-2014 Transmission Revenue Requirements
with ETC Adjustment Clause
Exhibit F: 2010-2012 Annual Transmission Revenue Requirements
Workpaper: Projected Administrative and General Expenses
Workpaper: Projected Regulatory Expenses
Attachment: ETC Invoices Paid by the City of Vernon
The Brattle Group. Testimony Exhibit A: Qualifications
of Philip Q Hanser and Judy W. Chang
Exhibit Al: Philip Q Hanser, Principal ............................................................................................. I
Exhibit A2: Judy W. Chang, Principal.. ...... ..... ...................................... 21
PHILIP Q HANSER Principal
Philip Q"Hanser is a principal of The Brattle Group and has over twenty-five years of consulting and
litigation experience in the energy industry. His expertise includes issues ranging from industry
structure, market power and associated regulatory questions, to specific operational and strategic
questions such as transmission: pricing, generation planning, tariff strategies, fuels procurement,
environmental issues, forecasting, demand -side management, and other management and financial
issues. He has supported clients' efforts in insurance recovery of environmental liabilities arising
from former manufactured gas plant sites, assessed liability risk in mass tort suits, and designed
statistical database auditing procedures.
He has appeared as an expert witness before the U.S. Federal Energy Regulatory Commission
(FERC), the California Energy Commission (CEC), the New Mexico Public Service Commission
(NMPSC), the Public Service Commission of Wisconsin (PSCW), the Vermont Public Service
Board (VPSB), the Public Utilities Commission of Nevada (PUCN), the Connecticut Siting
Commission, the Pennsylvania Department of Environmental Protection, before arbitration panels,
and in Federal and state, courts. He served for six years on the American Statistical Association's
Advisory Committee to the Energy Information Administration (EIA). He serves on CIGRE's
(Conseil International des Grands`Reseaux Electriques) Working Group C5-8, Working Group on
Renewables and Energy Efficiency in a Deregulated Market. Prior to joining The Brattle Group, he
served as the manager of the Demand -Side Management Program at the Electric Power Research
Institute (EPRI). He has published widely in leading industry and economic journals. Mr. Hanser
has taught at the University of the Pacific,University of California 'at Davis, and Columbia
University, and guest lectured at the Massachusetts Institute of Technology, Stanford University,
and the University of Chicago.
REPRESENTATIVE EXPERIENCE
Analysis of Electricity Generation, Contracts, and Wholesale Markets
• For the California Department of Water Resources provided expert testimony in
federal bankruptcy court with regard to the public interest standard to be applied to
Calpine Corporation's rejection of its contracts. This assignment included a
valuation of the contract over time through the use of a simulation model of the
California market, as well as an assessment of the potential reliability implications
for the California market:
PHILIP Q HANSER
Principal 2
For the . California Department of Water Resources and the California. Attorney
General's Office, provided experttestimony on damages resulting from Sempra
Energy Resources breaches of its: power, purchase agreement. in both arbitration
hearings and California state court. _ Analyzed two years, of hourly data on energy
deliveries, market prices, ISO charges, and invoice charges to: identify and evaluate
performance violations and:invoice overcharges., Assisted 'counsel in developing the
theory of the case and provided general litigation, support in preparation, for and
during arbitration.
• For Dominion Electric Marketing,:: Inc. (DEMI), provided assistance in their response
to a complaint by United Illuminating (UI) regarding their wholesale supply contract.
The dispute centered on the allocation of reliability must run costs between UI as a
load -serving entity and DEMI as wholesale supplier.
• For the California Department. of Water Resources critically reviewed the California
.ISO's proposed implementation of locational marginal pricing (IMP) and analyzed
implications for "seller's choice" supply contracts. Developed a framework for
quantifying the incremental congestion,costs that ratepayers would face if suppliers
financially delivered power to the lowest priced nodes; estimated potential
incremental contract costs using a third party's GE -MAPS market simulations (and
helped to improve their model inputs to more accurately reflect the transmission
system in California). Made recommendations to the CAISO as to how to address
the issue.
• Provided expert testimony in Massachusetts state court on the.damages incurred by a
power plant developer as a result of alleged contractual violations by a supplier for a
plant constructed in ISO -NE.
• For a Florida utility, provided a confidential expert report evaluating the benefits.of
the power from a co -generator and its potential rate implications, and assisted in the
negotiation of a co -generation contract with a large, industrial customer.
• Assisted a U.S. electric utility in the preparation of a bid proposal to an industrial
firm for the leasing of a new power plant. The assignment included risk analysis of
the proposal, assessment of financial and rate impacts, and market assessment of
competitors' potential offerings.
PHILIP Q HANSER
Principal
Resource Planning and Procurement
• For the,EdisonElectric Institute, co-authored a report on the general inapplicability
of standard financial portfolio theory to the resource portfolios � of utilities.
• For the investor -owned utilities of Wisconsin, provided testimony before the Public
Service Commission of Wisconsin on of capital issues for use in its statewide
resource planning exercise.
• For an international development bank, evaluated generation resource needs for an
Eastern European country as well as:a determination of alternative means to meet
those generation needs. This assignment included analysis of the impact of
privatizationon the country's economy, its import and export sectors;:and future
development of electricity and gas resources.
Environment
• For an Eastern utility with substantial coal -generating facilities, provided advice with
regard to maintenance procedures and risk exposure to New Source Review
standards under the Clean Air Act Amendments.
• For a Western generator with substantial coal -generating facilities he 1as provided
assistance with regard to responding to allegations by the Environmental Protection
Agency of failure to comply with the New Source Review standards under the Clean
Air Act Amendments:
• For Illinois Power Company, provided expert testimony in federal court on the
regulatory and rate base implications of the Clean Air Act Amendments, in support
of the calculation of noncompliance economic damages arising from New Source
Review.
• For a gas utility, assisted in the developient-of potential manufactured gas liabilities
for use in insurance recovery and in estimating potential recovery under a variety of
insurance,allocation theories and estimated the risk distribution of the estimates.
3
PHILIP Q HANSER
Principal 4
• For a gas utility, assisted in the assessment of the announcement effect of
environmental liabilities on its cost of capital. This assignment included estimation
of changes in market betas for pre and post -,environmental liability announcement.
Energy Efficiency, Demand -Side Management, and Reneivables
• For Central, Vermont Public Service, provided expert testimony on the impact of its
demand -side management programs before the Vermont Public. Service Board.
• For Ameren/UE's Illinois subsidiaries, provided expert testimony_ on the potential for
gas demand -side management and resulting potential rate implications:,
• For a Northeast utility developed an assessment of the potential penetration -rate of
microturbines. For the utility service territories under consideration, evaluated the
back-up generation rates and connection charges likely to be incurred for such
systems to determine customer costs and benefits.
• For a utility located in WECC procuring renewable resources, provided a system
integration study for; a range of renewable project proposals Used production
costing and power flow models to estimate the "deliverability" of various proposals,
including estimating the LMP prices and the potential congestion costs. Ranked the
proposed renewable power projects by their.: estimated benefits and costs, and
delivered a formal presentation at the completion of the project.
• For a power marketer and developer of independent power projects in Great Britain,
assisted in the preparation of comments on proposals by the UK pool regarding the
role of demand -side bidding and the pricing of transmission losses.
• For a Texas utility, provided expert testimony regarding breach of contract claims
made against it by an industrial participant in an energy efficiency project.
Reviewed the energy efficiency impacts of program. Calculated the net present
value of the project in relation to variousi rate. options and market prices.
• For Connecticut Light and Power, providedlestimony in support of an application
for a Certificate of Environmental Compatibility and Public Need for the
construction of a 345-kV electric transmission line and reconstruction of an existing
PHILIP Q HANSER
Principal 5
1.15-kV electric transmission line. At issue was the use of distributed resources to
substitute for the proposed lines.
Analysis of Market Power
• For the California Parties, provided litigation support and testimony regarding
manipulation of energy and ancillary service market prices and the outage behavior
of gas fired power plants during 2000-01`. The proceeding, before the Federal
Energy Regulatory Commission'involved Enron, Dynegy, Mirant, Reliant, Williams,
and other suppliers in the U.S. and Canada. The analyses focused on the use by
suppliers of generation, outages to affect market prices through physical withholding,
as well as the use of pricing to yield economic withholding.
• For the California Parties, provided litigation support and testimony regarding
Enron's transmission and ancillary services 'market manipulation strategies,
including `Death Star' and `Get Shorty.'
• For Southern California Edison, submitted testimony before the FERC describing the
implications for the electricity market of the manipulation of gas market prices.
• For Sierra Pacific Resources Company, provided expert testimony before the Public
Utilities Commission of Nevada and the FERC regarding the market power
implications of generation asset divestiture required for the merger of Sierra Pacific
Power and Nevada Power Company. Developed a Cournot market model to assess
the market power implications of selling, off alternative groupings of generation.
• For the Pennsylvania -New Jersey -Maryland Interconnection, LLC (PJM) co-
authored annual report on the state of its markets. The report included an assessment
of the market's competitiveness and potential structural deficiencies, and identified
potential instances of market abuse.
• For PJM, developed an ensemble of metrics for assessing market power in its
markets. The metrics included an early warning system to permit PJM interventions
into market abuse at the earliest possible stage:
PHILIP Q HANSER
Principal 6
• For PJM, developed software for unilateral market power assessment: and assisted
PJM in its preliminary implementation. Its use was demonstrated with an incident
involving potential market power abuse by PJM members.
RTO Design and Participation
• For Northeast Utilities provided .testimony before the FERC with regard to the
economics of imposing local installed capacity (LICAP) requirements on ISO -NE.
Also has provided expert testimony before the FERC in support of its applications
for market -based rate authority.
• For NSTAR provided testimony before the, FERC on several matters including the
necessity of imposing bid caps on the New England electricity market, replacement
energy rates for generators when transfer capability into a transmission -constrained
zone was reduced because of system upgrades, and the appropriateness of granting
market -based rate authority to a generator in a transmission -constrained zone.
Developed a Cournot market model to forecast the potential impact on market prices
in the transmission -constrained zone that.the majority ofNSTAR's service territory
is located.
• For Nevada Power Company; provided expert testimony before the FERC for its
market -based rate authority. application.
• For Otter Tail Power .Company, provided an affidavit to the FERC assessing how the
Midwest ISO's proposed,Transmission and Energy Market Tariff would affect Otter
Tail Power both operationally and financially. Based on the strategies that were
pursued by some market participants during the ,200.1 California electricity market
crisis, demonstrated the potential to pursue similar strategies in MISO and harm
Otter Tail. and its customers.
• For Edison Mission Energy's subsidiary Midwest Gen, provided expert testimony to
the FERC for its market -based rate authority application..
• For a Midwest utility, examined the implications of differing configurations of the
independent system operator on potential market power concerns. The issue
PHILIP Q HANSER
Principal 7
particularly examined was the question of seams and how different ISO
configurations affected the costs of transactions.
• Co-authored a report for the New York Independent System Operator's (NYISO)
assessing the reliability implications =of modifying its rules regarding installed
capacity.
• Submitted testimony to the Public Utilities Commission of Texas (PUCT) regarding
a proposed rule to allocate costs of procuring replacement reserves to market
participants in ERCOT. The proposed rule required ERCOT to assign the majority
of such costs directly to market participants who relied on ERCOT's balancing
energy (i.e., real-time energy) market. However, a review of the market rules and the
historical evidence indicated that the majority of the procurement of replacement
reserves was not caused by this behavior. The PUCT rejected the proposed cost
allocation rule; and instead required ERCOT to uplift the replacement reserve costs
based on the load ratio shares of market participants until the implementation of a
reasonable allocation rule or the start of the Texas Nodal Market.
• For the Edison Electric Institute, authored a report on standard market design and its
implications for utilities within regional transmission organizations.
Forecasting and Weather Normalization
• For an electric utility in the Southeast, reviewed<the existing weather normalization
process and diagnosed problems with weather data and regression model. Developed
alternative daily and monthly normalization models, improved degree day
specification, selection of weather stations, and regression specification to double
prediction accuracy and improve stability of normalization process.
• For PJM, conducted a comprehensive review of its models for forecasting peak
demand and re -estimated new models to validate recommendations. Individual
models were developed for 18 transmission zones as ,well as a model for the
entire PJM system.
PHILIP Q HANSER
Principal 8
• For a Southwestern utility, developed models for forecasting monthly sales -and
loads for the residential, commercial and industrial customer classes using primary
data on customer loads, weather conditions and economic activity.
• For the Public Service Company, of New Mexico, provided expert testimony before
the Public Utilities Commission of New Mexico regarding the forecasted growth of
the El Paso, Texas and Juarez, Mexico markets and their electricity requirements.
• For a Southeastern utility, developed a model for forecasting monthly demand that
incorporated the impacts of. its significantly declining housing market and which
served the basis for its treasurer's revenue forecast.
Rate Design and Related issues
• For Ameren/UE's Missourisubsidiary, provided expert testimony on its rate design
before the Missouri Public Utility Commission. Assisted the development of
company witnesses' rationale for the choice of cost of service allocation method,
developed benchmarks for the rate increase against similarly situated utilities, as well
for other commodities' escalations, and evaluated - proposed demand -side
management programs and, rate options.
• For Ameren/UE's Illinois subsidiaries, provided expert -testimony on the potential for
gas demand -side management. The testimony discussed potential rate implications
of such programs .on the revenue of the utilities. .
• For the Edison, Electric Institute, co-authored a series of papers with'.regard to issues
facing utilities. The reports covered the issues of fuel adjustment clauses; .mitigating
large rate increase. impacts, and the Energy Policy Act of 2005.
• For a U.S. electric utility,.assisted in the valuation of generation assets for use in its
testimony on stranded costs. This included development a-fmancial model to
determine the generation assets' market value, development of a convolution
algorithm to convert market scenarios into a probability distribution of asset values,
and statistical analysis of the relationship of the utility's generation assets' operating
costs in comparison to its competitors. The assignment also included testimony
preparation, interrogatories, and rebuttals.
PHILIP Q HANSER
Principal 9
• For the City of Vernon submitted testimony to the FERC regarding its revenue
requirements for transmission.
Transmission
• Before staff members of the FERC, assisted in the development of a review of the
implications of the restructuring in transmission assets' cost of capital
• For a power marketer and developer of independent power'projects in Great Britain,
assisted in the preparation of comments on proposals by the UK pool regarding the
pricing of transmission losses and the role of demand -side bidding.
• For a European transmission company, .provided an , analysis of the likely
development of the European electricity market. Also assessed market implications
for the transmission company of modifications to the transmission grid.
• For Hydro Quebec, provided expert testimony before the Regie d'Energie regarding
whether a set of privately held transmission facilities constituted a looped
transmission system and, thus, was subject to requests for transmission service.
Plant Performance and Strategy
• For the Keystone-Conemaugh Project Office, performed a benchmarking analysis to identify
the areas in which Keystone and Conemaugh coal units were better performing or under-
performing compared to other units with similar characteristics, This involved comparing
the historical operational and cost performance of the Keystone and Conemaugh coal units
against their peer groups; identifying the areas where the performance of the Keystone and
Conemaugh coal units were above and below the average quartile of their peer groups; and
developing metrics and methodologies to combine the results of individual comparisons
across the operational and cost performance assessments.
• For a U.S. electric utility, assisted in the development of a legislative and regulatory
strategy with regard to restructuring. This assignment included generation asset
valuation in a competitive market, development of stand-alone transmission and
distribution rates under cost -of -service and performance -based regulation, and
estimation of stranded costs.
PHILIP Q HANSER
Principal 10
Other energy experience
• For the Electric Power Research Institute (EPRI), developed and directed a research
program to provide electric utilities the following capabilities: marketing research,
pricing and rate design, integrated resource planning, capital budgeting,
environmental impacts of electric utilities and end -use technologies,. load research,
forecasting, and demand -side management through software tools, database
development and technology development. Assisted in the development of the Load
Management Strategy Testing Model (LMSTM), enhancements to the Electric
Generation Expansion Analysis, Model. (EGEAS). Co -wrote reports_ on the
environmental impacts of electric technologies, environmental externalities, cost -
benefit analysis of evaluation of DSM programs, rate design and costing, integrated
resource , planning, impacts of interruptible . and curtailable loads, product
differentiation, activity -based costing, DSM program evaluation, and others. Served
as project manager of ,the Edison Electric Institute (EEI), National Rural Electric
Cooperatives Association (NRECA), American Public Power Association (APPA),
and National Association of Regulatory Utility Commissioners (NARUC) jointly
sponsored Electric.Utility Rate Design Study (EURDS). Represented the Institute
before various regulatory commissions, Federal agencies, and utility executives. He
served on the Environmental Protection Agency's advisory committee for the Clean
Air Act Amendments. He also served as the operating agent for, Annex IV, Improved
Methods for Integrating Demand -Side Options into Utility Resource Planning, of the
Intemational Energy Agency Agreement on Demand -Side Management.-
• For a California utility, supervised short- and long-term�forecasts of sales and peak
demand for use inlresource and corporate planning. Supervised and helped prepare
forecast documentation for public hearings before the California Energy Commission
and represented the utility to the Commission on the forecast. Supervised the design
and implementation of long-term strategic planning:. and financial models, and
prepared both marginal and embedded cost of service studies for the utility and
assisted in their use for the design of customer rates. Evaluated the impact of energy
conservation programs and legislation on long-term system resource requirements.
Designed and implemented the residential survey of appliance holdings and
commercial customer equipment survey.
PHILIP Q HANSER
Principal 11
Non -energy Related
• Submitted testimony in bankruptcy court ` regarding ` the estimation of inventory
subject to reclamation by a wholesale pharmaceuticals supplier which was sold to a
bankrupt retail drug chain. The retail chain failed to maintain proper inventory
records and a statistical approach which used a 'combination of data on overall'
inventory and the shipment and replenishment records of the supplier was used to
develop the estimate.
• Designed a statistically valid database sampling procedure for assessing the validity
of insurance claims arising from mass tort actions. The database contained summary
information on the claims and for each claim there was, at times, voluminous
information on the individual cases. The sampling procedure was used to determine
which -records would be chosen and assessed the individual''s claim eligibility. `
• Assessed the liability risk of an insurance company that provided coverage relevant
to a mass tort suit. A Markov chain model was developed to estimate the size`of the
potential population and then a risk model was developed to calculate potential
exposure.
TESTIMONY AND REGULATORY FILINGS
Before the . Pennsylvania Public Utility Commission, Docket No. P-2008-2020257, prepared
testimony on behalf of Wellsboro Electric Company concerning the causes and pricing of
transmission congestion, July 30, 2008.
Before the Regie De L'Energie, Prepared Affidavit on Behalf of Hydro -Quebec regarding the public
availability of SIS reports performed by a transmission provider, June 19, 2008.
Before the Federal Energy RegulatoryCommission, Docket No. EL08- -000, Prepared Direct
Testimony on Behalf of the City of Vernon's revised TRR filing with the FERC, April 3, 2008.
Before the Regie De L'Energie, Prepared Expert Report on Behalf of Hydro -Quebec TransEnergie
to assess whether the transmission facilities owned by ELL may be considered as a "radial generator
lead", March 13, 2008.
PHILIP Q HANSER
Principal 12
Before the American Arbitration Association, Case No. 74Y 1980019606MAVI, Prepared Rebuttal
Report on Behalf of the California Department of Water Resources to evaluate the reports that
William Hogan, Jeffrey Tranen, and Ellen Wolfe provided on behalf of Sempra Generation, June 4,
2007.
Before the American Arbitration Association, Case No. 74Y1,980019606MAVI, Prepared Expert
Report on Behalf of the California Department of Water Resources to evaluate certain claims made
by the California Department of Water Resources ("DWR") in its Demand for Arbitration regarding
the performance of Sempra Energy Resources, now known as Sempra Generation, under the Energy
Purchase Agreement between the parties; and to -calculate amounts that Sempra would owe to DWR
assuming liability is established, May 14, 2007.
Before the United.States Bankruptcy Court, Northern District of Ohio, Eastern Division, Case Nos.
01-44007 through 01-44015, Expert Report in regard to McKesson's inventory reclamation in the
Phar-Mor bankruptcy, March 9, 2007.
Before the Public Utility Commission of Texas, Docket No. 3,3416, Prepared Rebuttal Testimony on
Behalf of Constellation New Energy, Inc.'s appeal and complaint of ERCOY decision to approve
PRR 6.76, PRR 674 and request for expedited relief, January 11, 2007.
Before the Public Utility Commission of Texas, Docket No..33416, Prepared Direct Testimony on
Behalf of Constellation NewEnergy, Inc. to analyze and discuss the flaws and potential negative
impacts of the allocation methods under Protocol Revision Request;("PRR") 676 which relates to
procurement costs for Replacement Reserve Service ("RPRS") and Out of Merit Capacity,
November 22, 2006.
Before the American.Arbitration Association, Case No. GIC 789291, Prepared Rebuttal Report�on
Behalf of California Department of Water Resources vs. Sempra Energy Resources, July 11, 2006
Before the State Office of Administrative Hearings, Prepared Expert Report on Behalf of TXU
Energy Solutions, regarding their demand -side. management program and the difference between the
actual and projected savings in the energy bill of University of Texas, July 7, 2006.
Before the ,Missouri, Public Service Commission, Case No. ER-2007-0002, Prepared Direct
Testimony on Behalf of Union Electric Company with regard to Ameren UE's rate design proposals, .
July 5, 2006.
PHILIP Q HANSER
Principal
13
Before the American Arbitration Association, Case No. GIC 789291, Prepared Expert Report on
Behalf'of California Department of Water Resources vs. Sempra Energy Resources, June 9, 2006.
Before the Superior Court of the State of California, J.C.C.P. Nos. 4221, 4224, 4226 and 4228,
Prepared Declaration in support of California State Agencies' opposition to motion on shortened
time and motion in support of preliminary approval of class action settlement, June 8, 2006.
Before the Superior Court of the State of California, J.C.C.P. Nos. 4221, 4224, 4226 and 4228,
Prepared Declaration in support of California State Agencies' opposition to proposed publication
notice, January 13, 2006.
Before the United States Bankruptcy Court, Case No. 05-60200(BRL), Prepared Declaration on
Behalf of Calpine Corporation with regard to the public interest standard for the rejection of the
contract, December 30, 2005.
Before the FERC, Docket No. EL05-76-001, Prepared Direct Testimony on Behalf of Dominion
Energy Marketing, Inc. (DEMI), regarding a dispute between DEMI and The United Illuminating
Company as to which party is responsible for paying certain costs associated with Reliability Must -
Ran agreements under a December 28, 2001 Power Supply Agreement between the two parties,
December 5, 2005.
Before the American Arbitration Association, Case No. 74Y1980019304VSS, Prepared Expert
Report on Behalf of California Department of Water Resources vs. Sempra Energy Resources with
regard to damages from multiple contract breaches, May 2005.
Before the FERC, Docket No. EL03-180-000, Prepared Supplemental Testimony on Behalf of the
California Parties with regard to Enron's circular scheduling and paper trading gaming practices,
January 31 2005.
Before the FERC, Docket No. ER96 ; 496-010, et al., Prepared Affidavit on Behalf of Northeast
Utilities Service Company and affiliated companies market -based rate authorization, September 27,
2004, Revised December 9, 2004.
Before the Connecticut Siting Board, Docket 2,17 Prepared' Testimony on Behalf of Connecticut
Light and Power in support of its application fora` Certificate of Environmental Compatibility and
PHILIP Q HANSER
Principal 14
Public Need for the construction of a 345-kV electric transmission line and reconstruction of an
existing 115-kV electric transmission line between Connecticut Light and Power Company's
Plumtree Substation in Bethel, through the Towns of Redding; Weston, and Wilton, -and to Norwalk
Substation in Norwalk, Connecticut, November, 2004.
Before, the FERC, Docket No, ER04-691-000 Prepared Affidavit on Behalf of Otter Tail Power
Company (OTP). regarding problems that may result from the implementation of M3SO's markets
tariff in DTP's region, May 7, 2004.
,Before the, FERC, Docket No. ER03-563-030, Prepared Joint Affidavit with Judy W. Chang on
Behalf of Devon Power LLC, et al., March 24, 2004.
Before the FERC, Docket No. EL03-180-000, PreparedDirectTestimony on Behalf of the
California Parties with regard to Enron's .circular scheduling and paper, trading gaming practices,
February 27, 2004
Before the Commonwealth of Massachusetts, Case No. 99-6016, Prepared Expert Report on Behalf
of Alstom Corporation and Black and Veatch vs Meriden Corporation, LLC, Review of "Value of
the Meriden Power Project", January 9, 2004 ,
Before the FERC, Docket No. EL03-159-000, Prepared Declaration on Behalf of The California
Parties, Re: Gaming Activities Of Modesto Irrigation District, October, 2003.
Before the FERC, Docket No. ER03-118-000, Prepared Affidavit on Behalf of Otter Tail .Power
Company For Otter Tail Power Company, assessing how the Midwest ISO'. s proposed -Transmission
and Energy Market Tariff will affect Otter Tail Power both operationally and financially, September
15, 2003.
Before the Pennsylvania Environmental Hearing Board, New Jersey Department of Environmental
Protection vs. Pennsylvania Department of Environmental Protection and Lower Mount Bethel
Energy, LLC, Docket No. 2001-280-C, Prepared Expert Report on Behalf of Pennsylvania. Power
and Light, May 2, 2003.
Before the FERC, Docket No. EL00-95-069, Prepared Rebuttal Testimony on Behalf of Southern
California Edison for the California Parties regarding manipulation of energy and ancillary service
market prices and the outage behavior of gas fired power, plants, March 20, 2003.
PHILIP Q HANSER
Principal 15
Before the FERC, Docket No. EL00-95-069 Prepared Testimony on Behalf of Southern California
Edison for the California Parties regarding manipulation of energy and ancillary service market
prices and the outage behavior of gas fired power plants, February 24, 2003.
Before Southern District Court of Illinois, Docket No.99-833-MBR, Prepared .ExpertReport for
Department of Justice, Environmental Protection Agency vs; Illinois Power Company and Dynegy
Midwest Generation regarding<the likely rate treatment of; July 29, 2002.
Before the FERC, Docket No. ER99-3693-000, Prepared Direct Testimony on Behalf of Edison
Missi'on1nergy and Edison Mission Marketing<and Trading, Inc. on behalf of Midwest Generation's
application for market -based rate authority, April 1,2002
Before the FERC, Docket No. ERO 1-890-000, Prepared Rebuttal Testimony on Behalf of NSTAR on
the appropriate rates for generators during transmission upgrades or enhancements requiring
substantial and sustained reduction in transfer capability, September 21 2001.
Before the FERC, Docket No. EL01-79-000, Prepared affidavit on Behalf of NSTAR, in their
intervention of the granting of market -based rate authority to Sithe, May 2001.
Before the FERC and the Public Utilities Commission of Nevada, Docket No. ECO-173-000,
Prepared Affidavit on Behalf of Sierra Pacific Resources Company, regarding the market power
implication of generation asset divestiture required for the merger of ;Sierra Pacific Power and
Nevada Power Company, February 23, 2001.
Before the California Energy Commission, Prepared Expert Report on Behalf of Calpine
Corporation; Socioeconomic Resources: Economic Benefits of the Metcalf Energy Center, October
27, 2000.
Before the FERC, Docket No. EL00-83-000, Prepared Affidavit on Behalf ofNSTAR with regard to
the necessity of imposing bid caps on the New England electricity market, June 23, 2000.
Before the FERC, Docket No. ER99-2338-001, Prepared Direct Testimony on Behalf of Nevada
Power Company in support of the divestiture of its generation assets, June 24, 1999.
PHILIP Q HANSER
Principal 16
Before the FERC, Docket No. ER99-2338-001, Prepared Direct Testimony on Behalf of Nevada
Power Company -in support of the divestiture of its generation assets, March 301999.
Before the Vermont Public Service Board, Docket No. ,6018, Prepared Rebuttal Testimony on Behalf
of Central Vermont Public Service Corporation on the impact of its demand -side management
programs, April, 10, 1998:
Before the New Mexico Public Utility Commission, Case No. 2769, Prepared Direct Testimony
prepared on Behalf of the Public Service Company of New Mexico regarding, forecasted growth of
the El Paso and Juarez, Mexico markets, 1997.
Before the Public Service, Commission of Wisconsin, Docket No. 05-EP-7, Prepared Direct
Testimony on Behalf of investor -owned utilities of Wisconsin on the utilities cost of capital, May
1995.
Before the FERC, Docket No. RP95-363-0,15, Prepared Affidavit on Behalf of Southern California
Edison describing the implications for the electricity market of the manipulation of gas market
prices.
ACADEMIC HISTORY
Guest Lecturer, Energy Laboratory Short Courses, Massachusetts
Institute of Technology, Cambridge, MA
Visiting Lecturer, Department of Economics;
University of California, Davis; Davis, CA
Assistant Professor, Departments of Economics and Mathematics,
University of the Pacific, Stockton, CA
Ph.D. Candidacy Requirements Completed, Columbia University, NY
Phil.M. (Economics and Mathematical Statistics) Columbia University
A.B. (Economics'and Mathematics) The Florida State University, FL
Time Series and Econometric Forecasting, University of California
at Berkeley Engineering Extension Course
Data Analysis and Regression, American Statistical Association
Short Course, San Diego, CA
1997-1998
1981-1982
1975-1980
1975
1975
1971
September 1979
August 1978
PHILIP Q HANSER
Principal
PROFESSIONAL MEMBERSHIPS
American Statistical Association,
Member of Committee on Energy Statistics,
Institute of Electrical and Electronics Engineers,
Association of Energy Service Professionals, Board Member,
Journal ofADSMP, Editor,
American Economic Association,
HONORS
Teaching Incentive Award, University of the Pacific
Teaching Assistantship in Econometrics, Columbia University
National Science Foundation Research Traineeship
Undergraduate and Graduate Research Assistantships,
Florida State University
Omicron Delta Epsilon, Economics Honor Society
PUBLICATIONS AND PRESENTED PAPERS
17
1974-current
1993-1999
1986-current
1991-1995
1995
1979
1974
1972 -1974
1968 -1972
1971
"Utility Supply Portfolio Diversity Requirements" (with Frank Graves), The Electricity Journal,
Vol. 20, Issue 5, June 2007.
"Electric Utility Automatic Adjustment Clauses Revisited: Why They Are Needed More Than Ever"
(with Frank Graves and Greg Basheda), The Electricity Journal, Vol. 20, Issue 5; June 2007.
"Rate Shock Relief' (with Frank Graves and Greg Basheda), Electric Perspectives, May/June 2007.
"Rate Shock Mitigation" (with Frank Graves and Greg Basheda), prepared for Edison Electric
Institute, May 2007.
"Wire We Here? Coal in the West," Law Seminars International, Coal in the West Conference,
Denver, Colorado, March 30, 2007.
PHILIP Q HANSER
Principal
18
"Electric Utility Automatic Adjustment Clauses: Benefits and Design Considerations" (with Frank
Graves and Greg Basheda), Edison Electric Institute, August 2006.
"Can Wind Work In An LMP Market?" (with Serena Hesmondhalgh and Dan Harris), Natural Gas
& Electricity, November 2005.
"The CAISO'S Physical Validation Settlement Service: A Useful Tool for All LMP-Based Markets"
(with Jared S. des Rosiers, Metin Celebi, Joseph B. Wharton), The Electricity Journal, September
2005.
"Does SMD Need a New Generation of Market Models? Or How I Learned to Stop Worrying and
Enjoy Carrying a Pocket Protector," SMD Conference, Washington, D.C., December 5, 2002.
"A Summary of FERC's Standard Market Design NOPR,"Edison Electric Institute, August 2002.
"Standard Market Design in the Electric Market: Some Cautionary Thoughts," SMD Conference,
May 10, 2002, Chicago, Illinois.
"The Design of Tests for Horizontal Market Power in Market -Based Rate Proceedings" (with James
Bohn and Metin Celebi), The Electricity Journal, May 2002.
"The State of Performance -Based Regulation in the U.S.Electric Industry" (with D.E.M.
Sappington, J.P. Pfeifenberger, and G.N. Basheda), The Electricity Journal, October 2001.
"Deregulation and Monitoring of Electric Power Markets" (with R.L.Earle and J.D. Reitzes), The
Electricity Journal, October 2000.
"Shortening the NYISO's Installed Capacity Procurement Period: Assessment of Reliability
Impacts," NYISO, May 2000.
"PJM Market Competition Evaluation White Paper," (with Frank C. Graves), prepared for PJM,
L.L.C., October 1998.
"Lessons from the First Year of Competition in the California Electricity Market" (with R.L.Earle,
W.C. Johnson, and J.D. Reitzes), The Electricity Journal, October 1999.
PHILIP Q HANSER
Principal 19
Comments to the FERC concerning Regional Transmission Organizations Notice of Proposed Rule
Making, RM99-2, (with Peter Fox -Penner), September 17, 1999.
"In What Shape is Your ISO?" (with J.P. Pfeifenberger, G.M. Basheda and P.S. Fox -Penner),
The Electricity Journal, Vol. 11, No. 6, July 1998.
"What's in the Cards for Distributed Resources?" (with J. P. Pfeifenberger and P.R. Ammann), in
Special Issue of The Energy Journal, Distributed Resources: Towards a New Paradigm of the
Electricity Business, January 1998.
"One -Part Markets for Electric Power: Ensuring the Benefits of Competition" (with F.C. Graves,
E.G. Read, and R.L. Earle), in Power Systems Restructuring: Engineering and Economics, ed. M.
Ilic, F. Galiana, and L. Fink, (Boston, MA: Kluwer Academic Publishers, 1998)
"Power Market Price Forecasting: Pitfalls and Unresolved Issues" (with R.L. Earle and F.C.
Graves), forthcoming in The Energy Journal.
Ten EPRI reports and approximately 20 articles in EPRI Reports and Conference Proceedings.
"Insurance Recovery for Manufactured Gas Plant Liabilities" (with G.S. Koch and K.T. Wise),
Public Utilities Fortnightly, April 1997.
"Real -Time Pricing - Restructuring's Big Bang?" (with J.B. Wharton and P. Fox -Penner),
Public Utilities Fortnightly, March 1997.
"Load Impact of Interruptible and Curtailable Rate Programs" (with D.W. Caves, J.A Herriges, and
R.J. Windle), IEEE Transactions on Power Systems, Vol. 3, No. 4, November 1988.
"Estimating Hourly Electric Load with Generalized Least Squares Procedures" (With N. Toyama
and C.K. Woo.), The Energy Journal, April 1986.
"Transfer Function Estimation Using TARIMA," SAS User's Group International, 1982
Proceedings. Cary, North Carolina: SAS Institute. Inc., 1982.
"Invited Editorial Response to Behavioral Community Psychology: Integrations and Commitments,"
by Richard Winett, The Behavior Therapist 4(5), Convention, 1981.
PHILIP Q HANSER
Principal 20
Statistics Through Laboratory Experiences (with D. Christianson and D. Hughes),: Stockton, CA:
University of the Pacific 1976-1977_
"Unsolved Advanced Problem," American Mathematical Monthly, May 1975.
"Multiattribute Utility Theory and Earthquake Mitigation Policy" (with T. Munroe), Western
Economic Association Conference, June 1978.
"Introduction to Multivariate Data Analysis Techniques," Bureau of Applied' Social Research,
Columbia University, New York, NY, 1973.
JUDY WEI YA CHANG Principal
Judy Chang is an economist with a background in electrical engineering and over 12 years of
experience in advisin. g electric power companies. and project developers with regulatoryand
fmancial issues as they relate to renewable energy and demand -side management programs. She
also has significant experience in transmission -related analyses, including estimating electricity
prices'4 in a variety of electricity wholesale markets. In addition, she assists clients on issues of
market design, asset valuation, finance,and regulatory policies.
Ms. Chang has submitted expert testimonies to the U.S. Federal Energy Regulatory Commission
on capacity markets and reactive power issues and has written numerous testimonies and articles
detailing the economic analyses of market designs for capacity and energy markets across the
U.S. She has advised clients on issues relating to the transition from zonal to locational pricing
in several U.S. wholesale' electric markets, which included the use 'of modeling tools to estimate
congestion costs for power sellers and buyers.
Ms. Chang has also spent, several, years in India working with global organizations in evaluating
and financing renewable energy investments. She received her Bachelor of Science in Electrical
Engineering at University of California at Davis and her Master's of Public Policy at Harvard
Kennedy School.
REPRESENTATIVE CONSULTING EXPERIENCE
Renewable Energy Engagements and Demand -Side ff iciency
• For the Connecticut utilities, analyzed the New England renewable energy market
including a detailed evaluation of short-term and long-term supply and demand balance
renewable energy in the region, an examination of the supply potential in the region and
the potential effect' of transmission investment choices on renewable energy development
in the region. Authored the renewable energy section of the utilities' 2009 resource
planning report.
• For a power purchaser in the West, assisting the client in designing a Request for
Proposals (RFP)' from renewable energy developers. The team is currently preparing to
analyze the bid offers resulting from the RFP. The analysis will entail an estimation of
energy, capacity and REC prices in the region.
• For transmission company, evaluating the likely economic benefits of a transmission
project proposal, including the amount and quality of renewable energy resources that the
proposed transmission can help support. Using Brattle's in-house RECAP model, we
estimated the likely carbon emissions savings from implementing a regional extra -high
voltage transmission overlay and enabling the energy delivery from high -qualify wind
resources located in remote regions.
JUDY WEI YA CHANG
Principal 22
• , For a utility in the West, assessing and estimating the cost of integrating' intermittent
resources into the utility's supply portfolio. Designed'the first user -interactive evaluation
tool to estimate the investment and operational cost associated with increasing regulation,
load -following; day -ahead scheduling, and ramping services .that will be needed with
increasing intermittent resources that have generation output that can be unpredictable
and variable in nature.
• For a utility in the Midwest, authored a white paper that analyzes the economic cost and
benefits of wind investments. The paper focuses on the ownership structure of the
projects and their potential impact on local economies.
• For an international organization, managed and evaluated renewable energy investments
in lhdia; including the likely impact of transmission congestion and curtailment on the
value of the investment. Responsible for debt and equity investments 'in 4 Indian wind
farms and created a pipeline of >10 renewable energy investment opportunities.
• For The Government of India, advised on how to strategically position a government -run
lending institution in renewable energy.
• For several utilities in the U.S., led consulting and client internal teams in simulating the
impact Demand -Side Management programs on company's financial performance.
Advised client on DSM program parameters, avoided cost estimation, cost and benefit
analyses, and regulatory es on shareholder incentive
y , gu ry strategies incentives.for utilities to expand DSM
programs
Electric System Modeling Engagements
• For a utility fulfilling a state renewable resource requirement, M.S. Chang led a team to
analyze the potential economic and system impact of entering into purchasing power
contracts with several renewable resource developers. This engagement included
performing a system impact analysis of the western part of the U.S. Such an analysis
included performing a load flow analysis, estimating the locational marginal prices for
the western system and evaluating the potential changes in transmission congestion
resulting from purchasing power from the proposed renewable resources.
• For a New England utility, performed detailed analyses of the potential impact of the
change from zonal pricing to locational pricing and the utility's exposure to congestion
charges as a result of the implementation of IMP. The analysis was performed using a
Brattle in-house oligapolist model that simulated the bidding behaviors of power sellers
JUDY WEI YA CHANG
Principal 23
in a market before and after the implementation of LMP. The results included a
comparison of the financial impact of the transition to LMP-based market: Hourly prices
were forecasted with the emphasis on utility's relative congestion cost exposure under
a zonal pricing versus a LMP regime. The result of the analysis was used todesign the
utility's congestion hedging strategies.
• For a market participant in the Midwest ISO and Pennsylvania -New Jersey -Maryland
(" PJM")markets, evaluated various long-term transmission cost allocation designs while
eliminating pancaked transmission costs between `the two regional transmission
organizations ("RTOs") =d` analyzed the potential customer impact of each design.
• For the government of Colombia, analyzed the effects of inadequate supply of reactive
power, compiled an international comparison of how reactive power is managed on eight
electric systems, proposed a regulatory framework for reactive' power management and
drafted market rules to be implemented by the system administrators in Colombia to
improve the supply and usage of reactive power and thereby improve the system
reliability of the electricity network. Included in this engagement;' the project team used
a load -flow analysis to determine the optimal reactive power requirement for generators,
distribution companies and transmission owners.
Regulatory and Market Design Engagements
• For the utility and industrial customers in the Maine, co-authored a report that discussed
alternatives of transmission organization participation for the State of Maine and market
design issues associated with the alternatives. This report also explained various
methodologies of allocating New England's' ransmission costs and analyzed the cost
implications of alternative allocations of investments.
• Submitted expert testimony before Federal Energy Regulatory Commission (FERC) on
behalf of an electricity supplier regarding the measures of generation market power in
New England.
• Several regions in the U.S. have begun to institute a mandatory locational installed
capacity (ICAP) requirement for energy companies that serve retail customers. However,
these locational ICAP requirements can significantly increase the market power of local
generators located' in transmission -constrained areas. For an electric utility in New
England, analyzed i the- implications of instituting a locational Installed Capacity (ICAP)
requirement on those who serve retail customers in' the transmission -constrained zones.
JUDY WEI YA CHANG
Principal 24
e The FERC has asked some RTOs to revise resource adequacy requirements in some
regions., In. early 2004, ISO -New . England submitted a proposal ; for instituting a
locational installed capacity requirement (ICAP) .and for administering a locatonal ICAP
market. For Northeast Utilities, Ms. Chang assessedthe impact of ISO-NE's proposal on
load -serving entities and filed written testimony before the FERC critiquing the ISO-
NE's proposal.
• For New York ISO ("NYISO"), performed a study on how the rule changes in generation
capacity requirement might affect reliability of system.Conducted an economic analysis
on how changes the requirements in the capacity market may affect the profitability of
electric generation suppliers and load serving entities.
• For a utility in the New;, _England electricity market, evaluated , the cost of congestion
given the existing and proposed market rules on financial transmission rights, congestion
cost allocation, and the market, shares and the operational characteristics of the
generators. With the results of the analysis, assisted top executives in making strategic
investment decisions:
• For an electric utility, assess the pricing and market dynamics in the New England
electricity market and diagnosed the potential for firms to offer generation resources at
strategically designed prices and thereby exercise occasional market power. Assessed the
impact of this strategic behavior.
• For an Australian natural, gas distribution company, conducted a report of stranded cost
experiences and lessons from North -America, focusing on the regulatory and economic
progress of the natural gas and electricity industries. Studied historical events, regulatory
decisions, and actions of the FERC and states, as well as the economic drivers of those
decisions. Compared and contrasted multiple methods of calculating stranded costs and
the financial implications of each.
Asset and Contract Valuation Related Engagements
• As some electricity wholesale markets become over -saturated with merchant generation
facilities, some plant owners have experienced significant financial difficulties and others
have been unable to complete previously, planned generation projects. For a power plant
equipment supplier, Ms. Chang ; analyzed the eastern regional electricity market in the
U.S. and provided litigation support for counsel on estimating the potential value of an
JUDY WEI YA CHANG
Principal 25
unfinished power plant. In addition, provided damage estimations that developer may
have incurred resulting from an alleged contract violation.
• Fora company proposing a new merchant transmission project, Ms. Chang was part of a
team that developed the valuation model to assist project developer determine the timing
and the size of the project. Under the merchant business model, the developer must
assume full financial risks for the project. The valuation model used here includes a
price forecast tool and a volatility valuation model. Ms. Chang also helped design an
open season process and a bidding package for bidders to demonstrate their interested in
obtaining transmission rights on the new line.
• Post -deregulation, many former vertically integrated utilities sold off their generation
assets and are now in the position of purchasing power on behalf of their customers. For
a utility facing significant financial risks through its power, purchase activities, evaluated
the reasonableness of its purchase methodologies in light of the regulatory uncertainties
ever -changing restructuring landscape.
• For an Australian gas company faced with open access and emergence of competitive
market, performed cost of capital and asset valuation for the purpose of access rate filing.
• For a' large utility in northeastern U.S. seeking to value its generationassets, conducted a
detailed financial and operational performance analysis. ` Created a comprehensive set of
pro forma financial statement tool to model different organizational structures and to
evaluate the impact of operational efficiency. Valued the utility's power generation
plants using simulated free cash flow over the life of each plant. Performed scenario
analysis to evaluate keep versus sell alternatives for all or specific plants and assessed
options of life extensions and early retirements of particular plants. Generated potential
business strategy options for the client to consider and created a tool that the client could
use to test out additional strategies.
• For a regulated utility countering an application from a potential competing utility for a
certificate of convenience and necessity to construct in its service territory, conducted a
cost and benefit analysis of the alternate electricity provider and its electricity prices on
the region's industrial and economic development. Examined the -potential for regional
commercial and industrial growth, particularly in the capital -intensive sectors, which may
cause wage rate increases, and evaluated macroeconomic factors such as trade
economics.
JUDY WEI YA CHANG
Principal 26
REPRESENTATIVE TESTIMONY AND.REGULATORY FILINGS
Before Federal Energy Regulatory Commission (FERC) in Principles for Efficient and Reliable
Reactive Power Supply and Consumption, Docket No. AD05-1-000, filed on April 4, 2005.
Before FERC; in Application for Market -based Rate Authority, Prepared Affidavit on behalf of
Northeast Utilities in Docket No.. ER96-496 et. al., filed on September 27, 2004.
Before the FERC, affidavit on behalf of Northeast Utilities in Docket No. ER03-563-030, Devon
Power LLC, etc. al. Prepared Joint Affidavit with Philip Hauser, filed on March 24, 2004.
REPRESENTATIVE PUBLICATIONS AND PRESENTED PAPERS (BY DATES)
"Update on Renewable Energy Market Trends," presented at Seminar on Financing Clean
Energy Projects under the Reinvestment Act of 2009, (organized by Environment Business
Council of New England), June 11, 2009.
"Assessment of a Maine ISA Structure as a. Possible Alternative to ISO -NE Participation," (with
Ken Belcher, Johannes P. Pfeifenberger, and Delphine Hou), May 2009.
"Transmission Super Highways: Assessing the Potential Benefits of Extra -High -Voltage
Transmission Overlays in the Midwest," (with Peter S. Fox -Penner, Delphine Hou, and Ryan
Hledik), March 2009.
"2009 Integrated Resource Plan for Connecticut," (with Onur Aydin, Marc Chupka, Mariko
Geronimo, Dean M. Murphy, Samuel A. Newell, and Joseph B. Wharton), January 1, 2009.
"International Renewable Energy Financing," presented at Euromoney's Renewable Energy
Finance Forum, New Delhi, India, November 30, 2006. .
"Wind Power Grid Integration: How to Evaluate Potential Grid Impact of Proposed Wind
Projects", presented at Electric Power 2005 Conference, April 6, 2005.
"LMPs/FTRs Alone Will Not Solve Transmission Problems Blackout Showed", (with Philip
Hauser), Natural Gas and Electricity, Volume 20, Number 4, November 2003.
JUDY WEI YA CHANG
Principal 27
"Transmission Management in the Deregulated Electric Industry — A Case Study on Reactive
Power" (with Frank C. Graves and Dean M. Murphy), The Electricity Journal, Volume:16, Issue
8 October, 2003.
"Transmission Management in the Deregulated Electric Industry — A Case Study on Reactive
Power," Ancillary Services Conference, Denver, Colorado, October 9, 2003.
"Regulatory Design for Reactive Power and Voltage Support Services," presented to Comisi6n
de Regulaci6n de Energia y Gas, Bogota, Colombia, December 2001.
"International Review of Reactive Power Management", presented to Comisi6n de Regulaci6n
de Energia y Gas, Bogota, Colombia, May 4, 2001.
"Assessment of Energy Demand Growth and the Need for Peaking Plants," Merchant Plant
Finance Conference, Atlanta, Georgia, September 14, 2000.
"Competition in Gas Pipeline Markets: International Precedent for Regulatory Coverage
Decisions," Report to the National Competition Council of Australia (with Paul Carpenter), June
2000.
"Shortening the NYISO's Installed Capacity Procurement Period: Assessment of Reliability
Impacts," NYISO, May 2000.
"Electricity Price Forecasting with Imperfect Market Conditions," Electricity Market Pricing
Conference, Denver, Colorado, August 9, 1999.
The Brattle Group Testimony Exhibit B:' Historical and
Offer of Settlement ETC Rates and Costs
Historical and Offer of Settlement ETC Rates and Costs................................................................1
The Brattle Group. Testimony
Exhibit B
Exhibit B: Historical and Offer of Settlement ETC Rates and Costs
ETC - Rate ($/kW -month)
ETC - Capacity (NW)
ETC - Cost ($)
SCE
SCE`
SCEa
SCE Mead-
Victorville-
SCE Mead-
Victorville-
SCE Mead- Victorville-
Year
Month
Laguna
Lugo
LADWP `
' Laguna
Lugo
LADWP
Laguna...
Lugo
LADWP
[A]
[B]
[C]
[D]
[E]
[F]
[G]
[Fll
Ill
[J]
[K]
[1]
2008
Jan
1.04756
0.5100
0.2842
26
it
81
27,237
5,610
23,020
[2]
Feb
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
23,020
[3]
Mar
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
23,020
[4]
Apr
1.04756 _
0.5100
0.2842
26
11
81
27,237
5,610
23,020
[5]
May
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
23,020
[6]
Jun
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
23,020
[7]
Jul
1.04756
0.5100
0.2842
26
1l
81
27,237
5,610
23,020
[8]
Aug
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
232020
191
Sep
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
23,020
[10)
Oct
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
23,020
(11]
Nov
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
23,020
[12]
Dec
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
23,020
[13]
2009
Jan
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
23,020
[14]
Feb
1.04756
0.5100
0.2842
26
11
81
27,237
5,610
23,020
[15]
Mar
1.0400
0.5100
0.2842
26
11
81
27,040
5,610
23,020
(16]
Apr
1.0400
0.5100
0.2771
26
11
81
27,040
5,610
22,445
(171
May
1.0400
0.5100
0.2842
26
11
81
27,040
5,610
23,020
[18)
Jun
1.0400
0.5100
0.2842
26
it
81
27,040
5,610
23,020
[19]
Jul
1.0400
0.5100
0.2842
26
11
81
27,040
5,610
23,020
[20)
Aug
1.2500
1.0000
0.2842
26
11
81
32,500
11,000
23,020
[2.1]
Sep
1.2500
1.0000
0.2842
26
11
81
32,500
11,000
23,020
[22)
Oct
1.2500
1.0000
0.2842
26
11
81
32,500
11,000
23,020
[23]
Nov
1.2500
1.0000
0.2842
26
11
81
32,500
11,000
23,020
[24].
Dec
1.2500
1.0000
0.2842
26
11
81
32,500
11,000
23,020
[25]
2010
Monthly
1.5900
1.7000
0.2842
26
11
81
41,340
18,700
23,020
[26]
2011
Monthly
1.7500
1.7500
0.2842
26
11
81
45,500
19,250
23,020
[271
2012
Monthly
1.9100
1.9100
0.2842
26
11
81
49,660
21,010
23,020
Annualized Expenses
[28)
2008
Annual
326,839
67,320
276,240
[29)
2009
Annual
352,173
94,270
275,665
[30)
2010
Annual
496,080
224,400
276,240
[31]
2011
Annual
546,000
231,000
276,240
[321
2012
Annual
595,920
252,120
276,240
Annualized Expenses by Utility
SCE
LADWP
Total
[33]
2008
Annual
394,159
276,240
670,399
[34]
2009
Annual
446,443
275,665
722,108
[35]
2010
Annual
720,480
276,240
996,720
[36]
2011
Annual
777,000
276,240
1,053,240
[37]
2012
Annual
848,040
276,240
1,124,280
Sources and Notes
[Iq-[14D]: From SCE invoices to Vernon from January 2008 through February 2009, as provided by City of Vernon.
[1F]-[14G]`. From SCE invoices to Vernon from January 2008 through February 2009, as provided by City of Vemon.
[II]-[14J]: Column [I] = Column [C) x Column [F] x 1,000. Column [J] = Column [D] x Column [G] x 1,000.
[lE]-[14E]: Column [E] = Column [K] / Column [H] / 1,000. The basic transmission capacity rate is $0.27/kW-mo as provided on the invoice.
The calculated rate of $0.28/kW-mo includes $575 in scheduling and dispatch fees for the Marketplace to Victorville-Lugo Substations
and $575 in scheduling and disptach fees for the Victorville-Lugo to the Marketplace Substations.
[1H]-[14H]: From LADWP invoices to Vernon from January 2008 through May 2009, as provided by City of Vemon.
[1K]-[14K]: From LADWP invoices to Vernon from January 2008 through May 2009, as provided by City of Vemon.
[15C]-[27D]: From Offer of Settlement as filed by Southern California Edison Company, Docket No. ER08-1343-000 (consolidated).
Victorville-Lugo (FERC Rate Schedule No. 360) and Mead (FERC Rate Schedule No. 207).
[15F]-[27H]: Contract capacities are assumed to remain as is.
[1511-[27J]: Column [I] = Column [C] x Column [F] x 1,000. Column [J) = Column [D] x Column [G] x 1,000.
[16K]: Invoice shows no charge for scheduling and dispatch fees for Victorville-Lugo to Marketplace Substation.
[28]-[29]: Sum of all months for 2008 and 2009, respectively.
[30]-[32]: Monthly expenses in Rows [25]-[27] x 12 months/year, per year.
[33]-[37]: SCE is the sum of Columns [I] and [J] from Rows [281-[32]. LADWP is Column [K) from Rows [28]-[32].
T�° BrattleGroup
Transmission Revenue Requirements
&0 20/�1 '
-'_ �rauu�uuuu�o��v�onm ,_,—.—...^_-_—.----.~------------_.l
'
`
'
`
'
~ �
,
`
'
�
The Brattle Group Testimony
Exhibit C
Exhibit C: 2009 Transmission Revenue Requirements ($)
ETC Expenses ($)
SCE Mead- SCE Victorville- A&G Regulatory
Year Laguna Lugo LADWP Expenses Expenses Total
(A) [B] [C] [D] [E] [F] , [G],
[1] 20.09 352,173 94,270 275,665 5,040 217,200 944,348
Sources and Notes
[B]-[)]: See Exhibit B: Historical and Offer of Settlement ETC Rates and Costs.
[E]: See Workpaper: Projected Administrative and General Expenses. Provided by City of Vernon.
[F]: See Workpaper: Projected Regulatory Expenses ($). Provided by City of Vernon.
[G]: Sum of [B] through [F].
f
The Brattle Group Testimony Exhibit D: ETC
Adjustment Clause Calculations
ExhibitDl: 2010 ETC Adjustment Clause......................................................................................1
Exhibit D2: 2011 ETC Adjustment Clause ......... '............................`.......................................2
Exhibit D3: 2012 ETC Adjustment Clause..................................::..................................................3
Exhibit D4: 2013 Illustrative ETC Adjustment Clause ...............................................................4
Exhibit D5: 2014 Illustrative ETC Adjustment Clause. ............. .................................................5
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Exhibit E: Actual 2010-2012 and Illustrative 2013-
2014 Transmission Revenue Requirements with ETC
Adjustment Clause
Actual 2010-2012 and Illustrative 2013-2014 Transmission Revenue Requirements with ETC
Adjustment Clause ($) .......... ........1
The Brattle Group, Testimony
Exhibit E
Exhibit E: Actual 2010-2012 and Illustrative 2013-2014 Transmission Revenue Requirements with ETC Adjustment Clause ($)
ETC Adjustment Clause Components
A&G
Regulatory
SCE ETCs LADWP ETC
Expenses
Expenses Total
Year Component I: Projected
Component II: Cumulative Component III: Interest
SCE ETC Expense
(Over)/Under Collection on Component II
[A] [B]
[q [D] [E]
[F]
[G] [H]
[I]
2010 720,480
0. 0 276,240
5,040
217,200 1,218,960
[2]
2011 777,000
0 0 276,240
5,040
217,200 1,275,480
[3]
2012 848,040
0 0 276,240
5,040
217,200 1,346,520
[4]
?a .,�s4�„ % `.� r' 0 1�6i40e 511
...
27�Q0ey. $D
�_ ...
Sources and Notes
[A]: The calendar year in which rates are projected for the ETC Adjustment Clause and includes the true -up and compounded interest on the balance from the prior period.
[B]-[D]: See Exhibits DI through D5 for ETC Adjustment Components.
[E]: See Exhibit B: Historical and Offer of Settlement ETC Rates and Costs.
[F]: See Workpaper: Projected Administrative and General Expenses.
[G]: See Workpaper: Projected Regulatory Expenses ($).
[H]: Sum of [B] through [G].
[4]-[5]: 2013 and 2014 numbers are illustrative only.
F
The Brattle Group Testimony Exhibit F: 2010-2012
Annual Transmission Revenue Requirements
2010-2012 Annual Transmission Revenue Requirements ($).........................................................1
The'Brattle Group Testimony
Exhibit F
Exhibit F: 2010-2012 Annual Transmission Revenue Requirements ($)
ETC Expenses ($)
SCE Mead- SCE Victorville- A&G
Regulatory
Year Laguna Lugo LADWP Expenses
Expenses
Total
[A] [B] [C] [D] [E]
[F]
[G]
[1] 2010 496,080 224,400 276,240 5,040
217,200
1,218,960
[2] 2011 546,000 231,000 276,240 5,040
217,200
1,275,480
[3] 2012 595,920 252,120 276,240 5,040
217,200
1,346,520
Sources and Notes
[lB]-[3D]: See Exhibit B: Historical and Offer of Settlement ETC Rates and Costs.
[E]: See Workpaper: Projected Administrative and General Expenses.
[F]: See Workpaper: Projected Regulatory Expenses ($).
[G]: Sum of [B] through [F].
1
The Brattle Group Testimony Workpaper:
Administrative and General Expenses
Projected Administrative and General Expenses.............................................................................1
The Brattle Group Testimony
Workpaper: Administrative and General Expenses
Workpaper: Projected Administrative and General Expenses
Estimated Hours Per Month
Total Hours
Hourly Rate
Total ($)
Contract
ISO Regulatory
Per
Per
Salary+
Budgeted
Employee
Administration
Activities Support
Month
Year
Benefits Overhead
Combined
A&G
[A]
IB]
[C] [D]
[E]
IF]
IG] [H]
[I]
[I]
[1] Resource Planning Manager
1.0
1.0 1.0
3.0
36
$85.44 25%
$106.80
3,845
[2] Scheduler
0.5
0.5 0
1.0
12
$60.67 25%
$75.84
910
[3] Associate Scheduler - Billing
0.5
0 0
0.5
6
$38.00 25%
$47.50
285
[4] Total
5,040
Sources and Notes
[I] - [3]: Provided by City of Vernon.
[E]: Sum of [B] through [D].
IF]: [E] x 12 months/year.
[G]: Provided by City of Vernon.
[H]: Provided by City of Vernon.
[I]: [G] x (I+ [H]).
[J]: IF] x [I].
[0]: Sum of [1J] through [M).
0
The Brattle Group Testimony Workpaper: Regulatory
Expenses
Projected Regulatory Expenses($)..................................................................................................1
1
The Braule Group Testimony
Workpaper. Regulatory Expenses
Workpaper: Projected Regulatory Expenses ($)
[A] [Bl
[1] Legal 172,200
[2] Consultant 45,000
[3] Total 217,200
Sources and Notes
[1 ] - [2]: Provided by City of Vernon.
[3]: Sum of[ I I and [2]. -
1
Prepared Testimony of
The Brattle Group
July 6, 2009
Work Papers Attachment Replacement Sheet
(The Attachment to the Work Papers will consist of invoices received from
Southern California Edison for each of two Existing Transmission Contracts
("ETCs") for the period January, 2008 through February, 2009, along with
invoices received from the Los Angeles Department of Water & Power for on ETC
for the period
January, 2008 through May, 2009.
Invoices are omitted from this package for the sake of brevity.)
LA-331058 v1
Exhibit 3
Appendix I
Effective August 1, 2009
Transmission Owner Tariff (cont.)
APPENDIX I
Transmission Revenue Requirement and TRBAA
The Vernon Base Transmission Revenue Requirement is $944,348 and is comprised of the following
components:
Base TRR costs not subject to ETC Adjustment Clause: $497,905
ETC Adjustment Clause:
Forecast SCE ETC Costs: $446,443
Balance of Difference between prior year
Forecast and Actual SCE ETC Costs: $0
Interest on Difference between prior year
Forecast and Actual SCE ETC Costs: $0
The ETC Adjustment Clause is: The projected SCE ETC Cost for the next calendar year, plus the
true -up (positive or negative) of the prior October through September SCE ETC Cost with interest
calculated pursuant to 18 C.F.R. § 35.19a. The ETC Adjustment Clause will be recalculated annually
and filed with the. Commission with a proposed effective date of January 1 of each year.
The TRBAA is a positive $286,851 for calendar year 2009.
Vernon's Gross Load, consistent with its TRR, used by the ISO to develop the Transmission Access Charge is
1,257,502 MWh.
All of Vernon's transmission facilities and Entitlements placed under the ISO's Operational Control are High
Voltage Facilities as defined by the ISO Tariff.
The TRBAA will be recalculated annually consistent with the ISO Tariff approved by the Vernon City
Council, and provided to the ISO.
Authorized by City of Vernon
Ordinance No. 940
Issued on: July 13, 2009 Resolution No. Effective: August 1, 2009
Tenth Revised Sheet No. 22
Superseding Ninth Revised Sheet No. 22
Exhibit 4
Appendix I
Effective January 1, 2010
APPENDIX I
Transmission Revenue Requirement and TRBAA
The Vernon Base Transmission Revenue Requirement is $1,218,960 and is comprised of the following
components:
Base TRR costs not subject to ETC Adjustment Clause: $498,480
ETC Adjustment Clause:
Forecast SCE ETC Costs: $720,480
Balance of Difference between prior year
Forecast and Actual SCE ETC Costs: $0
Interest on Difference between prior year
Forecast and Actual SCE ETC Costs: $0
The ETC Adjustment Clause is: The projected SCE ETC Cost for the next calendar year, plus the
true -up (positive or negative) of the prior October through September SCE ETC Cost with interest
calculated pursuant to 18 C.F.R. § 35.19a. The ETC Adjustment Clause will be recalculated annually
and filed with the Commission with a proposed effective date of January 1 of each year.
The TRBAA is $[ ] for calendar year 2010.
Vernon's Gross Load, consistent with its TRR, used by the ISO to develop the Transmission Access Charge is
1,257,502 MWh.
All of Vernon's transmission facilities and Entitlements placed under the ISO's Operational Control are High
Voltage Facilities as defined by the ISO Tariff.
The TRBAA will be recalculated annually consistent with the ISO Tariff approved by the Vernon City
Council, and provided to the ISO.
Authorized by City of Vernon
Ordinance No. 940
Issued on: July 13, 2009
Resolution No. Effective: January 1, 2010
Eleventh Revised Sheet No. 22
Superseding Tenth Revised Sheet No. 22
Exhibit 5
Appendix I
Effective January 1, 2011
APPENDIX I
Transmission Revenue Requirement and TRBAA
The Vernon Base Transmission Revenue Requirement is $1,275,480 and is comprised of the following
components:
Base TRR costs not subject to ETC Adjustment Clause: $498,480
ETC Adjustment Clause:
Forecast SCE ETC Costs: $777,000
Balance of Difference between prior year
Forecast and Actual SCE ETC Costs: $0
Interest on Difference between prior year
Forecast and Actual SCE ETC Costs: $0
The ETC Adjustment Clause is: The projected SCE ETC Cost for the next calendar year, plus the
true -up (positive or negative) of the prior October through September SCE ETC Cost with interest
calculated pursuant to 18 C.F.R. § 35.19a. The ETC Adjustment Clause will be recalculated annually
and filed with the Commission with a proposed effective date of January 1 of each year.
The TRBAA is $[ ] for calendar year 2011.
Vernon's Gross Load, consistent with its MR, used by the ISO to develop the Transmission Access Charge is
1,257,502 MWh.
All of Vernon's transmission facilities and Entitlements placed under the ISO's Operational Control are High
Voltage Facilities as defined by the ISO Tariff.
The TRBAA will be recalculated annually consistent with the ISO Tariff approved by the Vernon City
Council, and provided to the ISO.
Authorized by City of Vernon
Ordinance No. 940
Issued on: July 13, 2009 Resolution No. Effective: January 1, 2011
Twelfth Revised Sheet No. 22
Superseding Eleventh Revised Sheet No. 22
Exhibit 6
Appendix I
Effective January 1, 2012
APPENDIX I
Transmission Revenue Requirement and TRBAA
The Vernon Base Transmission Revenue Requirement is $1,346,520 and is comprised of the following
components:
Base TRR costs not subject to ETC Adjustment Clause: $498,480
ETC Adjustment Clause:
Forecast SCE ETC Costs: $848,040
Balance of Difference between prior year
Forecast and Actual SCE ETC Costs: $0
Interest on Difference between prior year
Forecast and Actual SCE ETC Costs: $0
The ETC Adjustment Clause is: The projected SCE ETC Cost for the next calendar year, plus the
true -up (positive or negative) of the prior October through September SCE ETC Cost with interest
calculated pursuant to 18 C.F.R. § 35.19a. The ETC Adjustment Clause will be recalculated annually
and filed with the Commission with a proposed effective date of January 1 of each year.
The TRBAA is $[ ] for calendar year 2012.
Vernon's Gross Load, consistent with its TRR, used by the ISO to develop the'Transmission Access Charge is
1,257,502 MWh.
All of Vernon's transmission facilities. and Entitlements placed under the ISO's Operational Control are High
Voltage Facilities as defined by the ISO Tariff.
The TRBAA will be recalculated annually consistent with the ISO Tariff approved by the Vernon City
Council, and provided to the ISO.
Authorized by City of Vernon
Ordinance No. 940
Issued on: July 13, 2009 Resolution No. Effective: January 1, 2012
Thirteenth Revised Sheet No. 22
Superseding Twelfth Revised Sheet No. 22
Exhibit 7
Amended TO Tariff
(Clean)
Effective August 1, 2009
Authorized by City of Vernon
Ordinance No. 940
Issued on: April 24, 2001
CITY OF VERNON, CALIFORNIA
TRANSNHSSION OWNER TARIFF
Resolution No. 7751
Effective: January 1, 2001
.Sheet No. 1
Transmission Owner Tariff (cont.)
TABLE OF CONTENTS
Paae No.
1. Preamble...................................................................................................................................................4
2. Effective Date..........................................................................................................................................4
3. TO Definitions ...... :................................................................................................................................. 4
4. Eligibility................................................................................................................................................ 6
5. Access Charges ......................................................:................................,........................................... 6
5.1 Transmission Revenue Requirement .................. ........... I .......................................................... 7
5.2 Transmission Revenue Balancing Account Adjustment("TRBAA')....................................... 7
5.3 Existing Transmission Contract Adjustment
6. Ancillary Services —Applicability and Charges..................................................................................... 7
7. Billing and Payment................................................................................................................................7
8. Obligation to Interconnect or Construct Transmission Expansions and Facility Upgrades .................... 9
8.1 Participating TO Obligation to Interconnect............................................................................. 9
8.2 Participating TO Obligation to Construct Transmission Expansions or Facility Upgrades ....10
8.3 Request for FERC Deference Regarding Need Determination...............................................11
9. Expansion Process.................................................................................................................................11
9.1 Determination of Facilities......................................................................................................11
9.2 Obligation to Build..................................................................................................................12
Authorized by City of Vernon
Ordinance No. 940
Issued on: July 13, 2009 Resolution No. Effective: August 1, 2009
Third Revised Sheet No. 2
Superseding Second Revised Sheet No. 2
Transmission Owner Tariff (cont.)
9.3
Provisions Relating To Transmission Construction On the Systems Of Other TOs ...............14
10. Interconnection Process. ......... ......... .!...... :.......
15
.:.,..:.. ......... ......... .....:...
10.1
Applicability ............ .................................................................................................15
10.2
Applications
10.3
.... ........ ........ ......... ......... ......... ......... ........ ...a..... .....................15
Completed Application
........ .................................................................................................
15
10.4
Notice of Need for System Impact Study ...............................
10.5
..............................................16
System Impact Study Cost Reimbursement and Agreement .. ......... ......... .....................16
10.6
System Impact Study Procedures ....... ......... ........ ........ .....................
10.7
. .....................17
Relevant Sections Apply Upon Receipt of Facilities Study Agreement
10.8
..................................
Partial Interim Service ....................................... .....................................................................:18
10.9
Expedited Procedures for New Facilities
............................................................... ..............
18
11. Uncontrollable Forces and Indemnification ..... .................
........ ........................................18
11.1 Procedures to Follow if Uncontrollable Force Occurs ........ .........................................18
11.2 Indemnification .... .: 19
12. Regulatory Filings...........................................................................................................................19
13. Miscellaneous........................................ .........
......... ......... .......... .........................................19
13.1
Notices ........ ......... .........
13.2
.......... .................... .....:.,............ ........................19
Waiver........................`
13.3
......... ......... ........................................................ .........................19
Confidentiality
13.4
...........................................................
Titles ....
13.5
......... ........ ....... .... ......... ..................................................................20
Severability......................................... ::...............................................
13.6
.................................20
Preservation of Obligations
13.7
.....................................................................................................21
Governing Law
13.8
........................................................................................................................21
Appendices Incorporated
13.9
................................................................................................21
Consistency with ISO Tariff ............................ ....................
13.10
..........................................21
Disputes
..................... ......... ......... ......... ...............................................................21
APPENDIXI ................... ......,............................................................................................................................. 22
APPENDIXII..: ......................... ......... ......... ......... ......... ......... ........ ..........................................23
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
Second Revised Sheet No. 3
Superseding First Revised Sheet No. 3
Transmission Owner Tariff (cont.)
1. Preamble. Vernon's TRR for its high voltage transmission facilities and Entitlements placed under
the ISO's operational control, and certain terms and conditions relating to transmission expansion of
and interconnection with Vernon's high voltage transmission facilities and Entitlements placed under
the ISO's operational control, are set forth in this TO Tariff.
2. Effective Date. This TO Tariff is effective on the date on which Vernon became a Participating TO,
January 1, 2001, and shall continue to be effective so long as Vernon is a party to the
3. TO Definitions. Certain capitalized terms used in this TO Tariff that are set out immediately;below
shall have the meanings set out immediately below. Capitalized terms used in this tariff and not
defined below shall have the meanings set out in the ISO Tariff as it maybe amended from time to
time.
3.1 Completed Application. An application that satisfies all of the information and other
requirements of this TO Tariff, including any required deposit.
3.2 Direct Assignment Facilities. Facilities or portions of facilities that are constructed by the
Participating TO for the sole use or benefit of a particular party requesting Interconnection
i.
under this TO Tariff. Direct Assignment Facilities shall be specified in the Interconnection
Agreement that governs service to such party.
3.3 Existing Transmission Contract Adjustment Clause. The mechanism that adjusts
Vernon's Base TRR for changes in the costs associated with certain Existing Transmission
Contracts ("ETCs"), consisting of Vernon's projected annual cost of its ETCs with Southern
California Edison ("SCE") for the next calendar year, plus the true -up (positive or negative)
of the prior year's costs of such ETCs (as invoiced to Vernon by SCE during the period of
October through September) as compared with the projected cost of such ETCs for the same
period, including interest on the true -up amount at the rate computed by the Federal Energy
Regulatory Commission pursuant to 18 C.F.R. § 35.19a.
3.4 Facilities Study Agreement. An agreement between a Participating TO and either a Market
Participant, Project Sponsor, or identified principal beneficiaries pursuant to which the
Market Participants, Project Sponsor, and identified principal beneficiaries agree to reimburse
the Participating TO for the cost of a Facility Study.
3.5 _ Facility or Facilities Study. An engineering study conducted by a Participating TO to
determine required modifications to the Participating TO's transmissionsystem, including the
cost and scheduled completion date for such modifications that will be required to provide
needed services.
3.6 Local Regulatory Authority. In the case of Vernon, the Vernon City Council.
Authorized by City of Vernon
Ordinance No. 940
Issued on: July 13, 2009 Resolution No. Effective: August 1, 2009
Third Revised Sheet No. 4
Superseding Second Revised Sheet No. 4
Transmission Owner Tariff (cont.)
3.7 Net FTR Revenue. The sum of 1) The revenue received by the Participating TO from the
sale, auction, or other transfer of the FTRs provided to it pursuant to Section 36.4.3 FTR, or
any substantively identical successor provision, of the ISO Tariff; and:2) For each hour: a) the
Usage Charge revenue received by the Participating TO associated with its Section
.36.4.3FTRs; minus b) Usage Charges that are: i) incurred by the Scheduling Coordinator for
the Participating TO under
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008
Resolution No. 9562
Effective: April 23, 2008
Fourth Revised Sheet No. 5
Superseding Third Revised Sheet No. 5
Transmission Owner Tariff (cont.)
ISO Tariff. Section 27.1.2.1.4, ii) associated with the Participating>TO's Section36.4.3 FTRs,
and iii) incurred by the Participating` TO for its energy transactions but not incurred as a result
of the use of the transmission by a third -party and minus c) the charges paid by the
Participating TO pursuant to Section 27.1.2.1.4 to the extent such charges are incurred by the
Scheduling Coordinator of the Participating TO on Congested Inter -zonal Interfaces that are
associated with the Section 36.4.3 FTRs provided to the Participating TO. The component of
Net FTR Revenue represented by item 2) immediately above shall not be less than zero for
any hour.
3.8 Participating TO. A party to the TCA whose application under Section 2.2 of the TCA has
been accepted and who has placed its transmission assets and Entitlements under the ISO's
Operational Control in accordance with the TCA. A Participating TO may be an Original
Participating TO or a New Participating TO. For purposes of this TO Tariff, the Participating
TO is Vernon.
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
Third Revised Sheet No. 5a
Superseding Second Revised Sheet No. 5a
Transmission Owner Tariff (cont.)
3.9 Project Proponent. A Market Participant or group of Market Participants that: (i),advocates
a transmission addition or upgrade, (ii) is unwilling to pay the full cost of the proposed
transmission addition and upgrade, and thus is not a Project Sponsor; and (iii) initiates
proceedings under the ISO ADR Procedures to determine the need for the proposed
transmission addition or upgrade.
3.10 System Impact Study. An engineering study conducted by a Participating TO to determine
whether a request for Interconnection to the Participating TO's transmission system would
require new transmission additions or upgrades.
3.11 System Impact Study Agreement. An agreement between a Participating TO and an entity
that has requested Interconnection to the Participating TO's transmission system pursuant to
which the entity requesting Interconnection agrees to reimburse the Participating TO for the
cost of a System Impact Study.
3.12 Transmission Revenue Balancing Account Adjustment ("TRBAA"). A mechanism
established by the Participating TO which will ensure that all Transmission Revenue Credits
and other credits specified in Sections 6 and S of Appendix F, Schedule 3 of the ISO Tariff,
flow through to ISO Tariff and TO Tariff transmission customers.
3.13 Transmission Revenue Credit. 'Collectively, 1) the sum of. a) all revenues received by the
Participating TO from the ISO for Wheeling service, plus b) Usage Charge revenues received
by the Participating TO pursuant to Section 27.1.2.1.6(ii) of the ISO Tariff plus c) NET FTR
Revenue received by the Participating TO; minus 2) any charges attributable to the
Participating TO (but not attributable to the FTR Holder) pursuant to ISO Tariff 27.1.2.1.7.
3.14 Transmission Revenue Requirement. The TRR is the total annual authorized revenue
requirements associated with transmission facilities and Entitlements turned over to the
Operational Control of the ISO by the Participating TO. The costs of any transmission facility
turned over to the Operational Control of the ISO shall be fully included in the Participating
TO's TRR. The TRR includes the costs of transmission facilities and Entitlements and
deducts Transmission Revenue Credits and credits for Standby Transmission Revenue and the
transmission revenue expected to be actually received by the Participating TO for Existing
Rights and Converted Rights. The TRR is shown in Appendix I.
4. Eligibility. Transmission service over Vernon's high voltage transmission facilities and Entitlements
placed under the ISO's Operational Control shall be provided only to Eligible Customers as defined
by the ISO Tariff. Any dispute as to whether a customer is eligible for wholesale transmission service
shall be resolved by FERC and any dispute as to whether a Vernon End -Use Customer is eligible for
service under this TO Tariff shall be resolved by the Local Regulatory Authority. At the present time,
there are no Vernon End -Use Customers eligible for service under this tariff.
5. Access Charges. The applicable Access Charges are provided in the ISO Tariff.
Authorized by City of Vernon
Ordinance No. 940
Issued on March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
Fourth Revised Sheet No. 6
Superseding Third Revised Sheet No. 6
Transmission Owner Tariff (cont.)
5.1 Transmission Revenue Requirement. As set forth in the ISO Tariff, the Transmission
Revenue Requirement for each Participating TO shall be used to develop the Access Charges
set forth in the ISO Tariff. Vernon's. Transmission Revenue Requirement is set forth in.
Appendix I.
5.2 Transmission Revenue Balancing Account Adjustment C'TRBAA°'). The Participating
TO, shall maintain -a Transmission Revenue Balancing Account ("TRBA") that will ensure
that all Transmission Revenue Credits and the refunds, specified" in Sections 6 and 8 of
Appendix F, Schedule 3 of the ISO Tariff, flow through to ,transmission customers. The
TRBAA shall be equal to: TRBAA = TRCF + TRCT + I .
TRCT The balance representing the prior period difference between the projected
Transmission Revenue Credits and the actual credits.
TRCF = . The forecast of Transmission Revenue Credits for the following calendar year.
I = The interest balance for the TRBA, which shall be calculated using the interest rate
pursuant to Section 35.19(a) of FERC's regulations under the Federal Power Act
(18 C.F.R. § 35.19(a)). Interest shall be calculated based on the average TRBA
principal balance each month, compounded quarterly.
The Vernon TRBAA, calculated in accordance with the ISO Tariff and approved by the City
Council, is stated in Appendix L
5.3 ETC Adjustment. ETC Adjustment Clause shall be equal to: ETC Adjustment = ETCCF +
ETCCT+ I.
ETCCT = The balance representing the prior period difference between the projected cost of
the SCE ETCs ("SCE ETC Cost") and the actual cost.
ETCCF = The forecast of SCE ETC Cost for the following calendar year.
I = The interest balance for the. ETC, which shall be calculated using the interest rate
pursuant to Section 35.19(a) of FERC's regulations under the Federal Power Act
(18 C.F,R. § 35.19(a)). Interest shall be calculated based on the average ETC true -
up balance each month, compounded quarterly.
6. Ancillary Services —Applicability and Charges. If any Ancillary Services are required, Vernon will
not provide such services, but transmission customer will be required to meet any such requirement in
accordance with the ISO Tariff.
7. Billing and Payment.
7.1 [intentionally left blank]
Authorized by City of Vernon
Ordinance No. 940
Issued on July 13, 2009 Resolution No. Effective: August 1, 2009
Third Revised Sheet No. 7
Superseding Second Revised Sheet No. 7
Transmission Owner Tariff (cont.)
7.2 The ISO, in accordance with the ISO Tariff, shall pay the Participating TO, among other
things, Wheeling; Usage, Access Charge revenues, and FT ;auction proceeds (excluding
Usage Charge revenues payable to FTR Holders) in accordance with the ISO Tariff.
7.3 Users of Vernon's high voltage transmission facilities. and Entitlements placed under the
ISO's Operational Control shall pay to the ISO all applicable charges in accordance with the
ISO Tariff.
Authorized by City of Vernon
Ordinance No. 940
Issued on: July 13, 2009 Resolution No.
Effective: August 1, 2009
Third Revised Sheet No. 8
Superseding Second Revised Sheet No. 8
Transmission Owner Tariff (cont.)
8. Obligation to Interconnect or Construct Transmission Expansions and Facility Upgrades.
8.1 Participating TO Obligation to Interconnect. Sections 8, 9, and 10, and their subparts, are
provided for.consistency.with other PTOs' TO Tariffs and for potential future application
should Vernon acquire transmission facilities. These Sections 8, 9, and 10 are not presently
applicable to any Vernon facility. If the situation changes so that Vernon has legal authority
over transmission facilities so that Vernon is able to implement the provisions of Sections 8,
9, and 10 so that those provisions become effective, to the extent consistent with Sections
9.2.1 and 9.3.3 of this TO Tariff, the Participating TO shall, at the request of a third party
pursuant to Section 210, interconnect its system to the generation of such third party, or
modify an existing Interconnection. Interconnections under this TO Tariff shall be available
to entities eligible to request interconnection consistent with the provisions of Section 210(a)
of the FPA.
8.1.1 Upgrade to Transmission System. Interconnection must be consistent with
Good Utility Practice, in conformance with all Applicable
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
Second Revised Sheet No. 9
Superseding First Revised Sheen No. 9
Transmission Owner Tariff (cont.)
Reliability Criteria; all applicable statutes; and regulations. The Participating
TO will not upgrade its existing or planned transmission system to
accommodate the Interconnection if doing so would impair system reliability, or
would otherwise impair or degrade pre-existing firm transmission service.
Costs Associated with Interconnection. The cost of any Direct Assignment
Facilities constructed pursuant to this section shall be bome by the party
requesting the Interconnection. Any additional.costs associated with
accommodating the Interconnection shall be allocated in accordance with the
cost responsibility methodology set forth in the ISO Tariff for transmission
expansions or upgrades. Any disputes regarding such cost' allocation shall be
resolved in accordance with the ISO ADR Procedures. If a Market Participant
fails to raise through the ISO ADR Procedures a dispute as to whether a
proposed transmission addition or upgrade is needed; or as to the identity, if
any, of the beneficiary, then the Market Participant shall be deemed to have
waived its right to raise such dispute at a later date. The determination under the
ISO ADR Procedures as to whether the transmission addition or upgrade is
needed and the identity, if any, of the beneficiaries, including any determination
by FERC or on appeal of'a FERC determination in accordance with that
process, shall be final.
Execute Interconnection Agreement. Prior to the construction of any
Interconnection facilities pursuant to this TO Tariff, the party requesting an
Interconnection shall execute an appropriate Interconnection Agreement that
will be filed with FERC or the Local Regulatory Authority, in the case of a
Local Publicly Owned Electric Utility, and that will include, without limitation,
cost, responsibilities for engineering, equipment, and construction costs. All
costs shall be paid in advance by the requesting party.
8.1.4 Coordination with ISO on Interconnection Requests. The Participating TO
shall coordinate with the ISO, pursuant to the provisions of the TCA, in
developing Interconnection standards and guidelines for processing
Interconnection requests under this TO Tariff.
8.2 Participating TO Obligation to Construct Transmission Expansions or Facility
Upgrades. The Participating TO shall be obligated to: (1) perform System Impact or Facility
Studies where the Project Sponsor or the ISO agrees to pay the study cost and specifies the
project objectives to be achieved, and (2), build transmission additions and facility upgrades
where the Participating TO is obligated to construct or expand facilities in accordance with
and subject to the limitations of the ISO Tariff atid`this TO Tariff.
8.2.1
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008
Obligation to Construct. A Participating TO shall not be obligated to
construct or expand Interconnection facilities or system upgrades unless
Resolution No. 9562 Effective: April 23, 2008
First Revised Sheet No. 10
Superseding Original Sheet No. 10
Transmission Owner Tariff (cont.)
and until the conditions stated in. Section 9.2.1 hereof have been satisfied.
8.2.2 Local Furnishing. Participating TO Obligation to Construct. A Local
Furnishing Participating TO shall not be obligated to construct or expand
Interconnection facilities or system upgrades unless and until the conditions
stated in Section 9.3.3 hereof have been satisfied.
8.3 Request for FERC Deference Regarding Need. Determination. It is intended that FERC
grant, substantial deference to the factual determinations of the ISO, (including the ISO's
ADR Procedures), the Vernon City Council, WSCC, or RTG coordinated planning processes
as to the need for -or construction of a facility, -the need for full cost recovery, and the
allocation of costs.
9. Expansion Process.
9.1 Determination,of;Facilities. A Participating TO shaRperform a Facilities Study in
accordance.with this Section where (1) the Participating TO is obligated to construct or
expand facilities in,accordance with the ISO Tariff and this TO Tariff; (2) a Market
Participant agrees to pay the,costs of the Facilities Study and specifies the project objectives
to be achieved in terms of increased capacity or reduced congestion; or (3) the Participating
TO is required to perform a Facilities Study pursuant to the ISO Tariff.
9.1.1 Payment of Facilities Study's Cost.
9.1.1.1 Market Participant to, Pay for Facilities Study. Where a Market
Participant requests a Facilities Study and the need for the
transmission addition or upgrade has not yet been established in
accordance with the procedures established herein and the ISO
Tariff, the Market Participant shall pay the cost of the Facilities
Study.
9.1.1.2 ProJect Sponsor or Project Proponent to Pay for Faculties
Study. Where the facilities to be added or upgraded have been
determined to be needed in accordance with the procedures
established herein and the ISO Tariff, the Project Sponsor, Project
Proponent, or the ISO requesting the study shall pay the reasonable
cost of the Facilities. Study, When the Participating TO is the
Project Sponsor in accordance with the ISO Tariff, the costs of the
Facilities Study shall be recovered through the Access Charges and
transmission rates.
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562_ Effective: April 23, 2008
Second Revised Sheet No. 11
Superseding First Revised Sheet No. 11
Transmission Owner Tariff (cont.)
9.1.1.3 Principal Beneficiaries to Pay for Facilities Study. Where the
facilities to be added or upgraded have been determined to be
neededand the principal beneficiaries have been identified by the
ISO or 'ISO ADR Procedures in accordance with the ISO Tariff, the
Project Sponsor and the identified principal beneficiaries shall pay
the reasonable cost of the Facilities Study, in such proportions as
may be agreed, or, failing agreement, as determined in accordance
with the IS6 APR Procedures.
9.1.2 Payment Procedure. Wherea Facilities Study is being conducted pursuant to
this TO" Tariff, the Participating TO shall, as soon as practicable, tender to the
Market Participant, Project Sponsor, Project Proponent, ISO, or identified
principal beneficiaries, as the case maybe, a Facilities Study Agreement that
defines the scope; content, assumptions;' and terms of reference for such study,
the estimated time required to complete it, and such other provisions as the
parties may reasonably require and pursuant to which such Market Participant,
Project Sponsor, Project Proponent, the ISO, or identified principal beneficiaries
agree to reimburse the Participating TO the reasonable cost of performing the
required Facilities Study. If the Market Participant, Project Sponsor, Project
Proponent; the ISO, or identified principal beneficiaries, as the case may be,
agree to the terms of the Facilities Study Agreement, they shall execute the
Facilities Study Agreement and return it to the Participating TO within ten
Business Days. If such Market Participant, Project Sponsor, Project Proponent,
the ISO, or identified principal beneficiary elects not to execute a Facilities
Study Agreement, the Participating TO shall have no obligation to complete a
Facilities Study.
9.1.3 Facilities Study Procedures. Upon receipt of an executed Facilities Study
Agreement, a copy of which has been provided to the ISO by the party
requesting the Facilities Study; the Participating TO will use due diligence to
complete the required Facilities Study in accordance with the terms of the
Facilities Study Agreement.
9.2 Obligation to Build.
9.2.1 Due Diligence to Construct. Subject to Section 9.3.3 of this TO Tariff, the
Participating TO shall use due diligence to construct, within a reasonable time,
additions or upgrades to its transmission system that it is obligated to construct
pursuant to the ISO Tariff and this TO Tariff. The Participating TO's obligation
to build will be subject to: '1) its ability, after making a good faith effort, to
obtain the necessary`approvals and property rights under applicable federal,
state, and local laws;, 2) the presence of a cost recovery mechanism with cost
responsibility assigned in accordance with the ISO Tariff; and 3) a signed
Participation
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
First Revised Sheet No. 12
Superseding Original Sheet No. 12
Transmission Owner Tariff (cont.)
Agreement. The Participating TO will not construct or expand its existing or
planned transmission system, if doing so would impair system reliability as
determined through systems analysis based on the Applicable Reliability
Criteria.
9.2.2 Delay in. Construction or. Expansion. If any event occurs that will materially
affect the time for completion of new facilities, or the ability to complete them,
the Participating TO shall promptly notify: (1) the Project Sponsor with regard
to facilities determined to be needed; (2) the Parties to the Participation
Agreement with regard to facilities.determined to be needed pursuant to the ISO
Tariff where principal beneficiaries were identified; and (3) the ISO. In such
circumstances, the Participating TO shall, within thirty days of noticing such
Project Sponsor, Parties to the Participation Agreement, and the ISO of such
delays,.convene a technical meeting with such Project Sponsor, Parties to the
Participation Agreement, and the ISO to discuss the circumstances which have
arisen and evaluate any options available. The. Participating TO also shall make
available to such Project Sponsor, Parties to, the Participation Agreement, and
the ISO, as the case may. be, studies and work papers related to the cause and
extent of the delay and the Participating TO's ability to complete the new
facilities, including all information that is in the possession of the Participating
TO that is reasonably needed to evaluate the alternatives.
9.2.2.1 Alternatives,to the Original Facility Additions. If the review
process of Section, 9.22 determines .that one or more alternatives
exist,to the originally planned construction project, the Participating
TO shall present such alternatives for consideration to the Project
Sponsor, Parties to the Participation Agreement, and the ISO, as the
case may be. If upon review of any alternatives, such Project
Sponsor, the ISO, or Parties to the Participation Agreement wish to
evaluate or proceed with one of the alternative additions or
upgrades, such Project, Sponsor, -the ISO, or Parties to the
Participation Agreement may request that the Participating TO
prepare a revised Facility Study pursuant to Sections 9.1.1, 9.1.2,
and 9.1.3 of this TO Tariff. In the event the Participating TO
concludes that no reasonable alternative exists to the originally
planned addition or upgrade and the Project Sponsor or Parties to
the Participation Agreement; or the ISO disagree, the dispute shall
be resolved pursuant to the ISO ADR Procedure.
9.2.2.2 Refund Obligation for Unfinished Facility Additions. If the
Participating TO and the Project Sponsor, the ISO, or Parties to the
Participation Agreement, as,the case maybe, mutually agree that no
other reasonable alternatives exist, the obligation to construct the
requested additions or upgrades shall terminate and any deposit not
yet applied toward the expended project
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24.2008 Resolution No. 9562 Effective: April 23, 2008
First Revised Sheet No. 13
Superseding Original Sheet No. 13
Transmission Owner Tariff (cont.)
costs shall be returned with interest pursuant to FERC Regulation
35.19(a)(2)(iii). However, the Project Sponsor and any identified
principalbeneficiaries, as the case may be, shall be responsible for
all costs prudently incurred by the Participating TO through the
time the construction,was suspended.
9.3 Provisions Relating To Transmission Construction On the Systems Of Other TOs.
9.3.1 Responsibility for Third Party Additions, A Participating TO shall not be
responsible for making arrangements for any engineering, permitting, and
construction of any.necessary facilities additions on the system(s) of any other
entity or for obtaining any regulatory approval for such facilities. The
Participating TO will undertake reasonable efforts through the coordinated
planning process to assist in making such arrangements, including, without
limitation, providing any information or data required by such other electric
system pursuant to Good Utility Practice.
9.3.2 Coordination, of Third -Party System Additions. Where transmission
additions or upgrades being built pursuant to the ISO Tariff require additions or
upgrades on other systems, to the extent consistent with Section 9.3.3 of this TO
Tariff the Participating TO shall coordinate construction on its own system with
the construction required by others. The Participating TO, after consultation
with the ISO, the Project Sponsor, and Parties to the Participation Agreement,
as the case may be, may defer construction if thenewtransmission facilities on
another system cannot be completed in a timely manner. The Participating TO
shall notify such Project Sponsor, Parties to the Participation Agreement, and
the ISO, in writing.of the basis for any decision to defer construction and the
specific problems which must be resolved before it will initiate or resume
construction of the new facilities. Within forty Business Days of receiving
written notification by the Participating TO of its intent to defer construction
pursuant to this section, such Project Sponsor, Parties to the Participation
Agreement, or the ISO may challenge the decision in accordance with the ISO
ADR Procedure.
9.3.3 Expansion by "Local :Furnishing Participating TOs. ° Notwithstanding any
other provision of this TO Tariff, prior to requesting that a Local Furnishing
Participating TO construct or expand facilities, the ISO or Project Sponsor shall
tender (or cause to be tendered) an application under Section 211 of the FPA
requesting FERC to issue an order directing the Local Furnishing Participating
TO to construct or expand facilities as necessary to provide transmission service
as determined pursuant to the ISO Tariff. Such Local Furnishing Participating
TO shall thereafter, within ten Business Days of receiving a copy of the Section
211 application, waive its right to a request for
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
First Revised Sheet No. 14
Superseding Original Sheet No. 14
Transmission Owner Tariff (cont.)
service under Section213(a) of the FPA and to the issuance of a proposed order
under Section 212(c)of the FPA. Upon receipt of a final order from FERC
under Section 211 of the FPA that is no longer subject to rehearing or appeal,
such Local Furnishing Participating TO shall construct or expand facilities to
comply with that FERC order and shall transfer to the ISO Operational Control
over the Local Furnishing Participating TO's expanded transmission facilities in
accordance ,with :the,ISO Tariff. , -
10. Interconnection Process.
10.1 Applicability. All requests for interconnection directly to the ISO Controlled Grid from
parties eligible to request such Interconnection consistent with Section 210(a) of the FPA
shall be.processed pursuant to the;provisions of this Section 10 which is subject to the
applicable interconnection, integration, exchange, operating, joint ownership and joint
participation agreements, and the rights and obligations of owners of jointly -owned facilities.
10.2 Applications. Parties requesting Interconnections shall submit written applications to the
Participating TO and.shall send a copy o£the application to the ISO. The Participating TO
shall time -stamp the application to establish study<priority.
16.3 Completed Application. A Completed Application shall provide all of the information listed
in 18 C.F.R. § 2.20, including, but not limited to; the following:
(i) The identity, address, telephone number, and facsimile number of the entity
requesting service;
(ii) The Interconnection point(s) and the. location of the transmission addition
contemplated by the applicant;
(iii) The resultant (or new) maximum amount of Interconnection capacity requested at
each point which may experience such an increase;. and the increased transmission
capacity of the transmission addition requested;
(iv) The proposed date for initiating an Interconnection. In addition to the information
specifiedabove, when required to properly evaluate system conditions, the
Participating TO also may ask the; applicant to provide the following:
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
Second Revised Sheet No. 15
Superseding First Revised Sheet No. 15
Transmission Owner Tariff (cont.)
(v) The electrical location -of the source of the power (if known) to be transmitted
pursuant to the applicant's request for Interconnection. If the source of the power is
not known, a system purchase will be assumed;
(vi) The electrical location'of the ultimate load (if known). If the location of the load is
not known, a system sale will be assumed; and
(vii) Such other information as the Participating TO reasonably requires to process the
application.
The Participating TO will treat theinformationin (v) and (vi) as confidential at the request of
the applicant except to the extent that disclosure of this information is required by this TO
Tariff, by regulatory orjudicial order, for reliability purposes pursuant to Good Utility
Practice, or Pursuant to RTG or ISO transmission information sharing agreements. The
Participating TO shall treat this information consistent` with the standards of conduct
contained in Part 37 of FERC's regulations:
10.4 Noticecof Need for System Impact Study. After receiving a Completed Application for
Interconnection; the Participating TO shall determine on a nondiscriminatory basis whether a
-System Impact -Study -is needed. If the Participating TO determines that a System Impact
Study is necessary to accommodate the requested Interconnection, it shall so inform the
applicant (and shall send a courtesy copy to the ISO), as soonas practicable. In such cases,
the Participating TO shall within twenty Business Days of receipt of a Completed
Application, tender a System Impact Study Agreement that defines the scope, content,
assumptions and terms- of reference for such study, the estimated time required to complete it,
and such other provisions as the parties may reasonably require, and pursuant to which the
applicant. shall agree to reimburse the Participating TO for the "reasonable costs of performing
the required. System Impact Study. For an Interconnection request to remain a Completed
Application, the applicant shall execute the System Impact Study Agreement and return it to
the Participating TO within ten Business Days. If the applicant elects not to execute a System
Impact Study Agreement, its application shall be deemed withdrawn, and the applicant shall
reimburse to the Participating TO and the ISO all costs reasonably incurred in processing the
application.
10.5 System Impact Study Cost Reimbursement and Agreement.
10a.5A Cost Reimbursement. The'System Impact Study Agreement shall clearly
specify the maximum charge, based on the Participating To's estimate of the
cost and time for completion of the System Impact Study. The charge shall not
exceed the reasonablecost of the study. In performing the System Impact Study,
the Participating TO shall rely, to the extent reasonably practicable, on existing
transmission planning studies. The applicant will not be assessed a charge for
such existing studies; however, the applicant.will be responsible for the
reasonable charges associated with any modifications to existing
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
First Revised Sheet No.16
Superseding Original Sheet No. 16
Transmission Owner Tariff (cont.)
planning studies that are reasonably necessary to evaluate the impact of the
applicant's request.
10.5,2 ;Multiple Parties. If multiple parties request Interconnection at the same
location, the Participating TO may conduct a single System Impact Study. The
costs of that study shall be pro -rated among the parties requesting
Interconnection.
10.6 System Impact Study Procedures. Upon receipt of an executed System Impact Study
Agreement, the Participating TO will.use due diligence to complete the required System
Impact Study within a sixty day period. The System Impact Study shall identify any system
constraints which cannot be reasonably accommodated through ISO Congestion
Management, such that transmission expansions or upgrades would be required to provide the
requested Interconnection. In the event that the Participating TO is unable to complete the
required System Impact Study withinsuch time period, it shall so notifythe applicant. and
provide an estimated completion date along with an explanation of the reasons why additional
time is required to complete the required studies. A copy of the completed System Impact
Study and related work papers shall be made available to the applicant and;the ISO. The
Participating TO will use the same due diligence -in completing the System Impact Study for
,others as it uses when completing studies for its affiliated UDC. The Participating TO shall
notify ,the applicant and the ISO immediately upon completion of the System Impact Study.
10.6.1 Failure to Execute an Interconnection Agreement, If the Participating TO
finds that the transmission system will be adequate to accommodate all of a
request for Interconnection and that no costs are likely to be incurred for new
transmission additions or upgrades, the applicant must execute.an
Interconnection Agreement -within ten Business Days of completion of the
System Impact Study or the application shall be deemed terminated and
withdrawn.
10.6.2 Facilities Study Procedures, If a System Impact Study indicates that additions
or upgrades to the transmission system are needed to meet, an applicant's
request, the Participating TO shall, within fifteen Business Days of the date of
the System Impact Study, tender to the applicant a,Facilities Study Agreement
that defines the scope, content, assumptions and terms of reference for such
study, the estimated time required to complete it, and such other provisions as
the parties may reasonably require, and pursuant to which the applicant agrees
to, reimburse the Participating TO, for performing the required Facilities Study.
For a service request to remain a Completed Application, the applicant shall
execute the Facilities Study Agreement and return it to the Participating TO
within, ten Business Days. If the applicant elects not to execute a Facilities
Study Agreement, its application shall be. deemed withdrawn and the applicant
shall reimburse to the
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
First Revised Sheet No. 17
Superseding Original Sheet No. 17
10.7
10.8
10.9
Transmission Owner Tariff (cunt.)
Participating TO all costs reasonably incurred in processing the application not
covered by the System Impact Study Agreement.'
Relevant Sections Apply Upon Receipt of Facilities Study Agreement. Upon receipt of an
executed facilities Study Agreementbythe Participating TO, the relevant portions of
Sections 9.1.3 through 9.3.3 of this TO Tariff shall apply.
Partial Interim Service.If the Participating TO determines that there will not be adequate
transmission capability to satisfy the full amount of a Completed Application for an increase
in the maximum rate of delivery or receipt associated with a new request for Interconnection,
the Participating TO nonetheless shall be obligated to offer and provide the portion of the
requested Interconnection that can be accommodated without any additions or upgrades.
However, the Participating TO shall not be obligated to provide the incremental amount of
requested Interconnection that requires the addition of facilities or upgrades to the
transmission system until such facilities or upgrades have been placed in service.
Expedited Procedures for New Facilities. In lieu of the procedures set forth above, the
applicant shall have the option to expedite the process by requesting the Participating TO to
tender at one time, together with the results of required studies, an "Expedited Service
Agreement" pursuant to which the applicant would agree to compensate the Participating TO
for allcosts reasonably incurred pursuant to the terms of this TO Tariff. In order to exercise
this option, the applicant shall request in writing an Expedited Service Agreement covering
all of the above -specified items within twenty Business Days of receiving the results of the
System Impact Study identifying needed facility additions or upgrades or costs incurred in
providing the requested Interconnection. The Participating TO shall tender an Expedited
Service Agreement within ten Business Days of the applicant's request. While the
Participating TO agrees to provide the applicant with its best estimate of the new facility costs
and other charges that may be incurred, unless otherwise agreed by the parties such estimate
shall not be binding and the applicant must agree in writing to compensate the Participating
TO for all costs reasonably incurred pursuant to the provisions of this TO Tariff. The
applicant shall execute and return such Expedited Service Agreement within ten Business
Days of.its receipt or the, applicant's request for Interconnection will cease to be a Completed
Application and will be deemed terminated' and withdrawn. In that event, the applicant shall
reimburse to the Participating TO all costs' reasonably incurred in processing the application
not covered by terms of the System Impact Study Agreement.
11. Uncontrollable Forces and Indemnification.
11.1 Procedures to Follow if Uncontrollable Force Occurs. In the event of the occurrence of an
Uncontrollable Force which prevents a Party from performing any of its obligations under
this TO Tariff, such Party shall (i) immediately notify the other Parties in writing of the
occurrence of such Uncontrollable Force, (ii) not be entitled to suspend performance in any
greater scope or longer duration
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
First Revised Sheet No. 18
Superseding Original Sheet No. 18
Transmission Owner Tariff (cont.)
than is, required by the. Uncontrollable Force; (iii) use. its best efforts to mitigate the effects of
such Uncontrollable. Force, remedy its inability to perform, and resume full performance
hereunder, (iv) keep the other Parties apprised of such efforts on a continual basis and (v)
provide written notice of the resumption of -performance hereunder. Notwithstanding. any of
the foregoing, the settlement of any, strike, lockout or labor dispute constituting an
Uncontrollable Force shall be within the sole discretion of the Party: to this TO Tariff
involved in such strike, lockout, or labor dispute and the requirement that a Party must use its
best efforts to remedy the cause of the Uncontrollable Force and mitigate>its effects and
resume full performance hereunder shall not apply to strikes, lockouts, or labor disputes. No
Party -will be considered in default as to any obligation under this TO Tariff if prevented from
fulfilling the obligation due to the occurrenceofan Uncontrollable Force.
11.2 Indemnification. A Market Participant shall at all times indemnify, defend, and save the
Participating TO harmless from any and all damages, losses, claims, (including claims and
actions relating to injury or to death of any person or damage. to property), demands, suits,
recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to
third parties, arising out, of or resulting from the Participating TO's.performance of its
obligations under this TO Tariff on behalf of a Market Participant,; except in cases of
negligence or intentional wrongdoing by the Participating TO.
12. Regulatory Filings. Nothingcontained herein shall be construed as affecting, in anyway, the right of
Vernon to unilaterally make application to FERC as it deems necessary and appropriate to recover its
Transmission Revenue Requirements, or for a change in its terms and conditions, including changes in
rate methodology, or for a change in designation of transmission facilities and Entitlements to be
placed under the ISO's control, pursuant to the applicable FERC rules, regulations, policies, and
governing statutes.
13. Miscellaneous.
13.1 Notices. Any notices, demand, or request in accordance with this TO Tariff, unless otherwise
provided in this TO Tariff, shall be in writing and shall be deemed properly served, given, or
made:.-(i) upon, delivery if delivered in person, (ii) five days after deposit in the mail if sent by
first class United States mail, postage prepaid, (iii) upon receipt of confirmation by return
electronic facsimile if sent by facsimile, or (iv) upon delivery if delivered by prepaid
commercial courier service, in each case addressed to;a Party at the address set forth in
Appendix H. Any Party may at any time, bynotice to the other Parties, change the
designation or address of the person specified in Appendix II to receive notice on its behalf.
Any notice of a routine character in connection with service under this TO Tariff shall be
given in such a manner as the Parties may determine from time_to.time, unless otherwise
provided in this TO Tariff.
13.2 Waiver. Any waiver at any time by any Party of its rights with respect to any default under
this TO Tariff, or with respect to any other matter arising in connection with this TO Tariff,
shall not constitute or be deemed a waiver with
Authorized by City of Vernon
Ordinance No. 940
Issued on: April 24, 2001 Resolution No. 7751 Effective: January 1, 2001
Sheet No. 19
Transmission Owner Tariff (cont)
respect to any subsequent default or other matter arising in connection with this TO Tariff.
Any delay short of the statutory period of limitations in asserting or enforcing any right shall
not constitute or be deemed a waiver.
13.3 Confidentiality.
13.3.1 Maintaining Confidentiality if Not for Public Disclosure. The Participating TO
shall maintain the confidentiality 'ofall of the documents, data, and information
provided to it by any other Party that such Party may designate as confidential,
provided, however, that the information will not be confidential by the
receiving Party if (1) the designating Party is required to provide such information
for public disclosure pursuant to this TO Tariff or applicable regulatory
requirements, or (2) the information becomes available to the Public on a non -
confidential basis (other than from the receiving Party).
13.3.2 _Disclosure of Confidential Information. Notwithstanding anything in this
Section 11.3.2 to the contrary, if any Party is required by applicable laws or
regulations, or in the course of administrative or judicial proceedings, to disclose
information that is otherwise required to be maintained in confidence pursuant to
this: Section 113.2, the Party may disclose such information; provided, however,
that as soon as such Party learns of the -disclosure requirement and prior to making
such disclosure, such Party shall notify. the affected Party or Parties of the
requirement and the terms thereof. The affected Party or Parties may, at their sole
discretion.and own costs, direct -any challenge to or defense against the disclosure
requirement and the disclosing Party shall cooperate with such affected Party or
Parties to the maximum extent practicable to minimize the disclosure of the
information consistent with applicable law. The disclosing Party shall cooperate
with the affected Parties to obtain proprietary or confidential treatment of
confidential information by the person to whom such information is disclosed prior
to any such disclosure.
13.4 Titles. The captions and headings in this TO Tariff are inserted solely to facilitate reference
and shall have no bearing upon the interpretation of any of the rates, terms, and conditions of
this TO Tariff.
13.5 Severability. If any term, covenant, or condition of this TO Tariff or the application or effect
of any such term, covenant, or condition is held invalid as to any person, entity, or
circumstance, or is determined to be unjust, unreasonable, unlawful, imprudent, or otherwise
not in the public interest, by any court or government agency of competent jurisdiction, then
such term, covenant, or condition shall remain in force and effect to the maximum extent
permitted bylaw, and all other terms, covenants, and conditions of this TO Tariff and their
application shall not be affected thereby but shall remain in force and effect. The Parties shall
be relieved of their obligations only to the extent necessary to eliminate such regulatory or
other determination, unless a court or
Authorized by City of Vernon
Ordinance No. 940
Issued on: March 24, 2008 Resolution No. 9562 Effective: April 23, 2008
First Revised Sheet No. 20
Superseding Original Sheet No. 20
Transmission Owner Tariff (cont.)
governmental agency of competent jurisdiction holds that such provisions are not severable
from all other provisions of this TO Tariff.:
13.6 Preservation of Obligations. Upon termination of this TO Tariff, all unsatisfied obligations
of each Party shall be preserved until satisfied.
13.7 Governing Law. This TO Tariff shall be; interpreted, governed by, and construed under the
laws :of the State of California, without regard to the principles of conflict of laws thereof, or
the laws of the United States, as applicable, as if executed and to be performed wholly within
the State of California:.
13.8 Appendices Incorporated. The appendices to this TO Tariff are attached to this TO Tariff
and are incorporated by reference as if fully set forth herein.
13.9 Consistency with ISO Tariff. This TO Tariff is intended to be consistent with the ISO
Tariff, and, if necessary, shall be amended to conform with any changes authorized or
required in any finalorder in FERC-Docket No. ER00-2019.
13.10 Disputes. Except as; by law; the ISO: ADR Procedures shall apply to all disputes
between parties which arise under this TO Tariff or under or in respect of the proposed terms
and conditions of a Facilities Study Agreement, System+Impact Study Agreement or
Expedited Service Agreement. The ISO ADR Procedures set forth in Section 13 of the ISO
Tariff shallnot apply to disputes as to whether rates and charges set forth in this TO Tariff
(other than charges for studies) are -just -and reasonable under the FPA.
Authorized by City of Vernon
Ordinance No. 940
Issued on: April 24, 2001
Resolution No. 7751
Effective: January 1, 2001
Sheet No. 21
Transmission Owner Tariff (cont.)
APPENDIX I
Transmission Revenue Requirement and TRBAA
The Vernon Base Transmission Revenue Requirement is $944,348 and is comprised of the following
components:
Base TRR costs not subject to ETC Adjustment Clause: $497,905
ETC Adjustment Clause:
Forecast SCE ETC Costs: $446,443
Balance of Difference between prior year
Forecast and Actual SCE ETC Costs: $0
Interest on Difference between prior year
Forecast and Actual SCE ETC Costs: $0
The ETC Adjustment Clause is: The projected SCE ETC Cost for the next calendar year, plus the
true -up (positive or negative) of the prior October through September SCE ETC Cost with interest
calculated pursuant to 18 C.F.R. § 35.19a. The ETC Adjustment Clause will be recalculated annually
and filed with the Commission with a proposed effective date of January 1 of each year.
The TRBAA is a positive $286,851 for calendar year 2009.
Vernon's Gross Load, consistent with its TRR, used by the ISO to develop the Transmission Access Charge is
1,257,502 MWh.
All of Vernon's transmission facilities and Entitlements placed under the ISO's Operational Control are High
Voltage Facilities as defined by the ISO Tariff.
The TRBAA will be recalculated annually consistent with the ISO Tariff approved by the Vernon City
Council, and provided to the ISO.
Authorized by City of Vernon
Ordinance No. 940
Issued on July 13, 2009 Resolution No. Effective: August 1, 2009
Tenth Revised Sheet No. 22
Superseding Ninth Revised Sheet No. 22
Transmission Owner Tariff (cont.)
APPENDIX II
NOTICES
Designated Representative:
Mr. Donal O'Callaghan
City Administrator
City of Vernon
4305 Santa Fe Avenue. _
Vernon, California 90041
Tel. No. (323) 583-8811
Fax No. (323) 581-7924
Authorized by City of Vernon
Ordinance No. 940
Issued on: July 13, 2009 Resolution No. Effective: August 1, 2009
Second Revised Sheet No. 23
Superseding First Revised Sheet No. 23
CERTIFICATE
STATE OF CALIFORNIA )
) ss
COUNTY OF LOS ANGELES)
I, Manuela Giron, City Clerk of the City of Vernon, County
of Los Angeles, State of California, hereby certify that the
attached is a.full and complete copy of:
RESOLUTION NO. 10,005 - A Resolution of the City Council of
the City of Vernon Adopting a Ne' Transmission Revenue
Requirement Associated with Vernon s High Voltage (Over 200
KV) Entitlements Located Outside of he City and Adopting an
Amended Transmission Owner Tariff for _rposes of the City's
Participation in the California Independent System Operator
IN WITNESS WHEREOF, I have hereunto set my hand and affixed
the official Seal of the CityofVernon, County of Los Angeles
State of California, on this /3 day of July 2009.
SEAL:
M uela Giron
City Clerk
Vt AL
INTEROFFICE "�� I t1� AI&%&RAk6ff(JUNCIL
h
IMED
Light & Power DepartmentRECE(� �
JUL 0 8 2009
CIDaA K S OFFg 7, 2009
CITY C RK ®ISTRI UTI®N
� ;g
TO: Donal O'Callaghan
Director of Light & Power
FROM: Abraham Alemu 7"
Electric Resources Planning & Development Manager
SUBJECT: Transmission Owner Tariff and Transmission Revenue Requirement Amendments/ SCE
Offer of Settlement
Attached for your review and approval is the complete package for the Council's consideration on
July 13th of the SCE Offer of Settlement and the related amendments to the City's Transmission
Owner Tariff and the City's Transmission Revenue Requirement for entitlements placed under the
California Independent System Operator operational control Specifically, attached are the following
files:
• Draft Resolution (approving the amendments to the TO Tariff and TRR)
• Staff Report Cover .
• Staff Report
• SCE Offer of Settlement (Exhibit 1 to the Staff Report)
• Testimony of the Brattle Group with exhibits (Exhibit 2 to both the Staff Report and the Draft
Resolution)
• Appendix I reflecting TRR to be effective August 1, 2009 (Exhibit 3 to both the Staff Report and
the Draft Resolution)
• Appendix I reflecting TRR to be effective January 1, 2010 (Exhibit 4 to both the Staff Report
and the Draft Resolution)
• Appendix I reflecting TRR to be effective January 1, 2011 (Exhibit 5 to both the Staff Report
and the Draft Resolution)
• Appendix I reflecting TRR to be effective January 1, 2012 (Exhibit 6 to both the Staff Report
and the Draft Resolution)
July 7, 2009
Donal O'Callaghan
Page 2
• Amended TO Tariff to be effective August 1, 2009 (Exhibit 7 to both the Staff Report and the
Draft Resolution).
DO:AA:eo
Attachments
c: Abraham Alemu
Document Control
R�
u
rg�
STAFF REPORT
LIGHT & POWER
DATE: July 6, 2009
TO: Honorable Mayor and City Council
FROM: Donal O'Callaghan, Director of Light & Power
RE: Transmission Owner Tariff and Transmission Revenue Requirement
Amendments/ SCE Offer of Settlement
PURPOSE
Staff Report is attached .
Recommendation:
DO:AA:eo
Attachments
c: Document Control
CITY OF VERNON LIGHT & POWER DEPARTMENT
STAFF REPORT REGARDING: (i) THE PROPOSED SETTLEMENT
REGARDING CERTAIN EXISTING TRANSMISSION CONTRACTS
WITH SOUTHERN CALIFORNIA EDISON WHICH ARE PART OF
VERNON'S HIGH VOLTAGE (OVER 200 KV) ENTITLEMENTS
LOCATED OUTSIDE OF THE CITY; AND (ii) THE ESTABLISHMENT
OF A NEW TRANSMISSION REVENUE REQUIREMENT
ASSOCIATED WITH VERNON'S HIGH VOLTAGE ENTITLEMENTS
AND ADOPTION OF AN AMENDED TRANSMISSION OWNER
TARIFF FOR PURPOSES OF THE CITY'S PARTICIPATION IN THE
CALIFORNIA INDEPENDENT SYSTEM OPERATOR.
July 6, 2009
The City of Vernon is a Scheduling Coordinator and a Participating
Transmission Owner ("PTO") in the California Independent System Operator ("ISO").
To participate in the ISO, PTOs are required to turn over administrative control of
their transmission facilities and entitlements to the ISO. In return, the ISO collects
revenues for each PTO pursuant to calculations that reflect the expenses and capital
costs incurred by each PTO to provide transmission services. These calculations
are known as Transmission Revenue Requirements ("TRRs").
The relationship between PTOs and the ISO is governed by a Transmission
Control Agreement ("TCA"), which sets forth specific duties and obligations of all
PTOs. The TCA requires all PTOs to file a Transmission Owner Tariff ("TO Tariff')
and TRR with the Federal Energy Regulatory Commission ("FERC"). The TCA
further requires all PTOs to file any changes in their TRRs with the FERC. The City
last filed an amended TRR with FERC on April 23, 2008. That TRR, which was
accepted by FERC on July 2, 2008, set the City's Base TRR at $918,137.
At present, the City's high voltage transmission assets consist of three long-
term contracts (known as "existing transmission contracts" or "ETCs") which provide
the City with dedicated access to high voltage transmission facilities owned by other
Staff Report
TRR 2009
Page 2 of 8
entities. Specifically, the City has contractual entitlements to utilize transmission
assets pursuant to one long-term transmission contract with the Los Angeles
Department of Water and Power ("LADWP"), and two long-term transmission
contracts with Southern California Edison ("SCE"). The ETCs with SCE consist of
one (the "SCE Victorville-Lugo ETC" described in SCE's FERC Rate Schedule 360)
providing 11 MW of transmission capacity along the path between the Victorville-
Lugo midpoint and the point of interconnection with the City's internal transmission
system (aka the "City Gate"), and one (the "SCE Mead ETC" described in SCE's
FERC Rate Schedule 207) providing 26 MW of transmission capacity along the path
between the Mead 230 substation and City Gate..
The costs of these ETCs make up the majority of the costs recovered through
the City's TRR. Until recently, for each of the ETCs, the City paid the owner of the
transmission facilities a fixed rate which was specific to the transmission path
provided under each ETC. As a result, Vernon was able to set its TRR on April 23,
2008 at a fixed sum of $918,137.
SCE's APPLICATION TO CONVERT ETCs TO "POSTAGE STAMP" RATES
On August 1, 2008, SCE proposed to increase its TRR and associated rates
in FERC Docket No. ER08-1343-000. In a related filing submitted in FERC Docket
No. ER08-1353-000, SCE proposed to transition both of Vernon's ETC's from their
current, fixed "path -specific" rates to a so-called "postage stamp" rate methodology
which reflects the blended rate which SCE charges the ISO pursuant to its own
TRRs for the actual usage of all of SCE's transmission facilities by customers of the
ISO (the "HVECAC Rate"). FERC accepted SCE's filings in an order issued on
September 30, 2008 and made the TRR increase and the proposed change in ETC
rate calculations effective March 1, 2009, subject to refund and the outcome of
hearing and settlement judge proceedings.
The City protested both of SCE's filings and has over the past several
months, through outside counsel, participated in settlement discussions with SCE
and certain other private and governmental parties which have intervened in the two
related FERC dockets. Through those negotiations, the City, SCE and the other
Staff Report
TRR 2009
Page 3 of 8
interested parties have reached a proposed settlement of their disputes related to
SCE's filings. On July 1, 2009, SCE filed an Offer of Settlement reflecting the
settlement terms agreed between it and the parties in Docket Nos. ER08-1343-000
and ER08-1353-000, a copy of which is. attached hereto as "Exhibit 1 ".
The Offer of Settlement includes an agreement for the rates under each of the
City's ETCs with SCE to be increased, over a period of time, until a point beginning
January 1, 2013 when the rate under both the SCE Victorville-Lugo ETC and the
SCE Mead ETC will be set to equal SCE's then -existing HVECAC Rate.
Specifically, under the Offer of Settlement, there will be Little change in the SCE ETC
rates until August 1, 2009.' Beginning on August 1, 2009 and continuing on January
1, 2010, January 1, 2011, January 1, 2012 and January 1, 2013 the rates charged to
the City under each of the ETCs with SCE will increase pursuant to an agreed -upon
rate schedule as follows:
The Offer of Settlement remains subject to the approval of the City Council.
Subsequent to City Council approval of the Offer of Settlement, and with additional
approval of the City Council, the City plans to file a petition with FERC and the ISO
to reflect a change in the City's currently effective TRR to include the rates proposed
Prior to SCE's current effort to amend the ratesofthe City's ETCs with SCE, the City's rate
under the SCE Mead ETC was $1.04756 per kW -month. The Offer of Settlement rounds the City's
rate under the SCE Mead ETC to $1.04 per kW -month for the period between March 1, 2009 and
August 1, 2009.
Staff Report
TRR 2009
Page 4 of 8
in the Offer of Settlement.
The Offer of Settlement provides the City with a sufficient period of time to
implement adjustments to the City's TRR to reflect the City's increased costs as a
result of the SCE ETCs moving to "postage stamp" rates. In the absence of the
agreement reflected in the Offer of Settlement, the City would have the option to
continue to protest the conversion of the SCE ETCs to postage stamp rates and ask
FERC to resolve the question of whether such a conversion is appropriate. It
appears, however, that there is strong support for the settlement and that the City
would likely be the only one of SCE's remaining ETC customers that would be
pursuing such a protest. Moreover, FERC appears to generally support the
conversion of all of the ETCs which SCE has with any party to "postage stamp" rates
and has made the conversion of Vernon's ETCs with SCE effective March 1, 2009,
subject to refund and the outcome of hearing and settlement judge proceedings.
EFFECT OF SCE's CONVERSION OF ETCs TO "POSTAGE STAMP" RATES
As a result of the revisions to the rates that the City will be paying under each
of the ETCs with SCE if the Offer of Settlement is approved, beginning August 1,
2009 the City's existing TRR will no longer completely compensate the City for the
costs of its transmission assets. In order to continue to completely recover the City's
costs for the ETCs with SCE and LADWP, therefore, the City must as of August 1,
2009 adopt and file a revised TRR that reflects the agreed upon rates for the City's
ETCs with SCE as set forth the in the Offer of Settlement. As explained further
below, for the period from August 1, 2009 through December 31, 2012, if the Offer of
Settlement is approved, the costs of City's transmission assets, including the costs
of the ETCs with SCE, can be summarized as follows:
August 1, 2009 — December 31, 2009
$944,348
January 1, 2010 — December 31, 2010
$1,218,960
January 1, 2011 — December 31, 2011
$1,275,480
January 1, 2012 — December 31, 2012
$1,346,520
Calculations of these costs are reflected in attached "Exhibit 2-C" and "Exhibit 2-F".
Staff Report
TRR 2009
Page 5 of 8
In addition, because the City's costs under ETCs with SCE will continue to
change with each increase in the rates charged by SCE pursuant to this agreed rate
schedule and, beginning on January 1, 2013, with each further change to SCE's own
HVECAC rate, Staff proposes that the City's TO Tariff be amended to incorporate a
mechanism (an "ETC Adjustment Clause") that will allow any change in the rates
charged to the City under the SCE Victorville-Lugo ETC and/or the SCE Mead ETC
to automatically flow -through to the City's TRR.
This staff report also supports the establishment of a new TRR and the
amendment of Vernon's TO Tariff to reflect the ETC Adjustment Clause.
ETC ADJUSTMENT CLAUSE MECHANISM
As noted above, the ETCs with SCE and LADWP comprise the majority of the
City's TRR (the remainder consisting of the City's Administrative & General costs
(reflecting the costs of City staff involved in administering the ETCs and the City's
relationship with the ISO as a PTO).and Regulatory Expenses (consisting of legal
and consulting expenses incurred in connection with the City's role as a PTO).
Because the City's costs under the SCE Victorville-Lugo ETC and the SCE Mead
ETC are now expected to change at least annually through December 31, 2012 and,
beginning on January 1, 2013 will change up to several times per year as SCE's
HVECAC Rate changes due to changes in SCE's own TRR, in order to ensure that
the City's TRR accurately reflects the City's actual costs under the SCE Victorville-
Lugo ETC and the SCE Mead ETC, it could be necessary for the City to change its
TRR several times per year. Pursuant to the TCA, each new TRR would need to be
filed with FERC, which would create a heavy time burden on City staff and cause the
City to incur substantial additional regulatory expenses.
In order to ensure that the City's TRR continues to accurately reflect the City's
costs under the SCE Victorville- Lugo ETC and the SCE Mead ETC as the rates
under those ETCs change, without the need to repeatedly amend the City's TRR,
The Brattle Group, an experienced utilities consulting firm, has developed an ETC
Adjustment Clause mechanism. When added to the City's TO Tariff, the ETC
Adjustment Clause will allow any change in the rates charged to the City under the
Staff Report
TRR 2009
Page 6 of 8
SCE Victorville-Lugo ETC and/or the SCE Mead ETC to flow -through to the City's
TRR through an annual adjustment to the City's Base TRR. That annual adjustment
will include a forecast of the City's expected costs for SCE Victorville-Lugo ETC
and/or the. SCE Mead ETC for the coming year, as well as a true -up calculation
which will capture any costs (including interest) associated with changes to the rates
for those ETCs between the periods of each annual adjustment.
Staff has reviewed the ETC Adjustment Clause prepared by The Brattle
Group and proposes that the City's TO Tariff be amended to include such an ETC
Adjustment Clause.
CALCULATION OF VERNON'S TRRs
The Brattle Group has prepared a new TRR effective August 1, 2009, as
explained in the prepared testimony with included exhibits, attached hereto as
"Exhibit 2". The City's staff has reviewed the new TRR. The TRR, if approved, will
be implemented by a tariff sheet included as Appendix I of the TO Tariff, attached
hereto as "Exhibit 3".
The TRR is calculated to reflect the increase in the rates charged under the
SCE Victorville-Lugo ETC and the SCE Mead ETC effective August 1, 2009. In
addition, because the Offer of Settlement also includes an agreed -upon schedule of
rate increases for each of Vernon's ETCs with SCE for the years 2010 to 2012, the
Brattle Group has calculated new TRRs for the City to be effective January 1 2010,
January 1, 2011 and January 1, 2012. The Brattle Group proposes to implement the
new TRRs for each of these years through the ETC Adjustment Clause, as reflected
in "Exhibits 4, 5 and 6" attached hereto. The TRR for each period is calculated as
follows:
• August 1, 2009 TRR — Exhibit 2-C Line [1][G]: $944,348. This figure is
calculated by determining the sum of the costs for the SCE MEAD ETC
(Line[1][B]), the SCE Victorville-Lugo ETC (Line[1][C]), the LADWP
ETC (Line[1][D]), A&G Expenses (Line[1][E]) and Regulatory Expenses
(Line[1][F])•
• January 1, 2010 TRR — Exhibit 2-F Line [1][G]: $1,218,960. This
figure is calculated by determining the sum of the costs for the SCE
MEAD ETC (Line[1][B]), the SCE Victorville-Lugo ETC (Line[1][C]), the
Staff Report
TRR 2009
Page 7 of 8
LADWP ETC (Line[1][D]), A&G Expenses (Line[1][E]) and Regulatory
Expenses (Line[1][F]).
January 1, 2011 TRR — Exhibit 2-F Line [2][G]: $1,275,480. This
figure is calculated by determining the sum of the costs for the SCE
MEAD ETC (Line[2][B]), the SCE Victorville-Lugo ETC (Line[2][C]), the
LADWP ETC (Line[2][D]), A&G Expenses (Line[2][E]) and Regulatory
Expenses (Line[2][F]).
January 1, 2012 TRR — Exhibit 2-F Line [3][G]: $1,346,520. This
figure is calculated by determining the sum of the costs for the SCE
MEAD ETC (Line[3][B]), the SCE Victorville-Lugo ETC (Line[3][C]), the
LADWP ETC (Line[3][D]), A&G Expenses (Line[3][E]) and Regulatory
Expenses (Line[3][F]).
Because the rates between August 1, 2009 and December 31, 2012 are fixed, as set
forth in the schedule above, the true -up and interest portions of the ETC Adjustment
clause for that period will be zero.
As discussed in the prepared testimony from The Brattle Group, beginning
January 1, 2013, the City's TRR will continue to be calculated based upon the then -
existing SCE HVECAC Rate, which will be passed -through to the City's TRR
pursuant to the ETC Adjustment Clause mechanism. In the period beyond 2013, the
Adjustment Clause will reflect the differences arising from Vernon's projected
charges under the SCE Victorville-Lugo ETC and/or the SCE Mead ETC and the
actual costs incurred by the City for those ETC in each year.
AMENDMENT OF THE TO TARIFF
At the direction of the City's staff, outside counsel has prepared, and the
City's staff has reviewed, an Amended TO Tariff, attached hereto as "Exhibit 7",
which will be filed with the FERC and the ISO upon approval by the Council. The
Amended TO Tariff is essentially the same as the City's current TO Tariff, except
that the tariff has been modified to reflect the addition of the ETC Adjustment Clause
mechanism.
Staff Report
TRR 2009
Page 8 of 8
RECOMMENDATIONS
1. Approve the Offer of Settlement filed by SCE in Docket Nos. ER08-
1343-000 and ER08-1353-000 in substantially the form attached
hereto as Exhibit 1".
2. Approve the new TRR of $944,348, as reflected in the attached
"Exhibit 3", to be effective August 1, 2009.
3. Approve the new TRR of $1,218,960, as reflected in the attached
"Exhibit 4", to be effective January 1, 2010.
4. Approve the new TRR of $1,275,480, as reflected in the attached
"Exhibit 5", to be effective January 1, 2011.
5. Approve the new TRR of $1,346,520, as reflected in the attached
"Exhibit 6", to be effective January 1, 2012.
6. Approve the Amended TO Tariff, including the addition of the ETC
Adjustment Clause mechanism, attached hereto as "Exhibit 7", to be
effective August 1, 2009:--� �61�
7. Approve the TRR calculated at any point hereafter pursuant to the
Amended TO Tariff, including the ETC Adjustment Clause, as the
appropriate Base TRR for the City of Vernon for the period then in
effect.
8. Approve the submission to the FERC and the ISO of the appropriate
TRRs and amended TO Tariff, and supporting documentation such as
the City Council Resolution approving the TRRs and amended TO
Tariff, this Staff Report, and the testimony of the Brattle Group in
substantially the form presented in "Exhibit 2" and with exhibits
submitted according to the advice of counsel.
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PROOF OF PUBLICATION
(2015.5 C.C.P.)
STATE OF CALIFORNIA,
COUNTY OF LOS ANGELES
I am a citizen of the United States and a resident
of the County aforementioned; I am over the age of
eighteen years, and not a party to or interested in
the above -entitled matter. I am the principal clerk
of the printer of
EASTERN GROUP PUBLICATIONS'
EASTSIDE SUN, MEXICAN AMERICAN SUN
NORTHEAST SUN, BELL GARDENS SUN
VERNON SUN, COMMERCE COMET,
CITYTERRACE COMET, MONTEBELLO COMET
MONTEREY PARK COMET,
E.L.A. BROOKLYN BELVEDERE COMET AND
WYVERNWOOD CHRONICLE,
newspapers of general circulation, printed and
published THURSDAYS in the County of Los
Angeles, and which newspaper has been adjudicated
a newspaper of general circulation by the Superior
Court of the County of Los Angeles, State of
California, under the
date of JUNE 21. 1966.
CASE NUMBER 884861;
that the notice, of which the annexed is a printed
copy (set in type not smaller than nonpareil), has
been published in each regular and entire issue of
said newspaper and not in any supplement thereof
on the following dates, to -wit:
JUNE 25,
all in the year 2009.
I certify (or declare) under penalty of perjury that I
the foregoing is true and correct.
Dated at LOS ANGELES, California,
this 251hday of JUNE. 2009.
CITY OF VERNON
Proof of Publication of
Notice of Public Hearing: Monday, July 6 2009
at 9:00 am ... To consider evidence to amend
Vernon's Transmission Owner Tariff and
establish Vd`non's`new ...
a
Signature