united states of america before the federal energy ... · first solar, inc., complainants, v....
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
California Wind Energy Association and First Solar, Inc., Complainants,
v. Southern California Edison Company and California Independent System Operator
Corporation, Respondents.
) ) ) ) ) )
Docket No. EL14-14-000
ANSWER OF SOUTHERN CALIFORNIA EDISON COMPANY
/Claire E. Torchia/ Claire E. Torchia Southern California Edison Company P.O. Box 800 Rosemead, CA 91770 (626) 302-6945 [email protected]
/Jennifer L. Key/ Jennifer L. Key Steptoe & Johnson LLP 1330 Connecticut Avenue, N.W. Washington, D.C. 20036 (202) 429-6746 [email protected]
Dated: January 17, 2014
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Table�of�Contents� I.� HISTORY AND BACKGROUND OF THE EKWRA PROJECT ......................... 4�
II.� POST-RECONFIGURATION, THE EKWRA FACILITIES ARE NON-INTEGRATED, LOCAL DISTRIBUTION FACILITIES THAT WERE PROPERLY RELEASED FROM CAISO’S OPERATIONAL CONTROL .......... 7�
III.� COMPLAINANTS’ ALLEGATIONS ARE WITHOUT MERIT ........................ 10�
A.� FERC Approval Was Not Required for the CAISO to Transfer Operational Control of the EKWRA Facilities ........................................... 10�
B.� SCE Applied the Appropriate Classification Criteria ................................. 12�
1.� Wholesale Usage Does Not Render a Facility Integrated Transmission .................................................................................... 13�
2.� The Mansfield Test Is an Appropriate Test for Determining Whether the Facilities Are Non-Integrated and Should Be Removed from CAISO Control ....................................................... 15�
3.� Complainants “Generator Tie” Arguments Are Misguided ............. 19�
C.� The Complainants’ Misapply Classification Precedent .............................. 23�
D.� Complainants’ Allegations Regarding Reliability Impacts Are Unfounded ................................................................................................... 27�
E.� SCE Made the Requisite Filings to Implement Reclassification and Did Not Subject Customers to After-the-Fact Rule Changes ..................... 32�
1.� SCE Made the Requisite Filings to Implement the Classification .................................................................................... 32�
2.� There Has Been No Change In the Ground Rules ........................... 34�
IV.� COMMUNICATIONS ........................................................................................... 37�
V.� CONCLUSION ...................................................................................................... 37�
Exhibit 1: List of EKWRA Facilities Exhibit 2: Excerpt of 2009 SCE Annual Transmission Reliability Assessment Exhibit 3: Affidavit of Jorge Chacon Exhibit 4: First Solar Development, Inc. Phase 2 Final Report Exhibit 5: CAISO Presentation on EKWRA (March 2010)
UNITED STATES OF AMERICA BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
California Wind Energy Association and First Solar, Inc., Complainants,
v. Southern California Edison Company and California Independent System Operator
Corporation, Respondents.
) ) ) ) ) )
Docket No. EL14-14-000
ANSWER OF SOUTHERN CALIFORNIA EDISON COMPANY
Pursuant to Rule 213 of the Rules of Practice and Procedure of the Federal Energy
Regulatory Commission (“Commission” or “FERC”) (18 C.F.R. §385.213 (2013)),
Southern California Edison Company (“SCE”) hereby submits this answer (“Answer”) to
the Complaint of California Wind Energy Association and First Solar, Inc. against
California Independent System Operator Corporation and Southern California Edison
Company Requesting Fast Track Processing (“Complaint”). In the Complaint, the
California Wind Energy Association (“CalWEA”) and First Solar, Inc. (“First Solar”)
(collectively, “Complainants”) allege that the recent release of operational control over
certain facilities in the East Kern Wind Resource Area (“EKWRA facilities”)1 by the
California Independent System Operator Corporation (“CAISO”) was not performed in
1 The Complainants refer to these facilities as the Antelope Valley facilities in their
Complaint. Note that SCE is using the term to refer to only those facilities designated for release, which are listed in a document attached as Exhibit 1.
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accordance with the Amended and Restated Transmission Control Agreement (“TCA”),2
violates Commission precedent, “may adversely impact the reliability and efficiency of
the CAISO grid, and will have unjust and unreasonable rate consequences for generators
affected by the transfer.”3
The Complaint is without merit. Contrary to the Complainants’ allegations, the
CAISO’s release of operational control of the EKWRA facilities fully complies with the
TCA, adheres with Commission policy and precedent, and provides for consistent
treatment of generators and other customers connected to the SCE distribution system; it
is therefore just and reasonable.
SCE understands that some generators may have concerns with the release of and
reclassification of the EKWRA facilities as non-integrated facilities due to the resulting
changes in the allocation of interconnection-related costs.4 All customers and potential
customers, however, have been on notice since 1996 that “facilities may have multiple
uses and that the initial classifications of facilities as transmission or local distribution are
subject to change as the uses of the facilities change.”5 Moreover, as early as 2010, SCE
2 Amended and Restated Transmission Control Agreement Among CAISO and
Transmission Owners, originally effective as of March 31, 1998. 3 Complaint at 2. 4 Throughout this Answer, SCE uses the term “reclassification” to refer to both its
determination that the relevant facilities are “non-integrated” and its determination that they are also “local distribution facilities.”
5 Pac. Gas and Elec. Co., 77 FERC ¶ 61.077 (1996); see also Cabazon Wind Partners, LLC v. S. Cal. Edison Co., 109 FERC ¶ 61,203 at P 18 (2004) (“Cabazon Hearing Order”), 113 FERC ¶ 63,009 (2005) (“Cabazon Initial Decision”), Opinion No. 490, 117 FERC ¶ 61,212 (2006) (“Cabazon Order”).
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began giving generators specific notice of the potential impacts of EKWRA, allowing
them to consider the cost allocation impacts of connecting to non-integrated facilities.
The EKWRA reclassification was not a choice for SCE. On the contrary, it was a
necessary step to ensure compliance with existing Commission policies, tariffs, and
regulations. SCE simply cannot choose to disregard FERC regulations and cannot put
itself in a position of picking financial winners and losers among its customers. SCE
must treat all of its customers in a non-discriminatory fashion. Indeed, as explained
below, SCE sought to reclassify the facilities at issue in this proceeding much in the same
way and on the same basis that it has classified facilities for the past 15 years of CAISO
operations – in a manner that implements FERC directives and ensures that all wholesale
and retail customers pay an appropriate share of system costs in accordance with FERC
and state cost allocation policies.
In reality, the Complainants’ real complaint does not lie with SCE. Rather, it is a
request for a full-scale change to established Commission rules regarding the
classification of facilities – change that will have significant and detrimental impacts and
is beyond the scope of this proceeding. The Commission should not make ad hoc
changes to its longstanding policy and precedent simply to benefit a small group of
generators that nonetheless chose to proceed with their projects despite being fully aware
of the risks of doing so.
For these reasons and others that are explained more fully below, the Commission
should dismiss the Complaint.
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I. HISTORY AND BACKGROUND OF THE EKWRA PROJECT
The Antelope-Bailey 66 kV system is owned by SCE. In 1998, the system was
transferred to the operational control of the CAISO. At that time, the system was
determined to be a part of SCE’s transmission network pursuant to the technical-
functional test, i.e., the seven-factor test referenced in Section 4.1.1(ii) of the TCA and
used to distinguish such network facilities from local distribution facilities, which remain
under SCE control.
In its 2009 SCE Annual Transmission Reliability Assessment provided to the
CAISO for purposes of its transmission planning process,6 SCE identified the EKWRA
Project to mitigate reliability issues. The EKWRA Project separates the Antelope-Bailey
66 kV system into three separate and distinct systems: (i) the northern system, which will
be served from the Windhub 66 kV Substation (a substation that is not part of the CAISO
grid and has never been under CAISO operational control), (ii) the southern system,
which will be served either from the Antelope 66 kV Substation or from the Bailey 66 kV
Substation, and (iii) the two 66 kV lines (and its substation termination facilities on each
end) connecting the Neenach Substation to the Antelope and Bailey Substations.7 The
6 Exhibit 2 is an excerpt of this assessment. 7 The two 66 kV lines connecting the Neenach Substation to the Antelope and Bailey
Substations are not being released from CAISO control and their classification is not at issue here. The EKWRA Project is described in somewhat more detail in the Affidavit of Jorge Chacon, attached as Exhibit 3 to this Answer and in Attachments A and C to the Complaint. For a diagram of the EKWRA reconfiguration, see Attachment 1-1 and 1-2 to Exhibit 3, which includes two color-coded simplified one-line diagrams illustrating the 500 and 220 kV system and Attachment 2-1 and 2-2 to Exhibit 3, which includes two color-coded one-line diagrams illustrating the 66 kV connections.
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EKWRA Project has the added benefit of creating capacity for further renewable energy
development. However, as a result of the EKWRA Project, the Antelope and Bailey 66
kV systems no longer operate in parallel with the 220 kV system.
Issues involving the EKWRA Project were discussed at a CAISO stakeholder
meeting in March 2010.8 In April 2010, the CAISO management approved the EKWRA
Project.9 After receiving the CAISO’s approval, SCE moved forward with the EKWRA
Project’s development and it and the CAISO immediately began to inform
interconnection customers of the potential impacts, including that use of, and
interconnection to, such facilities eventually would be governed by SCE’s Wholesale
Distribution Access Tariff (“WDAT”).
For example, in a Study Report (Exhibit 4) for one of First Solar’s generators,
issued in July, 2010, the CAISO explained as follows:
The study included the modeling of the East Kern Wind Resource Area (“EKWRA”) 66 kV reconfiguration project. This project was proposed by SCE in the CAISO 2010 Transmission Plan as a reliability project to address numerous reliability criteria violations in the existing Antelope-Bailey 66 kV network. This project was presented and recommended for approval by CAISO at the February 16, 2010 CAISO transmission plan stakeholder meeting. The EKWRA project was approved by CAISO on April 8, 2010. The EKWRA project has a proposed in-service date of December 2013. For additional details, see the group report.
8 East Kern Wind Resource Area (EKWRA) 66kV Reconfiguration, Stakeholder
Conference Call March 19, 2010 (CAISO power-point presentation attached as Exhibit 5). 9 See CAISO Board briefing documents, Briefing on 2010 Transmission Plan-Attachment
B, at 3 (listing the EKWRA Project), available at: http://www.caiso.com/Documents/Board%204)%20Briefing%20on%202010%20Transmission%20Plan and http://caiso.com/Documents/100325BriefingonTransmissionPlan-AttachmentB.pdf
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When EKWRA is constructed and energized, portions of the existing Antelope-Bailey 66 kV system, including the existing Del Sur 66 kV Substation, may operationally change from network facilities under CAISO control to SCE distribution facilities. This may also impact the classification of some of the upgrades specifically identified in this study as network upgrades at Del Sur Substation and result in those upgrades ultimately being classified as distribution upgrades.
Issues related to network versus non-network classification of facilities and EKWRA were discussed in a 2010 CAISO Transmission Plan stakeholder conference held on March 19, 2010.10
SCE and the CAISO also included information about the potential for reclassification in
generator interconnection agreement (“GIAs”) filings. For example, the CAISO
thoroughly explained the potential cost allocation impacts in its Transmittal Letter filed in
Docket No. ER12-2209 (at 7-8) if the reclassification occurred:
With respect to repayment of amounts advanced by the customer to fund the reclassified facilities, given that the ISO would no longer have an SGIA with the customer, it logically follows that any further repayment for such facilities would cease upon termination of the SGIA. There is no provision under the ISO tariff that provides for repayment of amounts advanced by an interconnection customer for distribution facilities, much less for facilities that are no longer part of the ISO controlled grid. This outcome is also consistent with the principle articulated in Order No. 2003 and other relevant Commission precedent that interconnection customers are eligible for repayment for costs advanced for network facilities because all users of the transmission system, not just the generator, derive a benefit from network facilities, even if those facilities would not have been installed but for the generator. On the other hand, those facilities that are radial in nature and solely benefit the generator are not eligible for reimbursement.
10 Emphasis added.
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If the facilities identified as network upgrades in the Blue Sky Ranch SGIA are re-classified as distribution facilities, it will be because they will operate in a radial fashion, and therefore, will no longer provide a network benefit to transmission customers. As a result, it would be inappropriate and unfair to expect the ISO’s transmission customers to bear the burden of funding repayment of such facilities.11
Although the Commission ordered the removal of language discussing the reclassification
from the GIAs, it also specifically rejected requests for exemptions from
reclassification.12
II. POST-RECONFIGURATION, THE EKWRA FACILITIES ARE NON-INTEGRATED, LOCAL DISTRIBUTION FACILITIES THAT WERE PROPERLY RELEASED FROM CAISO’S OPERATIONAL CONTROL
Section 4.7.1 of the TCA sets forth a clear path for relinquishment of facilities
from CAISO operational control. TCA Section 4.7.1 states, in pertinent part, that:
the CAISO may relinquish its Operational Control over any transmission lines and associated facilities constituting part of the CAISO Controlled Grid if, after consulting the Participating TOs owning or having Entitlements to them, the CAISO determines that it no longer requires to exercise Operational Control over them in order to meet its Balancing Authority Area responsibilities and they constitute . . . (ii) lines and associated facilities which, by reason of changes in the configuration of the CAISO Controlled Grid, should be classified as “local distribution” facilities in accordance with FERC's applicable technical and functional test, or should otherwise be excluded from the facilities subject to CAISO Operational Control consistent with FERC established criteria.13
11 Internal citations omitted. 12 E.g., S. Cal. Edison Co.,141 FERC ¶ 61,100 at P 28 (2012) (“Silverado”). 13 TCA Sections 4.7.1 (i) and (iii) are not relevant here.
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TCA Section 4.7.2 provides:
Before relinquishing Operational Control over any transmission lines or associated facilities pursuant to section 4.7.1, the CAISO shall inform the public through the CAISO Website of its intention to do so and of the basis for its determination pursuant to Section 4.7.1. The CAISO shall give interested parties not less than 45 days within which to submit written objections to the proposed removal of such lines or facilities from the CAISO’s Operational Control. If the CAISO cannot resolve any timely objections to the satisfaction of the objecting parties and the Participating TOs owning or having Entitlements to the lines and facilities, such parties, Participating TOs, or the CAISO may refer any disputes for resolution pursuant to the CAISO ADR Procedures in Section 13 of the CAISO Tariff. Alternatively, the CAISO may apply to FERC for its approval of the CAISO’s proposal.
SCE analyzed the EKWRA facilities and determined that, as a result of the
EKWRA Project, the facilities operate radially, are no longer integrated with the
transmission system, and can only be classified as non-integrated, i.e., local distribution
facilities.14 As such, on August 26, 2013, pursuant to TCA Section 4.7.1, SCE formally
asked the CAISO to release the EKWRA facilities from CAISO operational control as of
December 15, 2013 due to a change in the configuration of the EKWRA facilities
resulting from the EKWRA Project. SCE provided an analysis to the CAISO in the form
of the white paper, which is attached to the Complaint as Attachment C (“White Paper”).
This White Paper described SCE’s analysis of why the facilities at issue would not
be integrated transmission after completion of the EKWRA Project. In its analysis, SCE
14 See Exhibit 3, Chacon Affidavit.
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clearly demonstrated that upon reconfiguration, pursuant to both the seven-factor and
Mansfield tests, the separated systems became non-integrated, local distribution facilities.
Pursuant to the TCA, on September 13, 2013 (i.e., before relinquishing operational
control), the CAISO issued a market notice and posted it on its website, informing the
public of its intent to relinquish operational control of the EKWRA facilities.15 In that
market notice, CAISO indicated that interested parties would have 45 days, until October
29, 2013, to submit written objections to the proposed removal of such lines or facilities
from the CAISO’s operational control. The CAISO received timely comments from four
parties, including one set of comments from Complainants. On November 18, 2013, the
CAISO held a meeting among interested stakeholders in an attempt to resolve any timely
objections. At that meeting, the CAISO provided copies of the White Paper to meeting
participants.
On November 26, 2013, the CAISO issued a letter on its website,16 stating that the
CAISO “no longer requires to exercise Operational Control over [the EKWRA facilities]
in order to meet its Balancing Authority Area responsibilities” and does not object to
SCE’s assertion that the EKWRA facilities should be classified as “local distribution” in
accordance with FERC’s technical and functional tests. As discussed in Section III(C),
that decision is rational and consistent with CAISO policy and procedure, as well as
15 See CAISO Market Notice re ISO Intention to Release Transmission Lines and
Associated Facilities from operational control, dated September 13, 2013, available at: http://www.caiso.com/Documents/ISO_Intention-ReleaseTransmissionLines-AssociatedFacilities-OperationalControlSep13_2013.htm
16 Complaint, Att. B.
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applicable FERC precedent. In the November 26 letter, the CAISO also explained that it
was unable to resolve any timely objections to the satisfaction of the objecting parties and
SCE. No party initiated dispute resolution. Moreover, although Section 4.7.2 of the
TCA says that “CAISO may apply to FERC for its approval of the CAISO’s proposal,” it
does not go so far as to require CAISO to do.17 SCE thus has done everything that the
TCA procedurally requires and Complainants have failed to identify a single procedure
set forth in Sections 4.7.1 and 4.7.2 that SCE neglected or violated.
III. COMPLAINANTS’ ALLEGATIONS ARE WITHOUT MERIT
Complainants raise a host of specious arguments attacking the CAISO’s and
SCE’s implementation of the process described above. These arguments are readily
dismissed either because they rest on indisputably erroneous facts and misunderstandings
of tariff language or fail to acknowledge clear FERC precedent. The response below is
intended to meet the requirement set forth in 18 C.F.R. Section 385.213(b)(2)(i) to admit
or deny each allegation by addressing all material allegations.
A. FERC Approval Was Not Required for the CAISO to Transfer Operational Control of the EKWRA Facilities
The Complainants argue that “the transfer of the Antelope Valley 66 kV facilities
from the CAISO Tariff to the Edison WDAT is subject to Commission review under the
17 With regard to another reclassification of SCE facilities (Devers-Mirage), several
parties submitted comments protesting the CAISO’s intention to release control. There, no party filed for dispute resolution, the CAISO did not go to FERC, and the facilities were reclassified without anyone, including Complainants, ever challenging this approach as being inconsistent with the TCA.
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plain terms of the TCA.”18 Complainants likewise assert that “CAISO has both a
contractual and a regulatory obligation to seek Commission approval to transfer control
over the facilities at issue here.”19
First, under the plain terms of the TCA, FERC approval is not required prior to
CAISO relinquishing operational control. The Commission approved the TCA, which
includes precatory language that the CAISO may seek FERC approval in the event of a
dispute, but does not require the CAISO to do so. Moreover, the TCA requires no
Federal Power Act (“FPA”) Section 205 filing with regards to change in facilities under
CAISO operational control and Atlantic City Elec. Co. v. FERC, 295 F.3d 1 (D.C. Cir.
2002) dictates that a FPA Section 203 filing is not required. Finally, as the Complaint
shows, all parties retain their remedies to petition FERC should they disagree with the
CAISO decision about the release of facilities from its operational control.
Complainants also accuse SCE of attempting to make unilateral ratemaking
changes without seeking Commission approval.20 That accusation is untrue. Wholesale
generators no longer connected to CAISO facilities must convert their three-party CAISO
Tariff GIAs into WDAT GIAs and enter into Wholesale Distribution Service Agreements
(“WDSAs”). SCE knows such agreements must be filed under FPA Section 205 and as
18 Complaint at 4. 19 Complaint at 13 n.20. 20 Complaint at 5, 31-32.
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discussed infra has made requisite filings here, just as it has done previously in near-
identical circumstances.21
B. SCE Applied the Appropriate Classification Criteria
Section 4.7.1 of the TCA allows the CAISO to release operational control of
facilities that, among other things, “should be classified as ‘local distribution’ facilities in
accordance with the FERC’s applicable technical and functional test,” or “should
otherwise be excluded from the facilities subject to CAISO operational control consistent
with FERC established criteria.” The technical test refers to the seven-factor test set forth
in FERC Order 888.22 Other case law, including the Cabazon and Whitewater23 cases,
indicates that the Mansfield test also can be used to determine if facilities are non-
integrated.24 Accordingly, SCE applied both tests, although the impact of a finding that
21 SCE previously implemented the change in control and reclassification of its Devers-
Mirage facilities in a similar manner. For example, in Docket No. ER13-1804, SCE replaced an existing GIA with a WDAT GIA and filed a WDSA for an existing generator previously connected to a CAISO grid facility that was reclassified as a result of the Devers-Mirage project.
22 The seven-factor test is the technical portion of the “technical and functional test” referred to in TCA Section 4.7.1. Functionally, the EKWRA facilities are used to serve both retail and wholesale customers. Thus, the seven-factor test is used to determine jurisdiction over the facilities (as opposed to jurisdiction over the service provided over the facilities).
23 S. Cal. Edison Co., 100 FERC ¶ 61,219 at P 25 (2002) ((“Whitewater First Hearing Order”), 107 FERC ¶ 61,017 (2004) (“Whitewater Second Hearing Order”)), 111 FERC ¶ 63,032 (2005) (“Whitewater Initial Decision”), Opinion No. 487, 117 FERC ¶ 61,103 at P 72 (2006) (“Whitewater Order”)).
24 Indeed, SCE’s hesitancy to rely only on the seven-factor test stems, in part, from concern that FERC could take the position that such test cannot be used for classification. In the Cabazon Initial Decision (at P 177), the Presiding Administrative Law Judge (“ALJ”) relied on FERC precedent to reject SCE’s use of the seven-factor test to classify facilities. The Commission Staff continues to insist that the seven-factor not be used to determine how to classify facilities. In a recent Initial Decision, the ALJ noted that Staff argued that “the seven factor test is a means for determining jurisdiction, not classification, of facilities.” Sw. Power
(Continued…)
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the facilities are non-integrated is the very same as a finding that they are local
distribution – the result is that the facilities are subject to the WDAT when used by
wholesale customers.
1. Wholesale Usage Does Not Render a Facility Integrated Transmission
To get around having Mansfield or the seven-factor test apply, Complainants
assert that the EKWRA facilities cannot be “local distribution” facilities, because they
“are, and will remain, functional wholesale facilities.”25 They claim that “Edison
concedes that none of the lines will serve an exclusive state jurisdictional local
distribution function because Edison intends to transfer all of the lines to its FERC-
jurisdictional WDAT which covers ‘wholesale distribution’ service.”26 According to the
Complainants, placing the reconfigured EKWRA facilities under the WDAT – a FERC
jurisdictional tariff – “makes them ‘functional wholesale’ facilities, not state
jurisdictional ‘local distribution’ facilities.”27 This argument is flawed.
Complainants effectively are arguing that because the facilities at issue are used by
some wholesale customers, as evidenced by the fact that wholesale service over them will
be provided under the WDAT, the facilities cannot be released from the CAISO’s
operational control. But the entire purpose of the WDAT is to provide wholesale service
Pool, Inc., 143 FERC ¶ 63,003 at P 85 (2013) (“SPP”). Notably, the ALJ in the SPP case found the seven-factor test quite useful, ruling that it may be applied to classify facilities. Id. at P 223.
25 Complaint at 21 (emphasis added). 26 Id. 27 Id. at 3-4.
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over facilities not under the CAISO’s operational control and not otherwise subject to
FERC jurisdiction, i.e., local distribution facilities. A facility cannot be subject to the
WDAT and be under the CAISO’s operational control. The WDAT would not be
necessary if all facilities used for wholesale purposes were under CAISO control.
Complainants are essentially claiming that any wholesale usage requires that a
facility be classified as network transmission. That, however, is contrary to settled law.
In one of its earliest orders describing the WDAT, the Commission explained that the
WDAT is “limited to the use by wholesale purchasers of transmission service over
facilities identified as local distribution.”28 The D.C. Circuit has made it absolutely clear
that local distribution facilities were not limited to those used exclusively by retail
customers, arguing that an interpretation of the statute “to exclude only ‘facilities used
exclusively in local distribution . . . [w]ould eviscerate state jurisdiction over numerous
local facilities, in direct contravention of Congress’ intent.”29 Thus, facilities used by
wholesale customers may properly be labeled local distribution facilities:
the Commission may regulate the entire transmission component (rates, terms and conditions) of the wholesale transaction – whether the facilities used to transmit are labeled “transmission” or “local distribution”– it may not
28 San Diego Gas & Elec. Co., 82 FERC ¶ 61,324 at 62,270 (1998) (emphasis added)
(“San Diego”). For a brief period of time, the Commission reversed course and argued that local distribution facilities were those used exclusively by retail customers. The D.C. Circuit, however, rejected this interpretation. Detroit Edison Co. v. FERC, 334 F.3d 48 (D.C. Cir. 2003) (“Detroit Edison”).
29 Detroit Edison, 334 F.3d at 54 (emphasis added).
15
regulate the ‘local distribution’ facility itself, which remains state jurisdictional.30
The fact that the facilities are used by wholesale customers has absolutely no bearing on
the question posed here – whether the facilities belong under CAISO operational control.
In sum, under the TCA, non-integrated and/or local distribution facilities do not belong
under CAISO operational control regardless of whether they are used by wholesale
customers and that is the reason that the WDAT exists.
2. The Mansfield Test Is an Appropriate Test for Determining Whether the Facilities Are Non-Integrated and Should Be Removed from CAISO Control
Complainants criticize SCE for relying on Mansfield to justify its reclassification
of the EKWRA facilities because the Mansfield decision post-dated the TCA and the
TCA was never amended to import that test or to make “integration” a factor in the
analysis.31 Complainants argue that SCE’s reliance on this test, which they state was “not
provided for in the TCA,” renders the reclassification plan “facially invalid.”32 First and
30 Standardization of Generator Interconnection Agreements and Procedures, Order
2003-C, FERC Stats. & Regs. ¶ 31,190 at P 53 (2005), subsequent history omitted. See also Cal. Pac. Elec. Co., LLC, 133 FERC ¶ 61,018 at P 48 (2010) (“CalPeco”) (“the Commission can exercise jurisdiction over the use of a facility for a Commission-jurisdictional service without claiming jurisdiction over those facilities for all purposes.”). The Commission sometimes prefers not to use the term “local distribution” to describe distribution facilities used to provide service to wholesale customers (using terms such as “non-integrated facilities”). Indeed, in orders issued years after Detroit Edison, the Commission explained that instead of using the term “local distribution facilities,” it would call distribution facilities used by wholesale customers “non-integrated facilities.” E.g., Cabazon Order at P 4 n.5.
31 Complaint at 17. 32 Id.
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foremost, SCE relied on the seven-factor test (see White Paper) as well as on the
Mansfield test and reached the same determination, rendering this argument moot.
Second, the fact that the Mansfield test was developed by the Commission after
the TCA was drafted, does not preclude SCE or the Commission from relying on it to
determine what facilities should be excluded from the CAISO operational control. TCA
Section 4.7.1(ii) allows for exclusion based on the seven-factor test finding of local
distribution or based on other “FERC established criteria.” Certainly, the Mansfield test,
which was established by the Commission and used by FERC to determine if a facility is
integrated, would qualify as other “FERC established criteria.” There is no reason to
interpret “FERC established criteria” so narrowly as to include only criteria in existence
prior to the TCA.
Complainants argue that the Mansfield test “does not assess whether facilities
should be classified as local distribution facilities as opposed to transmission facilities”33
and assert that, instead, “[t]he Mansfield test addresses the question whether facilities
form part of an integrated network for cost allocation purposes – which is a ratemaking
question, not a state/federal jurisdictional question.”34 But SCE did not apply the
Mansfield test for the purpose of determining state or federal jurisdiction over the
facilities; as already explained, the test was applied to determine if the CAISO should
release the facilities because they are not integrated under FERC criteria. In fact, SCE
33 Complaint, Att. D at 1 (hereinafter, “Shirmohammadi Affidavit”). 34 Id.
17
agrees with Complainants that the purpose of the Mansfield test is to determine
integration for cost allocation purposes. It is for that very reason that it is appropriate to
use the Mansfield test as a substitute for, or in conjunction with, the seven-factor test to
determine whether facilities should be included or excluded from CAISO operational
control.
The CAISO Tariff, through a series of defined terms,35 provides that the costs of
facilities under the CAISO’s operational control are rolled into the rates of transmission
customers, while the costs of excluded facilities are not. Underlying this basic rate
structure was a Commission policy to prevent cross-subsidization – costs of integrated
network facilities, which benefit the entire system, are spread across all wholesale and
retail customers. As to local distribution facilities, the Commission allocates the costs of
such non-integrated facilities to those wholesale customers that directly benefit from
them,36 while state commissions may allocate the costs of such facilities to their retail
customers. A primary purpose of Sections 4.1 and 4.7 of the TCA is to distinguish
facilities that benefit all FERC-jurisdictional transmission customers from those that do
not. Given that, as Complainants admit, “the Mansfield test addresses the question
35 See CAISO Tariff, App. A, Definitions of Transmission Revenue Requirement, Regional Transmission Revenue Requirement, Local Transmission Revenue Requirement, and Operational Control; see also CAISO Tariff Appendix F, Schedule 3.
36 See Allegheny Power, 122 FERC ¶ 61,160 at P 23 (2008) (“Briefly, under Commission precedent, when facilities are integrated and thus provide system-wide benefits, facilities’ costs generally are rolled-in and charged to all customers served. However, when facilities are not integrated and thus do not provide system-wide benefits, direct assignment typically is used to allocate costs to those customers who use the facilities”) (internal citation omitted); see also id. at P 32 (allowing for partial direct assignment of costs “to avoid the creation of rate subsidies (paid by customers using only non-integrated facilities).”).
18
whether facilities form part of an integrated network for cost allocation purposes” it is
fully appropriate to use the test to determine what facilities are integrated network
facilities that should be under CAISO operational control, thereby allowing costs of those
facilities to be rolled into rates. Indeed, the Commission applied the Mansfield test in
Cabazon and Whitewater to determine if facilities were appropriate to be classified as
integrated network transmission and, if so, to order them placed under CAISO control.37
In Cabazon, the Commission upheld the presiding judge’s determination “that the
facilities are not integrated because they do not meet the Commission’s five-factor test
for network integration under Mansfield.”38 Likewise, in Whitewater, the Commission
found that Mansfield applied, stating:
Accordingly, we will apply the Mansfield factors to determine whether the Venwind Line is part of the integrated grid. Applying the five factors of Mansfield is appropriate in this case because, as SCE points out, the factors were used in Mansfield to analyze whether radial lines not operated in parallel with the transmission system should nonetheless be classified as network facilities and thus rolled-in. Similarly, the Venwind Line is a radial line, as the presiding judge found in the Initial Decision. Thus, we find that application of the Mansfield factors is a reasonable approach to analyzing the Venwind Line.39
Complainants attempt to distinguish the EKWRA facilities and argue that
Mansfield does not apply to them because the EKWRA Project involves relinquishment
37 Although most of the facilities at issue in the two cases were found not to be integrated,
certain breakers were reclassified as integrated transmission and placed under CAISO control. 38 Cabazon Order at P 14. 39 Whitewater Order at P 72 (internal footnotes omitted).
19
of “operational control over an array of existing facilities that serve many different
generators and retail customers.”40 However, Complainants cite no precedent to support
their contention that Mansfield is inapplicable to relinquishment of operational control
over an array of facilities such as the EKWRA facilities.41 In fact, the Commission has
applied Mansfield to an array of existing facilities.42
3. Complainants “Generator Tie” Arguments Are Misguided
Complainants argue that SCE “has failed to show that any of the Antelope Valley
lines will be directly assignable radial generator tie lines after the EKWRA conversion”
and that none of the facilities proposed to be transferred from CAISO and placed under
SCE’s WDAT are radial lines needed to interconnect generators.43 These “generation
tie” arguments are rendered moot by the fact that SCE is not basing its determination that
the EKWRA facilities should be reclassified on the TCA Section 4.7.1(i) test for
generation ties. What SCE has argued is that sometimes local distribution facilities are so
loaded with generation and that load is so sparse that they effectively function like a
40 Shirmohammadi Affidavit at 1 (emphasis added). 41 SCE notes that the Commission has declined to use the Mansfield test to determine if
low-voltage (i.e., 12 kV and below) distribution systems are integrated. In Pinnacle West Capital Corp., 133 FERC ¶ 61,034 at P 19 (2010) (“Pinnacle West”), FERC held that “Mansfield has traditionally been applied as a test for the integration of discrete transmission or subtransmission facilities, generally involving the integrity of the bulk power system.” In effect, the Commission held that the Mansfield test should be applied to subtransmission-voltage, but not distribution-voltage facilities. In a case of the same vintage, CalPeco, involving the classification of an entire distribution system, the Commission applied the seven-factor test rather than Mansfield.
42 E.g., Allegheny Power, 122 FERC ¶ 61,160 at P 29 (holding that “[b]ased on a review of the record and considering the five Mansfield factors,” the subtransmission facilities associated with thirteen delivery points are integrated with subtransmission networks).
43 Complaint at 24-25.
20
generation tie line under certain conditions. Even though Complainants’ generation tie
arguments are moot, SCE will respond to Complainants’ points raised within the context
of their generation tie arguments – that the facilities meet NTEC’s44 “any degree of
integration”45 test or the “at or beyond” test.46 As explained below, both such tests are
unhelpful.
First, the Commission has made quite clear that the “any degree of integration”
test and the Mansfield test are not to be applied to the same sorts of facilities. Pursuant to
NTEC, in order to be reviewed under this “any degree of integration” test, a facility must
not be radial in nature.47 Some of the facilities under review in NTEC operated in-line
with or parallel to the transmission facilities and were therefore subjected to the “any
degree of integration” test.48 Likewise, in Whitewater, the Commission agreed with SCE
that Mansfield, rather than NTEC, is appropriate “to analyze whether radial lines not
operated in parallel with the transmission system should nonetheless be classified as
network facilities and thus rolled-in.”49 As was the case in Whitewater, the EKWRA
facilities are no longer operated in parallel to SCE’s transmission system as a result of the
44 Northeast Texas Elec. Coop., 100 FERC ¶ 63,033 (2002) (“NTEC Initial Decision”),
108 FERC ¶ 61,084 at P 19 (2004) (“NTEC”), reh’g denied, 111 FERC ¶ 61,189 (2005) (“NTEC Rehearing”).
45 Complaint at 25. 46 Id. at 26. 47 See NTEC at P 13 n.29 (citing NTEC Initial Decision at P 35 & n.59 for proposition
that “Mansfield concerned facilities located on radial lines that were not pool transmission facilities and did not provide parallel capability to the transmission grid.”)
48 NTEC Rehearing at P 6. 49 See Whitewater Order at P 65 and P 72.
21
EKWRA Project, and now operate radially to the transmission system.50 Accordingly,
application of Mansfield rather than NTEC is clearly appropriate.
Second, a literal application of the “any degree of integration” test is particularly
unsuited to apply to facilities with increasing levels of distribution-connected generation.
If certain FERC decisions, namely those that indicate that failure of even one Mansfield
factor results in a finding of integration, are applied literally in an era of ever increasing
distribution-connected generation, the result would eviscerate state jurisdiction over
distribution. Under a literal application of the “any degree of integration” test, for a new
housing development, where all houses are equipped with solar panels, the entire
neighborhood’s distribution system would be integrated transmission. In sum, the “any
degree of integration” test is particularly unhelpful in classifying facilities that have the
attributes of local distribution facilities under the seven-factor test, but are used by
generators to transmit their energy to market.51
The Complainants also suggest that the Commission only allows direct assignment
to the customer of facilities if those facilities are on the generator’s side of the point of
interconnection with the grid and that the EKWRA facilities are at or beyond the point of
50 See Affidavit of Jorge Chacon at PP 15-26. 51 In effect, the increase in generation connected to distribution systems, particularly in
rural, low-load areas may result in what are local distribution facilities functioning much more like generation ties. That is, power flows in one direction, but due to the degree of distribution-connected generation on the system, the power flow is sometimes or always toward the grid. But this does not mean that all wholesale transmission customers benefit from such distribution facilities and should bear their costs.
22
interconnection with various generators.52 Complainants further assert that “[h]ere, none
of the Antelope Valley facilities proposed for the transfer to the Edison WDAT are on the
‘generator’s side of the point of interconnection.’”53 The obvious flaw in this argument is
that it does not address the situation often presented with the rise of distribution-
connected generation – where the point of interconnection (“POI”) is on the local
distribution system, i.e., on a non-integrated facility. The applicability of the “at or
beyond” test to an interconnection to SCE’s distribution system was resolved in
Whitewater in SCE’s favor. There, the Commission explained that:
for generator interconnections, there are only two categories of facilities: interconnection facilities and network upgrades. Here, however, the facilities may belong to a third category: they may be upgrades to non-integrated facilities that can be directly assigned to the generator.54
The Commission made it clear that where this third category exists, the “at or beyond”
test is unhelpful to distinguish between non-integrated facilities and network upgrades.55
In that case, the Commission instead applied Mansfield.
Although the “at or beyond” test is not relevant here, as this case does not involve
interconnection-related upgrades, the very existence of the term “Distribution Upgrades,”
which is defined by Order No. 2003 to be “modifications, and upgrades … at or beyond
52 Complaint at 26; Shirmohammadi Affidavit at 2. 53 Complaint at 26. 54 Whitewater Order at PP 60, 73. 55 See also S. Cal. Edison Co., 128 FERC ¶ 63,003 at P 46 (2009), aff’d Opinion No. 390,
139 FERC ¶ 61,185 (2012) (“Green Borders”).
23
the Point of Interconnection,” demonstrates that the Commission now recognizes that the
“at or beyond” test applies where the POI is located within the integrated grid.
C. The Complainants’ Misapply Classification Precedent
Although they largely rely on erroneous classification standards, the Complainants
also address Mansfield and rely heavily on an argument that bidirectional flow of certain
of the EKWRA Project lines show that these facilities fail Mansfield factor 2.56
However, as Trial Staff pointed out (and the Commission agreed) in Whitewater,
Mansfield factor 2 does not test simply whether there is bidirectional flow on the line, but
rather whether the transmission provider relies on that bidirectional flow to serve its own
load or the load of its other transmission customers.57 Trial Staff concluded (and the
Commission agreed) that one of disputed facilities in Whitewater (the Devers-Zanja Line)
– which normally performed a dual function as a radial line carrying power to the
Banning Substation and as a large generation interconnection facility carrying power
from the Windpark generators to the Devers Substation – was not integrated. On the
Antelope and Bailey systems, the prevailing flow will be from the transmission network
to local load. On the newly-configured Windhub system, the prevailing flow will be
from the transmission network to local load when local load exceeds the amount of
generation produced, and when generation production exceeds local load, flow over these
lines will reverse. This situation is nearly identical to that presented in Whitewater, and
56 Shirmohammadi Affidavit at 5. Mansfield factor 2 addresses whether energy flows only in one direction, from the transmission system to the customer over the facilities, or in both directions.
57 Whitewater Order at PP 91, 92.
24
as a result, the Commission should determine that these facilities are not integrated
transmission facilities.
Indeed, many of SCE’s distribution facilities are subject to bidirectional flow
under certain operating conditions, but this does not mean that these facilities are part of
the integrated transmission network. SCE has a significant amount of generation
interconnected to its 115 kV, 66 kV, and 33 kV systems. Some of these systems have
more generation connected to them than load at all times. Some of these systems have
more generation than load during some parts of the day or year and, at other times, more
load than generation. This occurrence is increasingly common on SCE’s distribution
system because SCE has seen a large increase in the number of wholesale renewable
generators connected to its distribution system. However, in these instances, the normal
and primary operating flow is radial in nature.58
Complainants also focus on whether the three new systems will be looped, arguing
that there will be loops within the Antelope and Windhub systems59 and that “Antelope,
Bailey and Windhub 66 kV facilities are integrated with each other via automatic
switches that can close in a contingency.”60 As to the first issue, the existence of some
remaining loops within the Antelope system and Windhub system does not render it
integrated transmission. For example, in Pinnacle West, although the FERC indicated
58 Chacon Affidavit at PP 17-24. 59 Shirmohammadi Affidavit at 5-6. 60 Complaint at 29.
25
that there was “at least minimal looping of the 69 kV and 12 kV lines,”61 such loops did
not cause FERC to find the facilities integrated transmission. Such distribution or
subtransmission loops, which are consistent with SCE’s distribution planning practices,
are common on other SCE 66 kV facilities classified as distribution, as explained in detail
in the Affidavit of Jorge Chacon.62
As to the second issue, Mr. Shirmohammadi argues that closing open breakers will
create a closed loop, stating:
there will remain numerous normally open switches available on the Antelope 66 kV system that can be used to create additional loops and new power flow routes within this 66 kV system and also between this 66 kV system and the other two 66 kV systems, (Bailey 66 kV system and Windhub 66 kV system described below), hence changing the direction of flows on all three 66 kV systems’ facilities under numerous additional conditions. These same normally open switches can also be used, if needed, to create loops through the bulk transmission system to address certain reliability concerns of the CAISO controlled grid in the area.63
Actually, the reconfigured systems are not planned or designed to form looped or parallel
paths between the local distribution systems, as doing so would create the thermal
overload and reliability problems that the EKWRA Project is being implemented to
address. Moreover, the situation described does not render facilities integrated as
demonstrated by prior cases involving SCE’s system. In the Whitewater case, one of the
facilities at issue was normally operated with the breakers open, preventing the formation
61 Pinnacle West Capital Corp., 131 FERC ¶ 61,143 at P 33 (2010). 62 Chacon Aff. at PP 15-16. 63 Shirmohammadi Affidavit at 5.
26
of a loop; however, there were situations where one set of breakers would be closed in
certain emergency situations and the other breakers automatically opened.64 Despite
moments where both breakers could be closed, the Commission held that this
circumstance did not make those facilities network.65 The Commission has explained
that “occasional loop flow does not compel the conclusion that a facility is integrated
with the transmission network.”66
In Cabazon, the Commission similarly rejected this concept that switches that are
open in abnormal circumstances such as an emergency would result in a “looped” or
integrated system.67 The Presiding ALJ found credible SCE’s definition of the term
“looped facilities” – “facilities [that] form a circular path for power flows when in their
normal operating configuration.”68 She rejected the definition proposed by the
generator’s witness: “that a primary path and a backup path form a physical loop such
64 Trial Staff explained: “Specifically, the Devers-Banning-Zanja Line under both
normal operating conditions and emergency conditions operates on a radial configuration. Contrary to Whitewater’s witness Russell, the Devers-Banning-Zanja Line never operates as a looped line, because of the breakers at Banning. In the event of a power flow interruption, the normally closed breaker connecting Banning to the Devers-Banning-Zanja Line opens and the normally open breaker closes to permit power to flow to Banning from the Garnet-Maraschino Line. Therefore, there is never a looped connection of the Devers-Banning-Zanja Line.” Whitewater Initial Decision at P 26.
65 Whitewater Order at P 87. 66 Florida Municipal Power Agency v. Florida Power & Light Co., 74 FERC ¶ 61,006 at
61,010 n.129 (1996), reh’g denied, 96 FERC ¶ 61,130 (2001), aff’d, 315 F.3d 362 (D.C. Cir. 2003).
67 Cabazon Initial Decision at PP 182-83 (the ALJ found for example that “with the exception of a possible momentary overlap of breaker closure, that is never scheduled to occur, the disputed facilities were never, and may never be, part of a loop.”).
68 Id. at P 183 n.50 (emphasis added).
27
that power can be quickly routed to a load and/or from a generator over the backup path
in the event that the primary path is disabled.”69
Similarly, the Bulk Electric System rulemaking included an exclusion for radial
systems connected by normally open switches because “to write the definition to include
radial systems connected by a normally open switch, with the caveat that entities can
request an exception, would result in a flood of exception requests.”70
D. Complainants’ Allegations Regarding Reliability Impacts Are Unfounded
Complainants raise concerns regarding the CAISO’s ability to abide by North
American Electric Reliability Corporation (“NERC”)’s balancing-related “Reliability
Standards” and the California Public Utilities Commission (“CPUC”)/CAISO-developed
Resource Adequacy (“RA”) requirements if the EKWRA facilities are released.
Complainants cannot explain how the release of operational control would impair the
CAISO’s ability to meet the balancing Reliability Standards. Generation interconnected
to SCE’s distribution facilities still remains in the CAISO balancing authority area
(“BAA”) both electrically and physically. The change in operational control has no
impact on the CAISO dispatch authority over generation. Generators larger than 1 MW
69 Id. at P 13. 70 Order No. 773, Revisions to Electric Reliability Organization Definition and Rules of
Procedure, 141 FERC ¶ 61,236 at P 173 (2012).
28
interconnected to the distribution system are subject to CAISO control under Section 4.6
of the CAISO Tariff.71 Section 7.7.2.3 describes the CAISO’s control over generation:
All Generating Units and System Units that are owned or controlled by a Participating Generator are (without limitation to the CAISO’s other rights under this CAISO Tariff) subject to control by the CAISO during a System Emergency and in circumstances in which the CAISO considers that a System Emergency is imminent or threatened. The CAISO shall, subject to this Section 7, have the authority to instruct a Participating Generator to bring its Generating Unit on-line, off-line, or increase or curtail the output of the Generating Unit and to alter scheduled deliveries of Energy and Ancillary Services into or out of the CAISO Controlled Grid, if such an instruction is reasonably necessary to prevent an imminent or threatened System Emergency or to retain Operational Control over the CAISO Controlled Grid during an actual System Emergency. . . . Each QF subject to an Existing QF Contract and not subject to a PGA or Net Scheduled PGA will make reasonable efforts to comply with the CAISO’s instructions during a System Emergency without penalty for failure to do so.
If generation is interconnected to the EKWRA facilities today and can be used for
balancing, reserves, and frequency purposes, such generation can still be used in that
fashion after CAISO’s release of operational control. The Complainants provide no
proof to the contrary; nor could they.72 Generation interconnected to distribution
71 CAISO Tariff Section 4.6.3.2 provides an exemption only for certain under 1 MW
generators: “A Generator with a Generating Unit directly connected to a Distribution System will be exempt from compliance with this Section 4.6 and Section 10.1.3 in relation to that Generating Unit provided that (i) the rated capacity of the Generating Unit is less than one (1) MW, and (ii) the Generator does not use the Generating Unit to participate in the CAISO Markets.”
72 That said, most EKWRA facility-connected generation is variable and/or otherwise incapable of ramping, so it is not likely to be used to ensure compliance with the identified BAA requirements.
29
facilities can be used for such purposes, to the extent otherwise eligible to provide such
services under the CAISO Tariff.
Complainants also fail to explain how release of operational control could impact
in any way a generator’s RA status. RA status has nothing at all to do with whether a
generator is connected to transmission or distribution; rather, it has to do with
“deliverability” status under the CAISO Tariff, which can be attained by generators
interconnected to the distribution system.73
Complainants criticize SCE’s WDAT congestion management protocols and
scheduling practices as being inconsistent with CAISO’s74 and also assert that SCE “has
no congestion management protocols at all and that CAISO recently filed a plan to
implement 15-minute transmission scheduling” “[w]hile Edison schedules service
hourly.”75 As to the scheduling issue, there is no scheduling under the WDAT – hourly,
15-minute, or otherwise. This fact was explained nearly 15 years ago, in the Initial
Decision on the terms of the WDAT, which decision was summarily affirmed in relevant
part by the Commission:
Wholesale distribution service is very different in nature from transmission service, . . . . Wholesale distribution customers do not schedule WD[A]T service. . . . In direct contrast to
73 See Cal. Indep. Sys. Operator Corp., 144 FERC ¶ 61,189 at PP 37, 40 (2013). 74 Complaint at 19. 75 Id. at 18.
30
transmission service, wholesale customers request service once, and only once.76
Because the CAISO runs the only scheduling regime, there is no WDAT regime with
which the CAISO regime could conflict.77
SCE’s WDAT has no bid-based congestion management scheme, because it
simply does not need one. In the WDAT Initial Decision, the Presiding ALJ explained
that the distribution system is a congestion-free system. He noted that service “requests
are always honored, either through the allocation to the customer of available distribution
capacity, or through the customer-funded construction of new distribution facilities.”78
Simply put, under normal post-EKWRA operating conditions there is no competition
among any customers to use the distribution system. Complainants apparently are
claiming that SCE’s WDAT regime, which under normal operation distribution system
conditions ensures that distribution-interconnected generation is always available for the
CAISO to dispatch, somehow hampers CAISO reliability. This argument is illogical.
Under the existing regime, the CAISO does not have to concern itself with the possibility
that SCE could impact a generator’s response to CAISO dispatch instructions based on
76 Pac. Gas & Elec. Co., 88 FERC ¶ 63,007 at 65,062 (1999) (“WDAT Initial Decision”)
(emphasis added), aff’d in relevant part, 100 FERC ¶ 61,156 (2002). 77 The Complaint mentions that the CAISO is moving intertie scheduling and settlement
from an hourly to a 15-minute basis and establishing a 15-minute settlement for internal resources and convergence bids. Complaint at 18. As explained in the very letter cited by Complainants, the CAISO has long calculated five-minute locational marginal prices for internal resources for each five-minute dispatch interval and settled on 10-minute basis using the average of two consecutive five-minute locational marginal prices.
78 WDAT Initial Decision at 65,062.
31
SCE making decisions as to which generators are economic to dispatch. It would be
wholly infeasible for both SCE and CAISO to take bids to relieve congestion from the
very same set of generators and for both to have dispatch control over them. In fact, it is
the lack of a separate bid-based congestion management regime that makes SCE’s system
compatible with that of the CAISO.
The Complainants’ next concern is that the CAISO has no control over outage
schedules under the WDAT and that SCE will be able to take facilities out of service to
suit its own requirements, rather than those of the CAISO grid.79 Taking this reasoning
to its illogical conclusion, no generating facility can operate under the WDAT because
the inevitable outage coordination issues would impair CAISO operations. In fact, the
three California investor-owned utilities (“IOUs”), including SCE, all have generation
interconnected to distribution pursuant to WDATs that provide them with authority to
curtail when necessary due to abnormal operations.80 CAISO and the IOUs have
managed to coordinate outages of the distribution system for the past 15 years and
Complainants have not identified an instance where a WDAT outage ever impaired
CAISO BAA operations.
79 This sentence assumes that SCE’s “own requirements” are not fully aligned with those
of the CAISO – given that the two entities have a common interest as relates to the reliability of BAA, the claim is based on a flawed view of the relevant interests relating to BAA operations.
80 When SCE must curtail distribution service, WDAT Section 12 provides for pro rata curtailment. WDAT Attachment C as well as Attachment B address CAISO scheduled curtailments, not distribution service curtailments. The 2011 outage notifications attached to the Complaint do not reflect SCE policy.
32
E. SCE Made the Requisite Filings to Implement Reclassification and Did Not Subject Customers to After-the-Fact Rule Changes
The Complainants raise two primary sets of arguments relating to the
reclassification/release and its potential rate impacts. First, they argue that SCE has
either failed to make or has improperly made the requisite rate filings triggered by the
release of the facilities. Second, Complainants argue that interconnection customers
trying to develop their projects should not be forced to contend with changing ground
rules. Neither argument has merit.
1. SCE Made the Requisite Filings to Implement the Classification
The Complainants argue that the CAISO and SCE do not have the unilateral right
to deny GIA customers refunds for facilities formerly classified as network upgrades.81
In fact, SCE has a unilateral and express contractual right under its GIAs to make
requisite Section 205 filings seeking Commission approval of amended GIAs reflecting
the reclassification. SCE is filing with the Commission the GIAs affected by the
reclassification.82 Only upon the effective date of Commission’s acceptance of the
amended GIAs would reimbursements for network upgrades that have been reclassified
81 Complaint at 5, 31-32. 82 See e.g., Large Generator Interconnection Agreement among the CAISO, SCE and
Portal Ridge Solar A, LLC, et al. § 30.11 (filed in Dkt. No. 14-333). Portal Ridge is owned by Complainant First Solar and the Study Report for this Project Queue Number 342 is attached as Exhibit 4. In fact, all pro forma-based GIAs include Section 205 rights for the Transmission Provider or Transmission Owner that allow such entities to propose unilateral changes to their GIAs.
33
as distribution upgrades cease.83 SCE’s intent was to file changes to GIAs and file
WDSAs within 30 days of service commencing (i.e., by January 14, 2014).84 SCE made
its first such filing on December 20, 2013 and met its January 14, 2014 target for most
such filings.85
The Complainants criticize SCE for failing to conduct a load flow analysis to
apportion costs between retail and wholesale customer groups86 and also claim that costs
have not been properly apportioned between retail and wholesale customer groups.87 But
they base these claims on the assumption that WDAT customers pay a rolled-in formula
rate for distribution service. Wholesale loads using the WDAT pay for a portion of the
distribution system on a direct assignment basis. Wholesale generators do not pay to
transport power under the WDAT, but must pay for distribution upgrades caused by their
interconnection requests. Thus, the statement in the Complaint that SCE proposes to
“recover the costs of the affected facilities on a rolled-in basis through its WDAT formula
rate from all customers taking WDAT service,”88 is flat wrong. No WDAT customer
pays a rolled-in rate or a formula rate. WDAT customers pay a direct assignment rate,
reflecting the cost of specific facilities, or they pay no rate at all. In contrast, as to its
83 Such cessation of credits would be subject to refund were the Commission to suspend
the matter and set if for hearing. 84 SCE withheld from filing other GIAs earlier in order to give generators a reasonable
period of time to review the amendments and allow affected generators to raise any concerns. 85 The last few filings have been submitted as of the date of this Answer. 86 Complaint at 5, 6, and 14. 87 Id. at 14. 88 Id.
34
transmission system, SCE does use a rolled-in, formula rate to determine the transmission
revenue requirement that is flowed through CAISO transmission charges, but an FPA
Section 205 filing is not necessary to adjust that formula rate to reflect the EKWRA
reclassification.89
In sum, SCE now has made all requisite rate filings needed to implement the
reclassification/release and there is no basis to reverse that release on such grounds.
2. There Has Been No Change In the Ground Rules
The Complainants argue that “interconnection customers trying to develop their
projects should not be forced to contend with changing ground rules that can materially
affect the economics of projects that rely on long-term financing and power sales
contracts.”90 Complainants cite to two cases that are concerned with what tariff
interconnection procedures to follow,91 a question which is simply not at issue in this
case and has no bearing on amending GIAs to reflect the reclassification of facilities due
to changes in their configuration.
Cases involving changes to tariff interconnection procedures can result in the
changing of the cost recovery ground rules and under those circumstances, the
89 The formula adjusts annually and has an annual true-up mechanism which addresses
cases in which facilities are added to or removed from CAISO control. 90 Complaint at 33. 91 Complaint at 33, n.64. Under the West Deptford precedent cited, the Commission has
determined that it will be flexible in determining which set of interconnection procedures to apply to an interconnection customer and that the “execution date of [a GIA] does not by itself establish which tariff provision will apply to a process that from initiation to completion may take place for many years (over five years in this case).” PJM Interconnection, L.L.C. 139 FERC ¶ 61,184 at 41 (2012).
35
Commission carefully considers principles of reliance and regulatory certainty.92 But this
case does not involve a change in the cost recovery ground rules set forth in a tariff. The
CAISO Tariff/WDAT cost recovery policies remain the same. The test for CAISO
operational control has not changed either. Complainants thus are not being subjected to
an unexpected change in the applicable tariff rules – what has changed is the actual
physical configuration of the facilities.
Well-established Commission precedent confirms that facilities may be
reclassified well after a GIA has been executed and filed with FERC.93 For example, in
Duke Hinds II, the Commission ordered the reclassification of facilities years after the
original GIAs had been executed and filed with the Commission.94 The Whitewater and
Cabazon cases involved generators seeking to reclassify distribution facilities such that
the upgrades to them would become network upgrades and the costs spread among all
transmission customers – demonstrating that the impacts of reclassification can cut both
ways.
Furthermore, SCE and the CAISO have made every effort to inform customers of
these established ground rules, namely that facilities could be reclassified as the uses of
the facilities change. In 1996, the Commission specifically put all potential CAISO-
92 See Rail Splitter Wind Farm, LLC v. Ameren Services Co., 146 FERC ¶ 61,017 at PP
22, 24 (2014). 93 Duke Energy Hinds, LLC v. Entergy Services, Inc., 102 FERC ¶ 61,068 at P 28 (2003)
(“Duke Hinds II”), reh’g 117 FERC ¶ 61,210 (2006) (“Duke Hinds III”); see also ExxonMobil Corp. v. Entergy Services, Inc., 118 FERC ¶ 61,032 at P 5 (2007).
94 Duke Hinds II at PP 5-7.
36
region customers, including both generators and loads, on notice that facilities could be
reclassified. With regard to First Solar, it was informed on July 14, 2010 that certain
network facilities could be reclassified as distribution facilities as a result of the EKWRA
Project.95
Indeed, the Commission already rejected a generator’s attempt to be forever
exempt from the financial impacts of the EKWRA reclassification in light of notice
provided to it:
we reject Silverado’s request for exemption from any potential reclassification of network upgrades. We find that in the instant filings CAISO describes the EKWRA reconfiguration project as one of the reliability mitigation measures necessary to accommodate interconnection of new generation in that region. Informed of this possibility, Silverado nevertheless made a business decision to proceed with interconnection despite the risk of upgrades being reclassified from network to distribution. Under these circumstances, we find the request for exemption to be inappropriate based on the disclosure of the reliability mitigation measures necessary for inter-connection.96
The existence of such notice also directly refutes the Complainant’s unsupported
assertion that the CAISO and SCE had made “assurances” that reclassification would not
be necessary.97 Complainants attempt to use a quote out of context from Silverado as
evidence that such assurances were made.98 In Silverado, system changes in addition to
95 See Exhibit 4 at 14. 96 Silverado at P 30. 97 Complaint at 4. 98 Complaint at 9, n.9.
37
those related to the EKWRA Project were required in order for the facilities at issue to be
reclassified from network to distribution. As the CAISO stated in its filing:
The EKWRA reconfiguration, by itself, will not cause the upgrades identified in the Dry Ranch SGIA to become distribution upgrades. Rather, an additional system reconfiguration required to interconnect another project in the ISO’s queue will cause the existing Antelope 66 kV substation and the upgrades associated with that substation identified for the Dry Ranch project to become radial.99
The quote is, in fact, referencing non-EKWRA facilities that remain classified as
network. Complainants have no basis and have provided no other evidence to support
their claim that SCE and the CAISO made assurances that no reclassification of any of
the Antelope Valley 66 kV facilities would be necessary.
IV. COMMUNICATIONS
Communication regarding this Answer should be addressed to the following
individuals:
Claire E. Torchia (626) 302-6945 [email protected]
Jennifer L. Key (202) 429-6746 [email protected]
99 Transmittal Letter at 5, Dkt. ER12-2207 (July 5, 2012).
38
V. CONCLUSION
WHEREFORE, SCE respectfully requests that the Commission dismiss the
Complaint for the reasons stated above.
Respectfully submitted,
/Claire E. Torchia/ Claire E. Torchia Southern California Edison Company P.O. Box 800 Rosemead, CA 91770 (626) 302-6945 [email protected]
/Jennifer L. Key/ Jennifer L. Key Steptoe & Johnson LLP 1330 Connecticut Avenue, N.W. Washington, D.C. 20036 (202) 429-6746 [email protected]
EXHIBIT 1
List of Facilities previously under CAISO Control that will become Radial Systems after Completion of the EKWRA Project1
• Acton-Ritter Ranch • Acton-Palmdale-Shuttle • Anaverde-Ritter Ranch • Antelope-Anaverde-Helijet • Antelope-Cal Cement • Antelope-Del Sur-Glow • Antelope-Del Sur-Rosamond • Antelope-Lancaster-Oasis • Antelope-Lancaster-Lanpri-Shuttle • Antelope-Quartz Hill Circuit 1 • Antelope-Quartz Hill Circuit 2 • Antelope-Quartz Hill-Shuttle • Antelope-Ritter Ranch Circuit 1 • Antelope-Ritter Ranch Circuit 2 • Antelope-Rosamond • Bailey-Gorman • Cal Cement-Goldtown-Monolith-Windland • Cal Cement-Monolith-Rosamond-Windfarm • Cal Cement-Monolith-Windparks • Correction-Cummings-Kern River 1 • Corum-Rosamond • Cummings-Monolith • Del Sur-Lancaster-Riteaid • Corum-Goldtown • Gorman-Kern River 1 • Goldtown-Lancaster • Lancaster-Littlerock-Piute • Lancaster-Purify-Redman • Helijet-Little Rock-Palmdale-Rockair • Oasis-Palmdale-Quartz Hill • Piute-Redman ������������������������������������������������������������1�Including�associated�facilities,�including�breakers,�disconnects,�substations�etc.�
List of Facilities previously under CAISO Control that will remain in Network Service after Completion of the EKWRA Project • Bailey 220/66 kV Transformation • Bailey 66 kV Bus positions 6, 7, 8, and 11 Antelope-Neenach 66 kV line • Bailey-Neenach-Westpac 66 kV line (Excludes Westpac leg which is Non-ISO today) • Neenach Substation 66 kV Facilities • Antelope 220/66 kV Transformation • Antelope 66 kV Bus
EXHIBIT 2
Section 7 Page 25
7F. CONCLUSIONSIn this study, criteria violations were found for subtransmission equipment that will overload for base case and contingency conditions. The “East Kern Wind Resource Area 66 kV Reconfiguration Project” (OD 2013) will mitigate the criteria violations. The East Kern Wind Resource Area 66 kV project will separate the exiting Antelope-Bailey 66 kV system into two systems. The northern system will be served radially from Windhub substation. The southern system will remain parallel to the 230 kV system at Antelope and Bailey and will retain the label of the Antelope-Bailey 66 kV system. All north-to-south lines that once connected the northern system to the southern system will be opened. This project will address both load service performance criteria violations and remove the limitation on wind generation in the Tehachapi Pass.
The available spare Bailey 230/66 kV transformer bank will be energized in 2014 to mitigate the voltage criteria violation identified at Westpac, Oso, Frazier Park, Bailey, Gorman and Neenach.
Additionally, there are plans for two large customer substations for which the conceptual plan for tap and/or looped method of service has been provided. Large customer No. 1 requested a conceptual plan for either a single line or two line service. The conceptual plan for large customer No. 1 is either tap or loop to the existing Goldtown-Lancaster 66 kV line. Large customer No. 2 requested a conceptually plan for two line service. The method of service is to provide a two line service by looping in the Antelope-CalCement 66 kV line.
2009 SCE Annual Transmission Reliability Assessment
EXHIBIT 3
UNITED STATES OF AMERICA BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
California Wind Energy Association and First Solar, Inc., Complainants, v.Southern California Edison Company and California Independent System Operator Corporation, Respondents.
))))))
Docket No. EL14-14-000
AFFIDAVIT OF JORGE CHACON FOR SOUTHERN CALIFORNIA EDISON COMPANY
I, Jorge Chacon, being duly sworn, depose and state as follows:
I. INTRODUCTION
1. My name is Jorge Chacon. My business address is 3 Innovation Way, Pomona,
California 91768.
2. I am submitting this affidavit on behalf of Southern California Edison Company
(“SCE”). The statements made herein are true and correct to the best of my knowledge and
belief.
3. I obtained a Bachelor of Science degree in Electrical Engineering from California
State Polytechnic University Pomona, in 1997. Currently, I am the Generation Interconnection
Planning Manager in SCE’s Transmission and Distribution Business Unit. In that capacity, I am
responsible for managing the planning of transmission system projects, among other duties.
Over the past 16 years, I have performed transmission planning studies with respect to
transmission capability in the SCE electric system in order to accommodate new generation
interconnections.
Chacon Affidavit Page 2 of 16
4. The purpose of my affidavit is to describe the EKWRA Project and how it
impacts the characteristics and functionality of certain facilities. In addition, I will apply both
the seven-factor and Mansfield tests to the facilities at issue.
II. EKWRA PROJECT DESCRIPTION
5. The EKWRA Project is a system reconfiguration project approved by the
California Independent System Operator Corporation (“CAISO”) in 2010 to address reliability
issues that required mitigation on SCE’s Antelope-Bailey 66 kV system.1 The EKWRA Project
splits the 66 kV Antelope-Bailey system into northern and southern systems served radially from
three different transmission source substations (Antelope, Bailey, and Windhub) in order to
mitigate thermal overload problems, prevent subtransmission level voltage dips,2 and avoid
possible voltage collapse. The Windhub Substation became available as a potential transmission
source substation when SCE developed the Tehachapi Renewable Transmission Project
(“TRTP”). Final engineering and design activities for the initial TRTP 220 kV facilities at the
Windhub Substation began in 2007. Additional facilities were later installed to support the
interconnection of new wind generation projects into Windhub Substation at the 66 kV voltage
level. Such interconnections resulted in the advancement of some of the Windhub 66 kV
Substation facilities identified as part of the EKWRA Project.3 Such 66 kV facilities were placed
into service in March 2012 and were never placed under CAISO operational control, as the
CAISO point of interconnection was identified to be the Windhub 220 kV bus. With the 1 Final California ISO Transmission Plan, section 4.4 (dated April 7, 2010) (“ISO recommends reconfiguring
Antelope – Bailey 66 kV to mitigate the thermal overloads under both heavy summer and light spring conditions, and the voltage collapse and the transient voltage dips under light spring condition.”).
2 In SCE’s own nomenclature, the 55 kV, 66 kV, and 115 kV voltages are referred to as subtransmission voltages, but that term is not particularly relevant here. As will be discussed below, SCE’s subtransmission systems and facilities were virtually all classified as local distribution shortly before the CAISO began operations.
3 See S. Cal. Edison Co., 134 FERC ¶ 61,089 (2011).
Chacon Affidavit Page 3 of 16
progression of TRTP, Windhub 500 kV operation was achieved in early 2013. Construction of
the remaining Windhub 66 kV Substation facilities commenced in November 2012 and were
completed in November 2013.
6. On December 15, 2013, parallel operation changed to radial operation for most of
the Antelope-Bailey 66 kV system when certain circuit breakers were opened, as shown on
Attachment 2-2. At that time, the northern, eastern, and southern portions of the system became
a radial 66 kV distribution system connected to the Antelope Substation with limited northern
facilities migrated as radial connections to the Windhub 66 kV system. The western portion of
the reconfigured system consists mostly of radial distribution systems connected to the Bailey 66
kV Substation.
7. As construction of the EKWRA Project continues, the remaining northern portion
of the system will be migrated to the Windhub Substation, completing the radial distribution
system, while the southern and eastern portions will mostly remain radially connected to the
Antelope Substation, as shown in Attachment 2-3. There will continue to be two 66 kV lines in
the southern portion that remains in parallel operation with the integrated transmission network,
and will therefore remain under the CAISO’s operational control. Such connection will result in
parallel operation of a limited set of facilities, specifically the 220/66 kV transformer banks at
both the Antelope and Bailey Substations, all 66 kV equipment at both the Antelope and Bailey
Substations, the Neenach 66 kV Substation, and the 66 kV lines connecting Neenach to both the
Antelope and Bailey Substations. The remaining 66 kV facilities and all other 66 kV substations
in the Antelope-Bailey 66 kV system will operate in a radial fashion, as changes to system
conditions on the integrated transmission network will not change flow patterns on these
remaining facilities (the “EKWRA facilities”).
Chacon Affidavit Page 4 of 16
8. To date, SCE has completed significant elements of the EKWRA Project,
including the construction needed to migrate the northern portion of the existing Antelope-Bailey
66 kV system to be served out of the Windhub 66 kV Substation (i.e., the construction of the
Windhub 66 kV switchrack, including equipping of all necessary 66 kV positions and the 66 kV
underground getaways that will be used to reroute existing 66 kV lines into the Windhub
Substation). In addition, the portions of the EKWRA Project completed to date have allowed
additional queued generation projects that were dependent on certain portions of the EKWRA
Project to interconnect. These projects could not have otherwise been interconnected on the 66
kV system without upgrades that would have been more extensive and consequently more costly
than the EKWRA Project. To date, 157 MW of additional queued generation has been
interconnected as a result of the EKWRA Project.4 This amount of new generation will increase
to 277 MW with completion of the additional queued generation projects that have executed
interconnection agreements and are currently in the process of project execution.5 SCE forecasts
completion of the remaining 66 kV line work associated with the EKWRA Project by June,
2014.
III. APPLICATION OF THE SEVEN-FACTOR TEST
9. As described in detail below, in order to show that the EKWRA facilities are no
longer integrated transmission facilities, I applied the Order 8886 seven-factor test to determine
whether the facilities at issue herein were appropriate to classify as local distribution facilities, as
4 See S. Cal. Edison Co., 134 FERC ¶ 61,089 (2011), see also, Dkt. No. ER12-1462, Dkt. No. ER13-220, Dkt.
No. ER13-2, Dkt. No. ER13-220, and Dkt. No. ER497. 5 See Dkt. No. ER13-1972 and Dkt. No. 14-469. 6 Order 888, Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission
Services by Public Utilities, Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, FERC Stats & Regs ¶ 31,036 at 31,771 (1996) (subsequent history omitted) (“Order 888”).
Chacon Affidavit Page 5 of 16
well as the Mansfield7 test, to assess whether the subject facilities were integrated transmission
facilities. In Order 888, the Commission listed seven factors to identify non-jurisdictional local
distribution (as opposed to transmission) facilities.
10. The indicators of local distribution in the Commission’s seven-factor test are:
(i) that local distribution facilities are normally in close proximity to retail customers; (ii) that
local distribution facilities are primarily radial in character; (iii) that power flows into local
distribution systems, and rarely, if ever, flows out; (iv) that when power enters a local
distribution system, it is not reconsigned or transported onto some other market; (v) that power
entering a local distribution system is consumed in a comparatively restricted geographic area;
(vi) that meters are based at the transmission/local distribution interface to measure flow into the
local distribution system; and (vii) that local distribution systems will be of reduced voltage.
Factor One--Proximity of facilities to retail customers:
11. Antelope 66 kV system: With implementation of the entire EKWRA Project, the
Antelope 66 kV system will be comprised of twenty-one substations that are planned to support
approximately 600 MW of peak retail load. These substations are shown in Attachment 2-3. In
SCE planning studies, approximately 15% of the peak load customers and 37% of the off-peak
load customers are modeled as large, non-conforming retail load customers. These large retail
customers include a sewage treatment plant, a prison, manufacturing facilities, retail warehouses,
and aerospace facilities, all of which connect to the Antelope system directly at 66 kV. The
Antelope system also serves many smaller retail load customers. According to the 2010 Census,
the aggregate population of the largest cities served by the Antelope system exceeds 347,000
people. The 66 kV facilities, which have as a source the Antelope Substation, are the only 7 Mansfield Municipal Electric Department v. New England Power Co., 97 FERC ¶ 61,134 (2001) (“Mansfield”).
Chacon Affidavit Page 6 of 16
facilities that provide service to retail load in the greater Lancaster/Palmdale area. Hence, the
reconfigured Antelope 66 kV system is in close proximity to retail customers.
12. Bailey 66 kV system: With implementation of the EKWRA Project, the Bailey
66 kV system is comprised of five substations that are planned to support approximately 30 MW
of peak retail load. These substations are shown in Attachment 2-3. As is assumed in SCE
planning studies, approximately 70% of the peak load customers and 82% of the off-peak load
customers are modeled as large, non-conforming retail load customers. There is one large retail
customer, a cement plant, which connect directly at 66 kV voltage level. The Bailey system also
serves many smaller retail load customers at the Gorman and Frazier Park Substations, which are
within five miles of the Bailey Substation. Except for localized emergency system conditions on
the 66 kV system, the 66 kV facilities, which have as a source the Bailey Substation, are the only
facilities that provide service to retail load in the Bailey system. Hence, the Bailey 66 kV system
is in close proximity to retail customers. Additionally, there is a wholesale load (a pumping
plant) and generating facility operated by the California Department of Water Resources that is
directly connected to Bailey Substation at 66 kV. This wholesale interconnection has been
classified as non-CAISO and is unaffected by the EKWRA Project.
13. Windhub 66 kV system: With implementation of the full EKWRA Project, the
Windhub 66 kV system will be comprised of 11 substations that are planned to support
approximately 120 MW of peak retail load. These substations are shown in Attachment 2-3. As
is assumed in SCE planning studies, approximately 47% of the peak load customers and 64% of
the off-peak load customers are modeled as large, non-conforming retail load customers. These
large retail customers include two cement plants and one prison, all which will connect directly
to the Windhub system at 66 kV. The Windhub system will also serve many smaller retail load
customers, most of whom are located in the City of Tehachapi or town of Mojave, both of which
Chacon Affidavit Page 7 of 16
are within 10 miles of the Windhub Substation. Except for localized emergency system
conditions on the 66 kV system, the 66 kV facilities whose source is the Windhub Substation are
the only facilities that provide service to retail load in the Windhub system. Hence, the Windhub
66 kV system is in close proximity to retail customers.
14. Antelope-Bailey 66 kV system: As shown in Attachment 2-3, only one load-
serving substation (the Neenach 66 kV Substation), with a peak retail load of approximately six
megawatts, will remain in parallel with the transmission network following completion of the
EKWRA Project. This parallel operation is due to the fact that the Neenach Substation is
normally served by two source stations (i.e., two stations connecting to the integrated
transmission system), the Bailey and Antelope Substations, through a 66 kV line connection to
both substations. However, as part of the CAISO’s 2014 Transmission Plan, other post-EKWRA
Project system modifications and upgrades have been discussed that would reconfigure the
Neenach Substation to operate in a radial manner,8 similar to all of the other area facilities.
Factor Two--Primarily radial in character:
15. The use of 55 kV, 66 kV, and 115 kV voltages to build a distribution network that
is served via one transmission source substation and thus not operated in parallel with the 500 kV
and 220 kV transmission system is common to SCE’s system. Prior to the CAISO commencing
operations, FERC approved the exclusion of nearly all of SCE’s 55 kV, 66 kV, and 115 kV
facilities from the CAISO transmission network, and their classification as local distribution
facilities, because they are radial in nature as they are normally served via one source substation.
The Antelope-Bailey 66 kV system was an exception to the classification as local distribution,
8 See page 40 at http://www.caiso.com/Documents/PresentationDay1_2013-
2014TransmissionPlanningProcessNov20_2013.pdf
Chacon Affidavit Page 8 of 16
classified instead as under CAISO operational control since it operated in parallel with the
220 kV transmission facilities connected to the Antelope and Bailey Substations. With
implementation of the EKWRA Project, the impacted 66 kV systems, excluding the limited set
of facilities that will remain under CAISO control, will be radial (i.e., not be operated in parallel)
with the networked transmission system, as the reconfigured 66 kV lines do not form a loop back
into any other 220 kV substations under normal conditions since they will be served via one
source substation. Under localized emergency conditions on the 66 kV system, load may be
rolled between the reconfigured systems via use of normally-open 66 kV system tie lines.
However, the systems are not planned or designed to form looped or parallel paths between the
systems, as doing so would create the thermal overload and reliability problems that the
EKWRA Project is being implemented to address. Rolling load between the systems would be
performed utilizing standard “drop” and “pick up” operating procedures used throughout all of
SCE’s 66 kV systems.
16. All of SCE’s 66 kV distribution systems include substations which are provided
distribution service through multiple 66 kV lines. In such instances, local 66 kV “loops” may be
created but such loops are not operated in parallel with the integrated transmission system, as
illustrated by Attachment 2-2. These loops are thus radial distribution loops.
Factor Three--Power flows into local distribution systems:
17. As with any radial distribution system with generation interconnecting thereto, the
flow at the point of interconnection with the transmission system is unidirectional, but its
direction can vary based on system conditions. As discussed below, in two of the three 66 kV
systems (Antelope and Bailey), such flows are expected to always be inbound from the 220 kV
system to the 66 kV system, while the flows can vary in direction on the Windhub 66 kV system.
The basis for this conclusion is discussed below.
Chacon Affidavit Page 9 of 16
18. In analyzing which direction power is likely to flow, certain assumptions must be
made concerning generation development. As part of the generation interconnection study
process, SCE and the CAISO have analyzed a worst-case scenario, one in which there are
maximized flows on the EKWRA facilities, in an effort to identify any necessary mitigation to
thermal overloads or system voltages triggered by queued generation projects. These studies
assumed that the EKWRA Project would be in place – as it is an approved CAISO project – and
further assumed that all queued generation would actually develop. In SCE’s experience,
however, it is extremely unlikely that all new generation interconnection requests would
materialize and SCE does not anticipate that all or even of a majority of the remaining projects in
the queue will in fact ultimately materialize. As such, for purposes of determining the generation
available to offset load demand and applying the seven-factor test, SCE reasonably only accounts
for projects with executed generation interconnection agreements as representing projects that
may ultimately offset load demand in the reconfigured 66 kV systems.
19. Antelope 66 kV system: Based on currently executed generation interconnection
agreements, the prevailing flow over the 66 kV facilities that will be served radially from the
Antelope Substation will be from the transmission network to local load. The only way the flow
could be reversed is if the area saw an unanticipated increase in the number of new generation
projects or an unexpected increase in output while load remained constant or decreased.
However, such a possibility is certainly not imminent given the low number of executed
generation interconnection agreements, the low number of new generation megawatts remaining
in queue, and the significant amount of load to be served by these radial 66 kV facilities
(approximately 600 MW in 2014).
20. Bailey 66 kV system: Currently, there are no new generation projects seeking
interconnection to the 66 kV facilities that will be served radially from the Bailey Substation.
Chacon Affidavit Page 10 of 16
Consequently, the prevailing flow over these 66 kV facilities will be from the transmission
network to the local load. The only way the flow could be reversed is if the area saw an
unanticipated increase in the number of new generation projects. However, such a possibility is
not imminent given that no new generation projects have requested interconnection to any of
these radial 66 kV facilities served out of the Bailey Substation.
21. Windhub 66 kV system: On the newly configured Windhub system, flow will be
from the transmission network to the local load when local load exceeds the amount of
generation produced. When generation production exceeds local load, flow over these lines will
reverse and the 66 kV lines will behave like radial generation tie lines.
22. Even if a larger amount of generation does develop in the entire area served by
the EKWRA facilities, the primary change would be that the facilities would function similarly
to a generation tie line during the period in which the connected generation exceeds the
connected load. That is, the fact that energy sometimes may flow toward the transmission
network at Windhub and theoretically could do so at the other 66 kV substations does not mean
the facilities are integrated. During the 1980s, substantial quantities of Qualifying Facility
(“QF”) generation projects were interconnected to SCE’s 66 kV and 115 kV systems. As noted,
with the creation of the CAISO, the majority of such systems were classified as local distribution
facilities. SCE has seen a major increase in the amount of generation projects seeking
interconnection to its distribution facilities over the past several years. As of January 14, 2014,
SCE has 288 active generation interconnection requests seeking interconnection through SCE’s
Wholesale Distribution Access Tariff (“WDAT”), which requests total in excess of 5,170 MWs.
Of these, 83 projects totaling 1,485 MW have already been placed into service. In addition, SCE
has in excess of 300 other active generation interconnection requests seeking interconnection
Chacon Affidavit Page 11 of 16
utilizing the CPUC Rule 21 interconnection process and which total is in excess of 600 MWs.
Of these, 59 projects totaling 131 MW have already been placed into service.
23. As a result of the recent increase in generation connecting to SCE’s distribution
system, systems on which in some cases already included significant QF development, there are
situations that exist where there is excess generation on the distribution system that flows onto
the transmission system. An example of such a condition exists in the Devers 115 kV system,9
where the total amount of interconnected generation resources totals 860 MW and the load
demand ranges from approximately 480 MW during peak load conditions to 240 MW during off-
peak load conditions. Additionally, with the increase in distributed generation from rooftop solar
projects, energy storage projects and other small generation projects, there are increasing
numbers of distribution circuits where power flows or will flow in both directions depending on
load levels and the generation on that individual circuit.
24. The fact that power may flow to the transmission system from the distribution
system as a result of increased generation on the distribution system does not mean that such
distribution system has the characteristics of an integrated transmission system. Such a condition
results in the distribution system behaving like generation tie-lines, which are also facilities that
are non-integrated with the transmission system.
Factor Four--When power enters a local distribution system, it is not reconsigned or transported onto some other market:
25. Following completion of the EKWRA Project, power entering any of the three
distribution systems from the source stations integrated to the CAISO grid will remain within
9 The Devers 115 kV System was previously under CAISO control as part of a paralleled Devers-Mirage 115 kV
system but upgrades implemented in 2013 resulted in radial operation of the system. The Devers-Mirage 115 kV system followed the same process followed for the Antelope-Bailey 66 kV system and the CAISO relinquished operational control of the Devers 115 kV and Mirage 115 kV systems in 2013.
Chacon Affidavit Page 12 of 16
that distribution system. As demonstrated in Attachment 2-2, the normally-open system ties
created by the EKWRA Project will prevent this power from being transported back to the grid
or consigned to another market.
Factor Five--Consumption of power entering the distribution system is in a restricted area:
26. Power entering the newly configured Antelope, Bailey, and Windhub systems
would be consumed in a comparatively restricted geographical area. While the load density of
these newly formed radial distribution systems is not anticipated to be as great as other SCE
distribution systems, power entering one of these distribution systems could not serve load
outside the individual system under normal conditions. SCE does not anticipate outbound flow
from the reconfigured 66 kV systems interconnected to Antelope and Bailey Substations. There
are likely to be times when generation production may be greater than load in the Windhub 66
kV system. I am informed that today, most of the generation interconnected consists of QFs that
sell their energy to SCE rather than merchant generators selling into other markets.
Factor Six--Metering based at the transmission/local distribution interface to measure flow into the local distribution system:
27. The newly formed 66 kV systems will be metered at or near the point of
interconnection to the CAISO controlled grid. Such meters will measure flows into the
distribution systems.
Factor Seven--Local distribution will be of reduced voltage:
28. SCE has thirty-eight 66 kV systems, of which thirty-seven are currently classified
as distribution facilities. The Antelope-Bailey 66 kV system was the only SCE 66 kV system not
classified as distribution. With the completion of the EKWRA Project, the majority of the
system (excluding a limited number of 66 kV facilities discussed above) will be functionally
equivalent to the remaining thirty-seven SCE 66 kV distribution systems. With the completion
Chacon Affidavit Page 13 of 16
of upgrades identified to be triggered in the Phase 2 Cluster Study, all of the 66 kV facilities
served out of the Antelope and Bailey Substations will be functionally equivalent to the
remaining thirty-seven SCE 66 kV distribution systems. Given that every other 66 kV system
that SCE owns is classified as distribution, 66 kV is considered a distribution voltage.
IV. APPLICATION OF THE ������� TEST
29. In the Mansfield case, the Commission addressed the issue of whether certain
transmission facilities were or were not integrated into the relevant transmission provider’s
transmission system and, as such, could properly be categorized as network transmission
facilities. FERC affirmed the Presiding Judge’s adoption of a five-factor test:10 I understand the
five factors to be: 1) Whether the facilities are radial, or whether they loop back into the
transmission system; 2) Whether energy flows only in one direction, from the transmission
system to the customer over the facilities, or in both directions, from the transmission system to
the customer, and from the customer to the transmission system; 3) Whether the transmission
provider is able to provide transmission service to itself or other transmission customers over the
facilities in question; 4) Whether the facilities provide benefits to the transmission grid in terms
of capability or reliability, and whether the facilities can be relied on for coordinated operation of
the grid; and 5) Whether an outage on the facilities would affect the transmission system. As
discussed herein, I considered those five factors when I undertook the analysis as to whether the
EKWRA Project facilities were properly identified as distribution facilities:
��� ����� Factor One--The facilities will be operated radially and will not loop back into the integrated transmission system:
10 Mansfield at 61,613-14.
Chacon Affidavit Page 14 of 16
30. Mansfield Factor One requires analysis that is identical to that required for Factor
Two of the seven-factor test. Therefore, please see my analysis presented for Factor Two in
Paragraphs 15-16 above.
��� ����� Factor Two--Energy will flow primarily from the transmission system to local load:
31. Mansfield Factor Two requires analysis that is identical to that required for Factor
Three of the seven-factor test. Therefore, please see my analysis presented for Factor Three in
Paragraphs 17-25 above.
��� ����� Factor Three--Transmission provider provision of transmission service to itself or other transmission customers:
32. After December 15, 2013, the reclassified facilities are not used to provide
transmission service. SCE provides distribution service on the EKWRA facilities from the
CAISO controlled grid to a customer’s point of interconnection to the distribution system. For
SCE’s retail customers, such distribution service is provided pursuant to its retail tariff, subject to
the jurisdiction of the CPUC. For wholesale generators or loads, distribution service will be
provided pursuant to SCE’s WDAT, subject to the jurisdiction of the FERC. The transmission
provider, the CAISO, will not be using the reclassified facilities to transport power. Under the
CAISO construct, the CAISO provides transmission service over the integrated transmission grid
subject to its operational control. Distribution Providers, such as SCE, provide distribution
service to or from the CAISO controlled grid over the distribution facilities subject to its
operational control.
��� ����� Factor Four--The impacted facilities do not provide benefits to the integrated transmission grid in terms of capability or reliability:
33. The EKWRA Project was approved to mitigate NERC Category A, B and C
violations on 66 kV facilities. Due to the radial nature of the impacted 66 kV facilities, upon
Chacon Affidavit Page 15 of 16
implementation of the EKWRA Project, such facilities cannot be relied upon for coordinated
operation of the integrated transmission network because they do not operate in parallel with the
integrated transmission network. The reconfigured 66 kV systems will operate independently of
one another during normal conditions. As a result, under normal conditions, these EKWRA
Project-impacted 66 kV facilities will not add to the capability of the integrated transmission
grid. Consequently, there will be no benefit to the integrated transmission system in terms of
capability or reliability as a result of the reconfigured 66 kV facilities with completion of the
EKWRA Project.
��� ����� Factor Five--An outage on impacted facilities would not impact the integrated transmission network:
34. Outages on the impacted systems will not impact the integrated transmission
network because they do not operate in parallel with the integrated transmission network.
Outages on the radial Windhub 66 kV system will not impact the integrated transmission
network facilities serving the 66 kV Antelope or Bailey radial systems, and vice-versa since
there is no normally-closed connection between the two radial portions of the systems. The
reconfigured 66 kV facilities will be connected to the CAISO controlled grid in a radial fashion
at a single point or through a single source substation; therefore, an outage of facilities internal to
one of these radial systems will result in localized impacts internal to the radial system and will
not propagate to the integrated transmission network and therefore will not impact the CAISO
controlled grid. The radial portions of the reconfigured 66 kV systems will function
independently of each other and independently of the integrated transmission network as radial
operation. Consequently, an outage on the radial portions of any one of these reconfigured
systems would not impact the ability of the CAISO controlled grid to transmit energy over the
Chacon Affidavit Page 16 of 16
integrated transmission network as outages to radial facilities do not change flows on the
integrated transmission network.
35. In conclusion, my analysis of SCE’s electric system after the completion of the
EKWRA Project is that the EKWRA facilities will be local distribution facilities and will not
function as integrated transmission facilities. Additionally, I believe that removing these
facilities from CAISO operational control will not have any negative impact on grid reliability as
evidenced by the existence of thirty-seven other similarly situated 66 kV systems within SCE’s
service territory.
Neenach66 kV Antelope
500/220/66 kV
Bailey220/66 kV
Windhub500/220/66 kV
North of Magunden
South of Vincent
To Ventura County & South of
Pardee
To San Bernardino
County
Antelope-Bailey 66 kV SystemMultiple 66 kV SubstationsConnected via multiple 66 kV lines(See Attachment 2-1)
Operated in Parallel with220 kV and 500 kVBulk Electric System
Legend – Pre EKWRA
500 kV Line
500 kV Substation
220 kV Line
66 kV Line
220 kV Substation
66 kV Substation
Simplified 66 kV System Representation(lines, substation, and internal connections not shown)
220 kV Source Stations for 66 kV System
Attachment 1-1
Neenach66 kV Antelope
500/220/66 kV
Bailey220/66 kV
North of Magunden
South of Vincent
To Ventura County & South of
Pardee
To San Bernardino
County
Bailey 66 kV SystemRadially Operated from220 kV and 500 kVBulk Electric System(See Attachment 2-3)
Antelope 66 kV SystemRadially Operated from220 kV and 500 kVBulk Electric System
(See Attachment 2-3)
Windhub 66 kV SystemRadially Operated from220 kV and 500 kVBulk Electric System(See Attachment 2-3)66 kV line not shown in pre-split as it is inside the bubble
66 kV line not shown in pre-split as it is inside the bubble
66 kV line not shown In pre-split as it isinside the bubble
Windhub500/220/66 kV
Legend – POST EKWRA
500 kV Line
500 kV Substation (Under CAISO Control)
220 kV Line66 kV Line
220 kV Substation
66 kV Substation
66 kV Normally Open System Tie
Simplified 66 kV System Representation(lines, substation, and internal connections not shown)220 kV Source Stations for 66 kV System
Attachment 1-2
Wind Gen
(14)VARWIND
Wind Gen
Wind Gen
Wind Gen
BREEZE
Wind Gen
Wind Gen
Wind Gen
Wind Gen
Hydro Gen
LORAINE
HAVILAH
WALKERBASIN
CORRECTION
CUMMINGS
MONOLITH
Hydro Gen
Wind Gen
CALCEMENT
GOLDTOWN
CORUM
ROSAMOND
GREAT LAKES
REDMAN
ALAMO
OSO
NEENACH
WESTPAC
BAILEY
GORMAN
FRAZIERPARK
PIUTE
WILSONA
LITTLEROCK
TORTOISEOASIS
ROCKAIRHELIJET
ANAVERDEPALMDALE
ACTON
QUARTZ HILL
SHUTTLE
LANCASTER
RITE AID
LANPRI
DELSUR
ANTELOPE U.G.
Wind GenWind Gen
WindFarm
Windland
WindPark
RITTER RANCH
Purify
Antelope-Bailey 66 kV SystemSystem Prior to Commencement of EKWRA
Red outline = ISO controlled facilities
Black outline = Non-ISO controlled facilities
GLOW
Attachment 2-1Pre EKWRA
WINDHUB500 kV – CAISO Control220 kV – CAISO Control66 kV – Non-CAISO Control
220 kV – CAISO Control66 kV – CAISO Control
500 kV – CAISO Control220 kV – CAISO Control66 kV – CAISO Control
Wind Gen
(14)VARWIND
Wind Gen
Wind Gen
Wind Gen
BREEZE
Wind GenWind Gen
Wind Gen
Wind Gen
Hydro Gen
LORAINE
HAVILAH
WALKERBASIN
CORRECTION CUMMINGS
MONOLITH
Hydro Gen
Wind Gen
CALCEMENT
GOLDTOWN
CORUM
ROSAMOND
GREAT LAKES
REDMAN
ALAMO
OSO
NEENACH
WESTPAC
BAILEY
GORMAN
FRAZIERPARK
PIUTE
WILSONA
LITTLEROCK
TORTOISEOASIS
ROCKAIRHELIJET
ANAVERDEPALMDALE
ACTON
QUARTZ HILL
SHUTTLE
LANCASTER
RITE AID
LANPRI
DELSUR
ANTELOPEU.G.
Wind GenWind Gen
WindFarm
Windland
WindPark
RITTER RANCH
Purify
Antelope-Bailey 66 kV SystemAntelope 66 kV SystemBailey 66 kV SystemWindhub 66 kV System
Normally Open 66 kV System Tie
GLOW
Wind Gen
Windhub
Legend
66 kV Lines (CAISO Controlled)
CAISO Source Bus
66 kV Lines (Radial from Antelope)66 kV Lines (Radial from Bailey)
66 kV Substation (CAISO Controlled)66 kV Substation (Radial from Antelope)66 kV Substation (Radial from Bailey)66 kV Substation (Radial from Windhub)
66 kV Lines (Radial from Windhub)
Dec, 15, 2013Attachment 2-2
500 kV – CAISO Control220 kV – CAISO Control66 kV – Non-CAISO Control
220 kV – CAISO Control66 kV – CAISO Control
500 kV – CAISO Control220 kV – CAISO Control66 kV – CAISO Control
Wind Gen
(14)VARWIND
Wind Gen
Wind Gen
Wind Gen
BREEZE
Wind GenWind Gen
Wind Gen
Wind Gen
Hydro Gen
LORAINE
HAVILAH
WALKERBASIN
CORRECTION CUMMINGS
MONOLITH
Hydro Gen
Wind Gen
CALCEMENT
GOLDTOWN
CORUM
ROSAMOND
GREAT LAKES
REDMAN
ALAMO
OSO
NEENACH
WESTPAC
BAILEY
GORMAN
FRAZIERPARK
PIUTE
WILSONA
LITTLEROCK
TORTOISEOASIS
ROCKAIRHELIJET
ANAVERDEPALMDALE
ACTON
QUARTZ HILL
SHUTTLE
LANCASTER
RITE AID
LANPRI
DELSUR
ANTELOPEU.G.
Wind GenWind Gen
WindFarm
Windland
WindPark
RITTER RANCH
Purify
Antelope-Bailey 66 kV SystemAntelope 66 kV SystemBailey 66 kV SystemWindhub 66 kV System
Normally Open 66 kV System Tie
GLOW
Wind Gen
Windhub
Legend
66 kV Lines (CAISO Controlled)
CAISO Source Bus
66 kV Lines (Radial from Antelope)66 kV Lines (Radial from Bailey)
66 kV Substation (CAISO Controlled)66 kV Substation (Radial from Antelope)66 kV Substation (Radial from Bailey)66 kV Substation (Radial from Windhub)
66 kV Lines (Radial from Windhub)
Post EKWRAAttachment 2-3
500 kV – CAISO Control220 kV – CAISO Control66 kV – Non-CAISO Control
220 kV – CAISO Control66 kV – CAISO Control
500 kV – CAISO Control220 kV – CAISO Control66 kV – CAISO Control
EXHIBIT 4
Appendix A - Q #342
First Solar Development, Inc.
PV-4 Generation Project
Final Report
July 14, 2010
This study has been completed in coordination with Southern California Edison per CAISO Tariff Appendix Y Large Generator Interconnection Procedures (LGIP) for Interconnection Requests in a Queue Cluster Window
Table of Contents
1. Executive Summary .......................................................................................................... 3
2. Project and Interconnection Information ........................................................................... 4
3. Study Assumptions............................................................................................................ 6
4. Power Flow Analysis ......................................................................................................... 7
4.1 Overloaded Transmission Facilities ......................................................................... 7
4.2 Power Flow Non-Convergence ................................................................................ 7
4.3 Recommended Mitigations ....................................................................................... 7
5. Short Circuit Analysis ........................................................................................................ 8
5.1 Short Circuit Study Input Data .................................................................................. 8
5.2 Results ...................................................................................................................... 8
5.3 Preliminary Protection Requirements ....................................................................... 9
5.4 Additional SCD Discussion ....................................................................................... 9
6. Reactive Power Deficiency Analysis ................................................................................. 9
7. Transient Stability Evaluation .......................................................................................... 10
7.1 Transient Stability Study Scenarios ........................................................................ 10
7.2 Results .................................................................................................................... 10
8. Deliverability Assessment ............................................................................................... 10
8.1 On Peak Deliverability Assessment ....................................................................... 10
8.2 Off- Peak Deliverability Assessment ...................................................................... 10
9. Operational Studies ......................................................................................................... 11
9.1 IC Proposed Project Timelines ............................................................................... 11
9.2 System Upgrade Timelines .................................................................................... 11
9.3 TRTP Licensing and Construction Timelines ......................................................... 13
9.4 East Kern Wind Resource Area Upgrades ............................................................ 14
9.5 Conclusion .............................................................................................................. 14
10. Environmental Evaluation/Permitting .............................................................................. 15
11. Upgrades, Cost Estimates and Construction schedule estimates ................................. 15
12. Study Caveats ................................................................................................................. 18 Attachments:
1. Generator Machine Dynamic Data 2. Dynamic Stability Plots (see Appendix F) 3. SCE Interconnection Handbook 4. Short Circuit Calculation Study Results (see Appendix H) 5. Deliverability Assessment Results 6. Allocation of Network Upgrades for Cost Estimates
3
1. Executive Summary
Edison Mission Energy originally submitted a completed Interconnection Request (IR) to the California Independent System Operator Corporation (CAISO) for their proposed PV-4 Generation Project (Project), interconnecting to the CAISO Controlled Grid. Subsequently, a Consent to Assignment Agreement was executed, assigning ownership of the Project to First Solar Development, Inc., the Interconnection Customer (IC). The Project is a solar plant utilizing Xantrex GT 500 photovoltaic (PV) solar inverters with an output of 50 MW to the Point of Interconnection (POI) which is at Southern California Edison Company’s (SCE) Del Sur Substation in Kern County, California. The IC has proposed a Commercial Operation Date of July 1, 2013 for the Project.
In accordance with Federal Energy Regulatory Commission (FERC) approved Large Generator Interconnection Procedures (LGIP) for Interconnection Requests in a Queue Cluster Window (ISO Appendix Y), this project was grouped with “Transition Cluster” projects (Transition Cluster Phase II Study or Phase II study) to determine the impacts of the group as well as impacts of this Project on the CAISO Controlled Grid.
The group report has been prepared separately identifying the combined impacts of all projects in the group on the CAISO Controlled Grid. This report focuses only on the impacts of this project.
The report provides the following:
1. Transmission system impacts caused by the Project;
2. System reinforcements necessary to mitigate the adverse impacts caused by the Project under various system conditions; and
3. A list of required facilities and a non-binding, good faith estimate of (a) the Project’s cost responsibility, and (b) the time required to permit, engineer, design, procure and construct these facilities.
The Phase II study results have determined that the Project contributes to overloading of transmission facilities for which mitigation plans have been proposed. These mitigation plans include the use of congestion management for base case and contingency overloads, and the use of Special Protection System (SPS) under identified contingency outage conditions.
In addition, the Project is partly responsible for overstressing circuit breakers at the Vincent 500 kV, Windhub 220 kV1, and Antelope 66 kV buses.
1 Identification of facility voltages (220 kV) in this Phase II Study are shown consistent with SCE System Operating Bulletin 123. However, all studies were predicated on the base voltages reflected in the Western Electricity Coordinating Council (WECC) base cases. For the SCE bulk power system, the WECC base cases reflect 230 kV and 500 kV base voltages; consequently, all per-unit calculations presented were based on 230 kV and 500 kV voltages.
4
The Project contributes to reactive power deficiencies in the transmission system under base case and contingency outage conditions, and voltage criteria violations under contingency conditions. The study concluded that use of congestion management under base case conditions to limit South of Vincent flows to 8500 MW or less will be required.
The non-binding costs to interconnect the Project are:
Interconnection Facilities2 $3,400,000 including ITCC3;
Network Upgrades4 $2,108,000
Distribution Upgrades5 $0
The anticipated time to construct the facilities associated with the Project is approximately 24 months from the signing of the Large Generator Interconnection Agreement (LGIA). In addition there may be operational constraints related to the construction of upgrades to accommodate projects ahead in queue. See Section 9 “Operational Studies” for additional details.
2. Project and Interconnection Information
During the period between the Transition Cluster Phase I and Phase II technical analysis, The IC submitted a revised Appendix B to the CAISO LGIP which requested modifications to the Project’s original plan. As a result of this request, SCE applied the following changes to the Project’s depiction in the Transition Cluster Phase II study.
Project Change(s) in Phase II Study:
1. Gen-tie parameters were changed to reflect new conductor type (1113 kcmil ACSR) and increased length (approximately 3 miles decrease).
Table 2-1 provides the Phase II general information about the Project.
Table 2-1: PV-4 Generating Station Project General Information
Project Location Kern County, California
SCE Planning Area Northern Bulk System Number and Type of Generators 100 Xantrex GT500 Solar Inverters
Interconnection Voltage 66 kV
Maximum Generator Output 50 MW
2 The transmission facilities necessary to physically and electrically interconnect the Project to the CAISO Controlled
Grid at the point of interconnection. These costs are not reimbursable. 3 Income Tax Component of Contribution. 4 The additions, modifications, and upgrades to the CAISO Controlled Grid required at or beyond the Point of
Interconnection to accommodate the interconnection of the Generating Facility to the CAISO Controlled Grid. Network Upgrades shall consist of Delivery Network Upgrades and Reliability Network Upgrades.
5 These upgrades are not part of the CAISO Controlled Grid and are not reimbursable
5
Generator Auxiliary Load 0.0 MW
Maximum Net Output to Grid 50 MW
Power Factor Range 0.93 lagging to leading
Padmount Transformer Fifty 34.5/0.315 kV transformers, each rated for 1.0 MVA with an impedance of 5.47% at 1.0 MVA base
Step-up Transformer One 66/34.5 kV transformer rated for 60/80/100 MVA with impedances of 7% at 30 MVA
Point of Interconnection Del Sur 66 kV Substation
Commercial Operation Date July 1, 2013 (customer requested date) Individual Project Appendix B Changes between Phase I and Phase II
Gen-tie length decrease and new conductor.
Figure 2-1 provides the map for the Project and the transmission facilities in the vicinity. Figure 2-2 shows the conceptual single line diagram of the Project as modeled in the Phase II Study.
Figure 2-1 : Map of the Project
6
Del Sur 66 KV Substation
EQUIVALENT GENERATOR DATA (EQ)Number of units: 50 per feederIndividual generator output: 0.5 MW“EQ” Rated Output: 25 MWVoltage Rating: 0.315 kVPF: > 0.93Nominal output current: 916 A rmsMaximum output fault current: 1040 A (est)Manufacturer: XantrexModel: GT 500
TC08SC33# 94231
66 KV BusMAIN TRANSFORMER DATA:Rated Voltage: 66/34.5 kVRated MVA: 60/80/100 MVAImpedance: 7% @ 30 MVAH Winding: DeltaX Winding: Wye-Ground
TOT307_A# 94232
34.5 KV Bus
tot307_a# 94233
0.315 KV
EQUIVALENT PADMOUNTTRANSFORMER DATA (EQ)Transformer Units: 25Individual Rating: 1.0 MVA“EQ” Rated MVA: 25 MVARated Voltage: 34.5/0.315 kVImpedance: 5.47% @ 25 MVAH Winding: Wye-GroundX Winding: Wye
tot307_b# 94234
0.315 KV
PV 25 MW PV 25 MW
“EQ” “EQ”
“EQ” “EQ”
Line/Gen-Tie Data:Distance: 6.0 miles 1113 kcmil ACSRZ1 (p.u.) = 0.01294+j0.08798, B/2 (p.u.) = 0.00176Z0 (p.u.) = 0.06647+j0.37152, B/2 (p.u.) = 0.00083Line Rating: 1040/1150 A normalPhase Configuration: DeltaPhase Spacing (ft): A-B: 8 ft., B-C: 8 ft., C-A: 8 ft.Distance of lowest conductor to Ground: 30 ft.Ground Wire Type: Steel Conductor Size: 7/16Distance to Ground: 52 ft.
Figure 2-2: Proposed Single Line Diagram as modeled in the Phase II Study
3. Study Assumptions
For details about the Transition Cluster interconnection information and the group study assumptions, including relevant changes between the Phase I and Phase II studies, see the group report Sections 2 and 4.
The following design assumptions are applicable to the Project:
A. The following Facilities were estimated and included in the Phase II Study:
o It is assumed SCE would be required to install one additional dead-end structure and a total of two spans of line to reach the proposed 66 kV line position.
o The required revenue metering cabinet and retail load meters to be installed at the generating facility will be installed by SCE.
o The required remote terminal unit (RTU) to be installed at the generating facility will be installed by SCE.
B. The following facilities are to be installed by the Interconnection Customer and are not
included in this Phase I Study:
o The Project 66 kV gen-tie line from the generating facility to the last structure outside the Del Sur Substation property line will be installed by the Project and is not included in the Phase II Study results. The customer’s 66 kV gen-tie line right of way should extend up to the edge of the SCE substation property line.
7
o The Project 66 kV gen-tie line must be equipped with fiber optics to provide a telecommunication path required for the RTU. The cost of the fiber optics on the gen-tie will be included in the cost of the gen-tie line and is not included in the Phase II Study results.
o All required CAISO metering equipment at the generating facility will be provided by the customer and is not included in the Phase II Study.
o All required revenue metering equipment to meter the generating facility retail load will be specified by SCE and installed by the customer at their end of the Project 66 kV gen-tie line and is not included in the Phase II Study.
4. Power Flow Analysis
The group study indicated that the Project contributes to the following transmission facility overloads or non-convergence problems. The details of the analysis and overload levels are provided in the group study.
4.1 Overloaded Transmission Facilities
Category “A”
Pardee-Pastoria-Warne 220 kV T/L
Category “B”
Lugo-Vincent #1 or #2 500 kV T/L Pardee-Pastoria-Warne 220 kV T/L
Category “C”
Pardee-Pastoria-Warne 220 kV T/L Pardee-Bailey 220 kV T/L Bailey-Pastoria-Warne 220 kV T/L
4.2 Power Flow Non-Convergence
Category “C”
Lugo-Vincent 500 kV T/L N-2 outage
4.3 Recommended Mitigations
A combination of congestion management for base case and contingency overloads, and the use of SPS to under identified contingency outage conditions, is required to mitigate the power flow impacts of the project described above. See the group report for additional details.
8
5. Short Circuit Analysis
Short circuit studies were performed to determine the fault duty impact of adding the Transition Cluster projects to the transmission system. The fault duties were calculated with and without the projects to identify any equipment overstress conditions.
The cost responsibility of each individual project was determined based on the methodology applied in the Phase I Study once overstressed circuit breakers were identified. Costs of replacing and/or upgrading circuit breakers located within a Transition Cluster Group were allocated among all generation projects located within that Group. Costs of replacing and/or upgrading circuit breakers not located within a particular Transition Cluster Group were allocated over the entire Transition Cluster. Costs were allocated pro rata on the basis of the maximum megawatt electrical output of each proposed new Large Generating Facility or the amount of megawatt increase in the generating capacity of each existing Generating Facility.
5.1 Short Circuit Study Input Data
The following input data provided by the Applicant of this Project was used in this study:
Xantrex GT 500 PV Inverter Short Circuit Data @ 0.5 MVA Base:
Positive Sequence subtransient reactance (X’’1) = 0.88 p.u.
Negative Sequence subtransient reactance (X’’2) = 0.88 p.u.
Station Step-up Transformer
The 66/34.5 kV transformer is rated for 60/80/100 MVA with impedances of 7% at 30 MVA
Generation Tie Line
The generation tie line assumed 6.0 miles of 1113 ACSR conductor.
5.2 Results
All bus locations where the Transition Cluster Projects increase the short-circuit duty by 0.1 kA or more and where duty is in excess of 60% of the minimum breaker nameplate rating are listed in Appendix H of the Group Report. These values have been used to determine if any equipment is overstressed as a result of the Transition Cluster interconnections and corresponding network upgrades, if any. The Transition Cluster Phase II breaker evaluation identified the following overstressed circuit breakers:
Vincent Substation 500 kV CB962, CB862, CB852, CB812, CB912, CB952, CB722, CB712, CB752, CB762, and CB822.
9
Kramer 220 kV CB4022, CB6022, CB6012, CB4082, and CB4102 Windhub 220 kV CB4102, CB6102, CB4122, CB6102, CB6122,
CB4122, CB4132, CB2132, CB6112, and CB6132 Antelope 66 kV (total of 34 66 kV CBs)
Based on the cost assignment methodology applied in the Phase II Study, the Project will have the assigned cost responsibility for mitigation of the short-circuit duty results described above. The total cost responsibility allocated to the Project is provided in Attachment 6.
5.3 Preliminary Protection Requirements
Protection requirements are designed and intended to protect SCE’s system only. The preliminary protection requirements were based upon the interconnection plan as shown in Figure 2-2.
The applicant is responsible for the protection of its own system and equipment and must meet the requirements in the SCE Interconnection Handbook provided in Attachment 3.
5.4 Additional SCD Discussion
The Phase II Study has shown significant increases in Single-Line-Ground (SLG) short-circuit duty with the addition of numerous grounded interconnection transformers. For details, see Appendix H. It is recommended that the Project’s step-up transformers be specified, if possible, in such a way to limit the Project’s contribution to SLG SCD on the SCE system. This may be accomplished by installing transformers with delta-connected high side windings or with “impedance-grounded” wye-connected high side windings.
6. Reactive Power Deficiency Analysis
Reactive power deficiency analysis was performed in the group study. The reactive power deficiency analysis included power flow sensitivity analysis in the Northern Bulk System as well as reactive margin (QV) analysis on selected non-convergent cases from the power flow study. The analysis found that the project contributes to reactive power deficiencies in the transmission system under base case and contingency conditions, and voltage criteria violations under contingency conditions. In particular, the reactive power deficiency analysis confirmed that the non-convergence cases in the power flow analysis were real transmission system deficiencies due to the addition of Transition Cluster projects – such as insufficient reactive margin – and not numerical solution problems. The study concluded that use of congestion management to limit south of Vincent flows to 8500 MW or less will mitigate this problem. For additional details, see the group report.
10
7. Transient Stability Evaluation
Transient stability studies were conducted using the full loop base cases to ensure that the transmission system remains in operating equilibrium, as well as operating in a coordinated fashion, through abnormal operating conditions after the Transition Cluster projects begin operation. The generator dynamic data used in the study for the Project is shown in Attachment 1.
7.1 Transient Stability Study Scenarios
Disturbance simulations were performed for a study period of 10 seconds to determine whether the Transition Cluster Phase II projects will create any system instability during a variety of line and generator outages. The most critical single contingency and double contingency outage conditions in the Northern Bulk System were evaluated. For the list of specific line and generator outages evaluated, see the group report.
7.2 Results
In the stability analysis performed in the Northern Bulk System with the addition of Transition Cluster projects and upgrades in place to mitigate base case and outage related overload problems, no significant transmission system stability problems relative to existing stability criteria were identified. The study concluded that the Project would not cause the transmission system to go unstable under Category “B” and Category “C” outages. For a more detailed discussion on the stability analysis see the group report. The stability plots are provided in Attachment 2.
8. Deliverability Assessment
8.1 On Peak Deliverability Assessment
CAISO performed an On-Peak Deliverability Assessment. The power flow study results for Category “A”, “B”, and “C” are detailed in Attachment 5.
8.2 Off- Peak Deliverability Assessment
A modified version of the power flow 2013 Spring Off-Peak base case was created to perform the off-peak deliverability assessment of the Transition Cluster projects. The assumptions to create this case are listed in the group study. The impacts of this project are shown in Attachment 5.
11
9. Operational Studies
9.1 IC Proposed Project Timelines
The latest information provided by the IC has indicated that the proposed date for the generator step-up transformer to receive back feed power is February 2013 and the proposed Commercial Operation Date is July 2013.
9.2 System Upgrade Timelines
The Project involves the installation of the following interconnection facilities:
1. A dead-end structure and dedicated double breaker position at Del Sur 66 kV substation to bring in the Project gen-tie;
2. An RTU at Project Facility; and
3. The installation of telecommunications equipment to provide diverse protection and data transfer capability to the RTU, and SCADA data recording equipment.
The anticipated time to construct these facilities is 24 months upon execution of LGIA.
The study concluded that the Project was not allocated any Delivery of Distribution Upgrades.
This Phase II Study assumed that all previously triggered short-circuit duty impacts would be mitigated by the corresponding triggering project. Consequently, this study evaluated the incremental impacts associated with the addition of the Transition Cluster projects, including appropriate transmission upgrades as identified in this study, in an effort to cost allocate the incremental upgrades associated with the addition of the Transition Cluster projects. However, it should be clear that for reliability reasons it may be necessary to implement mitigation upgrades previously triggered by queued ahead generation projects prior to allowing interconnection of Transition Cluster generation projects. The circuit breaker upgrades that were triggered by queued-ahead projects are identified in Section 4.6 of the group report. The Operational Study undertaken as part of this Phase II Study identified the required timing for circuit breaker upgrades triggered by queued-ahead generation projects. The Table below identifies the first year that circuit breaker upgrades triggered by queued-ahead projects were found to be required in this Operational Study at each substation location.
12
Table 9-1: Circuit Breaker Upgrades Triggered by Queued-ahead Projects Year Location 2010 Devers 115 kV
Ellis 66 kV Etiwanda 220 kV Inyokern 115 kV Vincent 220 kV Antelope 66 kV Neenach 66 kV
2011 Terawind 115 kV 2012 Mira Loma 220 kV
Villa Park 220 kV
2013 Antelope 220 kV Chino 220 kV Devers 220 kV Lugo 500 kV Mesa 220 kV Vincent 500 kV
2014 Mira Loma 500 kV Vincent 220 kV
2015 None 2016 None
This Phase II Study assumed that the timelines for construction of the upgrades listed in Table 9-1 to accommodate queued-ahead projects will also be sufficient to accommodate the operational requirements for the Transition Cluster projects. In the event that the Transition Cluster projects will need to accelerate these upgrades, the projects will need to do so via a separate agreement. Operational studies will be conducted on an annual basis or more frequently as needed to identify such requirements.
The circuit breaker upgrades that were triggered by Transition Cluster projects are identified in Section 8.2 of the group report. The Operational Study undertaken as part of this Phase II Study identified the required timing for circuit breaker upgrades triggered by Transition Cluster projects. The Table below identifies the first year that circuit breaker upgrades triggered by Transition Cluster projects were found to be required in this Operational Study at each substation location.
Table 9-2: Circuit Breaker Upgrades Triggered by Transition Cluster Projects Year Location 2013 Antelope 66 kV
2014 None
2015 Vincent 500 kV Windhub 220 kV
2016 Kramer 220 kV
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9.3 TRTP Licensing and Construction Timelines
The latest information available regarding TRTP Segments 4-11 construction timelines and in-service dates can be obtained from the Quarterly Compliance Report (April 2010) of Southern California Edison Company Regarding Status of Transmission Projects, pursuant to CPUC Decision (“D,”) 06-09-003. Specifically:
Table 9-3: TRTP 4-11 Project Status (from SCE AB-970 Compliance Filing, April 2010)
TRTP SEGMENTS 4-11 PROJECT DESCRIPTION
PLANNED IN-SERVICE DATE
Segment 4 - Construct two new 220 kV T/Ls traveling approximately 4 miles over new right-of-way (ROW) from the Drycreekwind Substation (formerly referred to as “Cottonwind Substation”) to the proposed new Whirlwind Substation. Construct a new 500 kV T/L, initially energized to 220 kV, traveling approximately 16 miles over expanded ROW from the proposed new Whirlwind Substation to the existing Antelope Substation. Construct new 500 kV T/Ls to loop existing Midway-Vincent No. 3 - 500 kV line in and out of proposed Whirlwind (part of Segment 9) substation.
3/31/2012
Segment 5 - Rebuild approximately 18 miles of the existing Antelope – Vincent 220 kV T/L and the existing Antelope – Mesa 220 kV T/L to a second single Antelope-Vincent 500 kV T/L over existing ROW between the existing Antelope Substation and the existing Vincent Substation.
10/31/2012
Segment 6 - Rebuild approximately 32 miles of existing 220 kV T/L to 500 kV standards from existing Vincent Substation to the southern boundary of the Angeles National Forest (ANF). This segment includes the rebuild of approximately 27 miles of the existing Antelope – Mesa 220 kV T/L and approximately 5 miles of the existing Rio Hondo – Vincent 220 kV No. 2 - T/L.
3/31/2014
Segment 7- Rebuild approximately 16 miles of existing 220 kV T/L to 500 kV standards from the southern boundary of the ANF to the existing Mesa Substation. This segment would replace the existing Antelope – Mesa 220 kV T/L.
3/31/2014
Segment 8 - Rebuild approximately 33 miles of existing 220 kV T/L to 500 kV standards from a point approximately 2 miles east of the existing Mesa Substation (the “San Gabriel Junction”) to the existing Mira Loma Substation. This segment would also include the rebuild of approximately 7 miles of the existing Chino – Mira Loma No. 1 line from single-circuit to double-circuit 220 kV structures.
3/31/2014
Segment 9 -Construct Whirlwind Substation, a new 500/220 kV substation located approximately 4 to 5 miles south of the Drycreekwind Substation in Kern County in the TWRA. Upgrade of the existing Antelope, Vincent, Mesa, Gould, and Mira Loma Substations to accommodate new T/L construction and system compensation elements.
5/31/2012 / 11/31/2013
Segment 10 - Construct a new 500 kV T/L traveling approximately 17 miles over new ROW between the Windhub Substation and the proposed new Whirlwind Substation. 3/31/2012
Segment 11 - Rebuild approximately 19 miles of existing 220 kV T/L to 500 kV standards between the existing Vincent and Gould Substations. This segment would also include the addition of a new 220 kV circuit on the vacant side of the existing double-circuit structures of the Eagle Rock – Mesa 220 kV T/L between the existing Gould Substation and the existing Mesa Substation.
2/1/2015
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The California Public Utilities Commission has issued a Certificate of Public Convenience and Necessity (CPCN) for TRTP Segments 4-11. The CPUC and the Angeles National Forest are now engaged in a joint California Environmental Quality Act (CEQA)/National Environmental Policy Act (NEPA) process in accordance with applicable state and federal environmental regulations, policy, and law. SCE is in the process to obtain the necessary governmental approvals, authorizations, and permits as required by federal, state, and local laws, regulations, and ordinances pursuant to the requirements specified under CPUC General Order 131-D. Appendix M of the Proponents Environmental Assessment (PEA) for TRTP lists these requirements in greater detail. One approval item that may impact the TRTP construction schedule, specifically identified in the SCE AB-970 Compliance Filing in April 2010, is the issuance of a Biological Opinion from the U.S. Fish and Wildlife Service (USFWS). To date the Biological Opinion has not been issued. The planned in-service dates for the various segments of TRTP are subject to change based on the timing and details of these approvals, authorizations, and permits.
9.4 East Kern Wind Resource Area Upgrades
The study included the modeling of the East Kern Wind Resource Area (“EKWRA”) 66 kV reconfiguration project. This project was proposed by SCE in the CAISO 2010 Transmission Plan as a reliability project to address numerous reliability criteria violations in the existing Antelope-Bailey 66 kV network. This project was presented and recommended for approval by CAISO at the February 16, 2010 CAISO transmission plan stakeholder meeting. The EKWRA project was approved by CAISO on April 8, 2010. The EKWRA project has a proposed in-service date of December 2013. For additional details, see the group report. When EKWRA is constructed and energized, portions of the existing Antelope-Bailey 66 kV system, including the existing Del Sur 66 kV Substation, may operationally change from network facilities under CAISO control to SCE distribution facilities. This may also impact the classification of some of the upgrades specifically identified in this study as network upgrades at Del Sur Substation and result in those upgrades ultimately being classified as distribution upgrades. Issues related to network versus non-network classification of facilities and EKWRA were discussed in a 2010 CAISO Transmission Plan stakeholder conference held on March 19, 2010. For additional details see http://www.caiso.com/20al/20a1dbe417300.html.
9.5 Conclusion
Based on information available at this time, assuming an anticipated LGIA execution date of September 2010, and taking into consideration the upgrades described above that were allocated to the Project, there are no
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anticipated operational constraints associated with the construction of the Interconnection Facilities. The operational study conclusion is that the IC proposed timeline can be met.
However, there are anticipated operational constraints for full delivery based on timelines to construct upgrades for higher queued projects. TRTP Segments 4-11 are currently scheduled to be completed by February 2015. This date is after the IC requested in-service date. This means that the Project may be required to interconnect on an interim “Energy Only” basis until these upgrades are ultimately constructed, based on CAISO Deliverability Study findings. This also means the Project may be subject to additional congestion, mitigated by CAISO’s operating protocols, until such time as all required Delivery Network upgrades are constructed.
All of these findings assume no TRTP delay associated with the pending Biological Opinion from the USFWS. Any delays to TRTP based on the Biological Opinion or on other permitting and licensing issues will impact the conclusions in this report and may impact the Project in-service date.
This conclusion is based on the estimated time for engineering, licensing, procurement, and construction of a typical project. Schedule durations may change due to the number of projects approved and release dates. The ability to meet the IC proposed operating date is subject to constraints such as resource availability, system outage availability, and environmental windows of construction.
10. Environmental Evaluation/Permitting
Please see Section 12 of group report.
11. Upgrades, Cost Estimates and Construction schedule estimates
To determine the cost responsibility of each generation project in Transition Cluster, the CAISO developed cost allocation factors based on the individual contribution of each project (Attachment 6). The cost allocation for the Interconnection Facilities and Network Upgrades for which the Project is responsible is as follows:
PTO’S INTERCONNECTION FACILITIES
1. Transmission: Project 66 kV Generation Tie Line
Install one new 70 foot tubular steel pole (TSP) and 500 circuit feet of 954 SAC between the last Project structure and the substation dead-end rack at the Del Sur 66 kV switchyard.
2. Substations:
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Del Sur Substation Install the following equipment at 66 kV for the new 66 kV gen-tie line:
Install one 39-foot-high by 22-foot-wide 66kV line steel dead-end structure and foundations.
Install one 66 kV, 1200A, 31.5kA circuit breaker and foundation. Install two sets of 66 kV, 1200A vertically mounted, group operated
disconnect switches on the new line dead-end structure. Install one set of 66 kV, 1200A horizontally mounted, group operated
disconnect switches including 9-foot steel support structure and foundation. Install three surge arrestors. Install two 69000-115V potential transformers with 7’-2” steel pedestal
support structures and foundations. Install the following equipment at the existing MEER Building on two new 19-
inch racks: o One SEL 311C Relay o One GE D60 Relay
3. Telecommunications Install lightwave, channel, and associated equipment supporting RTU
requirements for the Project interconnection.
4. Transmission Project Licensing, and Environmental Health and Safety Obtain licensing and permits, and perform all required environmental activities for the SCE portion of the Project gen-tie line.
5. Metering Services Organization
Install a revenue metering cabinet and revenue meters required to meter the retail load at the generating facility.
The customer will provide the required metering equipment (voltage and current transformers).
6. Power System Control
Install one RTU at the generating facility to monitor typical generation elements such as MW, MVAR, terminal voltage and circuit breaker status at each generating unit and the plant auxiliary load and transmit this information to the SCE regional grid control center.
PLAN OF SERVICE RELIABILITY NETWORK UPGRADES 1. Del Sur Substation:
Engineer and install equipment to expand the 66 kV bus at Del Sur Substation: Install one 22-foot-high by 22-foot-wide 66 kV bus steel dead-end structure
and foundations. Install two 69000-115V potential transformers with 7’-2” steel pedestal support
structures and foundations. Relocate three 66 kV switch rack PTs and three (3) disconnect switches
installed on the west side of the operating bus to the east/opposite side of the operating bus. Install new steel pedestal support structures and foundations.
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Expand existing Del Sur RTU to install additional points required for the Project 66 kV gen-tie position. Modify substation layout as follows: Relocate 16-foot substation entrance gate 5-feet to the west. Relocate the driveway 5-feet to the west. Reinforce control cable trench to allow for use as part of the driveway.
Sub-transmission: Install two TSPs to raise the height of existing conductors inside Del Sur Substation for the gen-tie to cross under.
RELIABILITY NETWORK UPGRADES Below is a list of Reliability Network Upgrades with costs that have been allocated to the Project. See group report section 11 for scope details.
Short-Circuit Duty (SCD) Mitigation o Replace seven CBs and upgrade four CBs to achieve 63 kA
rating on overstressed Vincent 500 kV CBs
DELIVERY NETWORK UPGRADES No Delivery Network Upgrades have been allocated to the Project.
DISTRIBUTION UPGRADES No Distribution Upgrades have been allocated to the Project.
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Table 11.1: Upgrades, Estimated Costs, and Estimated Time to Construct Summary
Type of Upgrade Upgrade (May include the following) Description Estimated Cost x 1000
Estimated
Time to Construct
(Note 3)
PTO’s Interconnection
Facilities (Note 1)
Transmission, Substation, Telecommunications, Power System Control, Real Properties, Transmission Projects Licensing, and Environmental Health and Safety
Non-network facilities needed to
enable interconnection
$3,400 24 Months
Plan of Service Reliability Network
Upgrades Transmission, Substation
Direct Assigned Network upgrades needed to enable interconnection.
$1,792 24 Months
Reliability Network
Upgrades SPS, Substation
Allocated Network upgrades needed to
maintain system Reliability
$316 24 Months
Delivery Network
Upgrades
None Network upgrades
needed to support Full Delivery, if requested
$0 N/A
Distribution Upgrades
(Note 2)
None Non-CAISO SCE Distribution Facilities $0 N/A
Total $5,508 24 Months
Note 1: The Interconnection Customer is obligated to fund these upgrades and will not be reimbursed.
Note 2: These upgrades are not identified in ISO tariff, and are not reimbursable.
Note 3: The estimated time to construct (ETC) is for a typical project; schedules duration may change due to number of projects approved and release dates. Stacked projects impact resources, system outage availability, and environmental windows of construction. Assumption is SCE will need to obtain CPUC licensing and regulatory approvals prior to design, procurement and construction of the proposed facilities required to serve the interconnection customer and prerequisite facilities are in-service.
12. Study Caveats
12.1 Plan of Service The Plan of Service developed for the Project is based on the data submittals provided for each specific project in the cluster group and will serve as the basis for developing the LGIA and for permitting purposes. However, the final Plan of Service is subject to change based upon completion of preliminary and final engineering, identification of field conditions, and compliance with applicable environmental and permitting requirements.
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12.2 Customer’s Technical Data The study accuracy and results for the Phase II Study are contingent upon the accuracy of the technical data provided by the Interconnection Customer. Any changes from the data provided could void the study results. 12.3 Study Impacts on Neighboring Utilities Results or consequences of this Phase II Interconnection Study may require additional studies, facility additions, and/or operating procedures to address impacts to neighboring utilities and/or regional forums. For example, impacts may include but are not limited to WECC Path Ratings, short circuit duties outside of the CAISO Controlled Grid, and sub-synchronous resonance (SSR). 12.4 Relocations and Other Use of SCE Facilities The Interconnection Customer is responsible for all costs associated with necessary relocation of any SCE facilities as a result of this project and acquiring all property rights necessary for the Interconnection Customer’s Interconnection Facilities, including those required to cross SCE facilities and property. The relocation of SCE facilities or use of SCE property rights shall only be permitted upon written agreement between SCE and the Interconnection Customer. Any proposed relocation of SCE facilities or use of SCE property rights may require a separate study and/or evaluation to determine whether such use may be accommodated, and any associated cost would be non-refundable. 12.5 SCE Interconnection Handbook The Interconnection Customer shall be required to adhere to all applicable requirements in the SCE Interconnection Handbook. These include, but are not limited to, all applicable protection, voltage regulation, VAR correction, harmonics, switching and tagging, and metering requirements. 12.6 Western Electricity Coordinating Council (WECC) Policies The Interconnection Customer shall be required to adhere to all applicable WECC policies including, but not limited to, the WECC Generating Unit Model Validation Policy. 12.7 System Protection Coordination Adequate Protection coordination will be required between SCE-owned protection and Interconnection Customer-owned protection. If adequate protection coordination cannot be achieved, then modifications to the Interconnection Customer-owned facilities (i.e., Generation-tie or Substation modifications) may be required to allow for ample protection coordination 12.8 Standby Power and Temporary Construction Power The Phase II Study does not address any requirements for standby power or temporary construction power that the Project may require prior to the in-service date of the interconnection facilities. Should the Project require standby power or temporary construction power from SCE prior to the in-service date of the interconnection facilities, the IC is responsible to make appropriate arrangements with SCE to receive and pay for such retail service.
12.9 Construction Schedule The estimated time to construct (ETC) is for a typical project; schedules duration may change due to number of projects approved and release dates. Stacked projects impact resources, system outage availability, and environmental windows of construction.
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Assumption is SCE will need to obtain CPUC licensing and regulatory approvals prior to design, procurement and construction of the proposed facilities required to serve the interconnection customer and prerequisite facilities are in-service. 12.10 Telecommunication Assumptions The cost for telecommunication facilities that were identified as part of the IC’s Interconnection Facilities was based on an assumption that these facilities would be sited, licensed, and constructed by SCE as opposed to the IC doing this work. In addition, the telecommunication requirements for SPS were assumed based on tripping of the generator breaker as opposed to tripping the circuit breakers at the SCE substation. Any changes in these assumptions may affect the cost and schedule for the identified telecommunication facilities.
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Attachment 1
Generator Machine Dynamic Data
A user defined model xtxgtpv.p was provided by the Interconnection Customer for dynamic simulation. The parameters associated with the user defined model are listed below:
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Attachment 2
Dynamic Stability Plots
Please refer to Appendix F of the Group Report.
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Attachment 3
SCE Interconnection Handbook
Preliminary Protection Requirements for Interconnection Facilities are outlined in the SCE Interconnection Handbook.
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Attachment 4
Short Circuit Calculation Study Results
Please refer to Appendix H of the Group Report.
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Attachment 5
Deliverability Assessment Results
Please refer to Appendix I of the Group Report.
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Attachment 6
Allocation of Network Upgrades for Cost Estimates
Upgrades Type Needed For Total Cost
($1000) Cost Share
Allocated Cost
($1000) Vincent Circuit Breaker Reliability Short circuit duty mitigation $17,337 1.83% $316 Plan of Service Reliability Interconnection & telecom $1,792 100% $1,792
Total $2,108
EXHIBIT 5
Songzhe Zhu
Sr. Regional Transmission Engineer
Stakeholder Conference Call
March 19, 2010
East Kern Wind Resource Area (EKWRA) 66kV Reconfiguration
Agenda
� Scope of East Kern Wind Resource Area (EKWRA) 66kV reconfiguration project
� Impact to the bulk system
� Open discussion� Project schedule� Potential generation outage caused by EKWRA construction� Potential consequences for connected generators and
customers in interconnection process� Other concerns
� Next Step
Slide 2
Slide 3
Project Proponent: SCE
Type of Project: reliability
Needs: NERC Category A/B/C violations (2011)
� Category A overloads (on-peak & off-peak)
� Category B voltage collapse and transient voltage dip (off-peak)
� Category C overloads and voltage collapse(on-peak & off-peak)
Project Scope
� Separate the existing Antelope – Bailey 66 kV system into two systems.
� The northern system will be served radially from Windhub Substation.
Costs
� < $20M under TAC recovery for the southern Antelope area
� > $50M non-TAC recovery for the northern Windhub area
Expected In-Service: December 31, 2013; some elements may be advanced
Interim Solution: OP-068
Summary of East Kern Wind Resource Area 66 kV Reconfiguration (EKWRA) Project
System configuration post-EKWRA project
� Northern 66kV system radially served from Windhub
� Antelope – Bailey 66kV system remains parallel to the bulk system
� Three normally opened (n.o.) tie lines between the northern system and Antelope – Bailey system:� Gorman (n.o.) – Kern River� Antelope – Cal Cement (n.o.) – Rosamond� Corum (n.o.) – Goldtown (n.o.) - Rosamond
Slide 4
System configuration post-EKWRA project (Cont.)
� Substations in the Northern 66kV system� Breeze, Cal Cement, Correction, Corum, Cummings, Goldtown,
Havilah, Loraine, Monolith, Northwind, Walker Basin
� Lines in the Northern 66kV system� Windhub – Cal Cement� Windhub – Cal Cement – Monolith� Windhub – Goldtown – Midwind – Monolith – Morwind� Windhub – Enwind – Canwind – Varwind� Windhub – Flowind – Dutchwind� Cal Cement – Windpark� Arbwind – Monolith� Monolith – Loraine – Walker Basin – Havilah – Borel� Monolith – Breeze� Monolith – Cummings – Correction – Kern River
Slide 5
System configuration post-EKWRA project (Cont.)
� Existing Generation in the Northern 66kV system� Arbwind, Canwind, Dutchwind, Enwind, Flowind, Kern River,
Midwind, Morwind, Northwind, Oakwind, Southwind, Zondwind
� LGIP/SGIP projects in the Northern 66kV system currently in ISO Queue� Queue # 79, 86B, 91, 348, 349, 521
Slide 6
System configuration post-EKWRA project (Cont.)
Slide 7
Impact to the bulk system
Slide 8
Impact to the bulk system (Cont.)
� Impact to south of Antelope flow is small
� Net generation out of Windhub may be reduced under peak conditions by EKWRA project� 2013 1-in-10 load forecast for the Northern 66kV system is
106MW� Existing wind output under summer peak condition is low
� Net generation out of Windhub may be increased under off-peak conditions by EKWRA project� Generation exceeds the loads in the Northern 66kV system
Slide 9
Open Discussion
Slide 10
� Project schedule
� Potential generation outage during construction of EKWRA
� Potential consequences for connected generators and customers in interconnection process
� Change in POI; treatment of line loss
� Other concerns
Next Step
� The project was approved by ISO management to mitigate reliability problems.
� The ISO will analyze any policy issues triggered.
Slide 11
CERTIFICATE OF SERVICE
I hereby certify that I have this day served the foregoing document upon each
person designated on the official service list compiled by the Secretary in these
proceedings.
Dated at Rosemead, California, this 17th day of January, 2014.
/s/ Rodger Torres Rodger Torres, Case Analyst SOUTHERN CALIFORNIA EDISON CO. 2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-3902