Application No.: A.20-07-008 Exhibit No.: SCE-01 Witnesses: N. Woodward

(U 338-E)

Recovery Bond Financing

Policy Overview

Before the

Public Utilities Commission of the State of California

Rosemead, California July 8, 2020

Direct Testimony Supporting Southern California Edison's Application for Recovery Bond Financing: Policy Overview

Table Of Contents

Section Page Witness

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I.  INTRODUCTION .............................................................................................1 N. Woodward 

II.  THE SECURITIZATION ..................................................................................3 

A.  Capital Structure ....................................................................................6 

III.  OVERVIEW OF TESTIMONY ........................................................................6 

1.  Exhibit SCE-01 Policy Overview (N. Woodward, SCE) ...........................................................................................7 

2.  Exhibit SCE-02: Background on Utility Securitization (E. Chang, Barclays) ...........................................7 

3.  Exhibit SCE-03: Transaction Overview (B. Pang, SCE) ...........................................................................................7 

4.  Exhibit SCE-04: Customer Benefits (S. Deana, SCE) ...........................................................................................8 

5.  Exhibit SCE-05: Taxation (M. Childs, SCE) .............................9 

6.  Exhibit SCE-06: Ratemaking (R. Thomas, SCE) ......................9 

7.  Exhibit SCE-07: Proposal for Future Financing Orders (C. Peterman, SCE) ........................................................9  

8.  Testimony Appendix A: Statements of Qualifications 

Direct Testimony Supporting Southern California Edison's Application for Recovery Bonds Financing: Policy Overview

List Of Tables

Table Page

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Table II-1 Capital Expenditures Authorized by Decision 20-04-013 ..........................................................4 

Table II-2 Initial AB 1054 CapEx Authorized Pursuant to Decision 20-04-013 ........................................5 

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I. 1

INTRODUCTION 2

This Exhibit SCE-01 introduces Southern California Edison’s (“SCE’s”) proposal to finance an 3

initial amount of fire risk mitigation capital expenditures approved by the California Public Utilities 4

Commission (the “Commission”) through the issuance of Recovery Bonds backed by a Fixed Recovery 5

Charge.1 The expenditures (“Initial AB 1054 CapEx”) are the first tranche of SCE capital expenditures 6

that are subject to Assembly Bill 1054 (“AB 1054”) and Public Utilities Code Section 8386.3(e).2 SCE 7

also seeks to establish a streamlined process for Commission authorization of additional bonds to 8

recover additional costs and expenses related to catastrophic wildfires including the remaining capital 9

expenditures subject to AB 1054 and Section 8386.3(e), in each case as they are found to be just and 10

reasonable by the Commission. 11

The Securitization is pursuant to AB 1054 and Section 850(a)(2), which permit securitization of 12

“costs and expenses related to catastrophic wildfires” that the Commission has determined to be just and 13

reasonable, including fire risk mitigation capital expenditures described in Section 8386.3(e).3 Section 14

8386.3(e) applies to the first $1.575 billion in approved fire risk mitigation capital expenditures that 15

SCE incurs (referred to as Total AB 1054 CapEx).4 Section 8386.3(e) precludes SCE from including 16

Total AB 1054 CapEx in equity rate base (thereby preventing SCE’s shareholders from earning an 17

equity rate of return on such expenditures), but it expressly authorizes SCE to finance Total AB 1054 18

1 For this and the remaining Exhibits, capitalized terms used but not defined in the Exhibit have the meaning

attributed in the Application or other Exhibits.

2 For this and the remaining Exhibits, unless otherwise noted, all references to “Section” are to the California Public Utilities Code.

3 Pub. Util. Code § 850(a)(2).

4 See Pub. Util. Code § 8386.3(e) (referencing “the first five billion dollars ($5,000,000,000) expended in aggregate by large electrical corporations on fire risk mitigation capital expenditures included in the electrical corporations’ approved wildfire mitigation plans”); id. § 3280(n) (allocating 31.5 percent of the $5 billion in aggregate capital expenditures to SCE, thus yielding an SCE share of $1.575 billion).

2

CapEx and debt financing costs related to those capital expenditures through issuance of a financing 1

order.5 2

Consistent with these provisions, the Securitization seeks recovery of: (1) Initial AB 1054 CapEx 3

in the amount of $326,981,000; (2) the debt financing costs of the Initial AB 1054 CapEx, which is 4

presently estimated to be $4,805,170; and (3) financing costs (as defined in Section 850(b)(4)) 5

associated with the issuance of the Recovery Bonds, including credit enhancement costs, if any (as used 6

herein, “Upfront Financing Costs”), which are presently estimated to be $5,355,143 (collectively, the 7

“Authorized Amount”).6 The capital expenditures were incurred under a Commission-approved wildfire 8

mitigation plan, the Grid Safety and Resiliency Program (“GSRP”), and have already been determined 9

to be just and reasonable by the Commission.7 The Securitization also satisfies the other requirements 10

of Section 850.1(a)(1)(A). Issuance of the Recovery Bonds would benefit customers8 by providing 11

low-cost financing for approved wildfire mitigation capital expenditures. As explained more fully in 12

Exhibit SCE-04, the use of securitization to recover these expenditures compares favorably to the use of 13

traditional utility financing mechanisms, including financing through SCE’s authorized capital structure 14

in the absence of a return on common equity, reducing the overall costs to SCE’s electrical customers. 15

The public interest is likewise served by financing at the lowest cost achievable Commission-approved 16

measures to reduce the risk of catastrophic wildfires. 17

In addition to the Securitization, SCE intends to seek future financing orders to securitize other 18

Section 850 et seq. costs and expenses, including the portion of SCE’s $1.575 billion of Total AB 1054 19

that remains after deducting the Initial AB 1054 CapEx at issue in this Application. To streamline future 20

5 Pub. Util. Code § 8386.3(e).

6 Use of the securitization proceeds is discussed in Exhibits SCE-03 and SCE-06.

7 D.20-04-013.

8 As used herein and in the remaining Exhibits of testimony, references to “customer” include the term “consumer” as defined in Section 850(b)(3) and as used in Section 850.1(b). See Pub. Util. Code § 850(b)(3) (“‘Consumer’ means any individual, governmental body, trust, business entity, or nonprofit organization that consumes electricity that has been transmitted or distributed by means of electric transmission or distribution facilities, whether those electric transmission or distribution facilities are owned by the consumer, the electrical corporation, or any other party.”).

3

financings, SCE proposes to submit requests for additional financing orders via Tier 3 advice letters, 1

which it will submit after the Commission makes a just and reasonable determination regarding the costs 2

and expenses to be securitized. In reviewing SCE’s submission, the Commission would issue an 3

additional financing order by way of a resolution if it determines that the relevant amounts or costs are 4

recovery costs within the meaning of Public Utilities Code Section 850(a)(10) as well as making any 5

other necessary findings. 6

II. 7

THE SECURITIZATION 8

SCE’s proposed, initial Securitization has its genesis in the GSRP, which is a comprehensive 9

wildfire mitigation program that SCE designed to address California’s increasing wildfire risk. 10

On September 10, 2018, SCE filed an application seeking Commission approval to record and 11

recover costs associated with the GSRP.9 On July 31, 2019, SCE entered a settlement with various 12

interested parties (the “GSRP Settlement”), which authorized a 2018-2020 capital expenditure forecast 13

of $407 million (expressed in 2018 constant dollars) and a 115% reasonableness threshold for capital 14

expenditures related to the Wildfire Covered Conductor Program (“WCCP”). On April 16, 2020, the 15

Commission issued Decision 20-04-013, which adopts the GSRP Settlement in its entirety. In approving 16

the GSRP Settlement, the Commission expressly concluded that the capital expenditures authorized by 17

the agreement are “reasonable and supported by the record in this proceeding.”10 18

Table II-1 summarizes total authorized direct capital expenditures under the GSRP Settlement 19

and Decision 20-04-013, which are adjusted from 2018 constant dollars to nominal dollars and increased 20

to reflect the 115 percent reasonableness threshold for WCCP.11 As Table II-1 illustrates, total 21

authorized GSRP direct capital expenditures, in nominal dollars, are approximately $476.3 million. As 22

of the date of this Application, SCE has incurred GSRP capital expenditures in excess of the $476.3 23

9 A. 18-09-002.

10 D. 20-04-013 at p. 49.

11 As set forth in Advice 4197-E-A.

4

million threshold but those additional expenditures above the threshold remain subject to Commission 1

review and approval. 2

Table II-1 Capital Expenditures Authorized by Decision 20-04-013

As summarized in Table II-2 below, SCE incurred $304.5 of the $476.3 million in authorized 3

direct capital expenditures on or after August 1, 2019, bringing those expenditures within the Equity 4

Rate Base Exclusion set forth at Section 8683.3(e).12 In addition to the $304.5 million in direct capital 5

expenditures, SCE incurred approximately $21.6 million in related Allowance for Funds Used During 6

Construction (AFUDC) and capitalized overhead expense (also referred to as indirect capital 7

expenditures), which brings the total capital additions, or Initial AB 1054 CapEx, to $327.0 million. 8

12 As applied to SCE, the Equity Rate Bar Exclusion set forth in Section 8683.3(e) applies to “the first [$1.575

billion] . . . expended . . . on fire risk mitigation capital expenditures included in [SCE’s] approved wildfire mitigation plans.” Pub. Util. Code § 8693.3(e); see also id. § 3280(n) (allocating 31.5 percent of the $5 billion in aggregate capital expenditures to SCE, thus yielding an SCE share of $1.575 billion). Section 8683.3(e) does not define the term “first expended” for purposes of determining which approved capital expenditures count towards the $1.575 billion. But the Commission has previously construed the Equity Rate Base Exclusion as applying to approved capital expenditures made on or after August 1, 2019, which is the first day of the first month following AB 1054’s effective date. (See D.20-04-013, p. 49, Conclusion of Law No. 6). SCE is currently tracking Initial AB 1054 CapEx in a subaccount to its GSRP Balancing Account entitled “GSRP Costs Subject to AB 1054.”

Description 2018‐2020 (2018$) 

2018‐2020 (Nominal $) 

Nominal with 115% WCCP Threshold 

Wildfire Covered Conductor   $                      284,842    $                      303,122    $                      348,591  

Non‐WCCP‐Capital   $                      122,448    $                      127,702    $                      127,702  

Total Capital   $                      407,290    $                      430,824    $                      476,293  

5

Table II-2 Initial AB 1054 CapEx Authorized Pursuant to Decision 20-04-013

SCE’s proposed initial Securitization seeks recovery of Initial AB 1054 CapEx and debt 1

financing costs related to those capital expenditures. AB 1054 expressly authorizes the Commission to 2

issue a financing order permitting SCE to recover these expenditures through the issuance of bonds 3

backed by a Fixed Recovery Charge on customer bills. Specifically, Section 850(a)(2) identifies “fire 4

risk mitigation capital expenditures identified in subdivision (e) of section 8386.3” as costs and expenses 5

that may be securitized.13 And Section 8386.3(e) states that an electrical corporation may recover 6

through a financing order both fire risk mitigation capital expenditures subject to the Equity Rate Base 7

Exclusion and “the debt financing costs of these fire risk mitigation capital expenditures.”14 8

No separate reasonableness review is required for the Initial AB 1054 CapEx because the 9

Commission has already determined that the Initial AB 1054 CapEx expenditures are just and 10

reasonable under Section 451. In Decision 20-04-013, the Commission determined that SCE’s 11

forecasted GSRP capital expenditures were “reasonable and supported by the record in this 12

proceeding.”15 13

13 Pub. Util. Code § 850(a)(2).

14 Pub. Util. Code § 8386.3(e).

15 D. 20-04-013 at p. 49. Decision 20-04-013 approved a settlement of, and closed, SCE’s Application (A.18-09-002), which requested authority for recovery of GSRP costs and expenses under, among other provision, Section 451 of the Public Utilities Code. In approving the GSRP Settlement, the Commission found that GSRP costs and expenses were “reasonable” up to the stated thresholds and authorized SCE to recover such costs and expenses without further reasonableness review. D. 20-04-013 at 49–50. The Commission further found that permitting recovery by SCE was “consistent with the law and public interest” and would not “contravene[] any statute.” Id. at 49.

Description  $000 Total Direct Capital Expenditures Authorized by D.20‐04‐013   $                476,293  Less Spent Prior to August 1, 2019 (Not Subject to AB 1054)   $                171,838  

Authorized Direct CapEx Subject to AB 1054   $                304,455    Authorized Direct CapEx Subject to AB 1054   $                304,455  Plus AFUDC and Overhead   $                   22,525  

Total Capital Additions (Initial AB 1054 CapEx)   $                326,981  

6

A. Capital Structure 1

In connection with the Securitization, SCE proposes to remove from SCE’s ratemaking capital 2

structure the securitized debt.16 The special purpose entity (“SPE”) that issues the securitized debt—not 3

SCE—will have the legal obligation to pay principal and interest on the debt and such repayment will be 4

supported by a separate and dedicated revenue stream from customers. Thus, the securitized debt is not 5

properly considered SCE debt as part of its capital structure. However, for financial reporting purposes, 6

the securitized debt will be consolidated and recorded as a liability on SCE’s consolidated financial 7

statements. Because Section 8386.3(e) requires that Total AB 1054 CapEx be excluded from SCE’s 8

“equity rate base” and these accounting entries do not properly reflect SCE’s debt and equity balances 9

that finance rate base, SCE believes it appropriate to exclude from SCE’s ratemaking capital structure 10

the securitized debt and requests that the Commission approve these adjustments in connection with the 11

application.17 12

III. 13

OVERVIEW OF TESTIMONY 14

SCE’s testimony in support of this Application is comprised of seven exhibits, which are 15

summarized as follows: 16

16 The most recent Cost of Capital Decision, D.19-12-056, set SCE’s authorized ratemaking capital structure as

consisting of 52 percent common equity, 43 percent long-term debt, and 5 percent preferred equity. SCE currently has less than 52 percent equity on its financial books, primarily because the liabilities associated with the 2017 and 2018 wildfires resulted in non-cash charges to equity on its balance sheet, although SCE has received a narrow waiver to exclude these non-cash charges when calculating compliance with the requirement to maintain this common equity level. See D.19-12-056, Decision On Test Year 2020 Cost Of Capital For The Major Energy Utilities (December 19. 2019).

17 This exclusion would apply equally with respect to the ratemaking capital for purposes of the holding company conditions (see D.88-01-063) as well as the Affiliate Transaction Rules (see D.06-12-029 (Rule IX.B.)), including in connection with any dividends. Alternatively, consistent with D.20-05-005, the Commission could issue a waiver from compliance with the authorized capital structure for these same purposes and associated with the life of the Recovery Bonds.

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1. Exhibit SCE-01 Policy Overview (N. Woodward, SCE) 1

2. Exhibit SCE-02: Background on Utility Securitization (E. Chang, Barclays) 2

The proposed Recovery Bonds are part of a category of financial instruments generally described 3

as asset-backed securities. This Exhibit, sponsored by Eric Chang, Managing Director of Securitized 4

Products Origination at Barclays, provides general background on asset-backed securities, as well as a 5

more detailed review of the market for utility securitizations. After providing an overview of the history 6

of this market, it surveys the basic structuring principles of securitization financing, with a focus on the 7

considerations relevant to utility securitizations. Exhibit SCE-02 also discusses the size of the 8

asset-backed securities market and the pricing mechanics, marketing strategies, and typical fees and 9

expenses associated with these transactions. Finally, Exhibit SCE-02 discusses the anticipated treatment 10

of the Securitization by rating agencies, including the importance and adequacy of the proposed 11

financing order to achieving the highest possible ratings as well as rating agencies’ treatment of 12

securitizations in rating the utility’s corporate credit. Barclays is SCE’s structuring advisor for this 13

Securitization. 14

3. Exhibit SCE-03: Transaction Overview (B. Pang, SCE) 15

This Exhibit provides an overview of the proposed Securitization and explains considerations 16

that determined the transaction’s structure. These considerations include the need to structure the 17

transaction to obtain the highest possible rating from rating agencies, as well as tax and accounting 18

considerations. Exhibit SCE-03 also describes the characteristics, servicing, transaction costs, and use of 19

net proceeds of the Recovery Bonds. And it describes the proposed collection and remittance of Fixed 20

Recovery Charges. As discussed more fully in Exhibit SCE-03, SCE proposes that it recover the 21

Authorized Amount through the issuance of Recovery Bonds backed by nonbypassable Fixed Recovery 22

Charges to be collected from SCE’s customers. The Recovery Bonds will be issued in one or more series 23

by one or more legally separate SPEs, which are wholly-owned subsidiaries of SCE. These SPE(s) will 24

transfer the Recovery Bond proceeds to SCE in a true sale in exchange for the right to receive Fixed 25

Recovery Charges in amounts sufficient to pay debt service on the Recovery Bonds as well as the costs 26

8

of servicing the Recovery Bonds and supporting the operations of the SPE (referred to as Ongoing 1

Financing Costs). The SPE(s) will also receive the right to obtain adjustments to the Fixed Recovery 2

Charges as necessary to ensure timely repayment of the Recovery Bonds. 3

4. Exhibit SCE-04: Customer Benefits (S. Deana, SCE) 4

This Exhibit establishes that the Securitization satisfies the requirements for issuance of recovery 5

bonds set forth in Section 850.1(a)(1)(A). That section states that, upon receiving an application for a 6

financing order, the Commission shall issue the financing order if it finds the following: (a) The costs to 7

be reimbursed have been found to be just and reasonable under Section 451 or 451.1; and (b) issuance of 8

the bonds, including all material terms and conditions: (1) is just and reasonable; (2) is consistent with 9

the public interest; and (3) reduces, to the maximum extent possible, the rates on a present value basis 10

that customers would pay as compared to use of traditional utility financing.18 11

Exhibit SCE-04 establishes that the Recovery Bonds will reduce customer rates on a present 12

value basis as compared to traditional utility financing, including financing using SCE’s authorized 13

capital structure in the absence of a return on common equity. First, as required by statute, Exhibit 14

SCE-04 compares the revenues that SCE would need to collect from customers to recover the Initial AB 15

1054 CapEx using traditional ratemaking at SCE’s authorized rate of return on rate base (7.68%), as 16

opposed to financing through securitized debt. Based upon the market conditions described therein, 17

Exhibit SCE-04’s calculations demonstrate a present value difference of approximately $173.5 through 18

issuance of securitized debt rather than traditional financing for Initial AB 1054 CapEx, reflecting 19

substantial savings to SCE’s customers through securitization. 20

Second, Exhibit SCE-04 also compares the revenue required to finance Initial AB 1054 CapEx 21

using SCE’s authorized capital structure in the absence of a return on common equity (4.84%). The 22

comparison without return on common equity also shows a significant present value difference and, 23

hence, savings for SCE customers through securitized debt financing. 24

18 Pub. Util. Code § 850.1(a)(1)(A).

9

5. Exhibit SCE-05: Taxation (M. Childs, SCE) 1

This Exhibit describes the tax implications of the proposed securitization. Specifically, 2

securitization-related customer charges are recognized as income to the utility as they are collected over 3

time. While SCE may apply to the CPUC to recover taxes associated with the charges from customers, 4

SCE anticipates that such taxes will be offset by tax benefits associated with the securitization obviating 5

the need for a fixed recovery tax amount. Since these tax benefits will be realized earlier in time than the 6

taxable revenue collected from customers, there will be a net cash flow surplus in early years. The tax 7

savings resulting from the timing of these two cash flows is referred to as accumulated deferred income 8

taxes (“ADIT”), that is calculated on a net present value basis. The ADIT savings will be reduced and 9

may be eliminated by net cash flow deficits in later years. As discussed in Exhibit SCE-03 and 06, SCE 10

proposes to track these tax implications outside of the securitization using standard ratemaking 11

mechanisms. SCE may use this same approach for other securitizations described in Exhibit SCE-07, but 12

may also change how taxes are incorporated in future securitizations based on the facts and 13

circumstances specific to those transactions. 14

6. Exhibit SCE-06: Ratemaking (R. Thomas, SCE) 15

This Exhibit describes SCE’s proposed rate design, cost allocation among customers, and 16

illustrative rates for the Fixed Recovery Charges that will be sold and pledged to secure the Recovery 17

Bonds. The proposed ratemaking mechanisms described in Exhibit SCE-06 are necessary to ensure 18

repayment of the Recovery Bonds and accurate accounting for associated transactions. Exhibit SCE-06 19

also describes how SCE proposes to present the Fixed Recovery Charges on customer bills. 20

7. Exhibit SCE-07: Proposal for Future Financing Orders (C. Peterman, SCE) 21

This Exhibit discusses SCE’s proposal that the Commission adopt a streamlined procedure for 22

the issuance of future financing orders authorizing the recovery of additional Section 850 et seq. costs 23

and expenses, including fire risk mitigation capital expenditures identified in Section 8386.3(e). For 24

example, this initial Application contemplates securitization of $326,981,000 million in Initial AB 1054 25

CapEx. If approved, that would leave a remainder of $1.248 billion of Total AB 1054 CapEx to be 26

10

securitized through future financing orders following a determination by the Commission that the 1

underlying capital expenditures are just and reasonable. 2

Consistent with the Commission’s authority to “establish procedures for the expeditious 3

processing of an application for a financing order,”19 SCE proposes in SCE-07 that as part of any 4

financing order approving the Securitization, the Commission authorize a process by which SCE may 5

submit requests for additional financing orders via a Tier 3 advice letter. SCE would submit such a 6

request subsequent to a reasonableness determination by the Commission regarding additional costs and 7

expenses to be securitized. After reviewing SCE’s submission, if it determines that the relevant amounts 8

or costs are recovery costs within the meaning of Public Utilities Code Section 850(a)(10) the 9

Commission would issue an additional financing order by way of a resolution and in that resolution 10

make any other necessary findings for the issuance of additional recovery bonds. 11

Exhibit SCE-07 also describes the applicability of findings and testimony from this proceeding 12

to subsequent Tier 3 advice letter requests for additional financing orders and the process whereby SCE 13

will provide supplemental information for any material changes from this Application. 14

8. Testimony Appendix A: Statements of Qualifications 15

This Appendix sets forth the qualifications of each of the witnesses sponsoring the testimony in 16

support of SCE’s Application.17

19 Pub. Util. Code § 850.1(g).

Application No.: A.20-07-008 Exhibit No.: SCE-02 Witnesses: E. Chang (Barclays)

(U 338-E)

Recovery Bond Financing

Background on Utility Securitization

Before the

Public Utilities Commission of the State of California

Rosemead, California July 8, 2020

Direct Testimony Supporting Southern California Edison's Application for Recovery Bond Financing: Background on Utility Securitization

Table Of Contents

Section Page Witness

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I.  PURPOSE OF TESTIMONY ............................................................................1 E. Chang (Barclays) 

II.  SECURITIZATION BACKGROUND AND OVERVIEW OF THE SECURITIZATION MARKET .........................................................................1 

III.  A DESCRIPTION OF UTILITY TRANSACTION STRUCTURES ...............9 

IV.  DESCRIPTION OF UTILITY SECURITIZATION BONDS STRUCTURING SALE AND PRICING CONSIDERATIONS ....................20 

V.  DESCRIPTION OF THE RATING AGENCY PROCESS.............................23 

VI.  DESCRIPTION OF THE MARKETING PROCESS FOR UTILITY SECURITIZATION BONDS ..........................................................................28 

VII.  UPFRONT FINANCING COSTS (BOND ISSUANCE COSTS) ..................31 

VIII.  CONCLUSION ................................................................................................33 

Direct Testimony Supporting Southern California Edison's Application for Recovery Bond Financing: Direct Testimony Supporting Southern California

Edison's Application for Wildfire Recovery Bond Financing: Background on Utility Securitization

List Of Tables

Table Page

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Table II-1 Historical U.S. ABS (2016-2019) ...............................................................................................3 

Table II-2 Historical U.S. Utility ABS, as of June 30, 2020 .......................................................................4 

Table II-3 Recent Utility Securitization Annual Servicing Fee Percentages .............................................14 

Table III-4 Recent Utility Securitization Annual Administration Fees .....................................................19 

Table VII-5 Recent Utility ABS Issuance Costs ........................................................................................32 

1

I. 1

PURPOSE OF TESTIMONY 2

Q: What is the purpose of your testimony? 3

A: The purpose of my testimony is to: (i) provide a brief history and overview of the 4

securitization market, including the structural features of commercial securitization transactions; 5

(ii) describe key structural and security features of utility securitizations; (iii) discuss structuring, 6

sale, and pricing considerations of utility securitizations; (iv) describe the rating agency process 7

and considerations for utility securitizations; (v) describe the marketing process for utility 8

securitizations; (vi) describe the costs of issuance associated with utility securitizations 9

generally, and specifically these estimated costs for Southern California Edison Company’s 10

(“SCE”) initial recovery bond issuance; and (vii) provide concluding remarks to the testimony. 11

II. 12

SECURITIZATION BACKGROUND AND OVERVIEW OF THE SECURITIZATION 13

MARKET 14

Q: Please provide a brief history of the securitization market. 15

A: The first securitizations in the United States were secured by pools of mortgage loans 16

when institutions such as the Government National Mortgage Association created trusts to hold 17

pools of residential home mortgage loans and issue mortgage-backed securities that were sold to 18

investors. Principal and interest due on the mortgage-backed securities was paid from the cash 19

flows from the underlying mortgages securing the transactions. 20

The securitization market has subsequently expanded in both size and the number of asset 21

classes that have been securitized. Today, the asset-backed securities (“ABS”) market is seen as 22

an important, well-established and efficient means to raise debt financing for companies across 23

various industries and asset classes. Common consumer ABS asset classes that are securitized 24

include credit cards, auto loans and leases, equipment loans and leases, student loans, and 25

2

consumer personal loans. In 2019, the ABS market saw a total issuance volume of $236.4 1

billion1. 2

Utility securitizations first came to market in the mid-1990s. In 1995, Puget Sound 3

Power and Light Company (“Puget”) issued the first utility securitization with $202 million of 4

pass-through certificates to recover conservation expenditures approved by the Washington 5

Utilities & Transportation Commission. The bonds were secured by Puget’s right to bill and 6

collect securitization charges from its customers to recover the approved conservation 7

expenditures. In 1996, the State of California signed into law The Electric Utility Industry 8

Restructuring Act (“AB 1890”), which restructured the electric services industry in the state to 9

make the generation of electricity competitive in California. As part of the legislation, the 10

California Public Utilities Commission (“CPUC”) committed to giving electric utilities the 11

opportunity to recover stranded costs. Following AB 1890 coming into law, SCE, Pacific Gas & 12

Electric Company (“PG&E”), San Diego Gas & Electric Company, and Sierra Pacific Power 13

Company all issued utility securitizations between 1997 and 1999 for a total approximate volume 14

of $6 billion. The most recent California utility securitizations were two 2005 transactions 15

issued by PG&E totaling approximately $2.7 billion. Utility securitizations have ranged from 16

approximately $35 million to $4 billion in offered size. In total, approximately $56 billion of 17

utility securitizations have been successfully issued in the ABS market across utilities and states, 18

with approximately $19 billion issued since the last California utility securitization in 20052. 19

The utility securitization market has historically offered securitizations that are issued to recover 20

costs such as rate stabilization, stranded costs, pollution control costs, and storm recovery costs. 21

Q: Please provide a description of the securitization market. 22

A: The securitization market has remained steady since the financial crisis, with issuances 23

peaking at $240 billion in 2018 and then slightly down in 2019 at $236 billion as shown in Table 24

1 See Table II-1 for details on ABS issuance volume by asset class.

2 See Table II-2 for full transaction details.

3

II-1 below. While the beginning of 2020 saw significant momentum from issuers and investors, 1

the spread of the COVID-19 virus has had a short-term negative impact on the new issuance 2

pipeline for securitizations. Although there were no ABS issuances from March 11th until 3

April 14th, the securitization market has since re-opened to significant investor demand, but it is 4

expected that the total issuance volume for 2020 will be down materially compared to previous 5

years. The typical non-utility securitization size can range from approximately $200 million to 6

greater than $2.0 billion. There have been a number of large historical transactions in the 7

standard (non-utility) ABS market. 8

Table II-1 Historical U.S. ABS (2016-2019)

Q: Please describe the size of the utility securitization market and investor base. 9

A: Across 74 transactions, over $55 billion of utility securitization bonds have been issued 10

successfully by electric utility companies across the country since the sector began in 1995 as 11

shown in Table II-2 below. 12

2016 2017

Asset Class Volume ($ Billions) Asset Class Volume ($ Billions)

Auto 87.21 Auto 94.24

Consumer Loan 9.42 Consumer Loan 12.45

Credit Cards 34.61 Credit Cards 47.23

Equipment 10.33 Equipment 12.28

Other / Esoteric 35.14 Other / Esoteric 46.34

Student Loan 14.57 Student Loan 15.85

Total 191.27 Total 228.38

2018 2019

Asset Class Volume ($ Billions) Asset Class Volume ($ Billions)

Auto 103.02 Auto 109.31

Consumer Loan 11.38 Consumer Loan 15.13

Credit Cards 36.56 Credit Cards 24.26

Equipment 14.23 Equipment 19.58

Other / Esoteric 56.43 Other / Esoteric 54.58

Student Loan 18.39 Student Loan 13.50

Total 240.01 Total 236.36

4

Table II-2 Historical U.S. Utility ABS, as of June 30, 2020

5

Utility securitizations are unique as they are supported by a “statutory credit” rather than 1

commercial assets. Utility securitizations are also episodic, as they arise to address specific 2

financing needs of the electric utility market. Accordingly, the amount of utility securitizations 3

is unrelated to the overall market capacity and investor appetite for such issuances at the time. In 4

addition, there are many examples where the utility achieved its required funding target amount 5

through multiple issuances over a period of time (e.g. Long Island Power Authority in 2013, 6

2015, 2016, and 2017). The utility securitization market has seen transactions of significant size 7

such as the 1999 issuance by PEPCO totaling $4 billion, which is the largest utility securitization 8

offered to date. 9

Utility bond securitizations are a well-established asset class that are broadly understood 10

in capital markets. A diverse range of investors have participated in utility bond securitizations to 11

date, including domestic and international banks, money managers, investment advisors, 12

pensions funds, insurance companies, corporate cash managers, and different types of trust 13

funds. The bonds are able to receive high credit ratings even when the issuer has entered into 14

bankruptcy or the rating agencies have issued a downgrade of their credit, thus justifying 15

investors’ confidence in the bonds and their ability to withstand certain stressful outcomes. 16

Q: Please provide a description of the securitization process and structure in general. 17

A: General Overview and Legal / Bankruptcy Considerations. Securitization is the 18

process of financing cash flows from a specific asset or pool of assets, and issuing claims on 19

these assets, through the issuance of asset-backed securities. These securities rely solely on the 20

cash flow stream generated by the underlying asset or pool of assets, and not by the credit of the 21

originating company. For utility securitizations, the asset is the right of a utility to bill and 22

collect a securitization charge paid by the utility’s customers in its service territory, as will be 23

described in further detail in this testimony. As a result, a securitization’s credit quality and 24

ratings reflect the predictability or volatility of that associated cash flow, and the securitization is 25

able to achieve attractive financing costs and higher credit ratings (of which the highest rating is 26

AAA(sf)) than the originating company. Legal isolation (also referred to as “de-linking”) of the 27

6

credit quality of the issued ABS from the credit quality of the originating company is 1

accomplished when the originating company sells the cash flow generating asset to a 2

bankruptcy-remote Special Purpose Entity (“SPE”) in a transaction that represents a “true sale” 3

for bankruptcy purposes. This de-linking process serves to protect investors from changing 4

credit circumstances or a potential bankruptcy of the originating company. As a bankruptcy-5

remote SPE, the issuing trust needs to comply with certain independent director requirements, 6

needs to limit its purpose and the activities in which it may engage, and is typically prohibited 7

from incurring any other debt or obligations. Opinions of legal counsel that the treatment of the 8

sale of the revenue generating assets to the SPE is a “true sale” for bankruptcy purposes and that 9

the SPE is bankruptcy-remote from the sponsor (typically called a “non-consolidation” opinion) 10

are vital components in most securitizations and, as discussed below, are important 11

considerations for the rating agencies. 12

Rating Agency and Structural Considerations. In most securitizations, the issuer will 13

engage nationally recognized statistical rating organizations, otherwise known as rating agencies, 14

to evaluate the creditworthiness of the securitization and provide credit ratings on specified 15

classes of the transaction. The rating agencies typically have published methodologies for major 16

asset classes (including utility securitizations) that lay out the qualitative and quantitative 17

analysis the rating agencies conduct when reviewing a transaction. The analysis conducted by 18

the rating agencies generally includes a few broad categories, including (1) a review of the 19

originating company as sponsor and servicer, (2) analysis of the collateral, (3) historical portfolio 20

performance stress analysis, and (4) a legal review of the transaction. 21

(1) The rating agencies will review the originating company’s background and its 22

business experience as part of their due diligence. If it is a company’s first-time 23

issuance, some rating agencies require an on-site visit to the company’s offices to 24

receive a better understanding of the day-to-day operations of the company. The 25

rating agencies will also review the company’s financial statements to better 26

7

understand the financial state of the company. Additionally, the rating agencies will 1

review the originating company’s ability to service the securitized assets. 2

(2) Another part of analysis that rating agencies conduct is a review of the company’s 3

securitized assets, also known as collateral. The rating agencies will take into 4

account the composition of the collateral and will review the diversity of the obligor 5

or customer base and different trends, characteristics, and groupings applicable to the 6

collateral or asset type. If the rating agencies feel that the selected pool of loans for 7

the securitization (the typical collateral for a “commercial securitization”) are not 8

sufficiently diverse or are overly concentrated, this may impact their assessment of 9

the credit performance of the pool of loans and the assets may not be ideal for 10

securitization. 11

(3) The rating agencies also conduct an in-depth review of the credit quality of the 12

securitized assets. This consists of reviewing historical delinquencies and charge-offs 13

(defaults) of the company’s collateral portfolio as well as other performance metrics 14

that depend on the asset class. As it pertains to utility securitizations, rating agencies 15

will also analyze historic and projected forecasts of electric consumption. The rating 16

agencies create models that will run stress scenarios based on the historical and 17

projected data to determine the strengths and weaknesses of the collateral. 18

(4) The rating agencies will review the legal structure of the transactions and legal 19

opinions supporting the transactions, including the legal opinions supporting the true 20

sale and non-consolidation analyses. 21

The structural protections put in place in a securitization transaction are also an important 22

variable in the rating agency review process. The typical securitization can include multiple 23

forms of credit enhancement that enable the transaction to endure volatile economic 24

environments and achieve a higher rating. Credit enhancement may consist of a combination of 25

the following items: 26

8

‐ Overcollateralization: the transfer of securitized assets to the SPE with an aggregate 1

payment obligation that exceeds the amount necessary to repay the loan; 2

‐ Excess spread: interest earned on the assets in excess of the interest on the notes, the 3

servicing fee, and other administrative expenses; 4

‐ Subordinate classes with lower assigned credit ratings (based on the priority of 5

principal and interest payments); 6

‐ Cash reserve accounts; and/or 7

‐ A surety bond or letter of credit provided by a highly-rated financial institution. 8

The total amount of credit enhancement for a particular class of notes is decided by 9

applying incremental stressful assumptions to the projected bond cash flows. In standard 10

transactions, the senior most notes, rated AAA, require the highest level of credit enhancement 11

because of the advantage of the associated borrowing cost savings. 12

Servicing Considerations. The purpose of the servicer is to collect the payments from 13

the underlying pool of assets and transfer the collected funds to the SPE. Rating agencies are 14

particularly focused on the quality and experience of the servicer since the process of servicing is 15

complex and requires specific knowledge relating to the underlying assets. In the event of a 16

servicing default by the originating company, the executed transaction documents usually allow 17

for the bond trustee to appoint a replacement servicer. 18

Accounting and Tax Considerations. While the securitized assets in the transaction are 19

legally transferred to an SPE, US GAAP typically requires the originator to consolidate with the 20

SPE. Therefore, the assets and liabilities associated with the securitization are then consolidated 21

with the assets and liabilities of the originator for financial statement purposes. 22

From a tax perspective, two basic issues are typically considered when structuring a 23

securitization: 1) whether any income taxes are triggered in connection with the transfer of the 24

securitized assets from the originator to the SPE; and 2) whether any income taxes are triggered 25

at the SPE level from the daily ongoing activities of the SPE. 26

9

Securitizations are typically treated as debt for tax purposes, and the assets are deemed to 1

have been “pledged” to secure the originator’s debt. The “debt for tax” characterization means 2

that the securitized assets are still deemed to be paid by the originator for tax purposes, which 3

defers any possible immediate tax liability. For securitizations, taxes are payable over time as 4

the revenues are billed. For tax reasons, the originator maintains ownership of the securitized 5

assets, discloses income generated by the securitized assets, and deducts interest expense payable 6

by the SPE. 7

Securitizations are typically structured such that the SPE is overlooked for tax purposes. 8

This done in order to avoid reductions in cash collections available to the bondholders resulting 9

from tax obligations, including the impact from any future changes in tax legislation. 10

III. 11

A DESCRIPTION OF UTILITY TRANSACTION STRUCTURES 12

Q: Please provide a description of utility securitizations. 13

A: Utility securitizations follow many similar processes and principles as described above, 14

and in addition have certain distinct features specific to the asset class. The asset in a utility 15

securitization is the right of a utility to bill and collect a nonbypassable securitization charge paid 16

by utility customers (and often other consumers of electricity) in the utility’s service territory in 17

an amount necessary to generate cash flow sufficient to pay the debt service and other ongoing 18

financing costs of the transaction. The right to bill and collect the securitization charge is a 19

property right authorized and created by statute and a financing order issued by the public utility 20

commission. (In my testimony, I refer to this property right as “recovery property”, although it 21

is often referred to as transition property or given other names, depending upon the statutory 22

scheme.) Recovery property includes the right to periodically adjust the securitization charges 23

through a true-up mechanism to ensure the timely collection of securitization charge revenues 24

sufficient to pay debt service and other ongoing financing costs of the securitization. 25

The utility sells the recovery property to a newly established, bankruptcy-remote SPE in a 26

legal “true sale” that isolates the collateral from consolidation with the utility and claims by 27

10

creditors of the utility. The SPE then issues ABS bonds supported by a pledge of the recovery 1

property (the primary collateral) and certain other limited assets of the SPE (the “other 2

collateral”) to ABS investors (or “bondholders”). A trustee acts on behalf of the bondholders, 3

routinely remitting payments to the bondholders, paying servicer and other ongoing financing 4

costs, and ensuring bondholder rights, created by the statute, the financing order, and the bond 5

documents, are protected. The utility, acting as the seller and servicer, performs routine billing, 6

collection, and reporting duties for the SPE per a servicing agreement between the utility and the 7

SPE. The ability to segregate the collateral in a bankruptcy-remote SPE and the ability to make 8

periodic adjustments to the securitization charges are critical to the rating agencies’ analysis to 9

reach the highest possible rating category (AAA(sf)), the typical target rating in most utility 10

securitizations. 11

The structure of a utility securitization is generally described in Diagram A below. 12

Diagram A

Q: What are the key security features of a utility securitization? 13

A: The key security feature in a utility securitization is a statutorily authorized “true-up 14

mechanism” or “true-up adjustment”, which is a form of credit enhancement unique to utility 15

11

securitizations. The true-up mechanism periodically adjusts the securitization charge billed to 1

the utility’s customers based on projected electric consumption, collections, and expected 2

delinquencies and charge-offs. The true-up mechanism ensures the estimated securitization 3

charge collections match the scheduled payments on the bonds and related financing costs. 4

True-ups are typically required on an annual or semi-annual basis, although more frequent true-5

ups are often permitted on an as needed basis. Because the true-up mechanism allows the cash 6

flow in a utility securitization to be adjusted to satisfy the debt service and other ongoing 7

financing costs, other forms of credit enhancement that are common in commercial 8

securitizations, such as overcollateralization, have generally not been required in utility 9

securitizations. 10

In addition to the true-up mechanism, utility securitizations utilize a closed cash flow 11

structure, with excess cash captured and held in an excess funds account to be used as a credit in 12

the true-up mechanism. 13

Typically, the only other credit enhancement in a utility securitization is an equity 14

contribution limited to 0.50 percent of the initial principal amount of the bonds. This equity may 15

be used if available cash flow is insufficient to pay debt service and other ongoing financing 16

costs. 17

Q: How are debt service and related financing costs allocated among utility customers 18

in utility securitizations? 19

A: Utility securitizations have used various methods to allocate the cost of the securitization 20

(i.e., debt service and other ongoing financing costs) among and across customer rate classes. In 21

some cases, the cost allocation methodology is dictated by the statutory scheme; in others, it is a 22

function of the historic allocation of similar costs among customer classes. As a consequence, 23

the securitization charge is often different for each class of customers. In most utility 24

securitizations, the securitization charge is a consumption-based (kWh) charge, although in some 25

instances the charge may also be a function of demand (kW). If the securitization cost is 26

allocated among multiple classes of customers, the delinquencies in one class of customers are a 27

12

cost (ultimately) shared by all customers of the utility, creating “cross-collateralization” of the 1

debt service burden among all customers. This cross-collateralization is viewed favorably by the 2

rating agencies, enhancing the chance for the highest possible ratings. 3

Q: How are utility securitizations typically structured? 4

A: Utility securitizations have historically been offered as amortizing structures based on an 5

established debt service amortization schedule. The date in the amortization schedule where the 6

principal of each bond is expected to be fully paid down is known as the “expected final maturity 7

date”. When structuring a utility securitization, the targeted expected final maturity date can 8

vary depending on the required debt service profile. It is not guaranteed, nor is it a legal 9

obligation, for the bonds to be fully paid down on the expected final maturity date. The bonds 10

must be paid in full by the “legal final maturity date”, which is typically set approximately two 11

years after the expected final maturity date. The rating agencies rate the transactions assuming 12

the utility securitization pays off by the legal final maturity date. 13

Q: Please describe some of the bankruptcy related considerations relating to utility 14

securitization. 15

A: Similar to other types of securitizations, utility securitizations must include the legal 16

separation of the securitized assets from the utility via a true sale of the recovery property from 17

the utility to the SPE. This is accomplished through the “true sale” of the recovery property to 18

the SPE, which isolates the recovery property from consolidation with the utility and claims by 19

creditors of the utility. This “true sale” is often statutorily authorized by the securitization 20

legislation. Similar to commercial securitizations, the bankruptcy-remote SPE needs to comply 21

with certain independent director requirements, needs to limit its purpose and the activities in 22

which it may engage, and is typically prohibited from incurring any other debt or obligations. 23

The SPE must deal with its utility parent on an arm’s-length basis to ensure that it remains 24

bankruptcy-remote from the parent. 25

13

Q: Please describe some of the servicing considerations in a utility securitization. 1

A: The servicing function in utility securitizations is a similar process to what is required in 2

other types of securitizations. In utility securitizations, the servicer, which is initially the 3

sponsoring utility, is required to perform certain duties on behalf of the bondholders, which 4

including billing and collecting the securitization charge from consumers, applying to the public 5

utility commission for periodic true-up adjustments, remitting the securitization charges to the 6

bond trustee, and providing periodic reports summarizing current aspects of the transaction. 7

Servicing fees in utility securitizations must allow the utility to recover its costs of 8

servicing the recovery property. This helps ensure that the SPE can be treated as bankruptcy-9

remote from the utility. 10

Servicing fees in utility securitization are most commonly expressed as a fixed 11

percentage of the original principal balance of the transaction, which allows the servicing fee to 12

remain constant over the lifetime of the transaction. This differs from most other types of 13

securitizations where the servicing fee is expressed as a percentage of the transaction’s current 14

balance, which will decrease over time as transactions amortize. This difference accounts for the 15

fact that in utility securitizations, the customer base and the related servicing duties remain fairly 16

constant throughout the transaction’s lifetime, whereas servicing duties decrease over the 17

lifetime of other securitizations as assets in the securitized pool are paid down. Servicing fees 18

paid for recent utility securitizations have ranged between 0.05 percent and 0.10 percent of the 19

initial principal balance. Table III-3 below illustrates the servicing fee paid in recent utility 20

securitizations: 21

14

Table III-3 Recent Utility Securitization Annual Servicing Fee Percentages

As the cost of servicing is driven by factors such as the number of customers and 1

complexity of billing practices, servicing costs do not vary based on the transaction size, and 2

thus the servicing fee percentage for larger utility securitizations tends to be lower than that for 3

smaller utility securitizations. In the event of a servicer default, the bond trustee is typically 4

allowed to appoint a successor servicer, for which a higher fee is paid relative to the base 5

servicing fee. Replacement servicing fees in past utility securitizations have generally been 6

between 0.60 percent and 1.25 percent of the initial principal balance. This difference in 7

compensation reflects the potential cost and difficulty of securing a replacement servicer that is 8

not already involved in the customer billing and collection process. To date, I am not aware of 9

any utility securitization where a servicer has been replaced. 10

Q: Please describe some of the rating agency considerations specific to utility 11

securitizations. 12

A: Similar to other types of securitizations, all major rating agencies have published 13

methodologies for assigning ratings in utility securitizations. In their review of a utility 14

securitization, the rating agencies will focus on key elements of the securitization legislation, the 15

financing order, the true-up mechanism (which ensures payment of the required debt service), 16

the nonbypassability of the securitization charge, and any overcollateralization or other forms of 17

credit enhancement. As the sources of payment for the transaction are limited only to the 18

recovery property, the rating agencies will perform various “stress tests” on the cash flows 19

(which vary by each rating agency) to ascertain whether interest will be paid on time and 20

15

principal will be paid by the legal final maturity date. The rating agency stress test analysis is 1

most commonly focused on projected vs. actual consumer consumption, delinquency, and net 2

charge-off rates. Rating agencies will also review to ensure the securitization charge as a percent 3

of total customer billing is not greater than certain predetermined thresholds. A more detailed 4

description of rating agency considerations, including key features of the financing order, is 5

provided in the “Rating Agency Process” section below. 6

Q: Please describe the tax and accounting considerations specific to utility 7

securitizations. 8

A: As in other securitization transactions, utility securitizations are designed to achieve 9

favorable “debt-for-tax” treatment. To achieve this result, utility securitizations are structured as 10

“Qualifying Securitization” transactions pursuant to the safe harbor attributes detailed in IRS 11

Revenue Procedure 2005-62. As a “Qualifying Securitization,” the establishment of the recovery 12

property, the transfer of recovery property to the SPE and the issuance of securitization bonds 13

will not cause current recognition of gross income by the utility for federal income tax purposes. 14

Instead the securitization charges will be recognized as income to the utility as they are collected 15

over time. 16

A Qualifying Securitization must satisfy the following requirements: 1) the SPE must be 17

a wholly owned subsidiary of the utility capitalized with an equity interest of at least 0.5 percent 18

of the initial aggregate principal amount of securitization bonds issued; 2) the bonds must be 19

secured by the recovery property; 3) the securitization charges must be nonbypassable and 20

payable by consumers within the utility’s service territory; and 4) payments on the bonds must 21

be made at least on a semi-annual basis except for the initial payment period which may be 22

longer or shorter. 23

Treatment as a “Qualifying Securitization” within the meaning of IRS Revenue 24

Procedure 2005-62 is typically supported by an opinion of tax counsel to the sponsoring utility 25

that relies on the attributes detailed above. 26

16

Most utility securitizations do not meet the accounting requirement for off-balance sheet 1

treatment, and are instead recognized as liabilities on the related utility’s balance sheet. 2

Q: What makes up the security for the bonds in a utility securitization? 3

A: As stated, the principal security for a bond is the recovery property that is sold into the 4

SPE, consisting of the right to impose, collect and receive nonbypassable securitization charges 5

from the utility’s consumers for amounts necessary to pay principal and interest on the 6

securitization bonds, as well as to pay the other ongoing financing costs, on time and in full. The 7

recovery property includes the right to adjust the securitization charge periodically by using the 8

true-up adjustment discussed above. 9

Q: What do you mean by “nonbypassable” securitization charges? 10

A: In basic terms, nonbypassable means that if a consumer resides in the utility’s service 11

territory, the consumer must pay the securitization charge, even if the consumer buys its 12

electricity from an alternative service provider or a successor to the utility, including a 13

municipality that might acquire a portion of the utility’s service territory. 14

Q: You mentioned earlier that the bonds in a utility securitization are typically secured 15

by “other collateral”. What is the composition of this “other collateral”? 16

A: “Other collateral” generally comprises the trust accounts established by the SPE at 17

transaction closing to be held by the bond trustee for the benefit of the bondholders. These 18

accounts and subaccounts typically consist of a “Collection Account” and various subaccounts. 19

These subaccounts will hold (i) securitization charge remittances pending application by the 20

bond trustee under the “waterfall” provisions of the trust indenture (“general subaccount”); (ii) 21

the initial equity contribution by the utility discussed below (“capital subaccount”); and (iii) 22

securitization charge collections, together with earnings on the Collection Account, in excess of 23

required periodic payments of debt service and all other ongoing financing costs (the “excess 24

funds subaccount”). Amounts in the excess funds subaccount are used as a “credit” in future 25

true-up adjustments to the securitization charge. In some securitizations, the bond trustee also 26

creates an account to hold any securitization charges collected in excess of the required debt 27

17

service for the purpose of providing additional credit support (any “Overcollateralization 1

Subaccount”). I do not anticipate that an Overcollateralization Subaccount will be created for 2

the SCE securitizations, but SCE has requested the flexibility to create such an account should 3

market conditions or SCE’s condition change such that the creation of such an account would 4

serve to lower borrowing costs and thus benefit electric consumers. 5

Q: You mention earlier in your testimony that the securitization charges also recover, 6

in addition to principal and interest on the bonds, other “ongoing financing costs”. What 7

are these “ongoing financing costs”? 8

A: Generally, these ongoing financing costs are expenses that are incurred on an annual 9

basis to service the bonds and support the operations of the SPE. These ongoing financing costs, 10

which must be recovered throughout the life of the bonds from securitization charge collections, 11

generally include, but are not limited to, servicing fees, administrative fees, bond trustee fees, 12

legal and accounting fees, rating agency surveillance fees, other operating expenses of the SPE, 13

credit enhancement expenses (if any), and related costs. The most significant of these costs is 14

the servicing fee. The servicing arrangement is evidenced by a servicing agreement between the 15

utility, as initial servicer, and the SPE. The utility also enters into an administration agreement 16

with the SPE, under which the utility agrees to act as administrator for the SPE to support the 17

functions of the SPE. Another ongoing cost is that of the bond trustee. The servicing, 18

administration and bond trustee fees and their underlying arrangements are described in greater 19

detail below. Ongoing financing costs also typically include a permitted rate of return on the 20

sponsor’s invested capital, often equal to the rate of interest payable on the longest maturing 21

tranche of bonds. This return is paid to the sponsor from securitization charges in accordance 22

with the waterfall established in the indenture providing for the issuance of the bonds. 23

A detailed estimation of ongoing financing costs for the initial SCE securitization is presented in 24

Mr. Pang’s testimony (Exhibit SCE-03). 25

18

Q: Please generally describe the contents and purpose of a servicing agreement and the 1

role of the servicer. 2

A: The servicing agreement is an agreement between the sponsoring utility, as the initial 3

servicer of the securitization bonds, and the SPE, as the issuer of the securitization bonds. The 4

servicing agreement sets forth the responsibilities and obligations of the servicer, including, 5

among other things, billing and collecting securitization charges, responding to customer 6

inquiries, terminating electric service, filing for true-up adjustments, and remitting collections to 7

the bond trustee for distribution to bondholders. The servicing agreement prohibits the initial 8

servicer’s ability to resign as servicer unless it is unlawful for the initial servicer to continue in 9

such a capacity. In order to continue servicing the transaction without interruption, the initial 10

servicer’s resignation would not be effective until a successor servicer has assumed its 11

obligations. The servicer may also be terminated from its responsibilities upon a majority vote 12

of bondholders under certain circumstances, such as the failure to remit collections within a 13

specified period of time. Any merger or consolidation of the servicer with another entity would 14

require the merged entity to assume the servicer’s responsibility under the servicing agreement. 15

In exchange for its role as servicer, the utility will be entitled to earn a servicing fee. This 16

servicing fee is meant to offer the utility a reasonable return in its role as servicer. As described 17

earlier, ensuring there is reasonable compensation to the servicer helps to ensure the bankruptcy-18

remoteness of the SPE from the utility. I have discussed above the customary level of servicing 19

fees for a utility securitization for the utility as well as for any replacement or successor servicer. 20

The estimate for SCE’s servicing fee is shown testimony of Mr. Pang (Exhibit SCE-03). The 21

terms of the servicing agreement are critical to the rating agency analysis of the securitization 22

bonds and the ability to achieve the highest credit ratings. The rating agencies will be primarily 23

concerned with the nature and frequency of the true-up adjustments to be performed by the 24

servicer. They will want to see that true-up adjustments are required to occur at least annually in 25

the initial years and more frequently in the last year the bonds are expected to be outstanding. In 26

addition, more frequent (e.g., quarterly) true-ups should be permitted if the servicer deems it 27

19

necessary to meet debt service and other ongoing financing costs. The rating agencies will 1

require that the servicing agreement generally contemplate a servicer's ability to remit 2

securitization charges on a daily basis, within two business days of receipt or posting to the 3

utility’s account. 4

Q: What is the role of the administrator? 5

A: As described above, the securitization bonds will be issued by a bankruptcy-remote SPE. 6

The SPE will have no employees. As a consequence, the utility must provide administrative 7

services to the SPE for the SPE to function as an independent legal entity. The administrative 8

services will include, among others, maintaining general accounting records, preparing quarterly 9

and annual financial statements, arranging for annual audits of the SPE’s financial statements, 10

preparing all required external financial filings, preparing any required income or other tax 11

returns, and related support. These services are separate from those of the servicer. 12

To compensate the administrator for its services and thus ensure the bankruptcy-remote 13

status of the SPE, the administrator is paid an administration fee. The administration fee is in the 14

range of approximately $50,000 to $200,000 per year. Table III-4 below illustrates the 15

administrative fee paid in recent utility securitizations: 16

Table III-4 Recent Utility Securitization Annual Administration Fees

Deal Date Principal Amount ($mm) Annual Administration Fee

($)

AEP Texas Restoration Funding Sept 2019 235.282 100,000

PSNH 2018-1 May 2018 635.663 75,000

UDSA 2017 Oct 2017 369.465 199,996

DUK June 2016 1,294.290 50,000

UDSA 2016A Mar 2016 636.770 165,000

20

Q: What is the role of the bond trustee? 1

A: The bond trustee receives and processes securitization charges from the servicer, 2

calculates the amounts due to bondholders on each payment date, allocates collections in 3

accordance with the priority of payments for the transaction, invests amounts on deposit in each 4

Collection Account subaccount in eligible investments, and provides periodic reports that detail 5

account activity and balances to various parties. Generally, the bond trustee operates at the 6

direction of the servicer, as agent for the SPE. 7

IV. 8

DESCRIPTION OF UTILITY SECURITIZATION BONDS STRUCTURING SALE 9

AND PRICING CONSIDERATIONS 10

Q: Do utility securitization bonds typically pay fixed or floating rates? 11

A: Utility securitization bonds have traditionally paid interest on a fixed rate basis. This has 12

largely been dictated by the need to achieve predictable savings to utility customers, as well as 13

the AAA(sf) ratings typically assigned to utility securitizations and the need to use complex 14

derivative structures to achieve a floating rate. 15

Q: How are the maturities and amortization structures for utility securitization bonds 16

typically determined? 17

A. The maturities and amortization structures for utility securitization bonds vary based 18

upon various considerations, including statutory constraints, the nature of costs being recovered, 19

ratemaking or other regulatory considerations, and bond cash flow considerations. 20

Q: Please discuss whether the securitization bonds are offered in a public transaction 21

registered with the Securities and Exchange Commission or in a private placement. 22

A: Although it will depend on prevailing market conditions at the time of issuance, most 23

utility securitizations have been offered pursuant to an offering registered with the U.S. 24

Securities and Exchange Commission (“SEC”), generally referred to as a public offering. 25

Generally, public offerings are considered to be more liquid than private placements, and 26

therefore may be more attractive to investors, which would likely lead to lower overall costs for 27

21

SCE’s consumers. However, it may be important for the utility to retain some flexibility to issue 1

a Rule 144A private placement transaction, to address possible market or other disruptions that 2

may arise, such as the recent pandemic. 3

Q: How are utility securitizations priced in the marketplace? 4

A: Fixed income securities are traditionally priced to a benchmark rate index that matches 5

the weighted average life (“WAL”) of the bond. Utility securitization bonds have historically 6

priced off of the mid-swap benchmark rate index. The credit spread is the incremental return 7

required by investors over the benchmark rate to invest in a specific security – in this case, the 8

utility securitization bond. The total yield for a tranche of utility securitization bonds is the sum 9

of (i) the benchmark rate and (ii) the credit spread. These spreads are used to determine the 10

various tranches (or maturities) of securitization bonds to be offered and sold as well as their 11

respective expected and final maturity dates, to minimize the cost of borrowing. 12

Q: What are the considerations taken into account when developing the tranching 13

structure of the utility securitization bonds? 14

A: Both quantitative and qualitative considerations are taken into account when structuring 15

the tranching of the securitization bonds, including the: 16

General market conditions at the time of pricing, 17

Interest rate environment, 18

Shape of the underlying benchmark yield curve, 19

Perceived investor liquidity of the bonds, 20

General investor risk appetite, 21

Investor maturity preferences, 22

Competing supply in the new issue market, 23

Secondary trading levels for comparable securities, 24

Relative value versus comparable securities, and 25

Calendar in general. 26

22

The goal of the structuring process is to design a tranched structure that will appeal to different 1

classes of bond investors. Achieving that goal will increase the number of investors seeking to 2

invest in that security and, in turn, obtain the lowest practicable debt cost, thus providing the 3

lowest practical total cost to the utility consumers. 4

23

V. 1

DESCRIPTION OF THE RATING AGENCY PROCESS 2

Q: Please describe the rating agency process for utility securitizations. 3

A: An important component of preparing for the marketing and pricing of the securitization 4

bonds is obtaining the highest possible ratings on the bonds from the rating agencies. The major 5

rating agencies all have published criteria for utility securitization. The rating agency process 6

generally consists of: 7

1. Preparing and distributing an initial rating agency presentation and accompanied 8

securitization bond cash flows, including cash flow stress scenarios unique to each 9

transaction. 10

2. Questions from each rating agency to the utility, its lead underwriter, and its legal 11

counsel, based on the initial rating agency presentation and cash flows. 12

3. A legal review of the transaction. 13

4. A servicing due diligence review. 14

Q: Please further describe the key elements of the rating agency review process for 15

utility securitizations. 16

A: For the initial rating agency presentation, the utility and its lead underwriter will compile 17

the key elements that each rating agency will require to facilitate their review of the 18

securitization bond financing, based on each rating agency’s unique ratings methodologies. The 19

presentation will include items such as a review of the purpose of the transaction, the proposed 20

transaction structure, an analysis of the recovery property, an analysis of historical credit losses 21

of and write-downs on the utility’s receivables, forecast usage data, and an analysis of the 22

utility’s servicing and forecasting capabilities. As referenced previously in Sections I and II, the 23

rating agencies will then conduct an analytical and qualitative assessment of the transaction as 24

well as a detailed review of the servicer and will ask follow-on questions or request further data 25

from the utility, its lead underwriter, and its legal counsel. 26

24

Expanding on the rating agency “stress test” analysis discussed in Section II, rating 1

agencies will perform various cash flow stress analyses, analyzing the expected securitization 2

bond cash flows under various stress test scenarios. Each rating agency has its own cash flow 3

stresses that it asks for as part of its review. These cash flow stresses are generally downside and 4

extreme scenarios to assess whether or not the bonds would pay timely interest and principal by 5

the legal final maturity date. Rating agencies may ask the utility and its lead underwriter to 6

provide additional stressed cash flow outputs for further analysis. Additionally, the size and 7

diversity of the consumer base, classes within the base and the size of the securitization charge as 8

a percent of the aggregate consumer electric bill are important factors in the rating agency 9

process. Rating agencies will also review the legal integrity of the utility securitization by 10

examining the legislation and financing order, the offering documents and transaction 11

documents, and any legal opinions. Extensive review of the securitization bond structure will 12

also occur. Key legal elements of the transaction that the rating agencies will include the 13

following:3 14

1. The nonbypassable nature of the securitization charges (See Sections 850(b)(7) and (8), 15

and 850.1(b) of the Securitization Statute). 16

2. Transfer of recovery property by SCE to another entity as an “absolute transfer” and “true 17

sale,” provided that the governing documentation expressly states that the transfer is an 18

“absolute transfer” and a “true sale” (See Sections 850.1(e)(2)(B), 850.2(c) and 850.4. of 19

the Securitization Statue). 20

3. A current property right (recovery property), which creates a separate and current right to 21

receive the revenues from the nonbypassable securitization charges (See Sections 22

850(b)(11), 850.1(e) and (h), 850.2(d), 850.3, 850.4(a), (c) and (d). of the Securitization 23

Statue). 24

3 Where appropriate I have cited provisions in the Securitization Statute which I believe address the

rating agency issues.

25

4. The assignment of the SPE’s rights to the bond trustee, for the benefit of the bondholders, 1

in a perfected first priority security interest (See Sections 850.2(b)–(d) and 850.3 of the 2

Securitization Statute). 3

5. The terms of a “true up” mechanism and frequency of adjustment (See Section 850.1(g) 4

of the Securitization Statute). 5

6. The sufficiency of expected collections to adhere to the scheduled amortization schedule 6

of the recovery bonds. 7

7. Transaction subaccounts. 8

8. The expected final payment dates compared to the legal final payment dates on the 9

securitization bonds, and whether bond interest and principal are likely to be paid off in 10

the worst case scenario by the legal final payment dates. 11

9. The irrevocability of the financing order (See Section 850.1(e) of the Securitization 12

Statute). 13

10. The state non-impairment pledge and reaffirmation of the state’s pledge by the CPUC 14

(See Section 850.1(e) of the Securitization Statute). 15

11. Any federal and state constitutional protections. 16

12. The presence of obligations to pay by substantially all of the utility customers (See 17

Section 850.1(a)(2) of the Securitization Statute). 18

Ultimately, the rating agency’s analysis will determine the amount of credit enhancement 19

the structure will need. Apart from the capital contribution of 0.5% of the initial bond balance, 20

which serves as a cash reserve, there is no excess spread, subordination, overcollateralization, or 21

letters of credit or surety bonds typically required for a utility securitization. As stated, the 22

primary form of credit enhancement is the right to impose and collect nonbypassable 23

securitization charges from consumers in the amount necessary to repay principal, interest and 24

other ongoing financing costs on the securitization bonds and the ability to adjust the amounts of 25

the securitization charges through the true-up adjustment mechanism. The performance of the 26

securitization bonds is primarily driven by the ability to accurately predict the future level of 27

26

electricity consumption, delinquencies, charge-offs and adjust for any variance by utilizing the 1

true-up adjustment. 2

Q: Do you believe that the form of financing order proposed by SCE establishes the 3

foundation necessary to secure the highest possible rating from the rating agencies and the 4

flexibility to structure the financing in a manner consistent with investor preferences at the 5

time of pricing? 6

A: Yes, I believe that it does. 7

Among other important features, the financing order: 8

- includes terms, such as an elaborate true-up mechanism, which ensure that the Fixed 9

Recovery Charges (which are the securitization charges under the Securitization 10

Statute) will produce revenues adequate to meet scheduled debt service requirements 11

and the other ongoing financing costs on a timely basis; 12

- provides provisions describing the nonbypassability of the Fixed Recovery Charges; 13

- provides adequate provisions to mitigate any potential risk to the SPE of an SCE 14

bankruptcy, which is accomplished via a legal “true sale” for bankruptcy purposes to 15

a bankruptcy-remote SPE; 16

- reaffirms the CPUC of the state’s non-impairment pledge; 17

- includes provisions that facilitate favorable “debt-for-tax” treatment for the 18

securitization; and 19

- includes provisions giving SCE flexibility to include additional credit enhancement 20

and otherwise structure the tranching and other terms of the bonds to obtain the 21

optimal pricing through an Issuance Advice Letter process. 22

Q: How will the rating agencies view securitization when assessing the utility’s debt 23

credit rating? 24

A: Each rating agency takes its own approach when assessing the qualitative and 25

quantitative impact of securitization on a company’s credit. 26

27

Qualitatively, Moody’s believes that the utility benefits from securitization given the 1

immediate source of cash and that consumers benefit from lower rates due to the lower cost of 2

capital associated with the bond coupon. The organization has indicated that new frameworks 3

surrounding securitizations will generally be tested over time as regulatory agencies issue 4

decisions. With this certainty may come benefits, such as improved timeliness of recovery of 5

operating and capital costs or improvements in regulatory underpinnings, both of which can 6

improve a utility's overall credit scores. Quantitatively, Moody’s views securitizations as being 7

on-credit debt for the utility for purposes of calculating credit ratios due, in part, to the fact that 8

the securitization charge naturally lowers the utility's ability to raise rates for other purposes 9

while still keeping them affordable for customers. This on-credit treatment occurs irrespective of 10

GAAP accounting treatment. Due to the mortgage-style amortization associated with utility 11

securitizations, Moody's notes that the on-credit treatment of the securitization will make credit 12

metrics look worse in early years and better in later years. 13

Qualitatively, S&P views securitization as at least neutral, and generally positive for 14

credit quality. They appreciate the up-front cash proceeds that can be used to potentially pay 15

down debt that carries a higher coupon with interest savings passed on to consumers in the form 16

of lower rates. Quantitatively, S&P deconsolidates securitized debt and associated revenues and 17

expenses when assessing a utility’s credit as long as the structure contains a number of protective 18

features. These include making the securitization charge irrevocable and nonbypassable; and that 19

the securitization structure is an absolute transfer and holds a first-priority interest in the fixed 20

recovery charges, contains periodic “true-ups” to handle any over- or under-collections, and a 21

reserve account to handle any temporary shortfalls. According to S&P, this off-credit treatment 22

stems from the fact that all consumers are responsible for the principal and interest payments 23

associated with the securitization, and the utility essentially acts as a pass-through entity for 24

servicing the debt. 25

28

VI. 1

DESCRIPTION OF THE MARKETING PROCESS FOR UTILITY SECURITIZATION 2

BONDS 3

Q: Please describe how utility securitizations are marketed and priced. 4

A: Recovery Bonds are expected to be an attractive investment to investors in traditional 5

asset-backed securities. Additionally, the Recovery Bonds will be marketed to corporate debt 6

investors who are buyers of utility issues and previous utility securitization bonds who may see 7

Recovery Bonds as an attractive investment. The Recovery Bonds will be marketed to a broad 8

investor base with the objective of lowering the all-in cost as demand for Recovery Bonds 9

increases. The marketing process includes various phases, each uniquely tailored to each 10

transaction. Below are the general steps in a marketing process for utility securitization, but the 11

actual process could vary based on the then-current market environment at the time of marketing. 12

1. Pre-marketing. This process is the marketing phase conducted before the official 13

transaction announcement, with the goal of soliciting broad investor interest in the 14

transaction. Underwriters will work to bring the transaction to the attention of investors 15

and inform investors of the deal, its structure and terms, and its strengths, and facilitate 16

the answering of investor questions. This phase generally includes an electronic notice to 17

investors that the transaction is likely to be announced shortly, a roadshow (usually in 18

electronic form), and solicitations for one-on-one conference calls with potential 19

investors. The underwriters and issuer will also disseminate the estimated pricing at 20

which the bonds will aim to price, or initial pricing thoughts (“IPTs”), usually in the form 21

of a credit spread over a benchmark rate. In response, investors will provide indications 22

of interest, which is generally the dollar amount of bonds they are requesting at the 23

specified IPTs. 24

2. Announcement. The next step is to officially announce the transaction to the market, 25

which is typically done following pre-marketing efforts. Generally speaking, utility 26

securitizations will price in the same week during which they are announced, in order to 27

29

reduce unforeseen event risk over the weekend, which may affect deal execution. 1

Following the official announcement, the bonds will be offered for sale to investors 2

through the team of underwriters selected for the transaction, and bond pricing is further 3

discussed. 4

3. Price Guidance. Price guidance is discussed amongst the underwriters and issuer 5

following the receipt of investor indications of interest and feedback. The underwriters 6

will send out a notice to investors with updated pricing thoughts, which again are 7

typically presented as a range of credit spreads stated against the given benchmarks for 8

the bonds. Price guidance levels can be either tighter (lower) or wider (higher) than the 9

IPTs based on investor demand in the transaction to that point. After releasing price 10

guidance and receiving sufficient orders from investors in each class, the underwriters 11

will announce a time to the market at which the book will close and no subsequent orders 12

will be accepted; this is commonly known as “going subject.” This step can only occur 13

when the book has at least an equal amount of orders on the bonds as the principal 14

amount of bonds offered (generally referred to as being “fully-subscribed”). The 15

underwriters will exercise professional judgment in making a recommendation to close 16

the book, based on all relevant factors, including market conditions, the speed at which 17

orders came in for investors, and the composition of investor types in the book. 18

4. Price Testing. After taking the book subject, underwriters will begin to refine the 19

pricing level. Based on the volume of investor interest and feedback, underwriters may 20

seek to adjust the spreads tighter, provided the adjustment does not decrease the 21

aggregate investor demand below the size of the bond. Testing of the pricing levels is 22

generally done through an electronic notice to investors of the tighter testing spread 23

levels and gauging investor demand at these levels. Price testing is done to ensure the 24

maximum distribution of the bonds at the lowest prices possible, given market conditions 25

at the time. The underwriters will use professional judgement with respect to the 26

30

recommendation to the issuer for the amount of tightening to arrive at finalized pricing 1

spread levels. 2

5. Launch. Once the pricing levels have been determined for the transaction, it will be 3

launched at that specific spread level. The intention of this stage is to officially declare to 4

investors at which credit spread the bonds will be priced and issued. This will be the 5

market clearing pricing level of the credit spread, subject only to movements in the 6

underlying benchmark rates. 7

6. Allocation. At this stage, the market clearing pricing level has been determined by the 8

marketing process, but the final book (how much each investor will purchase) has yet to 9

be determined. The underwriters will work to recommend a specific amount of bonds to 10

be sold (or “allocated”) to each investor. Each allocation depends on a number of factors, 11

including but not limited to the size of the investor’s order, when the investor placed its 12

order, the investor’s experience in the sector, and the investor’s flexibility during the 13

pricing process. Ultimately, each investor will purchase its final allocations for the 14

transaction at transaction settlement. 15

7. Pricing. The underwriters will price the transaction by spotting the underlying 16

benchmark rate and adding the market clearing credit spread to determine the pricing 17

bond yield and coupon for the bonds. 18

8. Settlement. At the conclusion of the pricing process, SCE along with its underwriters 19

and legal team, will work toward finalizing the transaction offering and documents and 20

close the transaction, with transaction settlement typically occurring approximately five 21

business days after pricing. 22

The above summary is general, and marketing efforts will be specifically crafted for the 23

transaction, based on the facts and circumstances of each deal, as well as the investor feedback 24

and orders on the actual day of pricing. 25

31

VII. 1

UPFRONT FINANCING COSTS (BOND ISSUANCE COSTS) 2

Q: What are the typical bond issuance costs associated with the issuance of utility 3

securitization bonds? 4

A: Financing costs associated with the issuance of utility securitization bonds are financed 5

from the proceeds of the securitization bonds. These financing costs are referred to as “upfront 6

financing costs.” Upfront financing costs include underwriting fees and expenses, any original 7

issue discount, legal fees and expenses (including those associated with application for the 8

financing order), structuring advisory fees and expenses, any interest rate lock or swap fees and 9

costs (if any), SEC registration fees, rating agency fees, accounting fees and expenses, printing 10

and EDGARizing costs, bond trustee fees and expenses, any CPUC fees and expenses, and other 11

miscellaneous costs (such as, in the case of the SCE securitization, Section 1904 fees). Upfront 12

financing costs also include reimbursement to the utility for amounts advanced for payment of 13

these financing costs. Upfront financing costs may also include the costs of credit enhancement, 14

including the costs of funding any reserve or overcollateralization account, or of purchasing a 15

letter of credit or bond insurance policy. As stated above, under current market conditions, I do 16

not anticipate that SCE will be required to fund an overcollateralization account or obtain 17

additional credit enhancement in connection with its proposed securitization transactions. 18

However, circumstances may change and SCE has requested authority to fund such credit 19

enhancement costs if it will result in savings to consumers and approved in the Issuance Advice 20

Letter, as described in Mr. Pang’s testimony (Exhibit SCE-03). 21

Q: Has SCE estimated its upfront financing costs in its testimony? 22

A: Yes, upfront financing costs for the initial securitization transaction are estimated in Mr. 23

Pang’s testimony (Exhibit SCE-03). Mr. Pang has estimated that total bond issuance costs for 24

the initial securitization (assuming no credit enhancement) will be approximately $5.36 million, 25

or 1.59 percent of the initial principal amount of the securitization bonds. 26

32

Q: Do you believe that these upfront financing cost estimates are reasonable and 1

appropriate, and consistent with prior utility securitizations? 2

A: Yes, I believe that the upfront financing costs described in detail in Mr. Pang’s testimony 3

(Exhibit SCE-03) are reasonable and appropriate in light of the complexity of the securitization 4

transaction and the long lead-time necessary to develop and bring this transaction to a close. 5

Similar to recent utility transactions, the timeline for this transaction (and associated upfront 6

financing costs) accounts for the financing order application process, the shelf registration 7

process with the SEC for a public offering, the bond structuring and rating agency process, legal 8

documentation and opinions and transaction marketing and syndication. In arriving at my 9

conclusions, I have reviewed the underwriters’ costs as well as total bond issuance costs in other 10

recent securitization transactions and compared it to the expected upfront financing costs that 11

Mr. Pang details in his testimony. Total upfront financing costs on these recent utility 12

securitizations have ranged from approximately 1.0 – 3.0% of the original principal amount of 13

the utility securitization bonds (see Table VII-5). 14

Table VII-5 Recent Utility ABS Issuance Costs

Deal

No. State Utility Pricing Date Size ($mm)

Underwriting

Fees (%)

Total

Cost

($mm)

Total Cost

(% of Size)

1 TX AEP Texas Sep 2019 $235.00 0.40% $4.10 1.74%

2 NH PSNH May 2018 $635.66 0.41% $6.74 1.06%

3 LA Entergy July 2015 $98.73 0.35% $2.97 3.01%

4 OH AEP July 2013 $267.41 0.40% $3.74 1.40%

5 OH FirstEnergy Jan 2013 $444.92 0.40% $9.05 2.03%

33

Q: Please provide a brief description of SCE’s contemplated recovery bond financing 1

plan. 2

A: As discussed in greater detail in the testimony of Mr. Pang, SCE proposes to finance up 3

to $1.575 billion of fire risk mitigation capital expenditures (“Total AB 1054 CapEx”) approved 4

by the CPUC through the issuance of recovery bonds backed by Fixed Recovery Charges. The 5

initial recovery bond issuance (the “Securitization”) will finance approximately $337,141,000 of 6

such Total AB 1054 CapEx (including related financing costs) with the remaining costs to be 7

financed in subsequent securitization transactions. 8

VIII. 9

CONCLUSION 10

Q: Please summarize your testimony. 11

A: I believe that utility securitizations will yield the lowest cost of funds to the utility, in 12

view of the expected AAA ratings. I also believe that the form of the financing order proposed 13

by SCE establishes the legal foundation necessary to secure the highest possible rating from the 14

rating agencies and to structure the financing in a manner consistent with investor preferences at 15

the time of pricing. For these reasons, the proposed Financing Order should be adopted by the 16

CPUC. 17

I also believe that SCE’s proposed bond issuance costs for the Securitization are 18

reasonable, in light of historical precedent. 19

Q: Does this complete your direct testimony? 20

A: Yes, it does. 21

Application No.: A.20-07-008 Exhibit No.: SCE-03 Witnesses: B. Pang

(U 338-E)

Recovery Bond Financing

Transaction Overview Testimony

Before the

Public Utilities Commission of the State of California

Rosemead, California July 8, 2020

Direct Testimony Supporting Southern California Edison's Application for Recovery Bond Financing: Transaction Overview

Table Of Contents

Section Page Witness

-i-

I.  TRANSACTION OVERVIEW .........................................................................1 B. Pang 

II.  GENESIS OF TRANSACTION ........................................................................1 

III.  OVERVIEW OF ASSEMBLY BILL NO. 1054 ...............................................2 

IV.  MATURITY AND SIZING OF THE PROPOSED TRANSACTION ...............................................................................................4 

V.  PROPOSED TRANSACTION STRUCTURE..................................................4 

VI.  PROPOSED RECOVERY BOND STRUCTURE AND PAYMENT TERMS ..........................................................................................8 

VII.  TRANSACTIONAL ISSUES: CREDIT RATINGS, TAXES AND ACCOUNTING. ......................................................................................9 

A.  Credit Rating Issues .............................................................................10 

1.  Bankruptcy Opinions ...............................................................10 

2.  FRC Characteristics .................................................................11 

3.  True-Up Mechanism ................................................................11 

4.  Credit Enhancement, Capital Subaccount and Return .......................................................................................16 

5.  FRC Revenue Forecasts ...........................................................17 

6.  Billing by Third Parties ............................................................17 

7.  Legislative and Regulatory Risks; Risk of Municipalization ......................................................................19 

B.  Tax Issues.............................................................................................20 

C.  Accounting Issues ................................................................................21 

VIII.  SERVICING THE RECOVERY BONDS ......................................................21 

IX.  ADMINISTRATOR FOR THE SPE ...............................................................23 

X.  ONGOING FINANCING COSTS ..................................................................23 

Direct Testimony Supporting Southern California Edison's Application for Recovery Bond Financing: Transaction Overview

Table Of Contents (Continued)

Section Page Witness

-ii-

XI.  BILLING AND REMITTANCE OF FRCs; APPLICATION OF REVENUES BY BOND TRUSTEE ...............................................................24 

XII.  ISSUANCE ADVICE LETTER PROCESS ....................................................26 

XIII.  UPFRONT FINANCING COSTS, PRE-SECURITIZATION DEBT FINANCING COSTS, AND USE OF NET PROCEEDS ...................27 

XIV.  CONCLUSION ................................................................................................29 

Appendix 3.1 Estimated Authorized Amount, including Pre-Securitization Debt Financing Costs and Upfront Financing Costs 

Appendix 3.2 Estimated Annual Ongoing Financing Costs 

Appendix 3.3 Revenue Requirements (“RRQ”) of FRC 

1

I. 1

TRANSACTION OVERVIEW 2

This testimony, in conjunction with Exhibit SCE-02, describes the transactional structure and 3

bond features for the first series of recovery bonds under AB 1054 (“Recovery Bonds”, as more fully 4

described below) proposed for issuance by Southern California Edison Company’s (“SCE”). As 5

described in SCE-07, SCE proposes that the transaction structure described in this testimony be 6

approved for use in future recovery bond transactions requested by SCE. This testimony also addresses 7

certain considerations that determined the proposed structure for the Recovery Bonds. Attached as 8

Appendix D to the Application is a form of financing order (the “Financing Order”) for the proposed 9

transaction. 10

II. 11

GENESIS OF TRANSACTION 12

The transaction has its genesis in SCE’s Grid Safety and Resiliency Program (“GSRP”), which 13

SCE seeks to finance in part through the proposed securitization. SCE designed the GSRP to address 14

California’s increasing wildfire risk by hardening the electric system and enhancing its situational 15

awareness and operational capabilities. On April 24, 2020, the Commission issued Decision 20-04-013, 16

which adopted the GSRP Settlement in its entirety. That settlement resolved and concluded SCE’s 17

application to record and recover costs associated with the GSRP, as described in the Application and 18

Exhibit SCE-01. Among the costs and expenses approved by the Commission as “reasonable and 19

supported by the record in this proceeding,” were GSRP capital expenditures incurred after August 1, 20

2019 in the amount of $326,981,000 (the “Initial AB 1054 CapEx”), which are the subject of the 21

Application.1 22

1 As described in Exhibit SCE-07, SCE anticipates seeking to securitize additional costs and expenses related to

catastrophic wildfires, including fire risk mitigation capital expenditures identified in subdivision (e) of Section 8386.3, as those costs or expenses are determined to be just and reasonable by the Commission.

2

III. 1

OVERVIEW OF ASSEMBLY BILL NO. 1054 2

On July 12, 2019, Governor Newsom signed into law Assembly Bill No. 1054 (“AB 1054”), 3

which amended Division 1, Part 1, Chapter 4, Article 5.8 of the California Public Utilities Code (Section 4

850 – 850.8) and authorizes the issuance of recovery bonds (the “Recovery Bonds”). Some of the 5

critical relevant provisions of Article 5.8 (as amended, “Article 5.8”) are set forth below. 6

Recovery Bonds Authorized: If an electrical corporation submits an application for recovery of 7

costs and expenses related to catastrophic wildfires, including fire risk mitigation capital 8

expenditures identified in subdivision (e) of Section 8386.3, in a proceeding to recover costs and 9

expenses in rates, and the Commission finds that some or all of the costs and expenses identified in 10

the electrical corporation’s application are just and reasonable pursuant to Section 451, then the 11

Commission may issue a financing order authorizing the recovery of such costs and expenses. 12

Nonbypassable Charges: The Commission can impose nonbypassable charges (which Article 5.8 13

refers to as “fixed recovery charges” (“Fixed Recovery Charges” or “FRCs”)) on consumers to pay 14

the principal, interest, and other Financing Costs (as defined in Section 850(b)(4)). Except for a 15

limited number of exemptions, the FRCs are applicable to all existing and future electric consumers 16

in SCE’s service territory as it exists as of the date of the financing order (“SCE’s Service 17

Territory”). 18

Customer Benefits: The issuance of the Recovery Bonds and the imposition and collection of 19

FRCs are authorized if the Commission finds: A. the Recovery Costs (i.e., the Initial AB 1054 20

CapEx) to be reimbursed from the Recovery Bonds have been found to be just and reasonable; and 21

B. the issuance of such Recovery Bonds (i) is just and reasonable, (ii) is consistent with the public 22

interest, and (iii) would reduce, to the maximum extent possible, the rates on a present value basis 23

that consumers would pay as compared to the use of traditional utility financing mechanisms.2 24

2 Exhibit SCE-04 provides analyses of securitization compared against traditional utility financing and

traditional utility financing without an equity return.

3

No Debt or Liability of the State: Neither the State of California nor any political subdivision 1

thereof will be liable for any amounts associated with the Recovery Bonds or the FRCs, and the 2

State’s credit and taxes shall not be pledged to pay for the Recovery Bonds or associated costs. 3

Periodic True-Up Adjustments: There shall be periodic true-up adjustments of the FRCs using the 4

true-up mechanism approved by the Commission in the financing order (which shall be made at least 5

annually and may be made more frequently) as necessary to correct for any overcollection or 6

undercollection of the FRC revenues authorized by the financing order and to otherwise ensure the 7

timely and complete payment and recovery of the Recovery Bond principal and interest, and other 8

Ongoing Financing Costs (as defined below) over the authorized repayment term. 9

Irrevocable Charges: The Commission’s financing order authorizing Recovery Bonds and the 10

FRCs shall be irrevocable by future Commissions. 11

Current Property Right: Article 5.8 creates a separate and current property right (“Recovery 12

Property”) to receive the revenues from the nonbypassable FRCs, including all rights to obtain 13

adjustments to the FRCs, and to all revenues, collections, claims, payments, moneys, or proceeds of 14

or arising from the FRCs. 15

State Pledge: The State of California pledges and agrees with SCE, owners of Recovery Property, 16

Special Purpose Entities (“SPEs”) that issue Recovery Bonds, and holders of Recovery Bonds that 17

the State shall neither limit nor alter, except as otherwise provided with respect to the periodic true-18

up adjustment pursuant to subdivision (g) of Section 850.1, the FRCs, Recovery Property, the 19

financing order or rights under the financing order until the Recovery Bonds, together with the 20

interest on the Recovery Bonds and other Ongoing Financing Costs are fully paid and discharged. 21

Timeline for Financing Orders and Appeals: Sections 850.1, 1731 and 1756 establish the 22

timeline for financing orders, rehearings and appeals. 23

The Commission is to act on the application for a financing order within 120 days of when it is 24

filed. 25

Per Section 1731(b)(1), any application for rehearing must be filed within 10 days of the date of 26

the issuance of the order or decision. 27

4

Per Section 1731(d), the Commission is to issue its decision on any application for rehearing 1

within 210 days of the filing for rehearing. 2

Per Section 1756(a), any appeal must be made directly to the court of appeal or the California 3

Supreme Court and must be filed within 30 days after the Commission denies rehearing. 4

True Sale: Authorizes the transfer of Recovery Property by SCE to another entity as an “absolute 5

transfer” and “true sale,” provided that the governing documentation expressly states that the transfer 6

is an “absolute transfer” and a “true sale.” 7

Pledge of Property Right as Collateral: Authorizes the pledge of Recovery Property by its owner 8

for the benefit of Recovery Bond investors. 9

IV. 10

MATURITY AND SIZING OF THE PROPOSED TRANSACTION 11

SCE requests authority for a first series of Recovery Bonds to be sized and marketed to minimize 12

costs in the Authorized Amount,3 consisting of an amount equal to the sum of (i) the Initial AB 1054 13

CapEx, (ii) the debt financing costs of the Initial AB 1054 CapEx (“Pre-Securitization Debt Financing 14

Costs”), and (iii) Upfront Financing Costs (as defined below) associated with the issuance of each series 15

of Recovery Bonds. To attract a broad range of investors, each series may be divided into multiple 16

tranches, each with its own scheduled final payment date and final legal maturity date. A final legal 17

maturity date beyond the scheduled final payment date is a standard feature that allows for delays in 18

scheduled principal payments due to variations in the cash flows from the recovery property. The tenor 19

and amortization details for the Recovery Bonds of each series would be determined at issuance. 20

V. 21

PROPOSED TRANSACTION STRUCTURE 22

SCE has proposed a transaction structure for the first series of Recovery Bonds that is authorized 23

by AB 1054 and is consistent with achieving the highest possible credit ratings on the Recovery Bonds. 24

This transaction structure is described below. The Recovery Bonds will be issued by a wholly-owned, 25

3 The Authorized Amounts are listed in Appendix 3.1, Table 1 and Table 2 and, other than the amount for the

Initial AB 1054 CapEx, they are estimates, with final amounts to be included in the Issuance Advice Letter.

5

special purpose entity (the “SPE”) that will be created and capitalized by SCE, as described below. The 1

Bonds will be secured by “Recovery Property,” which Section 850(b)(11) defines as the right, title and 2

interest of SCE: (i) in and to Fixed Recovery Charges, including all rights to obtain adjustments to Fixed 3

Recovery Charges in accordance with Article 5.8 and a Financing Order, and (ii) to be paid the amount 4

that is determined in a Financing Order to be the amount that SCE is lawfully entitled to receive 5

pursuant to the provisions of Article 5.8 and the proceeds thereof, and in and to all revenues, collections, 6

claims, payments, moneys, or proceeds of or arising from the Fixed Recovery Charges. Article 5.8 7

requires the Commission to set these rates at a level that provides sufficient funds to timely pay debt 8

service on the Bonds and other “Financing Costs.”4 SCE refers to these Financing Costs, which are 9

associated with servicing the Recovery Bonds and supporting the operations of the SPE, as “Ongoing 10

Financing Costs.” 11

SCE will transfer the Recovery Property via a true sale and absolute transfer to the SPE that is 12

legally separate and bankruptcy remote from SCE. This ensures that if SCE ever becomes bankrupt, the 13

Recovery Property will not be included in SCE’s bankruptcy estate. Rather, the revenues from the 14

Recovery Property will continue to be available to pay the debt service on the Recovery Bonds and other 15

Ongoing Financing Costs. The Recovery Bonds will be issued under an indenture and administered by a 16

Bond Trustee. The Recovery Property as well as all other rights and assets of the SPE (“Bond 17

Collateral”) will be pledged to the Bond Trustee for the benefit of the holders of the Recovery Bonds 18

and to secure payment of debt service on the Bonds and other Ongoing Financing Costs. 19

SCE will contribute equity to the SPE equal to at least 0.50 percent of the initial aggregate 20

principal amount of the Recovery Bonds. The SPE equity will be pledged as Bond Collateral to secure 21

the Recovery Bonds and will be deposited into a capital subaccount (described below) held by the Bond 22

Trustee. This equity contribution is a requirement of the Internal Revenue Service (“IRS”) in order to 23

characterize the Recovery Bonds as obligations of SCE for Federal income tax purposes.5 24

4 Section 850.1(e). The definition of “Financing Costs” is set forth in Section 850(b)(4).

5 See IRS Rev. Proc. 2005-62.

6

To fund the acquisition of the Recovery Property, the SPE will issue Recovery Bonds to 1

investors. The Recovery Bonds will be secured by the Bond Collateral held by the Bond Trustee. 2

Holders of Recovery Bonds secured by this Bond Collateral may exercise all remedies pursuant to this 3

security interest if there is a default. The proceeds (net of Upfront Financing Costs) from the Recovery 4

Bonds will be transferred from the SPE to SCE as payment of the purchase price for the Recovery 5

Property. 6

The following diagram illustrates the Bond transaction structure: 7

Bond Transaction Structure

The Bond Trustee will retain all Fixed Recovery Charge collections received from SCE in a 8

collection account (the “collection account”) and distribute these funds to make scheduled principal and 9

interest payments on the Recovery Bonds and to pay other Ongoing Financing Costs in accordance with 10

the bond indenture “waterfall” provisions. SCE anticipates that the collection account would include 11

three subaccounts: (1) a general subaccount to hold revenues and investment earnings pending 12

application under the indenture waterfall provisions (the “general subaccount”), (2) a capital subaccount 13

to hold the equity capital contribution made by SCE (the “capital subaccount”), and (3) an excess funds 14

subaccount to hold revenues and investment earnings collected in excess of amounts necessary to pay 15

principal, interest and other Ongoing Financing Costs (the “excess funds subaccount”). The collection 16

account may also contain additional accounts to accommodate any credit enhancements (including any 17

overcollateralization subaccount) approved in an Issuance Advice Letter. The Bond Trustee would 18

7

invest all Fixed Recovery Charge collections in investment grade short-term debt securities that mature 1

on or before the next Recovery Bond payment date. Any investment earnings would be retained in the 2

collection account to pay principal, interest or other Ongoing Financing Costs. If any funds remain in 3

the collection account after distributions are made on a Recovery Bond payment date, they would be 4

credited to the excess funds subaccount. These amounts in the excess funds subaccount as well as the 5

capital subaccount would be available to pay principal, interest or other Ongoing Financing Costs as 6

they come due. Any excess moneys in the excess funds subaccount would be used to offset and reduce 7

the Fixed Recovery Charge on the next Fixed Recovery Charge adjustment date. 8

Upon payment in full of all Recovery Bonds and the discharge of all Ongoing Financing Costs, 9

amounts remaining with the Bond Trustee would be distributed in the following order of priority: first, 10

an amount equal SCE’s initial equity contribution into the capital subaccount, together with any required 11

rate of return would be paid to SCE, and second, all other amounts held by the Bond Trustee in any fund 12

or account (including any overcollateralization account) would be returned to SCE, and such amounts, 13

together with any Fixed Recovery Charge revenues thereafter received by SCE, would be credited to 14

customers through normal ratemaking processes. 15

The Commission shall have full access to the books and records of the SPE. SCE shall not make 16

any profit from the SPE, provided that, as requested by SCE and as described in this Exhibit SCE-03 of 17

the Application, it shall be entitled to receive a return on its equity contribution equal to the weighted 18

average interest rate on the Recovery Bonds. The equity contribution will be deposited in the capital 19

subaccount. The return owed to SCE will be payable as an Ongoing Financing Cost from Fixed 20

Recovery Charge revenues after payment of debt service on the Recovery Bonds and all other Ongoing 21

Financing Costs. 22

The transaction structure described above is consistent with prior utility securitizations and is 23

designed to ensure the highest possible rated Recovery Bonds. Section VII describes how the 24

transaction structure addresses rating agency concerns, as well as tax and accounting treatment. 25

As described in SCE-07, SCE has proposed that the Commission approve the use of this 26

transaction structure by SCE in connection with future issuances of recovery bonds (“Additional 27

8

Recovery Bonds”) issued by additional SPE’s (“Additional SPEs”) to recover other Section 850 et seq. 1

costs and expenses, including the remainder of SCE’s Total AB 1054 CapEx. 2

VI. 3

PROPOSED RECOVERY BOND STRUCTURE AND PAYMENT TERMS 4

SCE is considering different structuring possibilities for the first series of Recovery Bonds. 5

These same considerations should be relevant to the structuring of future Additional Recovery Bond 6

issuances. To attract a broad range of investors, the Recovery Bonds may be divided into multiple 7

tranches, each with its own scheduled final payment date and final legal maturity date. A final legal 8

maturity date beyond the scheduled final payment date is a standard feature that allows for delays in 9

scheduled principal payments due to variations in the cash flows from the recovery property. The 10

number of tranches, as well as the principal amount, scheduled final payment dates, and final legal 11

maturity dates, interest rate, interest payment dates and other details of each tranche would be 12

determined at the time each series of Recovery Bonds is priced, to reduce, to the maximum extent 13

possible, the rates that Consumers would pay. 14

SCE proposes that the first series of Recovery Bonds will be fixed rate instruments, in order to 15

ensure predictable savings to Consumers. SCE further proposes that the first series of Recovery Bonds 16

be repaid using a level, mortgage style amortization, with full repayment scheduled not later than 18 17

years following the issuance date and the final legal maturity of the latest maturing tranche of Bonds 18

will be no later than 20 years after the date of issuance. The Recovery Bonds may have an initial 19

payment period longer than other payment periods to accommodate the impact of billing delays due to 20

the limitations of the implementation of SCE’s new billing system (as discussed in Exhibit SCE-06). 21

Each separate Recovery Bond tranche would be priced based on its average life (or maturity), 22

determined by the principal amortization schedule at the time of issuance. The pricing would be a basis 23

point spread over the swap rate or the rate on United States Treasury Notes with a comparable average 24

life. The pricing of utility securitizations is discussed more generally in Mr. Chang’s testimony in 25

Exhibit SCE-02. The final details of the Recovery Bonds in this Securitization would be provided in an 26

9

Issuance Advice Letter submitted with the Commission after pricing, in the form shown in Attachment 2 1

to the Financing Order. 2

With the advice of its structuring advisor, SCE has developed a proposed Recovery Bond 3

payment structure for this first series of Recovery Bonds, including tranches and estimated interest rates, 4

which is set forth below. 5

Preliminary Recovery Bond Structure

This structure has been used in the savings comparisons provided in Exhibit SCE-04. The 6

structure may be adjusted at the time of pricing to reflect current market conditions and to reduce, to the 7

maximum extent possible, the rates that Consumers would pay. 8

As further discussed below, based upon the advice of its structuring advisor and the current 9

market conditions, SCE does not anticipate including additional credit enhancements for this first series 10

of Recovery Bonds (e.g., overcollateralization, letters of credit, or bond insurance). However, if 11

circumstances warrant the inclusion of additional credit enhancement, SCE requests the flexibility to 12

include any such credit enhancement in the Recovery Bond structure. The inclusion of these features 13

subsequently would be approved through the Issuance Advice Letter process (described below). 14

SCE proposes that the final structure and terms of any future series of Additional Recovery 15

Bonds, including number of tranches, as well as the principal amount, scheduled final payment dates, 16

and final legal maturity dates, interest rates, payment dates and other details will be determined through 17

the same Issuance Advice Letter process, as described in Exhibit SCE-07. 18

VII. 19

TRANSACTIONAL ISSUES: CREDIT RATINGS, TAXES AND ACCOUNTING. 20

The proposed transaction structure is necessary to ensure the highest possible rated Recovery 21

Bonds. The transaction will be structured to address three issues—credit ratings, taxes, and 22

Class Balance Coupon Price Yield

Swap 

Benchmark

Spread to 

Swaps 

(bps)

Treasury 

Benchmark

Spread to 

Treasury 

(bps)

Average 

Life

First 

Principal 

Payment

Last 

Principal 

Payment

Principal 

Payment 

Windows Legal Final

A‐1 168,433,000 1.30% 99.998% 1.298% 0.398% 90 0.340% 96 5.49 11/15/2021 11/15/2030 11/21‐11/30 11/15/2032

A‐2 168,708,000 2.50% 99.991% 2.503% 0.803% 170 0.847% 166 14.21 11/15/2030 11/15/2038 11/30‐11/38 11/15/2040

Total 337,141,000

10

accounting—discussed below. These issues should be equally relevant to future Additional Recovery 1

Bond issuances. 2

A. Credit Rating Issues 3

Unambiguous support in regulatory approvals and legislative language would help ensure that 4

the Recovery Bonds receive the highest possible rating from nationally recognized credit rating 5

agencies. The credit analysis conducted by the rating agencies of the Recovery Bonds centers on the 6

extent to which the structure of the transaction isolates the securitized assets (Recovery Property) from 7

the credit risks of the originating company (SCE), and on the credit quality of those assets themselves. 8

The credit ratings would be based on several factors, including those listed in Exhibit SCE-02 and those 9

described below. 10

1. Bankruptcy Opinions 11

In connection with the transaction, SCE would provide to the credit rating agencies an opinion 12

from its legal counsel that: (1) the transfer of the Recovery Property from SCE to the SPE constitutes a 13

“true sale” for bankruptcy purposes; and (2) such SPE would not be substantively consolidated with 14

SCE for bankruptcy purposes. This legal opinion would provide assurance to the credit rating agencies 15

that each SPE’s assets (including Recovery Property) would not be part of SCE’s bankruptcy estate, and 16

thus not be available to SCE’s creditors, should SCE subsequently commence bankruptcy proceedings. 17

Instead, this revenue stream would continue to be collected for the SPE, which has pledged it to 18

investors to pay Recovery Bond debt service and other costs. 19

The Recovery Bond transaction structure would include the features required by counsel to 20

deliver the required “bankruptcy-remote” opinions, including (i) restrictions in the SPE organizational 21

documents limiting the activities of the SPE to the issuance of Recovery Bonds and related activities and 22

eliminating the SPE’s ability to voluntarily file for bankruptcy, (ii) the appointment of one or more 23

independent directors to the SPE board, (iii) the payment of servicing and administration fees adequate 24

to compensate SCE or any successor servicer for their costs of providing service, and (iv) adequate 25

notice to customers and creditors of SCE of the SPE’s ownership of the Recovery Property. These 26

11

structural characteristics, among others, should permit the delivery of the true sale and non-1

consolidation opinions by legal counsel required by the rating agencies. 2

2. FRC Characteristics 3

Article 5.8 provides that the FRCs would be both irrevocable and nonbypassable (as further 4

discussed in Exhibit SCE-06), which assures Recovery Bond investors that the FRCs would not be 5

interrupted, eliminated, or avoided by consumers in SCE’s Service Territory. Except for specified 6

exemptions in Section 850.1(i), the FRCs would be applicable to all existing and future electric 7

consumers in SCE’s Service Territory. 8

As further discussed in Exhibit SCE-06, the FRCs would be imposed on all non-exempted 9

consumers on a cents-per-kilowatt-hour (“kWh”) basis. Each customer class would pay an FRC based 10

on such class’s contribution to SCE’s distribution-related costs as described in Exhibit SCE-06, 11

beginning with the ones set in the 2018 General Rate Case (“GRC”) Phase 2 and updated periodically 12

pursuant to a Non-Routine True-Up Mechanism Advice Letter (described below). This is consistent 13

with the allocation for distribution charges applied to distribution capital expenditures under traditional 14

utility financing. SCE’s proposed rate design is discussed more particularly in Exhibit SCE-06. 15

In addition to the Authorized Amount, SCE must be able to recover, through Fixed Recovery 16

Charges, the Ongoing Financing Costs associated with servicing the Recovery Bonds and supporting the 17

operations of the SPE. These Ongoing Financing Costs include without limitation, servicing fees, 18

administration fees, accounting fees and expenses, rating agency surveillance fees, trustee fees and 19

expenses, independent director fees, printing / EDGARizing expenses, return on equity, miscellaneous 20

fees and expenses, and credit enhancement costs, if required, in order to ensure the bankruptcy 21

remoteness of the SPE and obtain the highest possible rating on the Bonds 22

3. True-Up Mechanism 23

The statutorily-authorized “true-up” mechanism, which is common to all utility securitizations 24

including those in California, is the critical credit enhancement feature for securitization bonds. This 25

mechanism requires the periodic adjustment of the FRCs so that the FRC revenues are sufficient to pay, 26

on a timely basis, the Recovery Bonds and all other Ongoing Financing Costs (including the 27

12

replenishment of any draws on the capital subaccount) related to such series of Recovery Bonds. Article 1

5.8 requires the Commission to adjust the FRCs at least annually, and more often if necessary, to ensure 2

the FRC revenues are sufficient to timely pay the Recovery Bonds and all other Ongoing Financing 3

Costs related to such series of Recovery Bonds. To satisfy this statutory requirement for a periodic true-4

up adjustment of the FRCs, SCE proposes that the FRCs be adjusted: (i) annually to correct any 5

overcollection or undercollection of FRC revenues; and (ii) more frequently, if necessary, to ensure that 6

the FRCs provide sufficient funds to timely pay the Recovery Bonds and all other Ongoing Financing 7

Costs related to such series of Recovery Bonds. SCE requests that the Commission approve the use of 8

an advice letter process to implement the periodic true-ups. Under SCE’s proposal, SCE would submit 9

annual Routine True-Up Mechanism Advice Letters at least 15 days before the annual adjustment date 10

specified in the Issuance Advice Letter (the “FRC annual adjustment date”). These submissions are 11

meant to ensure that the actual FRC collections are neither more nor less than required to repay the 12

Recovery Bonds and all other Ongoing Financing Costs related to such series of Recovery Bonds. 13

Because these annual Routine True-Up Mechanism Advice Letters should be ministerial, SCE proposes 14

that the revised FRCs in the annual Routine True-Up Mechanism Advice Letters (assuming timely filing 15

by SCE with the Commission) go into effect automatically on the FRC annual adjustment date. 16

SCE may also submit interim Routine True-Up Mechanism Advice Letters periodically as SCE 17

deems necessary. The interim true-up adjustment would be used if SCE forecasts that FRC collections 18

would be insufficient to make all scheduled payments of principal and interest on the Recovery Bonds 19

and other Ongoing Financing Costs (including the replenishment of any draws on the capital 20

subaccount) on a timely basis during the current or next succeeding payment period. If SCE determines 21

that an interim Routine True-up Mechanism Advice Letter is necessary, SCE would submit an interim 22

Routine True-Up Mechanism Advice Letter at least 15 days before the proposed effective date of the 23

FRC, and the revised FRC would go into effect automatically on such effective date (assuming timely 24

submission by SCE with the Commission). All Routine True-Up Mechanism Advice Letters would be 25

based on the pro forma example in Attachment 3 to the Financing Order. 26

13

SCE would submit annual and interim Routine True-Up Mechanism Advice Letters until the 1

Recovery Bonds and all other Ongoing Financing Costs are paid in full. In the case of any adjustments 2

occurring after the final scheduled payment date for a series of Recovery Bonds, there would be Routine 3

True-Up Mechanism Advice Letters submitted no less frequently than quarterly to obtain adjustments to 4

the FRCs necessary to correct for overcollections or undercollections by the earlier of the next bond 5

payment date or the final legal maturity date for the series. If SCE commits in any servicing agreement 6

to file semi-annual Routine True-Up Mechanism Advice Letter on a mandatory basis, to accommodate 7

rating agency considerations, such mandatory true-ups will be identified in the Issuance Advice Letter. 8

Prompt implementation of the Routine True-Up Mechanism Advice Letters is critical to the 9

rating agencies’ determination of: (1) the reliability and adequacy of funds to make debt service 10

payments on the Recovery Bonds, and (2) whether other credit enhancements would be required to 11

obtain the highest possible credit ratings. Since it is important that the Recovery Bonds have the highest 12

possible credit rating and because the Routine True-Up Mechanism Advice Letters should be 13

ministerial, the FRC adjustments proposed in Routine True-Up Mechanism Advice Letters would be 14

implemented automatically as described previously. Parties would have limited notice and opportunity 15

to protest the Routine True-Up Mechanism Advice Letters, and the Energy Division would review the 16

Routine True-Up Mechanism Advice Letters, but only to confirm the mathematical accuracy of the 17

proposed true-up adjustment. Therefore, even though SCE proposes that the Commission establishes a 18

mechanism to implement revisions to the FRCs automatically, all FRC-related Routine True-Up 19

Mechanism Advice Letters would be subject to protest, review, and correction to the extent allowed by 20

Section 850.1(e). However, any protest, review, and correction would be limited to the correction of 21

mathematical errors in the Routine True-Up Mechanism Advice Letter. No protest, review or required 22

modification to correct an error in a Routine True-Up Mechanism Advice Letter would delay its 23

effective date, and any correction or modification which could not be made prior to the effective date 24

would be made in the next true-up. 25

26

14

SCE may also submit Non-Routine True-Up Mechanism Advice Letters to reflect any revisions 1

to the “total distribution” allocation factors (as described in Exhibit SCE-06) adopted in any subsequent 2

GRC Phase 2 or other applicable proceeding (an “Allocation Factor Non-Routine Adjustment”) and may 3

also submit Non-Routine True-Up Mechanism Advice Letters to propose revisions to the logic, 4

structure, and components of the cash flow model described in Attachment 1 to the Financing Order (an 5

“Other Factor Non-Routine Adjustment”). Non-Routine True-Up Mechanism Advice Letters to reflect 6

Allocation Factor Non-Routine Adjustments (“Allocation Factor Non-Routine True-Up Mechanism 7

Advice Letters”) would be submitted at least 60 days before the date when the proposed changes would 8

become effective, with the resulting changes effective on the effective date identified in the Allocation 9

Factor Non-Routine True-Up Mechanism Advice Letter, except as provided below. Because Allocation 10

Factor Non-Routine Adjustments are part of the existing logic of the True-Up Mechanism, as with 11

Routine True-Up Mechanism Advice Letters, any protest, review or correction of such a submission 12

would be limited to the correction of mathematical errors in the Allocation Factor Non-Routine True-Up 13

Mechanism Advice Letter. If any modification to correct a mathematical error in such Allocation Factor 14

Non-Routine True-Up Mechanism Advice Letter must be made and cannot be implemented within the 15

60-day period, the Commission may delay its effective date for up to 30 days so that the correction can 16

be made. However, the FRCs would continue to be imposed under Routine True-Up Mechanism 17

Advice Letters using existing allocation factors until the Allocation Factor Non-Routine True-Up 18

Mechanism Advice Letter becomes effective. All Non-Routine True-Up Mechanism Advice Letters 19

would be based on the pro forma example in Attachment 4 to the Financing Order. 20

Non-Routine True-Up Mechanism Advice Letters to reflect Other Factor Non-Routine 21

Adjustments (“Other Factor Non-Routine True-Up Mechanism Advice Letters”) would be submitted at 22

least 90 days before the date when the proposed changes would become effective, with the resulting 23

changes effective on the effective date identified in the Other Factor Non-Routine True-Up Mechanism 24

Advice Letter. SCE proposes that the Energy Division prepare for the Commission’s consideration a 25

resolution that adopts, modifies, or rejects the proposed revisions to the cash flow model as proposed in 26

the Other Factor Non-Routine True-Up Mechanism Advice Letter. The public would have an 27

15

opportunity to review and protest an Other Factor Non-Routine True-Up Mechanism Advice Letter in 1

accordance with Commission procedures to the extent allowed by Section 850.1(e). Absent a 2

Commission resolution that adopts, modifies, or rejects the Other Factor Non-Routine True-Up 3

Mechanism Advice Letter, SCE may implement FRC adjustments proposed in an Other Factor Non-4

Routine True-Up Mechanism Advice Letter on the effective date identified in the letter. 5

The Routine True-Up Mechanism Advice Letters and Non-Routine True-Up Mechanism Advice 6

Letters would calculate a revised FRC for each series of Recovery Bonds using the cash flow model 7

described in Attachment 1 to the Financing Order, or a revised cash flow model as described in a Non-8

Routine True-Up Mechanism Advice Letter, as applicable, which would reflect the following 9

adjustments: 10

An adjustment would be made for the amount of any funds held by the Trustee in the general 11

subaccount or the excess funds subaccount as of date no earlier than fifteen business days 12

prior to the calculation date (the “Calculation Cut-Off Date”). 13

Estimated Ongoing Financing Costs would be modified to reflect actual costs. 14

An adjustment would be made to reflect any change in the write-off policy. 15

An adjustment would be made to reflect any change in the average days sales outstanding, 16

including any anticipated delay or acceleration of the collection of customer bills. 17

An adjustment would be made to reflect FRC collections that would be received at the 18

existing tariff rate after the Calculation Cut-Off Date. 19

All true-up adjustments to the FRCs would ensure the billing of FRCs necessary to satisfy the 20

Periodic Payment Requirement for the related series of Recovery Bonds for each of the two payment 21

periods following the effective date of the adjusted FRC. The amount of FRCs required to be billed to 22

consumers to satisfy the Periodic Payment Requirement (on or before the first day of the month 23

preceding a “Payment Date”) is referred to as the “Periodic Billing Requirement.” True-up submissions 24

would be based upon the cumulative differences, regardless of the reason, between the Periodic Payment 25

Requirement and the actual amount of FRC collections remitted to the Bond Trustee for the series of 26

Bonds. 27

16

In the Financing Order, SCE has requested that the Commission find that the Routine True-Up 1

Mechanism Advice Letters and Non-Routine True-Up Mechanism Advice Letters described above 2

constitute “applications” within the meaning of Section 850.1(g) and authorize SCE to submit these 3

Advice Letters to implement true-up adjustments to the FRCs. Further, SCE has requested that this 4

same true-up mechanism and methodology be approved for use to calculate Fixed Recovery Charges 5

supporting Additional Recovery Bond issuances. 6

4. Credit Enhancement, Capital Subaccount and Return 7

The SPE may obtain additional credit enhancements to ensure repayment of the Recovery Bonds 8

in the form of an overcollateralization subaccount if the credit rating agencies require 9

overcollateralization to receive the highest possible credit rating on the Recovery Bonds, or if the all-in 10

cost of the Recovery Bonds with the overcollateralization would be less than without the 11

overcollateralization. Overcollateralization is a credit enhancement technique in which amounts 12

collectible in relation to a financial asset exceed the required payments on security, ensuring investors 13

timely payment. The required amount of overcollateralization, if any, may be collected via the FRCs. 14

The overcollateralization requirement, if any, would be sized based upon input from the rating agencies 15

indicating the amount necessary to achieve the highest possible credit rating. Any overcollateralization 16

that is collected from consumers in excess of total debt service and other Recovery Costs would be the 17

property of the SPE. 18

SCE may also obtain bond insurance, letters of credit, and similar credit-enhancing instruments, 19

but only if required by the credit rating agencies to achieve the highest possible credit rating on the 20

Recovery Bonds, or if the all-in cost of the Recovery Bonds with these other credit enhancements would 21

be less than without the enhancements. 22

SCE does not anticipate requiring any external credit enhancements described in the preceding 23

paragraph for the first series of Recovery Bonds. Further, based upon current market conditions, SCE 24

does not anticipate being required by the credit rating agencies to establish an overcollateralization 25

subaccount for the first series of Recovery Bonds, but to the extent such an account is required, the exact 26

17

amount and timing of its collection via the FRCs would be determined before the Recovery Bonds are 1

issued and approved through the Issuance Advice Letter process. 2

In addition, the bond collateral held by the Bond Trustee would be available as a credit 3

enhancement. This collateral would include, as mentioned above, an equity contribution in an amount 4

required to obtain favorable IRS tax treatment for the transaction, as described below in Section B, Tax 5

Issues (i.e., currently 0.50 percent of the initial aggregate principal amount of the Recovery Bonds). If 6

the equity capital is drawn upon, it may be replenished from future FRCs. SCE has requested that it be 7

entitled to receive a return on its equity contribution equal weighted average interest rate on the 8

Recovery Bonds. This equity return would be paid as an Ongoing Financing Cost from the FRC 9

revenue and would be distributed to SCE on an annual basis, after payment of debt service on the 10

Recovery Bonds and other Ongoing Financing Costs. 11

5. FRC Revenue Forecasts 12

In addition to evaluating the effectiveness of the FRC true-up mechanism, the rating agencies 13

would also analyze SCE’s ability to make accurate forecasts of energy usage by its community choice 14

aggregation, community aggregation, bundled and direct access electric customers, by looking at 15

historical data on a forecasted versus actual usage basis. The rating agencies are expected to apply a 16

wide range of assumptions on uncollectibles, average days to customer payment (or “average days sales 17

outstanding”), and energy usage as well as the effectiveness of the true-up mechanism to assess the 18

sensitivity of FRC revenues to changes in those assumptions. 19

6. Billing by Third Parties 20

The rating agencies would also focus on the financial strength and the billing and collecting 21

experience of the servicer. Although not common, third parties bill and collect payments from some of 22

the customers that would pay the FRC.6 In order to ensure that the Recovery Bond credit rating would 23

not be adversely affected, SCE requests that the Commission continue to require that the following 24

6 Currently, out of 27,000 direct access customers, SCE provides consolidated billing for approximately 5,000

customers and shares billing responsibility with the third-party biller for 22,000 customers; only 80 customers are billed exclusively by a third-party biller.

18

principles be applied in establishing minimum standards for all electric service providers or other third 1

parties (“Third Party Billers”) that bill and collect the FRC from electric consumers. 2

Regardless of who would be responsible for performing the billing and collection functions, 3

consumers must always be responsible for paying the FRCs. This clear and continuing 4

consumer obligation is unaffected by Third Party Billers billing and collecting the FRC and 5

then remitting their aggregated FRC collections to SCE. 6

Even if a Third Party Biller performs the metering and billing functions for the FRC, SCE 7

must have access to information regarding customer usage and billings in order to properly 8

report FRC revenues to the Bond Trustee as required under its Servicing Agreement. 9

To minimize investors’ credit risk in the case of non-payment of the FRC, appropriate shut-10

off policies must be maintained to allow action by SCE in the case of non-payment of the 11

FRC, regardless of who is responsible for billing and collecting the FRC; provided, however, 12

that temporary changes in utility shut-off procedures due to emergencies, such as the current 13

COVID-19 pandemic, should be permitted. 14

Appropriate standards, procedures, and credit policies must be in place to ensure that the 15

collection of FRCs by a Third Party Biller does not result in an increased risk to Recovery 16

Bond investors. Such standards should be consistent with existing rating agency standards 17

governing billing, collecting, and reporting for servicers in similar utility asset-backed 18

securities transactions. Rating agencies and potential Recovery Bond investors would see an 19

additional layer of risk if Third Party Billers with less than investment grade credit ratings 20

collect and hold FRCs prior to remittance to SCE. To ensure that the risk associated with 21

Third Party Biller default is mitigated, rating agencies would want to see that appropriate 22

credit policies are in place. For example, if a Third Party Biller conducting metering and 23

billing were not rated or were rated below investment grade, the rating agencies might 24

require that all customer collections be remitted daily or, alternatively, might require security 25

deposits, letters of credit, or other forms of credit enhancement from SCE. Furthermore, a 26

Third Party Biller conducting metering and billing must have systems capabilities and 27

19

procedures in place that are necessary to bill, collect, and report, and as applicable, pay the 1

FRCs over to SCE. 2

In the event of default by a Third Party Biller conducting metering and billing, billing and 3

collecting responsibilities must be promptly transferred to another party to minimize 4

potential losses of FRC revenues. If a Third Party Biller defaults on its timely payments to 5

SCE of FRC collections, the rating agencies would expect prompt action to replace the 6

defaulting entity to assure that the FRCs paid by consumers could be passed on to Recovery 7

Bond investors. SCE’s current electric rules meet this requirement by requiring that 8

defaulting Third Party Billers be replaced by SCE for metering and billing within two 9

months.7 10

Maintaining these guidelines is important to achieving the highest possible credit rating and the 11

minimum ratepayer cost associated with the Recovery Bond issuance. As a result, SCE requests that the 12

Commission continue to require that SCE maintain appropriate procedures for Third Party Billers 13

conducting metering and billing as set forth in SCE’s Electric Rule 22.P., “Credit Requirements.” 14

7. Legislative and Regulatory Risks; Risk of Municipalization 15

Additional factors the rating agencies would consider when rating the Recovery Bonds are the 16

legislative risks associated with Article 5.8, including the risk that the authorizations or requirements 17

therein could be overturned or abolished in the future by any means, including voter initiatives. Since 18

the amendments to Article 5.8 in AB 1054 were passed by very high margins in the California 19

Legislature, SCE expects the rating agencies to conclude that the legislative risk associated with the 20

transaction should not affect the Recovery Bond credit ratings. Furthermore, the support of key 21

customer constituencies in both the legislative and regulatory process should also reassure the rating 22

agencies that the voter initiative risk should not affect the Recovery Bond ratings. 23

The rating agencies would also analyze the regulatory risk associated with the transaction. As 24

stated in Article 5.8, the Commission’s financing orders and the FRC would be irrevocable. The 25

7 SCE’s Electric Rule 22, Section N and Rule 22.1, Section A.2 (referencing 60 days for transition back to

bundled service, including billing and collection, if third party billers cannot fulfill their obligations)

20

Commission would not have authority either by rescinding, altering or amending the financing order or 1

otherwise, to revalue or revise for ratemaking purposes the recovery costs or the costs of recovering, 2

financing, or refinancing the recovery costs, or in any way to reduce or impair the value of Recovery 3

Property either directly or indirectly by taking FRCs into account when setting other rates. 4

In the event of a future municipalization or an acquisition of SCE’s facilities by an entity that 5

does not set retail rates subject to the Commission’s regulation, the Commission would ensure continued 6

payment of FRCs by placing conditions on the Commission’s approval of the transaction.8 By 7

conditioning its approval on the continued payment of FRCs, the Commission’s approach would respect 8

the State’s legal obligation under AB 1054 not to limit or alter the FRCs until the Recovery Bonds and 9

all related Ongoing Financing Costs are fully paid.9 10

Nevertheless, the quality of the financing order, particularly with regard to the initial tariff 11

implementation, the true-up mechanism and requirements for Third Party Billers, including potentially 12

municipal acquirers, would be carefully reviewed by the rating agencies when they determine the rating 13

of the Recovery Bonds. 14

B. Tax Issues 15

The transaction would be structured to be a “Qualifying Securitization” pursuant to IRS Revenue 16

Procedure 2005-62 such that: (1) the SPE will be a wholly owned subsidiary of SCE capitalized with an 17

equity interest of at least 0.5 percent of the initial aggregate principal amount of Recovery Bonds issued; 18

(2) the Recovery Bonds will be secured by the Recovery Property; (3) the FRCs will be nonbypassable 19

and payable by consumers within SCE’s Service Territory; and (4) payments on the Recovery Bonds 20

8 See SB 550 (2019); Pub. Util. Code §§ 851(a), (b)(1), 854.2(b)(1)(F). Taken together, those provision require

the Commission’s authorization for any sale or disposition of the utility’s system or property (via a transaction greater than $5 million), including for any “voluntary or involuntary change in ownership of assets from an electrical or gas corporation to ownership by a public entity.”

9 See Pub. Util. Code § 850.1(e) (“The State of California does hereby pledge and agree with the electrical corporation, owners of recovery property, financing entities, and holders of recovery bonds that the state shall neither limit nor alter, except as otherwise provided with respect to the true-up adjustment of the FRCs pursuant to subdivision (i), the FRCs, any associated fixed recovery tax amounts, recovery property, financing orders, or any rights under a financing order until the recovery bonds, together with the interest on the recovery bonds and associated financing costs, are fully paid and discharged …”).

21

would be on a semi-annual basis except for the initial payment period which may be longer. As a 1

“Qualifying Securitization,” the establishment of the Recovery Property, the transfer of Recovery 2

Property to the SPE, and the issuance of Recovery Bonds will not cause current recognition of gross 3

income to SCE for federal income tax purposes. The transfer would not be treated as a sale for tax 4

purposes, and the Recovery Bonds will be treated as SCE’s own debt for tax purposes. SCE would 5

secure an opinion of tax counsel to the effect that the Recovery Bond transaction is a “Qualifying 6

Securitization” under IRS Revenue Procedure 2005-62. 7

Exhibit SCE-05 describes the tax consequences of the Securitization and the Initial AB 1054 8

CapEx and the calculation of the net present value of the tax benefits. SCE anticipates that these upfront 9

tax benefits may be reversed by net cash flow deficits in later years, so proposes addressing tracking and 10

treatment of tax impacts outside of this securitization, using standard ratemaking mechanisms. 11

C. Accounting Issues 12

The Recovery Bonds would be recorded as debt on SCE’s consolidated balance sheet. This is 13

either positive or neutral to rating agency calculations of debt depending on whether the rating agency 14

considers the Recovery Bond debt as on or off balance sheet for credit purposes, as further discussed in 15

Exhibit SCE-02. SCE would include a note to its financial statements disclosing that the Recovery 16

Bonds are secured solely by Recovery Property and related collateral subaccounts (including the SPE 17

equity); that Recovery Bond investors have no recourse to any assets or revenues of SCE; that while 18

such SPE is a subsidiary of SCE, it is legally separate from SCE; that the assets of such SPE are not 19

available to creditors of SCE; and that the Recovery Property is not legally an asset of SCE. 20

VIII. 21

SERVICING THE RECOVERY BONDS 22

SCE intends to act as servicer for the Recovery Property that would be pledged to secure the 23

Recovery Bonds, as reflected in a Servicing Agreement between SCE and the SPE. The role of the 24

servicer in utility securitizations is generally described by Mr. Chang in Exhibit SCE-02. In its capacity 25

as servicer, SCE would be responsible for determining consumers’ electricity usage, billing, collecting, 26

and remitting the FRC to the Bond Trustee, and submitting Routine True-up Mechanism Advice Letters 27

22

and Non-Routine True-up Mechanism Advice Letters as described above. To the extent SCE’s 1

consumers of electricity are billed by Third Party Billers, SCE proposes to bill these Third Party Billers 2

for the FRC, with the Third Party Billers being obligated to remit FRC collections to SCE. SCE would 3

remit estimated FRC collections to date, on behalf of the SPE, to the Bond Trustee, as described in 4

Section IX below. The Bond Trustee would be responsible for making principal and interest payments 5

to Recovery Bond investors and paying other Ongoing Financing Costs. 6

The SPE would be required to pay SCE a servicing fee that constitutes fair and adequate 7

consideration sufficient to obtain the true sale and bankruptcy opinions. The Bond Trustee would pay 8

this servicing fee to SCE as servicer from FRC collections. SCE expects to charge an annual servicing 9

fee of $168,571 (representing a servicing fee of 0.05 percent of the initial principal amount), plus out-of-10

pocket expenses (e.g., legal, accounting fees), to cover SCE’s incremental costs and expenses in 11

servicing the Recovery Bonds. In the event that SCE fails to perform its servicing functions 12

satisfactorily, as set forth in the Servicing Agreement, or is required to discontinue its billing and 13

collecting functions, an alternate servicer acceptable to the Bond Trustee, acting on behalf of the 14

Recovery Bond holders and approved by the Commission, would replace SCE and assume such billing 15

and collecting functions. In the event SCE is replaced and the new servicer must bill only the FRC 16

instead of the entire customer bill, servicing fees would be up to 0.60 percent of the initial Recovery 17

Bond principal amounts in order to ensure that a new servicer can be retained. As discussed above and 18

in Exhibit SCE-02, the credit quality and expertise in performing servicing functions are important 19

considerations when appointing an alternate servicer to ensure the Recovery Bond credit ratings are 20

maintained. Exhibit SCE-02 provides support for the servicing fees for SCE and any replacement 21

servicer. Moreover, SCE believes that the remedy of allowing the Commission to sequester Fixed 22

Recovery Charges in the cases of certain events of default under the Servicing Agreement upon the 23

application of the Bond Trustee, as permitted by Section 850.3(e), will enhance the credit quality of the 24

Recovery Bonds. 25

23

If SCE no longer performs servicing functions, the servicing fee would be paid directly to the 1

successor servicer by the Bond Trustee. SCE should not resign as servicer without prior Commission 2

approval. 3

IX. 4

ADMINISTRATOR FOR THE SPE 5

As described above, the Recovery Bonds would be issued by a “bankruptcy-remote” SPE. The 6

SPE would have no employees. As a consequence, SCE must provide administrative services to the 7

SPE for the SPE to function as an independent legal entity. These administrative services may include, 8

among others, maintaining general accounting records, preparation of quarterly and annual financial 9

statements, arranging for annual audits of the SPE’s financial statements, preparing all required external 10

financial filings, preparing any required income or other tax returns, and related support. These services 11

are separate from those of the servicer. 12

To compensate SCE for its administrative services and thus ensure the “bankruptcy remote” 13

status of the SPE as discussed above, SCE would be paid an annual administration fee of $75,000 per 14

year plus out-of-pocket expenses (e.g., legal, accounting fees). This compensation is meant to cover 15

expenses associated with administrative services provided by SCE. Exhibit SCE-02 provides support 16

for the administration fee. 17

X. 18

ONGOING FINANCING COSTS 19

In addition to principal and interest on the Recovery Bonds, consumers would pay, through the 20

FRC, the other Ongoing Financing Costs associated with servicing the Recovery Bonds and supporting 21

the operations of the SPE. These Ongoing Financing Costs include the amounts payable to SCE as 22

servicer or any successor servicer (as discussed above), the amounts payable to SCE as administrator (as 23

discussed above), trustee fees and expenses, independent director fees, legal fees and expenses, 24

accounting fees, rating agency surveillance fees, a return on SCE’s equity contribution, or invested 25

capital, deposited in the capital subaccount as well as any amounts required to replenish the capital 26

subaccount if there has been a draw from such account, and miscellaneous other costs and expenses 27

24

associated with servicing of the Recovery Bonds. Ongoing Financing Costs also include any payments 1

for any credit enhancement, including payments to third party credit support providers (e.g., letters of 2

credit or bond insurance providers), and any amount required to fund or replenish any reserve or 3

overcollateralization relating to the Recovery Bonds. Based upon current market conditions and the 4

advice of its structuring advisor, SCE does not anticipate that any such credit enhancement would be 5

required for the initial series of Recovery Bonds, but SCE requests the flexibility to utilize credit 6

enhancement should market conditions change and the use of credit enhancement would result in lower 7

charges to consumers. Any such credit enhancement would be subject to approval through the Issuance 8

Advice Letter process (described below). 9

Certain of these Ongoing Financing Costs, such as the administration fees and the amount of the 10

servicing fee for SCE (as the initial servicer) would be determinable, either by reference to an 11

established dollar amount or a percentage, on or before the issuance of any series of Recovery Bonds. 12

SCE’s return on its equity contribution, or invested capital, would depend upon actual interest rates on 13

each series of Recovery Bonds. Other Ongoing Financing Costs would vary over the term of the 14

Recovery Bonds. Ongoing Financing Costs would be recoverable from the Fixed Recovery Charges, 15

regardless of their amounts. 16

SCE has estimated Ongoing Financing Costs (assuming SCE will be the servicer, and that no 17

overcollateralization or other credit enhancement is required) to be approximately $0.5 million on an 18

annualized basis. These estimates are shown on Appendix 3.2 to this testimony. 19

XI. 20

BILLING AND REMITTANCE OF FRCs; APPLICATION OF REVENUES BY BOND 21

TRUSTEE 22

SCE would be responsible for remitting the FRC collections to the Bond Trustee. As previously 23

described, SCE would sell its right to FRC revenues and, as servicer, would be responsible for remitting 24

the FRC collections to the Bond Trustee. Because it would be operationally difficult and costly for SCE 25

to track actual collections in real time, SCE would remit estimated FRC revenues to the Bond Trustee. 26

SCE expects to remit estimated FRC revenues to the Bond Trustee on a daily basis and within two 27

25

business days of the date SCE projects it would have received such payments based upon its collection 1

history, to avoid an adverse impact on the Recovery Bond credit ratings. Estimated FRC daily 2

remittances would be based on daily billed amounts, historical delinquency patterns, and the historical 3

average number of days customer bills remain outstanding. 4

Over the life of the Recovery Bonds, SCE would prepare a monthly servicing report for the Bond 5

Trustee that shows the estimated FRC revenues by month. Not less often than semi-annually (or in the 6

case of the first year after the Recovery Bond issuance, following the first payment date), SCE will 7

compare actual Fixed Recovery Charge collections to the estimated Fixed Recovery Charge revenues 8

that have been remitted to the Bond Trustee. Such reconciliation shall be conducted within 60-days 9

following the end of such semi-annual (or initial payment) period. SCE may calculate “actual” Fixed 10

Recovery Charge collections based upon delinquency and payment patterns (days sales outstanding) 11

during such six month (or initial) period. The difference between the estimated Fixed Recovery Charge 12

revenues and the actual Fixed Recovery Charge collections, if there has been an over-remittance to the 13

Bond Trustee, would be netted against the following month’s remittance(s) to the Bond Trustee, or, if 14

there has been an under-remittance by SCE, would be deposited with the Bond Trustee by SCE within 15

ten days. 16

The Bond Trustee (acting on behalf of the SPE) would have a legal right to only the amount of 17

actual FRC cash collections. SCE acknowledges that, although it is remitting FRC charges based upon 18

an estimated basis, amounts collected that represent partial payments of a customer’s bill will be 19

allocated between the Bond Trustee and SCE based on the ratio of the portion of the billed amount 20

allocated for the Fixed Recovery Charge to the total billed amount. This allocation is an important 21

bankruptcy consideration in determining the true sale nature of the transaction. In the event of any 22

default by the Servicer, the Trustee will be entitled to receive a reconciliation of collections based upon 23

actual Fixed Recovery Charges, including this pro-rata allocation. In the event Additional Recovery 24

Bonds are issued by Additional SPEs, the Fixed Recovery Charges should be allocated pro rata between 25

the Bond Trustees for each series. 26

26

XII. 1

ISSUANCE ADVICE LETTER PROCESS 2

As described above, the final terms and structure of the Recovery Bonds, including (without 3

limitation) the principal amount, interest rates, number of tranches and principal amortization, scheduled 4

final payment dates and final legal maturity dates of each tranche, as well as the use of any credit 5

enhancement, would be determined at or before the time each series of Recovery Bonds is priced. The 6

final terms and structure would be designed, with the advice of the underwriters, with the objective of 7

reducing, to the maximum extent possible, the total cost of borrowing and, as a consequence, the total 8

cost to consumers. 9

SCE proposes that the final terms and structure of the Recovery Bonds, updated estimates of the 10

Upfront Financing Costs and the Ongoing Financing Costs for the first two Payment Periods after 11

issuance, as well as the initial FRCs, be set forth in an Issuance Advice Letter to be submitted with the 12

Commission not later than one business day after pricing. The Issuance Advice Letter would be in the 13

form shown in Attachment 2 to the Financing Order. This Commission has approved the use of an 14

Issuance Advice Letter process in prior financing orders.10 SCE proposes that the final terms and 15

structure of the Recovery Bonds, the recovery of Upfront Financing Costs and all Ongoing Financing 16

Costs incurred over the life of the Recovery Bonds, as well as the initial FRC, automatically be 17

approved and become effective at noon on the fourth business day after pricing unless before noon on 18

10 See In the Matter of the Application of Pacific Gas and Electric Company for: (1) Authority to Sell or Assign

Recovery Property to One or More Financing Entities; (2) Authority to Service Recovery Bonds on Behalf of Financing Entities; (3) Authority to Establish Charges Sufficient to Recover Fixed Recovery Amounts and Fixed Recovery Tax Amounts; and (4) Such Further Authority Necessary for PG&E to Carry Out the Transactions Described in this Application. (U 39 M) Decision 04-11-015 (November 19, 2004), Ordering Paragraph 33 (cited herein as “PG&E 2005 Order”). See generally In the Matter of the Application of the Southern California Edison Company (U 338-E) For: (1) Authority to Reduce Rates Effective January 1, 1998; (2) Authority to Sell or Assign Transition Property to One or More Financing Entities; (3) Authority to Service Application 97-05-018 Rate Reduction Bonds on Behalf of Financing Entities; (4) Authority to Establish Charges (Filed May 6, 1997) Sufficient to Recover Fixed Transition Amounts; and (5) Such Further Authority Necessary for Edison to Carry out the Transactions Described in this Application, Decision 97-09-056 September 3, 1997.

27

the fourth business day after pricing the Commission issues an order finding that the proposed issuance 1

does not comply with the requirements of the Financing Order. 2

As and to the extent required by the Commission, any Commission representatives would be 3

updated continuously throughout the marketing and pricing process to ensure timely final approval of 4

the Recovery Bond transaction. 5

As described in Exhibit SCE-07, SCE requests the final terms and structure of any series of 6

Additional Recovery Bonds will be determined through the same Issuance Advice Letter process. 7

XIII. 8

UPFRONT FINANCING COSTS, PRE-SECURITIZATION DEBT FINANCING COSTS, AND 9

USE OF NET PROCEEDS 10

Financing costs (as defined in Section 850(b)(4)) associated with the issuance and any credit 11

enhancement of the Recovery Bonds would be financed from the proceeds of the Recovery Bonds. 12

Such Upfront Financing Costs include underwriting fees and expenses, legal fees and expenses 13

(including those associated with this financing application), rating agency fees, accounting fees and 14

expenses, company’s advisory fee, servicer set-up costs, Securities and Exchange Commission (“SEC”) 15

registration fees, Section 1904 fees, printing and EDGARizing expenses, trustee / trustee counsel fees 16

and expenses, original issue discount, any Commission costs and expenses, and other miscellaneous 17

costs approved in the Financing Order. Upfront Financing Costs include reimbursement to SCE for 18

amounts advanced for payment of such costs. Upfront Financing Costs may also include the costs of 19

credit enhancements, as described above, including the costs of funding any reserve or 20

overcollateralization account or of purchasing a letter of credit or bond insurance policy. 21

SCE estimates that the Upfront Financing Costs associated with the Recovery Bonds, assuming 22

no credit enhancement, would be approximately $5.4 million, as shown in Table 1 of Appendix 3.1. 23

However, Upfront Financing Costs are subject to change, as the costs are dependent on the timing of 24

issuance, market conditions at the time of issuance, and other events outside SCE’s control, such as 25

possible litigation, incremental legal fees resulting from protracted resolution of issues, possible review 26

by the Commission, delays in the SEC registration process, and rating agency fee changes and 27

28

requirements. When the Recovery Bonds are sized and priced, Upfront Financing Costs would be 1

updated and included in the Issuance Advice Letter. 2

If the estimated Upfront Financing Costs included in the Issuance Advice Letter exceed actual 3

Upfront Financing Costs, any excess would be credited to the excess funds subaccount and used to 4

offset the revenue requirement in the next routine FRC true-up calculation. In the event that the actual 5

Upfront Financing Costs exceed the estimated amount in the Issuance Advice Letter, the shortfall 6

amount may be recovered in the next routine true-up adjustment for the Fixed Recovery Charges. 7

SCE has incurred and will incur Pre-Securitization Debt Financing Costs associated with 8

financing the Initial AB 1054 CapEx before issuance of the Recovery Bonds. These costs are broken 9

out in Table 2 of Appendix 3.1. In D.20-04-013, the decision approving the GSRP Settlement, the 10

Commission approved the revenue requirements (including applicable return consistent with Section 11

8386.3(e), which constitutes the Pre-Securitization Debt Financing Costs) associated with the Initial AB 12

1054 CapEx. Advice Letter 4197-E, which implements this decision, is pending review and approval 13

before the Commission. Because the disposition of Advice Letter 4197-E implementing the GSRP 14

decision will approve the Pre-Securitization Debt Financing Costs, there is no need for the Commission 15

to further review these costs and expenses in this proceeding. SCE anticipates receiving a final 16

disposition of Advice Letter 4197-E before the conclusion of this proceeding. However, to the extent 17

that does not occur, SCE requests authorization to recover the Pre-Securitization Debt Financing Costs 18

in the Financing Order as part of the Authorized Amount. 19

SCE would use the net proceeds received from the sale of the Recovery Bonds to pay or 20

reimburse SCE for costs and expenses related to the Initial AB 1054 CapEx, including Pre-21

Securitization Debt Financing Costs. SCE also requests authorization pursuant to Section 823(d) to 22

refund its short-term debt in connection with issuance of the Recovery Bonds. As discussed in Exhibit 23

SCE-06, SCE will use the net proceeds to reduce the AB 1054 sub-account of the GSRP balancing 24

account. 25

29

XIV. 1

CONCLUSION 2

SCE requests that the Commission approve the proposed transaction and transaction structure as 3

described in this Exhibit. SCE further requests that the transaction structure, including the true-up 4

mechanism and servicing arrangements, be found to be just and reasonable and in the public interest to 5

recover other Section 850 et seq. costs and expenses, including the remaining portion of Total AB 1054 6

CapEx, in future financing orders, authorizing the issuance of Additional Recovery Bonds by Additional 7

SPEs, as further described in Exhibit SCE-07. 8

Appendix 3.1

Estimated Authorized Amount, including Pre-Securitization Debt Financing Costs and

Upfront Financing Costs

3.1-1

Table 1: Estimated Upfront Financing Costs And Authorized Amount Amount Underwriters’ Fees and Expenses $1,348,564 Legal Fees and Expenses $2,000,000 Rating Agency Fees $720,000 Accounting Fees and Expenses $65,000 Company’s Advisory Fee $300,000 Servicer Set-up Costs $500,000 SEC Registration Fees1 $43,761 Section 1904 Fees $174,571 Printing / EDGARizing Expenses $85,000 Trustee / Trustee Counsel Fees and Expenses $25,000 Original Issue Discount $18,248 Commission's Costs and Expenses $[____] Miscellaneous $75,000 TOTAL ESTIMATED UPFRONT FINANCING COSTS $5,355,143 Initial AB 1054 CapEx Amount $326,981,000 Estimated Pre-Securitization Debt Financing Costs of Initial AB 1054 CapEx (see Table 2)

$4,805,170

Estimated Principal Amount of Recovery Bonds (rounded down to nearest thousand) (i.e., the Authorized Amount)

$337,141,000

1 Current fee rate is $129.80 per $1,000,000 offered

Table 2: Pre-Securitization Debt Financing Costs Amount Long-term Cost of Debt From August 1, 2019 to March 10, 2020 $1,430,458 Bridge Financing Cost From March 11, 2020 to Estimated Closing Date2 $3,374,712 TOTAL ESTIMATED PRE-SECURITIZATION DEBT FINANCING COSTS $4,805,170

2 Updated financing costs will reflect the interest expense up to the Closing Date

Appendix 3.2

Estimated Annual Ongoing Financing Costs

3.2-1

Estimated Annual Ongoing Financing Costs Annual Amount Servicing Fee (0.05% of initial securitization principal amount) $168,571 Administration Fee $75,000 Accounting Fees and Expenses $50,000 Legal Fees and Expenses $50,000 Rating Agency Surveillance Fees $62,000 Trustee Fees and Expenses $15,000 Independent Director Fees $5,000 Printing / EDGARizing Expenses $10,000 Return on Equity $36,546 Miscellaneous Fees and Expenses $10,000 TOTAL ESTIMATED ANNUAL ONGOING FINANCING COSTS (with SCE as Servicer) $482,117 Ongoing Servicing Fee with Third Party as Servicer (0.60% of initial securitization principal amount) $2,022,846 TOTAL ESTIMATED ANNUAL ONGOING FINANCING COSTS (with Third Party as Servicer) $2,336,392

Appendix 3.3

Revenue Requirements (“RRQ”) of FRC

3.3-1

Revenue Requirements (“RRQ”) of FRC

Fixed Recovery Charge (FRC)Securitized Debt RRQ($ in millions) 2021 2022 2023 2024 2025 2026-2030 2031-2035 2036-2050 TotalAnnual Debt Service $15.5 $23.4 $23.4 $23.4 $23.4 $116.9 $116.9 $66.3 $409.2Servicing & Administrative Fees (SCE) $0.2 $0.2 $0.2 $0.2 $0.2 $1.2 $1.2 $0.7 $4.3Rating Agency Fees $0.0 $0.1 $0.1 $0.1 $0.1 $0.3 $0.3 $0.2 $1.1Other Ongoing Financing Costs $0.1 $0.2 $0.2 $0.2 $0.2 $0.9 $0.9 $0.5 $3.1Subtotal $15.8 $23.9 $23.9 $23.9 $23.9 $119.4 $119.4 $67.6 $417.6Deferred Taxes ($0.0) ($0.1) ($0.1) ($0.2) ($0.2) ($0.9) ($0.2) $0.7 ($1.0)Franchise Fees $0.1 $0.2 $0.2 $0.2 $0.2 $1.1 $1.1 $0.6 $3.9Uncollectibles $0.0 $0.1 $0.1 $0.1 $0.1 $0.3 $0.3 $0.1 $0.9Annual FRC RRQ $15.9 $24.1 $24.0 $24.0 $23.9 $119.8 $120.5 $69.1 $421.4Present Value of Annual FRC RRQ $238.9

Application No.: A.20-07-008 Exhibit No.: SCE-04 Witnesses: S. Deana

(U 338-E)

Recovery Bond Financing

Customer Benefits of the Securitization

Before the

Public Utilities Commission of the State of California

Rosemead, California July 8, 2020

Direct Testimony Supporting Southern California Edison's Application for Recovery Bond Financing: Customer Benefits of the Securitization

Table Of Contents

Section Page Witness

-i-

I.  INTRODUCTION .............................................................................................1 S. Deana 

II.  COMPARISON BETWEEN SECURITIZATION AND TRADITIONAL UTILITY FINANCING UNDER PUBLIC UTILITIES CODE SECTION 850.1(A)(1)(A)(II)(III) .....................................2 

A.  Revenue Requirements Under Traditional Ratemaking ........................2 

B.  Revenue Requirements Under Securitized Debt Financing ...................4 

C.  Net Differences in Revenue Requirements ............................................5 

D.  Securitization Reduces the Revenue Requirements on a Present Value Basis................................................................................5 

III.  COMPARISON BETWEEN SECURITIZATION AND FINANCING OF INITIAL AB 1054 CAPEX WITHOUT AN EQUITY RETURN ............................................................................................6 

A.  Revenue Requirements Under Traditional Financing without an Equity Return .......................................................................6 

B.  Net Differences in Revenue Requirements ............................................7 

C.  Securitization Reduces the Revenue Requirements on a Present Value Basis................................................................................7 

IV.  CONCLUSION ..................................................................................................8 

Direct Testimony Supporting Southern California Edison's Application for Recovery Bonds Financing: Customer Benefits of the Securitization

List Of Tables

Table Page

-ii-

Table II-1 Traditional Ratmaking Revenue Recovery .................................................................................3 

Table II-2 Securitized Debt Fixed Recovery Charge Revenue Recovery ...................................................5 

Table II-3 Annual Savings: Securitization vs. Traditional Ratemaking ......................................................5 

Table III-4 Traditional Ratmaking Revenue Recovery without an Equity Return ......................................7 

Table III-5 Annual Savings: Securitization vs. Traditional Ratemaking without an Equity

Return .....................................................................................................................................................7 

1

I. 1

INTRODUCTION 2

This chapter presents a comparison of the customer revenue requirements to recover the Initial AB 3

1054 Capex under traditional utility financing mechanisms compared to recovery of those costs through 4

securitization. This analysis proceeds in two parts: (1) it provides the statutorily mandated comparison of 5

the proposed securitization against the cost of recovering the same amount through traditional ratemaking; 6

and (2) it provides an additional comparison of the proposed securitization against the cost of recovering the 7

same amount by financing through SCE’s authorized capital structure in the absence of a return on common 8

equity. The analysis meets the requirements of Public Utilities Code Section 850.1(a)(1)(A)(ii)(III) in that 9

the proposed securitization “would reduce, to the maximum extent possible, the rates on a present value 10

basis that consumers within SCE’s service territory would pay as compared to the use of traditional utility 11

financing mechanisms, which shall be calculated using the electrical corporation’s corporate debt and equity 12

in the ratio approved by the commission at the time of the financing order.”1 13

Section II presents a comparison of the revenue requirements to recover $326.981 million in capital 14

expenditures (“Initial AB 1054 CapEx”) that SCE has incurred related to catastrophic wildfires using 15

traditional ratemaking at SCE’s authorized rate of return on rate base (7.68%)2 as compared to the 16

securitized debt financing contemplated by this Application. Assuming the same structure and terms for 17

securitization, SCE expects that future securitizations up to the full $1.575 billion in AB 1054 CapEx 18

(“Total AB 1054 CapEx”) will yield similar customer benefits. 19

In addition to this statutorily required comparison, Section III also compares securitization to a 20

scenario in which these costs are recovered from customers in the normal-course, absent securitization. 21

Specifically, this analysis compares the estimated revenue requirements where these costs are financed with 22

traditional utility debt and preferred stock at SCE’s authorized costs of 4.74% and 5.70%, respectively,3 23

1 Pub. Util. Code § 850.1(a)(1)(A)(ii)(III).

2 See D.19-12-056 at 54 (OP 1).

3 See D.19-12-056 at 54 (OP 1). These current authorized rates result in a weighted average cost of capital of 4.84% in the absence of common equity.

2

consistent with Public Utilities Code Section 8386.3(e); and the securitized debt contemplated by this 1

Application. Since Section 8386.3(e) precludes SCE from earning an equity return on the Total AB 1054 2

Capex and also permits, but does not require, the financing of those costs through securitization, SCE 3

presents this additional comparison for evaluating the proposed and anticipated future securitizations. 4

All of these revenue requirement analyses rely on models that are presented in annualized form and 5

do not show details that have little cost impact in order to simplify the presentation and show the overall 6

savings from using the securitized debt financing. The underlying accounting of these models is made on a 7

monthly basis. 8

II. 9

COMPARISON BETWEEN SECURITIZATION AND TRADITIONAL UTILITY FINANCING 10

UNDER PUBLIC UTILITIES CODE SECTION 850.1(A)(1)(A)(II)(III) 11

Public Utilities Code Section 850.1(a)(1)(A)(ii)(III) requires that the proposed securitization “would 12

reduce, to the maximum extent possible, the rates on a present value basis that consumers within SCE’s 13

service territory would pay as compared to the use of traditional utility financing mechanisms, which shall 14

be calculated using the electrical corporation’s corporate debt and equity in the ratio approved by the 15

commission at the time of the financing order.”4 The analyses below show the estimated revenue 16

requirements using traditional utility financing using SCE’s authorized rate of return on rate base and using 17

securitized debt as contemplated by this Application. . 18

A. REVENUE REQUIREMENTS UNDER TRADITIONAL RATEMAKING 19

SCE calculates the estimated annual revenue requirements for recovering the Initial AB 1054 CapEx 20

consistent with the approved Grid Safety and Resiliency Program pursuant to D.20-04-013. This includes 21

the following assumptions for traditional rate base financing and cost recovery: 22

The principal costs are amortized over a 24-year period beginning in mid-2019, following the 23

straight-line book depreciation lives for each asset type; 24

4 Pub. Util. Code § 850.1(a)(1)(A)(ii)(III).

3

Applicable taxes (i.e., state and federal income tax, and franchise requirements) are calculated 1

consistent with federal and state tax lives for each asset; 2

The allowed rate of return for the wildfire costs is SCE’s current Commission approved rate of 3

return; 4

The costs include an additional allowance for uncollectible account expenses; and 5

The revenue requirement to be collected in 2021 is inclusive of the revenue requirement from 6

previous years that has not yet been collected, in addition to associated Pre-Securitization Debt 7

Financing Costs.5 8

Table II-1 contains the revenue requirements for SCE to recover the Initial AB 1054 CapEx. Using 9

the above assumptions, SCE’s revenue requirement will total $682 million over the life of the collection 10

period, which is equivalent to a present value of $412 million.6 11

Table II-1 Traditional Ratmaking Revenue Recovery

5 In D.20-04-013, the decision approving the GSRP Settlement, the Commission approving this revenue

requirement and construed Section 8386.3(e) as encompassing the first $1.575 billion expended by SCE on Commission-approved fire risk mitigation capital expenditures on or after August 1, 2019 (See D.20-04-013, p. 49, Conclusion of Law No. 6). This includes applicable return, which constitutes the Pre-Securitization Debt Financing Costs, though Advice Letter 4197-E is pending approval. Traditional ratemaking revenue recovery in Table II-1 assumes revenue requirement from 8/1/19 through 12/31/20 is tracked in GSRP Balancing Account and is recovered in 2021 rates.

6 The present value analysis was prepared using SCE’s authorized weighted-average cost of capital as the discount rate.

($ in millions) 2021 2022 2023 2024 2025 2026-2030 2031-2035 2036-2050 TotalInterest $6.0 $5.7 $5.3 $5.0 $4.7 $19.6 $13.4 $7.5 $67.2Preferred Dividend $0.8 $0.8 $0.7 $0.7 $0.7 $2.7 $1.9 $1.0 $9.4Earning for Common $15.7 $14.9 $14.0 $13.2 $12.4 $51.5 $35.2 $19.6 $176.5Total Taxes $4.8 $4.6 $4.4 $4.4 $4.2 $19.5 $15.4 $9.2 $66.5Operating Expenses (Franchise Requirements) $0.4 $0.4 $0.4 $0.4 $0.3 $1.5 $1.2 $1.3 $5.8Return $27.7 $26.3 $24.9 $23.7 $22.3 $94.8 $67.1 $38.5 $325.3Principal Amortization $14.8 $14.8 $14.5 $15.8 $14.5 $70.9 $66.1 $98.4 $309.7Subtotal $42.5 $41.1 $39.4 $39.4 $36.8 $165.7 $133.2 $136.9 $635.0Uncollectibles $0.1 $0.1 $0.1 $0.1 $0.1 $0.4 $0.3 $0.3 $1.3Revenue Requirement $42.6 $41.2 $39.4 $39.5 $36.9 $166.1 $133.5 $137.2 $636.32019 and 2020 Rev Req and Carrying Costs $45.6 - - - - - - - $45.6Revenue Requirement Collected $88.2 $41.2 $39.4 $39.5 $36.9 $166.1 $133.5 $137.2 $681.9Present Value of Revenue Req. Collected $412.4

4

B. REVENUE REQUIREMENTS UNDER SECURITIZED DEBT FINANCING 1

SCE estimates the annual revenue requirements under securitized debt financing by following 2

standard financial formulas for principal and interest payments on a mortgage-style loan.7 The guidelines 3

and assumptions for this calculation are discussed below: 4

The wildfire mitigation costs to be securitized are amortized, using a mortgage-style, equal payment 5

for principal and interest combined beginning in 2021; 6

For comparative purposes to traditional ratemaking, benefits from accumulated deferred income 7

taxes (ADIT) arising from the timing of the securitized deductions compared to the taxable revenue 8

are added to the revenue requirement;8 9

Because SCE does not collect all the revenue that is billed, an allowance for uncollectible accounts 10

expenses is added to the revenue requirement; 11

The securitized bonds are estimated to be repaid by the end of 2038; and 12

The interest rate on the securitized bonds is estimated to be about 2.20 percent. 13

Table II-2 contains the revenue requirements for SCE to recover the Initial AB 1054 CapEx 14

amortized over the 18-year estimated life of the bond. Using the above assumptions, SCE’s revenue 15

requirement will total $421 million over the life of the collection period, which is equivalent to a present 16

value of $239 million. 17

7 Mortgage-style financing includes a constant annual payment amount consisting of combined principal

amortization and interest payments. Over time, the interest due decreases as the principal balance is paid off. This decrease in interest payments is offset by an increase in the amount paid to principal to maintain a constant annual payment amount over the life of the loan. SCE uses this assumption for purposes of determining the revenue requirement; however, the amortization treatment for SCE’s proposed transaction is addressed in more detail in Exhibit SCE-03, Transaction Overview (B. Pang), Section X (Recovery Bond Characteristics and Terms).

8 For detailed discussion of tax treatments, please refer to Exhibit SCE-05 Taxation.

5

Table II-2 Securitized Debt Fixed Recovery Charge Revenue Recovery

C. NET DIFFERENCES IN REVENUE REQUIREMENTS 1

The net reduction in the revenue requirements stemming from the use of securitized debt is the 2

difference between the annual revenue requirements under conventional rate base financing (Table II-1) and 3

the securitized debt revenue requirements (Table II-2). Table II-3 presents the illustrative net revenue 4

requirements reductions for each year from 2021 through 2050. 5

Table II-3 Annual Savings: Securitization vs. Traditional Ratemaking

D. SECURITIZATION REDUCES THE REVENUE REQUIREMENTS ON A PRESENT 6

VALUE BASIS 7

In Table II-3, the revenue requirement savings associated with securitization as compared to 8

traditional utility financing are summarized on an annual basis, on an accumulated nominal basis, and as the 9

present value of the net revenue requirement reductions. The nominal savings over the full amortization 10

period is approximately $260.5 million. Using a discount rate of 7.68 percent,9 the present value of the 11

savings is approximately $173.5 million. 12

9 SCE assumes that the discount rate should be applied to the entire period of cost recovery and should be set equal

to the current CPUC authorized return on rate base, which is 7.68 percent. See D.19-12-056 at 54 (OP 1) (SCE Return on Rate Base 7.68 percent).

($ in millions) 2021 2022 2023 2024 2025 2026-2030 2031-2035 2036-2050 TotalAnnual Debt Service $15.5 $23.4 $23.4 $23.4 $23.4 $116.9 $116.9 $66.3 $409.2Servicing & Administrative Fees (SCE) $0.2 $0.2 $0.2 $0.2 $0.2 $1.2 $1.2 $0.7 $4.3Rating Agency Fees $0.0 $0.1 $0.1 $0.1 $0.1 $0.3 $0.3 $0.2 $1.1Other Ongoing Financing Costs $0.1 $0.2 $0.2 $0.2 $0.2 $0.9 $0.9 $0.5 $3.1Subtotal $15.8 $23.9 $23.9 $23.9 $23.9 $119.4 $119.4 $67.6 $417.6Deferred Taxes ($0.0) ($0.1) ($0.1) ($0.2) ($0.2) ($0.9) ($0.2) $0.7 ($1.0)Franchise Fees $0.1 $0.2 $0.2 $0.2 $0.2 $1.1 $1.1 $0.6 $3.9Uncollectibles $0.0 $0.1 $0.1 $0.1 $0.1 $0.3 $0.3 $0.1 $0.9Annual FRC RRQ $15.9 $24.1 $24.0 $24.0 $23.9 $119.8 $120.5 $69.1 $421.4Present Value of Annual FRC RRQ $238.9

($ in millions) 2021 2022 2023 2024 2025 2026-2030 2031-2035 2036-2050 TotalTraditional Ratemaking RRQ $88.2 $41.2 $39.4 $39.5 $36.9 $166.1 $133.5 $137.2 $681.9Securitized Debt RRQ $15.9 $24.1 $24.0 $24.0 $23.9 $119.8 $120.5 $69.1 $421.4Annual Savings $72.2 $17.1 $15.4 $15.5 $12.9 $46.3 $12.9 $68.1 $260.5Cumulative Annual Savings $72.2 $89.3 $104.8 $120.3 $133.2 $179.5 $192.4 $260.5 $260.5Present Value of Annual Savings $173.5

6

III. 1

COMPARISON BETWEEN SECURITIZATION AND FINANCING OF INITIAL AB 1054 CAPEX 2

WITHOUT AN EQUITY RETURN 3

Securitization of the Initial AB 1054 Capex also compares favorable against traditional utility 4

financing using utility costs of financing in the absence of the common equity component of SCE’s 5

long-term capital structure. Because Section 8386.3(e) precludes SCE from earning an equity return on the 6

Initial AB 1054 CapEx, SCE provides this additional analysis to compare securitization to a scenario in 7

which these costs are recovered from customers in the normal-course, absent securitization. 8

A. REVENUE REQUIREMENTS UNDER TRADITIONAL FINANCING WITHOUT AN 9

EQUITY RETURN 10

SCE generated the following estimate of the traditional revenue requirement following standard 11

financial formulas while rebalancing its long-term capital structure for the recovery of the Initial AB 1054 12

CapEx in the absence of common equity. The calculations in the tables that follow use the same 13

assumptions as those identified in Section II.A, with the exception that SCE’s 52% common equity 14

component of its capital structure is recovered instead via authorized levels of long-term debt and preferred 15

stock at 4.74% and 5.70% respectively, weighting the allocation of the common equity in accordance with 16

SCE’s authorized weightings of preferred stock (5%) and long-term debt (43%) for a weighted average cost 17

of capital of 4.84%. 18

Table III-4 contains the revenue requirements for SCE to recover the Initial AB 1054 CapEx without 19

an equity return. Using the above assumptions, SCE’s revenue requirement will total $503 million over the 20

life of the collection period, which is equivalent to a present value of $291 million. 21

7

Table III-4 Traditional Ratmaking Revenue Recovery without an Equity Return

B. NET DIFFERENCES IN REVENUE REQUIREMENTS 1

The net reduction in the revenue requirements stemming from the use of securitized debt to finance 2

the Initial AB 1054 CapEx is the difference between the annual revenue requirements under debt-only 3

financing (Table III-4) and the securitized debt revenue requirements (Table II-2). Table III-5 presents the 4

illustrative net revenue requirements reductions for each year from 2021 through 2045. 5

Table III-5 Annual Savings: Securitization vs. Traditional Ratemaking without an Equity Return

C. SECURITIZATION REDUCES THE REVENUE REQUIREMENTS ON A PRESENT 6

VALUE BASIS 7

In Table III-5, the revenue requirement savings associated with securitization as compared to 8

traditional ratemaking without an equity return are summarized on an annual basis, on an accumulated 9

nominal basis, and as the present value of the net revenue requirement reductions. The nominal savings is 10

approximately $81.8 million. Using a discount rate of 7.68 percent, the present value of the savings is 11

approximately $52.5 million. This means that, both nominally and on a net present value basis, securitized 12

debt will save ratepayers money by reducing the charges necessary to finance the wildfire mitigation costs 13

compared to traditional financing methods. 14

($ in millions) 2021 2022 2023 2024 2025 2026-2030 2031-2035 2036-2050 TotalInterest $12.5 $11.8 $11.1 $10.4 $9.8 $40.8 $27.9 $15.5 $139.9Preferred Dividend $1.7 $1.6 $1.6 $1.5 $1.4 $5.7 $3.9 $2.2 $19.6Earning for Common - - - - - - - - -Total Taxes ($1.0) ($0.8) ($0.7) ($0.4) ($0.3) $0.6 $2.5 $2.0 $1.8Operating Expenses (Franchise Requirements) $0.3 $0.3 $0.2 $0.3 $0.2 $1.1 $0.9 $1.1 $4.4Return $13.5 $12.9 $12.2 $11.7 $11.1 $48.2 $35.2 $20.8 $165.7Principal Amortization $14.8 $14.8 $14.5 $15.8 $14.5 $70.9 $66.1 $98.4 $309.7Subtotal $28.3 $27.6 $26.7 $27.5 $25.6 $119.2 $101.3 $119.2 $475.3Uncollectibles $0.1 $0.1 $0.1 $0.1 $0.1 $0.3 $0.2 $0.3 $1.0Revenue Requirement $28.3 $27.7 $26.7 $27.6 $25.7 $119.4 $101.5 $119.4 $476.32019 and 2020 Rev Req and Carrying Costs $26.9 - - - $26.9Revenue Requirement Collected $55.2 $27.7 $26.7 $27.6 $25.7 $119.4 $101.5 $119.4 $503.2Present Value of Revenue Req. Collected $291.4

($ in millions) 2021 2022 2023 2024 2025 2026-2030 2031-2035 2036-2050 TotalTraditional Ratemaking RRQ $55.2 $27.7 $26.7 $27.6 $25.7 $119.4 $101.5 $119.4 $503.2Securitized Debt RRQ $15.9 $24.1 $24.0 $24.0 $23.9 $119.8 $120.5 $69.1 $421.4Annual Savings $39.3 $3.6 $2.7 $3.6 $1.7 ($0.4) ($19.0) $50.4 $81.8Cumulative Annual Savings $39.3 $42.9 $45.6 $49.2 $50.9 $50.5 $31.5 $81.8 $81.8Present Value of Annual Savings $52.5

8

IV. 1

CONCLUSION 2

The revenue requirement calculations demonstrate that issuing securitization debt rather than a 3

traditional recovery method to recover the $326.981 million Initial AB 1054 CapEx, provides a cost savings 4

and overall benefit to SCE’s ratepayer base. When compared to traditional utility financing mechanisms 5

using SCE’s capital structure approved by the commission, issuing securitization debt generates a nominal 6

savings of approximately $260.5 million and a net present value savings of $173.5 million to SCE’s 7

ratepayer base. When comparing securitization debt financing to traditional utility financing without an 8

equity return, issuing securitization debt generates a nominal savings of approximately $81.8 million and a 9

net present value savings of $52.5 million to SCE’s ratepayer base. 10

Application No.: A.20-07-008 Exhibit No.: SCE-05 Witnesses: M. Childs

(U 338-E)

Recovery Bond Financing

Taxation

Before the

Public Utilities Commission of the State of California

Rosemead, California July 8, 2020

Direct Testimony Supporting Southern California Edison's Application for Recovery Bond Financing: Taxation

Table Of Contents

Section Page Witness

-i-

I.  TAXES ...............................................................................................................1 M. Childs 

Appendix 5.1 SCE’s Calculation of Income Tax Benefit of Proposed Securitization of Initial 1054 CapEx 

1

I. 1

TAXES 2

As described in Exhibit SCE-02, Revenue Procedure 2005-62 clarifies that a Qualifying 3

Securitization is not recognized as gross income to the utility when it receives the net proceeds of the 4

securitization bonds from the SPE. Instead, securitization-related customer charges are recognized as 5

income to the utility as they are collected over time under its usual method of accounting. Article 5.8 of the 6

Public Utilities Code states that the Commission may allow fixed recovery tax amounts for any portion of 7

the electrical corporation’s Federal and State of California income and franchise taxes associated with the 8

Fixed Recovery Charges, and not financed from proceeds of Recovery Bonds.1 9

Under the proposed securitization, SCE does not anticipate incurring net income and franchise tax 10

liabilities necessitating a separate charge. Accordingly, SCE does not contemplate the need for a separate 11

fixed recovery tax amount. This is because the revenue collected from customers,2 which is taxable income 12

when SCE receives it, will be offset by certain expenditures that are deductible and will reduce SCE’s 13

taxable income. These expenditures are: 14

15

1. Initial AB 1054 CapEx – deductible as tax depreciation over the life of the tax asset 16

generated; 17

2. Interest on the Recovery Bond – tax deductible as incurred; 18

3. Pre-Securitization Debt Financing Costs of the Initial AB 1054 Cap Ex – tax deductible over 19

the life of the bond; 20

4. Upfront Financing Costs, as described in Exhibit SCE-03, Section XII – tax deductible over 21

the life of the bond; 22

5. And Ongoing Financing Costs as described in Exhibit SCE-03, Section VIII – tax deductible 23

as incurred. 24

Some of these tax deductions occur at different times than when the taxable revenue is collected 25

from customers, resulting in a net cash flow surplus early on that will be reduced over time by net cash flow 26

deficits in later years. First, the Initial AB 1054 CapEx creates a capital asset for tax purposes that is 27

depreciated and deducted over an accelerated 20 year useful life of the asset. While this is a longer time 28

1 Pub. Util. Code § 850.1(a)(1)(B).

2 While this is primarily the FRC, it also includes all other recoveries from customers.

2

period than the anticipated 18-year amortization period for the Recovery Bonds, the tax deduction is 1

accelerated in earlier years. Second, Upfront Financing Costs and Pre-Securitization Debt Financing Costs, 2

while deductible over the same 18-year bond amortization period,, are also accelerated. The tax savings 3

resulting from these timing differences are referred to as accumulated deferred income taxes (“ADIT”). 4

With respect to the other categories of expenditures, the taxable revenues equal and offset expenses during 5

the period, resulting in no net cash flow (i.e. tax due is equal to tax recovered during the period with a net 6

cash flow of zero). 7

Appendix 5.1 sets forth the calculation of the interest benefits earned on ADIT to be returned to 8

customers. The interest benefits resulting from ADIT are calculated using the outstanding weighted average 9

ADIT balance as of each repayment date (i.e. each of the 35 payment dates for the 18 year Recovery Bonds) 10

and interest is then calculated based on the prorated bond yield rate for that period. SCE proposes crediting 11

or debiting these amounts to BRRBA in the period they are realized, similar to franchise and property tax 12

impacts, as described in Exhibit SCE-06. 13

SCE may use this same approach for other securitizations described in Exhibit SCE-07, but may also 14

change how taxes are incorporated in future securitizations based on the facts and circumstances specific to 15

those transactions. 16

Appendix 5.1

SCE’s Calculation of Income Tax Benefit of

Proposed Securitization of Initial 1054 CapEx

5.1-1

SCE’s Calculation of Income Tax Benefit of Proposed Securitization of Initial 1054 CapEx

Application No.: A.20-07-008 Exhibit No.: SCE-06 Witnesses: R. Thomas

(U 338-E)

Recovery Bond Financing

Ratemaking Mechanism and Rate Proposal

Before the

Public Utilities Commission of the State of California

Rosemead, California July 8, 2020

Direct Testimony Supporting Southern California Edison's Application for Recovery Bond Financing: Ratemaking Mechanism and Rate Proposal

Table Of Contents

Section Page Witness

-i-

I.  INTRODUCTION .............................................................................................1 R. Thomas 

II.  RATEMAKING MECHANISMS .....................................................................1 

A.  Tracking of Authorized Amounts Associated with the Recovery Bonds .....................................................................................1 

B.  Process for Implementing Issuance and True-Up Advice Letter Changes in Rates .........................................................................2 

C.  Recovery of Associated Costs Not Reflected in Securitization .........................................................................................3 

III.  RATE DESIGN .................................................................................................4 

A.  FRC Applicability ..................................................................................4 

B.  FRC Nonbypassability ...........................................................................4 

C.  Revenue Allocation and Rate Design ....................................................5 

1.  Residential Rate Design .............................................................7 

2.  CARE and FERA Rate Design ..................................................7 

a)  CARE .............................................................................7 

b)  FERA .............................................................................8 

c)  Recovery of CARE and FERA Funding and Related Rate Changes ....................................................8 

d)  Process for Calculating FRC Rate Factors.....................9 

D.  Illustrative Rates ..................................................................................10 

IV.  PRESENTATION ON CUSTOMER BILLS ..................................................11 

V.  INTERIM APPROACH TO INCLUDING THE FRC IN CUSTOMER BILLS PENDING CUSTOMER SERVICE RE-PLATFORM IMPLEMENTATION ...............................................................11 

A.  Rate Change to Incorporate FRC .........................................................12 

Direct Testimony Supporting Southern California Edison's Application for Recovery Bond Financing: Ratemaking Mechanism and Rate Proposal

Table Of Contents (Continued)

Section Page Witness

-ii-

B.  Bill Presentment ...................................................................................12 

C.  CARE/FERA Exemption .....................................................................13 

Appendix 6.1 SCE’s Proposed Options for Interim Bill Presentment for FRC 

Direct Testimony Supporting Southern California Edison's Application for Recovery Bonds Financing: Ratemaking Mechanism and Rate Proposal

List Of Tables

Table Page

-iii-

Table III-1 Approved GRC Distribution Allocators and Proposed Allocators Excluding

CARE/FERA..........................................................................................................................................6 

Table III-2 Present and Proposed Bundled Rates With Securitization - $24 Million

Revenue Requirement (Comparison of Rates Effective as of June 1, 2020) .......................................10 

1

I. 1

INTRODUCTION 2

This chapter describes SCE’s proposed ratemaking mechanisms and rate design to ensure repayment 3

of the Recovery Bonds and accurate accounting for associated transactions. Section II describes SCE’s 4

proposed tracking and balancing accounts for the costs associated with the Recovery Bonds. Section III 5

specifically explains how the Fixed Recovery Charge (“FRC”)1 will be calculated, describes SCE’s proposal 6

for allocating the FRC among customers and shows illustrative rate impacts by customer class. Section IV 7

describes how the charge will appear on customers’ bills and Section V proposes an interim approach for 8

incorporating the FRC in customer bills, while SCE’s customer service billing platform upgrades are being 9

implemented. 10

II. 11

RATEMAKING MECHANISMS 12

This section describes SCE’s proposed ratemaking mechanisms to recover from consumers the 13

revenue requirement associated with the Recovery Bonds collected through the FRC, as described in Exhibit 14

SCE-03, Transaction Overview (B. Pang) as well as other costs associated with Recovery Bond-related 15

transactions that are not included in the FRC. These mechanisms are proposed by SCE to ensure repayment 16

of the Recovery Bonds and provide the opportunity to recover certain transactions costs. 17

A. Tracking of Authorized Amounts Associated with the Recovery Bonds 18

AB 1054 authorizes the Commission to issue a financing order to authorize the recovery of certain 19

costs and expenses related to catastrophic wildfires (Authorized Amounts) through the issuance of Recovery 20

Bonds that are secured by a FRC on consumers’ monthly bills. Exhibit SCE-03 describes the Authorized 21

Amounts associated with Recovery Bonds to be recovered and establishes the annual revenue required to be 22

collected from customers, through an FRC on customer bills, to ensure repayment of the Recovery Bonds 23

1 The term “Fixed recovery charges,” as defined in Public Utilities Code Section 850(7), does not necessarily mean

equal cents per kWh charges or a fixed monthly charge, but instead refers more broadly to nonbypassable rates and other charges, including distribution charges, to recover Securitization costs.

2

and recovery of associated costs. The rate design and inclusion of FRC in customers’ monthly bills are 1

discussed in Sections III through V below. 2

All of the revenues received from the FRC will be transferred to the Bond Trustee for the benefit of 3

a Special Purpose Entity (“SPE”), a subsidiary of SCE. These revenues will be applied to pay the principal 4

and interest on the Recovery Bonds and the associated Ongoing Financing Costs. A detailed description of 5

these Ongoing Financing Costs is found in Exhibit SCE-02, Section III and Exhibit SCE-03, Section X. 6

Revenues received from the FRCs will not be recovered in an SCE regulatory balancing account.2 7

However, as described in Exhibit SCE-03, Section XI, SCE will track amounts billed to consumers through 8

the FRC and estimated amounts remitted to the Bond Trustee based on an assumed uncollectible rate. Data 9

detailed in the monthly or semi-annual servicer reports will be used to inform the true-up process described 10

in Exhibit SCE-03, Section VII and summarized in Section II.B below. Amounts collected by SCE will be 11

remitted to the Bond Trustee based upon estimated and estimated “actual” collections as described in 12

Exhibit SCE-03. 13

B. Process for Implementing Issuance and True-Up Advice Letter Changes in Rates 14

SCE’s proposal to use the Advice Letter process to establish and true-up the FRC is described in 15

detail in Exhibit SCE-03. This section briefly summarizes how the initial FRC and adjustments to the FRC 16

will be implemented through the Advice Letter process. This Section also describes how the FRCs will be 17

reported in connection with other ratemaking proceedings. 18

As described in Exhibit SCE-03, SCE will submit an “Issuance Advice Letter” to set the final terms 19

and structure of each series of Recovery Bonds, updated (final or near-final) Upfront Financing Costs and 20

the Ongoing Financing Costs for the first year after issuance. The Issuance Advice Letter will also establish 21

the initial FRCs. Following issuance of the Recovery Bonds, SCE (as servicer) will submit Routine True-22

Up Mechanism Advice Letters to adjust the FRC at least annually and more often as SCE deems necessary 23

to ensure the timely payment of the Recovery Bonds and associated Ongoing Financing Costs. SCE may 24

2 SCE will use the proceeds from the sale of the Recovery Bonds to offset the Initial AB 1054 CapEx-related costs,

a portion of which is currently being tracked in the AB1054 sub-account of the GSRP memorandum/balancing account, and the remaining portion of which is in plant balance.

3

also submit Non-Routine True-Up Mechanism Advice Letters to update allocation factors, if necessary, to 1

reflect the outcome of any future GRC Phase 2. SCE may also submit Non-Routine True-Up Mechanism 2

Advice Letters to propose revisions to the logic, structure, and components of the cash flow model described 3

in Attachment 1 to the Financing Order, all as further explained in Exhibit SCE-03, Section VII.A.3. 4

As stated, the FRC will be adjusted independently of changes to other SCE rates and charges. 5

However, changes to the FRC will impact how other SCE rates and charges are calculated, due to, among 6

other factors, tiered rates and other required discounts. Further, FRCs may be adjusted to reflect any 7

changes as a result of future GRC Phase 2 proceedings. Accordingly, for the convenience of the 8

Commission, rate schedule information supplied with the Advice Letter filings will vary depending upon the 9

nature of the Advice Letter. If the FRC is being implemented as a stand-alone rate change (i.e., the 10

implementation of the FRC is not being consolidated with any other rate changes), SCE will include the 11

updated customer FRC, SCE rate schedules, and tariffs in those True-Up Advice Letters. However, if the 12

FRC change is being consolidated with other rate changes (e.g., annual January 1 rate change to update 13

several different revenue requirements or an allocation factor change), the True-Up Advice Letter will not 14

include a copy of the SCE rate schedules and tariffs. Instead, the SCE rate schedules and tariffs will be 15

provided in a separate “consolidated rate change advice letter” that details all of the rate changes being 16

simultaneously implemented (including the updated FRC) and provides a final copy of all of the impacted 17

SCE rate schedules and tariffs for administrative ease. 18

C. Recovery of Associated Costs Not Reflected in Securitization 19

SCE proposes to recover costs associated with the Recovery Bonds (and subsequent Recovery 20

Bonds) that are not reflected in the securitization through existing ratemaking mechanisms. Among the 21

items to be recovered are franchise fees expense associated with the FRC and any applicable income or 22

property tax associated with the capital expenditures excluded from SCE’s equity rate base and recovered 23

through the Recovery Bonds.3 Income tax benefits are discussed in Exhibit SCE-05. SCE proposes to 24

3 Because the capital expenditures recovered through the Recovery Bond are excluded from SCE’s equity rate base,

any applicable property taxes will not be captured in SCE’s General Rate Case (GRC) and will thus need to be recovered through a separate entry in the BRRBA.

4

record these amounts in the distribution sub-account of SCE’s Base Revenue Requirement Balancing 1

Account (“BRRBA”) for recovery from customers.4 2

III. 3

RATE DESIGN 4

SCE proposes to design the FRC to most closely reflect the allocation and design of distribution 5

rates authorized in the decision adopting the 2018 GRC Phase 2 Revenue Allocation and Rate Design 6

Settlement.5 Because fire mitigation capital and its associated financing costs are distribution-related 7

expenditures, SCE appropriately allocates such costs to customer groups using distribution revenue 8

allocation factors. SCE requests authority to periodically update this rate design through the 9

aforementioned Non-Routine True-up Mechanism Advice Letter to reflect updates to the allocation adopted 10

in any future GRC Phase 2, if required in such future proceeding or otherwise deemed appropriate or 11

necessary by SCE. 12

A. FRC Applicability 13

Public Utilities Code Section 850.1(a)(2) provides that the FRC is to be recovered from existing and 14

future consumers, together with all other consumers of electricity, within SCE’s service territory as of the 15

date of the Financing Order (“SCE’s Service Territory”) until Recovery Bonds and associated financing 16

costs are paid in full. Accordingly, all Direct Access, Community Choice Aggregation, Community 17

Aggregation, and bundled service customers must pay the FRC, unless they are enrolled in the CARE or 18

FERA programs.6 19

B. FRC Nonbypassability 20

Section 850.1(b) provides that the FRC is nonbypassable for all consumers on whom the rate is 21

imposed. This includes all existing and future SCE customers, together with all other consumers of 22

4 The recovery of associated costs through existing ratemaking mechanisms is consistent with the recovery of

Department of Water Resources Bond Charge franchise fees through the Energy Resource Recovery Account (ERRA) balancing account. See SCE Preliminary Statement Part ZZ. Additionally, SCE may include a forecast of the BRRBA-eligible Recovery Bond costs in its annual January 1 consolidated rate change advice letter.

5 D.18-11-027.

6 See Section 850.1(i).

5

electricity, within SCE’s Service Territory, except for those customers participating in the CARE or FERA 1

programs (§ 850.1(a)(2)). Consumers that no longer take transmission and distribution retail service from 2

SCE after the date of the Financing Order, or that meet relevant criteria in applicable tariffs, are departing 3

load (“DL”) Consumers. For these DL Consumers on Transferred Municipal Departing Load (“Schedule 4

TMDL”) or New Municipal Departing Load (“Schedule NMDL”) schedules, SCE proposes to calculate the 5

FRC-related amounts that would need to be paid, using an approach that is consistent with the method 6

currently in place for calculation of TMDL and NMDL obligations. 7

C. Revenue Allocation and Rate Design 8

Costs that SCE seeks to securitize under AB 1054 are distribution infrastructure related expenditures 9

that would, but for securitization, be allocated to customers based on total distribution revenue allocation 10

factors. SCE therefore proposes to allocate these costs using “total distribution” allocation factors adopted 11

in SCE’s most-recent GRC Phase 2 proceeding. Allocation factors adopted in SCE’s GRC Phase 2 12

proceeding7 reflect a settled (or, rarely, litigated) process balancing a variety of stakeholder interests that are 13

represented in that proceeding, including but not limited to affordability, class equity, and conservation. 14

SCE finds no reason to change the basis of such allocation simply because such costs are being securitized. 15

As demonstrated through Table III-1 below, GRC Phase 2 allocators have been modified to account for the 16

exclusion of CARE and FERA customers, thus increasing the allocation to all groups. 17

7 A.17-06-030, D.18-11-027 Decision On Southern California Edison Company’s Proposed Rate Designs And

Related Issues (December 7, 2018).

6

Table III-1 Approved GRC Distribution Allocators and Proposed Allocators Excluding

CARE/FERA

To continue to reflect this balance in the FRC going forward, SCE seeks authority to revise its 1

distribution allocation factors to reflect (and be consistent with) changes arising from future GRC Phase 2. 2

SCE’s approach has precedent in other jurisdictions. In fact, the recent Florida securitizations by Duke 3

Power and Florida Power and Light allocated securitization costs among customer classes based upon the 4

last base rate case.8 As described in Exhibit SCE-03, SCE would use a Non-Routine True-up Mechanism 5

Advice Letter to make this change. 6

The FRC for each customer group will be a unique volumetric rate factor that is assessed on a cents-7

per-kilowatt-hour basis within each customer class; this is derived by multiplying the total revenue 8

requirement by each customer class allocation factor and then dividing the class-level allocated revenues by 9

the projected kWh sales of the respective customer classes. The total rates for most customer classes are 10

developed by adding the rates for each component together to derive the total applicable rate. 11

8 In re: Petition for Issuance of Nuclear Asset Recovery Financing Order, by Duke Energy Florida, Inc. d/b/a Duke

Energy, Docket Nos. 150148-EI, 150171-EI, Financing Order, p. 15 (2015); In re: Petition for issuance of a storm recovery financing order, by Florida Power & Light Company, Docket No. 060038-E1 Order No. PSC-06-0464-FOF-E1, Finding of Fact No. 80 (May 30, 2006).

Rate GroupDistribution 

Allocator

Distribution Allocator 

(Excluding CARE/FERA)

Non‐CARE 38.11% 43.52%

CARE 12.78% 0.00%

GS‐1 7.25% 8.34%

TC‐1 0.12% 0.14%

GS‐2 17.31% 19.90%

GS‐3 7.81% 8.98%

TOU‐8‐Sec 7.31% 8.41%

TOU‐8‐Pri 4.70% 5.41%

TOU‐8‐Sub 1.38% 1.59%

AG&P < 200 KW 2.02% 2.32%

AG&P >= 200 KW 1.15% 1.32%

Street Light 0.07% 0.08%

Total 100.0% 100.0%

7

Overall residential rates, and CARE and FERA customer rates, are governed by specific rate design 1

rules established in statute and other Commission decisions; application of the FRC to these groups is 2

discussed in more detail below. 3

1. Residential Rate Design 4

Electricity pricing for tiered and time-variant residential rates as well as allocation of costs to the 5

residential class are established based on specific Commission direction. Decision (D.)15-07-001 6

established the relationship between tiers for rate schedules that continue to have a tiered rate structure (e.g., 7

Schedule D). As most residential customers will be transitioned to time-based rate structures between 2020 8

and 2022, a subsequent decision (D.17-06-030) defined specific requirements for the relationship of the 9

time-variant rate structures (Schedule TOU-D) for pricing differences by season and time periods. SCE 10

proposes to retain the rate relationships established for tiered and time-variant rates with the addition of the 11

FRC, for the period over which these relationships are required. These relationships will be updated to be 12

consistent with any future rate setting decision(s) that adjusts the tiered or time-variant rate structures. The 13

FRC will be allocated to the residential class in the same manner as other classes, as described above. 14

2. CARE and FERA Rate Design 15

As discussed in the FRC Applicability section above, CARE and FERA customers are exempt from 16

paying the FRC. SCE proposes the rate design described below for CARE and FERA to achieve this 17

statutory mandate. SCE anticipates making these change to its billing system for both CARE and FERA in 18

2022. As discussed below in Section V.C, an interim solution will be used in 2021 that increases the 19

CARE/FERA line item discount to account for the FRC exemption. 20

a) CARE 21

Public Utilities Code Section 739.1(c)(1) provides that the average CARE discount may be 22

delivered via a percent line-item discount (for time-of-use rates) or through a cents/kWh rate (for tiered 23

rates), provided that the overall effective discount be between 30 and 35 percent off the otherwise applicable 24

rate. Currently, SCE’s CARE customers receive an overall effective discount of 32.5% off the Non-CARE 25

residential rate. This overall effective discount is comprised of a percent line item discount as well as 26

8

specific exemptions,9 including the Department of Water Resources (“DWR”) Bond Charge and, if 1

approved, the FRC. These specific exemptions add up to approximately 3.6%. With these specific 2

exemptions, the percent line-item discount that must be applied to the balance of the bill is approximately 3

28.9%, to create a total effective discount of 32.5% (i.e., the sum of 3.6% and 28.9%). By including an 4

additional specific FRC exemption to CARE rates, the percent line-item discount would decrease slightly 5

from the current 28.9%, but the total effective discount to CARE customers will remain at 32.5%. In 2022, 6

post transition to SCE’s new billing system, this effective CARE discount methodology will be applied to 7

both tiered and time-of-use CARE billing. This treatment of the CARE exemption to the FRC is the same 8

methodology used to exempt CARE customers from paying the DWR Bond Charge. 9

b) FERA 10

Section 739.12 requires that the FERA discount be set to 18% off the applicable rate.10 11

Currently, the 18% FERA discount is provided through a percent line-item discount applied to the bill based 12

on the otherwise applicable rate. If approved, that otherwise applicable rate will contain the FRC. As with 13

CARE, the specific FRC exemption for FERA will be subtracted from each FERA customer’s bill and then 14

the FERA line item discount of 18% will be applied to the subtotal bill for FERA customers. SCE will 15

therefore change the current FERA calculation to first remove the FRC amounts and then apply the 18% 16

line item discount. 17

c) Recovery of CARE and FERA Funding and Related Rate Changes 18

SCE proposes to recover the CARE/FERA FRC exemption in a manner that differs from the 19

current recovery methods used outside of the AB 1054 securitization context. The standard CARE discount 20

is recovered within the Public Purpose Programs Charge (“PPPC”) rate component from residential 21

customers. The standard FERA discount is recovered from all residential distribution rates. Because the 22

CARE/FERA FRC exemptions in this securitization are entirely distribution function costs, SCE proposes to 23

allocate the revenue requirements exempted for recovery from CARE/FERA customers to the non-exempt 24

9 This analysis is for time -of-use rates.

10 Section 739.12 requires that “The FERA program discount shall be an 18 percent line-item discount applied to an eligible customer’s bill calculated at the applicable rate for the billing period.”

9

residential and non-residential customers using proportional allocation factors based on contribution to 1

distribution costs less the CARE/FERA contribution. 2

d) Process for Calculating FRC Rate Factors 3

The FRC is unique to each rate group based on their respective allocation of FRC revenue 4

requirements and the forecasted sales. SCE will take the following steps to establish these cents-per-kWh 5

volumetric rates for each rate group: 6

Calculate all-in FRC revenue requirements, as described in Exhibit SCE-03; 7

Allocate the FRC revenue requirement using the GRC Phase 2 distribution allocation 8

factors with CARE/FERA and Non-CARE/FERA rate groups identified separately; 9

Allocate CARE/FERA exemption revenue requirements to all other rate groups using 10

proportional allocation factors based on contribution to distribution costs less the 11

CARE/FERA contribution; 12

Divide each rate group’s respective allocation of the FRC revenue requirement by its 13

respective authorized forecasted sales;11 14

Set each rate group’s FRC at a Clearing Rate12 sufficient to service the Periodic 15

Billing Requirement in each payment period; and 16

To the extent the Clearing Rate results in a revenue imbalance (i.e., over or under-17

collection of revenue), the imbalance will be applied to the FRC revenue requirement 18

through the true-up process described in Exhibit SCE-03. 19

11 Forecasted sales for the remainder of the then-current year and of the subsequent year, if applicable, of the

transaction would reflect SCE’s most-recently approved sales forecast, and as available, a pending forecast for any period not covered by the most recently-approved sales forecast.

12 The Clearing Rate refers to the rate level required to ensure recovery of a sufficient amount of revenue to pay the bond principle and interest payment at the end of each 6-month payment period (or slightly longer initial payment period). The Clearing Rate remains in effect over two payment periods, and is reset at the end of the second payment period through the true-up process.

10

D. Illustrative Rates 1

An example of the FRC volumetric cent-per-kWh charges and average bundled service rates for all 2

rate groups are shown in Table III-2, below.13 The example is based on an annual FRC revenue requirement 3

described in Exhibit SCE-03, with the base FRC amount and the CARE/FERA exemption allocated on the 4

basis of rate group contributions to distribution costs as determined in SCE’s 2018 GRC Phase 2 proceeding 5

and discussed above. The securitization is calculated in accordance with Application Appendix D, 6

Attachment 1 (Description of the True-Up Adjustment Mechanism and Implementing Cash Flow Model). 7

Table III-2 Present and Proposed Bundled Rates With Securitization - $24 Million Revenue

Requirement (Comparison of Rates Effective as of June 1, 2020)

The proposed rates in Table III-2 above are illustrative. Final FRCs by rate class will 8

not be calculated until after the final terms of an issuance of Recovery Bonds have been established. This 9

outlines the methodology that will be used in developing the proposed FRC. Barring significant changes in 10

the projected terms of an issuance of Recovery Bonds, the results presented herein, including the illustrative 11

FRC, should closely approximate the final figures. As described in Exhibit SCE-03, periodic adjustments 12

will be made to the FRC to account for annual sales forecast changes that generally take place in the first 13

quarter of the year, Ongoing Financing Costs, and assumed uncollectibles. SCE may also adjust the revenue 14

allocation factors occurring in a future GRC Phase 2 cycle. 15

13 Standby classes are included in Large C&I (Sec, Pri, Sub)

Rate Group Description Rate Name

June 2020 Group 

Average Rate ¢/kWh

Securitization Rate 

¢/kWh

Revised Rate After 

Adder ¢/kWh %Δ

Residential Domestic Non‐CARE 22.27 0.06 22.33 0.3%

Residential Domestic FERA 18.26 0.00 18.26 0.0%

Res/Dom Income Qualified CARE 13.96 0.00 13.96 0.0%

Small C&I (<20kW) GS‐1 19.56 0.04 19.60 0.2%

Traffic Control TC‐1 20.72 0.06 20.77 0.3%

Medium C&I (20‐200) GS‐2 19.66 0.04 19.70 0.2%

Medium C&I (200‐500) GS‐3 17.47 0.03 17.50 0.2%

Large C&I (Sec) TOU‐8‐Sec 15.66 0.03 15.69 0.2%

Large C&I (Pri) TOU‐8‐Pri 14.39 0.02 14.41 0.2%

Large C&I (Sub) TOU‐8‐Sub 9.69 0.01 9.69 0.1%

Small AG& Pump (<200kW) AG&P < 200 KW 16.65 0.04 16.69 0.3%

Large AG& Pump (<200kW) AG&P >= 200 KW 13.96 0.03 13.99 0.2%

Street/Area Lighting Street Light 19.16 0.00 19.16 0.0%

System 17.89 0.03 17.92 0.2%

Note: Standby classes included in Large C&I (Sec, Pri, Sub)

11

IV. 1

PRESENTATION ON CUSTOMER BILLS 2

California Public Utilities Code Section 850.1(g) provides “Any fixed recovery charge authorized by 3

a financing order shall appear on consumer bills.” SCE proposes the following bill presentation to ensure 4

that the FRC is adequately disclosed to customers consistent with the “true sale” opinion, discussed in 5

Exhibit SCE-03, which will be issued by legal counsel in connection with the Securitization. 6

First, SCE proposes to include the FRC as a single line item for billing and accounting purposes. 7

This line item could include the FRC and future securitization charges pursuant to AB 1054. SCE proposes 8

that the combined item be titled “Fixed Recovery Charge” and appear under the DWR Bond Charge on 9

consumers’ bills. When future financing orders are issued, this line item may be used to reflect multiple 10

FRCs securing multiple Recovery Bond issuances pursuant to Section 850 et seq. The bill and the insert 11

will be revised as appropriate to reflect any other costs that may be recovered through the FRC. 12

Second, SCE proposes to include an explanation of the billed charge on the “Things You Should 13

Know” section at the bottom of each customer bill. That explanation must state: (i) that the FRC has been 14

transferred to a Special Purpose Entity and does not belong to SCE; and (ii) that SCE is collecting the FRC 15

on behalf of that Special Purpose Entity. SCE proposes the following explanation for the bill presentation: 16

Fixed Recovery Charge: Your bill for electric service includes a charge that has been approved 17 by the CPUC to repay bonds issued for certain costs related to catastrophic wildfires. The right to 18 recover the FRC has been transferred to the Special Purpose Entity that issued the bonds and 19 does not belong to SCE. SCE is collecting the FRC on behalf of the Special Purpose Entity. 20

V. 21

INTERIM APPROACH TO INCLUDING THE FRC IN CUSTOMER BILLS PENDING 22

CUSTOMER SERVICE RE-PLATFORM IMPLEMENTATION 23

SCE is in the process of replacing its consumer billing system through its Customer Service 24

Replatform Project (“CSRP”). SCE anticipates that this new billing system will be undergoing final 25

go-live preparation in the first quarter of 2021, around the same time as SCE anticipates finalizing this 26

securitization transaction. Because certain changes related to the securitization – such as the inclusion of 27

the FRC as a line item on bills and implementation of the CARE/FERA exemption – require changes to the 28

12

billing system coding logic, significant modification and retesting is required and would delay the launch of 1

the CSRP system by several months. Moreover, even factor changes – such as rate increases to collect the 2

FRC that do not impact the coding logic – require several weeks of testing. These factor changes create 3

risks to CSRP implementation if made too close to the early April 2021 CSRP go-live date.14 CSRP 4

implementation requires that through June 2021 minimal factor changes and no coding changes occur. SCE 5

seeks authority to employ the following interim approach to incorporate the FRC in bills without negatively 6

impacting CSRP implementation. 7

A. Rate Change to Incorporate FRC 8

Incorporating the FRC into consumer bills requires factor changes. Factor changes must be given to 9

SCE’s CSRP team by January 15, 2021 to be incorporated into bills starting with the billing period 10

commencing early April 2021. CSRP cannot accommodate other factor changes until June 2021. As a 11

result, if the Recovery Bonds are priced on or before January 15, 2021, SCE will be able to include the FRC 12

in customers’ April 2021 bills. If pricing occurs later, SCE will not be able to include the FRC in customer 13

bills until at least June 2021 and may require fourteen weeks from closing to incorporate the FRC. 14

To address this delay, and to avoid the need to impose an unnecessary, high FRC in the initial period 15

to satisfy debt service requirements, SCE may structure a longer first interest payment period. Use of 16

delayed interest payment to address the lag from issuance to inclusion of the FRC in bills is common in 17

utility securitization transactions. The overall impact on customer rates of this interim approach should not 18

be material. 19

B. Bill Presentment 20

Including the FRC as a line item on each customer bill requires a change in coding logic that must 21

await full CSRP implementation and stabilization. SCE proposes an interim bill presentation that 22

aggregates the FRC among distribution charges on consumer bills. Each bill would also include an 23

explanation of the FRC in the “Things You Should Know” section, as described in Section IV above. SCE 24

proposes to either direct customers to a webpage on SCE.com, which would include information that would 25

14 If CSRP go-live date is delayed, SCE will instead include the FRC in SCE’s legacy CSS system.

13

enable consumers to calculate their FRC, by multiplying their monthly energy usage by their FRC rate, or, 1

may include that information on the bill itself. Those proposed bill presentment options are shown in 2

Appendix 6.1 hereto. 3

SCE believes both approaches satisfy Section 850.1(g), which provides that “Any fixed recovery 4

charge authorized by a financing order shall appear on consumer bills.” While the statute does not mandate 5

or provide specific guidance on the manner of bill presentation, SCE believes its inclusion of the charge 6

within distribution charges satisfies the requirement. Thus, either of SCE’s approaches to provide customers 7

more information about the specific level of the charges can be deemed compliant. 8

SCE’s preference is to use a link to a webpage instead of providing the information on the bill, 9

because it would allow SCE to provide a more thorough explanation of the FRC to customers. Using this 10

approach, SCE could develop easy-to-understand content that would enable each customer to calculate their 11

FRC. The content would be vetted with customers in advance, through customer market research (e.g. 12

customer focus groups), to ensure that the information is clear and usable. SCE regularly uses this combined 13

approach of offline and online information to convey complex rate and billing issues to its customers.15 14

C. CARE/FERA Exemption 15

With implementation of CSRP, all CARE/FERA discounts will be provided through the percentage 16

line-item discount methodology described above. Under normal circumstances the FRC would be deducted 17

prior to applying the percentage line-item discount to the sub-total amount. To avoid coding changes 18

necessary to perform this step, SCE will instead increase the percentage line-item discount such that the 19

resulting line-item discount is inclusive of the FRC amount. For example, if the CARE percentage line-item 20

discount is normally 28.9% and the FRC amount represents an incremental 0.3%, then the percentage line-21

item discount would be increased to 29.2% providing the additional discount needed to exclude the FRC. 22

This interim measure will allow SCE to implement the CARE/FERA exemption in the same manner as a 23

factor change. SCE expects the interim measure to be in place until the end of 2021, when the percentage 24

line-item discount approach will be implemented. 25

15 See e.g., SCE’s explanation of residential time-of-use rates, available at:

https://www.sce.com/residential/rates/Time-Of-Use-Residential-Rate-Plans.

Appendix 6.1

SCE’s Proposed Options for Interim Bill Presentment for FRC

6.1-1

SCE proposes to include a description of the FRC in the “Things You Should Know” section at the

bottom of each customer bill. Until SCE’s billing system can accommodate a FRC line item, SCE will

include a cross reference to a webpage on SCE.com (Option 1) or a table on the bottom of the bill or

detailing the FRC by customer class (Option 2).

Option 1: Link to SCE.com

6.1-2

Option 2: Table on the Bill

Application No.: A.20-07-008 Exhibit No.: SCE-07 Witnesses: C. Peterman

(U 338-E)

Recovery Bond Financing

Proposal for Future Financing Orders

Before the

Public Utilities Commission of the State of California

Rosemead, California July 8, 2020

Direct Testimony Supporting Southern California Edison's Application for Recovery Bond Financing: Proposal for Future Financing Orders

Table Of Contents

Section Page Witness

-i-

I.  PROPOSAL FOR FUTURE FINANCING ORDERS ......................................1 C. Peterman 

A.  Future Costs To Be Securitized .............................................................1 

B.  Proposed Tier 3 Advice Letter Process for Approval of Additional Financing Orders..................................................................2 

II.  CONCLUSION ..................................................................................................5 

1

I. 1

PROPOSAL FOR FUTURE FINANCING ORDERS 2

Southern California Edison Company (“SCE”) hereby submits its proposal requesting that the 3

Commission adopt a streamlined procedure for the issuance of future financing orders. Specifically, 4

SCE proposes that as part of the financing order approving this Application the Commission also 5

establish an advice letter process for SCE to submit requests for, and the Commission to consider and 6

issue future financing orders approving, the securitization of other Section 850 et seq. costs and 7

expenses, including fire risk mitigation capital expenditures under Section 8386.3(e). 8

A. Future Costs To Be Securitized 9

SCE plans to securitize under Section 850(a)(2) at least the remainder of the $1.575 billion of 10

“fire risk mitigation capital expenditures included in [SCE’s] approved wildfire mitigation plan[]” 11

(“Total AB 1054 CapEx”).1 This initial application contemplates securitization of $326,981,000 in 12

Initial AB 1054 CapEx. If approved, that would leave a remainder of $1.248 billion of Total AB 1054 13

CapEx to be securitized through future financing orders following a determination by the Commission 14

that the underlying capital expenditures are just and reasonable. SCE anticipates that certain costs 15

subject to review in its 2021 General Rate Case will make up this remaining Total AB 1054 Capex as 16

those costs are approved by the Commission in the General Rate Case. 17

GRC Track 2 (2019 Recorded Costs): SCE’s spending on AB 1054 CapEx in 2019 (other than 18

GSRP) is currently being reviewed in Track 2 of the GRC. SCE’s 2019 recorded costs are 19

tracked in SCE’s Wildfire Mitigation Plan Memorandum Account, Fire Risk Mitigation 20

Memorandum Account, and Fire Hazard Prevention Memorandum Account. SCE anticipates 21

that approximately $219 million2 in August-December 2019 costs will be subject to review and, 22

if approved, constitute AB 1054 CapEx. 23

1 Cal. Pub. Util. Code § 8386.3(e).

2 This includes $204 million of direct capital expenditures pending reasonableness review in Track 2 of SCE’s 2012 GRC.

2

GRC Track 3 (2020 Recorded Costs): SCE’s spending on AB 1054 CapEx in 2020, which 1

will include Grid Safety and Resiliency Program costs that exceed those authorized in D.20-04-2

013,3 will be reviewed in Track 3 of the GRC. SCE’s 2020 recorded costs are tracked in SCE’s 3

Wildfire Mitigation Plan Memorandum Account, Fire Risk Mitigation Memorandum Account, 4

Fire Hazard Prevention Memorandum Account, and Grid Safety and Resiliency Program 5

Memorandum/Balancing Account. SCE anticipates that approximately $787 million in 2020 6

costs will be subject to review and, if approved, constitute AB 1054 CapEx. 7

GRC Track 1 (2021 Test Year Costs): SCE’s 2021 Test Year forecast, including planned 8

spending on wildfire mitigation costs, will be reviewed in Track 1 of the GRC. Depending on 9

the amounts of AB 1054 CapEx approved in Tracks 2 and 3, there may be a remaining amount of 10

capital expenditures in 2021 (estimated to be approximately $243 million) that constitute AB 11

1054 CapEx. 12

B. Proposed Tier 3 Advice Letter Process for Approval of Additional Financing Orders 13

SCE proposes that the Commission’s decision on this Application authorize a process by which 14

SCE may submit requests for additional financing orders via a Tier 3 advice letter. SCE would submit 15

such a request subsequent to a reasonableness determination by the Commission regarding additional 16

Section 850 et seq. costs and expenses, including the remaining Total AB 1054 CapEx. After reviewing 17

SCE’s submission, if it determines that the relevant amounts or costs are recovery costs within the 18

meaning of Public Utilities Code Section 850(a)(10), the Commission would issue an additional 19

financing order by way of a resolution and in that resolution make any other necessary findings for the 20

issuance of additional recovery bonds. 21

For the Commission to issue a financing order, Section 850(a)(1)(A) requires that the following 22

conditions be satisfied: 23

3 To the extent there is GSRP spending in 2018-2020 above the settlement amounts approved in D.20-04-013,

those amounts are subject to a reasonableness review in Track 3 of the GRC. Any such capital expenditures from August-December of 2019 or 2020 could, if approved, constitute AB 1054 CapEx.

3

(i) The recovery cost to be reimbursed from the recovery bonds have been found to be just 1 and reasonable pursuant to Section 451 or 451.1, as applicable, or are allocated to the 2 ratepayers pursuant to subdivision (c) of Section 451.2. 3

(ii) The issuance of the recovery bonds, including all material terms and conditions of the 4 recovery bonds, including, without limitation, interest rates, rating, amortization redemption, 5 and maturity, and the imposition and collection of fixed recovery charges as set forth in an 6 application satisfy all of the following conditions, as applicable: 7

(I) They are just and reasonable. 8

(II) They are consistent with the public interest. 9

(III) The recovery of recovery costs through the designation of the fixed recovery 10 charges and any associated fixed recovery tax amounts, and the issuance of recovery 11 bonds in connection with the fixed recovery charges, would reduce, to the maximum 12 extent possible, the rates on a present value basis that consumers within the electrical 13 corporation’s service territory would pay as compared to the use of traditional utility 14 financing mechanisms, which shall be calculated using the electrical corporation’s 15 corporate debt and equity in the ratio approved by the commission at the time of the 16 financing order. 17

In its submission, SCE would show that the relevant amounts or costs are recovery costs within 18

the meaning of Public Utilities Code Section 850(a)(10) and identify the Commission decision(s) or 19

determination(s) regarding the reasonableness of those amounts or costs, consistent with Section 20

850(a)(1)(A)(i). The other required findings in Section 850(a)(1)(A)(ii) relate to the terms of the 21

recovery bonds to be issued and as discussed below, would already have been addressed as part of this 22

proceeding or will be addressed as part of a future request for an additional financing order. 23

In this proceeding, SCE requests that the Commission determine that the recovery of additional 24

Section 850 et seq. costs and expenses, including the Total AB 1054 CapEx, to the extent approved for 25

reasonableness as required in Section 850(a)(1)(A)(i), should be allocated among customers and should 26

be recovered through Fixed Recovery Charges calculated and adjusted based upon the True-Up 27

Mechanism, all as proposed by SCE and approved in this proceeding, and that such a cost allocation and 28

adjustment mechanism is both in the public interest and just and reasonable. SCE also requests that the 29

Commission determine that future use of the securitization transaction structure (including the use of 30

one or more newly-formed SPEs) and servicing arrangements generally described in SCE’s testimony 31

for such costs and expenses is also in the public interest and just and reasonable. The specific terms of 32

4

any future bond issuance similarly will be subject to the same Issuance Advice Letter approval process 1

described in SCE’s testimony. 2

Accordingly, SCE’s showing in this proceeding and the Commission’s determination in its 3

decision on this Application would apply equally to such future requests for additional financing orders. 4

Future submissions by SCE pursuant to the proposed process would include a similar showing to SCE-5

04 to demonstrate that the issuance of recovery bonds would result in savings for customers and, to the 6

extent there are material changes that affect the Commission’s consideration of other issues, SCE also 7

would include any revisions or additions necessary to supplement its showing. For example, SCE’s 8

future submissions may further describe (1) material changes in the interest rates, scheduled and final 9

maturity dates, amortization schedule, credit enhancement, etc. as well as the estimated upfront issuance 10

costs and ongoing financing costs associated with the bond issuance, (2) any other material changes in 11

bond market conditions and related issuance circumstances, and (3) any applicable changes in SCE’s 12

rate design. In future submissions SCE would provide the estimate of Upfront Financing Costs and 13

Ongoing Financing Costs associated with such issuance. These costs would be adjusted and finalized 14

using the same Issuance Advice Letter process as authorized in this Financing Order. To the extent 15

future submissions involve the issuance of multiple series of Recovery Bonds, the Upfront Financing 16

Costs would be adjusted and set forth in the Issuance Advice Letter relating to each issuance. SCE also 17

would provide notice to affected customers of the proposed change in rates consistent with General Rule 18

4.2 of General Order 96-B. SCE proposes that, upon submission of a future request for a financing 19

order, the Commission would make a good faith effort to adopt a financing order resolution within 60 20

days. SCE anticipates that such future financing orders would be substantially identical to any financing 21

order on this Application, but would take the form of Commission resolutions. SCE’s request would 22

include a proposed form of financing order as well as a redline comparison to the financing order issued 23

in this proceeding. 24

5

II. 1

CONCLUSION 2

SCE requests that the Commission adopt SCE’s proposal for a streamlined procedure for the 3

issuance of future financing orders. 4

Appendix A

Witness Qualifications

Application No.: A.20-07-008 Witnesses: E. Chang (Barclays)

M. Childs S. Deana B. Pang C. Peterman R. Thomas N. Woodward

(U 338-E)

Recovery Bond Financing

Witness Qualifications

Before the

Public Utilities Commission of the State of California

Rosemead, California July 8, 2020

A-1

A-2

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF ERIC CHANG 3

Q. Please state your name, business address and current employment position for the record. 4

A. My name is Eric Chang. My business address is 745 Seventh Avenue, New York, New York 5

10019. I am a Managing Director at Barclays Capital Inc. (“Barclays”) in the Securitized 6

Products Origination group. 7

Q. Briefly describe your educational background and professional experience. 8

A. I graduated from New York University Stern School of Business with a B.A. in Finance and 9

Marketing. My relevant professional experience includes working approximately 16 years in the 10

securitization industry. From 2005 – 2011, I was employed at Bank of America Merrill Lynch as 11

a securitization banker and executed asset-backed securities transactions across consumer asset 12

classes. Since 2011, I have been employed at Barclays as a securitization originator and banker 13

focused on a broad range of consumer asset classes, including utility securitizations. I have 14

worked on securitizations for a number of utilities including AEP Texas Central, CenterPoint 15

Energy and the Long Island Power Authority. Most recently in 2017, I worked as a lead banker 16

on a $369 million securitization for Long Island Power Authority where Barclays acted as 17

structuring agent and joint senior manager. 18

Q. Do you possess any professional licenses related to the securities industry? 19

A. Yes. I have both the Series 7 (General Securities Registered Qualification) and Series 63 20

(Uniform Securities Agent State Law Examination) licenses as qualified by the Financial 21

Industry Regulatory Authority (“FINRA”). The qualifications allow an individual to act as a 22

general securities representative or agent across a broad range of products in the securities 23

industry. 24

Q. What is the purpose of your testimony in this proceeding? 25

A. The purpose of my testimony in this proceeding is to sponsor Exhibit SCE-02 entitled 26

Background on Utility Securitization, which will: (i) provide a brief history and overview of the 27

A-3

securitization market, including the structural features of commercial securitization transactions; 1

(ii) describe key structural and security features of utility securitizations; (iii) discuss structuring, 2

sale, and pricing considerations of utility securitizations; (iv) describe the rating agency process 3

and considerations for utility securitizations; (v) describe the marketing process for utility 4

securitizations; (vi) describe the costs of issuance associated with utility securitizations 5

generally, and specifically these estimated costs for SCE’s first recovery bond issuance; and (vii) 6

provide concluding remarks to the testimony. 7

Q. Was this material prepared by you or under your supervision? 8

A. Yes, it was. 9

Q. Insofar as this material is factual in nature, do you believe it to be correct? 10

A. Yes, I do. 11

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 12

judgment? 13

A. Yes, it does. 14

Q. Does this conclude your qualifications and prepared testimony? 15

A. Yes, it does. 16

A-4

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF MARK W. CHILDS 3

Q. Please state your name and business address for the record. 4

A. My name is Mark W. Childs, and my business address is 2244 Walnut Grove Avenue, 5

Rosemead, California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am the Director of Tax for Southern California Edison Company. In this capacity, I am 8

responsible for managing and directing all of the tax accounting and tax regulatory functions for 9

the Company including all tax matters in this proceeding. 10

Q. Briefly describe your educational and professional background. 11

A. I hold a Bachelor of Science degree in Accounting from Pepperdine University. I joined the 12

Southern California Edison Company in 2010 and was then promoted into my current role 13

shortly after joining the Company. Prior to joining the Company, I spent sixteen years with 14

Mattel, Inc. most recently as the Senior Director of Tax. My primary responsibilities there 15

included the tax implementation and continued compliance with Sarbanes-Oxley as well as 16

managing and directing all of the tax accounting functions. 17

Q. What is the purpose of your testimony in this proceeding? 18

A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-05, 19

entitled Taxation, as identified in the Table of Contents thereto. 20

Q. Was this material prepared by you or under your supervision? 21

A. Yes, it was. 22

Q. Insofar as this material is factual in nature, do you believe it to be correct? 23

A. Yes, I do. 24

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 25

judgment? 26

A-5

A. Yes, it does. 1

Q. Does this conclude your qualifications and prepared testimony? 2

A. Yes, it does. 3

A-6

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF SERGIO P. DEANA 3

Q. Please state your name and business address for the record. 4

A. My name is Sergio P. Deana, and my business address is 2244 Walnut Grove Avenue, 5

Rosemead, California 91770 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am the Director of Corporate Finance, Capital Governance and Regulatory Economics in the 8

Treasurer’s Department. My present responsibilities are to oversee financial projections and 9

analyses for internal corporate purposes and regulatory filings. 10

Q. Briefly describe your educational and professional background. 11

A. I received a Bachelor of Science degree in Mechanical Engineering from Worcester Polytechnic 12

Institute in 2001, a Master of Science degree in Mechanical Engineering from Rensselaer 13

Polytechnic Institute in 2004, and a Master of Business Administration degree from 14

Northwestern University in 2007. I joined Southern California Edison in 2010 as a Project 15

Manager in the Business Planning and Financial Management team within the Transmission & 16

Distribution business unit. In 2013 I was promoted to Senior Manager within SCE’s Treasury 17

Department, overseeing cash and capitalization forecasts in the Financial Planning & Analysis 18

team. In 2016 I was promoted to Principal Manager overseeing first strategic analysis and capital 19

governance efforts, and later SCE’s consolidated financial projections. In 2020, I was promoted 20

to my current position of Director. Prior to joining Southern California Edison, I was an 21

engineer, supervisor and manager in the aerospace and industrial supply industries. 22

Q. What is the purpose of your testimony in this proceeding? 23

A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-04, 24

entitled Customer Benefits, as identified in the Table of Contents thereto. 25

Q. Was this material prepared by you or under your supervision? 26

A-7

A. Yes, it was. 1

Q. Insofar as this material is factual in nature, do you believe it to be correct? 2

A. Yes, I do. 3

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 4

judgment? 5

A. Yes, it does. 6

Q. Does this conclude your qualifications and prepared testimony? 7

A. Yes, it does. 8

A-8

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF KAM B. (“BILL”) PANG 3

Q. Please state your name and business address for the record. 4

A. My name is Bill Pang, and my business address is 2244 Walnut Grove Avenue, Rosemead, 5

California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am the Senior Manager, Capital Markets in the Treasurer’s Department. My current 8

responsibilities are to develop and execute financing strategies for Southern California Edison 9

Company (“SCE”) and Edison International (“EIX”). Our financing strategies involve issuing 10

various forms of short- and long-term debt, as well as preferred and common equity. 11

Q. Briefly describe your educational and professional background. 12

A. I received a Bachelor of Science degree in Mechanical Engineering from Carnegie Mellon 13

University in 1994 and a Master of Business Administration degree from the UCLA Anderson 14

School of Management in 2003. I joined SCE in 2017 as a senior manager responsible for long-15

term financing. From 2018 to 2019, I also implemented enhanced liquidity strategies by closing 16

multiple short-term credit facilities, while managing secured and unsecured debt issuances at 17

SCE and EIX. In 2020, my team and I were also tasked with leading SCE’s securitization efforts, 18

reporting directly to the Treasurer. Prior to joining SCE, I held various positions over 14 years at 19

Toyota Financial Services and led teams responsible for asset-backed securitizations, debt capital 20

markets, and interest rate hedging transactions. Prior to Toyota, I was a senior plant engineer in 21

the industrial gas and specialty chemicals industries. 22

Q. What is the purpose of your testimony in this proceeding? 23

A. The purpose of my testimony in this proceeding is to sponsor Exhibit SCE-03, entitled 24

Transaction Overview, as identified in the Table of Contents thereto. 25

Q. Was this material prepared by you or under your supervision? 26

A-9

A. Yes, it was. 1

Q. Insofar as this material is factual in nature, do you believe it to be correct? 2

A. Yes, I do. 3

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 4

judgment? 5

A. Yes, it does. 6

Q. Does this conclude your qualifications and prepared testimony? 7

A. Yes, it does. 8

A-10

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF CARLA PETERMAN 3

Q. Please state your name and business address for the record. 4

A. My name is Carla Peterman, and my business address is 8631 Rush Street, Rosemead, California 5

91770 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am Senior Vice President of Regulatory Affairs at SCE. I am responsible for the company’s 8

Regulatory Affairs, Energy and Environmental Policy, Strategic Planning, and Resource and 9

Environmental Planning and Strategy organizations at the national and state levels, overseeing 10

regulatory strategy and operations and environmental affairs. 11

Q. Briefly describe your educational and professional background. 12

A. Prior to joining SCE in 2019, I was appointed by California Governor Gavin Newsom to chair 13

the Commission on Catastrophic Wildfire Cost and Recovery. From 2013 to 2018 I was 14

Commissioner at the California Public Utilities Commission where I led on several clean-energy 15

initiatives. Prior to my CPUC appointment, I served on the California Energy Commission, 16

where I was the lead commissioner for renewables, transportation, and natural gas. I am also a 17

former board member of The Utility Reform Network, an organization that represents consumers 18

before the CPUC and California Legislature. I hold a Doctor of Philosophy degree in energy and 19

resources from the University of California Berkeley and also earned a Master of Science and 20

Master of Business Administration from Oxford University where I was a Rhodes Scholar. I 21

earned a Bachelor of Arts from Howard University. 22

Q. What is the purpose of your testimony in this proceeding? 23

A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-07, 24

entitled Proposal for Future Financing Orders, as identified in the Table of Contents thereto. 25

Q. Was this material prepared by you or under your supervision? 26

A-11

A. Yes, it was. 1

Q. Insofar as this material is factual in nature, do you believe it to be correct? 2

A. Yes, I do. 3

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 4

judgment? 5

A. Yes, it does. 6

Q. Does this conclude your qualifications and prepared testimony? 7

A. Yes, it does. 8

A-12

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF ROBERT THOMAS 3

Q. Please state your name and business address for the record. 4

A. My name is Robert Thomas, and my business address is 8631 Rush Street, Rosemead, California 5

91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A I am Director of the Pricing Design, Load Research, and Forecasting Groups in the Regulatory 8

Affairs Department at Southern California Edison Company. In this position, I am responsible 9

for development of SCE’s rate designs. I have held this position since September 16, 2019. 10

Q. Briefly describe your educational and professional background. 11

A. I hold a Bachelor of Science and Engineering from the University of Arizona, a Masters’ degree 12

in Business Administration from California State Polytechnic University, Pomona and a 13

Professional Engineering License in Mechanical Engineering. Prior to my current position, my 14

responsibilities have included Manager of the Analysis and Program Support Group, within 15

SCE’s Business Customer Division, where I was responsible for providing complex customer 16

specific rate and financial analyses involving self-generation, load growth, contract rates, and 17

hourly pricing options. Prior to this position, I was the SCE’s Program Manager for the Self 18

Generation Incentive Program. In this position, I was responsible for all aspects of the program 19

including dispute resolution, processing applications, and program promotion. 20

Q. What is the purpose of your testimony in this proceeding? 21

A. The purpose of my testimony in this proceeding is to sponsor all portions denoted in the Table of 22

Contents of Exhibit SCE-06, entitled Ratemaking Mechanism and Rate Proposal Testimony. 23

Q. Was this material prepared by you or under your supervision? 24

A. Yes, it was. 25

Q. Insofar as this material is factual in nature, do you believe it to be correct? 26

A. Yes, I do. 27

A-13

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 1

judgment? 2

A. Yes, it does. 3

Q. Does this conclude your qualifications and prepared testimony? 4

A. Yes, it does. 5

A-14

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF NATALIA WOODWARD 3

Q. Please state your name and business address for the record. 4

A. My name is Natalia Woodward, and my business address is 2244 Walnut Grove Avenue, 5

Rosemead, California 91770 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am Vice President and Treasurer of SCE. My responsibilities include managing and directing 8

the treasury functions for the company which include corporate financial planning and analysis, 9

capital markets, cash management, regulatory economics, risk management, capital analytics, 10

and trust investments. 11

Q. Briefly describe your educational and professional background. 12

A. Prior to my current role, I was the Director of Corporate Finance, Risk Management and Capital 13

Governance. My responsibilities included managing corporate budgeting, long term financial 14

planning, strategic and risk analyses, capital governance, capital analytics and risk management. 15

In that role, I served as a witness in SCE’s recent 2020 Cost of Capital proceeding, A.19-04-014. 16

Prior to that, I have held a variety of management positions at SCE, Edison Mission Energy and 17

Edison International, including in risk management, financial planning, and corporate finance. 18

Before joining the Edison companies, I held finance positions at Allegheny Energy, Merrill 19

Lynch and Dime Savings Bank. I earned a Master of Arts in Economics from University of 20

California, Davis and a Bachelor of Science in Mathematics and Economics from the University 21

of California, Los Angeles. 22

Q. What is the purpose of your testimony in this proceeding? 23

A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-01, 24

entitled Policy Overview, as identified in the Table of Contents thereto. 25

Q. Was this material prepared by you or under your supervision? 26

A-15

A. Yes, it was. 1

Q. Insofar as this material is factual in nature, do you believe it to be correct? 2

A. Yes, I do. 3

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 4

judgment? 5

A. Yes, it does. 6

Q. Does this conclude your qualifications and prepared testimony? 7

A. Yes, it does. 8