EXHIBIT M

Case: 19-30088 Doc# 4486-13 Filed: 10/25/19 Entered: 10/25/19 20:22:43 Page 1

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BEFORE THE PUBLIC UTILITIES COMMISSION 

OF THE STATE OF CALIFORNIA 

Application of Southern California Edison 

Company (U338E) for Authority to Establish Its 

Authorized Cost of Capital for Utility Operations 

for 2020 and to Partially Reset the Annual Cost of 

Capital Adjustment Mechanism. 

A.19-04-014

(Filed April 22, 2019) 

And Related Matters 

A.19-04-015, 

A.19-04-017, 

A.19-04-018 

(Filed April 22, 2019) 

OPENING BRIEF OF 

SAN DIEGO GAS & ELECTRIC COMPANY (U 902 M) 

ROSS R. FULTON 

AIMEE M. SMITH 

8330 Century Park Court 

San Diego, California 92123 

Telephone: (858) 654-1861 (Fulton) 

Telephone: (858) 654-1644 (Smith) 

Facsimile: (619) 699-5027 

Email: rfulton@sdge.com 

 amsmith@sdge.com 

Counsel for 

SAN DIEGO GAS & ELECTRIC COMPANY 

September 30, 2019 

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TABLE OF CONTENTS 

I. INTRODUCTION AND SUMMARY OF RECOMMENDATIONS ....................1

II. LEGAL STANDARDS AND POLICY CONSIDERATIONS ...............................5

III. RETURN ON EQUITY ...........................................................................................9

A. California Electric Utilities Face Heightened Risks ..................................10

1. California’s Wildfire Liability Regime Presents California 

Utilities with Unique Risks ............................................................12

a. The combination of increased wildfire damages, inverse 

condemnation, and uncertainty and perceived lack of ability 

for cost recovery led to credit rating downgrades and an 

increased cost of capital .................................................... 12

b. AB 1054 improves but does not fully mitigate the risks of 

California’s unique wildfire liability and cost recovery 

regime ............................................................................... 20

2. California Utilities Face Significant Non-Wildfire Risks ..............32

a. Ambitious Public Policy Initiatives .................................. 34

b. Increased Customer Adoption of Advanced 

Technologies ..................................................................... 41

c. Uncertainty Caused by Fundamental Changes to Utility 

Role in the Market ............................................................ 43

i. RPS Program Risks ............................................... 47

ii. RA Program Risks ................................................ 48

iii. IRP Process Risks ................................................. 49

d. Technology and Cyber Security Risk ............................... 52

e. Elevated Levels of Capital Investment ............................. 52

B. SDG&E’s ROE Proposal Reflects The Company’s Unique and 

Heightened Risks .......................................................................................53

1. Dr. Morin’s Traditional, Proxy-Based Recommendation ..............53

2. Concentric’s Quantification of SDG&E’s Unique Wildfire 

Risks ...............................................................................................57

C. Intervenors’ Recommendations Treat SDG&E as if The Company Faces 

Below-Average Risks and Should be Rejected .........................................61

1. Intervenors Admit That Returns Must Be Set Commensurate with 

Risks Yet Propose Below Average ROEs for SDG&E .................61

2. Once Intervenors’ ROE Proposals Modeling Errors Are Corrected, 

Intervenors’ Proposals are Near or Above Dr. Morin’s 

Recommendation ...........................................................................64

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3. Intervenors Ignore SDG&E’s Wildfire Risks and/or 

Overstate AB 1054’s Impact ..........................................................70

IV. CAPITAL STRUCTURE ......................................................................................75

A. Commission Precedent Supports an Authorized Capital Structure That 

Reflects Actual Recorded Ratios ...............................................................79

B. The Proposed Capital Structure Helps SDG&E Manage its 

Financial Risks ...........................................................................................80

C. SDG&E’s Proposed Capital Structure is Credit Supportive ......................85

V. EMBEDDED COST OF DEBT AND PREFERRED EQUITY ...........................89

VI. COST OF CAPITAL ADJUSTMENT MECHANISM .........................................90

A. Operation and Purpose of the CCM ...........................................................90

B. Proposed Modification of Dead Band ........................................................92

C. Proposed CCM Clarifications ....................................................................95

1. Clarification Regarding Split Credit Ratings Index Selection .......95

2. Clarification Regarding Ratings Change During CCM 

Years ..............................................................................................96

3. Guidance Regarding Downgrade to Non-Investment Grade 

Rating .............................................................................................96

VII. CONCLUSION ......................................................................................................97

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TABLE OF AUTHORITIES 

CONSTITUTIONAL PROVISIONS 

Cal. Const. Art. 12, Section 5 (1974) ...................................................................................5 

STATUTES AND LEGISLATION 

AB 1054, Stats. 2019-2020, Ch. 79 (Cal. 2019) ........................................................ passim 

Cal. Pub. Util Code § 216(b) (2016) ....................................................................................5 

Cal. Pub. Util. Code § 451.1 (2019) .......................................................................... passim

Cal. Pub. Util. Code § 2827 (2018) ...................................................................................43 

Cal. Pub. Util. Code §§3288(b) (2019) ..............................................................................20 

Cal. Pub. Util. Code § 3291(c) ...........................................................................................20 

Cal. Pub. Util. Code §3292(b) (2019) ................................................................................21 

Cal. Pub. Util. Code § 3292(f)(1) (2019) ...........................................................................21 

SB 100, Stats, 2017-2018, Ch. 312 (Cal. 2018) .......................................................35,36,37 

SB 237, Stats. 2017-2018, Ch. 600 (Cal. 2018) .................................................................46 

CASE LAW 

Barnham v. S. Cal. Edison Co., 74 Cal. App. 4th 744, 752 (1999) ....................................15 

Bluewater Works & Improvement Co. v. Puc. Serv. Comm’n, 

 262 U.S. 679, 692 (1923) ...............................................................................................7 

Covington & Lexington Turnpike Road Co. v. Sandford, 164 U.S. 578, 597 (1896) ..........7 

Duquesne Light Co. v. Barasch, 488 U.S. 299, 307-312 (1989) .....................................6, 7 

Federal Power Com. V. Hope Natural Gas Co., 320 U.S. 591, 603 (1944) .......................7 

Permian Basin Area Rate Cases, 390 U.S. 747, 768 (1968) ............................................5,7 

 

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CALIFORNIA PUBLIC UTILITIES COMMISSION DECISIONS 

D.03-12-035, 2002 Cal. PUC Lexis 1051 ............................................................................9 

D.07-12-049, 2007 Cal. PUC Lexis 593 ..............................................................................6 

D.08-05-035, 2008 Cal. PUC Lexis 204 .................................................................... passim 

D.10-03-022, 2010 Cal. PUC Lexis 71 ..............................................................................46 

D.12-12-034, 2012 Cal. PUC Lexis 593 .................................................................... passim 

D.13-03-015, 2013 Cal. PUC Lexis 131 .......................................................................98,99 

D.17-07-005, Cal. PUC Lexis 319 .....................................................................................98 

D.17-11-033, Cal. PUC Lexis 513 .....................................................................................17 

D.18-02-018, 2018 Cal. PUC Lexis 61 ..............................................................................36 

D.18-03-035, 2018 Cal. PUC Lexis 113 ....................................................................6, 8, 85 

D.18-06-030, 2018 Cal. PUC Lexis 256 ................................................................46, 51, 52 

D.18-10-019, 2018 Cal. PUC Lexis 480 ..........................................................40, 42, 46, 50 

D.19-03-012, 2019 Cal. PUC Lexis 152 ............................................................................41 

D.19-04-040, 2019 Cal. PUC Lexis 159 ................................................................36, 53, 54 

D.19-06-026, 2019 Cal. PUC Lexis 329 ................................................................50, 51, 52 

D.94-11-076, 1994 Cal. PUC Lexi 1151 ...........................................................................75 

D.99-06-057, 1999 Cal. PUC Lexis 315 ............................................................................75 

FEDERAL ENERGY REGULATORY COMMISSION DECISIONS 

Energy Services, Inc., 130 FERC ⁋61,023 (2010) .............................................................17 

San Diego Gas & Electric Co., 146 FERC ⁋63,017(2014) ...............................................17 

 

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OTHER AUTHORITIES 

Commission Rules of Practice and Procedure, Rule 13.11 .................................................1 

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of 105
BEFORE THE PUBLIC UTILITIES COMMISSION 

OF THE STATE OF CALIFORNIA 

Application of Southern California Edison 

Company (U338E) for Authority to Establish Its 

Authorized Cost of Capital for Utility Operations 

for 2020 and to Partially Reset the Annual Cost of 

Capital Adjustment Mechanism. 

A.19-04-014

(Filed April 22, 2019) 

And Related Matters 

A.19-04-015, 

A.19-04-017, 

A.19-04-018 

(Filed April 22, 2019) 

OPENING BRIEF OF 

SAN DIEGO GAS & ELECTRIC COMPANY (U 902 M) 

I. INTRODUCTION AND SUMMARY OF RECOMMENDATIONS 

Pursuant to the September 13, 2019 email ruling of Administrative Law Judge (“ALJ”) 

Brian Stevens and Rule 13.11 of the Rules of Practice and Procedure of the California Public 

Utilities Commission (the “Commission” or “CPUC”), San Diego Gas & Electric Company 

(“SDG&E”) submits this Opening Brief in support of its Test Year (“TY”) 2020 cost of capital 

application (“Application”). 

In the Application, SDG&E requests Commission authorization of an overall rate of 

return (“ROR”) of 8.95% for TY 2020. This is based upon a proposed return on common equity 

(“ROE”) of 12.38%, a proposed cost of long-term debt of 4.59%, and a proposed capital 

structure of 44% long-term debt and 56% common equity. 

SDG&E’s Proposed TY 2020 COC Structure 

Component Capital 

Ratio Cost Weighted Cost 

Long-Term Debt 44% 4.59% 2.02% 

Preferred Stock 0% 0% 0% 

Common Equity 56.00% 12.38% 6.93% 

Rate of Return (ROR) 8.95% 

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If adopted, SDG&E’s requested adjustments will increase the Company’s current ROR 

by 1.40% (i.e., 140 basis points). In addition, SDG&E proposes to modify the existing cost of 

capital mechanism (“CCM”) to narrow the dead band trigger to 50 basis points and identifies 

additional necessary clarifications to the CCM. 

Both Supreme Court precedent and basic principles of finance specify that the greater the 

risk, the greater the return that is required to attract investment. In other words, a utility with 

above average risk requires a higher ROE than one with average or below-average risk. In the 

Commission’s 2012 cost of capital decision, with SDG&E possessing an ‘A’ credit rating from 

Standard & Poor’s (“S&P”), SDG&E’s ROE was set around the national average for that year. 

Seven years later, SDG&E no longer possesses an ‘A’ credit rating. The risks identified in that 

2012 decision have only increased. Today, SDG&E faces heightened risks associated with 

California’s aggressive policy mandates coupled with a seismic shift in the existing utility model 

due to increasing levels of load departure. 

And those increased risks have been joined by the recently exacerbated threat posed by 

California’s unique catastrophic wildfire liability regime. Three factors contribute to this 

extraordinary risk for California’s electric utilities: 

 California’s higher risk of wildfires in highly populated, property dense 

areas compared to other states; 

 Inverse condemnation, which makes California utilities strictly liable for 

any wildfire damages linked to a utility’s equipment, regardless of fault; 

and 

 A lack of assurance of wildfire cost recovery, in contrast to that other 

jurisdictions, such as the Federal Energy Regulatory Commission

(“FERC”), where cost recovery for the same wildfire events is more 

reasonably expected. 

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Although inverse condemnation has applied to California utilities for decades, 

stakeholders’ perception of the risk from the State’s wildfire liability regime was greatly 

heightened by two recent events: 

 The size and severity of the 2017-2018 fires in California; and

 The Commission’s 2017 decision denying any recovery in SDG&E’s 

Wildfire Expense Management Account (“WEMA”) application 

proceeding regarding the costs and liabilities associated with the 2007 

wildfires in Southern California, despite FERC providing for full recovery 

for those same fires. 

These recent events have led to multiple credit rating downgrades for SDG&E (at least 

two notches by each credit rating agency) – even though SDG&E has been universally lauded for 

its operational management and wildfire mitigation programs and has not been subject to any 

significant wildfire liability since 2007. Yet as credit agencies have made clear, SDG&E’s 

operational excellence is outweighed by the State’s regulatory environment. 

Assembly Bill (“AB”) 1054, signed into law in July 2019, made significant 

improvements to the wildfire liability and cost recovery regime applicable to electric utilities in 

California. Foremost among these improvements is the creation of a wildfire fund to provide a 

source of funds for utilities to pay wildfire damage claims. Utilities must, however, reimburse 

the fund if the Commission determines that the utility acted unreasonably or imprudently. 

Presently, it is unclear how the Commission will apply the revised prudence standard in Public 

Utilities Code Section 451.1. Moreover, significant uncertainty exists with respect to the 

durability of the Wildfire Fund. And the Bill does nothing to address inverse condemnation. 

Finally, although AB 1054 enhances the wildfire mitigation and prevention requirements 

applicable to utilities, with the aim of reducing catastrophic wildfires, much work remains to be 

done by electric utilities and other stakeholders (e.g., forest management agencies, property 

owners, local governments) to reduce the risk of catastrophic wildfires. 

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As a result, while credit rating agencies removed their negative outlooks for SDG&E 

following AB 1054’s passage, they did not restore the Company’s prior credit ratings. Moody’s 

instead sees four ongoing credit challenges: 

 The “[e]levated political risk and public scrutiny in California;” 

 “Regulatory uncertainty with delayed rate case and pending cost of capital 

proceeding;” 

 “Execution risk in the CPUC’s implementation of the new prudency 

standards;” and 

 “Demanding public policy goals and moderate carbon transition risk.”1

SDG&E’s application reflects those risks. SDG&E’s proposed capital structure mirrors 

the Company’s actual capital structure for the last five years, and prudently lowers financial risks 

in light of SDG&E’s increased business risk. SDG&E’s requested ROE of 12.38% is based 

upon quantitative analyses performed by Dr. Roger Morin and John Reed and Jim Coyne for 

Concentric Energy Advisors (“Reed” or “Coyne” or collectively, “Concentric”), as well as 

qualitative and policy assessments by SDG&E witnesses Bruce Folkmann and Don Widjaja.2 

The proposed ROE will assist SDG&E in regaining its long-held ‘A’ credit rating – 

lowering costs for ratepayers – and will help improve investors’ perception of California’s 

regulatory environment. Given that SDG&E was granted an around average ROE and a 52% 

equity ratio in 2012 – while the Company had an ‘A’ credit rating – SDG&E’s request for an 

above average ROE and 56% common equity ratio is eminently reasonable at present, given the 

 

1

 Moody’s Investor Services, Credit Opinion: San Diego Gas & Electric Company, Update Following 

Outlook Change to Positive (August 2, 2019) (“Moody’s Aug. 2, 2019 Report”), Exh. SDG&E-23-C 

at 2 (“Failure to successfully implement the provisions of AB 1054 associated with the insurance fund 

in a consistent and credit supportive manner would likely trigger negative momentum on the rating.”). 

2

 As discussed below, Dr. Morin estimates that his recommendation, if he updated his analysis, would 

likely slightly decline by 20 basis points because of declining interest rates to 10.7 percent; meaning 

that SDG&E’s overall ROE request would become 12.18 percent. 

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market evidence of a higher cost of equity, multiple credit rating downgrades and high risks 

identified by credit rating agencies and other stakeholders. By contrast, a decision that lowers 

the Company’s return or does not accurately reflect the business and financial risks facing the 

Company relative to allowed ROEs nationwide may put further downward pressure on 

SDG&E’s credit rating and reinforce the perception that investing in a California utility is riskier 

than investing in utilities in other states. 

II. LEGAL STANDARDS AND POLICY CONSIDERATIONS 

As a public utility, SDG&E is an investor-owned, private corporation whose assets are 

employed to provide consumers with products – electric and gas services – that are deemed to be 

in the public interest.3 Public utility regulation is a substitute for competition. The goal is to 

replicate the results that a competitive market would achieve for setting reasonable prices and 

profits.4

 As the Commission has held, unlike a non-utility company – whose earnings depend on 

the ability to competitively price its products or services – a utility depends upon a fair return on 

investment because a utility’s prices are set by regulators irrespective of what a buyer is willing 

to pay.5

 

In permitting the setting of utility rates, the United States Supreme Court has long 

recognized that the unique status of privately-owned, public utilities entails a balancing of 

consumers and investors’ constitutional interests and necessitates the setting of a rate that 

 

3 See Cal. Const. Art. 12, Section (“§”) 5; Cal. Pub. Util. Code § 216(b). 

4 See Permian Basin Area Rate Cases, 390 U.S. 747, 768 (1968) (“Permian Basin Area Rate Cases”) 

(“the Constitution does not forbid the imposition, in appropriate circumstances, of maximum prices 

upon commercial and other activities.”). 

5

 Decision (“D.”) 07-12-049 at 14-15. 

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ensures the utility a “reasonable rate of return.”6

 That is, to provide electricity and natural gas to 

customers, a combined electric and gas utility needs to invest in infrastructure, such as 

substations, transformers, meters, power lines and pipelines. 

To invest in these ‘rate base assets,’ a utility raises funds by either issuing debt or selling 

equity.7 Both methods have costs. The company pays interest to debt creditors on borrowed 

funds. Or it pays a portion of its profits or dividends to equity investors, i.e., shareholders. 

These costs are known as the cost of capital. 

The Supreme Court has established constitutional requirements under the Fifth and 

Fourteenth Amendments for setting a fair rate of return to meet these costs of capital in the 

Bluefield, Hope, and Duquesne decisions.8 The Bluefield Court held that the rate of return must 

be “equal to that generally being made at the same time and in the same general part of the 

country on investments in other business undertakings which are attended by corresponding risks 

and uncertainties.”9

 The Bluefield Court further specified that the return should be “reasonably 

sufficient to assure confidence in the financial soundness of the utility, and should be adequate, 

under efficient and economical management, to maintain and support its credit, and enable it to 

raise the money necessary for the proper discharge of its public duties.”10

Hope reinforces the risk assessment, financial soundness, and capital attraction principles

of the Bluefield decision: 

From the investor or company point of view it is important that there be 

enough revenue not only for operating expenses but also for the capital 

 

6 Duquesne Light Co. v. Barasch, 488 U.S. 299, 307-312 (1989) (“Duquesne”). 

7 Id. 

8 See D.18-03-035 at 23-24, Finding of Fact (“FOF”) 3. 

9 Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm’n, 262 U.S. 679, 692 (1923). 

10 Id. at 693. 

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costs of the business. These include service on the debt and dividends on 

the stock . . . . By that standard the return to the equity owner should be 

commensurate with returns on investments in other enterprises having 

corresponding risks. That return, moreover, should be sufficient to assure 

confidence in the financial integrity of the enterprise, so as to maintain its 

credit and attract capital.11

And Duquesne reaffirms that a utility cannot be limited to a charge for the use of its property that 

is so low that it is considered “confiscatory” and an unconstitutional taking.12 

Accordingly, the Commission must exercise its judgment, in light of the evidence 

contained in the record of this proceeding, to meet the standard articulated by the United States 

Supreme Court and authorize a rate of return that is: 

 Sufficient to enable SDG&E to maintain its financial integrity; 

 Sufficient to maintain SDG&E’s creditworthiness; 

 Sufficient to allow SDG&E to attract new capital in the financial markets 

on reasonable terms; and 

 Commensurate with the risks facing SDG&E.13

The determination of what ROE is necessary to attract investment is determined by 

investor expectations.14 Although an energy utility is the exclusive service provider for 

 

11 Federal Power Com. v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944) (emphasis added) (citations 

omitted). 

12 See Duquesne at 307 (“The guiding principle has been that the Constitution protects utilities from 

being limited to a charge for their property serving the public which is so ‘unjust’ as to be 

confiscatory.”) (citing Covington & Lexington Turnpike Road Co. v. Sandford, 164 U.S. 578, 597 

(1896)); see also Permian Basin Area Rate Cases at 769 (“the power to regulate is not a power to 

destroy.”) (citations omitted). 

13 See D.12-12-034 at 18 (“We attempt to set the ROE at a level commensurate with market returns on 

investments having corresponding risks, and adequate to enable a utility to attract investors to finance 

the replacement and expansion of a utility’s facilities to fulfill its public utility service obligation.”); 

accord D.18-03-035 at 6-7; see generally Permian Basin Rate Cases, 488 U.S. at 782 (rate of return 

should “fully compensate investors for the risks they have assumed.”). 

14 California Public Advocates’ Office (“PAO”)/Rothschild Tr. V.4:637:11-16; Morin/SDG&E Exh. 

SDG&E-09 at 22 (“stock prices are based on investor expectations.”) (citation omitted). 

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transmission and distribution, it must raise capital in a competitive marketplace.15 The goal is to 

encourage private investors to invest private funds into capital projects that benefit the public.16 

“[I]nvestors price securities on the basis of long-term expectations.”17 “Common stocks 

are very long-term instruments more akin to long-term bonds than to one-year notes.”18 Under

the “most basic financial theory . . . the higher the risk, the higher the expected return.”19 “Risk 

and uncertainty are the same thing.”20 Uncertainty and/or risk require a higher return to entice 

investors to forego other investments or to use their capital in other ways.21 

The Commission has long sought to support strong, investment grade credit ratings – 

both to ensure the financial soundness of the utility and to lower costs to ratepayers.22 As Dr. 

Morin emphasized: 

[w]e got to do everything we can to get [SDG&E] back to a single A bond 

rating because it’s costing ratepayers an extra 10 million bucks for every 

 

15 See Morin/SDG&E Exh. SDG&E-04 at 10. 

16 D.12-12-034 at 29 (“Our goal . . . continues to be, to provide reasonable confidence in the utilities’ 

financial soundness, to maintain and support investment-grade credit ratings, and provide utilities the 

ability to raise money necessary for the proper discharge of their public duty.”). 

17 Morin/SDG&E Exh. SDG&E-04 at 33. 

18 Morin/SDG&E Exh. SDG&E-09 at 21; see also Stern/SCE Tr. V.1:108:24 – 109:1 (“The issue 

ultimately, though, is the outlook of investors in the utility, and the time frame that the investors may 

be considering the risks of the utility may go beyond the immediate period of the ROE assessment.”). 

19 Morin/SDG&E Exh. SDG&E-04 at 38; Morin/SDG&E Exh. SDG&E-09 at 30. 

20 Coyne/Reed/SDG&E Tr. V.4:724:26-27; accord Folkmann/SDG&E Exh. SDG&E-07 at 8. 

21 Morin/SDG&E Tr. V.2:231:18-20 (“In finance we call this the opportunity cost, the foregone 

return.”). See also Concentric/SDG&E Exh. SDG&E-12, Ch. 1 at 20-21 (“The cost [of equity] is an 

opportunity cost, as measured against other investments of comparable risk.”); Hern/IEI Tr. 

V.4:585:4-10 (same). 

22 D.12-12-034 at 8-9 (credit rating downgrades “result[] in increased financial risks for common equity 

holders, thereby requiring greater returns on common equity”); see also id. at 31 (noting that “A 

ratings are considered by S&P to be upper medium investment grade level and BBB to be medium 

investment grade level.”); D.03-12-035 at 42 (“the cost of investment grade debt is considerably less . 

. . the lower cost of a utility’s debt translates into lower rates, all else being equal.”). 

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hundred million dollars of capital raised. And these utilities, they are 

going to be rais[ing] [] billions of dollars.23

By contrast, if ROE is set below the level required by investors, it becomes difficult for a 

company to access capital. This forces a utility to rely more on debt financing, making the

company more financially leveraged and reducing the company’s credit rating, increasing costs 

for ratepayers.24 

III. RETURN ON EQUITY 

To arrive at a “fair ROE,” the Commission has “consistently evaluated analytical 

financial models as a starting point.”25 The Commission then considers “additional risk factors 

not specifically included in the financial models,” principally “financial, business, and 

regulatory” risks.26 In “the final analysis,” however, it is “the application of informed judgment, 

not the precision of financial models, which is the key to selecting a specific ROE estimate.”27

SDG&E’s proposed 12.38% ROE reflects SDG&E’s high levels of risk compared to peer 

utilities outside of California.

28 Since the Commission’s 2012’s Cost of Capital decision, the 

risks cited in that decision have only increased. And they have been joined by the newly 

recognized significant threat from California’s wildfire liability regime. This has resulted in 

SDG&E suffering multiple (at least two notches each by S&P, Moody’s, and Fitch) credit rating 

 

23 Morin/SDG&E Tr. V.2:249:16-22; accord Morin/SDG&E Exh. SDG&E-04 at 62 (“single A bond 

rating generally results in the lowest pre-tax cost of capital for regulated utilities, and therefore the 

lowest ratepayer burden.”). 

24 Morin/SDG&E Exh. SDG&E-04 at 5-7. 

25 D.12-12-034 at 18. 

26 Id. 28. 

27 Id.

28 See Morin/SDG&E Exh. SDG&E-09 at 4 (“SDG&E is among the riskiest, if not the riskiest, electric 

utility in the industry at this time.”). 

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downgrades in the last 18 months from its former ‘A’ rating – despite SDG&E not being 

responsible for any significant wildfire liability in 2017 and 2018 and being widely recognized 

for having a premier wildfire mitigation program. 

A. California Electric Utilities Face Heightened Risks 

As noted, the Commission has long assessed business, financial, and regulatory risks in 

setting ROE.29 This is analogous to the considerations that credit rating agencies make in 

analyzing a company’s credit worthiness. There are three primary credit rating agencies that 

assess SDG&E – Fitch, Moody’s, and S&P. Credit rating agencies “represent an independent, 

third-party opinion that is based on a consistent approach to assessing risk across time, security 

types, industries, and other considerations that inform investment decisions.”30 Although credit 

rating agency opinions are primarily aimed at long-term debt holders, “[e]quity investors, i.e.,

stockholders, also use credit ratings as a risk guide to help them decide the terms on which they 

will offer their capital to a utility.”31 As Michael Gorman described in testimony on behalf of the 

Energy Producers and Users Coalition (“EPUC”), Indicated Shippers (“IS”), and The Utility 

Reform Network (“TURN”), “[o]ne of the most direct pieces of information available to the 

equity market are the credit analysts’ assessment of the credit standing of the utilities.”32 The 

 

29 See D.12-12-034 at 28. 

30 Concentric/SDG&E Exh. SDGE&-05, Ch. 2 at 6; accord Concentric/SDG&E Exh. SDG&E-12, Ch. 

2, at 2 (“credit ratings are an independent and reliable measure of a company’s risk that are used by 

investors and other interested parties to assist in assessing risk.”). 

31 Concentric/SDG&E Exh. SDG&E-05 at 10. 

32 Gorman/EPUC/IS/TURN Tr. V.3:458:13-16. 

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Commission has also repeatedly looked to the opinion of credit rating agencies in assessing 

risk.33 

Credit rating agencies primarily assess “business” and “financial” risks, which add up to 

the total credit risk assessment. Financial risk is essentially a quantitative examination of

financial ratios and other metrics.34 Business risks are largely qualitative in nature.35 “Evaluating 

business risk for utilities is overwhelmingly a matter of regulatory risk.”36 For Moody’s, 

regulatory risk constitutes over 80% of the business risk component of the analysis and 50% of 

its entire credit analysis.37 For S&P, it is 60% of the business risk analysis and approximately 

40% of its total credit analysis.38 

Regulatory risk is not simply an assessment of the likelihood of a particular cost 

allowance or disallowance. Instead, credit rating agencies and other investors make a big picture 

assessment of regulatory risk.39 Risk itself financially impacts shareholders, because, as risks 

increase, share prices often decrease.40 

 

33 See, e.g., D.12-12-034 at 30; see also Conclusion of Law (“COL”) 14 (“Company-wide factors such 

as risks, capital structures, debt costs and credit ratings are considered in arriving at a fair ROE.”). 

34 Concentric/SDG&E Exh. SDG&E-05, Ch. 2 at 7. 

35 Id. 

36 Id. at 9; see also Morin/SDG&E Tr. V.2:218:19-21 (“A huge component of business risk, of course, 

is regulatory risk.”). 

37 Concentric/SDG&E Exh. SDG&E-05, Ch. 2 at 10. 

38 Id. 

39 See Morin/SDG&E Tr. V.2:314:20-27. 

40 See Stern/SCE Tr. V.2:173:20-24. 

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1. California’s Wildfire Liability Regime Presents California Utilities 

with Unique Risks 

a. The combination of increased wildfire damages, inverse 

condemnation, and uncertainty and perceived lack of ability 

for cost recovery led to credit rating downgrades and an 

increased cost of capital 

As Moody’s recently described, SDG&E and other California electric utilities face 

unique threats to their ongoing viability from wildfires and wildfire liability that is not shared by

any other utility outside of the state.41 This exclusive threat results from a combination of three 

factors that do not apply to utilities outside of California: 

 California’s higher propensity for fires in highly populated and propertydense areas; 

 The application of inverse condemnation, which makes a utility strictly 

liable for property damages arising from the fire when a utility’s 

equipment is linked to a wildfire, regardless of fault; and 

 The uncertainty and perceived inability of utilities to recover wildfire costs 

in situations where stakeholders believe that other jurisdictions, such as 

FERC, would allow recovery on the same utility behavior.42

Each is discussed in turn.

Wildfire Frequency and Magnitude: Wildfires have grown larger and more damaging 

in California for multiple reasons, including climate change and population growth in fire prone 

 

41 See S&P Global Ratings, Ratings Direct, Research Update: San Diego Gas & Electric Co. 

Downgrade to ‘BBB+,’ Outlook Remains Negative (Jan. 21, 2019) (“S&P Report Jan. 21, 2019”), 

Exh. PAO-03-C at 1 (noting that California faces “unique risks” from inverse condemnation and the 

inability to directly recover those costs). 

42 Moody’s Investors Service, FAQ on the Credit Implications of California’s New Wildfire Law (Aug. 

6, 2019) (“Moody’s Aug. 6, 2019 Report”), Exh. SDG&E-24-C; accord Coyne/Reed/SDG&E Tr. 

V.4:751 (describing how all three factors contribute to the risk); see generally Folkmann/SDG&E 

Exh. SDG&E-07 (describing Moody’s Aug. 6 analysis). 

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areas.43 The ten costliest wildfires in the United States have all occurred in California.44 The top 

five of those wildfires occurred in 2017 and 2018.45 As Dr. Richard McCann notes for the 

Environmental Defense Fund (“EDF”), “[e]ven if [California] had a low fire risk it would have

the highest number of properties and risk.”46 Credit rating agencies and others believe that the 

combination of climate change and population growth mean that the risk of wildfires in 

California will only continue to increase.47 

 

43 Moody’s Aug. 6, 2019 Report, Exh. SDG&E-24-C at 2; see also S&P Global Ratings, Credit FAQ: 

Will California Still Have an Investment-Grade Investor-Owned Electric Utility? (February 19, 2019) 

(“S&P Feb. 19, 2019 Report”), Exh. SCE-16 at 8 (noting that, although the topography is different 

throughout the state and that management of wildfires by a utility can mitigate some of the risks, 

“given the increasing effects of climate change, S&P Global Ratings assumes that all of California’s 

regulated electric utilities are susceptible to catastrophic wildfire-related risks.”). 

44 Insurance Information Institute, Facts + Statistics: Wildfires, Exh. SCE-14 at 3. 

45 Id. 

46 McCann/EDF Tr. V.6:1021:25-26; see also id. at 1021:21 – 1022:4 (noting that California has ten 

times the number of properties at risk for wildfire damages compared to Oregon). 

47 See Moody’s Aug. 6, 2019 Report, Exh. SDG&E-24-C at 1 (“Wildfires have grown larger and more 

damaging in California for various reasons, including climate change and population growth in fireprone areas.”). 

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Table 1: Comparison of Wildfire Size and Property Values Exposed to Wildfires48

Inverse Condemnation: As Moody’s describes, “under California’s inverse 

condemnation law, utilities are held liable for wildfire damages [that can reach tens of billions of 

dollars] if their equipment is found to be the source of ignition . . . regardless of fault or the 

reasonableness of their conduct.”49 As S&P notes, this shifts the burden for wildfire damages 

from insurance onto California’s electric utilities and their ratepayers, “effectively mak[ing] 

California’s utilities the insurer of last resort every time there is a devastating wildfire in their 

service territory.”50 Yet as S&P adds, an “electric utility is [not] large enough, sufficiently 

diversified, or adequately capitalized to be a reinsurer.”51 

 

48 Widjaja/SDG&E Exh. SDG&E-03 at 10. 

49 Moody’s Aug. 6, 2019 Report, Exh. SDG&E-24-C at 2; See Kevin O’Donnell/Federal Executive 

Agencies (“FEA”) Tr. V.3:360:11-17 (not aware of inverse condemnation applying in any other 

state); Gorman/EPUC-IS-TURN Tr. V.3:393:10-13 (same). 

50 S&P Jan. 21, 2019 Report, Exh. PAO-03-C at 3. 

51 S&P Feb. 19, 2019 Report, Exh. SCE-16 at 5.

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The upshot is that strict liability means that SDG&E and other California electric utilities 

will be implicated in more wildfires and be responsible for far more damages than a comparable 

utility would be outside of California under a negligence standard where a plaintiff has to prove 

that damages were linked to the utility’s negligent conduct.52 In other words, the likelihood that 

a California utility will face enormous wildfire liabilities will be much higher given the strict 

liability standard, meaning that the number of times that a utility has to seek cost recovery in 

highly publicized proceedings for a larger amount of damages is increased.53 

Wildfire Cost Recovery: Although inverse condemnation has applied to California 

public utilities since at least 1999, it was long presumed that the utility could socialize those 

wildfire costs across all ratepayers.54 But in the Commission’s “first-ever wildfire cost recovery 

proceeding in 2017,” the Commission, in SDG&E’s WEMA case, “denied SDG&E’s request to 

recoup wildfire costs that it had incurred in 2007” – even though FERC allowed SDG&E full 

recovery on FERC-jurisdictional portion of the costs arising out of the same fires.55 

As SDG&E chief financial officer Mr. Folkmann testified, prior to the WEMA decision, 

based on Commission precedent, the Company expected that 90 percent of the costs associated 

 

52 Reed/Coyne/SDG&E Tr. V.4:765:18-19 (“liabilities faced by the utility are greater because of inverse 

condemnation.”). 

53 See Folkmann/SDG&E Tr. V.5:794. 

54 See Barnham v. S. Cal. Edison Co., 74 Cal. App. 4th 744, 752 (1999) (“[t]he fundamental policy 

underlying the concept of inverse condemnation is to spread among the benefitting community any 

burden disproportionately borne by a member of that community, to establish a public undertaking for 

the benefit of all.”) (citation omitted); see also Moody’s Aug. 6, 2019 Report, Exh. SDG&E-24-C, at 

2 (“In theory, California utilities can pass on their wildfire costs to ratepayers if the [Commission] 

determines that the utilities had behaved prudently.”); Hern/IEI, Tr. V.4:619 (stating that market data 

demonstrated that the markets expected SDG&E to be found prudent in the Company’s 2017 Wildfire 

Expense Memorandum Account (“WEMA”) decision and be able to spread costs among ratepayers). 

55 Moody’s Aug. 6, 2019 Report, Exh. SDG&E-24-C at 2; see Stern/SCE Tr. V.1:96:24-27 (“the 

fundamental question of [SDG&E’s] prudence was evaluated in both cases. And different results 

were found.”).

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with the 2007 wildfires would be recovered. SDG&E accounted for those expectations 

accordingly.56 So the Commission’s decision to deny any recovery – after FERC allowed 

recovery – “raised doubts and, in the minds of some, contradicted what was expected.”57 As 

Moody’s states, the WEMA decision threw “into doubt the ability of utilities in the state to 

recover wildfire costs and raised questions about how incurring such costs would affect” a 

California utility’s financial stability.58 

The belief that California would make it more difficult, if not impossible, to recover 

wildfire costs was partly based on at least three significant differences in the prudence review 

standard applied by FERC compared to the standard applied by the CPUC in WEMA (prior to 

AB 1054’s revisions): 

Table 2: FERC v. CPUC Prudency Review Standards 

Issue FERC CPUC 

Burden of Proof Presumes that the utility was 

prudent unless a party raises a 

serious doubt.59

Maintains the burden of proof on a 

utility to demonstrate that it was 

prudent.60 

Standard for 

Prudence 

FERC’s prudence standard 

“‘permits considerable latitude, in 

that the Commission, in reviewing 

a decision . . . does not look for a 

Requires that a utility prove that it 

“exercise[ed] the best practices of the 

era.”62

 

56 Folkmann/SDG&E Tr. V.5:810:7-13. 

57 Id. at 810:24-26. 

58 Moody’s Aug. 6, 2019 Report, Exh. SDG&E-24-C at 2; Folkmann/SDG&E Tr. V.5:810 (The 

Commission’s decision to deny SDG&E recovery of wildfire costs). 

59 San Diego Gas & Electric Co., 146 FERC ¶ 63,017, P 57 (2014) (“The Commission’s presumption of 

prudence is not easily refuted.”); accord Entergy Services, Inc. (“Entergy Services”), 130 FERC ¶ 

61,023, P 52 (2010) (“[t]he utility does not have the burden of demonstrating that expenditures are 

prudent. Rather a challenger to prudence must create a ‘serious doubt’ as to the prudence of an 

expenditure.”). 

60 D.17-11-033 at 6 and COL 1 (“For costs to be found reasonable, the utility must prove that they were 

prudently incurred.”). 

62 D.17-11-033 at COL 1. 

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single correct result or require that 

every possible alternative be 

evaluated.’”61

Consideration of 

Inverse 

Condemnation 

Specified that, even if SDG&E’s 

presumption of prudence was not 

dispositive, the recovery of 

SDG&E’s wildfire costs was valid 

because SDG&E would likely be 

held responsible for such costs 

under inverse condemnation 

regardless of fault.63

Explicitly held that inverse 

condemnation was “not relevant to a 

Commission reasonableness review 

under the prudent manager standard” 

and that even if SDG&E were strictly 

liable there is nothing that would 

supersede the Commission’s 

jurisdiction over cost recovery.64

Equally important was investors’ uncertainty regarding the application of the prudence 

review – that California would not allow the recovery of wildfire costs on the same set of facts 

where other jurisdiction such as FERC would – regardless of the legal standard being applied.65 

Again, the cost of equity is determined by investor expectations or uncertain results, regardless 

of whether those expectations are consistent with the actual results that ultimately transpire. And 

the surprising nature of the WEMA decision led the market to believe that California would 

 

61 SDG&E, 146 FERC ¶ 63,017, P 56 (quoting Entergy Services, 130 FERC ¶ 61,023, P 51). 

63 SDG&E, 146 FERC ¶ 63,017, P 60. 

64 D.17-11-033 at 65. 

65 See S&P Feb. 19, 2019 Report, Exh. SCE-16 at 5 (“In our view, California’s regulatory process to 

recover these material wildfire costs is still unpredictable, relatively untested, and lacks transparency 

and [contains] uncertain[t]y regarding the timeliness of cost recovery.”); see also 

Coyne/Reed/SDG&E Tr. V.4:748:18-22 (“did you refer to a finding that the company failed to 

operate according to the standard? Or a finding that the Commission determined so? Because that 

really is the issue.”); Stern/SCE Tr. V.2179:20-25 (“From an investor’s perspective, that is an 

increased risk that isn’t necessarily associated with mismanagement. It’s associated with a different 

standard being applied for determining what is prudent and what is not.”). 

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make it more difficult, if not impossible, to recover wildfire costs – the difference between being 

prudent and being found prudent.66 

In short, the WEMA decision, combined with the size and frequency of the 2017-2018 

wildfires, “amplified in investors’ minds the risk that this loss [from wildfires] could be very 

large and could be entirely thrust on shareholders.”67 As noted, it underscored to stakeholders 

that California utilities face the unique combination of: (1) a high level of risk for destructive 

wildfires; (2) the frequency and size of damages that will result from strict liability compared to 

negligence; and (3) the uncertainty and perceived inability to recover wildfire costs compared to 

other jurisdictions.68

It was this regulatory environment that led credit rating agencies to repeatedly downgrade 

SDG&E’s credit rating (at least two notches by each rating agency) beginning in July 2018.69 

SDG&E had maintained an ‘A’ credit rating from S&P for 15 years.

70 The Company was not 

subject to any substantial wildfire liability for 2017 or 2018.71 Credit rating agencies lauded 

SDG&E’s business operations: 

 

66 See Folkmann/SDG&E Tr. V.5:826:18-20 (“the facts in the State of California so far have found zero 

recovery in the case of wildfires”); Hern/IEI, Tr. V.4:619:14-20 (noting that the data demonstrates that 

the market did not expect SDG&E to be denied any cost recovery and reacted “very negatively.”). 

67 Folkmann/SDG&E Tr. V.5:811:3-5; accord S&P Feb. 19, 2019 Report, Exh. SCE-16 at 7; See 

Hern/IEI Tr. V.4:587 (financial markets’ perception of the risk associated with inverse condemnation 

increased in 2017, driven in large part by the 2017 WEMA decision). 

68 Reed/Coyne/SDG&E Tr. V.4:751; see also S&P Report Jan. 21, 2019, Exh. PAO-03-C at 1 (noting 

that California faces “unique risks” from inverse condemnation and the inability to directly recover 

those costs). 

69 Widjaja/SDG&E Exh. SDG&E-03 at 12, Table 1 (detailing credit rating downgrades). 

70 Id. at 12. 

71 S&P Feb. 19, 2019 Report, Exh. SCE-16 at 8 (“SDG&E has not been financially responsible for a 

major devastating wildfire over the past decade.”). 

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 “We assess SDG&E’s operations as better than peers;”72

 SDG&E’s “operational management of wildfire mitigation [i]s 

exceptional;”73

 The Company has a “track record of effective wildfire mitigation;”74 and 

 SDG&E has “one of the most sophisticated advanced wildfire warning 

systems in the world.”75 

Yet credit rating agencies have found that SDG&E’s business operations are outweighed 

by the overall regulatory environment. For example, on January 21, 2019, S&P downgraded 

SDG&E’s overall credit rating to BBB+. In so doing, the rating agency also downgraded 

SDG&E’s business risk profile from ‘excellent’ to ‘strong.’76 S&P stated that, despite the 

Company’s “operational excellence” and “exceptional” management of wildfire mitigation, the 

rating agency was downgrading SDG&E’s business risk profile because it believed that inverse 

condemnation, combined with “insufficient regulatory protections to deal with the unique risks 

of inverse condemnation,” such as not providing a utility a “direct means to collect the wildfire 

costs from its ratepayers,” was “inconsistent with an excellent business risk profile 

assessment.”77 

 

72 See S&P Global Ratings, San Diego Gas & Electric Co. Ratings Affirmed, Outlook Revised to Stable 

from Negative (July 30, 2019) (“S&P July 30, 2019 Report”), Exh. SDG&E-22-C at 2. 

73 S&P Report Jan. 21, 2019, Exh. PAO-03-C at 2; accord Moody’s Aug. 2, 2019 Report, Exh. 

SDG&E-23-C at 1 (noting “SDG&E’s track record of effective wildfire mitigation”); S&P Feb. 19, 

2019 Report, Exh. SCE-16 at 8 (“In our view, SDG&E has one of the most sophisticated advanced 

wildfire warning systems in the world.”). 

74 Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 1. 

75 S&P Feb. 19, 2019 Report, Exh. SCE-16 at 8. 

76 S&P Jan. 21, 2019 Report, Exh. PAO-03-C at 2. 

77 Id. at 2-3. 

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As Dr. Morin notes, it is a rare and unusual event when a utility’s business risk profile is 

downgraded from “excellent.”78 The fact that such a change occurred here through no fault of

SDG&E demonstrates that this increased cost of capital is a result of the overall regulatory 

environment and not specific wildfire events.79 These credit rating downgrades “directly 

translate into higher cost of debt and higher cost of equity as a result of the increased perception 

of default and other risks.”80 The perception of the regulatory environment is also reflected in 

other market data, such as insurance premiums, where the market is being set more by regulatory 

risk and less by distinctions such as the strength of SDG&E’s wildfire mitigation program.81

b. AB 1054 improves but does not fully mitigate the risks of 

California’s unique wildfire liability and cost recovery regime

In response to this deteriorating situation,82 AB 1054 was passed as an urgency bill and 

signed into law by Governor Newsom on July 12, making the legislation effective immediately.83 

AB 1054 principally addresses the issue of cost recovery; primarily through creating a wildfire 

fund and revising the prudency standard to be applied to a utility that possesses a valid safety 

certification.84 The wildfire fund is expected to be capitalized with up to $21 million in funds; 

$10.5 billion from a loan from California’s Surplus Money Investment Fund, and $10.5 billion 

 

78 Morin/SDG&E Tr. V.2:200 – 201. 

79 See S&P Feb. 19, 2019 Report, Exh. SCE-16 at 8-9 (praising SDG&E’s wildfire mitigation programs 

but nonetheless noting that the rating agency downgraded the Company two notches because they 

“believe that all California electric utilities are susceptible to potential liabilities from wildfires 

because of environmental changes and high winds that could spread the fire at a rate that outpaces the 

capabilities of the first responders.”). 

80 Hern/IEI Tr. V.4:600:5-8. 

81 Coyne/Reed/SDG&E Tr. V.4:719. 

82 See S&P Feb. 19, 2019 Report, Exh. SCE-16 at 7.

83 See generally Folkmann/SDG&E Exh. SDG&E-01-S at 2-4 (discussing the mechanics of AB 1054). 

84 Id. at 2. 

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from shareholder contributions from SDG&E, Southern California Edison Company (“SCE”), 

and Pacific Gas & Electric Company (“PG&E”).85 AB 1054 seeks to extend the wildfire fund’s 

longevity by incentivizing the settlement of wildfire subrogation claims at or below 40 percent of 

the claimed value.86

A participating utility may seek payments from the wildfire fund for settlements and 

court judgments resulting from a catastrophic wildfire event.87 But the utility must reimburse the 

fund for amounts determined to be imprudently incurred by the Commission under the revised 

prudence standards in Public Utilities Code Section 451.1.88 The utility’s reimbursements to the 

wildfire fund for imprudently incurred costs are subject to a liability cap. This cap applies only 

if the utility meets certain requirements, including that it maintains a valid safety certificate.89 If 

applicable, the liability cap limits the amount of shareholder exposure for wildfire losses found 

to be imprudently incurred to 20% of the utility’s transmission and distribution equity rate base 

 

85 See Cal. Pub. Util. Code §§ 3288(b) and 3292(b). 

86 Cal. Pub. Util. Code § 3292(f)(1); see Folkmann/SDG&E Exh. SDG&E-01-S at Appendix E, 

Moody’s Investors Service, Rating Action: Moody’s affirms San Diego Gas & Electric’s Ratings; 

Changes Outlook to Positive from Negative (“Moody’s July 29, 2019 Report”) at 1 (“Even though the 

fund is capitalized with $21 billion of capital . . . it should be able to address over $40 billion of gross 

claims . . . because utilities are expected to maintain $1 billion of wildfire liability insurance each and 

the fund is designed to only pay subrogation claims that are settled at 40 cents on the dollar or less.”); 

see generally id. at 4 (discussing this provision). 

87 Cal. Pub. Util. Code § 3291(c). 

88 Id. at § 3292. 

89 Id. at § 3292(h)(3)(B). 

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for that year on a rolling three-year basis.90 For SDG&E, this liability cap is estimated to be 

$825 million based on 2018 rate base.91 

AB 1054 amends Section 451.1 of the California Public Utilities Code to provide revised 

standards for the Commission’s prudency review so that it more closely tracks the FERC review 

process above. Among other changes, Section 451.1 provides that the conduct of a utility with a 

valid safety certification will be deemed reasonable, unless a serious doubt is raised, in which 

case the utility must dispel that doubt.92 It also specifies that reasonable conduct “encompasses a 

spectrum of possible practices, methods, or acts consistent with utility system needs, the interest 

of the ratepayers, and the requirements of government agencies.”93

As Mr. Folkmann testified, “SDG&E’s position is that AB 1054 is a significant step in 

the right direction.”94 Credit rating agencies have had similar positive assessments.

 Fitch: the “enactment of A.B. 1054 mitigates the regulatory risks 

associated with the recovery of catastrophic wildfire liabilities for 

SDG&E;95 

 Moody’s: “we believe the [wildfire] insurance fund will be large enough 

to cover all but the most extreme downside scenarios over the next 

decade,” and “[p]ositive momentum on SDG&E’s rating is possible, 

barring any wildfire in its service territory” if there is a credit supportive 

 

90 See generally id. 

91 See Sempra Energy and SDG&E Securities and Exchange Commission Form 8-K (filed July 12, 

2019) (“July 12 Form 8-K”), available at http://investor.sempra.com/static-files/50cfab94-4107-4fc2-

ba72-425238a8656c. 

92 Cal. Pub. Util. Code § 451.1(c). 

93 Id. at § 451.1(b). 

94 Folkmann/SDG&E Tr. V.5:793:20-21. 

95 Fitch Ratings, Fitch Affirms San Diego Gas & Electric’s IDR at ‘BBB+’; Outlook Revised to Stable 

(July 17, 2019) (“Fitch July 17 Report”) at 3; see also S&P Global Ratings, Sempra Energy and 

Subsidiaries Ratings Affirmed; Outlooks Remain Negative (July 15, 2019) (“S&P July 15, 2019 

Report”) at 1 (“In our view, over the medium term, AB 1054 could significantly reduce Sempra and 

its subsidiaries credit risks related to California’s wildfires and California courts’ interpretation of the 

legal doctrine of inverse condemnation.”). 

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completion of SDG&E’s “pending 2019 general rate case and the cost of 

capital proceeding;”96

 S&P: “We believe that the credit-supportive liability cap and the revised 

standards of a utility’s reasonable conduct will offset the rising risks of 

[SDG&E’s] increased susceptibility to catastrophic wildfires due to 

climate change and California’s courts’ interpretation of inverse 

condemnation over the medium term.”97

Yet although AB 1054 mitigates the risk that a utility will bear enormous wildfire 

liabilities with no ability to recover them in rates, it does not eliminate that risk.98 This is 

reflected in the fact that, although credit rating agencies removed their negative outlook on 

SDG&E, none of the credit rating agencies increased the Company’s already-downgraded ratings 

to SDG&E’s previous ‘A’ credit status. 

TABLE 3: SDG&E Credit Rating Status Post-AB 1054 

Agency Rating Outlook Revision to Credit Rating 

Moody’s Baa1 Positive None 

S&P BBB+ Stable None 

Fitch BBB+ Stable None 

As Mr. Gorman acknowledged, SDG&E’s credit rating is “still rated lower today than it 

was in 2017.”99 The Public Advocates Office (“PAO”) has similarly noted the cautious reaction 

of credit rating agencies in a contemporaneous Commission proceeding: 

[T]he reactions of the credit rating agencies to AB 1054 do not support the 

. . . assumption that the [Wildfire] Fund will reduce costs to ratepayers by 

dint of a lower cost of capital. For example, S&P did not change its 

ratings for either Southern California Edison Company (SCE) or San 

Diego Gas & Electric Company in response to AB 1054 and the 

commitment of both companies to participate in the Fund. In both ratings 

 

96 Moody’s July 29, 2019 Report at 1-2. 

97 S&P July 30, 2019 Report, Exh. SDG&E-22-C at 2. 

98 See Folkmann/SDG&E Exh. SDG&E-01-S at 1. 

99 Gorman/EPUC/IS/TURN Tr. V.3:401:24-25. 

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affirmations, S&P warned of potential reasons to downgrade the utility 

within the next 18 months.100

For example, although Moody’s views AB 1054 as “very credit positive,” 101 it does not 

believe that AB 1054 is a “comprehensive solution for utility wildfire risks.”102 The muted 

response of credit rating agencies is for two primary reasons. First, Moody’s and other credit 

rating agencies do not view AB 1054 as a complete solution because it did not address two 

significant aspects of the unique wildfire risk threating California wildfire liabilities – the 

frequency and magnitude of wildfires in California and the application of inverse condemnation 

to investor owned utilities that cannot automatically spread the costs through rates.103 

As Fitch states, “[t]he continuation of inverse condemnation remains a long-term credit 

issue for SDG&E as an electric utility in California.”104 RRA, a group within S&P that 

periodically evaluates the regulatory climate for energy utilities throughout the country, similarly 

stated that, despite some of the “more constructive aspects of the California regulatory 

framework,” it was downgrading its rating of California’s regulatory climate from Average/1 to 

Average/2 a month after AB 1054’s passage, because – in RRA’s view – the combination of 

 

100 Rulemaking (“R.”) 19-07-017, Opening Comments of the Public Advocates Office (August 29, 

2019), Exh. SDG&E-27 at 16-17 (citation omitted). 

101 See Moody’s Aug. 6, 2019 Report, Exh. SDG&E-24-C at 2. 

102 Id.; accord S&P Global Market Intelligence, Regulatory Research Associates (“RRA”), State 

Regulatory Evaluations (Aug. 15, 2019) (“RRA Aug. 15, 2019 Report”), Exh. SDG&E-20-C at 3 

(downgrading California’s regulatory environment rating based, in part, on RRA’s view that a “more 

comprehensive approach” than AB 1054 is needed for California’s wildfire liability risk). 

103 See Moody’s Aug. 6, 2019 Report, Exh. SDG&E-24-C at 2 (“AB 1054 does not reform the state’s 

inverse condemnation law.”); S&P July 30, 2019 Report, Exh. SDG&E-22-C at 2 (noting that AB 

1054’s provisions need to offset “the rising risks of [SDG&E’s] increased susceptibility to 

catastrophic wildfires due to climate change and California’s courts’ interpretation of inverse 

condemnation.”). 

104 Folkmann/SDG&E Exh. SDG&E-01-S at Appendix C. 

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inverse condemnation and increased severe weather events “argues for a more comprehensive 

approach,”105 than AB 1054 provides. 

Second, the extent to which AB 1054 successfully reformed SDG&E’s ability to obtain 

cost recovery is also uncertain and untested. As Moody’s states, a “[f]ailure to successfully 

implement the provisions of AB 1054 associated with the [wildfire] fund in a consistent and 

credit supportive manner” would likely trigger negative credit momentum on SDG&E’s credit 

rating.106 RRA similarly notes that, while AB 1054 mitigates some of the California utilities’ 

exposure to wildfire liability, it is “unclear whether the funding mechanisms” in AB 1054 will 

avert California utilities being responsible for wildfire costs under inverse condemnation even if 

the utility “adhered to prevailing safety guidelines.”107 

Credit rating agencies see two primary risks related to AB 1054’s implementation: (1) 

uncertainty regarding how the revised prudency standard will be implemented; and (2) 

uncertainty as to how long the wildfire fund will remain solvent. As Mr. Folkmann testified 

regarding the application of the prudency standard, “[b]eauty is in the eye of the beholder.”108 

Although the revised language is modeled to more closely track FERC’s application of the 

prudency standard, assessing risk is about considering investor expectations. Investors have 

“[v]ery significant questions with regard to how the new prudency standard would be applied in 

a real fact situation.”109 This uncertainty is reflected in the credit rating agencies’ caution about 

AB 1054’s prudence standard revisions: 

 

105 RRA Aug. 15, 2019 Report, Exh. SDG&E-20-C at 3. 

106 Folkmann/SDG&E Exh. SDG&E-01-S at Appendix E. 

107 RRA Aug. 15, 2019 Report, Exh. SDG&E-20-C at 3. 

108 Folkmann/SDG&E Tr. V.5:805:11-12. 

109 Id. at 794:1-3. 

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 S&P: If “the [C]ommission does not implement AB 1054 in a creditsupportive manner then much of the new law’s credit-supportive elements 

related to the revised standards of a utility’s reasonable conduct could 

potentially be negligible;”110

 Moody’s: “The application of this revised prudency standard by the 

CPUC in a credit supportive manner would likely strengthen our view of 

the credit supportiveness of the regulatory environment in California. 

However, this is likely to take some time as it remains to be seen how 

challenging it will be for the intervenors to create serious doubt [and flip 

the burden of proof back to the utility], an undefined term and subject to 

the CPUC’s interpretation;”111

 Fitch: “Other credit constraints include . . . the lack of a track record of 

implementing the new legislation especially the new prudence standard 

which is subject to interpretation.”112 

The risk for investors is that California utilities will continue to be found imprudent under 

new vague, untested standards regarding the same event where another jurisdiction, such as 

FERC, would allow cost recovery.113 As Messrs. Graves and Mudge note, “[p]reparing for fires 

is extraordinarily complex.”114 Mr. Folkmann adds that wildfire proceedings have become 

“charged” events;115 reflected in Moody’s concern that “utilities in California tend to receive a 

higher level of scrutiny and attention from both the media and the public, such that issues can 

quickly become contentious.”116 These factors create uncertainty such that stakeholders cannot 

 

110 S&P July 30, 2019 Report, Exh. SDG&E-22-C at 2. 

111 Moody’s Aug. 2, 2019, Report, Exh. SDG&E-23-C at 5 (emphasis added). 

112 Folkmann/SDG&E Exh. SDG&E-01-S at Appendix C. 

113 See Concentric/SDG&E Exh. SDG&E-12, Ch. 1 at 19 (“the determination of what constitutes a 

reasonable and prudent manner is subject to each regulator’s interpretation of that standard.”); 

Folkmann/SDG&E Tr. V.5:792 (opining that applying the revised prudence standard in a credit 

supportive manner would be applying it in a manner similar to other jurisdictions, particularly 

FERC). 

114 Graves/Mudge/SCE Tr. V.3:494:7-8. 

115 Folkmann/SDG&E Tr. V.5:794. 

116 Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 6. 

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assume that AB 1054’s revised prudency standard will applied in the same manner as it is at 

FERC or in other jurisdictions. 

Investor fears have been underscored by the analytical assumption by Filsinger Energy 

Partners (“Filsinger”) – an energy consulting firm retained by Governor Newsom’s Wildfire 

‘Strike Force’ to assess the potential impacts of AB 1054 – that 75 percent of wildfire costs 

would be deemed imprudent in 2020, declining gradually to 25 percent by 2030 (the “variable 

prudency” assumption).117 Moody’s relied upon those Filsinger assumptions in making its

assessment of AB 1054’s impact.118 Because Moody’s relied upon the variable prudency 

assumption – and because that assumption was coming from a source that informed the state in 

setting its design of the AB 1054 – this variable prudency assumption is “shaping investor 

expectation[s]” about how AB 1054 “was likely to be applied,” regardless of whether the 

assumption turns out to be accurate.119 For stakeholders that are already skeptical of how the 

Commission will evaluate prudence given the WEMA decision, an assumption of 75 percent of 

wildfire costs being disallowed underscore the ongoing risk of California disallowing costs in 

situations where FERC and other jurisdictions would find prudent actions and allow cost 

recovery.120 

 

117 Filsinger Energy Partners, California Wildfire Fund Durability Analysis (June 26, 2019) (“Filsinger 

Jun. 26, 2019 Report”), Exh. TURN-01 at 2. 

118 See Folkmann/SDG&E Exh. SDG&E-01-S at Appendix B, p. 1; accord Moody’s Aug. 2, 2019 

Report, Exh. SDG&E-23-C at 5. 

119 Graves/Mudge/SCE Tr. V.3:494:23 – 495:14; see id. at 510:1-3 (Filsinger’s assumption of a sliding 

scale from 75%-25% imprudence from 2020 to 2030 is the “way these utility investors are going to 

view the risks going forward”); id. at 527 (noting that there is no other analysis of how the prudency 

standard will be applied beyond Moody’s reliance on Filsinger’s variable prudency standard for 

investors to rely upon); Coyne/Reed/SDG&E Tr. V.4:752:16 (the variable prudency outcomes are the 

assumptions that the “investment community [is] focused on”). 

120 Coyne/Reed/SDG&E Tr. V.4:719:10-14 (“The second question about prudence is going to be factspecific and, more importantly, it’s going to be fact-specific to a new prudent standard that has never 

been administered in California before.”); see also id. at 763:15-16 (explaining that Filsinger’s 75 

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As Kevin O’Donnell noted on behalf of the Federal Executive Agencies (“FEA”), he is 

not aware of FERC ever disallowing wildfire cost recovery – a significant difference from a 75 

percent disallowance assumption.121 Mr. O’Donnell added that FERC is “relatively consistent 

based on preceden[t],”122 meaning that stakeholders feel assured that FERC will assess wildfire 

prudency in a uniform manner, reducing uncertainty. Notably, based on the Agency’s 2014 

SDG&E decision, this means that FERC will likely continue to take inverse condemnation into 

account when assessing cost recovery for California utilities “even when the presumption of 

prudence is not dispositive” – a potentially significant continuing difference between FERC and 

the CPUC, as AB 1054’s revised prudency standard still not does provide for any consideration 

of strict liability.123 

Moreover, if Filsinger’s variable prudency assumption turns out to be inaccurate and 

utilities are found prudent more frequently, inverse condemnation’s burden-shifting onto utilities 

and ratepayers still increases risk to California utilities through rate pressure, potentially 

crowding out the ability of SDG&E to make other needed investments.124 

 

percent assumption refers to disallowance of “75 percent of the ultimate claim being presented to the 

CPUC”). 

121 See O’Donnell/FEA Tr. V.3:370-71; see also Concentric/SDG&E Exh. SDG&E-12, Ch. 1 at 9 

(noting that the Filsinger assumptions “indicat[e] that the revised prudence standard may be applied 

in a different manner than at FERC.”). 

122 O’Donnell/FEA Tr. V.3:382:7-8. 

123 Compare SDG&E, 146 FERC ¶ 63,017, P 60 (“While the presumption of prudence and lack of 

challenge are dispositive, as demonstrated above, even if they were not, under California law SDG&E 

would likely have been held responsible for such costs irrespective of fault. Therefore, inclusion of 

those costs . . . was valid.”), with Cal. Pub. Util. Code § 451.1 (not mentioning inverse condemnation 

or strict liability). 

124 See Folkmann/SDG&E Tr. V.5:853-54; Concentric/SDG&E Exh. SDG&E-05-S, Ch. 2 at 5 (“A 

negative rating factor that I think will persist for a considerable time is what I call ‘ratepayer fatigue,’ 

which was articulated by S&P as a secondary credit risk in a June 2019 commentary. If rate increases 

are necessitated for wildfire cost recovery, it could crowd out the ability of a utility to fully and timely 

recover other costs in rates. This lingering risk, a function of the continuing threat that inverse 

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And if California utilities are found prudent more frequently than in Filsinger’s “variable 

prudency” assumption, it increases the risk of the other primary concern regarding AB 1054 – 

the fear that the wildfire fund will quickly become insolvent more quickly – at which point the 

electric utilities also lose their cap on liability.125 

 S&P: If the fund becomes fully depleted, SDG&E loses the “loses the 

credit benefit of using the [wildfire] fund as a source of liquidity and more 

importantly loses the credit protection of the liability cap,” meaning that 

SDG&E’s “longer-term risks include the lack of an automatic replenishing 

mechanism and the depleting nature of the insurance fund whenever there 

is a catastrophic wildfire caused by a participating investor-owned electric 

utility;”126 

 Moody’s: “If and when the [wildfire] fund’s claims paying capability is 

exhausted, the majority of the credit friendly structures, including the 

disallowance cap, will terminate.”;127

 Fitch: if the “[f]requency and magnitude of catastrophic wildfires in the 

next few years deplete the fund much sooner than expected,” it could lead 

to a negative ratings action.128 

This makes the duration of the wildfire fund critical. Uncertainty regarding the wildfire 

fund’s durability goes beyond simply how often a utility will be found prudent. Moody’s in fact 

relies upon four Filsinger assumptions in assessing the durability of the wildfire fund: 

 The wildfire experience of the past five years applies; 

 Utilities maintain $1 billion of wildfire liability insurance; 

 “[Seventy five percent] of wildfire costs are disallowed in 2020 but fall[] 

steadily to 25% by 2030;” and 

 

condemnation’s burden-shifting poses to California utilities and their ratepayers, could act to limit the 

ratings upside for SDG&E and other utilities by suppressing the agencies’ view of regulatory risk in 

California.” (citation omitted)) 

125 Filsinger Jun. 26, 2019 Report, Exh. TURN-01 at 2 (noting the higher likelihood of the fund being 

exhausted if utilities are always found prudent); see O’Donnell/FEA Tr. V.3:377, 380 

(acknowledging that how long the fund lasts is tied to the rate of imprudency findings). 

126 S&P July 30, 2019 Report, Exh. SDG&E-22-C at 1-2.

127 Folkmann/SDG&E Exh. SDG&E-01-S at Appendix B, p. 1. 

128 Id. at Appendix C, p. 4. 

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 The subrogation incentives work as intended, inducing insurers to settle claims at a 40 

percent discount to stretch the wildfire fund’s coverage beyond its $21 billion 

capitalization.129 

One or all of these assumptions could be incorrect, leading to significant uncertainty 

regarding the duration of the fund. As discussed, without knowing how the revisions to the 

prudency standard will be applied, it is impossible to know with precision what percentage of 

catastrophic wildfire claims on the fund will be found prudent – and with it, how long the fund 

will last.130 Similarly, the wildfire fund’s duration will be much shorter if the experience of the 

last two years of catastrophic wildfire liability applies moving forward, rather than the last five 

years.131 That is, according to Filsinger, the last five years have seen an average utility-caused 

wildfire loss of $8.5 billion. But the average loss, for the last two years alone, is over $12 billion 

annually.132 

The provision incentivizing the settling of claims at 40 percent or less might not work as 

intended.133 An alternative assumption that the average wildfire experience of the last two years 

 

129 See id. at Appendix B, p. 1 (noting these four assumptions and Moody’s reliance on those 

assumptions in reaching their assessment about the longevity of the wildfire fund); Widjaja/SDG&E 

Exh. SDG&E-03-S at 5-7 (examining why each assumption may not be correct); Concentric/SDG&E 

Exh. SDG&E-05-S, Ch. 1, at 11 (same). 

130 See Coyne/Reed/SDG&E Tr. V.4:684:16-28 (explaining why it is important to assess all prudency 

scenarios). 

131 See Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 5 (“we also believe that the size of the 

wildfire fund is an important consideration for SDG&E’s credit quality, particularly as the state seems 

to be increasingly prone to more extreme events due to the combination of weather, climate change 

and population density.”). 

132 See Widjaja/SDG&E Exh. SDG&E-01-S at 6 (noting this distinction between the average of the last 

two years and the last five); see also Coyne/Reed/SDG&E Tr. V.4:723:17-19 (Filsinger recognized 

“that if, in fact, the performance was more like the last two years that the Wildfire Fund would be 

inadequate to remain solvent.”); Graves/Mudge/SCE Tr. V.3:524 (“there is a possibility that the fund 

will start to experience shortfalls even within the first three years.”). 

133 See Coyne/Reed/SDG&E Tr. V.4:723:21-25 (stating that the “assumption with regard to a 40 percent 

settlement rate on the claims, is very, very optimistic based upon the experience of SDG&E, [where] 

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continues, combined with an increase in the settlement percentage to 60 percent, results in a 

much quicker fund depletion regardless of how frequently a utility is found to have acted 

prudently.134 

And the wildfire fund exposes SDG&E to new contagion risks – namely that the duration 

of the fund is largely outside of the Company’s control. As S&P states: 

AB 1054 directly associates SDG&E’s credit quality to the operations of 

its California electric utility peers. Meaning even if SDG&E continues to 

maintain its operational excellence, its longer-term benefit of the creditsupportive liquidity cap is ultimately dependent on the operations of 

California’s other investor-owned electric utilities that are also 

contributing to the insurance fund.135

As Mr. Reed described, uncertainty exists regarding how AB 1054’s revised prudency 

standard, the duration of the wildfire fund, and the settlement incentive provision will work.136 

Uncertainty equals risk. Risk equals a return requirement. So we 

recognize there’s an uncertainty there. And we would hope that

uncertainty is reduced over the next 2, 5, 10 years. But today, as we stand 

here, it is uncertain, and uncertainty equals risk.137

Mr. Reed continued that it is likely going to take “a show-me kind of a result,” regarding 

cost recovery under the revised prudency standard to further lower risk regarding wildfire 

liability in California.138 Moody’s similarly indicated that, although the “application of this 

 

it was more like 56, 57 percent”); see also Graves/Mudge/SCE Tr. V.3:529:5-7 (noting that “it 

matters enormously how successful the State is in settling claims at a discount.”). 

134 Coyne/Reed/SDG&E V.4:723-24; accord Concentric/SDG&E Exh. SDG&E-05-S, Ch. 1, at 11 

(same). 

135 S&P July 30, Exh. SDG&E-22-C at 2; accord Folkmann/SDG&E Exh. SDG&E-01-S at Appendix C, 

p. 3 (“Contagion Risk: Funds available to SDG&E will be affected by the frequency and severity of 

wildfires in other IOUs’ service territories as well as their safety conduct which is less favorable, in 

Fitch’s view. If the fund is depleted, the limit of each utility’s liability does not apply.”). 

136 Coyne/Reed/SDG&E Tr. V.4:725. 

137 Id. at 725:5-10. 

138 Id. at 719:27. 

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revised prudency standard by the CPUC in a credit supportive manner would likely strengthen 

our view of the credit supportiveness of the regulatory environment in California . . . this is likely 

to take some time.”139 And any further positive ratings action is also dependent upon positive 

outcomes in this cost of capital proceeding and other regulatory proceedings.140 

This indicates that it will be a long process for any ratings improvement – likely 

dependent on experience with the application of the revised prudency standard, the wildfire 

fund’s durability, and credit-supportive outcomes in this cost of capital proceeding.141 Until that 

time, irrespective of the accuracy of wildfire fund-related assumptions, California utilities will 

continue to face unique risks from the combination of the greater probability of wildfire risk, 

inverse condemnation, and an uncertain regulatory environment following AB 1054.142

2. California Utilities Face Significant Non-Wildfire Risks 

In addition to the risks related to potential wildfire liability described above, SDG&E 

faces significant risks not related to wildfire liability that are relevant to the determination of 

SDG&E’s authorized ROE and overall ROR. Messrs. Folkmann and Widjaja explained that the 

unique nature of the non-wildfire risk currently faced by SDG&E stems primarily from the 

combination of California’s aggressive policy mandates and the uncertainty created by 

 

139 Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 5; see also Folkmann/SDG&E Exh. SDG&E01-S at Appendix E, pp. 3-4 (noting that actions that could lead to a positive ratings action include an 

effective implementation of A.B. 1054, the continued success in wildfire mitigation activities, a 

favorable GRC order and/or meaningful improvement in rate regulation, and indications that a repeal 

of inverse condemnation was forthcoming). 

140 Folkmann/SDG&E Exh. SDG&E-01-S at Appendix E, p. 1. 

141 Id. at 12; see also Concentric/SDG&E Exh. SDG&E-05-S, Ch. 2 at 4 (“The rating agency reactions 

(see below) indicate to me that incremental wildfire liability reform is a first step in a process that will 

take a long time to prove out before leading to widespread ratings improvement.”). 

142 Coyne/Reed/SDG&E Tr. V.4:754-55. 

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significantly increased load departure due to Community Choice Aggregation (“CCA”) and 

Direct Access (“DA”), which is upending the traditional utility model and regulatory framework. 

As Mr. Widjaja observed, “[t]he energy industry in California is in a period of 

unprecedented change as government policies, customer needs and technology innovation are 

transforming towards a more decentralized, less utility-centric environment; all while 

simultaneously advancing increasingly aggressive clean energy goals.”143 He noted the 

Commission’s own warning that the rapid changes occurring in California’s electric sector and 

lack of a comprehensive regulatory framework to address disaggregation of load, are “creating 

unintended adverse consequences.”144 In addition, factors such as cost shift and rate pressure 

due to increased reliance on Distributed Energy Resources (“DERs”), technology and 

cybersecurity risk, and SDG&E’s planned capital projects create investment risk. 

These risks cannot be analyzed in isolation; rather they are interconnected and 

interdependent, creating an amplified systemic risk that is new, complex, and difficult to track, 

and that is more likely to produce unforeseen or unpredictable outcomes.145 Moody’s assessment 

of these political and public policy challenges, taken together, resulted in the credit rating agency 

only rating SDG&E a “Baa” for the “Consistency and Predictability of Regulation,” and the 

“Timeliness of Recovery of Operating and Capital Costs;” meaning that they are holding back 

the credit rating agency from restoring SDG&E’s credit rating.146 Moreover, these risks are 

increasing at a rate above national utility averages.147 As SCE witness, Dr. Stern, correctly 

 

143 Widjaja/SDG&E Exh. SDG&E-03 at 19. 

144 Id. (citation omitted). 

145 Id. at 19 – 20. 

147 Id. at 20. 

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observed during the evidentiary hearing, “California is uniquely pursuing policies to a degree 

that is unparalleled in other jurisdictions.”148 SDG&E is committed to achieving the State’s 

ambitious energy policy and technology goals, and commends the Commission for its role as a 

change leader. As a practical matter, however, SDG&E’s ability to attract the capital investment 

necessary to allow it to meet the State’s policy objectives depends upon authorization of an ROE 

that provides investors a return commensurate with the higher risk profile caused by the 

embedded risk in SDG&E’s businesses.149

a. Ambitious Public Policy Initiatives 

California energy policy has continued to evolve with an even greater emphasis on clean 

and sustainable energy solutions.150 Most notably, Senate Bill (“SB”) 350 and SB 100 establish 

aggressive new clean energy, clean air and greenhouse gas (“GHG”) reduction goals for 2030 

and beyond.151 As emphasized above, SDG&E supports the State’s policy objectives. Yet 

Moody’s recently underscored the investment risk for SDG&E associated with the State’s 

mandates, pointing out “the significant demands that are placed on the California utilities, 

including many ambitious public policy initiatives that are implemented through utility 

operations.”152 

As Mr. Widjaja explained, the State’s decarbonization goals focus in the near-term on 

heavy reliance on renewable energy resources procured through the Renewable Portfolio 

Standard (“RPS”) program – SB 100 sets the current RPS standard at 60 percent by 2030, with 

 

148 SCE/Stern Tr. V.2:167:15-17. 

149 Widjaja/SDG&E Exh. SDG&E-03 at 20. 

150 Id. at 23. 

151 Folkmann/SDG&E Exh. SDG&E-07 at 10-11. 

152 Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 6; Folkmann/SDG&E Exh. SDG&E-07 at 10. 

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the remaining 40 percent of energy supplied by zero-carbon resources by 2045. He observed that 

these targets are among the most ambitious in the country.153 This conclusion was echoed by 

SCE witness, Dr. Stern, who testified during the evidentiary hearing that “the degree to which 

California is pursuing clean energy goals in things like RPS, in things like procurement of energy 

storage and things like electrification goes beyond what is happening in other parts of the 

country.”154

The ambitious clean energy goals set by the State, while laudable, present significant 

investment risk for California utilities. First, increased reliance on RPS resources presents 

operational risks related to integration of intermittent resources and grid reliability that are wellknown to the Commission.155 Safe and reliable operation of the electrical grid requires that 

electric supply always equal real-time electric demand. With the introduction of increasing 

levels of intermittent and variable RPS resources such as wind and solar onto the grid, system 

challenges associated with the mismatch between the daily peak demand and the daily peak of 

renewable generation become more acute. 

This mismatch creates operational risks for SDG&E related to over-generation by RPS 

resources and the challenge of ensuring that system resources can ramp to meet the wide swing 

in demand reflected in the “duck curve” developed by the California Independent System 

Operator (“CAISO”). SB 100 will drive an increase in the level of intermittent resources on the 

 

153 Widjaja/SDG&E Exh. SDG&E-03 at 23, citing Lawrence Berkley National Laboratory, U.S. 

Renewables Portfolio Standards, 2017 Annual Status Report (July 2017), available at http://etapublications.lbl.gov/sites/default/files/2017-annual-rps-summary-report.pdf.

154 SCE/Stern Tr. V.1:119:12-17. 

155 See, e.g., D.19-04-040 at FOFs 32-35 (noting that existing renewable and energy storage technologies 

are not sufficient to ensure system reliability); California Public Utilities Commission, Staff White 

Paper, Beyond 33% Renewables: Grid Integration Policy for a Low-Carbon Future (November 25, 

2015) at 1. 

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grid. In addition, many CCAs have clean energy goals that are intended to exceed the State’s 

RPS goals.156 Thus, since CCA formation in California is expected to continue its dramatic 

growth, it is reasonable to expect that levels of renewable generation on the grid may surpass 

even what is expected through implementation of SB 100. The need to integrate unprecedented 

levels of new renewable generation onto the grid could involve significant capital investments 

and operations and maintenance (“O&M”) costs and have a direct negative impact on SDG&E’s 

cash flow, balance sheet and credit metrics. 

Second, fully achieving the State’s 100 percent clean energy goal may involve reliance on 

newly-developed technologies. It is not clear that existing renewable technologies such as wind 

and solar, even with battery storage, will be sufficient by themselves to achieve the 100 percent 

zero-carbon objective.157 Thus, satisfaction of the statutory requirements of SB 100 may 

introduce new grid integration challenges that are not apparent today. The Commission will 

consider in its Integrated Resource Planning (“IRP”) proceeding potential requirements intended 

to address this situation.158 The potential for such future action is plainly relevant to equity 

investors’ analysis of SDG&E’s long-term investment risk. 

Third, the long-term contracting necessary to meet the State’s RPS and clean energy 

goals imposes financial and regulatory risk on SDG&E. SDG&E currently has a significant 

 

156 See, e.g., D.18-02-018 at 24. 

157 The Commission, the California Air Resources Board (“CARB”), and the California Energy 

Commission (“CEC”) will evaluate all aspects of the 100 percent zero-carbon goal, including 

safety/reliability and potential technologies, in a series of Joint Reports to the Legislature, the first of 

which will be completed by January 1, 2021. See Cal. Pub. Util. Code § 454.53(d)(2); see also 

California Energy Commission, SB 100 Joint Agency Report, available at 

https://www.energy.ca.gov/sb100. 

158 California Public Utilities Commission, 2018 California Renewables Portfolio Standard Annual 

Report (November 2018) at 47. 

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number of long-term RPS power purchase agreements (“PPAs”) in its resource portfolio.159 And 

SB 350 requires that at least 65 percent of RPS procurement be derived from long-term 

contracts. SDG&E’s high number of long-term PPAs could negatively impact SDG&E’s credit 

ratings to the extent that the credit rating agencies treat SDG&E’s obligations under such PPAs 

as “debt equivalent.”160 Martiza Mekitarian described the relationship between long-term PPAs 

and debt equivalence, explaining that “[d]ebt equivalence is a concept used by credit ratings 

agencies to describe the financial risk resulting from signing long-term contracts, such as PPAs . 

. . those agencies consider the fixed financial obligations resulting from long-term PPAs to be 

debt or debt equivalence due to the financial risk inherent in such multi-year contracts.”161 Ms. 

Mekitarian detailed during the evidentiary hearing how credit ratings agencies’ provide guidance 

regarding debt equivalence: 

There is some guidance [the credit ratings agencies] provide where they 

talk about how they calculate a potential debt factor for the PPAs that we 

have disclosed in our financial statements, such as a 10k. They can look at 

the 10k which was referenced earlier today, and in there we disclose the 

future obligations of our power purchase agreements. And even though 

these power purchase agreements are not calculated as debt on the books, 

they're future obligations to the company, some of the credit rating 

agencies can view that as higher risk and then they could impute an 

amount of debt that they convert when evaluating our credit metrics.162

The Commission has also addressed the credit ratings agencies’ method for determining 

debt equivalence: 

Credit agencies do not use a standard method to calculate long-term debt 

equivalence. S&P’s uses a risk factor of 50% as a generic guideline for 

 

159 SDG&E has also entered into long-term PPAs for conventional generation. See Moody’s Aug. 2, 

2019 Report, Exh. SDG&E-23-C at 7-8. 

160 Widjaja/SDG&E Exh. SDG&E-03 at 27. 

161 Mekitarian/SDG&E Exh. SDG&E-02 at 11. 

162 Mekitarian/SDG&E Tr. V.5:902:13-27. 

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utilities with PPAs included as an operating expense in base tariffs and 

lowers that risk factor to 25%, as appropriate, when purchased power costs 

may be recovered via a fuel-adjustment clause. Moody’s employs a 

different methodology in assessing utility PPAs. In certain cases, 

Moody’s would not impute any debt and in other cases consider PPAs as a 

positive risk mitigation factor. Moody’s recognizes that PPAs have been 

used by utilities as a risk management tool. Thus, it will not automatically 

penalize utilities for entering into contracts for the purpose of reducing 

risk associated with power price and availability. Moody’s look at the 

aggregate commercial position, evaluating the risk to a utility’s purchase 

and supply obligations. In addition, PPAs are considered by Moody’s to 

be similar to long-term supply contracts used by other industries and their 

treatment should not therefore be fundamentally different from that other 

contracts of a similar nature.163

This description is consistent with Moody’s recent statement that it treats certain SDG&E 

non-RPS contracts as operating costs rather than debt equivalent. It is important to note, 

however, that Moody’s caution that this treatment could change if there is “a deterioration in the 

regulatory support that decreases the utility’s ability to recover these [contract] costs.”164 

SDG&E’s debt equivalence exposure (and the potential for consolidation of certain PPAs under 

Accounting Standard Codification 810)165 increases SDG&E’s investment risk profile.166 

SDG&E’s execution of additional long-term PPAs in the future in order to meet the State’s RPS 

and clean energy requirements could cause SDG&E’s debt equivalence figure to continue to 

grow; meaning that SDG&E’s financial credit ratios will continue to deteriorate.167 The 

 

163 D.12-12-034 at 10-11. 

164 Moody’s Aug. 2, 2019, Report, Exh. SDG&E-23-C at 8. 

165 Widjaja/SDG&E Exh. SDG&E-03 at 27. Accounting Standard Codification (“ASC”) 810 “is a 

generally accepted accounting principal that requires an entity such as SDG&E having a controlling 

financial interest in another entity, such as its proposed purchase power tolling agreements, to 

consolidate those other entities into the financial statements of the controlling financial entity.” D.12-

12-034 at 10, n.22. 

166 Widjaja/SDG&E Exh. SDG&E-03 at 27; see also Mekitarian/SDG&E Exh. SDG&E-02 at 11-13. 

167 Widjaja/SDG&E Exh. SDG&E-03 at 27. 

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Commission has expressly acknowledged the risks associated with debt equivalence,168 making 

clear that debt equivalence impacts utility credit ratings and must be balanced in both the utility’s 

adopted capital structures and authorized ROE.169 

The ability of – and determination with which – stakeholders can challenge the utilities’ 

proposed procurement contracts and recovery of procurement costs incurred under Commissionapproved contracts is relevant to the analysis of debt equivalence and the level of regulatory 

support for cost recovery – as well as the risk of regulatory lag. In a section of Moody’s August 

2, 2019 report that specifically references the “[e]levated political risk and public scrutiny in 

California” in the context of the State’s aggressive renewables plans, Moody’s observes that 

“SDG&E’s credit also incorporates our view that utilities in California tend to receive a higher 

level of scrutiny and attention from both the media and the public, such that issues can quickly 

become contentious.”170 This perception of a relatively high degree of cost recovery risk is 

characterized by Moody’s as a “credit challenge” with the potential to negatively impact 

SDG&E’s credit rating.171 

Intervenors can and routinely do challenge the procurement contracts submitted for 

Commission approval by the utilities. Indeed, even when contracts have been approved by the 

 

168 Mekitarian/SDG&E Exh. SDG&E-02 at 13 (citing California Public Utilities Commission, An 

Introduction to Debt Equivalency (August 4, 2017), available at

http://www.cpuc.ca.gov/uploadedfiles/cpuc_public_website/content/about_us/organization/divisions/

policy_and_planning/ppd_work/ppd_work_products_(2014_forward)/ppd%20-

%20intro%20to%20debt%20equivalency(1).pdf. 

169 Mekitarian/SDG&E Exh. SDG&E-02 at 13 (citing D.12-12-034 at 29 (The Commission’s goal in 

considering debt equivalence is to “provide reasonable confidence in the utilities’ financial 

soundness, to maintain and support investment-grade credit ratings, and provide utilities the ability to 

raise money necessary for the proper discharge of their public duty.”). 

170 Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 6. 

171 Id. at 2. 

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Commission, the reasonableness of provisions included in such contracts have in some cases 

been challenged several years after Commission approval. This type of persistent stakeholder 

attack reinforces the perception that SDG&E exists in a “contentious” environment that subjects 

it to heightened cost recovery risk.172 Once contracts are approved, stakeholders may challenge 

the utility’s contract administration and the costs incurred under such contracts, and seek 

disallowance through the Energy Resource Recovery Account (“ERRA”) balancing account 

proceedings.173 Since CCA formation in SDG&E’s service territory is expected to grow 

dramatically over the next few years,174 it is logical to assume that challenges to SDG&E’s RPS 

contract costs by CCAs seeking disallowances will likewise grow. 

In D.18-10-019, issued in Phase One of the Commission’s Power Charge Indifference 

Adjustment (“PCIA”) proceeding, the Commission signaled its intent to establish “standards for 

more active management of the utilities’ portfolios in response to departing load in the future 

[and] . . . shareholder responsibility for future portfolio mismanagement, if any, so that neither 

bundled nor departing customers bear full cost responsibility if utilities do not meet established 

portfolio management standards.”175 Equity investors have little information at this point 

regarding the new standards the Commission will adopt or their impact on SDG&E. Indeed, the 

Commission acknowledges that “[t]here remains a significant degree of uncertainty regarding 

what further portfolio optimization and management tools will be possible and effective.”176 As 

Mr. Folkmann noted, the likelihood of increased challenges to SDG&E’s procurement costs due 

 

172 See id. at 7. 

174 Folkmann/SDG&E Exh. SDG&E-07 at 12. 

175 D.18-10-019 at 112 (emphasis added). 

176 Id. at 113. 

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to growth in CCA – combined with uncertainty regarding the Commission’s apparent intent to 

establish a new, potentially more stringent, prudence standard for utility procurement (compared 

to other jurisdictions) – increases the perception of risk associated with SDG&E’s long-term 

RPS (and, potentially, new technology resource) PPAs.177 

b. Increased Customer Adoption of Advanced Technologies 

Deployment of distributed energy resources (“DERs”) such as rooftop solar and energy 

storage has grown significantly since 2012. For example, net energy metering (“NEM”) 

resources have increased from approximately 130 cumulative megawatts (“MW”) in 2012 to 

over 995 cumulative MW in 2018.178 As discussed below, this growth in DERs creates two areas 

of investment risk for SDG&E. First, shrinking customer load volume results in cost shift to 

customers without DERs and puts upward pressure on customer rates. Second, higher levels of 

DERs on the system can potentially increase operational risk and cause unanticipated increases 

in capital and O&M costs. 

With regard to the first of these risks – i.e., cost shift resulting from reliance on DERs and 

the resulting pressure on customer rates – SDG&E notes that the average net monthly use per 

residential customer from 2010 to 2018 has declined approximately 20 percent due primarily to 

the installation of rooftop solar and the success of energy efficiency programs.179 While this 

increase in reliance on rooftop solar and adoption of energy efficiency measures aligns with 

California’s policy goals, the unintended consequence is that under the volumetric rate structure 

 

177 SDG&E/Folkmann Tr. V.5:827-828. 

178 SDG&E/Folkmann Exh. SDG&E-07 at 12. NEM is a tariff billing mechanism established pursuant 

to Cal. Pub. Util. Code § 2827 that allows eligible customer-generators to rely on an on-site 

distributed generation system (typically rooftop solar) to serve a portion of their energy needs, and to 

receive compensation for generation exported to the utility grid. 

179 Widjaja/SDG&E Exh. SDG&E-03 at 21. 

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currently in place for the California utilities this reduction in volume impedes SDG&E’s ability 

to collect the fixed costs of providing service and utility infrastructure investments from DER 

customers. Instead, fixed costs under-recovered from DER customers are shifted to non-DER 

customers.180 

The utility’s cost of providing service includes: (i) customer costs; (ii) distribution 

demand capacity costs; (iii) systems capacity costs; and (iv) commodity costs. In addition, retail 

rates also recover the costs of legislative and regulatory mandated public policy programs from 

customers. A significant percentage of the cost of providing utility services – specifically 

customer costs, distribution demand capacity costs, and systems capacity costs – are fixed and do 

not vary based on a customer’s kilowatt-hour (“kWh”) energy use.

181 Nevertheless, all of the 

utility’s costs of providing service (including fixed costs) are recovered from residential 

customers through a per-kWh volumetric rate. 

Since a residential customer’s reliance on a DER (and/or energy efficiency) reduces the 

volumes delivered to that customer, SDG&E’s ability to fully recover fixed costs from that 

customer is likewise reduced.182 Instead, these unrecovered costs are shifted to other residential 

customers.183 As noted, this type of cost shift is viewed negatively by the credit ratings agencies 

since such cost shifts generally create rate pressure “result[ing] in increases in [customer] bills 

that would reduce the headroom available to recover other costs.”184 Cost shifts such as those 

experienced due to the increase in DERs, as well as the decline in usage and sales, have resulted 

 

180 Id. at 20; Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 6. 

181 Widjaja/SDG&E Exh. SDG&E-03 at 20-21. 

182 Id. 

183 Id. at 21. 

184 Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 6. 

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in rate increases for SDG&E customers – rate increases that negatively impact the perception of 

SDG&E’s risk.185 

As for the second risk noted above – i.e., that operational challenges related to DERs 

increases capital and O&M costs – Mr. Widjaja explained that the shift from the traditional oneway energy flow to a highly unpredictable and geographically diverse two-way energy flow 

makes the planning and operation of the system progressively more complex, which in turn 

increases risk.186 For example, transformers can become overloaded in areas with high 

concentration of distributed generation, which threatens local distribution system reliability.187 

Greater reliance on DERs can result in a need for capital investments and increased O&M costs 

due to the potential for reduced life expectancy on existing infrastructure.188 SDG&E’s 

customers have tended to be early adopters of DERs. So SDG&E experiences this challenge 

more acutely, which contributes to investors’ perception of higher risks.189

c. Uncertainty Caused by Fundamental Changes to Utility Role 

in the Market 

For most of its history, SDG&E has operated as a vertically-integrated utility serving 

customers in its service territory as a monopoly provider.190 However, with the State’s embrace 

of customer choice (and DERs, as discussed above), the Commission is “revisiting ‘long held 

assumptions in [its] regulatory frameworks and examin[ing] the role of the electric utility at the 

 

185 Widjaja/SDG&E Exh. SDG&E-03 at 21. 

186 Id. 

187 Id. 

188 Id. at 23. 

189 Id. at 21-22. 

190 Id. at 20. 

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center of this system.’”191 Put simply, the century-old paradigm of SDG&E acting as the 

primary supplier of energy to customers on a uni-directional basis from large central generation 

plants connected to load centers is quickly becoming a thing of the past. 

The current reconceptualization of the incumbent utility’s role in the regulatory 

framework is primarily driven by the State’s policy in favor of retail customer choice. CCA 

programs allow communities to assume electric procurement responsibility for retail customers 

within their boundaries, thereby “replacing the regulated electric utilities as their provider.”192 

The CCA program was first established in 2002, but the state has experienced rapid growth in 

CCA formation in recent years.193 Similarly, the DA program allows certain customers to 

purchase their electricity from an Electric Service Provider (“ESP”) rather than their incumbent 

electric utility.194 DA-related load departure is currently capped at a statutory limit, but recentlyadopted legislation increased the statewide cap and requires the Commission to provide 

recommendations to the Legislature regarding a schedule for reopening DA to all remaining 

nonresidential customers.195 As a result, SDG&E predicts that within the next few years, it could 

be serving less than 25 percent of the load in its service territory.196 

 

191 Folkmann/SDG&E Exh. SDG&E-07 at 13. 

192 D.18-10-019 at 2, 5. 

193 See D.18-06-030 at 17 (“In recent years, the number of Community Choice Aggregators (CCAs) in 

California has increased dramatically.”); D.19-06-026 at 21 (discussing the “recent proliferation of 

LSEs and substantial load migration.”). 

194 See D.10-03-022 at Appendix 1. 

195 Senate Bill (“SB”) 237, Stats. 2017-2018, Ch. 600 (Cal. 2018).

196 Widjaja/SDG&E Exh. SDG&E-03 at 22; see also California Public Utilities Commission, 2018 

California Renewables Portfolio Standard Annual Report (November 2018) at 45 (estimating that 

IOUS could lose 60-80 percent of their current demand within the next decade).

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The State’s rapid evolution toward an environment where the majority of customer load 

is served by CCAs and ESPs is a significant alteration of SDG&E’s historical role in serving the 

customers located in its service territory. More broadly, the shift toward a world in which 

multiple providers (e.g., the utility, multiple CCAs, and multiple ESPs in a service territory) 

perform the procurement function in a disaggregated manner –with potentially no provider 

individually serving a majority of load – represents a fundamental change in California’s 

regulatory and market framework.197 This new construct has major implications for, among 

other things, implementation of system reliability and clean energy policy requirements, which 

are currently established on the basis of load. In other words, the risk to equity investors 

presented by the State’s ambitious new policy mandates is heightened by the complexities of 

achieving those mandates in an environment of rapidly departing load. As Mr. Folkmann 

pointed out, this combination “presents an exponentially increased risk compared to what existed 

in 2012.”198 

Not only is the speed and scale of the current evolution unprecedented; the Commission 

itself has acknowledged that there is no overarching strategy guiding this change. ‘“California 

may well be on the path towards a competitive market for consumer electric services but is 

moving in that direction without a coherent plan to deal with all the associated challenges that 

competition poses, ranging from renewable procurement rules to reliability requirements and 

consumer protection.”’199 This creates significant uncertainty, which presents risk. Investors in 

 

197 Folkmann/SDG&E Exh. SDG&E-07 at 12. 

198 Id. 

199 Id. at 13 (citing California Public Utilities Commission Staff White Paper, Consumer and Retail 

Choice, the Role of the Utility, and an Evolving Regulatory Framework (May 2017) at 3, available at 

http://www.ourenergypolicy.org/wp-content/uploads/2017/05/Retail-Choice-White-Paper-5-8-17.pdf. 

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California utilities have experienced the severe consequences of the State’s policy experiments in 

the past – indeed, stakeholders have expressed concern that the current market changes could be 

another energy crisis in the making.200

To be sure, the Commission is working to realign the existing regulatory framework to 

address the issues that arise from the new market dynamic.201 But whether the State’s policy 

initiatives will ultimately achieve the intended objectives of GHG mitigation, system reliability, 

cost-effectiveness and ratepayer protection while enabling customer choice remains to be seen. 

In the meantime, significant investor uncertainty regarding the impacts of the current changes 

continues to exist. And the implementation of the Commission’s new policy framework may 

impose substantial cost and risk on the California utilities, as discussed below. Thus, the 

perception of risk associated with SDG&E, and California utilities in general, is higher than for 

other utilities that are not navigating a major revamping of their market role and the related 

financial implications at the same time that they are implementing multiple ambitious policy 

initiatives and facing wildfire-related risks.202

 

200 See, e.g., California Public Utilities Commission, California Customer Choice: An Evaluation of 

Regulatory Framework Options for an Evolving Electricity Market (August 2018) at 5 noting that 

“Without a coherent and comprehensive plan, the current policies in place may drift California to an 

unintended outcome and breakdown in services like the Energy Crisis.” 

201 Folkmann/SDG&E Exh. SDG&E-07 at 13; see also Order Instituting Rulemaking to Develop an 

Electricity Integrated Resource Planning Framework and to Coordinate and Refine Long-Term 

Procurement Planning Requirements, issued February 11, 2016 in R.16-02-007 (implementing the 

IRP process to oversee statewide resource planning by all load-serving entities (“LSEs”) in order to 

ensure compliance with GHG reduction goals); D.18-06-030 (modifying the Resource Adequacy 

(“RA”) program to add multi-year forward procurement requirements, and has articulated a policy in 

favor of a central buyer framework designed to preserve grid reliability in the current environment of 

fragmented load). 

202 See, e.g. Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 2 (viewing SDG&E’s “[d]emanding 

public policy goals and moderate carbon transition risk” as “credit challenges.”). 

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i. RPS Program Risks 

In the context of the Commission’s RPS program, challenges related to utility load 

forecasting present significant financial and regulatory risk. Indeed, the Commission’s 2018 

Renewable Portfolio Standard Annual Report (“RPS Report”) identifies load forecasting 

uncertainty as a primary barrier to the utilities’ ability to achieve RPS goals, noting that “[t]he 

growth in the number of registered CCAs and the growing trend of IOU customers transitioning 

to CCAs makes it increasingly difficult to forecast future IOU load.”203 The difficulty in 

developing load forecasts creates a risk of RPS under-procurement or over-procurement by the 

utility. If a utility under-procures, it may incur non-compliance penalties and/or be forced to 

procure more expensive RPS resources, which creates pressure on the utility’s earnings as well 

as cost-recovery risk. Utility over-procurement present similar concerns – i.e., higher levels of 

spending impacts cash flow and exposure to cost-recovery risk. 

While the revised PCIA methodology is intended to ensure cost indifference for utility 

bundled customers, the new and potentially more stringent “portfolio optimization” aspect of the 

methodology undermines the effectiveness of this risk mitigation measure. As noted above, the 

Commission has suggested that it intends to adopt a new “more active” standard for utility 

portfolio management with shareholder responsibility for any portfolio mismanagement.204 The 

combination of difficulty in anticipating load departure in a multi-CCA/ESP environment and a 

more rigorous portfolio management prudence standard that are not shared by utilities outside 

the State creates obvious financial and regulatory risk. As Mr. Folkmann explained, “there are 

 

203 California Public Utilities Commission, 2018 California Renewables Portfolio Standard Annual 

Report (November 2018) at 45. 

204 See D.18-10-019 at 112. 

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significant long-term business and financial risks from stranded assets in the absence of an 

optimal way to downsize SDG&E’s portfolio to support the integration of CCAs.”205 

ii. RA Program Risks 

The utilities also face risk related to the Commission’s RA program. In the context of 

RA, the Commission has acted to mitigate the uncertainty related to forecasting bundled 

customer load in a departing load environment by establishing a binding load forecast process 

that locks in year-ahead RA requirements for all Commission-jurisdictional LSEs.206 The 

Commission has made clear, however, that the binding load forecast process applies solely to the 

RA program and does not impact an LSE’s legal ability to serve load (i.e., load may depart after 

the binding load forecast has become effective). 207 Thus, as a practical matter, the process 

serves more as an RA cost allocation measure than an accurate quantification of load share. The 

more relevant risks in the context of the RA program relate to the Commission’s multi-year 

forward local RA procurement requirements and the Commission’s policy in favor of a Central 

Buyer construct for procurement of RA resources (i.e., whether the utilities will serve as Central 

Buyer in their respective service territories).208

In response to increasing load disaggregation, the Commission has recently adopted a 

three-year forward local RA procurement requirement (100 percent in years one and two; 50 

percent in year three).209 Compliance with this requirement will result in an increase in the 

number of SDG&E’s PPAs with a term longer than one-year, which are considered “long-term” 

 

205 Folkmann/SDG&E Exh. SDG&E-07 at 14. 

206 D.19-06-026 at 27-29. 

207 Id. at 27. 

208 Id.

209 See D.18-06-030 at 24-30. 

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contacts for purposes of debt equivalence.210 This increase in multi-year RA PPAs will have risk 

implications related to debt equivalence, placing increased pressure on SDG&E’s balance sheet, 

cash flows and credit metrics. 

iii. IRP Process Risks 

Finally, the current load departure environment creates risk for SDG&E within the 

Commission’s IRP process. As a practical matter, integration of the resource planning activities 

of the utilities and CCAs/ESPs – and in particular, the effort to shift the procurement obligation 

increasingly toward the CCAs – has proven to be challenging given the differing degrees of 

sophistication among CCAs and the general lack of compliance by CCAs that was observed in 

the first cycle of the Commission’s IRP process. In its decision adopting the IRP Preferred 

System Portfolio (“PSP”), the Commission was blunt in addressing the deficiencies of the CCAs’ 

procurement activities to date: 

[B]ecause of load migration primarily away from IOUs to CCAs, we 

expect that the majority of procurement of new resources in the next 

decade will be conducted by CCAs. We are aware that several CCAs are 

beginning to procure new resources, primarily renewables and storage, in 

order to achieve the ambitious GHG goals for 2030. However, the amount 

of new resource procurement will need to be roughly twice what the CCAs 

have procured to date by 2022, and close to six times as much by 2030. 

These are ambitious goals that require a lot of concrete contracting in 

order to secure the resources necessary. It is not yet clear to us if it is 

feasible to rely on the CCAs for this level of procurement to achieve the 

2030 portfolio . . . At that level of contract size, it would take almost 6,000 

individual contracts to reach the 2030 new resource goals to achieve the 

optimal portfolio. This seems to be a serious challenge.

211

 

210 Mekitarian/SDG&E Exh. SDG&E-02 at 11-12. 

211 D.19-04-040 at 133-134 (emphasis added) (citations omitted). 

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The Commission expressed particular concern related to the CCAs’ lack of procurement 

of resources required for grid reliability, pointing out CCAs’ practice of leaning on reliability 

resources procured by utilities rather than procuring such resources for their own portfolios:212

We also wish to make clear to all LSEs that there is a shared responsibility 

among all of them for a reliable electric system that meets the state’s 

environmental goals at least cost. The Commission made this point clearly 

in the recent resource adequacy decision refining the program for local 

capacity needs. The current market trends appear to show that a large 

proportion of the responsibility for operational needs still rests on the 

large IOUs, despite the fact that resource adequacy requirements apply to 

all LSEs now serving customers. While the IOU customers have 

historically shouldered the burden of reliability resources, particularly 

natural gas, the load is departing rapidly for alternative providers, 

particularly CCAs, and the responsibility has not appeared to shift 

proportionately.

213

Since the Commission’s jurisdiction over CCAs and ESPs is more limited than its 

plenary jurisdiction over the utilities, it is foreseeable that if CCAs/ESPs fail to execute on their 

service provider requirements, the Commission would order the utilities to undertake the 

necessary procurement of existing or incremental resources on their behalf. Thus, the primary 

risk that SDG&E faces related to IRP is that load will continue to depart – thereby decreasing 

bundled load volume and increasing cost-shift, which places upward pressure on SDG&E’s rates 

and creates financial risk – but CCAs/ESPs will fail to assume the obligations associated with 

serving a significant portion of the retail customer base and the utilities will ultimately be forced 

to take on such obligations. 

 

212 Id. at 136. 

213 Id. at 135-136 (emphasis added) (citations omitted). 

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While the Commission does not presently seem to be inclined to order the utilities to 

undertake procurement on behalf of other LSEs,214 if circumstances were such that a material 

reliability or other customer-related concern were identified, the Commission’s perspective could 

change.215 Alternatively, the Commission could require SDG&E to enter into long-term PPA(s) 

for incremental resource(s) – either as part of “collective” action under the IRP process216 or on 

an individual basis. 

This risk is closely related to the risk, explained by Mr. Widjaja, that customer load that 

departs bundled utility service to be served by a CCA/DA provider might unexpectedly return to 

the utility. While such an event has not occurred to date, it does not follow that it never could, 

particularly given the relatively short period that most CCAs have been in operation. As Mr. 

Widjaja points out, “SDG&E, as the provider of last resort (“POLR”), must stand ready to 

provide electricity if the market does not meet customer demand due to a sudden exit or failure 

of an LSE.”217 This could “creat[e] unplanned procurement obligations that could put a strain on 

SDG&E’s balance sheet and cashflows.”218 

Stakeholders are aware of these issues related to the POLR obligation. But there is little 

certainty at this point regarding what mechanisms would apply to ensure a smooth transition in 

 

214 Id. at 139 (“the primary responsibility for procurement rests with the individual LSEs to serve their 

own load.”). 

215 See R.16-02-007, Proposed Decision Requiring Electric System Reliability Procurement for 2021-

2023 (September 12, 2019) at 32 (“We note that the Commission has the authority, articulated in § 

451.51(c), to direct the IOUs to procure renewable integration resources on behalf of the electricity 

system as a whole and allocate those costs on a non-bypassable basis to all benefitting customers.”). 

216 D.19-04-040 at 140 (“procurement mechanisms to develop resources that one or a small number of 

LSEs may not be able to bring to fruition on their own”). 

217 Widjaja/SDG&E Exh. SDG&E-03 at 22. 

218 Id. at 23. 

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the event of an unplanned exit by a CCA/ESP or who would bear the costs of such transition. 

This uncertainty makes it difficult to accurately quantify the potential impact, which serves to 

heighten the perception of SDG&E as relatively high-risk. 

d. Technology and Cyber Security Risk 

While all corporations face cyber risk (e.g., malware, malicious intent by insiders and 

inadvertent disclosure of sensitive information), the utility industry faces particular threats 

related to grid and infrastructure security, and the need to protect sensitive and confidential 

information.219

This risk is neither theoretical, nor far out in time; there is evidence, for example, that 

state-sponsored Russian actors attempted to hack the U.S. electric grid in July 2018.220 The 

consequences of an external actor successfully gaining control of the grid or other utility assets 

with the intent to cause harm to the public (e.g., an act of terrorism) could be severe – the result 

could be catastrophic gas leaks, fire, explosions and/or system outages.221 SDG&E must 

continuously invest in risk mitigation measures in order to safeguard its systems from 

technology, security, and cyber threats from potentially unknown and rapidly-changing 

sources.222 

e. Elevated Levels of Capital Investment 

SDG&E plans to undertake sizable capital projects over the next five years focused 

primarily on modernizing transmission and distribution infrastructure, and fire hardening 

 

219 Id. at 24. 

220 Id. (citing The New York Times, Russian Hackers Appear to Shift Focus to U.S. Power Grid (July 

27, 2018), available at https://www.nytimes.com/2018/07/27/us/politics/russian-hackers-electricgrid-elections-.html. 

221 Id. 

222 SDG&E/Widjaja, Exh. SDG&E-03 at 24. 

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measures designed to protect against extreme weather events and support public safety.223 These 

capital investments are expected to be in the range of $6.4 to $7.1 billion, requiring SDG&E to 

access the capital markets.224 

As discussed above, the regulatory cost recovery process imposes risk of under-recovery 

or delayed recovery of invested capital. An elevated level of capital investment increases this 

risk.225 Mr. Widjaja noted that “[c]redit rating agencies and investors consistently analyze and 

focus on the effect that elevated capital investments may have on cash flows and corresponding 

pressure on credit metrics.”226 

B. SDG&E’s ROE Proposal Reflects The Company’s Unique and Heightened 

Risks 

To respond to these elevated risks, SDG&E proposes a 12.38% ROE, based upon the 

recommendations of Dr. Roger Morin and Concentric.227 

1. Dr. Morin’s Traditional, Proxy-Based Recommendation 

Dr. Morin’s testimony provides market-based assessments of the risks associated with the 

Company’s equity and determines the investor-required return commensurate with those risks. 

Dr. Morin recommends a “barebones” 10.9% ROE for SDG&E228 – predicated on adoption of 

SDG&E’s proposed capital structure of an authorized 56 percent common equity ratio to manage 

 

223 Id. at 27. 

224 Id.

225 Id.

226 Id.

227 See Folkmann/SDG&E Exh. SDG&E-01-S at 13-14 (providing SDG&E’s revised ROE request 

following AB 1054’s passage). 

228 See Morin/SDG&E Exh. SDG&E-04 at 5; see also id. at 55 (noting that the proxy group was 

comprised of a “less risky group of companies.”). 

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financial risk – based on the “results of all [his] analyses, the application of [his] professional 

judgment, and the rather extraordinary risk circumstances of SDG&E.”229 

Dr. Morin reaches his conclusion by applying standard proxy-based cost of capital 

methodologies. Because SDG&E is a wholly-owned subsidiary of Sempra Energy and not 

publicly-traded, peer groups must be used to estimate the cost of equity.230 Dr. Morin applies 

statistical methods to estimate required equity returns – generally referred to as the discounted 

cash flow (“DCF”), risk premium, and capital-asset pricing model (“CAPM”) methods – to a 

group of investment-grade dividend-paying combination gas and electric utilities to establish an 

ROE range for SDG&E’s utility peer group.231 Specifically, Dr. Morin performed the following 

analyses: 

 a DCF analysis on a group of investment-grade dividend-paying 

combination gas and electric utilities using Value Line’s growth forecasts; 

 a DCF analysis on a group of investment-grade dividend-paying 

combination gas and electric utilities using analysts’ growth forecasts; 

 a traditional CAPM using current market data; 

 an empirical approximation of the CAPM using current market data; 

 historical risk premium data from electric utility industry aggregate data, 

using the yield on long-term US Treasury bonds; and 

 allowed risk premium data from electric utility industry aggregate data, 

using the yield on long-term US Treasury bonds.232

This resulted in the following ROE estimates for Dr. Morin’s proxy group. 

 

229 Id. at 60. 

230 Id. at 19, 22. 

231 Id. at 14-53. Dr. Morin’s prepared direct testimony provides a more detailed description of his 

application of the various methodologies. Dr. Morin believes it important to rely upon multiple 

methodologies as all have limitations, investors rely upon multiple methods, and the results of each 

method can be used to check the other. Id. at 14-15, 53. 

232 Id. at 53; see also D.12-12-034 at 22 (“The financial models commonly used in ROE proceedings are 

the [CAPM], Risk Premium Model (RPM), and DCF Model.”). 

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TABLE 4: Dr. Morin’s Proxy Estimates 

STUDY ROE

DCF Utilities Value Line Growth 10.1% 

DCF Utilities Analysts Growth 9.5% 

CAPM 8.5% 

Empirical CAPM 9.2% 

Historical Risk Premium 10.5% 

Allowed Risk Premium 10.4% 

Removing the outlying result of 8.5%, the results range from 9.2% to 10.5% with a 

midpoint of 9.9%, which Dr. Morin applied as the ROE estimate for the average risk utility in 

the peer group.233 As discussed further below, while Dr. Morin has not conducted an updated 

study, he estimates that the midpoint for the proxy group would now be 9.7 percent (about 10-20 

basis points less) based upon the decline in interest rates – which is somewhat counterbalanced 

by resulting increased risk premium.234 

Dr. Morin then adjusted his recommendation 100 basis points upwards from the midpoint 

of his proxy statistical range to account for the Company’s higher degree of risk compared to the 

average peer utility.235 Dr. Morin found that SDG&E’s “very high level of business, regulatory, 

and financial risks compared to the proxy group of companies” was buttressed primarily by three 

benchmarks: 

 Sempra Energy’s significantly higher beta risk measure compared to the 

peer group; 

 

233 Morin/SDG&E Exh. SDG&E-04 at 54. 

234 Morin/SDG&E Tr. V.2:317-318 (describing his ability to estimate this decline based upon his 40 

years of experience). 

235 Morin/SDG&E Exh. SDG&E-04 at 59. 

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 Sempra’s a higher than average DCF cost of equity risk results compared 

to the proxy group; and 

 SDG&E’s multiple-notch credit rating downgrades over the last two years, 

which demonstrate SDG&E’s “unresolved risk.”236 

Dr. Morin quantified this additional risk by comparing Sempra Energy’s beta of 0.75 

relative to the proxy group average of 0.6. Beta is a measure of the systematic risk of an 

individual stock in comparison to the unsystematic risk of the market as a whole.237 Sempra’s 

beta is 0.15 higher than the average of his proxy group (0.75 compared to 0.60), indicating that 

the return differential should be 0.15 multiplied by the market risk premium of 6.9%, or 100 

basis points, resulting in Dr. Morin’s 10.9 percent recommendation.238 

Dr. Morin emphasized that, if anything, Sempra Energy’s beta diversified does not fully 

capture the risks to SDG&E because Sempra is a multiactivity, diversified company, with 

multiple less risky subsidiaries. So SDG&E’s risks will not be fully reflected in market data.239 

As Dr. Morin states, “if SDG&E were a publicly-traded stand-alone entity, its beta would be 

much higher,” similar “to that of high-risk cyclical industrial companies, as suggested in the 

testimony of Concentric Energy Advisors in this proceeding.”240

 

236 Morin/SDG&E Tr. V.2:192-93; 265. 

237 Morin/SDG&E Exh. SDG&E-04 at 33-34. 

238 Id. at 59; see also Morin/SDG&E Tr. V.2:195. Dr. Morin’s ROE recommendation would become 

10.7% once his estimate of the effect of the decline in interest rates is taken into account. 

Morin/SDG&E Tr. V.2:270. 

239 Morin/SDG&E Tr. V.2:193; see also McCann/EDF Tr. V.6:1030:25-26 (stating that “SDG&E is a 

relatively minor factor in Sempra’s overall holdings.”). 

240 Morin/SDG&E Exh. SDG&E-04 at 55 (citation omitted); see also Morin/SDG&E Tr. V.2:267 

(stating that Dr. Morin believes that the other Sempra Energy subsidiaries would have a beta below 

0.75 to counterbalance SDG&E’s higher beta). 

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2. Concentric’s Quantification of SDG&E’s Unique Wildfire Risks 

Concentric similarly concludes that “typical cost of capital models and approaches” like 

standard proxy-based models, are, when standing alone, “ill-suited” for the “extraordinary 

circumstances” facing SDG&E and other California utilities from the potential for significant 

wildfire-related liability because the risks are not shared by non-California utilities in Dr. 

Morin’s peer group.241 Accordingly, Concentric’s analyses are “designed to measure greater 

shareholder risk generally, and the specific wildfire risks of SDG&E, and the impacts of these 

risks on SDG&E’s cost of equity.”242 While Concentric analyzed a variety of different methods 

to capture this unique risk, their proposal is based on three approaches: 

 An “Estimated Loss Approach,” estimating the earnings necessary to 

make up for the risk of shareholder wildfire loss; 

 A wildfire “Insurance Approach,” measuring how much it costs for 

SDG&E shareholders to bear the risk of wildfire liability as measured by 

the premiums that the Company pays to insurance companies; 

 And a “catastrophe (“CAT”) Bond Approach,” that uses CAT bond 

spreads as an additional measure of the equivalent cost to shareholders to 

bear wildfire liability risk.243 

Concentric found that these “[a]pproaches most reliably indicate the incremental cost of equity 

for SDG&E for its risks that are not reflected in Dr. Morin’s analysis for the proxy group 

utilities.”244 

 

241 Concentric/SDG&E Exh. SDG&E-05, Ch. 1 at 6-7. 

242 Id. at 6; see also Concentric/SDG&E Exh. SDG&E-12, Ch. 1 at 2-3 (summarizing key conclusions). 

243 Concentric/SDG&E Exh. SDG&E-05, Ch. 1 at 7-8, 50-53. 

244 Id. at 8; see also Concentric/SDG&E Exh. SDG&E-12, Ch. 1 at 7 (“Dr. Morin’s proxy group does not 

include any other companies that are subject to the same level of business risk associated with 

catastrophic wildfire liabilities as the Company, nor the regulatory risk associated with inability to 

recover liabilities that California utilities are subject to under the doctrine of inverse condemnation.”). 

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Following AB 1054’s passage, Concentric lowered their wildfire risk assessment by 

nearly 200 basis points after re-running their approaches to account for AB 1054’s wildfire fund 

cap and revised prudency standard – while considering the risks to the fund’s solvency and 

uncertainty regarding how the prudency standard will be applied.

245 Concentric assessed two 

scenarios based upon Filsinger’s “variable prudency” assumption discussed above: (1) an 

assumption of a finding of imprudence by the Commission 70 percent of the time (based upon 

the first three-year period of Filsinger’s variable prudency assumption); and (2) an assumption of 

a finding of imprudence 50 percent of the time (based upon Filsinger’s variable prudency 

assumption over a 10-year period).246 Concentric also assumed a “conditional probability of 25 

percent that the Wildfire Fund will be insolvent for SDG&E’s modeled fire scenarios.”247

Concentric’s Estimated Loss Approach takes the Company’s modeled risk of expected 

wildfire financial loss and determines “the earnings required to offset” the projected average 

wildfire loss above the Company’s $1.5 billion in wildfire insurance coverage.248 The wildfire 

risk model results in a 5.33 percent probability in any given year (about a one-in-20 year event) 

of a $1.5 billion or greater financial loss, with the average for such a loss being $3.68 billion.249 

 

245 Concentric/SDG&E Exh. SDG&E-05-S, Ch. 1 at 5-7; id. at 8-9 (noting that Concentric’s revised 

recommendation following AB 1054’s passage is a 57 percent reduction from their original estimate). 

246 Concentric/SDG&E Exh. SDG&E-12, Ch. 1 at 46. As noted, Concentric believes that it provided a 

reasonable range, based on the fact that the Governor’s office had it prepared for it, and Moody’s and 

investors are relying upon that assumption. Coyne/Reed/SDG&E Tr. V.4:752, 762-763. By 

comparison, prior to AB 1054’s passage Concentric assumed that SDG&E would be found liable 

100% of the time, based upon the WEMA precedent. See Concentric/SDG&E Exh. SDG&E-05-S, 

Ch. 1 at 10. 

247 Concentric/SDG&E Exh. SDG&E-05-S, Ch. 1 at 10-11 (stating that they believe that a 25% 

likelihood of uncertainty is an “appropriately cautious” assessment that not every one of Filsinger’s 

four assumptions will occur as Filsinger predicted). 

248 Concentric/SDG&E Exh. SDG&E-05, Ch. 1 at 50. 

249 Id. at 35. 

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Concentric first assumes that $1.5 billion of such a loss would be reimbursed through insurance 

policies and that SDG&E could recover the portion of liabilities subject to FERC review. They 

then applied Filsinger’s three and 10-year variable prudency assumptions (a 70 percent 

probability and 50 percent chance probability of an imprudence finding) to the portion of liability 

below the wildfire fund’s cap – and those same imprudence probabilities to the 25 percent 

chance of fund insolvency – to the remaining liability that would be subject to Commission 

review to determine the estimated potential annual loss to shareholders.250

Concentric’s Insurance Approach translates the premium insurance companies are 

requiring to insure SDG&E’s wildfire liability into a risk premium for the additional risk borne 

by shareholders of a projected average wildfire event above the Company’s insurance 

coverage.251 As Concentric states,“[g]iven that the insurance industry provides a clear price 

signal for the cost required to bear the risk of wildfire liabilities, insurance premiums provide a 

suitable proxy for the incremental risk premium investors require to invest in the Company.252 

Concentric’s CAT Bond Approach similarly measures the premium that CAT bond 

investors are requiring to bear the risk of wildfire liability relative to a three-year U.S. Treasury 

note as a separate “market measure of the equivalent premium that investors require to selfinsure the remaining potential shareholder liability.”253 With the Insurance and CAT Bond 

Approaches, Concentric applies the same assumptions regarding variable prudency and wildfire 

fund solvency to SDG&E’s wildfire modeling to determine the amount of wildfire damages that 

 

250 Concentric/SDG&E Exh. SDG&E-05-S, Ch. 1 at 12-15. 

251 Id. at 14-17. 

252 Id. at 14 (citing Ex. SDG&E-05 (Concentric) Ch. 1 at 40-41). 

253 Id. at 17. 

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the Company’s shareholders would be responsible for, and then applies SDG&E’s insurance and 

CAT bond pricing to determine the equivalent premium shareholders would require to 

effectively self-insure the amount of wildfire risk above the Company’s current insurance.254 

These are market-based measures of the true cost of SDG&E’s incremental wildfire risk 

following AB 1054’s passage. Based on these scenarios, Concentric recommends a 1.48% risk 

adjustment to SDG&E’s ROE proposal.255 

SDG&E’s overall ROE proposal is based upon Dr. Morin and Concentric’s combined 

recommendations.256 Dr. Morin and Concentric agree that, standing alone, Dr. Morin’s 

recommendation does not fully account for SDG&E’s risks because: 

 A proxy group of non-California utilities does not share SDG&E’s 

wildfire risk; and 

 As a diversified company, Sempra’s market data such as beta and DCF 

understates the full extent of SDG&E’s risk. 

In addition, investors view California utilities as riskier than average even if wildfire 

liability risk is completely removed.257 Quantifying SDG&E’s wildfire liability risk based upon 

the Company’s own internal modeling of wildfire loss and how the insurance industry and bond 

markets price that risk, in combination with Dr. Morin’s traditional peer group review approach, 

more accurately captures the Company’s cost of equity. 

 

 

254 Id. at 15. 

255 Id. at 21. 

256 See Folkmann/SDG&E Exh. SDG&E-01-S at 14. 

257 See id. at 19 (citing Concentric/SDG&E Exh. SDG&E-05, Ch. 1 at 48); see also Moody’s Aug. 2, 

2019 Report, Exh. SDG&E-23-C at 2 (discussing SDG&E’s risks from elevated political risk and 

public scrutiny and demanding public policy goals). 

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TABLE 5: SDG&E’S ROE PROPOSAL 

Source ROE Proposal 

Dr. Morin Traditional ROE Proposal 10.9% 

Concentric Wildfire Premium 1.48% 

Overall ROE Proposal 12.38% 

C. Intervenors’ Recommendations Treat SDG&E as if The Company Faces 

Below-Average Risks and Should be Rejected 

1. Intervenors Admit That Returns Must Be Set Commensurate with 

Risks Yet Propose Below Average ROEs for SDG&E 

By contrast, intervenors’ ROE proposals all suffer from the same fatal flaw. Intervenors 

agree that SDG&E’s return must be set commensurate with risks.258 That is the greater the risk, 

the greater the return.259 In making this assessment, all risks must be considered.260 And it is a 

sliding scale – meaning that a utility of above-average risk should have a higher ROE than an 

average or below risk utility.261 As Mr. O’Donnell states, “if you’re above average risk, you 

should be above the national average.”262

Multiple intervenors likewise acknowledge that RRA, in their annual and semi-annual 

review of nationwide rate case decisions, found that the authorized ROE for all electric utility 

 

258 Gorman/TURN Tr. V.3:393-94; O’Donnell/FEA Tr. V.3:358. 

259 Griffing/UCAN Exh. UCAN/POC-01 at 8. 

260 Griffing/UCAN Tr. V.6:978. 

261 O’Donnell/FEA Tr. V.3:359; Gorman/TURN Tr. V.3:393-94. 

262 O’Donnell/FEA Tr. V.3:363:26-28. 

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cases was 9.59% for 2018 and 9.66% for 2019263 – a slight increase.264 In addition to multiple 

intervenors citing these RRA reports, Mr. Rothschild states that it is his “understanding of 

investors that invest in utilities companies, [that] they have access and review those [RRA] 

reports.”265 

Moreover, several intervenors admit that inverse condemnation makes SDG&E and other 

California electric utilities riskier than utilities nationwide. 

 O’Donnell: Inverse condemnation “does make an investment in a 

[California utility] more risky, as a whole, than an investment in a utility 

that operates in a state without such liability risk;”266

 O’Donnell: “I understand and accept the fact that SDG&E has a higher 

level of risk due to inverse condemnation and the ongoing threat of 

wildfires;”267 

 

263 S&P Global, RRA Regulatory Focus, Major Rate Case Decisions – January – December 2018

(January 31, 2019) (“RRA Jan 31, 2019 Report”), Exh. SDG&E-25-C; S&P Global, RRA Regulatory 

Focus, Major Rate Case Decisions – January – July 2019 (July 22, 2019), Exh. SDG&E-26-C; see 

also O’Donnell/FEA Tr. V.3:361 (agree that those averages are correct); see also Morin/SDG&E 

Exh. SDG&E-09 at 6-7 (stating that the average authorized ROEs in the vertically integrated electric 

utility industry in 2018 and 2019 as reported in the Regulatory Research Associates quarterly review 

are in the 9.6% - 9.8% range). 

264 O’Donnell/FEA Tr. V.3:362. 

265 Rothschild/PAO Tr. V.4:662:19-21. Notably, several intervenors remove certain cases from the RRA 

data set to assert that the average allowed ROE in 2018 and 2019 is slightly lower than reported by 

RRA. See, e.g., Griffing/UCAN Tr. V.6:991-992 (admitting that he removed all settled rate cases to 

claim a national authorized ROE average of 9.6% for 2018 and 9.44% for 2019, despite 

acknowledging that settled rate cases must be “be consistent with the record developed in the 

proceeding.” Even then, Dr. Griffing’s alleged averages for 2018 and 2019 are inconsistent with 

RRA’s “fully litigated” case averages of 9.63% for 2018 and 9.56% for 2019); Gorman/TURN Exh. 

EPUC/IS/TURN-01 p. VIII, Exhibit MPG-11 (stating that the average authorized ROE for 2018 as 

provided by RRA is 9.55% and 9.57% after Mr. Gorman removed “limited-issue rider cases”). But 

see Gorman/TURN Exh. EPUC/IS/TURN-01 p. II-3 (asserting the industry authorized ROE for 2019 

is “about 9.6%.”). 

266 O’Donnell/FEA Exh. FEA-01 at 41; accord Tr. V.3:363:21-24 (agreeing that a “California utility is 

more risky than the average utility outside of the state” because of “inverse condemnation.”). 

267 O’Donnell/FEA Exh. FEA-01 at 57. 

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 Gorman: SDG&E and other California utilities have faced credit rating

downgrades as a result of “wildfire risk unique to California.”268

And Mr. Gorman admits that those credit rating downgrades for SDG&E have come despite the 

Company not facing any significant wildfire liability for 2017 or 2018.269 

Yet all intervenors propose ROEs that are to varying degrees below the current national 

allowed average for electric utilities; in other words an ROE that would be more appropriate for 

a utility of below average risk. 

 Aaron Rothschild, PAO: proposes an ROE of 8.49 percent – while 

admitting that he is not aware of any ROE set that low for an electric or 

combined gas and electric utility in 2018 or 2019 – and agreeing that such 

an ROE would be over 100 basis points below the current allowed national 

average270 – which would result in SDG&E having the lowest allowed 

ROE in the country; 

 Dr. Marlon Griffing, UCAN/POC: admits that his recommendation of 

9.15 percent would put SDG&E “among the low end of ROEs for U.S. 

electric operating companies;”271

 O’Donnell: repeatedly states that SDG&E is riskier than national utilities 

and is incorporating a wildfire risk adder into his proposal – before 

proposing a ROE for SDG&E of 9.5% that is below the currently 

authorized national average;272

 

268 TURN/Gorman Exh. EPUC/IS/TURN-01 at V-10. 

269 TURN/Gorman Tr. V.3:394-95. 

270 Rothschild/PAO Tr. V.4:639-41; see also Morin/SDG&E Exh. SDG&E-09 at 4 (stating that he is not 

aware of any allowed return near Mr. Rothschild’s recommendation, which is “even more galling 

when considering the fact that SDG&E is among the riskiest, if not the riskiest, electric utility in the 

industry at this time.”). 

271 Griffing/UCAN Exh. UCAN/POC-01 at 47; see also Morin/SDG&E Exh. SDG&E-09 at 37 (“Dr. 

Griffing recommends a ROE of 9.15% for SDG&E, which I believe would be among the lowest 

authorized return in the vertically integrated electric utility industry, despite the fact that SDG&E’s 

risk exceeds the average risk in the electric utility industry at this time.” (citation omitted)). 

272 O’Donnell/FEA Exh. FEA-01 at 64, Table 25; see also O’Donnell/FEA Tr. V.3:361-362 (agreeing 

that the average authorized ROE for electric utilities has slightly increased in 2019 compared to 

2018). 

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Even Mr. Gorman’s suggested wildfire “risk premium” of 0.65 percent puts his ROE 

recommendation at 9.65 percent – just below the 2019 allowed national average – making it 

hardly a risk premium at all.273

These proposals not only ignore all the record evidence to the contrary – including the 

exceptional threat that SDG&E and other California utilities face from, among other things, the 

increased threat of wildfires, inverse condemnation, and outlier prudency review – they ignore 

the intervenors’ own admonitions that return must be set consistent with risk. As Concentric 

states, “[a]ll else equal, given the choice between a company with a low probability of wildfire 

costs being borne by shareholders, and a company with a high probability of wildfire costs being 

borne by shareholders, an equity investor will have different return requirements for an 

investment in each company.”274 

2. Once Intervenors’ ROE Proposals Modeling Errors Are Corrected, 

Intervenors’ Proposals are Near or Above Dr. Morin’s 

Recommendation 

Worse, as Dr. Morin ably demonstrated in his rebuttal testimony, once modeling flaws 

are corrected, the intervenors’ ROE recommendations are generally near or above that offered by 

Dr. Morin. Those errors include the following: 

Failure to use ECAPM: As Dr. Morin establishes, the empirical CAPM (“ECAPM”) 

model has been proven to be more accurate – as the traditional CAPM “underestimates the return 

required from low-beta securities and overstates the return from high-beta securities.”275 Dr. 

 

273 Compare Gorman/TURN Exh. EPUC/IS/TURN at II-Ex. MPG-3 (proposing an ROE for SDG&E of 

9.65%), with id. at pp. V-10-11, Table 10 (seemingly attempting to disavow his proposed .65% 

wildfire risk premium). 

274 Concentric/SDG&E Exh. SDG&E-12, Ch. 1 at 20. 

275 Morin/SDG&E Exh. SDG&E-09 at 23. 

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Griffing acknowledges that he has applied the ECAPM method at least 11 times.276 Application 

of the ECAPM method raises the intervenors’ CAPM recommendations by a minimum of 50 

basis points.277 

Use of the Sustainable Growth Method: This method is inherently flawed in 

estimating the cost of equity for a regulated utility because it is logically circular. It requires an 

analyst to assume the answer by making an assumption about the expected profitability of a 

regulated entity – when that entity can only achieve that level of profitability if its ROE is 

authorized at that level.278 In other words, it makes little sense to assume that a regulated utility 

will earn a 10.5 percent return and then recommend a 9 percent return.279 Dr. Morin notes that 

multiple intervenors gave no weight to this method.280

Failure to Use an Accurate Market Risk Premium: Dr. Morin’s market risk premium 

(“MRP”) forecast of 6.9% is consistent with the vast literature on the subject and has been used 

by him many years.281 By contrast, certain intervenors’ use of survey data to establish the MRP 

is problematic “because they are not reliable,” very time dependent, and dependent on the 

measure of return being surveyed.282 

 

276 Griffing/UCAN Tr. V.6:977. 

277 See, e.g. Morin/SDG&E Exh. SDG&E-09 at 8. 

278 Morin/SDG&E Tr. V.2:202. 

279 Id. at 202-203. 

280 Id. at 205. 

281 Morin/SDG&E Exh. SDG&E-09 at 61-63; Morin/SDG&E Tr. V.2:256. 

282 Morin/SDG&E Tr. V.2:257; see also Villadsen/SCE Tr. V.2:325:11-20 (“And as we also heard from 

Dr. Morin, there’s a number of difficulties using surveys. We don’t know what it is these individuals 

respond to . . . we don’t know who responds to it. It’s self selection who responds to these surveys. 

As I discuss in my rebuttal testimony, there’s academic literature that talks about why surveys are 

very doubtful.”). 

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Failure to Include Flotation Costs: Flotation costs reflect the payments a company 

must make to an underwriter to issue new stock. It is the equivalent to closing costs when 

buying a home.283 The basic logic is that, to produce the return on equity required by investors, 

ROE must be increased by 20 basis points or the company will never net the full required return 

once flotation costs are incurred.284 Notably, Dr. Griffing also supports their inclusion.285

Misguided Focus on Book Value: As Dr. Morin testified, book value is irrelevant in 

setting ROE. Stock prices are set by the market, not regulation.286 “Utilities have been trading 

[above] book value for 30 years.”287 The market for capital investment is a competitive one. 288 

If the Commission unilaterally set SDG&E’s ROE at book value it would take a “masochist[]” to 

invest in SDG&E stock when that investor could invest in other utility stocks trading above book 

value.289 As Dr. Morin states, “[i]f utility stocks have market-to-book ratios of one and 

everybody else has a two or three on the overall stock market, you’re going to be at a 

disadvantage in terms of attracting capital.”290 Instead “[r]egulators should set the rate of return 

equal to the cost of equity regardless of the market-to-book ratio which is determined by the 

marketplace.”291 

 

283 Morin/SDG&E Exh. SDG&E-09 at 12. 

284 Morin/SDG&E Tr. V.2:303-04; see generally Morin/SDG&E Exh. SDG&E-04 at Appendix B 

(discussing the academic and empirical literature on the need for flotation costs). 

285 See Morin/SDG&E Exh. SDG&E-09 at 39. 

286 Id. at 32; see also Morin/SDG&E Tr. V.2:211:7 (“The market sets the stock price.”).

287 Morin/SDG&E Tr. V.2:211:2-3; accord id. at 298:20-23. 

288 Morin/SDG&E Exh. SDG&E-09 at 34. 

289 See Morin/SDG&E Tr. V.2:298. 

290 Id. at 299:16-20. 

291 Id. at 298:17-20. 

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Incorrect Choice of The Risk-Free Rate: Although intervenors criticize using interest 

rate forecasts from a group of professional government and private organizations to set the riskfree rate because those forecasts have been too high in the past, Dr. Morin convincingly provides 

three reasons that such forecasts should be used in setting the risk-free rate in CAPM.292 First, 

financial models are forward looking in nature.293 Dr. Morin relies upon interest rate forecasts 

from professional forecasters because, as published academic studies show, regardless of 

whether those forecasts turn out to be accurate, those forecasts are reflected in investor 

expectations and embedded in stock prices.294 This is the same reasoning as to why multiple 

intervenor experts rely upon analyst growth forecasts in their DCF modeling.295 

Second, rates are being set for the future, so it is appropriate to rely upon future interest 

rate expectations.296 Third, if one applies current interest rates of around two percent to the 

CAPM model, the CAPM model will produce cost of equity estimates of around five percent.297 

As a practical matter, such a result cannot be accurate because it is inconsistent with observable 

data. It suggests that the cost of equity is nearly equal to the cost of debt – which would indicate 

 

292 Id. at 254. 

293 Id. 

294 Id. at 254-255; see also Morin/SDG&E Exh. SDG&E-04 at 20; Morin/SDG&E Exh. SDG&E-09 at 

17-18, 43, 69. 

295 See Morin/SDG&E Exh. SDG&E-09 at 78 (noting how Gorman relies upon wide variety of analyst 

growth forecasts but ignored those same sources for forecasts of risk-free rate); see also id. at 50 

(noting how Mr. O’Donnell’s DCF estimate is incorrect because it does not use analyst growth 

forecasts); Morin/SDG&E Exh. SDG&E-04 at 20 (noting that there is considerable empirical 

evidence in the academic literature that support the superiority of analysts’ forecasts of earnings per 

share as measures of investor expectations). 

296 Morin/SDG&E Tr. V.2:254. 

297 Id. at 255. 

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that investors should be flocking to long-term debt, given that debt is a safer investment.298 This 

is not what is being observed in reality. 

Dr. Morin acknowledges that, since conducting his analysis in early 2019, interest rates 

have declined.299 He believes that this would result in a relatively minor 10-20 basis point 

difference in his proposal, with the average ROE for his peer group going from 9.9 to 9.7, 

meaning that his ROE recommendation for SDG&E would go from 10.9 to 10.7 once his 100 

basis point risk premium is included.300 As Dr. Morin indicates, any decline resulting from 

interest rates is somewhat offset by an increase in the risk premium. In other words, there is an 

inverse relationship between interest rates and risk premium. As interest rates decline, the risk 

premium increases because investors become less willing to undertake equity investments and 

need a higher premium to do so.301

 

 

298 Id.; see also Concentric/SDG&E Exh. SDG&E-12 at 16 (“Equity financing carries no repayment 

obligation and is therefore much riskier than a debt investor’s position.”). 

299 Morin/SDG&E Tr. V.2:263:8-14 (“Short-term treasury bill rates have come down prompted by the 

Federal Reserve action. The long-term rates have also come down by a much lesser extent, but they 

have come down. The forecast that I use here have also come down a little bit for the long term.”);

see also id. at 272:21-23 (“[W]henever there’s lower interest rates, there’s a surge toward dividendpaying utility stocks.”). 

300 Morin/SDG&E Tr. V.2:263; accord id. at 270:6-16 (“Q: So just to clarify, what would your revised 

recommendation be for SDG&E if you re-ran your analysis now? A: 9.7. Q: How about [] the 

overall [recommendation] once your [risk] premium is included? A: 10.7”). Dr. Morin did not 

update his modeling in supplemental testimony, because the supplemental testimony was solely 

“regarding the passage of Assembly Bill 1054” and Dr. Morin’s revised estimates are because of a 

decline in interest rates, not because of AB 1054’s passage. 

301 Morin/SDG&E Exh. SDG&E-04 at 46-47; Morin/SDG&E Exh. SDG&E-09 at 82. 

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So if an analyst relies upon a lower long-term interest rate, they have to increase their risk 

premium.302 The Commission recognizes this inverse relationship and the fact that the cost of 

equity does not move in tandem with interest rates, with a long-standing practice of adjusting the 

cost of equity by one-half to two-thirds relative to the change in bond yields.303 

The decline in interest rates also does not account the risks unique to California – 

including the multiple credit rating downgrades for SDG&E that occurred after Dr. Morin 

conducted his analysis.304 Nevertheless, Dr. Morin’s revised estimate of a 10.7 percent ROE for 

SDG&E based upon the changed interest rate environment demonstrates his sound judgment and 

willingness to accept the record evidence as-is – compared to intervenors ignoring SDG&E’s 

unique and above-average risks. 

 

302 Morin/SDG&E Exh. SDG&E-09 at 82 (noting that Mr. Gorman failed to make this adjustment); 

accord Vilbert/PG&E Tr. V.4:579.

303 See D.99-06-057 at 49-50 (“the Commission has had a practice of only adjusting rate of return by one 

half to two thirds of the change in the benchmark interest rate.”) (citing D.94-11-076). 

304 See Widjaja/SDG&E Exh. SDG&E-03 at 12, Table 1 (listing credit rating downgrades for SDG&E by 

Fitch and Moody’s in March after Dr. Morin conducted his study). 

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3. Intervenors Ignore SDG&E’s Wildfire Risks and/or Overstate AB 

1054’s Impact 

To that end, intervenors also either try to ignore the full impact of California’s wildfire 

liability risk on SDG&E’s cost of capital or overstate AB 1054’s risk reduction impacts. For 

instance, Mr. O’Donnell contends that AB 1054 should “alleviate many of the concerns 

regarding prudency and, based on reactions by the credit agencies as discussed below, is very 

much welcomed by the financial community.”305 But Mr. O’Donnell acknowledges that 

Moody’s relies on Filsinger’s assumption that 75 percent of wildfire cost recovery claims will be 

found imprudent in 2020 – a far cry from Mr. O’Donnell’s other acknowledgement that he is not 

aware of FERC disallowing a claim for wildfire cost recovery.306 

And, as detailed above, credit rating agencies see continuing uncertainty in how AB 

1054’s revised prudency standard will be applied. As Moody’s states in its July 29, 2019 report 

– a report Mr. O’Donnell relies upon – “[f]ailure to successfully implement the provision[s] of 

AB 1054 associated with the insurance fund in a consistent and credit supported manner [would] 

likely trigger negative momentum on SDG&E’s [credit] rating.”307 In fact, Mr. O’Donnell 

acknowledges that SDG&E faces an equal chance of another credit downgrade as it does of an 

upgrade.308

Mr. Gorman similarly admits that it was a “stretch” by him to say that AB 1054 “fully 

mitigated shareholder risk arising from California wildfires,” acknowledging that RRA reduced 

 

305 O’Donnell/FEA Exh. FEA-02 at 11. 

306 O’Donnell/FEA Tr. V.3:370-71, 377. 

307 Id. at 371:8-15. 

308 Id. at 371:20-21. 

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its rating of California’s regulatory environment following AB 1054’s passage.309 As noted, Mr. 

Gorman proposes a wildfire risk “premium,” based upon what he states is the spread between Arated utility bonds and Baa-rated utility bonds.310 But the cost of debt is less than the cost of 

equity.311 Moreover, as Concentric notes, “equity investors bear the residual risk associated with 

ownership, and have a claim on cash flows only after debt holders are paid.” 312 Mr. Gorman’s 

suggestion is thus an “incomplete measure of the risks borne by equity investors” because “credit 

rating agencies clearly anticipated that some form of wildfire liability relief would be enacted 

and held off on further downgrades of California utility debt until the degree of relief was 

known.”313 

Some intervenors go even farther and try to ignore ongoing wildfire risks assessments. 

For example, Dr. Richard Pavolvic on behalf of UCAN/POC attempts to claim that AB 1054 

“fully mitigates SDG&E wildfire business, financial and regulatory risk.”314 Dr. Pavolvic further 

asserts that “[i]t appears that the rating agencies[’] interests have moved on from wildfire risk 

mitigation.”315 But as detailed above, while AB 1054 is a significant improvement, SDG&E 

continues to face risks both in AB 1054’s implementation and from the ongoing threat of 

 

309 Compare Gorman/TURN Tr. V.3:398:19 – 399:21, with Gorman/TURN Exh. EPUC/IS/TURN-01 p. 

V-1. 

310 See Concentric/SDG&E Exh. SDG&E-12, Ch. 1 at 15 (citing Gorman/TURN Exh. EPUC/IS/TURN01 at V-10:11 to V-11:8). 

311 D.12-12-034 at 8 (“[C]ommon equity financing is more costly than long-term debt and preferred 

stock financing.”). 

312 Concentric/SDG&E Exh. SDG&E-12, Ch. 1 at 16. 

313 Id. at 11-12 (citing S&P, Credit FAQ, Feb. 19, 2019, Exh. SCE-16). 

314 Pavlovic/UCAN Exh. UCAN/POC-07 at 2. 

315 Id. at 8. 

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wildfires and inverse condemnation – as credit rating agencies continue to recognize. In fact, Dr. 

Pavlovic acknowledges that: 

 RRA lowered its ranking of the California regulatory environment a 

month after AB 1054’s passage; 

 Moody’s on August 2, 2019 listed four ongoing credit challenges for 

SDG&E, one of which is the execution risk of the implementation of the 

revised prudency standard; and 

 Moody’s on August 6, 2019 stated that it did not view AB 1054 as a 

“complete” solution to California’s wildfire liability risks.316

At other times, Dr. Pavlovic asserts that “credit ratings cannot be relied upon as probative 

evidence of SDG&E’s business, financial, and regulatory risk.”317 But Dr. Pavlovic himself then 

admits that the cost of debt is based upon credit ratings (regardless of whether one agrees with 

their rating),318 and that Dr. Pavlovic himself takes credit rating agency assessments “into 

consideration in terms of my assessment of what the risk is.”319

SDG&E’s recent experience also refutes the claim from certain intervenors that wildfire 

risk is simply an issue of utility management.320 As discussed, SDG&E is widely acclaimed for 

its “track record of effective wildfire mitigation.”321 The Company has made “significant 

investments” to “mitigate and prevent” wildfire risks.322 SDG&E has not been involved in any 

 

316 Pavolvic/UCAN V.6:1001-1005; see also Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 5 

(stating that “it remains to be seen how challenging it will be for the intervenors to create serious 

doubt, an undefined term and subject to the CPUC’s interpretation.”). 

317 Pavlovic/UCAN Exh. UCAN/POC-07 at 2. 

318 Pavolvic/UCAN Tr. V.6:997. 

319 Id. at 998:13-15. 

320 See Folkmann/SDG&E Exh. SDG&E-07 at 7. 

321 Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 1. 

322 Id. at 5. 

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significant utility-related wildfires in 2017 or 2018. Indeed, SDG&E has not been involved in a 

significant wildfire since 2007.323 

Nevertheless, the Company’s credit rating has still been downgraded multiple notches 

due to California’s wildfire liability regime. As noted, S&P explicitly specified it was 

downgrading SDG&E’s business risk from “excellent” to “strong” despite SDG&E having 

excellent operational management.324 So despite SDG&E’s best efforts, the Company faces a 

higher cost of capital because of the regulatory environment, evidenced by, among other things, 

Sempra Energy’s higher beta, higher DCF, and SDG&E’s multiple credit rating downgrades.325

Nor can the risk from wildfire liability be quantified simply by comparing SDG&E’s 

credit rating to the credit rating of utilities in other states.

326 Multiple factors influence overall 

credit score, including the size of the company and the company’s financial leverage.327 A better 

comparison is within California itself, comparing credit rating agency assessments of SDG&E 

before and after: (1) the Commission’s 2017 WEMA decision; and (2) the 2017-2018 

wildfires.328 Such a comparison amply demonstrates that credit rating agencies now view 

 

323 S&P Feb. 21, 2019 Report, Exh. SCE-16 at 8. 

324 S&P Jan. 21, 2019 Report, Exh. PAO-03-C at 3 (discussing S&P’s assessment that inverse 

condemnation, combined with a California utility not having a “direct means to collect the wildfire 

costs from its ratepayers” is “inconsistent with an excellent business risk profile assessment.”); see 

also Concentric/SDG&E Exh. SDG&E-05, Ch. 2 at 18 (“[A]s the ratings agencies have repeatedly 

stated, the overall regulatory risk in California is the main reason for the rating actions.”). 

325 See Morin/SDG&E Tr. V.2:193-94; see also Concentric/SDG&E Exh. SDG&E-12, Ch. 1 at 12 (“The 

Company has a highly regarded wildfire mitigation program and has not been involved in a 

substantial wildfire since 2007. Yet it has experienced multiple credit rating downgrades and a higher 

cost of equity because of the overall regulatory environment.”). 

326 See, e.g., Hern/IEI Tr. V.4:617. 

327 Hern/IEI Tr. V.4:617. 

328 Id. at 618. 

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SDG&E and other California utilities as facing unique risks from the State’s wildfire liability 

regime that do not apply in other states.329

This change in credit rating assessments also underscore how this is a newly recognized 

risk that was not factored in to the 2012 cost of capital proceeding. Again, although inverse 

condemnation applied to California utilities prior to 2012, investor expectations were reset by the 

WEMA decision and the 2017-2018 wildfires. Those events signaled to investors that: “(1) 

wildfires of this size and magnitude could be the new normal; and (2) California utilities face a 

significant threat of being both responsible for significant costs under inverse condemnation and 

being unable to recover those costs under the Commission’s prudency review” when they would 

be able to in other jurisdictions.330 

In fact, the Commission’s 2012 decision explicitly specified that it was not compensating 

investors with a higher ROE for wildfire risks because “none of the credit agencies reporting on 

the creditworthiness of either SCE or SDG&E mentioned any risks associated with wildfires.”331 

That is obviously the exact opposite from the situation today, with extensive credit rating agency 

focus on California’s wildfire liability regime.332 In other words: 

 In D.12-12-034, with SDG&E having an S&P ‘A’ credit rating, the

Commission placed SDG&E’s ROE around the 2012 national average;333 

 

329 Id. at 615-17 (noting that, before late 2017, California utilities were treated similar to utilities in other 

states, but the scale of recent wildfires and WEMA decision changed perception of risk 

environment.). 

330 Folkmann/SDG&E Exh. SDG&E-11 at 3; accord Moody’s Aug. 6, 2019 Report, Exh. SDG&E-24-C 

at 2. 

331 D.12-12-034 at 30 (citation omitted). 

332 See Folkmann/SDG&E Exh. SDG&E-07 at 15; Folkmann/SDG&E Exh. SDG&E-11 at 3. 

333 Compare D.12-12-034 at 40 (setting SDG&E’s ROE at 10.30%), with RRA Jan 31, 2019 Report, 

Exh. SDG&E-25-C at 6 (noting that the average ROE set in 2012 for composite gas and electric was 

10.09%). Concededly, the Commission stated in D.12-12-034 that it believed it was setting 

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 Many of the risks cited in D.12-12-034 that justified the Company’s ROE 

at that time have only increased;334 and 

 Those risks have been joined by the overarching threat from catastrophic 

wildfire liability. 

So if SDG&E was considered around average risk with an S&P ‘A’ rating in 2012 and no 

credit rating agency focus on wildfire liability, it is self-evidently riskier now at ‘BBB+,’ with 

extensive credit rating agency discussion of the threat from California’s wildfire liability regime; 

indicating that the Company’s ROE must be adjusted upward for this unique risk.335 As Mr. 

Folkmann testified, “[r]educing SDG&E’s ROE below its current 10.20% (which is still within 

the range of ROEs granted for 2018-2019), would send exactly the wrong signal to credit 

agencies and equity markets.”336 The reasonableness of the authorized ROE and capital structure

in this proceeding will thus have “clear implications” for the assessment of California’s 

regulatory climate.337 

IV. CAPITAL STRUCTURE 

A company’s capital structure is based on its ratio of: (i) common equity; (ii) long-term 

debt; and (iii) preferred stock (if applicable). The capital ratios, together with the embedded 

costs associated with each component, determine the company’s weighted-average cost of capital 

 

SDG&E’s ROE “slightly below the 10.36% average ROEs granted [to] United State electric utilities 

during the first six months of 2012.” D.12-12-034 at 40. 

334 See, e.g., Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 6 (“Our analysis considers the 

significant demands that are placed on the California utilities, including many ambitious public policy 

initiatives that are implemented through utility operations.”).

335 See Folkmann/SDG&E Exh. SDG&E-07 at 15. 

336 Id. at 16 (citations omitted). 

337 Morin/SDG&E Exh. SDG&E-09 at 9-10; see also Folkmann/SDG&E Exh. SDG&E-01-S at 

Appendix E, p. 1 (current SDG&E credit rating “assumes” a credit supportive outcome in this 

proceeding). 

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or authorized ROR.338 An appropriate capital structure is a component of a fair and reasonable 

ROE and ROR.339 The common equity element of a utility’s capital structure represents the 

percentage of capital supplied by shareholders; the greater the common equity ratio, the more 

shareholders have at stake and the more they will require in return.340 Long-term debt represents 

a measurement of a company’s financial leverage.341 Finally, preferred stock is issued in shares, 

similar to common equity, but receives preferential treatment for dividends.342

A debt ratio that is too low fails to take advantage of a tax-deductible source of financing 

that is lower-cost than equity.343 However, a debt ratio that is too high (with an equity ratio that 

is too low) increases the risk of debt repayment to lenders, which could result in higher costs of 

capital over the long-term.344 Both scenarios can negatively impact ratepayers. Thus, setting the 

appropriate capital structure is not as simple as increasing the debt ratio and decreasing the 

equity ratio – there is a point at which a company becomes too financially leveraged and its 

credit rating suffers as a result. As the Commission has observed, “as long-term debt ratios are 

increased, credit ratings tend to be downgraded which results in increased financial risks for 

common equity holders, thereby requiring greater returns on common equity [the costs of which 

are borne by ratepayers].”345

 

338 Mekitarian/SDG&E Exh. SDG&E-02 at 1. 

339 D.08-05-035 at 7-8. 

340 Mekitarian/SDG&E Exh. SDG&E-02 at 2. 

341 Id. at 2. 

342 Id. at 3. 

343 Id. at 2. 

344 Id.

345 D.12-12-034 at 8-9. 

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Ms. Mekitarian explained, “[a]n optimal capital structure is one that supports a strong 

credit rating, lowering borrowing costs for the utility and ratepayers.”346 She noted that “[t]his 

generally involves a blend of debt and equity. Debt is generally less expensive than equity, due 

to its tax advantage and lower risk. But a high debt ratio increases financial risks because it 

means that a company has been aggressive in financing its growth with debt.” 347 As a practical 

matter, a company with a high level of debt and fixed costs will require a higher return on both 

debt and equity since the earnings available to shareholders are more volatile and secondary to 

debt payments.348 Thus, a company’s authorized capital structure must include a ratio of debt to 

equity that is designed to provide a reasonable return in order to attract necessary capital. As the 

Commission has made clear, “[b]ecause the level of financial risk that the utilities face is 

determined in part by the proportion of their debt to permanent capital, or leverage, we must 

ensure that the utilities’ adopted equity ratios are sufficient to maintain reasonable credit ratings 

and to attract capital.”349 

SDG&E’s current authorized capital structure was adopted in D.12-12-034 and has not 

changed in seven years, notwithstanding significant downgrades to SDG&E’s credit rating. 

SDG&E proposes a revised capital structure comprised of 56 percent common equity, 44 percent 

debt, and zero percent preferred stock – a change from the Company’s currently authorized 

capital structure of 52 percent common equity, 45.25 percent debt, and 2.75 percent preferred 

stock.350 As discussed in more detail below, SDG&E submits that this change in its capital 

 

346 Mekitarian/SDG&E Exh. SDG&E-02 at 3. 

347 Id.

348 Id. 

349 D.12-12-034 at 5. 

350 Mekitarian/SDG&E Exh. SDG&E-02 at 3. 

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structure is necessary to reflect SDG&E’s actual (recorded) capital structure since 2013, to 

facilitate SDG&E’s management of its financial risks, and to improve its credit ratings.351 

Until its recent downgrades due to the unprecedented business, financial, and regulatory 

risks currently faced by California utilities, SDG&E had always maintained a strong credit rating 

that benefitted ratepayers and shareholders alike.352 SDG&E’s historically strong credit rating 

has been the result of its effective and proactive management of its actual capital structure. As 

discussed in more detail below, this effective and proactive management continues today and is 

reflected in SDG&E’s higher common equity layer, which has allowed SDG&E to maintain its 

high credit rating (until recent downgrades) and issue over $2 billion of long-term debt since the 

last cost of capital proceeding.353 Mr. Folkmann noted that “SDG&E has been operating at or 

above a 56% equity percentage since 2015 . . . [and as] SDG&E has faced increased business 

risks, these higher than authorized equity levels have improved credit metrics by reducing debt 

throughout this period with capital provided by shareholders, directly benefitting customers and 

shareholders.”354 The higher common equity ratio established by SDG&E has allowed SDG&E 

to limit its financial risk and access the debt markets at more reasonable rates.355 Accordingly, 

SDG&E’s proposed capital structure, which reflects its actual capital structure, should be 

adopted by the Commission. 

 

351 Id.

352 Id. at 6. 

353 Id. 

354 Folkmann/SDG&E Exh. SDG&E-01 at 14. 

355 Mekitarian/SDG&E Exh. SDG&E-02 at 6-7. 

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A. Commission Precedent Supports an Authorized Capital Structure That 

Reflects Actual Recorded Ratios 

SDG&E’s recommended change in its capital structure to increase its authorized common 

equity ratio and decrease long-term debt and preferred stock ratios is designed to reflect 

SDG&E’s actual (recorded) capital structure.356 

As reflected in the chart below, SDG&E’s average recorded (actual) capital structure 

since 2013 has been more heavily weighted towards common equity than its authorized 

structure.357 SDG&E retained earnings in common equity to balance the capital structure above 

its authorized common equity ratio of 52 percent.358

Table 6: SDG&E’s Historical Capital Structure 

  2013  2014  2015  2016  2017  2018  Current 

Authorized 

Common 

Equity  53.39%  54.44%  57.55%  57.21%  55.61%  56.15%  52.00% 

Long‐Term 

Debt  46.61%  45.56%  42.45%  42.79%  44.39%  43.85%  45.25% 

Preferred 

Stock  0.00%  0.00%  0.00%  0.00%  0.00%  0.00%  2.75% 

SDG&E’s proposal to align its authorized capital structure with its actual cap structure is 

consistent with Commission precedent in favor of approving an authorized capital structure that 

tracks a utility’s actual ratios. The Commission noted in D.12-12-034 that it “has previously 

reasoned that the utilities should be given some discretion to manage their capitalization with a 

 

356 Id. at 4. 

357 Id. at 5 and Appendix B. 

358 Id. at 5. 

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view towards a balance between shareholders’ interest, regulatory requirements, and ratepayers’ 

interest.”359 In that proceeding, the Commission found that SDG&E’s proposal for an authorized 

capital structure was consistent with its actual equity ratio and was reasonable.360 Likewise, the 

Commission found in D.18-03-035 that it was reasonable to adopt authorized capital structures 

that reflected the relevant utilities’ actual equity and debt ratios.361 This policy in favor of 

adopting an authorized capital structure that aligns with a utility’s actual capital structure was 

described in a 2017 Report issued by the Commission’s Policy & Planning Division, which 

offered the guidance that “[i]n California, a hypothetical capital structure, which is expected to 

approximate the actual capital structure of the utility over the long run is used.”362 

B. The Proposed Capital Structure Helps SDG&E Manage its Financial Risks 

A prudent financial manager must be proactive in managing and mitigating financial risk. 

Dr. Morin explained that lower financial risks (i.e., lower debt) should be used to offset higher 

business risks.363 He noted further that “SDG&E’s capital structure should be more conservative 

than that of its peers in order to partially compensate for its higher business risks,”364 and 

 

359 D.12-12-034 at 11 (citation omitted). 

360 Id. (“SDG&E seeks a common equity ratio for its revenue requirement which is the same as its actual 

common equity ratio. We concur with SDG&E and find a 46.25% long-term debt, 2.75% preferred 

stock and 52.00% common equity capital structure reasonable and we adopt it.”). 

361 D.18-03-035 at 22. 

362 California Public Utilities Commission, Utility General Rate Case – A Manual for Regulatory 

Analysts (November 13, 2017) at 29, available at

https://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_Website/Content/About_Us/Organization/Div

isions/Policy_and_Planning/PPD_Work/PPD_Work_Products_(2014_forward)/PPD%20General%20

Rate%20Case%20Manual.pdf. 

363 Morin/SDG&E Exh. SDG&E-04 at 62. 

364 Id.

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concluded that it “is clear from these multiple perspectives that SDG&E’s 56% common equity 

ratio is barely adequate given its very high business risks.”365

As noted, SDG&E’s use of an actual equity ratio higher than its authorized one improved 

credit metrics by reducing debt and keeping SDG&E’s capital costs reasonable relative to the 

costs associated with the authorized ratios. The major credit rating agencies quantify financial 

risk using key metrics such as funds from operations as a percent of total debt (“FFO-to-Total 

Debt”)366 and debt as a percentage of total capital (“Debt-to-Total Capital”).367 Each of these 

metrics is discussed below. The credit rating agencies use these financial metrics, along with 

their assessment of business risk and regulatory framework, to assign credit ratings.368 Thus, the 

credit metric guidance provided by the credit rating agencies is an important tool for determining 

the appropriate use of debt. 

Recent guidance regarding FFO-to-Total Debt suggest that a greater level of debt for 

SDG&E would be viewed negatively. In its March 14, 2019 credit opinion, Moody’s specified a 

lower bound adjusted FFO-to-Total Debt ratio of 24 percent for SDG&E to avoid further 

downgrades from its current Baa1 rating.369 In the same credit opinion, Moody’s calculated 

adjusted FFO-to-Total Debt for SDG&E as of December 2018 of 25 percent. 370 Thus, in order 

 

365 Id.

366 “The FFO-to-Total Debt ratio measures funds from operations as a percent of total debt. It indicates 

how much of its debt a company could retire with annual cash from operations, where a higher figure 

indicates a stronger ability to retire its debt, and thus lower financial risk.” Mekitarian/SDG&E Exh. 

SDG&E-02 at 9. 

367 Id. at 8. 

368 Id. 

369 Moody’s Investors Service, San Diego Gas and Electric Company, Update Following Downgrade to 

Baa1 Negative (March 14, 2019) at 1. 

370 Id. at 1 and 7. 

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to maintain its strong adjusted FFO-to-Total Debt ratio, debt issued by SDG&E in order to fund 

the business will need to be countered with a higher equity ratio.371

With regard to the Debt-to-Total Capital metric, Moody’s approach to assessing credit 

risk for regulated electric and gas utilities globally is described in its Rating Methodology for 

Regulated Electric and Gas Utilities, which provides a detailed rating grid that can be used as a 

reference tool to approximate credit profiles within the regulated electric and gas sector.372 In 

her prepared direct testimony, Ms. Mekitarian presented the following table that replicates 

Moody’s Debt Ratio benchmarks presented in the report.373

Table 7: Moody’s Debt Ratio Benchmarks 

Bond Rating Debt / Capital374

Aaa < 25% 

Aa 25% - 35% 

A 35% - 45% 

Baa 45% - 55% 

Ba 55% - 65% 

B 65% - 75% 

Caa ≥75% 

 

371 Mekitarian/SDG&E Exh. SDG&E-02 at 9. 

372 Id. (citing Moody’s Investors Service, Rating Methodology for Regulated Electric and Gas Utilities 

(June 23, 2017)). 

373 Id. at 10, Table 4. 

374 Ratios shown are for companies that Moody’s has identified to have a standard risk profile. 

Id. at 10, n.17. 

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As Ms. Mekitarian notes, “[i]t is in the interest of ratepayers to preserve SDG&E’s credit 

profile and maintain a strong balance sheet to support planned infrastructure growth.”375 Dr. 

Morin has emphasized the importance of SDG&E regaining its single ‘A’ bond rating for this 

purpose. He explains that, “[a] single A bond rating generally results in the lowest pre-tax cost 

of capital for regulated utilities, and therefore the lowest ratepayer burden, especially under 

adverse economic conditions” – the “[l]ong-term achievement/retention of a single A bond rating 

is in both a utility’s and ratepayers’ best interests.”376 

The table above shows that for SDG&E to return to a strong single ‘A’ bond rating, it 

must maintain a debt ratio in the range of 35 percent – 45 percent. This is consistent with 

SDG&E’s actual/proposed debt ratio of 44 percent (with an equity ratio of 56 percent). As Dr. 

Morin adds, “[f]or a single A bond rating, which I consider optimal and cost efficient for 

ratepayers, the debt ratio range is 35% - 45%, implying a common equity ratio range of 55% - 

65%. The Company’s proposed common equity ratio is almost at the bottom of this range, 

notwithstanding the fact that its business risk far exceeds that of its peers.”377 As Dr. Morin 

points out, certain intervenors’ focus on the common equity ratios of utility holding companies is 

not a relevant comparison.378 Dr. Morin instead noted that the average common equity ratio for 

the operating utilities captured by his peer group is 53 percent - 54 percent, indicating that 

 

375 Id. at 7; see also D.12-12-034 at 7 (“SDG&E’s capital structure is intended to preserve its strong ‘A’ 

investment grade credit rating of long-term debt, to attract long-term debt at low costs, and to 

maintain financial strength for the long-term management of its capital investment program.”). 

376 Morin/SDG&E Exh. SDG&E-04 at 62-63; see also Morin/SDG&E Tr. V.2:249:16-20 (“We got to do 

everything we can to get back to a single A bond rating because it’s costing ratepayers an extra 10 

million bucks for every hundred million dollars of capital raised.”). 

377 Morin/SDG&E Exh. SDG&E-04 at 61. 

378 See Morin/SDG&E Exh. SDG&E-09 at 26. 

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SDG&E’s 56 percent request is more than reasonable once the Company’s higher risks 

compared to the peer group are taken into account.379 

By contrast, debt utilization beyond the 35 percent to 45 percent range indicated by the 

target credit metrics defined above (i.e., a debt ratio higher than the 44 percent proposed by 

SDG&E) would put downward pressure on SDG&E’s credit rating. Accordingly, Dr. Morin 

concluded that “the Company’s requested common equity ratio is reasonable as a partial offset to 

its heightened business risk and a necessary financial metric to regain a single A or above bond 

rating.”380 

As discussed above, SDG&E’s credit rating downgrades have required the Company to 

take proactive steps to mitigate risk and ensure the stability of the Company. Ms. Mekitarian 

noted that the current downward pressure on SDG&E’s credit rating “will be further exacerbated 

if the Company takes on additional financial risks, in the form of additional debt to fund its 

robust capital program and increased debt equivalence related to Power Purchase Agreements 

(“PPA”) and Resource Adequacy (“RA”) obligations.”381 Ms. Mekitarian explained that 

SDG&E’s proposed capital structure is necessary to lessen financial risks to counterbalance both 

increased business risk from California’s wildfire liability regime, as well as other non-wildfire 

risks that may increase the Company’s debt.382

Ms. Mekitarian highlighted a few of these latter risks. She summarized SDG&E’s risk 

related to debt equivalence associated with long-term PPAs (discussed above), and observed that 

 

379 Id. (citing Morin/SDG&E Exh. SDG&E-04 at 61). 

380 Id. at 47. 

381 Mekitarian/SDG&E Exh. SDG&E-02 at 11. 

382 Id. at 7. 

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“these agreements will continue to negatively impact SDG&E’s credit profile and must be 

appropriately factored into the authorized capital structure.”383 She pointed out that the 

Commission has acknowledged the risks associated with debt equivalence,384 and that SDG&E’s 

proposed capital structure (and ROE) are intended to comprehensively manage the impact of 

debt equivalence. 

Ms. Mekitarian further explained that the elevated levels of capital investment detailed by 

Mr. Widjaja385 will require substantial funding, both internally and externally, potentially 

through a combination of debt issuances, internally generated cash flow, and retained earnings 

by suspending its dividend payments.386 And Ms. Mekitarian pointed out that a higher common 

equity ratio is necessary to counter the Tax Cuts and Jobs Act (“TCJA”) of 2017 likely negative 

impact on utility credit ratings.387 Notably, for the first time in its history, Moody’s downgraded 

its outlook on the U.S. utility sector to “negative,” citing lower cash flows and higher debt levels 

as federal tax reform and increased capital spending continued to weigh on the sector.388 

C. SDG&E’s Proposed Capital Structure is Credit Supportive 

Moreover, recent credit rating agency publications signal that adoption of SDG&E’s 

proposed capital structure – i.e., authorization of the Company’s continued use of a 56 percent 

 

383 Id. at 12. 

384 Id. at 13 (citing as an example, California Public Utilities Commission, An Introduction to Debt 

Equivalency (August 4, 2017), available at

http://www.cpuc.ca.gov/uploadedfiles/cpuc_public_website/content/about_us/organization/divisions/

policy_and_planning/ppd_work/ppd_work_products_(2014_forward)/ppd%20-

%20intro%20to%20debt%20equivalency(1).pdf). 

385 Widjaja/SDG&E Exh. SDG&E-03 at 27-28. 

386 Mekitarian/SDG&E Exh. SDG&E-02 at 15. 

387 Id. at 13-14. 

388 Moody’s Investors Service, Regulated Utilities – US, 2019 Outlook Shifts to Negative Due to Weaker 

Cash Flows, Continued High Leverage (June 18, 2018) at 1. 

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common equity ratio – is necessary to support its credit rating. The credit rating agencies have 

focused on this issue because, as Ms. Mekitarian pointed out, they assess the financial risk of 

SDG&E based on its actual capital structure rather than its authorized capital structure.389 Thus, 

to credit rating agencies, SDG&E is effectively at a 56 percent common equity ratio today. 

While SDG&E’s 56 percent actual equity ratio is viewed positively by credit ratings 

agencies and has helped to prevent further downgrades, the credit rating agencies are watching 

closely for a signal from the Commission that it is supportive of SDG&E’s financial stability in 

light of its heightened business risks. The instant proceeding is the Commission’s first 

opportunity since setting the 52 percent equity ratio to revisit it and authorize a higher equity 

level. As Mr. Folkmann noted, since “this question is at issue in this proceeding, they are paying 

attention to the risk that, if not authorized, the equity layer could be reduced.”390 In other words, 

SDG&E’s higher-than-authorized equity ratio has been seen as necessary to ensure its financial 

stability – and also temporary, pending authorization of a higher equity ratio in this proceeding – 

so Commission rejection of the requested 56 percent equity ratio in this case could create 

significant negative impacts to SDG&E credit rating. 

As Ms. Mekitarian explained, “if the Commission were to approve an equity ratio below 

the 56 percent that we’re currently operating under, it would send a really strong signal to the 

credit rating agencies that potentially the Commission is not supporting the credit of the 

company.”391 Ms. Mekitarian notes further that such action by the Commission could be 

 

389 Mekitarian/SDG&E Exh. SDG&E-08 at 6; see also Widjaja/SDG&E Tr. V.4:758-59;

O’Donnell/FEA Tr. V.3:367:4-6 (stating that “[w]hat’s most important is what is the actual numbers 

that the company has in its books.”). 

390 Folkmann/SDG&E Tr. V.5:849:20-23. 

391 Mekitarian/SDG&E Tr. V.5:941:14-20. 

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interpreted by SDG&E’s management as not supportive of SDG&E’s efforts to manage the 

business prudently and prevent further downgrades.392 The possibility that SDG&E would 

respond to the Commission’s direction by lowering its common equity structure and becoming 

more leveraged as viewed by credit rating agencies,393 could put further downward pressure on 

the Company’s credit rating. 

Moody’s, for example, has indicated that SDG&E’s current credit rating and outlook of 

“Baa1” and “positive” assumes a “credit supportive” outcome in the instant proceeding. It has 

indicated that it may downgrade SDG&E further if a 56 percent equity ratio is not approved. 

Specifically, in its July 12, 2019 Report, Moody’s stated: 

Importantly, the Baa1 rating assumes a credit supportive outcome of 

SDG&E's ongoing 2019 general rate case and cost of capital proceeding 

where the utility requested an increase in its equity layer to 56% (effective 

January 2020) from currently 52%. The outcome of these regulatory 

proceedings will be important for SDG&E's ability to further generate a 

ratio of CFO pre-W/C to debt that comfortably exceeds 20% on a 

sustained basis.394 

Moody’s reiterated this point on July 29, cautioning that “[t]he positive outlook assumes . 

. . credit supportive outcomes of the utility’s ongoing regulatory proceedings. These proceedings 

include its 2019 general rate case and the cost of capital, w[here] a decision [is] anticipated 

before year-end 2019.”395 Moody’s further noted in its “Factors that Could Lead to a 

Downgrade” discussion that “[d]ownward pressure is also likely if SDG&E records credit 

metrics that are weaker than currently anticipated for example due to outcomes of pending 

 

392 Id. at 941. 

393 Widjaja/SDG&E Tr. V.4:759. 

394 Moody’s Investors Service, Rating Action: Moody’s Affirms San Diego Gas & Electric Company’s 

Ratings; Outlook Remains Negative (July 12, 2019) (“Moody’s July 12 Report”) at 2. 

395 Moody’s July 29, 2019 Report at 1. 

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regulatory proceedings that are not credit supportive.”396 On August 2, Moody’s listed 

“[r]egulatory uncertainty with delayed rate case and pending cost of capital proceedings” as one 

of SDG&E’s top “credit challenges,” again listing non-credit supportive outcomes in pending 

regulatory proceedings as potentially leading to downgrades.397 

A Commission decision to retain the 52 percent equity ratio would also force the question 

of whether it is sustainable for equity investors to continue to finance a portion of the business 

without earning a return on that portion of their investment.398 Currently, equity investors are 

earning a return only on the authorized equity layer of 52 percent, rather than the 56 percent 

SDG&E has been operating under.399 While, as discussed above, raising the equity ratio to 56 

percent was necessary to maintain the financial stability of the Company, it is unlikely that 

equity investors would look favorably on continuation of this reduction of their return. 

Thus, a decision in the instant case to maintain SDG&E’s current 52 percent equity layer 

would send a message that the Commission is not supportive of the actions SDG&E has taken to 

date to preserve its credit rating. Notably, intervenors admit that their capital structure proposals 

for SDG&E would alter the Company’s current authorized capital structure by increasing the 

Company’s debt-to-equity ratio (i.e., making SDG&E more leveraged).400 Commission approval 

of SDG&E’s proposed 56 percent equity ratio, on the other hand, “would send a strong signal to 

credit rating agencies [and] investors in the market that the Commission is supportive of 

 

396 Moody’s July 29, 2019 Report at 2. 

397 Moody’s Aug. 2, 2019 Report, Exh. SDG&E-23-C at 2. 

398 See Mekitarian/SDG&E Tr. V.5:944. 

399 Id. at 944; Mekitarian/SDG&E Exh. SDG&E-08 at 6-7. 

400 See, e.g., Gorman/EPUC/IS/TURN Tr. V.3:394; O’Donnell/FEA Tr. V.3:366; Griffing/UCAN/POC 

Tr. V.5:984 

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SDG&E’s strong credit rating.”401 Accordingly, the Commission should authorize SDG&E’s 

continued use of a 56 percent common equity ratio in order to ensure a credit-supportive 

outcome of this proceeding. 

V. EMBEDDED COST OF DEBT AND PREFERRED EQUITY 

As Ms. Mekitarian explained, “[t]he embedded cost of debt represents all the costs 

associated with the issuance and servicing of debt, expressed as a percentage of the net proceeds 

received from debt issuances.”402 SDG&E’s currently-authorized embedded cost of long-term 

debt is 4.59 percent; this is also SDG&E’s forecasted embedded cost of long-term debt.403 Thus, 

SDG&E requests no change to its currently-authorized cost of long-term debt. In keeping with 

past cost of capital proceedings, SDG&E recommends setting the authorized cost of debt equal 

to the forecasted embedded cost of debt during Test Year 2020.404 

With regard to preferred equity, Ms. Mekitarian noted that SDG&E no longer relies on 

preferred stock as a source of financing.405 She explained that “SDG&E redeemed all issued and 

outstanding shares of its preferred stock in 2013 and does not anticipate issuing any preferred 

stock in the foreseeable future, as reflected in its actual capital structure.”406 Accordingly, 

SDG&E proposes an embedded cost of preferred stock of 0 percent. No intervenor opposes 

SDG&E’s preferred stock proposal.407

 

401 See Mekitarian/SDG&E Tr. V.5:942:9-12. 

402 Mekitarian/SDG&E Exh. SDG&E-02 at 16. 

403 Id. 

404 Id. at 17 (reflecting the trading level of SDG&E’s most recently issued 30-year bond). 

405 Id. 

406 Id. 

407 See Gorman/EPUC/IS/TURN Tr. Vol. 3 at 394:8-10 (accepting SDG&E’s proposal to “modify its use 

of preferred equity). 

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VI. COST OF CAPITAL ADJUSTMENT MECHANISM 

In D.08-05-035, the Commission adopted a uniform multi-year CCM for SDG&E, SCE 

and PG&E. The CCM is intended to eliminate the need for utilities to file a cost of capital 

application on an annual basis; the mechanism allows utilities to file cost of capital applications 

every three years and provides a means of recalibrating a utility’s authorized ROE and ROR if 

certain market conditions are met in the intervening years.408 

As discussed in more detail below, SDG&E supports continued reliance on the CCM 

mechanism – indeed, no party to this proceeding suggests that the CCM should be discontinued – 

and proposes the following revisions and clarifications to the CCM intended to ensure that the 

goals underlying adoption of the mechanism are fully achieved: 

 Narrow the dead band trigger to 50 basis points from the currently 

authorized 100 basis points; 

 Clarify the method for selection of a CCM benchmark index when the 

utility has split ratings; 

 Clarify the process for filing of a capital structure adjustment application 

to address a credit rating change between full cost of capital applications; 

and 

 Provide guidance regarding actions to be taken if a utility’s credit rating is 

downgraded to non-investment grade. 

A. Operation and Purpose of the CCM 

During the three-year period between utilities’ cost of capital applications, the CCM 

operates to establish a deviation range or “dead band” tied to utility bond yields that, if triggered, 

automatically re-sets the utility’s authorized ROE and ROR. The CCM is currently based upon: 

 The most recently adopted authorized capital structure and embedded 

costs for long-term debt and preferred stock; 

 The benchmark index as Moody’s Utilities Bond Index, based on the 

utility’s credit ratings; 

 

408 D.08-05-035 at 15-16. 

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 A benchmark interest rate representing either: (a) the October through 

September average of the applicable Moody’s Utilities Bond Index from 

the Test Year (“TY”) of the most recently adopted Cost of Capital; or (b) 

the October through September average following a triggering event and 

corresponding effective date of an automatic adjustment to the authorized 

Cost of Capital structure; 

 A 100-basis point dead band such that within plus or minus 100 basis 

points from the benchmark interest rate, the mechanism will not trigger; 

and 

 an adjustment ratio of 50 percent (i.e., in the event of a triggering event 

and corresponding adjustment to ROE, the ROE will be adjusted by half 

of the difference between Moody’s Utility Bond Index and the benchmark 

interest rate.).409

If the dead band is triggered – i.e., if the difference between the current 12-month 

October through September average Moody’s utility bond index rate and the benchmark exceeds 

100-basis points – an automatic adjustment to the utility’s ROE and updating of the embedded 

costs of long-term debt and preferred stock is made through an October 15 advice letter to 

become effective on January 1 of the following year.410 Once triggered, the CCM would 

continue to operate with a revised benchmark interest rate equal to the 12-month (October to 

September) average interest rate that caused the CCM to trigger.

411 Authorized capital structure 

is not adjusted through the CCM; however, a utility may file a cost of capital application outside 

of the CCM process if certain conditions are met.412

The Commission explained in its decision adopting the CCM that the mechanism 

“balances the interests of [utility] shareholders and ratepayers while simplifying and reducing 

 

409 D.13-03-015 at Appendix A, pp. 3-4. 

410 D.08-05-035 at 15. 

411 Id. at 16. 

412 Id. 

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ROE proceedings, workload requirements, and regulatory costs.”413 It detailed the material 

benefits conferred by the CCM: 

This CCM streamlines the major energy utilities’ cost of capital process 

while providing greater predictability of the utilities’ cost of capital by 

eliminating the use of interest rate forecasts and disputes concerning 

interest rate levels and trends, as well as uncertainties associated with 

conflicting perceptions of financial markets and the return requirements of 

investors. The CCM also enables the utilities, interested parties, and 

Commission staff to reduce and reallocate their respective workload 

requirements for litigating annual cost of capital proceedings.414

The CCM is viewed positively by market participants and regulatory stakeholders. As 

Mr. MacNeil observed, “[c]redit rating agencies and banks – who regularly evaluate the financial 

condition of the utilities – have indicated their preference for the automatic rate-setting 

mechanism, since it provides greater clarity and transparency in understanding changes to a 

utility’s ROE compared to the uncertainty of trying to predict litigation outcomes. This in turn 

promotes a degree of desired stability.”415

B. Proposed Modification of Dead Band 

In order to protect the interests of both ratepayers and equity investors,416 the 

Commission should modify the current CCM dead band to ensure that it operates as intended. 

Specifically, the Commission should re-set the dead band trigger to 50 basis points from the 

currently authorized 100 basis points. 

There are several objectives underlying the CCM that must be considered in evaluating 

the appropriate dead band: 

 

413 Id. at 5. 

414 Id. at 16. 

415 MacNeil/SDG&E Exh. SDG&E-06 at 3. 

416 See D.08-05-035 at 5. 

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 reduce the time and costs associated with filing and litigating Cost of 

Capital proposals annually; 

 produce objective results through readily available historical rates that 

eliminate the need for interest rate forecasts (and related forecasting risk); 

 represent a simple, transparent, and non-controversial adjustment 

mechanism (i.e., automatic adjustment rather than adjustment by litigated 

outcome); 

 limit frequent or abrupt changes, while remaining sensitive enough to 

trigger when fluctuations in the bond markets necessitate an adjustment; 

and 

 provide timely ratemaking information to stakeholders and the financial 

markets.417 

As a practical matter, the CCM will successfully achieve these objectives only if it 

includes a dead band that is sufficiently responsive to market changes. The Commission has 

made clear that a dead band that fails to trigger in order to protect ratepayers and shareholders is 

problematic, noting that “[a] deadband that is overly sensitive to interest rates cause needless 

volatility in revenues and rates. Conversely, a deadband that never triggers can impose 

unnecessary costs on shareholders or ratepayers, depending on which direction interest rates 

move.”418 Thus, to be effective, the dead band must be set to achieve both of the aims described 

in D.08-05-035 – i.e., it must provide a reasonable level of stability, while being sensitive 

enough that it can serve its intended purpose of adjusting the ROE/ROR when necessary to 

achieve the objectives articulated by the Commission. As Mr. MacNeil pointed out, “[a] CCM 

that never triggers or does so only very rarely is tantamount to having no CCM at all.”419

SDG&E’s proposed 50-basis point dead band would improve the sensitivity of the CCM 

without a material reduction in stability. For example, analysis of data from 2001 to the present 

 

417 MacNeil/SDG&E Exh. SDG&E-06 at 2. 

418 D.08-05-035 at 11 (emphasis added). 

419 MacNeil/SDG&E Exh. SDG&E-10 at 3-4. 

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establishes that a 50-basis point dead band on the Moody’s A Utilities Bond Index would have 

triggered a total of five times during that period.420 A 50-basis point dead band on the Moody’s 

Baa Utilities bonds index would have triggered a total of eight times during the same period.421 

It is worth noting that in all cases but one, the triggers during the relevant period would have 

been downward, thereby benefitting ratepayers.422 

Over the same period, the current 100-basis point dead band would have triggered only 

three times for the Moody’s A Utilities Bond index and three times for the Moody’s Baa Utilities 

Bond index.423 The additional trigger events that would have occurred under the 50-basis point 

dead band versus the 100-basis point dead band were downward triggers that would have led to a 

reduction in ROE benefitting ratepayers.424 This illustrates the point that a 50-point dead band 

would achieve the Commission’s objective of protecting both ratepayers and utility 

shareholders.425 In addition, that “the proposed 50% adjustment ratio of a 50 basis point dead 

band allows for a smaller adjustment should a trigger event occur, thereby reducing ROE 

volatility as the result of triggering of the CCM and preserving stability.”426

Although PAO opposes modifying the CCM mechanism, they do not provide any 

analysis as to why the Commission should maintain the CCAM as-is without changes.427 Thus, 

 

420 MacNeil/SDG&E Exh. SDG&E-06 at 8. 

421 Id. 

422 Id. 

423 Id. 

424 Id. 

425 See D.08-05-035 at 5. 

426 MacNeil/SDG&E Exh. SDG&E-10 at 4. 

427 Kjensli/PAO-09, Exh. PAO-09 at 4. 

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the Commission should narrow the current dead band to 50 basis points in order to ensure that it 

aligns with the Commission’s intent to avoid a dead band that is insufficiently responsive.428

C. Proposed CCM Clarifications 

SDG&E requests that the Commission adopt the following proposals intended to clarify 

certain aspects of the current CCM: 

 The selection of a CCM benchmark index when the utility has split 

ratings; 

 Clarify the process for filing of a capital structure adjustment application 

between full cost of capital applications; and 

 Guidance for utilities with non-investment grade ratings 

The proposed clarifications “simply seek more explicit guidance on how the CCM should 

be understood by the Commission and all stakeholders. Such direction is necessary to avoid 

after-the-fact questions and later requests for clarification.”429

1. Clarification Regarding Split Credit Ratings Index Selection 

The CCM index to be applied in a given instance should be determined based upon the 

credit ratings of the relevant utility. In the event of split ratings430 where the agencies’ credit 

ratings are set at different levels, SDG&E proposes that the lowest rating be used to determine 

the applicable index for the CCM. As Mr. MacNeil explained, “this is appropriate because the 

lowest credit rating of the three credit rating agencies is known by the financial markets and is 

therefore reflected in competitive pricing of financial instruments.”431

 

428 See D.08-05-035 at 11. 

429 MacNeil/SDG&E Exh. SDG&E-10 at 5. 

430 MacNeil/SDG&E Exh. SDG&E-06 at Appendix A, which provides an illustration of split ratings. 

431 Id. at 12. 

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2. Clarification Regarding Ratings Change During CCM Years 

In D.08-05-035, the Commission directed that the CCM include a provision that enables 

the utilities to file an application to adjust their capital structure during the period between full 

cost of capital applications: 

Authorized capital structures should continue to be recalibrated in full cost 

of capital proceedings. However, while there will be a three-year interval 

between full cost of capital applications, we recognize that changes in 

credit ratings may require an adjustment to the utilities’ capital structure 

within that time period. Hence, a provision should be included in the 

CCM for utilities to file a capital structure adjustment application that 

addresses ratepayer impacts within that time period.

432

Given this express Commission direction, the process for submitting a capital structure 

adjustment application should be clarified. SDG&E proposes adoption of the following process: 

 A ratings change (upgrade or downgrade) that occurs over the October 

through September CCM measurement period of any year that affects the 

applicable Moody’s Utilities Bond Index for the CCM would allow for the 

utility to update the applicable Moody’s Utilities Bond Index for the 

following year; 

 The applicable Moody’s Utilities Bond Index is based on the company’s 

ratings as of September 30 of that ratings change year; 

 The benchmark rate resets based on the 12-month average of the Moody’s 

Utilities Bond Index for the period of October 1 through September 30 

preceding the change; and 

 Any rating change update will be made through filing an advice letter in 

October of the ratings change year to implement the revised index and 

benchmark rate for the CCM, to be effective in the following CCM 

measurement period.433

3. Guidance Regarding Downgrade to Non-Investment Grade Rating 

Given the risk of downgrade to non-investment grade status currently faced by SDG&E 

and other California utilities, SDG&E requests clarification and guidance regarding the actions 

 

432 D.08-05-035 at 8 (emphasis added). 

433 MacNeil/SDG&E Exh. SDG&E-06 at 12-13. 

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to be taken in the event of a downgrade to below investment grade. SDG&E proposes that such 

a downgrade event trigger the use of a “Modified CCM”434 whereby: 

 The traditional CCM utility bond index trigger is suspended; 

 The authorized ROE remains in place and the authorized capital structure 

is not adjusted. But a utility would retain the currently authorized option 

to adjust its capital structure via a separate application related to the 

change in credit rating; 

 The costs of long-term debt and preferred stock would be updated to 

reflect the actual August month-end embedded costs, forecasted interest 

rates for variable long-term debt and new long-term debt and preferred 

stock schedule to be issued; 

 A Tier 2 advice letter would be filed in October of the downgrade year, to 

be effective January 1 of the following year; 

 Beginning the year immediately following the initial downgrade year, the 

costs of long-term debt and preferred stock would continue to be trued up 

annually in the same manner as in the downgrade year, until the first of: 

(1) the next full Cost of Capital proceeding; or (2) an upgrade of credit 

ratings back to investment grade; 

 An upgrade from non-investment grade to investment grade would trigger 

the re-instatement of the traditional CCM. The annual cost of debt and 

preferred stock true up would cease; and 

 Such an upgrade would not trigger an automated ROE adjustment. 

Instead, it would set the applicable CCM index and benchmark rate, with 

the 12-month October through September average Moody’s utility bond 

rates of that upgrade year becoming the new benchmark.435

VII. CONCLUSION 

For the reasons set forth above, the Commission should authorize: (i) an ROE of 12.38 

percent for SDG&E’s electric and gas distribution operations; (ii) a cost of long-term debt of 

4.59 percent and a proposed cost of preferred stock of zero percent; (iii) a capital structure for 

SDG&E’s CPUC-jurisdictional ratebase of 56 percent common equity, 44 percent long-term debt 

and zero percent preferred stock; (iv) an overall ROR of 8.95 percent for TY 2020; (v) the 

 

434 Id. at Appendix D, which contains additional analysis of the proposed Modified CCM. 

435 Id. at 13-14. 

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modification and clarifications to the existing CCM proposed herein; and (vi) all other relief that 

is reasonable and necessary. SDG&E reserves the right to request oral argument. 

Respectfully submitted, 

By: /s/ Ross R. Fulton 

Ross R. Fulton 

ROSS R. FULTON 

AIMEE M. SMITH 

8330 Century Park Court 

San Diego, California 92123 

Telephone: (858) 654-1861 (Fulton) 

Telephone: (858) 654-1644 (Smith) 

Facsimile: (619) 699-5027 

Email: rfulton@sdge.com 

 amsmith@sdge.com 

Counsel for 

SAN DIEGO GAS & ELECTRIC COMPANY 

September 30, 2019 

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