20240531Direct F. Graves.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-24-04
OF ROCKY MOUNTAIN POWER FOR )
AUTHORITY TO INCREASE ITS RATES ) DIRECT TESTIMONY OF
AND CHARGES IN IDAHO AND ) FRANK GRAVES
APPROVAL OF PROPOSED )
ELECTRIC SERVICE SCHEDULES AND )
REGULATIONS )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-24-04
May 2024

1 I . INTRODUCTION AND QUALIFICATIONS
2 Q. Please state your name, position, and business address .
3 A. My name is Frank Graves . I am a Principal at The Brattle
4 Group, located in our headquarters office at One Beacon
5 Street, Suite 2600, Boston, Massachusetts 02108 .
6 Q. On whose behalf are you submitting this direct
7 testimony?
8 A. I am submitting this direct testimony before the Idaho
9 Public Utilities Commission ("Commission") on behalf of
10 PacifiCorp d/b/a/ Rocky Mountain Power (the "Company") .
11 Q. Please describe your education and professional
12 experience.
13 A. For most of my career spanning over 30 years as a
14 consultant, I have worked in regulatory and financial
15 economics, especially regarding long-range planning for
16 electric and gas utilities, and in litigation matters
17 related to securities litigation and risk management. My
18 education includes an M. S . with a concentration in
19 finance from the M. I .T. Sloan School of Management in
20 1980, and a B.A. in Mathematics from Indiana University
21 in 1975 .
22 In regard to forecasting and mitigating utility
23 risks, which are central matters in this case, I have
24 extensive experience in all aspects of utility system
25 planning, regulatory policy and market modeling,
Graves, Di 1
Rocky Mountain Power

1 financial and ratemaking practices, and formal risk
2 management techniques . Recently, I have focused on
3 evaluating pathways to deep decarbonization of the
4 energy sector, including the impacts of much greater
5 reliance on renewable generation and distributed energy
6 resources . I have developed, evaluated, or used many
7 power system production and resource planning models as
8 well as utility financial projections for revenue
9 requirements and alternative rate design purposes, and
10 I have evaluated financial risk and cost of capital in
11 a wide variety of settings for energy infrastructure and
12 utility investments . I have given expert testimony on
13 financial and regulatory issues before the Federal
14 Energy Regulatory Commission ("FERC") , many state
15 regulatory commissions, and state and federal courts . My
16 background and qualifications are described in greater
17 detail in the resume attached as Exhibit No . 18 .
18 I am also sponsoring the following exhibits :
19 Exhibit No . 18—Resume of Frank Graves
20 Exhibit No . 19—Area Burned from Human Caused
21 Wildfires in the West
22 Exhibit No . 20—Costs of +$1 Billion Wildfires in the
23 United States
24 Exhibit No . 21—Recent Costs of Wildfire Insurance
25 Faced by Regional Utilities
26 Exhibit No . 22—Recent Wildfire Insurance Cost
27 Recovery Settlements Achieved by Regional Utilities
Graves, Di 2
Rocky Mountain Power

1 Q. Have you appeared as a witness in previous regulatory
2 proceedings?
3 A. Yes . I have testified many times before other public
4 utility commissions in approximately 35 states as well
5 as before the FERC. Though not in Idaho, on several
6 occasions I have previously testified on behalf of Rocky
7 Mountain Power regarding fuel forecasting, procurement
8 and hedging, incentives, and cost recovery mechanisms . '
9 More generally, I have participated in many rate cases,
10 prudence hearings, regulatory policy forums and
11 sometimes litigation on industry transitions and new
12 issues on such matters as power industry restructuring
13 via vertical unbundling, retail competition and Provider
14 of Last Resort service design, natural gas hedging
15 practices, extreme (cold) weather preparedness, and the
16 associated utility investment and business practices .
17 II . PURPOSE OF TESTIMONY AND SUMMARY CONCLUSIONS
18 Q. What is the purpose of your direct testimony in this
19 case?
20 A. The purpose of my testimony is to provide context for
21 the need and appropriateness of current PacifiCorp
22 initiatives to manage the growing risk of financial
23 exposure to wildfire-related liabilities as described in
' See e.g. , Docket No. 11-035-200 in Utah, Docket No. 20000-405-ER-11 in
Wyoming.
Graves, Di 3
Rocky Mountain Power

1 the testimony of Company witness Joelle R. Steward.
2 These initiatives include the following regulatory
3 approaches :
4 • An Insurance Cost Adjustment that will recover the
5 volatile and rapidly increasing annual costs of
6 insurance for excess liability (from wildfire damages to
7 third party properties and well-being) , and
8 • A new Insurance Mechanism allowing PacifiCorp to insure
9 against non-catastrophic levels of third-party wildfire
10 liabilities using the most economical combination of
11 commercial insurance and self-insurance, to the extent
12 commercial insurance is available .
13 • A Catastrophic Fire Fund that will involve creation of
14 a multi-state risk pool for rare but potentially
15 catastrophic fire events where third-party liabilities
16 could be well in excess of the Company' s coverages for
17 more ordinary levels of risk. This "tail risk" coverage
18 is necessary to preempt extreme financial distress that
19 could otherwise threaten the viability or quality of
20 ongoing utility service .
21 Toward this objective, I review metrics indicating
22 the scope of increased wildfire risk affecting the
23 Western United States ("U. S . ") , the resulting financial
24 exposure faced by regional electric utilities, the
25 experience of those utilities in managing that financial
Graves, Di 4
Rocky Mountain Power

1 exposure, and related implications for PacifiCorp' s
2 proposed remedies .
3 Q. Please summarize the principal conclusions of your
4 direct testimony.
5 A. I find that the structure and evolving terms of
6 PacifiCorp' s proposed remedies to growing wildfire
7 exposure are reasonable based on strong and readily
8 observable growing trends and threats of wildfires and
9 the resulting financial exposure . This risk coincides
10 with increasing limitations (high cost, limited
11 availability) of traditional risk management tools to
12 address such large exposures, and the resulting
13 development of new precedents for coping with this
14 problem that have been established in other
15 jurisdictions, particularly California.
16 More specifically, this conclusion is premised on the
17 following:
18 • PacifiCorp is facing an exogenous, largely climate-
19 induced fire-risk phenomenon. Growing wildfire risk
20 is similarly afflicting many other electric
21 utilities and society at large .
22 • With wildfire risks mounting, the demand for
23 wildfire insurance has been expanding at the same
24 time as the supply of insurers willing or able to
25 bear wildfire risk (and catastrophic climate-event
Graves, Di 5
Rocky Mountain Power

1 risk generally) is contracting or being exhausted.
2 Unsurprisingly, the current supply/demand
3 imbalance is resulting in much higher costs per
4 dollar of coverage . Company witness Mariya V.
5 Coleman discusses the challenges of procuring
6 excess liability insurance for the 2024-2025 policy
7 year.
8 • Electric utilities in the western U. S . have both
9 (i) faced dramatic increases in the levels and
10 unpredictability of wildfire insurance costs, and
11 (ii) crafted workable solutions for those costs in
12 recent rate-case proceedings . These solutions
13 appropriately recognize wildfire insurance as a
14 legitimate cost of service and form useful
15 precedents for PacifiCorp' s recovery of such costs .
16 • As a separate matter, to the degree commercial
17 insurance markets may become dysfunctional—e .g. , if
18 insurance premia offered to PacifiCorp rise to
19 levels in excess of statistically expected losses,
20 or if the availability of such insurance should
21 simply dry up to where it is not possible to obtain
22 sufficient incremental coverage—it may make sense
23 to replace or supplement commercial insurance with
24 self-insurance (which formed the basis for recent
25 settlements in California) . PacifiCorp is thus
Graves, Di 6
Rocky Mountain Power

1 developing a proposal for contingent authorization
2 to substitute self-insurance for commercial
3 insurance .
4 • Importantly, even with any level of available
5 commercial insurance (or self-insurance in
6 substitution thereof) , PacifiCorp still faces the
7 risk of rare but catastrophic exposure to
8 unprecedented levels of extreme wildfire loss
9 claims that I understand may be uninsurable at any
10 cost in commercial markets . Such worst-case events
11 could be crippling to PacifiCorp' s financial
12 stability and potentially disruptive to normal
13 utility operations . PacifiCorp is therefore
14 additionally proposing a Catastrophic Fire Fund-
15 above and beyond customary coverage—to absorb such
16 extreme losses . (The precise boundary of where to
17 begin such coverage, and how far to extend it into
18 the highest-cost conceivable outcomes, has not been
19 determined, but is a topic in ongoing workshops .
20 Here the purpose is to gain recognition of this
21 need and to create a structure for eventually
22 dealing with it. ) Like all insurance, this extreme-
23 event protection is desirable because it provides
24 liquidity for responding to such events, and
25 because it distributes the costs of their possible
Graves, Di 7
Rocky Mountain Power

1 occurrence more smoothly and broadly over time and
2 geography, i .e . diversifying risk.
3 • Subject to compliance with reasonable mitigation
4 standards, extreme wildfire loss claims (if they
5 occur) should be viewed as costs of utility service
6 recoverable from customers (just as insurance
7 premia normally are) . This is because such losses
8 are an unavoidable residual risk that cannot be
9 fully eliminated under any rational level of prior
10 insurance and any associated utility management
11 practices for mitigating such risks over time, for
12 several reasons : It is unrealistic to expect that
13 PacifiCorp (or any other utility) could fully avoid
14 extreme wildfire losses through physical mitigation
15 alone, which is limited by the extreme difficulties
16 of anticipating extreme weather, vast geography,
17 the time required to develop mitigation systems,
18 finite capital resources (and related concerns
19 about customer bill impacts from extreme mitigation
20 efforts) , and diminishing marginal returns to
21 wildfire mitigation investment . Put another way,
22 mitigation can reduce but not eliminate the
23 likelihood of fire events, while external
24 circumstances largely determine the resulting
25 damage from them.
Graves, Di 8
Rocky Mountain Power

1 • Customers and regulators themselves will also
2 recognize these factors in resisting large upfront
3 costs for wildfire mitigation or very extreme
4 contingency insurance . Wildfire insurance and
5 prevention efforts must be integrated and balanced
6 with all the other objectives and constraints of
7 providing reliable utility services at reasonable
8 rates . Thus, some form of agreed, socialized cost
9 recovery for these adverse possible situations
10 should be developed before they arise .
11 Importantly at this time, PacifiCorp is working with
12 fire liability risk assessment and insurance
13 professionals to update and extend its understanding of
14 the magnitude of possible wildfire liability risk that
15 could affect its service territories .
16 III . REGIONAL WILDFIRE RISK AND COST ARE GROWING
17 Q. Please describe the landscape of wildfire occurrence in
18 the West and beyond in recent years .
19 A. Wildfire risk is a growing and menacing global
20 phenomenon, which has had a material adverse impact on
21 diverse businesses and individuals far beyond Idaho in
22 recent years and months . Major wildfire risk zones have
23 been identified in geographies as diverse as Europe,
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1 Australia, Canada, South America, and the Western U. S . 2
2 In North America, wildfire risk has become a chronic
3 issue, i .e . , more frequent, larger, and more
4 consequential (similar to other climate-driven natural
5 disasters in the rest of the U. S . and around the world) .
6 For example, recent analysis of human-caused wildfires
7 in the West by the National Interagency Fire Center shows
8 an approximately four-fold increase from 2001 to 2023 in
9 acres burned annually (see also Exhibit No. 19) . 3 Across
10 the western states experiencing this trend, most major
11 events have been centered around California, but large
12 human-caused fires have also occurred in the Pacific
13 Northwest and Idaho (i .e . the 2022 Moose Fire outside
14 Salmon) .
15 In response to the increase of wildfire events in
16 the West and other climate change related events
17 throughout the country, utilities have experienced
18 credit rating consequences . Specifically, investor-
19 owned utilities and publicly owned utilities in
20 California and Hawaii have experienced actual downgrades
21 due to wildfire risk, while utilities that operate in
2 https://www.marshmclennan.com/insights/publications/2019/oct/wildfire-
paper--oct--2019-.html.
3 National Interagency Fire Center, "Wildfires and Acres, " May 24, 2024,
https://www.nifc.gov/fire-information/statistics/human-caused. The west
includes the Northwest, California, Northern Rockies, Great Basin, and
Southwest regions.
Graves, Di 10
Rocky Mountain Power

1 Colorado, Idaho, Oregon, Washington, and Utah have been
2 issued negative rating outlooks . 4
3 Q. How has this increase been correlated with the growth in
4 other extreme weather events?
5 A. The increasing frequency and severity of wildfires has
6 occurred in parallel with climate change generally, as
7 well as other climate-related natural disasters such as
8 floods, hurricanes, and severe cold-weather storms . It
9 is intuitive that wildfire risk can be both widespread
10 and increasingly severe and damaging, since it is
11 largely a function of the effects of climate change
12 interacting with residential and commercial growth in
13 locations already prone to ignition (the so-called
14 wildland-urban interface, or WUI) . Conditions such as
15 high temperatures and low precipitation have been linked
16 to extended fire seasons, exacerbating weather
17 conditions such as high winds, and near inability to
18 predict the behavior of individual fires . 5 The growth in
19 the overall burden of extreme weather events makes
20 insuring any of them more difficult .
21 Q. What about the cost impact of wildfires?
22 A. The cost impact of wildfires has grown with the frequency
4 S&P Global Ratings, A Storm is Brewing: Extreme Weather Events Pressure
North American Utilities, Credit Quality (Nov. 9, 2023) .
5 Next-Generation Fire and Vegetation Modeling for a Hot and Dry Future,
Federation of American Scientists, June 20, 2023.
Graves, Di 11
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1 and scope of physical impacts . Globally, the reported
2 annual economic losses from wildfires have more than
3 doubled since 2015 relative to the prior 15 years . 6 This
4 step-change is even more pronounced for the U. S . , where,
5 comparing the same time period, economic losses have
6 increased five-fold, and in some years amounted to many
7 tens of billions of dollars (see Exhibit No . 20) . 7
8 Q. How have affected utilities insured against this risk?
9 A. Utilities have customarily obtained commercial insurance
10 to cover multiple types of extreme event liabilities
11 that can cause third-party damages and injury, including
12 wildfires, on a bundled basis . In limited instances,
13 utilities have augmented commercial insurance with
14 capital market instruments to cover highly specified
15 risks such as wildfires in the form of so-called
16 "Catastrophe Bonds . " More recently, as further described
17 below, utilities in California have turned to self-
18 insurance specifically for wildfires .
19 Q. How has the growth in extreme events affected the
20 availability of commercial insurance?
21 A. Risks stemming from both climate change generally and
22 wildfires specifically have contributed to a tightening
6 Aon, 2023 Weather, Climate and Catastrophe Insight.
National Oceanic and Atmospheric Administration - National Centers for
Environmental Information U.S. Billion-Dollar Weather and Climate
Disasters (2023) , https://www.ncei.noaa.gov/access/billions/state-
summary/US.
Graves, Di 12
Rocky Mountain Power

1 of coverage availability provided by the commercial
2 insurance industry. The industry has noted that "many
3 risk buyers [seeking insurance coverage] are challenged
4 to find adequate coverage for their natural catastrophe-
5 prone exposures . "8 In response to significant and severe
6 losses and "limitations" in effectively modeling future
7 catastrophes (which are statistically difficult to
8 characterize, because they are both rare and extreme) ,
9 many insurance providers have chosen to "de-risk or
10 withdraw" from offering certain coverages . 9 Others are
11 hitting financial limits on their ability to diversify
12 or fund their own coverage offerings, so prices can
13 skyrocket . The problem appears to be anxiety over the
14 rising frequency and costs of fire events and the
15 correlated problems with other climate-related risks . 10
$ Aon, Climate and Catastrophe Insight, at 29 (2024) .
9 Howden, The Great Realignment at 14 (2023) , accessed at
https://www.howdengroup.com/sites/g/files/mwfley566/files/2023-01/the-
great-realignment-report-2023.pdf. See also, p. 11: "Persistent and
elevated catastrophe losses, along with the attendant issue of catastrophe
model efficacy, continued to drive sentiment in property lines amidst
concerns that changing weather patterns are increasing both the frequency
and severity of climate-sensitive perils. Higher retentions, tighter
terms and reduced frequency coverage (i.e. aggregates, lower excess-of-
loss layers, quota shares) reflected reinsurers' resolve to focus more on
capital protection after six consecutive years of above-average
catastrophe losses."
io See, Claire Wilkinson, Utilities contractors challenged in finding
wildfire coverage, Business Insurance, accessed at
https://www.businessinsurance.com/article/20210525/NEWS06/912342050/Uti
lities-contractors-challenged-in-finding-wildfire-coverage: "The lack of
interest from the marketplace to cover wildfire risks, in general, has
`spread like a wildfire' beyond California and throughout the country...".
Graves, Di 13
Rocky Mountain Power

1 Q. Have these climate change and wildfire risks affected
2 the availability of commercial insurance for electric
3 utilities, including for PacifiCorp?
4 A. Yes . PacifiCorp has encountered recent difficulty in
5 obtaining wildfire liability insurance . As explained by
6 Company witness Coleman, insurers who historically would
7 consider selling wildfire liability will no longer do
8 so .
9 This experience is hardly unique to PacifiCorp or
10 other Berkshire Hathaway Energy entities . In the course
11 of its 2023 general rate case ("GRC") process, Pacific
12 Gas & Electric Company ("PG&E") reported that "there has
13 been a significant decrease in the number of insurers
14 offering wildfire coverage to California [investor owned
15 utilities ("IOUs") ] . "11 This situation has led to PG&E
16 receiving anemic insurance company responses to recent
17 wildfire insurance solicitations, reporting only 16
18 offers to 73 inquiries in 2021 . 12 The trend was observed
19 as early as 2017, when Southern California Edison
20 ("SCE") was already noting a "diminishing general
21 liability and wildfire insurance market in California
ii Application of Pacific Gas and Electric Company for Authority, Among
Other Things, to Increase Rates and Charges for Electric and Gas Service
on January 1, 2023, Application (A. ) 21-06-021, Exhibit 9, Chapter 3 at
3-23.
i2 Id., p. 3-26.
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1 for investor-owned utilities, to the extent even
2 available . "13
3 Q. How has increased wildfire risk affected the cost of
4 commercial insurance?
5 A. Increased wildfire risk has led to sharp increases in
6 the cost of wildfire liability insurance for utilities .
7 Company witnesses Coleman and Steward address the cost
8 increases experienced by PacifiCorp. This reflects both
9 the increasing burden on the insurance industry from
10 rising claims and the much more difficult risk
11 estimation that has accompanied the global warming
12 aspects of the problem. For instance, the current
13 wildfire operational models are deemed "incapable" of
14 simulating and accounting for the "substantial ecosystem
15 changes that are occurring from climate change . "14 This
16 is occurring because there are too many factors changing
17 rapidly (e.g. soil dryness, number of extremely high
18 temperature days, unusually concentrated rainfall,
19 disease or pest infestation in plants and trees, etc . )
13 Letter from Russell G. Worden to Timothy J. Sullivan, "Letter of
notification establishing a Z-Factor for costs associated with
incremental wildfire-related liability insurance," at 2-3 (Dec. 29,
2017) .
14 Matthew Hurteau, Next-Generation Fire and Vegetation Modeling for a Hot
and Dry Future, Federation of American Scientists (June 20, 2023) ,
accessed at https://fas.org/publication/next-generation-fire-and-
vegetation-modeling-for-a-hot-and-dry-future/.
Graves, Di 15
Rocky Mountain Power

1 for which history does not provide sufficient evidence
2 of their consequences or interactions . 15
3 While frequently not made public, some wildfire
4 insurance costs and coverage levels have been made
5 available in financial and regulatory filings by the
6 California IOUs . More limited insurance data has been
7 provided by other utilities in the west, such as Avista
8 Corporation ("Avista") and Idaho Power Company ("Idaho
9 Power") in the course of their regulatory filings . Such
10 insurance cost data is summarized in Exhibit No. 2116 and
11 placed in context relative to insurance coverage levels
12 (where available) and operating and maintenance ("O&M")
13 expense . 17
14 • PG&E — PG&E has experienced the sharpest cost
15 increases, with wildfire liability insurance costs
16 growing by approximately a factor of ten since 2017
17 in both absolute terms and costs per dollar of
18 coverage . 18 For the period 2022-2023, PG&E' s
19 wildfire liability insurance expense stood at $745
20 million, for coverage of $940 million. 19 Thus, for
21 that period, PG&E was paying an effective wildfire
is Id.
16 Note that regulatory orders approving the recovery of self-insurance
costs are summarized below in Section V(A) .
17 Specifically, 0&M costs omitting fuel and purchased power.
19 A. 21-06-021, California Public Utilities Commission ("CPUC") Decision
("D.") 23-01-005 at Table 2 (Jan. 17, 2023) (the "PG&E Decision") .
19 Id.
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1 liability insurance premium of 79 percent of the
2 coverage ! PG&E' s wildfire liability insurance
3 expense for 2022-2023 comprised approximately
4 eight percent of its total 0&M expense for calendar
5 2022, versus approximately only 1 percent in 2017 . 20
6 (This highlights not just the need for new
7 insurance mechanisms, but the need for their costs
8 to be efficiently recovered in cost of service
9 rates . )
10 PG&E noted in its 2023 GRC application that
11 "the difficulty of managing the company' s risks
12 through the commercial insurance market alone
13 continues to be extremely challenging as does the
14 prospect of accurately forecasting the costs to do
15 so . "21 Among other things, the new market conditions
16 mean that "PG&E now procures most of its wildfire
17 coverage separately from coverage for other perils,
18 essentially creating two different insurance
19 towers—one for wildfire and one for non-wildfire . "22
20 • SCE — SCE has experienced similar, if less extreme,
21 increases in wildfire insurance costs, with costs
22 per dollar of coverage doubling since 2018, to
20 By comparison, PG&E's wildfire liability insurance expense for 2022-
2023 formed a significantly larger share—approximately 30%--of the
company' s authorized return on equity.
21 A.21-06-021, Application, Exhibit 9, Chapter 3 at 3-24.
22 Id. , at 3-23.
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1 43 percent for the 2022-2023 period. 23 SCE' s
2 wildfire liability insurance expense stepped up
3 from nine percent of 0&M in 2018 to nearly 13
4 percent on average for 2019-2021 .
5 In SCE' s 2021 GRC request, SCE recognized that
6 its wildfire liability insurance expense forecast
7 of $624 million was "significantly higher than
8 previous years, but that is not unexpected given
9 the dramatically increased risks faced by electric
10 utilities from wildfires, and the insurance
11 industry' s willingness to insure against those
12 risks . "24 SCE observed further that these wildfire
13 insurance market conditions were "well known to and
14 [had] been frequently and explicitly recognized by
15 the Commission. "25 SCE additionally noted that "in
16 the current insurance environment, it is impossible
17 to forecast wildfire liability insurance premiums
18 precisely. "26
19 • San Diego Gas & Electric ("SDG&E") — SDG&E' s
20 wildfire liability insurance costs nearly tripled
21 in absolute terms from the 2016-2017 period to
23 Edison International Form 10-K.
24 Application of Southern California Edison Company for Authority to
Increase its Authorized Revenues for Electric Service in 2021, Among Other
Things, and to Reflect that Increase in Rates, A.19-08-013, Opening Brief
of Southern California Edison Company at 238 (Sept. 11, 2020) .
2s Id.
26 Id. , at 247.
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1 2022-2023, when they stood at $221 million. 27
2 Assuming that (as reported in SDG&E' s 2020 cost of
3 capital proceeding28) SDG&E has maintained coverage
4 levels of approximately $1 . 5 billion, this
5 represents an effective average wildfire insurance
6 premium of 15 percent ($221mm/$1 . 5b) for 2022-2023 .
7 As a percentage of O&M costs, SDG&E' s wildfire
8 liability insurance costs grew from approximately
9 eight percent in 2016 to 14 percent on average for
10 2019-2022 . 29
11 In its 2024 GRC application, SDG&E noted that
12 " [i] nsurance market uncertainty continues because
13 of wildfire risk, inverse condemnation, and global
14 catastrophe losses . Because of this uncertainty and
15 continued volatility in the cost of liability
16 insurance, SoCalGas and SDG&E request that the
27 Application of San Diego Gas & Electric Company for Authority, Among
Other Things, to Update its Electric and Gas Revenue Requirement and Base
Rates Effective on January 1, 2024, A.22-05-016, SDG&E Prepared Direct
Testimony of Dennis J. Gaughan (Corporate Center - Insurance) , Table DG-
18 (years 2021 and 2022 are forecasts) (May 2022) .
28 Application of San Diego Gas & Electric Company, A.19-04-017, Exhibit
No. SDG&E-05, Prepared Direct Testimony of John J. Reed and James M. Coyne
at 34 (Apr. 2019) .
29 Importantly, the cost of insurance per dollar of coverage depends
critically on where the insurance is positioned in the stack of claims to
cover liabilities. The first layers to be drawn upon have a much higher
unit cost because they are statistically more exposed to the risks than
residual claims after these funds have been exhausted. Thus SDGE's average
could be well below its costs to specific risk tranches on the margin.
Graves, Di 19
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1 Commission reauthorize their [balancing accounts]
2 for liability insurance premiums . "30
3 • Avista — Avista reported a doubling in general
4 liability insurance expense between 2020 and 2022,
5 when costs reached $14 million. 31 This represented
6 a near doubling in insurance expense as a
7 percentage of 0&M —from 1 . 8 percent to 3 . 3 percent-
8 over the same period. Avista identified these cost
9 increases as "largely related to wildfire exposure
10 in the industry at large, and especially in the
11 West . 1132 Avista further characterized the costs as
12 "undoubtedly `extraordinary' and volatile"
13 relative to past years, and "beyond the Company' s
14 control, notwithstanding our best efforts under the
15 Wildfire Resiliency Plan. "33
16 • Idaho Power — Idaho Power reported a 64 percent
17 increase in Excess Liability insurance expense
18 between 2020 and 2022, when costs exceeded
19 $14 million. 34 This represented a 46 percent
31 A.22-05-016, SDG&E Prepared Direct Testimony of Dennis J. Gaughan
(Corporate Center - Insurance) at DJG-24 (May 2022) .
31 Avista Corporation v. WUTC, Washington Utilities and Transportation
Commission ("WUTC") , Docket Nos. UE-220053, UG-220054, UE-210854,
Rebuttal Testimony of Elizabeth M. Andrews, Table 7 (August 19, 2022) .
32 Avista Corporation v. WUTC, WUTC Docket Nos. UE-220053, UG-220054, UE-
210854, Direct Testimony of Elizabeth M. Andrews, p. 70 (Jan. 25, 2022) .
33 Id. , p. 68.
34 In the Matter of the Application of Idaho Power for an Accounting Order
Authorizing the Deferral of Incremental Wildfire Mitigation and Insurance
Costs, Case No. IPC-E-21-02, filed Jan. 22, 2021; In the Matter of the
Graves, Di 20
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1 increase in insurance expense as a percentage of
2 0&M expense—from 2 . 3 percent to 3 . 3 percent—over
3 the same period. Idaho Power has attributed these
4 costs "to the frequency and magnitude of Western-
5 state wildfires in recent years, as well as Idaho
6 Power' s specific wildfire risk. 1135 Like other
7 utilities, Idaho Power is a "price taker" when it
8 comes to buying insurance . The Company notes that
9 " [i] n that regard, despite annual assessment of its
10 insurance portfolio to identify the best value and
11 the retention of an experienced insurance broker,
12 the Company is subject to price increases as
13 insurers raise premiums due to losses, either
14 pertaining to Idaho Power or to insurers' overall
15 insured base . "36
16 Q. How have increased wildfire risks otherwise affected
17 electric utilities?
18 A. Perhaps inevitably, the interactions of wildfires and
19 utility equipment have led to claims and court rulings
20 against utilities . This has been exacerbated in
Application of Idaho Power for Authority to Increase its Rates and Charges
for Electric Service in the State of Idaho and for Associated Regulatory
Account Treatment, Case No. IPC-E-23-11, Motion for Approval of
Stipulation and Settlement, October 2023.
35 Application of Idaho Power for an Accounting Order Authorizing the
Deferral of Incremental Wildfire Mitigation and Insurance Costs Before
the Idaho Public Utilities Commission, Case No. IPC-E-21-02, Application
at 26 (Jan. 2021) .
36 Case No. IPC-E-23-1, Direct Testimony of Brian R. Buckham at 34 (June
2023) .
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1 California by the doctrine of "inverse condemnation"-
2 under which I understand utilities automatically bear
3 responsibility for wildfire damage claims involving
4 their equipment or operations as a legal matter,
5 regardless of negligence, mitigation practices, or
6 foreseeability. This policy does not apply in other
7 states, but legal decisions upholding wildfire liability
8 claims against utilities in other states with only
9 modest linkages to utility practices may have a similar
10 effect .
11 Wildfire claims have aggregated in the tens of
12 billions of dollars for the California IOUs (PG&E, SCE,
13 and SDG&E) , and, more recently, as much as $2 . 4 billion
14 in probable losses accrued by PacifiCorp as of September
15 30, 2023 . 37 Famously, the problems facing PG&E culminated
16 in it declaring bankruptcy to restructure its
17 liabilities and financing.
18 Q. Have there been adverse reactions from the credit rating
19 agencies?
20 A. Yes . Credit rating agencies have been concerned with the
21 risks of wildfires on utility credit profiles . As
22 specifically discussed by Company witness Steward, the
23 risk of wildfire liabilities was a cause for Standard &
24 Poor' s ("S&P") and Moody' s Investor Service ("Moody' s")
37 PacifiCorp Form 10-Q for period ending September 30, 2023, at 23.
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1 to downgrade PacifiCorp' s senior unsecured issuer rating
2 during 2023 . S&P downgraded PacifiCorp to BBB+ in June
3 2023, stating their belief that "the operating risks for
4 PacifiCorp have significantly increased. "38 Moody' s
5 downgraded PacifiCorp to Baal in November 2023 and
6 stated that "wildfire risk, a form of physical climate
7 risk, was a key driver of the downgrade . "39
8 These risks have affected credit profiles for
9 electric utilities across the industry. As recently
10 noted by S&P, " [d] amages and related costs from physical
11 risks are escalating in North America as regions
12 designated as high-fire risk expand. "40 Furthermore, S&P
13 "has downgraded more [Investor-Owned Utilities] due to
14 physical events (e .g. hurricanes, storms, and wildfires)
15 over the past six years by nearly 10 times compared with
16 the previous 13 years . 1141
17 IV. WILDFIRE MITIGATION CANNOT FEASIBLY ELIMINATE ALL RISK
18 Q. What are utilities currently doing to mitigate wildfire
19 risk?
20 A. Some utilities in the West are re-evaluating their fire
21 mitigation, risk management funding and protocols, and
38 S&P Global, PacifiCorp Downgraded to `BBB+', Outlook Revised to
Negative; Berkshire Hathaway Energy Co. Outlook Also Negative (June 20,
2023) . S&P assessed PacifiCorp' s "stand-alone credit profile" at BB+.
39 Moody's Investor Service, Rating Action: Moody's downgrades PacifiCorp
to Baal, outlook stable (Nov. 21, 2023) .
40 S&P Global, A Storm Is Brewing: Extreme Weather Events Pressure North
American Utilities' Credit Quality (Nov. 9, 2023) .
41 Id.
Graves, Di 23
Rocky Mountain Power

1 cost recovery mechanisms to be more proactive for this
2 kind of problem, including:
3 • Compiling better statistics on apparent risk over
4 long periods of time (even if very difficult to do
5 with any precision) , which allows them to at least
6 evaluate what the price of risk is in offered
7 insurance compared to their estimated loss
8 exposure . 42
9 • Formulating ex ante risk mitigation plans subject
10 to agreement with regulators and intervenors that
11 those plans are aggressive enough (spend enough but
12 not too much money) and are prioritized for most
13 likely effectiveness—with the intent that
14 compliance with these plans will inoculate the
15 utility against findings of imprudence and loss of
16 cost recovery if/when disasters occur despite
17 mitigation efforts . 43
42 For example, California utilities must submit public risk studies as
part of the CPUC's periodic Risk Assessment and Mitigation Phase ("RAMP")
proceedings. These studies are probabilistic in nature and address
wildfire risk along with a variety of other risks. See
https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-
division/risk-assessment-and-safety-analytics/risk-assessment-
mitigation-phase.
43 Note, for example, protocols relating to accessing the California
Wildfire Fund described below, which evaluate utility prudency "based on
actions taken by a utility, not the outcome of those actions." See Safety
Certification FAQ I Office of Energy Infrastructure Safety,
https://energysafety.ca.gov/what-we-do/electrical-infrastructure-
safety/wildfire-mitigation-and-safety/safety-certifications/safety-
certification-faqs/.
Graves, Di 24
Rocky Mountain Power

1 Q. Are these plans focused narrowly on wildfires or do they
2 encompass multiple risks?
3 A. It varies . In many cases, insurance covers a suite of
4 possible catastrophic problems of which wildfire is just
5 one . Also for sizing of effort and priority among such
6 risks, it is preferable that a utility' s extreme risk
7 management system not be designed piecemeal, one type of
8 risk at a time (though this is not uncommon, as some
9 hazards tend to occur rarely) but instead reflects some
10 attempt to achieve equal benefits per dollar of effort
11 put into mitigation across all major types of risks (such
12 as cybersecurity, system safety, wildfires, earthquake
13 recovery, extreme storm hardening and recovery) . This is
14 difficult because the types of damages across risk types
15 are quite distinct, but to some extent they can be
16 monetized or at least ranked in terms of dimensions like
17 energy delivery disruption likelihood, frequency of
18 occurrence, personnel and customer safety or survival
19 risk, interaction with other critical systems, tendency
20 to include property damage etc . , and their mitigations
21 can be ranked in terms of extent of the system and time
22 frame of improved protection achieved by each. This
23 allows an elementary comparison across risks for some
24 degree of equivalent response planning. An integrated
Graves, Di 25
Rocky Mountain Power

1 approach of this type lends further credibility to the
2 plans for whatever are the strongest concerns .
3 Q. Why can' t these efforts be relied upon to eliminate
4 wildfire risk?
5 A. Even with the best of utility-sponsored fire mitigation
6 plans, it is impossible (and would be too expensive even
7 if it were possible in principle) to fully eliminate the
8 wildfire risks in a large region. This is true for
9 several reasons :
10 • Extreme weather poses an unpredictable threat —
11 Extreme weather behaves differently than past
12 statistical evidence on temperatures,
13 precipitations, wind speed and the like, making it
14 extremely difficult to model rigorously. In the
15 parlance of statistics, catastrophic conditions are
16 "black swan" events, arising only in the "tails" of
17 the probability distributions otherwise describing
18 the range of typical experience . In addition to the
19 occurrence of extreme fires being very hard to
20 predict, this dramatically amplifies the
21 uncertainty range of possible economic damage
22 consequences of a given wildfire, even as
23 mitigation plans reduce the risk of a wildfire
24 outbreak occurrence . This means that the challenges
25 are a moving target, and factors outside the
Graves, Di 26
Rocky Mountain Power

1 control of the utility will significantly determine
2 the extent of the outcome of consequences and
3 damages of wildfires . As noted above, it has also
4 made modeling of fire risk quite difficult and
5 inconsistent with recently observed disasters .
6 • Wildfire mitigation comprises a massive geographic
7 challenge — It is not possible to pinpoint exactly
8 where wildfires will start in the future, hence one
9 cannot eliminate the wildfire events by preemptive
10 measures assured of taking place at the "right"
11 location among many possible locations where a fire
12 could start in a very large area encompassing
13 multiple states . Indeed, there is a paradoxical
14 situation that if/where mitigation works, it will
15 help avoid fires at those locations -- but then the
16 fires will happen somewhere else that was not yet
17 at the head of the line for earlier intervention,
18 making it look like those spots were somehow
19 neglected. But there will always be some such
20 areas, no matter what order is used for the
21 mitigation! All possible areas need to be targeted,
22 ideally in order of declining risk, which itself is
23 a diagnostic that takes time to develop and
24 implement .
Graves, Di 27
Rocky Mountain Power

1 • Other responsible entities — Responsibility to
2 mitigate wildfire risks is not uniquely a utility
3 responsibility, in terms of detection, prevention,
4 response or recovery. These needs are typically
5 distributed across multiple agencies and many
6 individuals, with utility mitigation plans forming
7 just one of many relevant factors .
8 • Competing priorities of maintaining service quality
9 — The expected benefits of additional expenditures
10 on wildfire mitigation plans need to be weighed
11 against customer benefits from spending that money
12 on other useful utility programs or service
13 features (reliability, resiliency, service
14 efficiency, customer services, relative risk
15 priority, etc. ) , or from simply not increasing
16 rates enough to cover all the feasible mitigation
17 activities . To date, utility expenditures approved
18 by regulators for wildfire mitigation plans
19 typically represent a small portion of total
20 revenue requirements . While that may well increase,
21 it will inevitably face budgetary caps .
22 • Law of diminishing marginal returns to mitigation
23 efforts — Another consideration that limits the
24 cost effectiveness of additional expenditures to be
25 spent on wildfire mitigation plans by utilities is
Graves, Di 28
Rocky Mountain Power

1 the economics "law" of diminishing marginal
2 returns . That is the tendency of economic
3 activities to see declining value per unit of
4 benefit as the scale of effort increases . This
5 arises for at least two reasons : First, early
6 economic efforts are usually directed at the "low
7 hanging fruit" where there are quicker paybacks;
8 higher hanging fruit is more difficult and
9 expensive to reach. Second, expanding some
10 capabilities on any system initially reduces
11 constraints in those direct service attributes, but
12 eventually constraints in other parts of the system
13 or operations start to bind. Since the types of
14 activities in the fire mitigation plans for a given
15 total budget will (or should) be selected based on
16 the greatest possible cost-effective impact in
17 mitigating the wildfire risks, expansion or
18 continuation of the total budget will gradually
19 start facing activities that tend to have smaller
20 and smaller incremental benefits . These declining
21 marginal benefits ultimately justify putting a
22 limit on how much improvement to pursue . In
23 general, all forms of risk reduction become
24 dramatically more expensive as the remaining
25 expected risks decline . This is similar to why
Graves, Di 29
Rocky Mountain Power

1 electric utilities in the U. S . have typically
2 implemented a 1-in-10 years Loss of Load
3 Expectation threshold (or variations thereof) for
4 determining planning reserve margins to maintain
5 resource adequacy, instead of trying to eliminate
6 all risk for reliability outage events .
7 Thus, residual risk is inevitable and even efficient
8 under even the most aggressive mitigation plan, so it is
9 more than likely that associated damage claims will
10 continue to occur. But wildfire mitigation plan
11 effectiveness will gradually reduce the amount and cost
12 of insurance otherwise needed.
13 Q. How should appropriate mitigation efforts be determined?
14 A. In a regulatory setting, while the utility has the
15 greatest expertise and best vantage point for assessing
16 costs and likely efficacy of any particular mitigation
17 program, the process of determining appropriate
18 mitigation efforts and protocols is as much negotiation
19 as analysis, involving all stakeholders . Again, given
20 the infeasibility of eliminating the risk, there must be
21 a balance of interest among stakeholders about how far
22 and fast to go, relative to using funds and resources
23 for other important utility services . Similarly, the
24 right amount and layering of insurance (commercial or
25 self-provided) also needs this joint resolution, as
Graves, Di 30
Rocky Mountain Power

1 insurance does not eliminate risk, it simply spreads out
2 how the expected risk is paid for, and it improves
3 liquidity if/when the risk occurs . There is no per se
4 right level of such smoothing, as this depends on risk
5 preferences and interacts (like mitigation) with other
6 budgetary tradeoffs for the utility and its customers .
7 The stakeholder workshops that PacifiCorp has been
8 implementing are a good venue for such discussions .
9 V. POTENTIAL REGULATORY RELIEF
10 Q. Are a utility' s wildfire risks and costs already
11 compensated by its allowed return on equity ("ROE")
12 making regulatory mechanisms unnecessary?
13 A. No, wildfire risks and costs are not typically
14 compensated by a utility' s allowed ROE, nor would such
15 compensation via an enhanced ROE allowance be very
16 effective in covering the problem. This is recognized by
17 regulators in the normal practice of providing for
18 recovery of insurance costs separately from allowed ROE
19 risk premiums, and it applies all the more to increased
20 insurance premia and/ or costs associated with extreme
21 wildfire events . Exogenous risks like wildfire liability
22 are not well captured in utility ROEs for several
23 reasons, mostly springing off the fact that they are
24 asymmetric risks, with the only possible outcomes being
25 either no losses or some losses, but no outcomes with
Graves, Di 31
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1 gains . Such insurance costs are intuitively one-sided.
2 The possible losses from insurance risks reduce the
3 expected cash flows from an asset, but that reduction is
4 not accompanied by any prospect of compensatory upside
5 returns .
6 Q. Please elaborate with some examples .
7 A. For example, when a public company faces an economic
8 loss from a third-party liability claim, or simply the
9 possibility of a future uninsured loss occurring, its
10 stock price will fall by the present value of the
11 expected loss, all else equal . That stock will not be
12 expected thereafter to appreciate more than similar
13 companies that do not have that problem, and so
14 shareholders will not have the opportunity to cover the
15 unexpected loss . 94 Net of the expected loss, the earnings
16 of the affected company will not tend to be higher
17 because of that adverse starting condition. Instead, its
18 business risks will be comparable to other companies
19 that do not have that problem. So the measured cost of
20 capital will not reflect this problem. (This would be
21 true even if all companies in the industry faced the
22 same kind of insurance risks . They all lose value and
44 Importantly, insurance losses can be diversified but they cannot be
diversified away, which is unlike other business risk that involves a
blend of uncorrelated economic outcomes, some positive and some negative.
Graves, Di 32
Rocky Mountain Power

1 none gain offsetting growth opportunities because of
2 it . )
3 The asymmetry problem is more severe for regulated
4 utilities than for unregulated companies, which have the
5 opportunity to choose when, where, how, and how much to
6 invest, and therefore are able to pick market
7 participation sectors where they have expectations of
8 earning returns in excess of their cost of capital . In
9 particular, they can try to stay away from market sectors
10 where they are exposed to asymmetric, downside risks .
11 Regulated utilities, by contrast, do not have this
12 discretion, as they operate under an obligation to serve
13 and then must sell services with cost-based pricing that
14 provides very limited or no upside opportunities
15 relative to allowed ROES . Because they cannot pick and
16 choose where to serve, the costs of insurance problems
17 must be treated like a legitimate cost of service item,
18 not as a risk the utility investors can or should just
19 internalize .
20 Q. What about allowing a premium ROE to cover asymmetric
21 risk?
22 A. An allowed ROE could be augmented, in principle, by a
23 premium to the customarily measured cost of capital to
24 reflect asymmetric risk. However, there are multiple
25 challenges to applying this ROE approach, not least that
Graves, Di 33
Rocky Mountain Power

1 there are considerable estimation difficulties of the
2 appropriate amount (given the recent growth in frequency
3 and severity of wildfires) which make it possible that
4 even a large premium only partly addresses the problem.
5 That is, they would have to be awarded the expected cost
6 of the excess risks remaining after any of their
7 conventional insurance mechanisms were exhausted - which
8 is the "black swan" part of the distribution that is not
9 well understood. That could be a huge number, bigger
10 than is likely to be acceptable . At the same time, any
11 such allowance may create the incorrect impression in
12 the eyes of the public and regulators that the utilities
13 have been fully compensated for damage costs, no matter
14 how large they might turn out to be, from all potential
15 wildfire catastrophes . Any events dramatically exceeding
16 the allowed premiums could be financially destructive to
17 the utility, hence to its service to customers .
18 Absent a meaningful opportunity to offset risk via
19 returns on investment, it is essential that utilities
20 have a variety of ex ante and ex post equitable cost
21 recovery mechanisms such as recovering higher commercial
22 insurance costs (possibly through self-insurance) and
23 those discussed below.
Graves, Di 34
Rocky Mountain Power

1 A. Recovering Higher Commercial Insurance Costs
2 Q. How have increased wildfire liability insurance costs
3 been handled by other utilities and their regulators?
4 A. The large increases in wildfire insurance costs
5 described above have presented urgent challenges in cost
6 recovery for affected utilities and their regulators . In
7 particular, the cost recovery settlements achieved by
8 the California IOUs ("California Precedents") , Avista
9 and Idaho Power (together, the "Regional Precedents")
10 provide useful context for PacifiCorp' s filing. The
11 Regional Precedents directly inform PacifiCorp' s filing
12 in the following ways :
13 • Regulatory acknowledgement of higher and more
14 uncertain wildfire insurance costs,
15 • Regulatory recognition of exogenous drivers, and
16 • Self-insurance mechanisms similar to those
17 currently being considered by PacifiCorp.
18 Importantly, the California Precedents further
19 underscore the recognition of current uncertainty in
20 wildfire liability insurance markets by authorizing the
21 recovery of wildfire insurance costs on a contingent
22 (i .e . formulaic) basis, as discussed further below.
23 Q. Please describe the California Precedents .
24 A. Given that the costs of commercial wildfire insurance
25 have reached such high levels, the California IOUs have
Graves, Di 35
Rocky Mountain Power

1 each recently been authorized or have settlements
2 pending that would authorize recovery of very
3 substantial wildfire self-insurance costs over multi-
4 year periods .
5 The California Settlements are summarized below and
6 in Exhibit No . 22 .
7 • PG&E — In CPUC D. 23-01-005, issued in January
8 202345, PG&E was authorized to self-insure by
9 setting aside funds potentially approaching recent
10 commercial cost levels toward covering wildfire
11 liability up to $1 billion annually for the "2023
12 GRC Period" : 2023-2026 .
13 In a "worst case" scenario assuming wildfire
14 liability claims of $1 billion in each year of the
15 2023 GRC Period, the PG&E Settlement provided that
16 72 percent of realized costs would be recovered via
17 PG&E' s Risk Transfer Balancing Account ("RTBA") 46
18 not subject to reimbursement "tied to the outcomes
41 See CPUC A.21-06-021, PG&E Decision (approving settlement between PG&E,
the Utility Reform Network, and the Public Advocates Office at the CPUC
("PGE Settlement") .
46 The RTBA had been previously established in CPUC D.20-12-005 (Dec. 3,
2020) to "record the difference between the amounts authorized in this
GRC and actual costs of insurance premiums for coverage up to
$1.4 billion" (D.20-12-005 at 249) . D.20-12-005 further noted that
" [r]egarding the establishment of the RIBA, we agree that insurance costs
for General Liability coverage has been difficult to predict in recent
times because of market conditions and the recent wildfires in California.
A two-way balancing account will also allow PG&E to address uncertainty
in a timely manner and at the same time ensure that there is adequate
insurance coverage" (D.20-12-005 at 254) .
Graves, Di 36
Rocky Mountain Power

1 of reasonableness reviews . "47 In such a "worst case"
2 scenario, most of the 28 percent portion remaining
3 uncollected at the end of the 2023 GRC Period could
4 be subsequently recovered from customers via a Tier
5 2 Advice Letter Filing, 48 with 5 percent paid by a
6 shareholder deductible . 49
7 Importantly, per the agreed Settlement
8 formulas illustrated in Appendix B of the PG&E
9 Settlement, the portion of claims recoverable not
10 subject to a reasonableness review could be
11 increased significantly under a less adverse loss
12 scenario . For example, were realized losses over
13 the 2023 GRC Period limited to the level actually
14 experienced for 2019-2021 ($458 million per year) ,
15 such recoveries would grow to 93 percent . so
16 In support of the PG&E Settlement, the PG&E
17 Decision acknowledged the insurance market
18 realities affecting PG&E :
19 "Due to a number of factors including PG&E' s
20 increased claims, the general liability
21 insurance market continued to increase insurance
22 premiums and reduce the availability of
23 insurance to cover wildfire risk. As Table 2
47 See PG&E Decision, at 13, and PG&E Settlement Section 3.4 and Appendix
B: "Illustrative Calculation Reflecting the Worst Case Scenario—Cost
Recovery for Undercollections at the End of the 2023 GRC Period", the
latter reflected in Exhibit 5.
48 PG&E Settlement Section 3.7 and Appendix B. Note that a Tier 2 Advice
Letter could be subject to challenge.
49 PG&E Settlement Section 3.2.3.
so See Exhibit RMP Exhibit No. 22.
Graves, Di 37
Rocky Mountain Power

1 illustrates, PG&E' s wildfire liability insurance
2 cost per limit of coverage grew until the costs
3 reached 81 . 6 percent of the coverage amount for
4 the 2020-21 insurance policy"51
5 As to self-insurance, the CPUC reasoned that
6 " [s] ince 2017, wildfire liability insurance for
7 third-party claims has risen to the point that
8 self-insurance is likely to achieve sufficient
9 insurance coverage at a lower overall cost to
10 PG&E' s customers than commercial insurance . "52 The
11 PG&E Decision went on to say that " [n] ow that the
12 cost of commercial insurance is up to 80 percent of
13 the coverage it would provide, the Commission finds
14 the Settlement recommending PG&E to use self-
15 insurance for wildfire claims to be a reasonable
16 alternative . "53
17 • SCE — Similar to PG&E, in CPUC D.23-05-013, 54 SCE
18 was authorized to self-insure toward covering
19 wildfire liability up to $1 billion annually for
20 the "Program Period" : July 2023-December 2028, 55
51 PG&E Decision, at 6. The PG&E Decision additionally recognized that
" [g] iven the significant difference in price for wildfire and non-
wildfire liability insurance, PG&E now purchases liability coverage for
wildfire claims separate from non-wildfire liability insurance" (PG&E
Decision at page 4) .
52 PG&E Decision, at 2.
53 Id. , at 15.
54 See A.19-08-013, D.23-05-013 (May 19, 2023) (the "SCE Decision") ,
approving the Settlement between SCE, The Utility Reform Network, and
the Public Advocates Office at the CPUC (the "SCE Settlement") .
55 Note that 2025 - 2028 would remain subject to revision in the 2025 GRC;
see SCE Decision page 6.
Graves, Di 38
Rocky Mountain Power

1 again by setting aside funds potentially
2 approaching recent levels of commercial wildfire
3 insurance costs .
4 In a "worst case" scenario assuming wildfire
5 liability claims of $1 billion in each year of the
6 Program Period, 74 percent of realized costs would
7 be recovered via SCE' s Risk Management Balancing
8 Account ("RMBA") 56 not subject to reimbursement tied
9 to the outcomes of "reasonableness reviews" . 57 In
10 such a "worst case" scenario, most of the
11 26 percent portion remaining uncollected the end of
12 the 2023 GRC Period could be recovered via a Tier
13 2 Advice Letter Filing58, with 1 . 25 percent paid by
14 a shareholder deductible (2 . 5 percent on amounts
15 above the $500 million of annual claims) .
16 Importantly, per the agreed Settlement formulas,
17 the portion of claims recoverable via the RMBA
18 could be increased significantly under a less
19 adverse scenario . For example, were realized losses
20 over the Program Period limited to $400 million per
21 year—per Appendix B, Example 2 of the SCE
56 As further described below, the RMBA was established as part of SCE's
2021 GRC.
57 SCE Decision, page 8; and SCE Settlement Section 3.4 and Appendix B:
"Illustrative Calculation Reflecting the Worst Case Scenario—Cost
Recovery for Undercollections at the End of the Program Period".
58 See SCE Settlement Sections 3.3.2, 3.7 and Appendix B. Note that a Tier
2 Advice Letter could be subject to challenge.
Graves, Di 39
Rocky Mountain Power

1 Settlement—claims recoverable via the RMBA would
2 grow to 85 percent .
3 In support of the settlement, the CPUC noted
4 the following:
5 "SCE' s wildfire insurance costs have increased
6 significantly in recent years . In the 2018 GRC,
7 the Commission authorized $92 . 4 million for
8 total liability insurance expense (combined
9 wildfire and non-wildfire) for the 2018 test
10 year. In the Track 1 decision, the Commission
11 authorized a 2021 test year forecast of $460 . 0
12 million for wildfire liability insurance costs
13 to obtain $1 billion of coverage based on SCE' s
14 recorded 2020 costs . Due to the volatility and
15 uncertainty of these costs, the Commission
16 authorized SCE to establish the one way RMBA to
17 ensure any overcollection is returned to
18 ratepayers and also authorized SCE to continue
19 to seek rate recovery of any costs in excess of
20 the forecast through its WEMA. "59
21 The CPUC articulated further the same
22 reasoning it had used in the PG&E Decisions :
23 "Although not guaranteed, we find it likely that
24 customers will receive more cost savings and
25 benefits from self-insurance in 2023 and 2024
26 compared to commercial insurance . The proposed
27 self-insurance program for SCE is substantially
28 similar to the multi-year 100 percent self-
29 insurance program for wildfire liability
30 approved for Pacific Gas and Electric Company
31 (PG&E) in its 2023 GRC. "60
59 SCE Decision, at 9-10. WEMA refers to the Wildfire Expense Memorandum
Accounts under which California utilities can record wildfire-related
costs pending authority to reflect those costs in rates. See also,
Decision Approving Southern California Edison Company's Application for
Authorization to Recovery Costs Related to Wildfire Insurance Premiums
Recorded in its Wildfire Expense Memorandum Account, D. 20-09-024 (Sept.
24, 2020) .
60 SCE Decision, at 13.
Graves, Di 40
Rocky Mountain Power

1 • SDG&E — In a joint motion filed in October 2023,
2 SDG&E and key stakeholders proposed a settlement
3 embedding a wildfire liability self-insurance
4 option within an authorized test year forecast of
5 $173 million for up to $1 billion in commercial
6 wildfire liability coverage . 61 The self-insurance
7 option would allow SDG&E (with SoCalGas) to set
8 aside $14 million per year toward the first $50
9 million of potential losses . 62 The SDG&E Settlement
10 remains under consideration by the CPUC.
11 Q. Please describe the other Regional Precedents .
12 A. Other noteworthy precedents include wildfire insurance
13 settlements recently achieved by Avista Corporation and
14 Idaho Power.
15 • Avista - In Final Order 10/04, 63 the Washington
16 Utilities and Transportation Commission ("WUTC")
17 approved a settlement authorizing Avista to
18 establish an Insurance Expense Balancing Account
19 for 2023 and 2024 with a step-up in baseline
20 authority of approximately $5 . 3 million.
61 See CPUC A.22-05-016, Joint Motion of Southern California Gas Company
(U 904 G) , SGD&E, The Public Advocates Office at the CPUC, The Utility
Reform Network, The Utility Consumer's Action Network, and Community Legal
Services for Adoption of a Settlement Agreement Resolving All Insurance
Issues, filed Oct. 24, 2023, (the "SDG&E Settlement") .
62 SDG&E Settlement, at 11.
63 WUTC Docket Nos. UE-220053, UG-220054, UE-210854 (cons. ) , Final Order
10/04 (Dec. 12, 2022) .
Graves, Di 41
Rocky Mountain Power

1 The WUTC noted the following:
2 " [W] e find that Avista has demonstrated
3 unprecedented increases and volatility in its
4 insurance costs . We agree that Avista has
5 shown the insurance expense increases in
6 recent years are "extraordinary" and
7 "volatile" and caused an under-recovery of
8 approximately $5 . 3 million in 2022 . We also
9 find that Avista has demonstrated that it has
10 taken and is taking appropriate steps to try
11 to control these costs, but has shown
12 unprecedented recent increases in insurance
13 that are largely out of its control . "64
14 • Idaho Power — The Commission has allowed Idaho
15 Power to defer incremental costs associated with
16 its insurance premiums . The Commission approved
17 this deferred treatment in 2021, stating the
18 following:
19 "We agree with the Company that customers
20 should benefit from adequate insurance
21 coverage . Insurance protects the Company and
22 its customers from unforeseen wildfire-
23 related costs which have caused utility
24 bankruptcy in recent years . While the
25 increased insurance premiums, including the
26 "wildfire load, " represent additional costs,
27 the alternative is not prudent or wise. We
28 believe the Company' s proactive investment
29 will provide benefits to customers should the
30 Company ever face significant wildfire
31 liability. We find it reasonable to allow the
32 Company to defer its Idaho jurisdictional
33 share of incremental wildfire insurance costs
34 above 2019 levels . 'f65
64 Id. , at 50.
61 Case No. IPC-E-21-02, Order No. 35077 at 8 (June 17, 2021) .
Graves, Di 42
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1 Idaho Power and interveners proposed a
2 settlement in Idaho Power' s 2023 GRC to continue
3 this deferred treatment . The Commission approved
4 the settlement . 66
5 Q. What are the implications of these precedents for
6 PacifiCorp' s filing?
7 A. The Regional Precedents have the following implications
8 for PacifiCorp' s filing:
9 • Perhaps most importantly, they demonstrate strongly
10 that PacifiCorp is not unique in facing the
11 dramatic and pressing challenge of increasing and
12 more volatile wildfire risk, insurance, and
13 potential damage costs .
14 • PacifiCorp' s utility peers and their regulators
15 recognize wildfire risk—and hence associated
16 insurance costs—as an exogenous risks - not
17 controllable but requiring cost of service
18 acceptance, somewhat like volatile fuel costs
19 require adaptive (tracking) cost recovery in order
20 for a utility to be financially stable power
21 provider.
22 • Regulatory cost recovery mechanisms need to evolve
23 to deal with the pace and scale of this problem. In
66 Case No. IPC-E-23-11, Order No. 36042 at 10 (Dec. 28, 2023) .
Graves, Di 43
Rocky Mountain Power

1 this regard, regulators have recently entered into
2 settlements with the California IOUs, Avista, and
3 Idaho Power that both defer increased insurance
4 costs, but in some cases pre-authorize the
5 contingent commitment of funds for self-insurance
6 (based on claims actually realized) .
7 • Even if recent wildfire liability conditions and
8 regulatory treatments can be described as a "new
9 normal, " it is not clear that this state of affairs
10 can be considered stable or predictable . The
11 uncertainty is underscored by the recognition in
12 approved settlements that current conditions are
13 "volatile" and the contingent nature of the
14 California settlements, which are designed to
15 accommodate a wide range of potential wildfire
16 liability outcomes . Thus, at this time, there is no
17 allowance that could be given with confidence that
18 over time it will most likely cover whatever
19 happens, with some ups and downs along the way.
20 Instead, mechanisms that adjust with realized
21 circumstances are needed.
22 • To the degree that PacifiCorp encounters
23 dysfunctional commercial insurance markets similar
24 to what the California IOUs have faced in recent
25 years, there is no reason that PacifiCorp should
Graves, Di 44
Rocky Mountain Power

1 not similarly avail itself the benefits of self-
2 insurance in some form.
3 B. Protection From Extreme Events
4 Q. What are potential consequences of utility exposure to
5 extreme wildfire claims exceeding normal coverage?
6 A. As noted above, the "new normal" has included not just
7 uncertainty about increased insurance costs but also the
8 increased likelihood that wildfire liability costs may
9 rarely but very significantly exceed available levels of
10 coverage at any price, possibly reaching several billion
11 dollars . Only a very small number of fires grow to such
12 levels of conflagration, but climate change and more
13 residences and other properties being in the WUI zone of
14 high risk have made the possibility of worst-case
15 scenarios very grim indeed. Claims to date have
16 materially eroded the affected utilities' financial
17 resiliency, and in the case of PG&E, led to its
18 bankruptcy in 2019 . I understand these huge risks are
19 virtually uninsurable in commercial markets, or at least
20 not at any reasonable price, so they need creative
21 utility-based mechanisms for solutions .
22 Q. Beyond just recovering the costs of insurance, how has
23 the risk of extreme wildfire claims been handled in other
24 jurisdictions?
25 A. Responding to the urgent threat posed by major wildfires
Graves, Di 45
Rocky Mountain Power

1 in 2017, 2018, and after, the State of California has
2 established mechanisms to protect utilities from
3 associated financial claims . The goals include
4 maintaining financial stability for utilities in support
5 of their obligation to reliably serve customers .
6 In August 2018, the California state legislature
7 passed a bill to address the cost allocation relating to
8 the 2017 wildfires . 67 While I am not an attorney, my
9 understanding is that Senate Bill 901 expanded various
10 fire prevention and mitigation efforts by several state
11 agencies, and it clarified the CPUC' s reasonableness
12 review of utility activities and costs regarding fire
13 mitigation. Importantly, the bill created a framework
14 for socializing wildfire-related costs in 2017 and in
15 future years through a securitized utility financing
16 mechanism. For 2017 specifically, the bill mandated that
17 the CPUC take into account "the electrical corporation' s
18 financial status" by determining "the maximum amount the
19 corporation can pay without harming ratepayers or
20 materially impacting its ability to provide adequate and
21 safe service. 1168 The bill thus established a mechanism
22 for PG&E to recover costs for 2017 wildfires that would
67 California Senate Bill 901 (Wildfires) , Legislative Counsel's Digest,
published September 8, 2018,
https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill id=2
01720180SB901.
68 Section 27 of Senate Bill 901.
Graves, Di 46
Rocky Mountain Power

1 otherwise be disallowed, at least beyond the point to
2 where the disallowance would threaten the utility' s
3 financial viability or its ability to provide utility
4 service . 69
5 Following PG&E' s bankruptcy filing in 2019, the
6 California state legislature passed Assembly Bill ("AB")
7 1054 to further address utility wildfire risk by, among
8 other things, establishing an insurance-like Wildfire
9 Fund (the "California Wildfire Fund") . The legislative
10 language in AB 1054 observed that " [t] he establishment
11 of a wildfire fund supports the credit worthiness of
12 electrical corporations, and provides a mechanism to
13 attract capital for investment in safe, clean, and
14 reliable power for California at a reasonable cost to
15 ratepayers . "70
16 The California Wildfire Fund provided $21 billion
17 of claim-paying coverage to California IOUs in the event
18 of wildfire damages exceeding $1 billion (assumed to
19 approximate the level of commercial insurance available
20 to each of the California IOUs) . Utility shareholders
21 and customers both contributed to the fund in equal
22 measure .
69 This concept was further developed by the CPUC in its Order Instituting
Rulemaking to Implement Public Utilities Code Section 451.2 Regarding
Criteria and Methodology for Wildfire Cost Recovery Pursuant to Senate
Bill 901 (2018) , July 8, 2019.
70 AB 1054, Section 1 (a) (5) .
Graves, Di 47
Rocky Mountain Power

1 It is my understanding that AB 1054 established
2 standards by which the CPUC could determine whether a
3 utility had acted prudently and was therefore eligible
4 to recover wildfire costs through the Fund (or, if the
5 Fund had been exhausted, potentially through electric
6 rates) . Prudent conduct in connection with a wildfire
7 event was broadly defined as that consistent with
8 actions that a reasonable utility would have undertaken
9 under similar circumstances, at the relevant point in
10 time, and based on the information available at that
11 time . In due course prudent utility conduct was more
12 specifically codified in the form of specific wildfire
13 mitigation programs and protocols needed to obtain a
14 "safety certification" which formed the main criterion
15 for access to the Fund. Importantly, as part of
16 qualifying for a safety certification, a utility' s
17 implementation of its wildfire mitigation plan "is
18 evaluated based on actions taken by a utility, not the
19 outcome of those actions . "71
71 See Safety Certification FAQ I Office of Energy Infrastructure Safety,
https://energysafety.ca.gov/what-we-do/electrical-infrastructure-
safety/wildfire-mitigation-and-safety/safety-certifications/safety-
certification-faqs/.
Graves, Di 48
Rocky Mountain Power

1 Q. Does Rocky Mountain Power benefit by any similar
2 mechanisms?
3 A. Yes . It is my understanding that Utah Senate Bill 224
4 ("SB 224") , enacted in March 2024, authorizes large-
5 scale electric utilities in that state to establish a
6 "Utah fire fund" for the purpose of offsetting
7 exclusively Utah-specific third-party wildfire
8 liabilities that are beyond the utility' s insurance (or
9 self-insurance) coverage limits, up to 50 percent of the
10 utility' s revenue requirement . Subject to approval by
11 the Commission, the Utah fire fund is intended to support
12 "the financial health of the large-scale electric
13 utility"72 and maintain or improve "the large-scale
14 electric utility' s ability to deliver safe reliable
15 services . "73 In support of the fund, a large-scale
16 electric utility may collect a customer surcharge over
17 a 10-year period, subject to limits on annual rate
18 increases (or cumulative amounts over 50 percent of the
19 utility' s revenue requirement) .
20 Separately, SB 224 limits utility liability for
21 third-party wildfire claims (including specified dollar
22 caps for certain non-economic damages) subject to
72 Utah S.B. 224, Part 3 § 54-24-301 (4) (a) .
73 Id.
Graves, Di 49
Rocky Mountain Power

1 Commission determination of utility compliance with a
2 wildfire mitigation plan. 74
3 The above features of SB 224 are unambiguously
4 favorable for the financial health of Rocky Mountain
5 Power. Details of how to integrate such state-specific
6 features into PacifiCorp' s overall insurance portfolio
7 are to be determined, but these features do not alter
8 the need for the mechanisms PacifiCorp is introducing
9 here .
10 Q. To what extent should extreme event wildfire risk be the
11 responsibility of utility customers?
12 A. Ultimately, all reasonable costs of the utility, whether
13 preemptive (insurance, mitigation) or reactive
14 (uncovered claims) , must be reasonably expected to be
15 recoverable in order for it to maintain financial
16 integrity sufficient to provide reliable, cost-effective
17 service and to attract capital . Wildfire costs are no
18 exception, despite the complex ways in which they may
19 arise or the abnormal size they could reach. As long as
20 they are not a product of gross negligence or
21 incompetence, they should be fully recoverable, either
22 spread out broadly and over time via pre-paid commercial
23 or self-insurance, or amortized after the fact for
24 amounts not covered by such reserves . As noted above in
74 Id. § 54-24-303, (3) , (4) and (6) .
Graves, Di 50
Rocky Mountain Power

1 Section IV, wildfire mitigation cannot reasonably be
2 expected to eliminate all risks . That is both infeasible
3 in principle and it becomes uneconomical at extremes .
4 Additionally, for regulated utilities, the necessary
5 judgment-calls relating to system hardening and/or
6 operating protocols do not fall solely within the
7 discretion of management . Mitigation expenditures and
8 operating protocols must be approved by regulators on
9 behalf of customers . This is a judgment based not so
10 much on fire prevention by itself but on what fire
11 prevention efforts could crowd out, assuming there is a
12 practical cap on what level of rates is acceptable . This
13 feature of the regulatory compact amounts, at minimum,
14 to an implicit recognition by regulators that agreed
15 mitigation efforts are optimized from a customer
16 spending and cost/benefit balancing perspective, and
17 therefore such costs (both direct and their residual
18 fire damage outcomes, if any) are prudent .
19 Q. How should customer responsibility for wildfire damage
20 claims be considered in cost recovery protocols?
21 A. It is certainly possible that legal reviews of fire
22 liability and damages may deem utilities responsible for
23 fires and their third-party harms . However, liability or
24 negligence standards brought to bear in wildfire damage
25 claims against utilities may not be aligned with the
Graves, Di 51
Rocky Mountain Power

1 guidelines or trade-offs necessarily embedded in
2 efficient and prudent wildfire mitigation plans and
3 overall utility management. The clearest example of this
4 is the doctrine of "inverse condemnation" applicable in
5 California, which imposes strict liability on the
6 utility without reference to regulatory standards of
7 prudent management . Negligence standards in other
8 jurisdictions may be interpreted to effectively embed
9 inverse condemnation, or for different reasons do not
10 reflect or proxy for feasible wildfire mitigation
11 plans . 75 Neither judges nor juries can be expected to
12 evaluate the technical intricacies of such plans, nor to
13 identify what tradeoffs were made or would have resulted
14 from a different course of action than what damaged the
15 plaintiffs .
16 In contrast, those considerations are central to
17 utility regulation and compensation for utility
18 operations . In essence, the analysis brought to bear in
19 assigning legal liability may not be similar to what is
20 appropriate and conventional for setting regulatory
21 responsibility standards, so adverse opinions from the
75 Notably, the California Wildfire Fund is intended as financial relief
from findings of liability, based on prudent utility management. See
Safety Certification FAQ I Office of Energy Infrastructure Safety,
https://energysafety.ca.gov/what-we-do/electrical-infrastructure-
safety/wildfire-mitigation-and-safety/safety-certifications/safety-
certification-faqs/.
Graves, Di 52
Rocky Mountain Power

1 former should not automatically bleed over to governing
2 disallowance actions of the latter.
3 Instead, it logically falls to utilities, to
4 choose, in conjunction with customers and regulators, a
5 level of mitigation that is balanced and acceptable. The
6 process is one of negotiation as well as analysis . Key
7 trade-offs must be evaluated between factors including
8 fire mitigation, service quality and reliability, rate
9 increases, and potential future exposure . As noted
10 above, the consensus solution is likely to stop well
11 short of attempting to solve the whole problem rapidly
12 or even fully.
13 As a natural consequence of these processes, there
14 will be residual risk —elected jointly by the
15 stakeholders . In this circumstance, one in which near-
16 term wildfire mitigation spending and associated rate
17 increases are balanced with competing imperatives, there
18 must be provision for recovering residual exposure
19 should it be incurred.
20 Q. What is the responsibility of the utility?
21 A. The quid pro quo for such contingent cost recovery, of
22 course, is that utility managers diligently pursue a
23 well-defined wildfire mitigation plan accepted by
24 customers and regulators . In the parlance of schools,
25 they should be graded on effort not on outcomes, as the
Graves, Di 53
Rocky Mountain Power

1 former are controllable while here the latter are not so
2 much. This principle was established in forming the
3 California Wildfire Fund, with the following key
4 components :
5 • Utility access to the insurance function of the
6 California Wildfire Fund is contingent on
7 maintaining a safety certification giving evidence
8 of compliance with an approved wildfire mitigation
9 plan.
10 • Such compliance is to be evaluated based on agreed
11 mitigation efforts—not wildfire outcomes—in
12 recognition of the challenges facing wildfire
13 mitigation and the regulatory process in forming a
14 consensus wildfire mitigation plan.
15 • Adherence to mitigation plan should be deemed proof
16 of prudence hence cost recovery. That is, absent
17 negligence, regulators should evaluate utilities on
18 the quality of their inputs to the fire prevention
19 problem, not on the outputs of how many fires
20 happen, how much they cost, or even whether a piece
21 of utility equipment was involved (except insofar
22 as that is a basis for revising future mitigation) .
Graves, Di 54
Rocky Mountain Power

1 Q. How does PacifiCorp' s proposal to address extreme risk
2 meet these criteria?
3 A. PacifiCorp' s proposal to establish a Catastrophic Fire
4 Fund remains in development via the stakeholder workshop
5 process . It is being proposed in conjunction with a
6 material slate of mitigation activities that should help
7 reduce the risks of fires occurring, but as noted
8 earlier, the ultimate scale of any fires that do occur
9 is largely beyond control, if those coincide with
10 adverse weather conditions . Thus, a Catastrophic Fund
11 remains essential . I understand that the details of the
12 Catastrophic Fire Fund proposal are intended to reflect
13 the principles enumerated above as they take further
14 shape .
15 VI . CONCLUSIONS
16 Q. Please summarize your principal conclusions .
17 A. My principal conclusions can be summarized as follows :
18 • PacifiCorp is facing an exogenous, largely climate-
19 induced phenomenon in increased wildfire risk.
20 • With wildfire risks mounting, the cost of wildfire
21 liability insurance is increasing dramatically.
22 Those costs should be recoverable even if not
23 perfectly foreseen in prior rate cases, akin to the
24 way fuel costs adjust .
Graves, Di 55
Rocky Mountain Power

1 • Similarly positioned utilities have crafted
2 workable solutions for those costs that recognize
3 wildfire insurance as a legitimate cost of service
4 in recent rate-case proceedings .
5 • To the degree that PacifiCorp encounters
6 dysfunctional commercial insurance markets similar
7 to what the California IOUs have faced in recent
8 years PacifiCorp should avail itself of the
9 benefits of self-insurance in some form.
10 • To the degree that PacifiCorp faces material and
11 increasing likelihood of catastrophic exposure to
12 unprecedented levels of extreme wildfire loss
13 claims, as ongoing analysis indicates is a credible
14 concern, PacifiCorp is proposing a Catastrophic
15 Fire Fund to provide liquidity and maintain longer
16 term financial stability. The design (size,
17 positioning and funding) of this Fund need to be
18 specified after better analytic information is
19 available about the risk magnitudes .
20 • Subject to compliance with reasonable mitigation
21 standards, uninsured extreme wildfire loss claims
22 (if they occur) should be viewed as costs of utility
23 service recoverable from customers (just as
24 insurance premia normally are) . This is true
25 regardless of legal decisions attributing utility
Graves, Di 56
Rocky Mountain Power

1 liability for fires, unless those findings are
2 based on gross negligence .
3 • Thus, some form of agreed, socialized cost recovery
4 for these adverse possible situations should be
5 developed before they arise .
6 Q. Does this conclude your direct testimony?
7 A. Yes .
Graves, Di 57
Rocky Mountain Power

Case No. PAC-E-24-04
Exhibit No. 18
Witness : Frank Graves
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Frank Graves
Resume of Frank Graves
May 2024

Rocky Mountain Power
Exhibit No. 18 Page 1 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Principal
Boston,MA +1.617.864.7900 [e-mail]
Mr. Frank C. Graves is a Principal of The Brattle Group who specializes in regulatory and financial
economics, especially for electric and gas utilities, and in litigation matters related to securities litigation,
damages from breached energy contracts, and risk management.
He has over 40 years of experience assisting utilities in forecasting,valuation, financial planning, and risk
management for many kinds of long range investment and service design decisions, such as generation
and network capacity expansion, fuel and gas supply procurement and hedging, pricing and cost recovery
mechanisms, cost and performance benchmarking, renewable asset selection and contracting, and new
business models for distributed energy technologies. He has testified before many state regulatory
commissions and the FERC as well as in state and federal courts and arbitration proceedings on such
matters as the prudence of investment and contracting decisions, risk management, cost of capital, costs
and benefits of new services, policy options for industry restructuring, adequacy of market competition,
and competitive implications of proposed mergers and acquisitions.
In the area of financial economics,he has assisted and testified in civil cases in regard to contract damages
estimation,securities litigation suits,special purpose audits of non-standard business transactions and their
accounting, tax disputes, risk management, and cost of capital estimation, and he has testified in criminal
cases regarding corporate executives' culpability for securities fraud.
He received an M.S.with a concentration in finance from the M.I.T. Sloan School of Management in 1980,
and a B.A. in Mathematics from Indiana University in 1975.
Mr. Graves is also a professional violinist and chairperson of the Dean's Advisory Council to the
Jacobs School of Music at Indiana University
AREAS OF EXPERTISE
• Utility Planning and Operations
• Financial Analysis and Commercial Litigation
• Regulated Industry Policy and Restructuring
• Energy Market Competition
PROFESSIONAL AFFILIATIONS
• IEEE Power Engineering Society
• Mathematical Association of America
• American Finance Association
Brattle 1

Rocky Mountain Power
Exhibit No. 18 Page 2 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Recent Activities
Testimony
For Public Service Company of New Mexico, Case No. 22-00270-UT before the New Mexico Public
Service Commission, Mr. Graves provided testimonies on whether the Four Corners Power Plant had
been prudently evaluated, environmentally upgraded, and contracted for fuel in decisions made over
the prior decade. Direct testimony December 2022, rebuttal July 2023.
For Peoples' Gas Light Co. and North Shore Gas of Chicago, he testified in their general rate cases
regarding whether various cost recovery or capital expenditure constraints should be place on the
companies because of expected decarbonization policies in Illinois that could cause natural gas to be
displaced by electrification. He argued that this is an important issue requiring more analysis and more
stakeholders than a GRC setting includes, so those issues should be set for a series of Future of Gas
workshops. Docket Nos. 23-0068 and 23-0069 before the Illinois Commerce Commission, June 2023.
For the Alberta Utilities Commission, Mr. Graves provided written direct and rebuttal testimony on
cost of capital risk-positioning in regard to decarbonization policies, and on the financial impacts of
service bypass by Rural Electrification Associations on FortisAlberta Company, Proceeding 27084,
February and April 2023.
For Holtec International, Mr. Graves provided testimony regarding feasibility of completing disposal
of spent nuclear fuel from decommissioning of Palisades nuclear plant ISFSI by 2040, before the
Nuclear Regulatory Commission, Docket No(s). 50-255-LT-2, 50-155-LT-2, 72-007-LT, 72-043-LT-2,
February 2023.
For Commonwealth Edison Company, testimony on the cost of equity capital for ComEd's four-year
rate plan, before the Illinois Commerce Commission. Docket No. 23-0055,January 17, 2023.
For members of the Wisconsin Utilities Association, testimony on how to regulate rooftop solar
development when it is contracted under long term power purchase agreements, Case No 9300-DR-
105, November 1 and 2, 2022,Wisconsin Public Service Commission.
For Peoples Gas Light and Coke, Inc. in Chicago, Illinois he testified on how to establish prudence for
recurring annual expenditures to replace aged and corroded iron pipe gas distribution infrastructure,
before the Illinois Commerce Commission, Docket 17-0137, October 2022.
For Northstar Vermont Yankee Co., he testified in the Court of Federal Claims (October 31, 2022)
regarding the company's position in a market for exchanging positions in the queue of spent nuclear
fuel removal rights, had DOE not breached its obligations to create a permanent repository. Oral
direct and rebuttal testimonies were presented. Docket 18-1209C.
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Exhibit No. 18 Page 3 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
For WE Energies, Mr. Graves provided testimony on the importance of maintaining or growing fixed
charges in electric rates as more and more customers adopt self-supply(rooftop solar)and smart energy
management technologies. Case Nos. 5-UR-110 and 6690-UR-127, October 4, 2022.
On behalf of Entergy's System Energy Resources,Inc.,Mr.Graves testified(September 28,2022)before
the FERC about whether various costs of structuring and periodically refinancing a capital lease for a
portion of the Grand Gulf Nuclear Station had been recorded properly for accounting and ratemaking
purposes under formula rates. FERC Docket EL20-72-000.
For Calpine Corp. Mr Graves testified in Bankruptcy Court in regard to why extraordinarily high
power prices that arose during the February 2021 extreme freeze causing nearly half of Texas to lose
power for several days should not be waived as ongoing liabilities for Brazos Municipal Power
Cooperative, which had incurred a $1.5billion liability to ERCOT from its inabilities to cover (or
hedge) its power needs during that situation. Docket No. 21-03863-ADV, March 2, 2022
For Public Service Company of New Mexico, Mr. Graves presented rebuttal and sur-rebuttal (March
15, 2021)testimonies before the NMPSC (Case No. 21-00017-UT) on whether ownership of a share of
the Four Corners power plant had been imprudently sustained in the past decade. He presented
analyses that supplemented past resource planning and that compared the realized costs of the Four
Corners plant to the alternative gas plant that critics felt should have been chosen, showing that even
if imprudent,little or no damages had ensued.
For Alta Windpower, testimony in regard to whether locations of adjacent wind farms was causing
interference and if so, how much harm to output was occurring (JAMS Case No.1220065657, January
16, 2021). He showed that plaintiff's alleged damages were highly speculative and overstated because
based on only a single scenario for complex future decarbonization economics, and that the plaintiffs
projection was out of line compared to many other forecasts.
For PacifiCorp before the Oregon Public Utility Commission (Docket UE-374, February 2020), Mr.
Graves prepared testimony on the difficulties in forecasting short-term power system balancing and
trading transactions and the resulting tendency for these to be underestimated in projected operating
costs,hence under-collected in rates. Based on a comparison to other states practices,he proposed that
such costs be fully recovered on a flow-through basis without risk-sharing, subject to prudence.
Client Engagements
• Electric resource planning is a much harder and different problem under deep decarbonization
goals than it was for the past few decades. Finding an economic mix of enough clean energy to
serve annual energy requirements, and electrifying then fitting/shifting load to the times when
that clean energy will be most available,have become much more important than efficient choices
for capacity adequacy. Mr. Graves is involved in IRP studies and in technology assessments of
what emerging clean energy mechanisms will be most likely to succeed, or what it would take for
them to do so.
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Exhibit No. 18 Page 4 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
• Mr.Graves has lead a study of how ambitious economy-wide decarbonization policies in New York
are creating a possible "death spiral" risk for natural gas distribution companies, due to potential
demand contraction from electrifying end-uses traditionally served by natural gas at the same time
as the industry requires capital investments in safety upgrades to aging infrastructure. He has
developed cost-benefit models of alternative pricing mechanisms for serving electric power
generators, as well as systems dynamics models of the feedbacks and tipping points in gas
distribution that may ensue unless significant regulatory innovations are allowed.
• Economic recovery from the stresses of the Covid pandemic involves significant opportunities for
infrastructure improvements. For the Coalition for Green Capital, Mr. Graves lead a Brattle team
collaborating with The Analysis Group to develop a proposal for a $100 billion"green accelerator"
package that would be provide funding and risk-sharing to debottleneck energy industry
improvements that would reduce GHG emissions, provide quick economic stimulus, and improve
equity to disadvantaged communities and customer segments. It is a portion of the infrastructure
bills being considered by Congress. Relatedly, he prepared an assessment of expected economic
harm from low income rental evictions from ending the Covid moratorium on rent liabilities, on
behalf of the National Low Income Housing Coalition.
• Liability for wildfire damages drove PG&E to bankruptcy in 2020. Mr. Graves was part of an
advisory team that helped appraise and explain the financial benefits to alternative means of
compensating victims as part of the debtor's Plan of Reorganization, including securitized debt or
contingent payments tied to future financial stability of the company.
• With improvements in performance and cost of microgeneration, as well as low cost natural gas,
many hospitals, universities, and similar campuses are considering combined heat and power
supply as an alternative to utility energy services. Mr. Graves has helped several such entities
evaluate potential benefits of CHP, including choosing the preferred size and mix of technology
and design of risk sharing terms in financial and operating contracts for the CHP systems.
Publications
"The Emerging Economics of Hydrogen Production", a Brattle presentation prepared in collaboration
with Environmental Defense Fund, reviewing hydrogen costs foreseeable through 2030 with recent
IRA tax incentives and improving technologies. Prepared with Josh Figueroa, Ragini Sreenath,
Lorenzo Sala,Jadon Grove, and Steven Thumb, March, 2024.
"The Role of Nuclear Power in US Electricity Markets"prepared with Carless Traviss for MIT and
CATF's Nuclear Power in a Low Carbon World conference,August 2023,
"Future of Gas Series: Transitioning Gas Utilities to a Decarbonized Future,"three Brattle
presentations (Assessing Risks,Aug 2021; Evaluating Strategies, Sept 2021; Setting Regulations, Nov
2021)with Long Lam, Kasparas Spokas, Josh Figueroa, Tess Counts, and Shreeansh Agarwal
"Brattle Issue Brief on ERCOT's Power Outage",March 2021, with Sam Newell, Jesse Cohen, and
Sophie Leamon.
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Rocky Mountain Power
Exhibit No. 18 Page 5 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
"2020 CAISO Blackouts and Beyond: The Future of California Resource Planning"with John Tsoukalis
and Sophie Leamon for LSI's Electric Power in the West Conference, January 2021.
"Clean Energy and Sustainability Accelerator—Opportunities for Long Term Deployment" on
recommended targets and mechanisms for use of a $100 billion economic recovery and decarbonization
stimulus package for the Biden administration. With Bob Mudge, Roger Lueken, and Tess Counts.
Prepared for the Coalition for Green Capital, January 14, 2021.
"Emerging Value of Carbon Capture for Utilities"with Kasparas Spokas and Katie Mansur, Public
Utilities Fortnightly, October 2020,p. 36-41
"Impacts and Implications of COVID-19 for the Energy Industry"for Energy Bar Association's Virtual
Fall Conference, October 13, 2020. (Also several presentations with co-authors Bob Mudge,Tess
Counts, Josh Figueroa, Lily Mwalenga, and Shivangi Panon the same topic at earlier dates, for public
release and other conferences.)
"System Dynamics Modeling: An Approach to Planning and Developing Strategy in the Changing
Electricity Industry" (with Toshiki Bruce Tsuchida, Philip QHanser, and Nicole Irwin), Brattle White
Paper, April 2019.
"California Megafires: Approaches for Risk Compensation and Financial Resiliency Against Extreme
Events" (with Robert S. Mudge and Mariko Geronimo Aydin), Brattle White Paper, October 1, 2018.
"Retail Choice: Ripe for Reform?" (with Augustin Ros, Sanem Sergici, Rebecca Carroll and
Kathryn Haderlein), Brattle White Paper, July 2018.
"Resetting FERC RoE Policy; a Window of Opportunity" (with Robert Mudge and Akarsh
Sheilendranath), Brattle White Paper, May 2018
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Exhibit No. 18 Page 6 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Full C.V.
Financial Analysis and Commercial Litigation
• Mr. Graves assisted a nuclear genco considering transfer of its responsibilities for spent fuel
management and site remediation to a third party aspiring to consolidate waste management
at a national repository. Analyses and financial projections of the costs, risks, and regulatory
hurdles for both approaches were developed to find the range of conditions under which the
transfer would be beneficial for the genco and financially viable for the new management
company.
• Liability for wildfire damages drove PG&E to bankruptcy in 2020. Mr. Graves was part of an
advisory team that helped appraise and explain the financial benefits to alternative means of
compensating victims as part of the debtor's Plan of Reorganization,including securitized debt
or contingent payments tied to future financial stability of the company.
• A public power utility faced viability-threatening financial distress after a major baseload
power plant project proved uneconomic when only partly completed. Mr. Graves led a team
that reassessed the decision path that resulted in this outcome, in order to identify what
expenditures or contract commitments might be deemed imprudent. He developed system and
financial models of the company under alternative resource plans, which also informed how
much financial burden would ensue from different kinds of penalties.
• Wildfires in California have become catastrophic in the past 5 years, creating both financial
turmoil for the utilities and controversy over how to insure and manage this problem. Mr.
Graves has been extensively involved in estimating the expected, growing cost of this problem
and the design of mechanisms to insure it and compensate investors for the likelihood of
uncompensated costs from fire damages.
• Despite well settled financial economics, there is great regulatory controversy surrounding
how or whether to make adjustments in cost of capital measurements for differences in
leverage between the proxy firms used to estimate the rate and the capital structure of the
target utility. Mr. Graves has lead analyses of how to demonstrate the need for this adjustment,
with testimony given to explain the foundations.
• For the government of Colombia, Mr. Graves testified in arbitration about misrepresentations
that occurred in the negotiation of royalties over coal mining production. Those negotiations
resulted in a royalty scheme that was much more favorable to the coal company than would
have been acceptable to Colombia had more realistic representations occurred. He showed that
the mining companies own studies projected much higher value and more favorable operating
conditions for the facility, and that alternative schedules for running the mine would have
produced more value than was asserted possible by its owners.
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Exhibit No. 18 Page 7 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
• For the co-owners of the SONGS nuclear power plant that had become inoperable due to failed
and irreparable steam generators, Mr. Graves provided written and oral testimony in
arbitration over what damages had been incurred by the utilities from having to replace the
nuclear plant with new generation, purchased power, and transmission upgrades, as well as
accelerated decommissioning liabilities. His report evaluated the impacts of the lost plant on
the entire western power market, including how it would change the needs and costs for
emission allowances in the California GHG market. He estimated that damages were nearly
$7 billion dollars.
• For an international energy company seeking to expand its operations in the US, Mr. Graves
lead an assessment of the market performance risks facing a possible acquisition target,in order
to determine what contingencies or market shifts were critical to it being an attractive target.
Uncertain long run wholesale energy conditions, tightening environmental regulations, and
disruptive technology development prospects were considered.
• For an international technology firm that had experienced a recent bankruptcy, Mr. Graves
assisted in the design of a study of how the remaining valuable assets could be deemed
assignable to disparate country-specific claims. Company operating practices for research and
development risk and profit sharing were evaluated to identify an equitable approach.
• For a merchant power company with a prematurely terminated development contract, Mr.
Graves co-lead a team to value the lost contract. The contract included several different kinds
of revenue streams of different risks, for which Brattle developed different discount rates and
debt carrying-capacity assessments. The case was settled with a very large award consistent
with the Brattle valuations.
• Holding company utilities with many subsidiaries in different states face differing kinds of
regulatory allowances, balancing accounts with differing lags and allowed returns for cost
recovery, possibly different capital structures, as well as different (and varying) operating
conditions. Given such heterogeneity, it can be difficult to determine which subsidiaries are
performing well vs. poorly relative to their regulatory and operational challenges. Mr. Graves
developed a set of financial reporting normalization adjustments to isolate how much of each
subsidiary's profitability was due to financial, vs. managerial, vs. non-recurring operational
conditions, so that meaningful performance appraisal was possible.
• Many banks, insurance firms and capital management subsidiaries of large multinational
corporations have entered into long term, cross border leases of properties under sale and
leaseback or lease in, lease out terms. These have been deemed to be unacceptable tax shelters
by the IRS, but that is an appealable claim. Mr. Graves has assisted several companies in
evaluating whether their cross border leases had legitimate business purpose and economic
substance, above and beyond their tax benefits, due to likelihood of potentially facing a role as
equity holder with ownership risks and rewards. He has shown that this is a case-specific
matter, not per se determined by the general character of these transactions.
• For a private energy hedge fund providing risk management contracts to industrial energy
users, a breach of contract from one industrial customer was disputed as supposedly involving
little or no loss because the fiend had not been forced to liquidate positions at a loss that
corresponded precisely to the abruptly terminated contract. Mr. Graves provided analysis
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Exhibit No. 18 Page 8 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
demonstrating how the portfolio loss was borne, but other fund management metrics used to
control positions, and other unrelated hedging positions, also changed roughly concurrently in
a manner that disguised the way the economic damage was realized over time. The case was
settled on favorable terms for Mr. Graves' client.
• Many utilities have regulated and unregulated subsidiaries, which face different types and
degrees of risk.Mr.Graves lead a study of the appropriate adjustments to corporate hurdle rates
for the various lines of business of a utility with many types of operations.
• A company that incurred Windfall Tax liabilities in the U.K. regarded those taxes as creditable
against U.S. income taxes, but this was disputed by the IRS. Mr. Graves lead a team that
prepared reports and testimony on why the Windfall Tax had the character of a typical excess
profits tax, and so should be deemed creditable in the U.S. The tax courts concurred with this
opinion and allowed the claimed tax deductions in full.
• For a defendant in a sentencing hearing for securities' fraud, Mr. Graves prepared an analysis
of how the defendant's role in the corporate crisis was confounded by other concurrent events
and disclosures that made loss calculations unreliable. At trial,the Government stipulated that
it agreed with Mr. Graves' analysis.
• For the U.S. Department of Justice,Mr. Graves prepared an event study quantifying bounds on
the economic harm to shareholders that had likely ensued from revelations that Dynegy
Corporation's "Project Alpha" had been improperly represented as a source of operating
income rather than as a financing. The event study was presented in the re-sentencing hearing
of Mr. Jamie Olis, the primary architect of Project Alpha.
• For a utility facing significant financial losses from likely future costs of its Provider of Last
Resort(POLR)obligations,Mr. Graves prepared an analysis of how optimal hindsight coverage
of the liability would have compared in costs to a proposed restructuring of theobligation. He
also reviewed the prudence of prior, actual coverage of the obligation in light of conventional
risk management practices and prevailing market conditions of credit constraints and low long-
term liquidity.
• Several banks were accused of aiding and abetting Enron's fraudulent schemes and were sued
for damages. Mr. Graves analyzed how the stock market had reacted to one bank's equity
analyst's reports endorsing Enron as a "buy,"to determine if those reports induced statistically
significant positive abnormal returns. He showed that individually and collectively they did
not have such an effect.
• Mr. Graves lead an analysis of whether a corporate subsidiary had been effectively under the
strategic and operational control of its parent, to such an extent that it was appropriate to
"pierce the corporate veil" of limited liability. The analysis investigated the presence of
untenable debt capitalization in the subsidiary, overlapping management staff, the adherence
to normal corporate governance protocols, and other kinds of evidence of excessive parental
control.
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Exhibit No. 18 Page 9 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
• As a tax-revenue enhancement measure, the IRS was considering a plan to recapture deferred
taxes associated with generation assets that were divested or reorganized during state
restructurings for retail access. Mr. Graves prepared a white paper demonstrating the
unfairness and adverse consequences of such a plan, which was instrumental in eliminating
the proposal.
• For a major electronics and semiconductor firm, Mr. Graves critiqued and refined a proposed
procedure for ranking the attractiveness of research and development projects. Aspects of risk
peculiar to research projects were emphasized over the standards used for budgeting an already
proven commercial venture.
• In a dispute over damages from a prematurely terminated long-term power tolling contract,
Mr. Graves presented evidence for the plaintiff power plant on why calculating the present value
of those damages required the use of two distinct discount rates: one (a low rate) for the
revenues lost under the low-risk terminated contract and another, much higher rate, for the
valuation of the replacement revenues in the risky, short-term wholesale power markets. The
amount of damages was dramatically larger under a two-discount rate calculation, which was
the position adopted by the court.
• The energy and telecom industries, especially in the late 1990s and early 2000s, were plagued
by allegations regarding trading and accounting misrepresentations, such as wash trades,
manipulations of mark-to-market valuations,premature recognition of revenues,and improper
use of off-balance sheet entities. In many cases, this conduct has preceded financial collapse
and subsequent shareholder suits. Mr. Graves lead research on accounting and financial
evidence, including event studies of the stock price movements around the time of the
contested practices, and reconstruction of accounting and economic justifications for the way
asset values and revenues were recorded.
• Dramatic natural gas price increases in the U.S. often put natural gas and electric utilities in the
position of having to counter claims that they should have hedged more of their fuel supplies
at times in the past. For several companies, Mr. Graves developed testimony to rebut this
hindsight criticism and risk management techniques for fuel (and power) procurement for
utilities to apply in the future to avoid prudence challenges.
• As a means of calculating its stranded costs, a utility used a partial spin-off of its generation
assets to a company that had a minority ownership from public shareholders. A dispute arose
as to whether this minority ownership might be depressing the stock price, if a "control
premium" was being implicitly deducted from its value. Using event studies and structural
analyses, Mr. Graves identified the key drivers of value for this partially spun-off subsidiary,
and he showed that value was not being impaired by the operating, financial and strategic
restrictions on the company. He also reviewed the financial economics literature on empirical
evidence for control premiums,which he showed reinforced the view that no control premium
de-valuation was likely to be affecting the stock.
• A large public power agency was concerned about its debt capacity in light of increasing
competitive pressures to allow its resale customers to use alternative suppliers. Mr.Graves lead
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Exhibit No. 18 Page 10 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
a team that developed an Economic Balance Sheet representation of the agency's electric assets
and liabilities in market value terms,which was analyzed across several scenarios to determine
safe levels of debt financing. In addition, new service pricing and upstream supply contracting
arrangements were identified to help reduce risks.
• Wholesale generating companies intuitively realize that there are considerable differences in
the financial risk of different kinds of power plant projects, depending on fuel type,length and
duration of power purchase agreements, and tightness of local markets. However, they often
are unaware of how if at all to adjust the hurdle rates applied to valuation and development
decisions. Mr. Graves lead a Brattle analysis of risk-adjusted discount rates for generation;very
substantial adjustments were found to be necessary.
• A major telecommunications firm was concerned about when and how to reenter the Pacific
Rim for wireless ventures following the economic collapse of that region in 1997-99. Mr.
Graves lead an engagement to identify prospective local partners with a governance structure
that made it unlikely for them to divert capital from the venture if markets went soft. He also
helped specify contracting and financing structures that create incentives for the venture to
remain together should it face financial distress, while offering strong returns under good
performance.
• There are many risks associated with operations in a foreign country, related to the stability of
its currency, its macro economy, its foreign investment policies, and even its political system.
Mr. Graves has assisted firms facing these new dimensions to assess the risks, identify strategic
advantages,and choose an appropriate,risk-adjusted hurdle rate for the market conditions and
contracting terms they will face.
• The glut of generation capacity that helped usher in electric industry restructuring in the US
led to asset devaluations in many places, even where no retail access was allowed. In some
cases,this has led to bankruptcy,especially of a few large rural electric cooperatives.Mr.Graves
assisted one such coop with its long term financial modeling and rate design under its plan of
reorganization,which was approved. Testimony was provided on cost-of-service justifications
for the new generation and transmission prices, as well as on risks to the plan from potential
environmental liabilities.
• Power plants often provide a significant contribution to the property tax revenues of the
townships where they are located. A common valuation policy for such assets has been that
they are worth at least their book value, because that is the foundation for their cost recovery
under cost-of-service utility ratemaking. However, restructuring throws away that guarantee,
requiring reappraisal of these assets. Traditional valuation methods, e.g., based on the
replacement costs of comparable assets,can be misleading because they do not consider market
conditions. Mr. Graves testified on such matters on behalf of the owners of a small, out-of-
market coal unit in Massachusetts.
• Stranded costs and out-of-market contracts from restructuring can affect municipalities and
cooperatives as well as investor-owned utilities. Mr. Graves assisted one debt-financed utility
in an evaluation of its possibilities for reorganization, refinancing, and re-engineering to
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Exhibit No. 18 Page 11 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
improve financial health and to lower rates. Sale and leaseback of generation, fuel contract
renegotiation, targeted downsizing, spin-off of transmission, and new marketing programs
were among the many components of the proposed new business plan.
• As a means of reducing supply commitment risk, some utilities have solicited offers for power
contracts that grant the right but not the obligation to take power at some future date at a
predetermined price, in exchange for an initial option premium payment. Mr. Graves assisted
several of these utilities in the development of valuation models for comparing the asking
prices to fair market values for option contracts. In addition,he has helped these clients develop
estimates of the critical option valuation parameters, such as trend,volatility, and correlations
of the future prices of electric power and the various fuel indexes proposed for pricing the
optional power.
• For the World Bank and several investor-owned electric utilities,Mr.Graves presented tutorial
seminars on applying methods of financial economics to the evaluation of power production
investments. Techniques for using option pricing to appraise the value of flexibility (such as
arises from fuel switching capability or small plant size)were emphasized.He has applied these
methods in estimating the value of contingent contract terms in fuel contracts (such as price
caps and floors) for natural gas pipelines.
• Mr. Graves prepared a review of empirical evidence regarding the stock market's reaction to
alternative dividend, stock repurchase, and stock dividend policies for a major electric utility.
Tax effects, clientele shifting, signaling, and ability to sustain any new policies into the future
were evaluated. A one-time stock repurchase, with careful announcement wording, was
recommended.
• For a division of a large telecommunications firm, Mr. Graves assisted in a cost benchmarking
study, in which the costs and management processes for billing, service order and inventory,
and software development were compared to the practices of other affiliates and competitors.
Unit costs were developed at a level far more detailed than the company normally tracked, and
numerical measures of drivers that explained the structural and efficiency causes of variation
in cost performance were identified. Potential costs savings of 10-50 percent were estimated,
and procedures for better identification of inefficiencies were suggested.
• For an electric utility seeking to improve its plant maintenance program, Mr. Graves directed
a study on the incremental value of a percentage point decrease in the expected forced outage
rate at each plant owned and operated by the company. This defined an economic priority
ladder for efforts to reduce outage that could be used in lieu of engineering standards for each
plant's availability. The potential savings were compared to the costs of alternative schedules
and contracting policies for preventive and reactive maintenance, in order to specify a cost
reduction program.
• Mr. Graves conducted a study on the risk-adjusted discount rate appropriate to a publicly-
owned electric utility's capacity planning. Since revenue requirements (the amounts being
discounted) include operating costs in addition to capital recovery costs, the weighted average
cost of capital for a comparable utility with traded securities may not be the correct rate for
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Exhibit No. 18 Page 12 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
every alternative or scenario. The risks implicit in the utility's expansion alternatives were
broken into component sources and phases, weighted, and compared to the risks of bondsand
stocks to estimate project-specific discount rates and their probable bounds.
Utility Planning and Operations
• Uncertainty over the pace and extent of potential distributed energy resources(DERs)adoption
by customers makes load forecasting and system planning much more complex, possibly
involving future "tipping points" when DER use could accelerate rapidly. However, statistical
histories on these improving technologies are not yet very informative as to when or why such
a shift might occur. Mr. Graves has assisted several distribution utilities with a new,behavior-
based modeling technique for long range system planning that simulates possible paths to DER
adoption, utilizing system dynamics methods that recognize feedbacks between electricity
prices, customers' propensities to use DERs, declining technology costs, cost shifting to non-
users, load shapes, and financial performance.
• Many large high-tech firms are seeking power supply services relying entirely on renewable
resources.This can only be done for average or cumulative power needs,but the resulting green
energy production will not match the time pattern of those firms' demand. Mr. Graves lead a
team evaluating how much risk is borne by a utility from offering such service over many years,
when it will have to balance a significant green supply(such as rooftop and utility- scale solar)
against its own load and the regional market.
• With improvements in performance and cost of microgeneration,many hospitals,universities,
and similar campuses are considering combined heat and power supply as an alternative to
utility energy services. Mr. Graves has helped several such entities evaluate potential benefits
of CHP, including choosing the preferred size and mix of technology and risk analysis of terms
in financial and operating contracts for the CHP systems.
• Many utilities are facing a concern through the expected useful lives of their coal plants are
being shortened by low gas prices and increased use of renewables. Mr. Graves helped a utility
justify early retirement of a coal plant with full recovery of its stranded costs, when that plan
could be replaced more economically with new wind plants while the tax incentives for their
development were still in effect.
• Mr. Graves developed a valuation and risk analysis model showing that a utility's RFP for new
generation could be better served by deferring new plant construction for a few years via a less
costly and less risky transitional market-based power supply contract with price and quantity
terms shaped to match the shifting needs over time until supply shortfalls were large enough
to justify the investment in a new power plant at efficient scale. The parties negotiated a multi-
year contract along these lines in lieu of pursuing the construction alternative that initially
came out of the RFP selection.
• In Maryland the electric distribution companies administer SOS (Standard Offer Service)
supply procurement and accounting to backup customers who do not use a competitive retail
power supplier. The utilities are authorized to recover both the direct and financing costs of
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Exhibit No. 18 Page 13 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
that service plus a return on equity. Mr. Graves developed a method for sizing an appropriate
equity return for the SOS risks and administrative services based on analogies to various
intermediation businesses on the internet, such as EBay, PayPal, and others—in which, like
SOS intermediation, the businesses do not take ownership for the products conveyed.
Testimony was provided.
• Mr. Graves co-lead a team of Brattle analysts to assess the relative influence of different factors
that were affected by the"Polar Vortex" cold snap of early 2014 that caused dramatic spikes in
local power and gas prices in parts of the mid-Atlantic and northeastern US. The risks of similar
recurring events were assessed in light of pending expansions of the electric and gas
transmission grids, as well as likely coal plant retirements.
• For the Board of Directors or executive management teams of several utilities, Mr. Graves has
lead strategic retreats on disruptive issues facing the electric industry in the future and how a
utility should choose which risks and opportunities to embrace vs.avoid.
• Air quality and other power plant environmental regulations were tightened considerably in
the period from about 2014-2018. Mr. Graves has co-developed a market and financial model
for determining what power plants are most likely to retire vs.retrofit with new environmental
controls, and how much this may alter their profitability. This has been used to help several
power market participants assess future capacity needs,as well as to adjust their price forecasts
for the coming decade.
• Successful merchant power plant development and financing depends in part on obtaining a
long term power purchase agreement. Mr. Graves directed a study of what pricing points and
risk-sharing terms should be attractive to potential buyers of long-term power supply contracts
from a large baseload facility.
• Many utilities are pursuing smart meters and time-of-use pricing to increase customer ability
to consume electricity economically. Mr. Graves has led a study of the costs and benefits of
different scales and timing of installation of such meters, to determine the appropriate pace.
He has also evaluated how various customer incentives to increase conservation and demand
response might be provided over the internet, and how much they might increase the
participation rates in smart meter programs.
• Wind resources are a critical part of the generation expansion plans and contracting interests
of many utilities, in order to satisfy renewable portfolio standards and to reduce long run
exposure to carbon prices and fuel cost uncertainty. Mr. Graves has applied Brattle's risk
modeling capabilities to simulate the impacts of on- and off-shore wind resources on the
potential range of costs for portfolios of wholesale power contracts designed to serve retail
electricity loads. These impacts were compared to gas CCs and CTs and to simply buying more
from the wholesale market to identify the most economical supply strategy.
• For a municipal utility with an opportunity to invest in a nuclear power plant expansion, Mr.
Graves lead an analysis of how the proposed plant fit the needs of the company, what market
and regulatory (environmental) conditions would be required for the plant to be more
economical than conventional fossil-fired generation,and how the development risks could be
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Exhibit No. 18 Page 14 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
shared among co-owners to better match their needs and risk tolerances. He also assessed the
market for potential off-take contracts to recover some of the costs and capacity that would be
available for a few years, ahead of the needs of the municipal utility.
• The potential introduction of environmental restrictions or fees for CO2 emissions has made
generation expansion decisions much more complex and risky. He helped one utility assess
these risks in regard to a planned baseload coal plant, finding that the value of flexibility in
other technologies was high enough to prefer not building a conventional coalplant.
• Mr. Graves helped design, implement, and gain regulatory approvals for a natural gas
procurement hedging program for a western U.S. gas and electric utility. A model of how gas
forward prices evolve over time was estimated and combined with a statistical model of the
term structure of gas volatility to simulate the uncertainty in the annual cost of gas at various
times during its procurement,and the resulting impact on the range of potential customer costs.
• Generation planning for utilities has become very complex and risky due to high natural gas
prices and potential CO2 restrictions of emission allowances. Some of the scenarios that must
be considered would radically alter system operations relative to current patterns of use. Mr.
Graves has assisted utilities with long range planning for how to measure and cope with these
risks, including how to build and value contingency plans in their resource selection criteria,
and what kinds of regulatory communications to pursue to manage expectations in this difficult
environment.
• For a Midwestern utility proposing to divest a nuclear plant, Mr. Graves analyzed the
reasonableness of the proposed power buyback agreement and the effects on risks to utility
customers from continued ownership vs. divestiture. The decommissioning funds were also
assessed as to whether their transfer altered the appropriate purchase price.
• Several utilities with coal-fired power plants have faced allegations from the U.S. EPA that
they have conducted past maintenance on these plants which should be deemed "major
modifications", thereby triggering New Source Review standards for air quality controls. Mr.
Graves has helped one such utility assess limitations on the way in which GADS data can be
used retrospectively to quantify comparisons between past actual and projected future
emissions. For another utility, Mr. Graves developed retrospective estimates of changes in
emissions before and after repairs using production costing simulations. In a third,he reviewed
contemporaneous corporate planning documents to show that no increase in emissions would
have been expected from the repairs, due to projected reductions in future use of the plant as
well as higher efficiency. In all three cases, testimony was presented.
• The U.S. Government is contractually obligated to dispose of spent nuclear fuel at commercial
reactors after January 1998, but it has not fulfilled this duty. As a result, nuclear facilities that
are shutdown or facing full spent fuel pools are facing burdensome costs and risks. Mr. Graves
prepared developed an economic model of the performance that could have reasonably been
expected of the government, had it not breached its contract to remove the spentfuel.
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Exhibit No. 18 Page 15 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
• Capturing the full value of hydroelectric generation assets in a competitive power market is
heavily dependent on operating practices that astutely shift between real power and ancillary
services markets, while still observing a host of non-electric hydrological constraints. Mr.
Graves led studies for several major hydro generation owners in regard to forecasting of market
conditions and corresponding hydro schedule optimization. He has also designed transfer
pricing procedures that create an internal market for diverting hydro assets from real power to
system support services firms that do not yet have explicit, observable marketprices.
• Mr. Graves led a gas distribution company in the development of an incentive ratemaking
system to replace all aspects of its traditional cost of service regulation. The base rates(for non-
fuel operating and capital costs) were indexed on a price-cap basis (RPI-X), while the gas and
upstream transportation costs allowances were tied to optimal average annual usage of a
reference portfolio of supply and transportation contracts. The gas program also included
numerous adjustments to the gas company's rate design, such as designing new standby rates
so that customer choice will not be distorted by pricing inefficiencies.
• An electric utility with several out-of-market independent power contracts wanted to
determine the value of making those plants dispatchable and to devise a negotiating strategy
for restructuring the IPP agreements. Mr. Graves developed a range of forecasts for the
delivered price of natural gas to this area of the country. Alternative ways of sharing the
potential dispatch savings were proposed as incentives for the IPPs to renegotiate their utility
contracts.
• For an electric utility considering the conversion of some large oil-fired units to natural gas,
Mr. Graves conducted a study of the advantages of alternative means of obtaining gas supplies
and gas transportation services. A combination of monthly and daily spot gas supplies,
interruptible pipeline transportation over several routes, gas storage services, and "swing"
(contingent) supply contracts with gas marketers was shown to be attractive. Testimony was
presented on why the additional services of a local distribution company would be unneeded
and uneconomic.
• A power engineering firm entered into a contract to provide operations and maintenance
services for a cogenerator,with incentives fees tied to the unit's availability and operating cost.
When the fees increased due to changes in the electric utility tariff to which they were tied, a
dispute arose. Mr. Graves provided analysis and testimony on the avoided costs associated with
improved cogeneration performance under a variety of economic scenarios and under several
alternative utility tariffs.
• Mr. Graves has helped several pipelines design incentive pricing mechanisms for recovering
their expected costs and reducing their regulatory burdens. Among these have been Automatic
Rate Adjustment Mechanisms (ARAMs) for indexation of operations and maintenance
expenses, construction-cost variance-sharing for routine capital expenditures that included a
procedure for eliciting unbiased estimates of future costs, and market-based prices capped at
replacement costs when near-term future expansion was an uncertain but probableneed.
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Exhibit No. 18 Page 16 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
• For a major industrial gas user, he prepared a critique of the transportation balancing charges
proposed by the local gas distribution company. Those charges were shown to be arbitrarily
sensitive to the measurement period as well as to inconsistent attribution of storage versus
replacement supply costs to imbalance volumes. Alternative balancing valuation and
accounting methods were shown to be cheaper,more efficient,and simpler to administer. This
analysis helped the parties reach a settlement based on a cash-in/cash-out design.
• The Clean Air Act Amendments authorized electric utilities to trade emission allowances(EAs)
as part of their approach to complying with SO2 emissions reductions targets. For the Electric
Power Research Institute (EPRI), Mr. Graves developed multi-stage planning models to
illustrate how the considerable uncertainty surrounding future EA prices justifies waiting to
invest in irreversible control technologies, such as scrubbers or SCRs, until the present value
cost of such investments is significantly below that projected from relying onEAs.
• For an electric utility with a troubled nuclear plant, Mr. Graves presented testimony on the
economic benefits likely to ensue from a major reorganization. The plant was to be spun off to
a jointly-owned subsidiary that would sell available energy back to the original owner under a
contract indexed to industry unit cost experience. This proposal afforded a considerable
reduction of risk to ratepayers in exchange for a reasonable, but highly uncertain prospect of
profits for new investors. Testimony compared the incentive benefits and potential conflicts
under this arrangement to the outcomes foreseeable from more conventional incentive
ratemaking arrangements.
• Mr. Graves helped design Gas Inventory Charge (GIC)tariffs for interstate pipelines seeking to
reduce their risks of not recovering the full costs of multi-year gas supply contracts. The costs
of holding supplies in anticipation of future,uncertain demand were evaluated with models of
the pipeline's supply portfolio that reveal how many non-production costs (demand charges,
take-or-pay penalties, reservation fees, or remarketing costs for released gas) would accrue
under a range of demand scenarios. The expected present value of these costs provided a basis
for the GIC tariff.
• Mr. Graves performed a review and critique of a state energy commission's assessment of
regional natural gas and electric power markets in order to determine what kinds of pipeline
expansion into the area was economic. A proposed facility under review for regulatory
approval was found to depend strongly on uneconomic bypass of existing pipelines and LDCs.
In testimony, modular expansion of existing pipelines was shown to have significantly lower
costs and risks.
• For several electric utilities with generation capacity in excess of target reserve margins, Mr.
Graves designed and supervised market analyses to identify resale opportunities by comparing
the marginal operating costs of all this company's power plants not needed to meet target
reserves to the marginal costs for almost 100 neighboring utilities. These cost curves were then
overlaid on the corresponding curve for the client utility to identify which neighbors were
competitors and which were potential customers. The strength of their relative threat or
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Exhibit No. 18 Page 17 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
attractiveness could be quantified by the present value of the product of the amount, duration,
and differential cost of capacity that was displaceable by the client utility.
• Mr.Graves specified algorithms for the enhancement of the EPRI EGEAS generation expansion
optimization model,to capture the first-order effects of financial and regulatory constraints on
the preferred generation mix.
• For a major electric power wholesaler, Mr. Graves developed a framework for estimating how
pricing policies affect the relative attractiveness of capacity expansion alternatives. Traditional
cost-recovery pricing rules can significantly distort the choice between two otherwise
equivalent capacity plans, if one includes a severe "front end load" while the other does not.
Price-demand feedback loops in simulation models and quantification of consumer satisfaction
measures were used to appraise the problem.This"value of service"framework was generalized
for the Electric Power Research Institute.
• For a large gas and electric utility, Mr. Graves participated in coordinating and evaluating the
design of a strategic and operational planning system. This included computer models of all
aspects of utility operations, from demand forecasting through generation planning to
financing and rate design. Efforts were split between technical contributions to model design
and attention to organizational priorities and behavioral norms with which the system had to
be compatible.
• For an oil and gas exploration and production firm, Mr. Graves developed a framework for
identifying what industry groups were most likely to be interested in natural gas supply
contracts featuring atypical risk-sharing provisions. These provisions, such as price indexing or
performance requirements contingent on market conditions, are a form of product
differentiation for the producer, allowing it to obtain a price premium for the insurance-like
services.
• For a natural gas distribution company, Mr. Graves established procedures for redefining
customer classes and for repricing gas services according to customers' similarities in load
shape, access to alternative gas supplies, expected growth, and need for reliability. In this
manner,natural gas service was effectively differentiated into several products,each with price
and risk appropriate to a specific market. Planning tools were developed for balancing gas
portfolios to customer group demands.
• For a Midwestern electric utility, Mr. Graves extended a regulatory pro forma financialmodel
to capture the contractual and tax implications of canceling and writing off a nuclear power
plant in mid-construction. This possibility was then appraised relative to completion or
substitution alternatives from the viewpoints of shareholders(market value of common equity)
and ratepayers (present value of revenue requirements).
• For a corporate venture capital group, Mr. Graves conducted a market-risk assessment of
investing in a gas exploration and production company with contracts to an interstate pipeline.
The pipeline's market growth, competitive strength, alternative suppliers, and regulatory
exposure were appraised to determine whether its future would support the purchase volumes
needed to make the venture attractive.
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FRANK C. GRAVES Witness:Frank Graves
• For a natural gas production and distribution company, he developed a strategic plan to
integrate the company's functional policies and to reposition its operations for the next five
years. Decision analysis concepts were combined with marginal cost estimation and financial
pro forma simulation to identify attractive and resilient alternatives. Recommendations
included target markets, supply sources, capital budget constraints, rate design, and a planning
system. A two-day planning conference was conducted with the client's executives to refine
and internalize the strategy.
• For the New Mexico Public Service Commission, he analyzed the merits of a corporate
reorganization of the major New Mexico gas production and distribution company. State
ownership of the company as a large public utility was considered but rejected on concerns
over efficiency and the burdening of performance risks onto state and localtaxpayers.
Regulated Industry Policy and Restructuring
• There has been a proliferation of customer-based renewable energy sources, smart appliances,
and storage. For a developer of energy management equipment and software to optimize the
use of such technologies, Mr. Graves and a Brattle team evaluated what types of services could
be economically attractive to customers and/or utility partners, and what the market potential
might be.
• Several states and cities have set goals of deep decarbonization of their local economies, often
dubbed "80 by 50" if they aspire to 80%reductions in GHG emissions by 2050. Achieving this
will involve radical change in the economy of those regions, potentially with dramatic load
growth due to electrification and massive investment in new infrastructure for end-use and
power supply and delivery. Mr. Graves has built models that show what types and degree of
change could arise, and what they might cost depending on how such transformations are
incentivized or enforced.
• As wholesale power and natural gas prices have fallen, interest in "retail choice" for energy
supply has increased.At the same time, some state regulatory agencies have become concerned
that misleading marketing and non-competitive pricing are too common in the mass market,
especially afflicting low income and senior residential customers. Mr. Graves lead a review of
such concerns that compared practices and market performance in several states to identify
what could be done to improve such services.
• For a group of utilities responding to a state mandate to consider means of encouraging
distributed technologies to be assessed and incentivized in parity with central station
generation, Mr. Graves and others at Brattle prepared alternative means of incorporating
marginal cost and externality value considerations into new cost/benefit assessment tools,
procurement mechanisms, and supply contracting.
• For a mid-Atlantic gas distribution utility, Mr. Graves assessed mark to market losses that had
occurred from gas supply hedges entered before spot prices declined precipitously. Concerns
were voice that this outcome indicated the company's hedging practices were no longer attune
to market conditions, so Mr. Graves developed and lead workshop between the company,
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FRANK C. GRAVES Witness:Frank Graves
intervener groups, and state commission staff to define new appropriate goals, mechanisms and
review standards for revised risk management approach.
• For a major participant in the Japanese power industry contemplating reorganization of that
country's electric sector following Fukushima, Mr. Graves lead a research project on the
performance of alternative market designs around the US and around the world for vertical
unbundling, RTO design, and retail choice.
• For several utilities facing the end of transitional"provider of last resort" (or POLR)prices,Mr.
Graves developed forecasts and risk analyses of alternative procurement mechanisms for
follow-on POLR contracts. He compared portfolio risk management approaches to full
requirements outsourcing under various terms and conditions.
• For a large municipal electric and gas company considering whether to opt-in to state retail
access programs, Mr. Graves lead an analysis of what changes in the level and volatility of
customer rates would likely occur, what transition mechanisms would be required, and what
impacts this would have on city revenues earned as a portion of local electric and gas service
charges.
• Many utilities experienced significant "rate shock" when they ended "rate freeze" transition
periods that had been implemented with earlier retail restructuring. The adverse customer and
political reactions have led to proposals to annual procurement auctions and to return to
utility-owned or managed supply portfolios. Mr. Graves has assisted utilities and wholesale
gencos with analyses of whether alternative supply procurement arrangements could be
beneficial.
• The impacts of transmission open access and wholesale competition on electric generators risks
and financial health are well documented. In addition, there are substantial impacts on fuel
suppliers, due to revised dispatch, repowerings and retirements, changes in expansion mix,
altered load shapes and load growth under more competitive pricing. For EPRI,Mr. Graves co-
authored a study that projected changes in fuel use within and between ten large power market
regions spanning the country under different scenarios for the pace and success of
restructuring.
• As a result of vertical unbundling, many utilities must procure a substantial portion of their
power from resources they do not own or operate. Market prices for such supplies are quite
volatile. In addition, utilities may face future customer switching to or from their supply
service,especially if they are acting as provider of last resort(POLR).This problem is a blending
of risk management with the traditional least-cost Integrated Resource Planning (IRP).
Regulatory standards for findings of prudence in such a hybrid environment are often not well
understood or articulated, leaving utilities at risk for cost disallowances that can jeopardize
their credit-worthiness. Mr. Graves has assisted several utilities in devising updated
procurement mechanisms, hedging strategies, and associated regulatory guidelines thatclarify
the conditions for approval and cost recovery of resource plans, in order to make possible the
expedited procurement of power from wholesale market suppliers.
• Public power authorities and cooperatives face risks from wholesale restructuring if their sales-
for-resale customers are free to switch to or from supply contracting with other wholesale
suppliers. Such switching can create difficulties in servicing the significant debt capitalization
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FRANK C. GRAVES Witness:Frank Graves
of these public power entities, as well as equitable problems with respect to non-switching
customers. Mr. Graves has lead analyses of this problem, and has designed alternative product
pricing,switching terms and conditions,and debt capitalization policies to cope with the risks.
• As a means of unbundling to retain ownership but not control of generation, some utilities
turned to divesting output contracts. Mr. Graves was involved in the design and approval of
such agreements for a utility's fleet of generation. The work entailed estimating and projecting
cost functions that were likely to track the future marginal and total costs of the units and
analysis of the financial risks the plant operator would bear from the output pricing formula.
Testimony on risks under this form of restructuring was presented.
• Mr. Graves contributed to the design and pricing of unbundled services on several natural gas
pipelines. To identify attractive alternatives, the marginal costs of possible changes in a
pipeline's service mix were quantified by simulating the least-cost operating practices subject
to the network's physical and contractual constraints. Such analysis helped one pipeline to
justify a zone-based rate design for its firm transportation service. Another pipeline used this
technique to demonstrate that unintended degradations of system performance and increased
costs could ensue from certain proposed unbundling designs that were insensitive to system
operations.
• For several natural gas pipeline companies, Mr. Graves evaluated the cost of equity capital in
light of the requirements of FERC Order 636 to unbundle and reprice pipeline services. In
addition to traditional DCF and risk positioning studies, the risk implications of different
degrees of financial leverage (debt capitalization)were modeled and quantified. Aspects of rate
design and cost allocation between services that also affect pipeline risk were considered.
• Mr. Graves assisted several utilities in forecasting market prices, revenues, and risks for
generation assets being shifted from regulated cost recovery to competitive, deregulated
wholesale power markets. Such studies have facilitated planning decisions, such as whether to
divest generation or retain it, and they have been used as the basis for quantifying stranded
costs associated with restructuring in regulatory hearings. Mr. Graves has assisted a leasing
company with analyses of the tax-legitimacy of complex leasing transactions by reviewing the
extent and quality of due diligence pursued by the lessor, the adequacy of pre-tax returns, the
character,time pattern,and degree of risk borne by the buyer(lessor),the extent of defeasance,
and compliance with prevailing guidelines for true-lease status.
Market Competition
• Mr. Graves assisted a nuclear plant owner with an assessment of whether a proposed merger
of a company in whom it had a partial investment interest would alter the co-owner's
incentives to manage the plant for maximum stand-alone value of the asset. Structural and
behavioral models of the relevant market were developed to determine that there would be no
material changes in incentive or ability to affect the value of the asset.
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• Mr. Graves has testified on the quality of retail competition in Pennsylvania and on whether
various proposals for altering Default Service might create more robust competition.
• Regulatory and legal approvals of utility mergers require evidence that the combined entity
will not have undue market power. Mr. Graves assisted several utilities in evaluating the
competitive impacts of potential mergers and acquisitions. He has identified ways in which
transmission constraints reduce the number and type of suppliers, along with mechanisms for
incorporating physical flow limits in FERC's Delivered Price Test (DPT) for mergers. He has
also assessed the adequacy of mitigation measures(divestitures and conduct restrictions)under
the DPT,Market-Based Rates, and other tests of potential market power arising from proposed
mergers.
• A major concern associated with electric utility industry restructuring is whether or not
generation markets are adequately competitive. Because of the state-dependent nature of
transmission transfer capability between regions,itself a function of generation use,the quality
of competition in the wholesale generation markets can vary significantly and may be
susceptible to market power abuse by dominant suppliers. Mr. Graves helped one of the largest
ISOs in the U.S. develop market monitoring procedures to detect and discourage market
manipulations that would impair competition.
• Vertical market power arises when sufficient control of an upstream market creates a
competitive advantage in a downstream market. It is possible for this problem to arise in power
supply,in settings where the likely marginal generation is dependent on very few fuel suppliers
who also have economic interests in the local generation market. Mr. Graves analyzed this
problem in the context of the California gas and electric markets and filed testimony to explain
the magnitude and manifestations of the problem.
• The increased use of transmission congestion pricing has created interest in merchant
transmission facilities. Mr. Graves assisted a developer with testimony on the potential impacts
of a proposed line on market competition for transmission services and adjacent generation
markets. He also assisted in the design of the process for soliciting and ranking bids to buy
tranches of capacity over the line.
• Many regions have misgivings about whether the preconditions for retail electric access are
truly in place. In one such region, Mr. Graves assisted a group of industrial customers with a
critique of retail restructuring proposals to demonstrate that the locally weak transmission grid
made adequate competition among numerous generation suppliers very implausible.
• Mr. Graves assisted one of the early ISOs with its initial market performance assessment and
its design of market monitoring tests for diagnosing the quality of prevailingcompetition.
Electric and Gas Transmission
• Substantial fleets of wind-based generation can impose significant integration costs on power
systems. Mr. Graves assisted in assessing what additional amounts and costs for ancillary
services would be needed for a Western utility with a large renewable fleet. The approach
included a statistical analysis of how wind output was correlated with demand,and how much
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FRANK C. GRAVES Witness:Frank Graves
forecasting error in wind output was likely to be faced over different scheduling horizons.
Benefits of geographic diversity of the wind fleet were also assessed.
• For a utility seeking FERC approval for the purchase of an affiliate's generating facility, Mr.
Graves analyzed how transmission constraints affecting alternative supply resources altered
their usefulness to the buyer, in comparison to the benefits from the affiliated plant.
• As part of a generation capacity planning study, he lead an analysis of how congestion
premiums and discounts relative to locational marginal prices (LMPs) at load centers affected
the attractiveness of different potential locations for new generation.At issue was whether the
prevailing IMP differences would be stable over time, as new transmission facilities were
completed,and whether new plants could exacerbate existing differentials and lead to degraded
market value at other plants.
• Mr.Graves assisted a genco with its involvement in the negotiation and settlement of"regional
through and out rates" (RTOR) that were to be abolished when MISO joined PJM. His team
analyzed the distribution of cost impacts from several competing proposals, and they
commented on administrative difficulties or advantages associated with each.
• For the electric utility regulatory commission of Colombia, S.A., Mr. Graves led a study to
assess the inadequacies in the physical capabilities and economic incentives to manage voltages
at adequate levels. The Brattle team developed minimum reactive power support obligations
and supplement reactive power acquisition mechanisms for generators, transmission
companies, and distribution companies.
• Mr. Graves conducted a cost-of-service analysis for the pricing of ancillary services provided
by the New York Power Authority.
• On behalf of the Electric Power Research Institute (EPRI), Mr. Graves wrote a primer on how
to define and measure the cost of electric utility transmission services for better planning,
pricing, and regulatory policies. The text covers the basic electrical engineering of power
circuits, utility practices to exploit transmission economies of scale, means of assuring system
stability, economic dispatch subject to transmission constraints,and the estimation of marginal
costs of transmission. The implications for a variety of policy issues are alsodiscussed.
• The natural gas pipeline industry is wedged between competitive gas production and
competitive resale of gas delivered to end users. In principle, the resulting basis differentials
between locations around the pipeline ought to provide efficient usage and expansion signals,
but traditional pricing rules prevent the pipeline companies from participating in the marginal
value of their own services. Mr.Graves worked to develop alternative pricing mechanisms and
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Exhibit No. 18 Page 23 of 42
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FRANK C. GRAVES Witness:Frank Graves
service mixes for pipelines that would provide more dynamically efficient signals and
incentives.
• Mr. Graves analyzed the spatial and temporal patterns of marginal costs on gas and electric
utility transmission networks using optimization models of production costs and network
flows. These results were used by one natural gas transmission company to design receipt-
point-based transmission service tariffs, and by another to demonstrate the incremental costs
and uneven distribution of impacts on customers that would result from a proposed unbundling
of services.
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FRANK C. GRAVES Witness:Frank Graves
TESTIMONY
For Public Service Company of New Mexico, Case No. 22-00270-UT before the New Mexico Public
Service Commission, Mr. Graves provided testimonies on whether the Four Corners Power Plant had
been prudently evaluated, environmentally upgraded, and contracted for fuel in decisions made over
the prior decade. Direct testimony December 2022, rebuttal July 2023.
For Peoples' Gas Light Co. and North Shore Gas of Chicago, he testified in their general rate cases
regarding whether various cost recovery or capital expenditure constraints should be place on the
companies because of expected decarbonization policies in Illinois that could cause natural gas to be
displaced by electrification. He argued that this is an important issue requiring more analysis and more
stakeholders than a GRC setting includes, so those issues should be set for a series of Future of Gas
workshops. Docket Nos. 23-0068 and 23-0069 before the Illinois Commerce Commission, June 2023.
For the Alberta Utilities Commission, Mr. Graves provided written direct and rebuttal testimony on
cost of capital risk-positioning in regard to decarbonization policies, and on the financial impacts of
service bypass by Rural Electrification Associations on FortisAlberta Company, Proceeding 27084,
February and April 2023.
For Holtec International, Mr. Graves provided testimony regarding feasibility of decommissioning of
Palisades nuclear plant ISFSI by 2040, before the Nuclear Regulatory Commission, Docket No(s). 50-
255-LT-2, 50-155-LT-2, 72-007-LT, 72-043-LT-2, February 2023.
For Commonwealth Edison Company, testimony on the cost of equity capital for ComEd's four-year
rate plan, before the Illinois Commerce Commission. Docket No. 23-0055, January 17, 2023.
For members of the Wisconsin Utilities Association, testimony on how to regulate rooftop solar
development when it is contracted under long term power purchase agreements, Case No 9300-DR-
105, November 1 and 2, 2022, Wisconsin Public Service Commission.
For WE Energies, Mr. Graves provided testimony on the importance of maintaining or growing fixed
charges in electric rates as more and more customers adopt self-supply(rooftop solar)and smart energy
management technologies. Case Nos. 5-UR-110 and 6690-UR-127, October 4,2022.
For Northstar Vermont Yankee Co., he testified in the Court of Federal Claims (October 31, 2022)
regarding the company's position in a market for exchanging positions in the queue of spent nuclear
fuel removal rights, had DOE not breached its obligations to create a permanent repository. Oral
direct and rebuttal testimonies were presented. Docket 18-1209C.
On behalf of Entergy's System Energy Resources,Inc.,Mr.Graves testified(September 28,2022)before
the FERC about whether various costs of structuring and periodically refinancing a capital lease for a
portion of the Grand Gulf Nuclear Station had been recorded properly for accounting and ratemaking
purposes under formula rates. FERC Docket EL20-72-000.
wo
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Exhibit No. 18 Page 25 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
For Calpine Corp. Mr Graves testified in Bankruptcy Court in regard to why extraordinarily high
power prices that arose during the February 2021 extreme freeze, causing nearly half of Texas to lose
power for several days, should not be waived as ongoing liabilities for Brazos Municipal Power
Cooperative, which had incurred a $1.5billion liability to ERCOT from its inabilities to cover (or
hedge) its power needs during that situation. Docket No. 21-03863-ADV, March 2, 2022
For Public Service Company of New Mexico, Mr. Graves presented rebuttal and sur-rebuttal (March
15, 2021)testimonies before the NMPSC (Case No. 21-00017-UT) on whether ownership of a share of
the Four Corners power plant had been imprudently sustained in the past decade. He presented
analyses that supplemented past resource planning and that compared the realized costs of the Four
Corners plant to the alternative gas plant that interveners felt should have been chosen instead,
showing that even if prior decisions had been imprudent,little or no damages had ensued.
For Alta Windpower, testimony in regard to whether locations of adjacent wind farms was causing
interference and if so, how much harm to output was occurring (JAMS Case No.1220065657, January
16, 2021). He showed that plaintiff's alleged damages were highly speculative and overstated because
based on only a single scenario for complex future decarbonization economics, and that the plaintiff's
projection was out of line compared to many other forecasts.
For PacifiCorp before the Oregon Public Utility Commission (Docket UE-374, February 2020), Mr.
Graves prepared testimony on the difficulties in forecasting short-term power system balancing and
trading transactions and the resulting tendency for these to be underestimated in projected operating
costs,hence under-collected in rates. Based on a comparison to other states practices, he proposed that
such costs be fully recovered on a flow-through basis without risk-sharing, subject toprudence.
On behalf of Public Service Company of New Mexico, presented testimony before the New Mexico
Public Regulation Commission on the merits of replacing the San Juan Generating Station coal units
with a fleet of renewables, storage and gas-fired peakers, and on the reasons for allowing full recovery
of the coal plant's sunk costs despite early retirement. Case No. 19-00018-UT, November 15,2019.
On behalf of both Southern California Edison and Pacific Gas & Electric Company, presented direct
and rebuttal testimony co-authored with Robert Mudge in regard to cost of wildfire risk under AB
1054, a state policy to create a fire insurance mechanism. Applications 19-04-014 and 19-04-015,
September 4, 2019.
For Dominion Energy Kewaunee,Mr.Graves filed expert testimony in the U.S.Court of Federal Claims
(Case No. 18-808 C, July 25, 2019) in regard to the ability of the plaintiff(Kewaunee Nuclear) to have
had all its spent nuclear fuel removed by the U.S. DoE, had the government met its obligations to
perform under the Standard Contract with the nuclear industry.Modeling shows why the government
ought to be liable for damages from otherwise unnecessary storage costs at the site. Similar testimonies
were filed on behalf of NorthStar for Vermont Yankee (Aug. 2019) and on behalf of Duke Power in
regard to the Crystal River nuclear plant (Sept.2019).
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Exhibit No. 18 Page 26 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
For Nicor Gas, a natural gas distribution company, Mr. Graves co-authored testimony on the cost of
equity capital utilizing a broad spectrum of risk-pricing methods and explaining how financial leverage
affects it. Testimony was filed with the Illinois Commerce Commission, Docket 18-xxxx, November 9,
2018.
For the electric transmission division of Pacific Gas & Electric, Mr. Graves presented testimony and co-
authored an accompanying report on the cost of capital impacts from the extreme risks arising from
potential liability for damages caused by large wildfires in California. Testimony before the FERC,Docket
ER19-= 000, Exhibit PGE-0019, October 1,2018.
For the Government of Colombia, written and oral testimony in regard to apparent misrepresentationsof
coal mine development costs and expected profitability by Glencore Corporation that adversely affected
royalty payments for Colombia to Glencore. Heard in the International Court of Arbitration, ICSID Case
No ARB/16/6, Washington DC, June 2018
Before the Pennsylvania Public Utility Commission,written direct testimony for Philadelphia Gas Works,
Docket No. R-2017-2586783, June 2017, regarding financial benchmarking of the company vs. investor
owned and public agency peers, and the need for a rate increase to maintain financial metrics and cover
future costs.
Direct testimony in regard to a claim for a share of lime consumption reduction costs obtained by Plum
Point as one of SMEPA's power plant operator/suppliers, on behalf of SMEPA, before the American
Arbitration Association in the matter of Southwest Mississippi Electric Power Association vs. Plum Point
Energy Associates, Case No. 01-15-0002-6062, September 2016.
Direct, Rebuttal and Supplementary Rebuttal reports regarding damages from loss of a nuclear generation
facility, on behalf of Southern California Edison Company, Edison Material Supply LLC., San Diego Gas
and Electric Company and City of Riverside before the International Chamber of Commerce in the matter
of Southern California Edison v.Mitsubishi Nuclear Energy Systems,Inc.and Mitsubishi Heavy Industries,
Ltd., Case No. 19784/AGF/RD, July 27, 2015 (direct), January 19, 2016 (rebuttal) and March 14, 2016
(supplemental).
Direct report re determination of an appropriate level of return needed for Standard Offer Service (SOS),
on behalf of Delmarva Power & Light Company and Potomac Electric Power Company before the
Maryland Public Service, Case Nos. 9226 and 9232,July 24, 2015.
Direct testimony in regard to the prudence of its gas hedging,on behalf of Hope Gas,Inc.,before the West
Virginia Public Service Commission, Case No. 12-1070-G-30C, June 24,2013.
Direct testimony on behalf of Public Service Company of New Mexico before the NM Public Regulation
Commission re appropriate profit incentives for energy conservation activities, Case No. 12-00317-UT,
October 5, 2012.
Rebuttal testimony on behalf of Rocky Mountain Power Company before the Public Service Commission
of Utah in regard to hedging practices for natural gas supply, Docket 11-035-200, July2012.
Rebuttal testimony on behalf of Rocky Mountain Power Company before the Public Service Commission
of Wyoming in regard to gas supply hedging and loss-sharing, Docket No. 20000-405-ER-11,June2012.
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Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Direct testimony on behalf of Ohio Power Company before the PUC of Ohio in regard to performance of
PJM capacity markets,in Ohio Power's application for its ESP service charges, Case No. 10-2929-EL-UNC,
March 30, 2012.
Expert report and oral testimony on behalf of Pepco Holdings, Inc. before the Maryland Public Service
Commission in regard to inadequacies in the MD PSC's RFP for new combined cycle generation
development in SVWMAAC, Case No. 9214, January 31, 2012.
Direct testimony on behalf of Columbus Southern Power Company and Ohio Power Company before the
Public Utilities Commission of Ohio in the Matter of the Commission Review of the Capacity Charges of
Ohio Power Company and Columbus Southern Power Company, Case No. 10-2929 -EL-UNC, August 31,
2011.
Rebuttal report on spent nuclear fuel removal on behalf of Yankee Atomic Electric Company, Connecticut
Yankee Atomic Power Company, Maine Yankee Atomic Power Company before the United States Court
of Federal Claims, Nos. 07-876C, No. 07-875C, No. 07-877C, August 5,2011.
Direct Testimony on rehearing regarding the allowance of swaps in Rocky Mountain Power's fuel
adjustment cost recovery mechanism, on behalf of Rocky Mountain Power before the Public Service
Commission of the State of Utah, July 2011.
Comments and Reply Comments on capacity procurement and transmission planning on behalf of New
Jersey Electric Distribution Companies before the State of New Jersey Board of Public Utilities in the
Matter of the Board's Investigation of Capacity Procurement and Transmission Planning, NJ BPU Docket
No. EO11050309, June 17, 2011; July 12, 2011.
Rebuttal testimony regarding Rocky Mountain Power's hedging practices on behalf of Rocky Mountain
Power before the Public Service Commission of the State of Utah, Docket No. 10-035-124, June 2011.
Expert and Rebuttal reports regarding contract termination damages,on behalf of Hess Corporation before
the United States District Court for the Northern District of New York,Case No. 5:10-cv-587(NPM/GHL),
April 29, 2011, May 13,2011.
Expert and Rebuttal reports on spent fuel removal at Rancho Seco nuclear power plant, on behalf of
Sacramento Municipal Utility District before the U.S.Court of Federal Claims,No.09-587C,October 2010,
July 1, 2011.
Rebuttal testimony on the Impacts of the Merger with First Energy on retail electric competition in
Pennsylvania, on behalf of Allegheny Power before the Pennsylvania Public Utility Commission, Docket
Nos. A-2010-2176520 and A-2010-2176732, September 13, 2010.
Expert and Rebuttal reports on the interpretation of pricing terms in a long term power purchase
agreement, on behalf of Chambers Cogeneration Limited Partnership before the Superior Court of New
Jersey, Docket No. L-329-08,August 23, 2010, September 21, 2010.
Expert and Rebuttal reports on spent fuel removal at Trojan nuclear facility,on behalf of Portland General
Electric Company, The City of Eugene, Oregon, and PacifiCorp before the United States Court of Federal
Claims No. 04-0009C,August 2010, June 29,2011.
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Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Rebuttal and Rejoinder testimonies on the approval of its Smart Meter Technology Procurement and
Installation Plan before the Pennsylvania Public Utility Commission on behalf of West Penn Power
Company d/b/a Allegheny Power, Docket No. M-2009-2123951, October 27, 2009, November 6, 2009.
Supplemental Direct testimony on the need for an energy cost adjustment mechanism in Utah to recover
the costs of fuel and purchased power, on behalf of Rocky Mountain Power before the Public Service
Commission of Utah, Docket No. 09-035-15,August 2009.
Expert and Rebuttal reports on spent nuclear fuel removal on behalf of Yankee Atomic Electric Company,
Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company before the United
States Court of Federal Claims, Nos. 98-126C,No. 98-154C, No. 98-474C, April 24, 2009,July 20,2009.
Expert report in regard to opportunistic under-collateralization of affiliated trading companies, on behalf
of BJ Energy,LLC,Franklin Power LLC,GLE Trading LLC,Ocean Power LLC,Pillar Fund LLC and Accord
Energy, LLC before the United States District Court for the Eastern District of Pennsylvania, No. 09-CV-
3649-NS, March 2009.
Rebuttal report in regard to appropriate discount rates for different phases of long-term leveraged leases,
on behalf of Wells Fargo &Co. and subsidiaries, Docket No. 06-628T, January 15, 2009.
Oral and written direct testimony regarding resource procurement and portfolio design for Standard Offer
Service, on behalf of PEPCo Holdings Inc. in its Response to Maryland Public Service Commission, Case
No. 9117, October 1, 2008 and December 15,2008.
Direct testimony regarding considerations affecting the market price of generation service for Standard
Service Offer(SSO) customers, on behalf of Ohio Edison Company, et al., Docket 08-125, July 24, 2008.
Direct testimony in support of Delmarva's "Application for the Approval of Land-Based Wind Contracts
as a Supply Source for Standard Offer Service Customers,"on behalf of Delmarva Power&Light Company
before the Public Service Commission of Delaware,July 24,2008.
Oral direct testimony in regard to the Government's performance in accepting spent nuclear fuel under
contractual obligations established in 1983, on behalf of plaintiff Dairyland Power Cooperative before the
United States Court of Federal Claims (No. 04-106C), July 17,2008.
Direct testimony for Delmarva Power & Light on risk characteristics of a possible managed portfolio for
Standard Offer Service,as part of Delmarva's IRP filings(PSC Docket No.07-20),March 20,2008 and May
15, 2008.
Oral direct testimony regarding the economic substance of a cross-border lease-to-service contract for a
German waste-to-energy plant on behalf of AWG Leasing Trust and KSP Investments, Inc before U. S.
District Court, Northern District of Ohio, Eastern Division, Case No. 1:07CV0857, January 2008.
Expert report (October 15, 2007) and oral testimony (September 21 and 22, 2010) in Commonwealth of
Pennsylvania Department of Environmental Protection, et al., v. Allegheny Energy Inc, et al. regarding
flaws in the plaintiffs' assessment of emissions attributed to repairs at certain power plants, Civil Action
No, 2:05ev1885.
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Exhibit No. 18 Page 29 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Direct testimony regarding portfolio management alternatives for supplying Standard Offer Service, on
behalf of Potomac Electric Power Company and Delmarva Power&Light Company before the Public
Service Commission of Maryland, Case No. 9117, September 14, 2007.
Direct testimony in regard to preconditions for effective retail electric competition,on behalf of New West
Energy Corporation before the Arizona Commerce Commission, Docket No. E-03964A-06-0168, August
31, 2007.
Direct and rebuttal testimonies regarding the application of OG&E for an order of commission granting
preapproval to construct Red Rock Generating Facility and authorizing a recovery rider, on behalf of
Oklahoma Gas&Electric Company(OG&E)before the Corporation Commission of the State of Oklahoma,
Case No. PUD 200700012,January 17, 2007 and June 18,2007.
Testimony in regard to whether defendant's role in accounting misrepresentations could be reliably
associated with losses to shareholders of Royal Ahold, on behalf of defendant Mark Kaiser
(executive at US Food Services) before the U.S. District Court of New York SI:04Cr733 (TPG)
(Docket No. 07-2365-cr).
Rebuttal testimony on proposed benchmarks for evaluating the Illinois retail supply auctions, on behalf of
Midwest Generation EME L.L.C.and Edison Mission Marketing and Trading before the Illinois Commerce
Commission Docket No. 06-0800,April 6,2007.
Direct and rebuttal testimonies on the shareholder impacts of Dynegy's Project Alpha for the sentencing
of Jamie Olis, on behalf of the U.S.Department of Justice before the United States District Court, Southern
District of Texas, Houston Division, Criminal No. H-03-217, September 12,2006.
Direct and rebuttal testimony on the need for POLR rate cap relief for Metropolitan Edison and
Pennsylvania Electric and the prudence of their past supply procurement for those obligations, on behalf
of FirstEnergy Corp before the Pennsylvania Public Utility Commission, Docket Nos. R-00061366 and R-
00061367,August 24, 2006.
Direct testimony regarding Deutsche Bank Entities' opposition to Enron Corp's amended motion forclass
certification, on behalf of the Deutsche Bank Entities before the United States District Court, Southern
District of Texas, Houston Division, Docket No. H-01-3624, February 2006.
Expert and Rebuttal reports regarding the non-performance of the U.S.Department of Energy in accepting
spent nuclear fuel under the terms of its contract, on behalf of Pacific Gas and Electric Company before
the United States Court of Federal Claims, Docket No. 04-0074C, into which has been consolidated No.
04-0075C, November 2005.
Direct testimony regarding the appropriate load caps for a POLR auction,on behalf of Midwest Generation
EME, LLC before the Illinois Commerce Commission, Docket No. 05-0159, June 8,2005.
Affidavit regarding unmitigated market power arising from the proposed Exelon—PSEG Merger,on behalf
of Dominion Energy, Inc. before the Federal Energy Regulatory Commission, Docket No. EC05- 43-000,
April 11, 2005.
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Rocky Mountain Power
Exhibit No. 18 Page 30 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Expert and rebuttal reports and oral testimonies before the American Arbitration Association on behalf of
Liberty Electric Power, LLC, Case No. 70 198 4 00228 04, December 2004, regarding damages under
termination of a long-term tolling contract.
Oral direct and rebuttal testimony before the United States Court of Federal Claims on behalf of
Connecticut Yankee Atomic Power Company, Docket No. 98-154 C, July 2004 (direct) and August 2004
(rebuttal), regarding non-performance of the U.S. Department of Energy in accepting spent nuclear fuel
under the terms of its contract.
Direct, supplemental and rebuttal testimony before the Public Service Commission of Wisconsin, on
behalf of Wisconsin Public Service Corporation and Wisconsin Power and Light Company, Docket No.
05-EI-136, February 27, 2004 (direct), May 4, 2004 (supplemental) and May 28, 2004 (rebuttal) in regard
to the benefits of the proposed sale of the Kewaunee nuclear power plant.
Testimony before the Public Utility Commission of Texas on behalf of CenterPoint Energy Houston
Electric LLC, Reliant Energy Retail Services LLC, and Texas Genco LP, Docket No. 29526, March 2004
(direct) and June 2004 (rebuttal), in regard to the effect of Genco separation agreements and financial
practices on stranded costs and on the value of control premiums implicit in Texas Genco Stock price.
Rebuttal and additional testimony before the Illinois Commerce Commission, on behalf of Peoples Gas
Light and Coke Company, Docket No. 01-0707, November 2003 (rebuttal) and January 2005 (additional
rebuttal), in regard to prudence of gas contracting and hedging practices.
Rebuttal testimony before the State Office of Administrative Hearings on behalf of Texas Genco and
CenterPoint Energy, Docket No. 473-02-3473, October 23, 2003, regarding proposed exclusion of part of
CenterPoint's purchased power costs on grounds of including"imputed capacity"payments in price.
Rebuttal testimony before the Federal Energy Regulatory Commission (FERC) on behalf of Ameren
Energy Generating Company and Union Electric Company,Docket No. EC03-53-000, October 6, 2003,in
regard to evaluation of transmission limitations and generator responsiveness in generation procurement.
Rebuttal testimony before the New Jersey Board of Public Utilities on behalf of Jersey Central Power &
Light Company, Docket No. ER02080507, March 5, 2003, regarding the prudence of JCP&L's power
purchasing strategy to cover its provider-of-last-resort obligation.
Oral testimony (February 17, 2003) and expert report (April 1, 2002) before the United States District
Court, Southern District of Ohio, Eastern Division on behalf of Ohio Edison Company and Pennsylvania
Power Company, Civil Action No. C2-99-1181, regarding coal plant maintenance projects alleged to
trigger New Source Review.
Expert Report before the United States District Court on behalf of Duke Energy Corporation, Docket No.
1:000V1262, September 16, 2002, regarding forecasting changes in air pollutant emissions following coal
plant maintenance projects.
Direct testimony before the Public Utility Commission of Texas on behalf of Reliant Energy, Inc., Docket
No. 26195, July 2002, regarding the appropriateness of Reliant HL&P's gas contracting, purchasing and
risk management practices, and standards for assessing HL&P's gas purchases.
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Rocky Mountain Power
Exhibit No. 18 Page 31 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Direct and rebuttal testimonies before the Public Utilities Commission of the State of California on behalf
of Southern California Edison, Application No. R. 01-10-024, May 1, 2002, and June 5, 2002, regarding
Edison's proposed power procurement and risk management strategy, and the regulatory guidelines for
reviewing its procurement purchases.
Rebuttal testimony before the Texas Public Utility Commission on behalf of Reliant Resources, Inc.,
Docket No. 24190, October 10, 2001, regarding the good-cause exception to the substantive rules that
Reliant Resources, Inc. and the staff of the Public Utility Commission sought in their Provider of Last
Resort settlement agreement.
Direct testimony before the Federal Energy Regulatory Commission (FERC) on behalf of Northeast
Utilities Service Company, Docket No. ERO1-2584-000, July 13, 2001, in regard to competitive impacts of
a proposed merchant transmission line from Connecticut to Long Island.
Direct testimony before the Vermont Public Service Board on behalf of Vermont Gas Systems,Inc.,Docket
No. 6495, April 13, 2001, regarding Vermont Gas System's proposed risk management program and
deferred cost recovery account for gas purchases.
Affidavit on behalf of Public Service Company of New Mexico, before the Federal Energy Regulatory
Commission (FERC), Docket No. ER96-155 1-000, March 26, 2001, to provide an updated application for
market based rates.
Affidavit on behalf of the New York State Electric and Gas Corporation, April 19, 2000, before the New
York State Public Service Commission,In the Matter of Customer Billing Arrangements,Case 99-M-0631.
Supplemental Direct and Reply Testimonies of Frank C. Graves and A. Lawrence Kolbe (jointly) on behalf
of Southern California Edison Company, Docket Nos. ER97-2355-00, ER98-1261-000, ER98-1685-000,
November 1, 1999, regarding risks and cost of capital for transmission services.
Expert report before the United States Court of Federal Claims on behalf of Connecticut Yankee Atomic
Power Company, Connecticut Yankee Atomic Power Company, Plaintiff v.United States of America,No.
98-154 C,June 30, 1999,regarding non-performance of the U.S. Department of Energy in accepting spent
nuclear fuel under the terms of its contract.
Expert report before the United States Court of Federal Claims on behalf of Maine Yankee Atomic Power
Company, Maine Yankee Atomic Power Company, Plaintiff v. United States of America, No. 98-474 C,
June 30, 1999, regarding the damages from non-performance of the U.S. Department of Energy in
accepting spent nuclear fuel and high-level waste under the terms of its contract.
Expert report before the United States Court of Federal Claims on behalf of Yankee Atomic Electric
Company,Yankee Atomic Electric Company, Plaintiff v.United States of America,No. 98-126 C,June 30,
1999, regarding the damages from non-performance of the U.S. Department of Energy in accepting spent
nuclear fuel and high-level waste under the terms of its contract.
Prepared direct testimony before the Federal Energy Regulatory Commission on behalf of National Rural
Utilities Cooperative Finance Corporation, Inc., Cities of Anaheim and Riverside, California v. Deseret
Generation&Transmission Cooperative, Docket No. EL97-57-001, March 1999, regarding cost of service
for rural cooperatives versus investor-owned utilities, and coal plant valuation.
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Rocky Mountain Power
Exhibit No. 18 Page 32 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Expert report and oral examination before the Independent Assessment Team for industry restructuring
appointed by the Alberta Energy and Utilities Board on behalf of TransAlta Utilities Corporation,January
1999, regarding the cost of capital for generation under long-term, indexed power purchaseagreements.
Oral testimony before the Commonwealth of Massachusetts Appellate Tax Board on behalf of Indeck
Energy Services of Turners Falls,Inc.,Turners Falls Limited Partnership,Appellant vs.Town of Montague,
Board of Assessors, Appellee, Docket Nos. 225191-225192, 233732-233733, 240482-240483, April 1998,
regarding market conditions and revenues assessment for property tax basis valuation.
Direct and joint supplemental testimony before the Pennsylvania Public Utility Commission on behalf of
Pennsylvania Electric Company and Metropolitan Edison Company, No. R-00974009, et al., December
1997, regarding market clearing prices, inflation, fuel costs, and discount rates.
Direct Testimony before the Pennsylvania Public Utilities Commission on behalf of UGI Utilities, Inc.,
Docket No. R-00973975,August 1997, regarding forecasted wholesale market energy and capacity prices.
Testimony before the Public Utilities Commission of the State of California on behalf of the Southern
California Edison Company, No. 96-10-038, August 1997, regarding anticompetitive implications of the
proposed Pacific Enterprises/ENOVA mergers.
Direct and supplemental testimony before the Kentucky Public Service Commission on behalf of Big
Rivers Electric Corporation,No. 97-204,June 1997,regarding wholesale generation and transmission rates
under the bankruptcy plan of reorganization.
Affidavit before the Federal Energy Regulation Commission on behalf of the Southern California Edison
Company in Docket No. EC97-12-000, March 28, 1997, filed as part of motion to intervene and protest
the proposed merger of Enova Corporation and Pacific Enterprises.
Direct, rebuttal, and supplemental rebuttal testimony before the State of New Jersey Board of Public
Utilities on behalf of GPU Energy, No. EO97070459, February 1997, regarding market clearing prices,
inflation, fuel costs, and discount rates.
Oral direct testimony before the State of New York on behalf of Niagara Mohawk Corporation in
Philadelphia Corporation, et al.v. Niagara Mohawk,No. 71149, November 1996, regarding interpretation
of low-head hydro IPP contract quantity limits.
Oral direct testimony before the State of New York on behalf of Niagara Mohawk Corporation in Black
River Limited Partnership v. Niagara Mohawk Power Corporation, No. 94-1125, July 1996, regarding
interpretation of IPP contract language specifying estimated energy and capacity purchase quantities.
Oral direct testimony on behalf of Eastern Utilities Associates before the Massachusetts Department of
Public Utilities,No.96-100 and 2320,July 1996,regarding issues in restructuring of Massachusetts electric
industry for retail access.
Affidavit before the Kentucky Public Service Commission on behalf of Big Rivers Electric Corporation in
PSC Case No. 94-032, June 1995, regarding modifications to an environmental surcharge mechanism.
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Rocky Mountain Power
Exhibit No. 18 Page 33 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Rebuttal testimony on behalf of utility in Eastern Energy Corporation v. Commonwealth Electric
Company,American Arbitration Association, No. 11 Y 198 00352 04, March 1995, regarding lack of net
benefits expected from a terminated independent power project.
Direct testimony before the Pennsylvania Public Utility Commission on behalf of Pennsylvania Power&
Light Company in Pennsylvania Public Utility Commission et al. v. UGI Utilities, Inc., Docket No. R-
932927, March 1994, regarding inadequacies in the design and pricing of UGI's proposed unbundling of
gas transportation services.
Direct testimony before the Pennsylvania Public Utility Commission, on behalf of Interstate Energy
Company,Application of Interstate Energy Company for Approval to Offer Services in the Transportation
of Natural Gas, Docket No. A-140200, October 1993, and rebuttal testimony, March 1994.
Direct testimony before the Pennsylvania Public Utility Commission,on behalf of Procter&Gamble Paper
Products Company, Pennsylvania Public Utility Commission v. Pennsylvania Gas and Water Company,
Docket No.R-932655,September 1993,regarding PG&W's proposed charges for transportation balancing.
Oral rebuttal testimony before the American Arbitration Association, on behalf of Babcock and Wilcox,
File No. 53-199-00127-92, May 1993, regarding the economics of an incentive clause in a cogeneration
operations and maintenance contract.
Answering testimony before the Federal Energy Regulatory Commission, on behalf of CNG Transmission
Corporation, Docket No. RP88-21 1-000, March 1990, regarding network marginal costs associated with
the proposed unbundling of CNG.
Direct testimony before the Federal Energy Regulatory Commission, on behalf of Consumers Power
Company, et al., concerning the risk reduction for customers and the performance incentive benefits from
the creation of Palisades Generating Company, Docket No. ER89-256-000, October 1989, and rebuttal
testimony, Docket No. ER90-333-000, November 1990.
Direct testimony before the New York Public Service Commission, on behalf of Consolidated Natural Gas
Transmission Corporation, Application of Empire State Pipeline for Certificate of Public Need, Case No.
88-T-132, June 1989, and rebuttal testimony, October, 1989.
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Rocky Mountain Power
Exhibit No. 18 Page 34 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
PUBLICATIONS, PAPERS, AND PRESENTATIONS
"The Emerging Economics of Hydrogen Production", a Brattle presentation prepared in collaboration
with Environmental Defense Fund, reviewing hydrogen costs foreseeable through 2030 with recent
IRA tax incentives and improving technologies. Prepared with Josh Figueroa, Ragini Sreenath,
Lorenzo Sala, Jadon Grove, and Steven Thumb, March, 2024.
"The Role of Nuclear Power in US Electricity Markets"prepared with Carless Traviss for MIT and
CATF's Nuclear Power in a Low Carbon World conference,August 2023,
"Future of Gas Series, Transitioning Gas Utilities to a Decarbonized Future"three Brattle
presentations (Assessing Risks,Aug 2021; Evaluating Strategies, Sept 2021; Setting Regulations, Nov
2021)with Long Lam, Kasparas Spokas, Josh Figueroa, Tess Counts, and Shreeansh Agarwal.
"Brattle Issue Brief on ERCOT's Power Outage",March 2021, with Sam Newell, Jesse Cohen, and
Sophie Leamon.
"2020 CAISO Blackouts and Beyond: The Future of California Resource Planning"with John Tsoukalis
and Sophie Leamon for LSI's Electric Power in the West Conference, January 2021.
"Clean Energy and Sustainability Accelerator—Opportunities for Long Term Deployment" on
recommended targets and mechanisms for use of a$100 billion economic recovery and decarbonization
stimulus package for the Biden administration. With Bob Mudge, Roger Lueken, and Tess Counts.
Prepared for the Coalition for Green Capital, January 14, 2021.
" Emerging Value of Carbon Capture for Utilities"with Kasparas Spokas and Katie Mansur, Public
Utilities Fortnightly, October 2020, p. 36-41
"Impacts and Implications of COVID-19 for the Energy Industry"for Energy Bar Association's Virtual
Fall Conference, October 13, 2020. (Also several presentations with co-authors Bob Mudge,Tess
Counts, Josh Figueroa, Lily Mwalenga, and Shivangi Pant on the same topic at earlier dates, for public
release and other conferences.)"
"System Dynamics Modeling: An Approach to Planning and Developing Strategy in the Changing
Electricity Industry" (with Toshiki Bruce Tsuchida, Philip QHanser, and Nicole Irwin), Brattle White
Paper, April 2019.
"California Megafires: Approaches for Risk Compensation and Financial Resiliency Against Extreme
Events" (with Robert S. Mudge and Mariko Geronimo Aydin), Brattle White Paper, October 1, 2018.
"Retail Choice: Ripe for Reform?" (with Agustin Ros, Sanem Sergici, Rebecca Carroll and Kathryn
Haderlein), Brattle White Paper, July 2018.
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Rocky Mountain Power
Exhibit No. 18 Page 35 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
"Resetting FERC RoE Policy; a Window of Opportunity" (with Robert Mudge and Akarsh
Sheilendranath), Brattle White Paper, May 2018.
"State of Play in Retail Choice" Gulf Coast Power Association Spring Conference, Houston Texas,April
16, 2018.
"Modeling the Utility of the Future and Developing Strategies to Adapt and Lead" EEI Strategic Issues
Roundtable, September 27, 2017.
"Managing Price Risk for Merchant Renewable Investments: Role of Market Interactions and Dynamics
on Effective Hedging Strategies" (with Onur Aydin and Bente Villadsen), Brattle Whitepaper, January
2017.
"Cap-and-Trade Program in California: Will Low GHG Prices Last Forever?" (with Yingxia Yang,
Michael Hagerty, Ashley Palmarozzo and Metin Celebi), Brattle Whitepaper, January 2017.
"DER Incentive Mechanisms as a Bridge to the Utility of the Future," SNL Conference, Washington, DC,
December 14 and 15, 2016.
"Economic Outlook for U.S. Nuclear Power-- Challenges and Opportunities," CSIS Nuclear Conference,
October 24, 2016.
"Computerized and High-Frequency Trading" (with Michael Goldstein and Pavitra Kumar), The
Financial Review, May 2014.
"LDC Procurement and Hedging" (with Steve Levine), Prepared for the American Gas Association
Energy Market Regulation Conference, New Orleans, LA, October 2014.
`TrattleReviewofAEPlanningMethodsandAustinTaskForceReport."(withBenteVilladsen),
Prepared for Austin Energy, September 24, 2014.
"How will the EPA's Clean Power Plan Impact Wind?"(with Kathleen Specs),North American Wind
Power, Vol. 11, No. 7, July 2014.
"Low Voltage Resiliency Insurance: Ensuring Critical Service Continuity During Major Power Outages,"
The Public Utilities Fortnightly,Vol. 151, No. 9, September 2013.
"How Much Gas is Too Much?" Law Seminars International Electric Utility Rate Cases Conference, Las
Vegas, NV, February 21, 2013.
"Potential Coal Plant Retirements-2012 Update" (with Metin Celebi and Charles Russell), Brattle
Whitepaper, October 2012.
"Centralized Dry Storage of Nuclear Fuel—Lessons for U.S. Policy from Industry Experience and
Fukushima" (with Mariko R. Geronimo and Glen A. Graves), Brattle Whitepaper,August 2012.
"Beyond Retrofit/Retirement: Complex Decisions for Coal Units" (with Metin Celebi and Chip Russell),
Brattle Whitepaper, April 16, 2012.
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Rocky Mountain Power
Exhibit No. 18 Page 36 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
"The Emerging Need for Greater Gas-Electric Industry Coordination" (with Matthew O'Loughlin, Steve
Levine,Anul Thapa and Metin Celebi), as comments to the FERC NOI, Docket AD12-12-000, regarding
gas-electric industry reliability issues, March 30, 2012.
"Gas Volatility Outlook and Implications," Law Seminars International Electric Utility Rate Cases
Conference, Las Vegas, Nevada, February 23, 2012.
"Public Sector Discount Rates" (Bin Zhou and Bente Villadsen), Brattle Whitepaper, September 2011
"Trading at the Speed of Light: The Impact of High-Frequency Trading on Market Performance,
Regulatory Oversight, and Securities Litigation" (with Pavitra Kumar and Michael Goldstein), 2011 No.
2, Brattle Whitepaper in Finance.
"Dodd-Frank and Its Impact on Hedging Strategies," Law Seminars International Electric Utility Rate
Cases Conference, February 10, 2011.
"Potential Coal Plant Retirements Under Emerging Environmental Regulations" (with Metin Celebi),
December 2010.
"Risk-Adjusted Damages Calculation in Breach of Contract Disputes: A Case Study" (with Bin Zhou,
MelvinBrosterman,andQuinlanMurphy),journalof Business UaluationandEconomicLossAnalysis 5,
No. 1, October 2010.
"Gas Price Volatility and Risk Management," (with Steve Levine),AGA Energy Market Regulation
Conference, Seattle, WA, September 30, 2010.
"Managing Natural Gas Price Volatility: Principles and Practices across the Industry" (with Steve
Levine),American Clean Skies Foundation Task Force on Ensuring Stable Natural Gas Markets, July
2010.
"A Changing Environment for Distcos,"NMSU Center for Public Utilities, The Santa Fe Conference,
March 15, 2010.
"Prospects for Natural Gas Under Climate Policy Legislation: Will There Be a Boom in Gas Demand?"
(with Steve Levine and Metin Celebi), The Brattle Group, Inc., March 2010.
"Gas Price Volatility and Risk Management" (with Steve Levine), Law Seminars International Rate
Cases: Current Issues and Strategies, Las Vegas, NV, February 11, 2010.
"Hedging Effects of Wind on Retail Electric Supply Costs"(with Julia Litvinova), The Electricityjournal,
Vol. 22, No. 10, December 2009.
"Overview of U.S. Electric Policy Issues," Los Alamos Education Committee,June 2009.
"IRP Challenges of the Coming Decade" NARUC Conference, Washington, DC, February 17, 2009.
"Volatile CO2 Prices Discourage CCS Investment" (with Metin Celebi), The Brattle Group, Inc.,January
2009.
"Drivers of New Generation Development—A Global Review" (with Metin Celebi), EPRI, 2008.
Brattle 36

Rocky Mountain Power
Exhibit No. 18 Page 37 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
"Utility Supply Portfolio Diversity Requirements" (with Philip QHanser), The Electricity journal, Vol.
20, No. 5, June 2007,pp. 22-32.
"Electric Utility Automatic Adjustment Clauses: Why They Are Needed Now More Than Ever" (with
Philip QHanser and Greg Basheda), The Electricity journal, Vol. 20, No. 5, June 2007, pp. 33-47.
"Rate Shock Mitigation," (with Greg Basheda and Philip QHanser),prepared for the Edison Electric
Institute (EEI), May, 2007.
"PURPA Provisions of EPAct 2005: Making the Sequel Better than the Original" presented at Center for
Public Utilities Advisory Council—New Mexico State University Current Issues Conference 2006 , Santa
Fe, New Mexico, March 21, 2006.
"The New Role of Regulators in Portfolio Selection and Approval" (with Joseph B. Wharton),presented
at EUCI Resource and Supply Planning Conference, New Orleans, November 4, 2004.
"Disincentives to Utility Investment in the Current World of Competitive Regulation" (with August
Baker), prepared for the Edison Electric Institute (EEI), October, 2004.
"Power Procurement for Second-Stage Retail Access" (with Greg Basheda),presented at Illinois
Commerce Commission's `Post 2006 Symposium', Chicago, IL, April 29, 2004.
"Utility Investment and the Regulatory Compact" (with August Baker), presented to NMSU Center for
Public Utilities Advisory Council, Santa Fe, New Mexico, March 23, 2004.
"How Transmission Grids Fail" (with Martin L. Baughman) presented to NARUC Staff Subcommittee on
Accounting and Finance, Spring 2004 Meeting, Scottsdale,Arizona, March 22, 2004.
"Resource Planning&Procurement in Restructured Electricity Markets," presented to NARUC Winter
Committee Meetings, Washington, DC,March 9, 2004.
"Resource Planning and Procurement in Evolving Electricity Markets" (with James A. Read and Joseph
B. Wharton), white paper for Edison Electric Institute (EEI), January 31, 2004.
"Transmission Management in the Deregulated Electric Industry—A Case Study on Reactive Power"
(with Judy W.Chang and Dean M.Murphy), The Electricityjournal,Vol. 16,Issue 8,October,2003.
"Flaws in the Proposed IRS Rule to Reinstate Amortization of Deferred Tax Balances Associated with
Generation Assets Reorganized in Industry Restructuring" (with Michael J. Vilbert),white paper for
Edison Electric Institute (EEI) to the IRS, July 25, 2003.
"Resource Planning&Procurement in Restructured Electricity Markets" (with James A. Read and
Joseph B. Wharton), presented at Northeast Mid-Atlantic Regional Meeting of Edison Electrical
Institute, Philadelphia, PA, May 6, 2003 and at Midwest Regional Meeting, Chicago, IL, June 18, 2003.
"New Directions for Safety Net Service—Pricing and Service Options" (with Joseph B. Wharton), white
paper for Edison Electric Institute (EEI), May 2003.
At
Brattle 37

Rocky Mountain Power
Exhibit No. 18 Page 38 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
"Volatile Markets Demand Change in State Regulatory Evaluation Policies" (with Steven H. Levine),
chapter20ofE]ectric&Natura]GasBusiness.UnderstandingA4 editedbyRobertE.Willett,Financial
Communications Company, Houston, TX, February 2003, pp. 377-405.
"New York Power Authority Hydroelectric Project Production Rates," report prepared for NYPA (New
York Power Authority) on the embedded costs of production of ancillary services at the Niagara and St.
Lawrence hydroelectric projects, 2001-2006, January 22, 2003.
"Regulatory Policy Should Encourage Hedging Programs" (with Steven H. Levine), Natural Gas, Vol. 19,
No. 4, November 2002.
"Measuring Gas Market Volatility—A Survey" (with Paolo Coghe and Manuel Costescu), presented at
the Stanford Energy Modeling Forum,Washington, DC, June 24, 2002.
"Unbundling and Rebundling Retail Generation Service: A Tale of Two Transitions" (with Joseph B.
Wharton), presented at the Edison Electric Institute Conference on Unbundling/Rebundling Utility
Generation and Transmission, New Orleans, LA, February 25, 2002.
"Regulatory Design for Reactive Power and Voltage Support Services" (with Judy W. Chang), prepared
for Comision de Regulacion de Energia y Gas, Bogota, Colombia, December 2001.
"Provider of Last Resort Service Hindering Retail Market Development" (with Joseph B. Wharton),
Natural Gas, Vol. 18, No. 3, October 2001.
"Strategic Management of POLR Obligations"presented at Edison Electric Institute and the Canadian
Electricity Association Conference, New Orleans, LA, June 5, 2001.
"Measuring Progress Toward Retail Generation Competition" (with Joseph B. Wharton) Edison Electric
Institute E-Forum presentation, May 16, 2001.
"International Review of Reactive Power Management" (with Judy W. Chang), presented to Comision
de Regulacion de Energia y Gas, Bogota, Colombia, May 4, 2001.
"POLR and Progress Towards Retail Competition—Can Kindness Kill the Market?" (with Joseph B.
Wharton),presented at the NARUC Winter Committee Meeting, Washington, DC, February 27, 2001.
"What Role for Transitional Electricity Price Protections After California?"presented to the Harvard
Electricity Policy Group, 24th Plenary Session, San Diego, CA, February 1, 2001.
"Estimating the Value of Energy Storage in the United States: Some Case Studies" (with Thomas Jenkin,
Dean Murphy and Rachel Polimeni) prepared for the Conference on Commercially Viable Electricity
Storage, London, England, January 31, 2001.
"PBR Designs for Transcos: Toward a Competitive Framework" (with Steven Stoft), The Electricity,
journal, Vol. 13, No. 7,August/September 2000.
"Capturing Value with Electricity Storage in the Energy and Ancillary Service Markets" (with Thomas
Jenkin, Dean Murphy and Rachel Polimeni)presented at EESAT, Orlando, Florida, September 18, 2000.
I� Brattle 38

Rocky Mountain Power
Exhibit No. 18 Page 39 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
"Implications of ISO Design for Generation Asset Management" (with Edo Macan and David A.
Andrade), presented at the Center for Business Intelligence's Conference on Pricing Power Products &
Services, Chicago, Illinois, October 14-15, 1999.
"Residual Service Obligations Following Industry Restructuring" (with James A. Read, Jr.), paper and
presentation at the Edison Electric Institute Economic Regulation and Competition Committee Meeting,
IE Brattle 39

Rocky Mountain Power
Exhibit No. 18 Page 40 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
Longboat Key, Florida, September 26-29, 1999. Also presented at EEI's 1999 Retail Access Conference:
Making Retail Competition Work, Chicago, Illinois, September 30-October 1, 1999.
"Opportunities for Electricity Storage in Deregulating Markets" (with Thomas Jenkin and Dean
Murphy), The Electricity journal, Vol. 12, No. 8, October 1999.
HowCompetitiveMarketDynamicsAffectCoal,NuclearandGasGenerationandFuelUse A10Year
Look Ahead(with L. Borucki, R. Broehm, S. Thumb, and M. Schaal), Final Report, May 1999, TR-
111506 (Palo Alto, CA: Electric Power Research Institute, 1999).
"Price Caps for Standard Offer Service:A Hidden Stranded Cost" (with Paul Liu), The Electricity
journal, Vol. 11, No. 10, December 1998.
MechanismsforEvaluatingtheRole ofHydroelectricGenerationinAncillaryServiceMarkets(with
R.P. Broehm, R.L. Earle, T.J. Jenkin, and D.M. Murphy), Final Report,November 1998, TR-111707 (Palo
Alto, CA: Electric Power Research Institute, 1998).
"PJM Market Competition Evaluation White Paper," (with Philip Hanser),prepared for PJM, L.L.C.,
October, 1998.
"The Role of Hydro Resources in Supplying System Support and Ancillary Services,"presented at the
EPRI Generation Assets Management Conference, Baltimore, Maryland, July 13-15, 1998. Published in
EPRI Generation Assets Management 1998 Conference: Opportunities and Challenges in the Electric
Marketplace, Proceedings, November 1998, TR-111345 (Palo Alto, CA: EPRIGEN, Inc., 1998).
"Regional Impacts of Electric Utility Restructuring on Fuel Markets" (with S.L. Thumb, A.M. Schaal, L.S.
Borucki, and R. Broehm),presented at the EPRI Generation Assets Management Conference, Baltimore,
Maryland, July 13-15, 1998. Published in EPRI Generation Assets Management 1998 Conference:
Opportunitiesand Challengesin the ElectricMarketplace,Proceedings,November 1998,TR-111345
(Palo Alto, CA: EPRIGEN, Inc., 1998).
EnergyMarketlmpactsofElectriclndustryRestructuring. Understanding WholesalePower
Transmission and Trading(with S.L.Thumb,A.M.Schaal,L.S.Borucki,and R.Broehm),Final Report,
March 1998, EPRI TR-108999, GRI-97/0289 (Palo Alto, CA: Electric Power Research Institute,1998).
"Pipeline Pricing to Encourage Efficient Capacity Resource Decisions"(with Paul R. Carpenter and
MatthewP.O'LoughIin),filedinFERC proceedings Fin an cial Ou do okfor th e Na tural Gas Pipeline
Industry, Docket No. PL98-2-000, February 1998.
"One-Part Markets for Electric Power: Ensuring the Benefits of Competition" (with E. Grant Read,
Philip QHanser,and Robert L.Earle),Chapter 7 in PowerSystemsRestructuring:Engineeringand
Economics,M. Ill , F. Galiana, and L. Fink, eds. (Boston: Kluwer Academic Publishers, 1998, reprint
2000),pp. 243-280.
"Railroad and Telecommunications Provide Prior Experience in`Negotiated Rates"' (with Carlos
Lapuerta), Natural Gas,Vol. 13, No. 12, July 1997.
IAt Brattle 40

Rocky Mountain Power
Exhibit No. 18 Page 41 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
"Considerations in the Design of ISO and Power Exchange Protocols: Procurement Bidding and Market
Rules" (with J.P. Pfeifenberger), presented at the Electric Utility Consultants Bulk Power Markets
Conference, Vail, Colorado, June 3-4, 1997.
"The Economics of Negative Barriers to Entry: How to Recover Stranded Costs and Achieve Competition
on Equal Terms in the Electric Utility Industry" (with William B. Tye), Electric Industry Restructuring,
Natural Resources journal,Vol. 37, No. 1,Winter 1997.
"Capacity Prices in a Competitive Power Market"(with James A.Read), The Virtual Utility.-Accounting,
Technology& Competitive Aspects of the Emerging Industry,S.Awerbuch and A.Preston,eds. (Boston:
Kluwer Academic Publishers, 1997), pp. 175-192.
"Stranded Cost Recovery and Competition on Equal Terms" (with William B. Tye), Electricity journal,
Vol. 9, No. 10, December 1996.
"Basic and Enhanced Services for Recourse and Negotiated Rates in the Natural Gas Pipeline Industry"
(with Paul R. Carpenter, Carlos Lapuerta, and Matthew P. O'Loughlin), filed on behalf of Columbia Gas
Transmission Corporation and Columbia Gulf Transmission Company,in its Comments on Negotiated
Rates and Terms ofService, FERC Docket No. RM96-7, May 29,1996.
"Premium Value for Hydro Power in a Deregulated Industry?Technical Opportunities and Market
Structure Effects,"presented to the EPRI Hydro Steering Committee Conference, Chattanooga,
Tennessee,April 19,1996,andtothe EPRIEnergyStorageBenefits Workshop,New Orleans,Louisiana,
May 22, 1996.
"Distributed Generation Technology in a Newly Competitive Electric Power Industry" (with Johannes P.
Pfeifenberger, Paul R. Ammann, and Gary A. Taylor),presented at the American Power Conference,
Illinois Institute of Technology,April 10, 1996.
"A Framework for Operations in the Competitive Open Access Environment" (with Marija D. Ilio,
Lester H. Fink,Albert M. DiCaprio), Electricity journal, Vol. 9, No. 3,April 1996.
"Prices and Procedures of an ISO in Supporting a Competitive Power Market" (with Marija Ilig,
presentedattheRestructuringElectricTransmissionConference,Denver,Colorado,September 27,
1995.
"Potential Impacts of Electric Restructuring on Fuel Use," EPRI Fuel Insights, Issue 2, September 1995.
"Optimal Use of Ancillary Generation Under Open Access and its Possible Implementation" (with Maria
Iliq, M.I.T.Laboratoryfor Electromagneticand ElectronicSystemsTechnical Report, LEES TR-95-006,
August 1995.
"Estimating the Social Costs of PUHCA Regulation" (with Paul R. Carpenter), submitted to the Security
and Exchange Commission's Requestfor Comments on Modernization ofthe Regulation ofPublic
Utility Holding Companies, SEC File No. 57-32-93, February 6,1995.
APrimeronElectricPowerFlowforEconomistsandUtilityPlanners, TR-104604, TheElectricPower
Research Institute, EPRI Project RP2123-19, January 1995.
IE Brattle 41

Rocky Mountain Power
Exhibit No. 18 Page 42 of 42
Case No. PAC-E-24-04
FRANK C. GRAVES Witness:Frank Graves
"Impacts of Electric Industry Restructuring on Distributed Utility Technology,"presented to the Electric
Power Research Institute/National Renewable Energy Laboratory/Florida Power Corporation
Conference on Distributed Generation, Orlando, Florida,August 24, 1994.
Pricing Transmission and Power in the Era of Retail Competition" (with Johannes P. Pfeifenberger),
presented at the Electric Utility Consultants'Retail Wheeling Conference,Beaver Creek,Colorado,June
21, 1994.
"Pricing of Electricity Network Services to Preserve Network Security and Quality of Frequency Under
Transmission Access" (with Dr. Marija IhO Paul R. Carpenter, and Assef Zobian), Response and Reply
comments to the Federal Energy Regulatory Commission in is Notice of Technical Conference on
Transmission Pricing, Docket No. RM-93-19-000, November 1993 and January 1994.
"Evaluating and Using CAAA Compliance Cost Forecasts,"presented at the EPRI Workshop on Clean
AirResponse, St. Louis,Missouri,November 17 and Arlington,Virginia,November 19,1992.
"Beyond Valuation—Organizational and Strategic Considerations in Capital Budgeting for Electric
Utilities,"presentedatEPRICapitalBudgetingNotebook Workshop,NewOrleans,Louisiana,April9-
10, 1992.
"Unbundling, Pricing, and Comparability of Service on Natural Gas Pipeline Networks" (with Paul R.
Carpenter), as appendix to Comments on FERC Order 636filed by Interstate Natural Gas Association of
America,November 1991.
"Estimating the Cost of Switching Rights on Natural Gas Pipelines" (with James A. Read, Jr. and Paul R.
Carpenter), presented at the M.I.T. Center for Energy Policy Research, "Workshop on New Methods for
Project and Contract Evaluation,"March 2-4, 1988; and in The Energy journal,Vol. 10,No. 4, October
1989.
"Demand-Charge GICs Differ from Deficiency-Charge GICs" (with Paul R. Carpenter), Natural Gas&
Electricity,Vol. 6, No. 1,August 1989.
"What Price Unbundling?" (with P.R. Carpenter), Natural Gas&Electricity, Vol. 5, No. 11, June 1989.
"Price-Demand Feedback,"presented at EPRI Capital BudgetingSeminar,San Diego,California,March
2-3, 1989.
"Applications of Finance to Electric Power Planning,"presented at the World Bank, Seminar on Risk
and Uncertainty in Power System Planning, October 13, 1988.
"Planning for Electric Utilities: The Value of Service" (with James A. Read, Jr.), in Moving Toward
Integrated Value-Based Planning, Electric Power Research Institute, 1988.
"Valuation of Standby Charges for Natural Gas Pipelines" (with James A. Read, Jr. and Paul R.
Carpenter), presented to M.I.T. Center for Energy Policy Research, October, 1987.
At
Brattle 42

Case No. PAC-E-24-04
Exhibit No. 19
Witness : Frank Graves
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Frank Graves
Area Burned from Human Caused Wildfires in the West
May 2024

Rocky Mountain Power
Exhibit No. 19 Page 1 of 1
Case No. PAC-E-24-04
Witness:Frank Graves
AREA BURNED FROM HUMAN CAUSED WILDFIRES IN THE WEST
5,000
4,500
m 4,000
c
3,500
m �
3,000
u CA
p 2,500
C s Trend line
2,000
v
E 1,500
z
1,000
500
0
O O O O O -1 —1 —1 -1 N N
O O O O O O O O O O O O
N N N N N N N N N N N N
Source: National Interagency Coordination Center, https://www.nifc.gov/fire-
information/statistics/human-caused. The West includes the Northwest, California,
Northern Rockies, Great Basin, and Southwest regions.
Brattle 1

Case No. PAC-E-24-04
Exhibit No. 20
Witness : Frank Graves
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Frank Graves
Costs of +$I Billion Wildfires in the United States
May 2024

Rocky Mountain Power
Exhibit No.20 Page 1 of 1
Case No. PAC-E-24-04
Witness:Frank Graves
COSTS OF $1 BILLION+ WILDFIRES IN THE UNITED STATES
35,000 2001 to 2012 average: 2013 to 2022 average:
30,000 $1,907 million $9,843 million
25,000
L �
LL O
c = 20,000
H
0 15,000
10,000
5,000
m to r_ rn V-1 m � r_ 0') �
0 0 0 0 0 � � � � � fV
0 0 0 0 0 0 0 0 0 0 0
N (V N N N N CV N N N CV
Source: National Oceanic and Atmosphere Administration — National Centers for
Environmental Information U.S. Billion-Dollar Weather and Climate Disasters
(2023), https://www.ncei.noaa.gov/access/billions/state-summary/US.
Brattle

Case No. PAC-E-24-04
Exhibit No. 21
Witness : Frank Graves
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Frank Graves
Recent Costs of Wildfire Insurance Faced by
Regional Utilities
May 2024

Rocky Mountain Power
Exhibit No.21 Page 1 of 1
Case No. PAC-E-24-04
Witness:Frank Graves
RECENT COSTS OF WILDFIRE INSURANCE FACED BY REGIONAL UTILITIES
Period
Units 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23
PG&E(Wildfire Liability) [a]
Costs $M 43 72 120 385 159 708 707 745
Coverage Limits $M 931 869 843 1,400 430 868 900 940
Costs/Coverage % 5% 8% 14% 28% 37% 82% 79% 79%
Cal.Year O&M Expense(excl.fuel and purchased power) $M 6,949 7,327 6,383 7,153 8,750 8,707 10,194 9,725
Insurance Cost/O&M Expense % 0.6% 1.0% 1.9% 5.4% 1.8% 8.1% 6.9% 7.7%
SCE(Wildfire) [b]
Costs $M 237 400 450 413 357
Coverage Limits $M 990 1000 870 875 835
Costs/Coverage % 24% 40% 52% 47% 43%
Cal.Year O&M Expense(excl.fuel and purchased power) $M 2,702 2,936 3,523 3,588 4,659
Insurance Cost/O&M Expense % 8.8% 13.6% 12.8% 11.5% 7.7%
SDG&E(Wildfire Liability) [c]
Costs $M 80 110 129 183 202 215 221
Coverage Limits $M 1,500 1,500 1,500 1,500 1,500 1,500 1,500
Costs/Coverage % 5% 7% 9% 12% 13% 14% 15%
Cal.Year O&M Expense(excl.fuel and purchased power) $M 1,048 1,020 1,058 1,181 1,455 1,587 1,677
Insurance Cost/O&M Expense % 7.6% 10.8% 12.2% 15.5% 13.9% 13.6% 13.2%
Avista(General Liability) [d]
Costs $M 7 9 14
Coverage Limits $M na na na
Costs/Coverage % na na na
Cal.Year O&M Expense(excl.fuel and purchased power) $M 360 372 417
Insurance Cost/O&M Expense % 1.8% 2.5% 3.3%
Idaho Power(Excess Liability) [e]
Costs $M 7 8 9 11 14
Coverage Limits $M na na na na na
Costs/Coverage % na na na na na
Cal.Year O&M Expense(excl.fuel and purchased power) $M 401 392 388 396 437
Insurance Cost/O&M Expense % 1.8% 1.9% 2.3% 2.8% 3.3%
[a] A. 21-06-021,CPUC Decision (D.) 23-01-005 at Table 2 (Jan. 17, 2023),Table 2; PG&E 10K;S&P Capital IQ.
[b] EIX Form 10-K;S&P Capita[ IQ.
[c] Application of San Diego Gas&Electric Company for Authority,Among Other Things,to Update its Electric and
Gas Revenue Requirement and Base Rates Effective on January 1, 2024,A.22-05-016,SDG&E Prepared Direct
Testimony of Dennis J. Gaughan (Corporate Center-Insurance),Table DG-18(years 2021 and 2022 are forecasts)
(May 2022)..Application of San Diego Gas &Electric Company,A.19-04-017, Exhibit No.SDG&E-05, Prepared
Direct Testimony of John J. Reed and James M. Coyne at 34(Apr. 2019);S&P Capital IQ.
[d] Avista Corporation v.WUTC,Washington Utilities and Transportation Commission (WUTC), Docket Nos. UE-
220053, UG-220054, UE-210854, Rebuttal Testimony of Elizabeth M.Andrews,Table 7(August 19, 2022);S&P
Capital IQ.
[e] In the Matter of the Application of Idaho Power for an Accounting Order Authorizing the Deferral of
Incremental Wildfire Mitigation and Insurance Costs, Idaho Public Utilities Commission Case No. IPC-E-21-02,filed
Jan. 22,2021; In the Matter of the Application of Idaho Power for Authority to Increase its Rates and Charges for
Electric Service in the State of Idaho and for Associated Regulatory Account Treatment, Idaho Public Utilities
Commission (IPUC)Case No. IPC-E-23-11, Motion for Approval of Stipulation and Settlement, October 2023;S&P
Capital IQ.
Brattle

Case No. PAC-E-24-04
Exhibit No. 22
Witness : Frank Graves
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Frank Graves
Recent Wildfire Insurance Cost Recovery Settlements
Achieved by Regional Utilities
May 2024

Rocky Mountain Power
Exhibit No.22 Page 1 of 1
Case No. PAC-E-24-04
Witness:Frank Graves
Recent Wildfire Insurance Cost Recovery Settlements Achieved by Regional Utilities
PG&E SCE SDG&E Avista Idaho Power
Jurisdiction CPUC CPUC CPUC WUTC 1 PUC
Decision/Settlement Application 21-06-021: Application 19-08-013: Application No.22-05-016: Dockets UE-220053,UG- Case No.IPC-E-23-11,Motion
DECISION APPROVING DECISION MODIFYING JOINT MOTION FOR 220054,UE-210,Final Order for Approval of Stipulation
SETTLEMENT REGARDING DECISION 21-08-036 AND ADOPTION OF ASETTLEMENT 10/04 Rejecting Tariff Sheets; and Settlement
WILDFIRE LIABILITY ADOPTING AGREEMENT RESOLVING ALL Granting Petition;Approving
INSURANCE COVERAGE AGREEMENT REGARDING INSURANCE ISSUES and Adopting Full Multiparty
WILDFIRE LIABILITY Settlement Stipulation Subject
INSURANCE to Conditions;Authorizing and
Requiring Compliance Filing
Date Jan-23 May-23 Oct-23 Dec-22 Oct-23
Status Settlement Approved Settlement Approved Settlement Filed Settlement Approved Settlement Filed
Applicable Period 2023-2026 2023-2028 2024-2027 2023-2024 2024
Insurance Type Self Self Self Option** Commercial Commercial Commercial
Average Annual Losses($M): Worst Case Recent Exp. Worst Case App.B,Ex.2 Worst Case
1,000.0 458.0 1,000.0 400.0 50.0
Average Annual Loss Allocations ($M):
Preauthorized Recovery* 718.8 424.8 741.4 338.3 33.5 173.0 8.3 14.5
Shareholder Deductible 50.0 22.9 12.5 0.0
Undercollection/(Overcollection) 231.3 10.3 246.1 61.7
Average Annual Loss Allocations (%):
Preauthorized Recovery* 71.9% 92.8% 74.1% 84.6% 67.0%
Shareholder Deductible 5.0% 5.0% 1.3% 0.0%
Undercollection/(Overcollection) 23.1% 2.2% 24.6% 15.4%
Preauthorized Cost/Target Coverage(%): 17.3% NA NA
Preauthorized Cost/O&M (%)***: 7.4% 4.4% 15.9% 7.3% 2.0% 10.3% 3.3% 3.3%
Cost Deferral Mechanisms Balancing Account Balancing Account Balancing Account Balancing Account TBD
*Varies with actual losses for self-insurance
**Embedded within commercial authorization @$14m per year up to$50m.
***WA portion for Avista
Brattle