Petition for Writ of Certiorari — San Diego Gas & Electric Company, Petitioner v. California Public Utilities Commission
Supreme Court briefApr 30, 2019
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No. 18-____
IN THE
Supreme Court of the United States
SAN DIEGO GAS & ELECTRIC COMPANY,
Petitioner,
v.
PUBLIC UTILITIES COMMISSION OF THE
STATE OF CALIFORNIA,
Respondent.
On Petition for a Writ Of Certiorari to the
California Court of Appeal, Fourth Appellate
District
PETITION FOR A WRIT OF CERTIORARI
Jeffrey N. Boozell
QUINN EMANUEL URQUHART
& SULLIVAN, LLP
865 S. Figueroa St., 10th Floor
Los Angeles, CA
(213) 443-3200
Kathleen M. Sullivan
Counsel of Record
Stephanie N. Solomon
QUINN EMANUEL URQUHART
& SULLIVAN, LLP
51 Madison Ave., 22nd Floor
New York, NY 10010
(212) 849-7000
kathleensullivan@
quinnemanuel.com
April 30, 2019
Counsel for Petitioner
i
QUESTION PRESENTED
Whether it is an uncompensated taking for public
use in violation of the Fifth and Fourteenth Amendments for a State to impose strict liability for inverse
condemnation on a privately owned utility without
ensuring that the cost of that liability is spread to
the benefitted ratepayers.
ii
PARTIES TO THE PROCEEDING
The following were parties to the proceeding before the California court of appeal:
1. San Diego Gas & Electric Co. (“SDG&E”), Petitioner in this Court, was Petitioner below.
2. The Public Utilities Commission of the State of
California, Respondent in this Court, was Respondent below.
3. Protect Our Communities Foundation was a
Real Party in Interest below.
4. The Utility Reform Network was a Real Party
in Interest below.
5. Utility Consumers Action Network was a Real
Party in Interest below.
6. Ruth Hendricks was a Real Party in Interest
below.
7. San Diego Consumers’ Action Network was a
Real Party in Interest below.
8. Mussey Grade Road Alliance was a Real Party
in Interest below.
9. Pacific Gas and Electric Company was an Interested Entity/Party below.
10. Southern California Edison Gas Company
was an Interested Entity/Party below.
iii
RULE 29.6 DISCLOSURE STATEMENT
SDG&E is a private, investor-owned utility. Enova Corporation owns 100% of SDG&E. Sempra Energy in turn owns 100% of Enova Corporation.
Sempra Energy has no parent corporation, and no
publicly held company owns 10% or more of its stock.
iv
TABLE OF CONTENTS
Page
QUESTION PRESENTED........................................... i
PARTIES TO THE PROCEEDING ........................... ii
RULE 29.6 DISCLOSURE STATEMENT ............... iii
TABLE OF AUTHORITIES....................................... vi
INTRODUCTION ........................................................ 1
OPINIONS BELOW .................................................... 4
JURISDICTION .......................................................... 4
CONSTITUTIONAL PROVISIONS
INVOLVED ....................................................... 4
STATEMENT .............................................................. 4
REASONS FOR GRANTING THE WRIT ................ 11
I.
THE DECISION BELOW CONFLICTS
WITH THE TAKINGS CLAUSE AND
THIS
COURT’S
TAKINGS
PRECEDENTS ............................................... 11
II.
THIS CASE IS AN IDEAL VEHICLE
TO ADDRESS THE QUESTION
PRESENTED .................................................. 19
III.
THIS CASE PRESENTS A QUESTION
OF
EXCEPTIONAL
NATIONAL
IMPORTANCE ............................................... 21
CONCLUSION .......................................................... 27
APPENDIX A—California Court of Appeal's Decision
(November 13, 2018)……………………………1a
v
APPENDIX B—California Supreme Court's Decision
(January 31, 2019)……………………...………5a
APPENDIX C—California Public Utilities
Commission Decision
(November 30, 2017)………….…………...……6a
APPENDIX D—California Public Utilities
Commission, Joint Concurrence
(December 26, 2017)………...…………...……86a
APPENDIX E—California Public Utilities
Commission, Order Denying Rehearing
(July 13, 2018)………..…………………...……94a
vi
TABLE OF AUTHORITIES
Page
Cases
Armstrong v. United States,
364 U.S. 40 (1960)..................................... 13, 14, 17
Babbitt v. Youpee,
519 U.S. 234 (1997)............................................... 13
Barham v. S. Cal. Edison Co.,
74 Cal.App. 4th 744 (1999) ............... 6, 7, 10, 12, 16
Dolan v. City of Tigard,
512 U.S. 374 (1994)............................................... 13
Duquesne Light Co. v. Barasch,
488 U.S. 299 (1989)............................................... 18
Eastern Enterprises v. Apfel,
524 U.S. 498 (1998)............................................... 17
Edison International, Southern California
Edison Company v. Superior Court (Abate)
No. B294164 (Cal. App. Dec. 3, 2018), No.
S253094 (Cal. Dec. 17, 2018) ................................. 21
In re 2007 Wildfire Insurer Litig.
(Super. Ct. San Diego County, Jan. 29,
2009, No. 37-2008-0093083, CU-NP-CTL) .............7
In re San Diego Gas & Elec. Co.,
146 FERC ¶ 63,017, 2014 WL 713556
(2014)........................................................................8
vii
Kelo v. City of New London,
545 U.S. 469 (2005)............................................... 13
Knick v. Township of Scott,
862 F.3d 310 (3d Cir. 2017)
cert. granted 138 S. Ct. 1262 (2018) ................ 19, 20
Lingle v. Chevron U.S.A. Inc.,
544 U.S. 528 (2005)............................................... 15
Marshall v. Department of Water and Power
219 Cal. App. 3d 1124 (1990) .................................6
Monongahela Nav. Co. v. United States,
148 U.S. 312 (1960)......................................... 13, 17
Pacific Bell Tel. Co. v. S. Cal. Edison Co.,
208 Cal.App.4th 1400 (2012) ..................................6
Pacific Gas & Electric Co. v. Superior Court
(Abbott)
No. A154847 (Cal. App. July 20, 2018), No.
S251585 (Cal. Oct. 1, 2018) ................................... 20
Pacific Gas & Electric Co. v. Superior Court
(Abu-Shumays)
No. C087071 (Cal. App. May 9, 2018), No.
S249429 (Cal. June 8, 2018) .................................. 20
Penn Central Transp. Co. v. New York City,
438 U.S. 104 (1978)............................................... 15
San Diego Gas & Elec. Co. v. Sup. Ct.,
13 Cal. 4th 893 (1996) ............................................6
Sultum v. Tahoe Regional Planning Agency,
520 U.S. 725 (1997)............................................... 13
viii
Williamson County v. Hamilton Bank of
Johnson City,
473 U.S. 172 (1985)............................................... 19
Statutes
28 U.S.C. § 1257(2) ......................................................4
42 U.S.C. § 1983 ........................................................ 20
Cal. Pub. Util. Code, §451.1 ...................................... 21
Cal. Stats. 2018, ch. 626, §§ 26–27, 32 ..................... 21
U.S. Constitutional Provisions
U.S. Const. amend. V ............................................ 4, 12
U.S. Const. amend. XIV, § 1 ................................. 4, 12
California Constitutional Provisions
Cal. Const. Art. I, sec. 19 .......................................... 12
Other Authorities
Anne C. Mulkern, No silver bullet. Can Calif.
Save its utilities?, E&E News (Apr. 1,
2019),
https://www.eenews.net/stories/1060137633 ........ 24
ix
Arvo Van Alstyne, Statutory Modification of
Inverse Condemnation: The Scope of
Legislative Power, 19 Stan. L. Rev. 727, 738
(1967)...................................................................... 13
Cal. Assembly Comm. on Utils. & Energy
(Feb. 26, 2018),
http://assembly.ca.gov/media/assemblyutilities-energy-committee-20180226/video.......... 25
Cal. Dep’t of Forestry & Fire Prot., Top 20
Most Destructive California Wildfires (Nov.
19, 2018),
http://www.fire.ca.gov/communications/
downloads/fact_sheets/Top20_Destruction.p
df ............................................................................. 27
Chelsea Harvey, Here’s What We Know About
Wildfires and Climate Change, Scientific
American (Oct. 13, 2017),
https://www.scientificamerican.com/article/
heres-what-we-know-about-wildfires-andclimate-change/ ...................................................... 26
Ethan Howland, Utilities to fight climate risk
via insurance upgrades, 2018 CQ Roll Call
Was. Energy Briefing 1673 (Nov. 14, 2018).......... 22
Governor Newsom’s Strike Force, Wildfires
and Climate Change: California’s Energy
Future (Apr. 12, 2019),
https://www.gov.ca.gov/wpcontent/uploads/2019/04/Wildfires-andClimate-Change-California%E2%80%99sEnergy-Future.pdf. ................................................ 25
x
Greg Gordon & Kevin Prior, PCG Has
Suspended Dividends, Citing Uncertainty
Regarding Wildfire-Related Liabilities,
Evercore ISI (Dec. 21, 2017) ............................ 23, 25
Ivan Penn & Peter Eavis, Liability Claims
From Wildfires Threaten Utility, N.Y.
Times, Nov. 14, 2018, available at
https://www.nytimes.com/2018/11/14/busine
ss/energy-environment/california-fireutilities.html. ......................................................... 24
J.D. Morris, California considers wildfire
insurance fund to avoid repeat of PG&E’s
woes, S.F. Chronical (Feb. 25, 2019),
https://www.sfchronicle.com/business/articl
e/California-mulls-wildfire-insurance-fundto-avoid-13641330.php?psid=oFzg ........................ 24
Jonathan Arnold, CPUC Denies SDG&E
Wildfire Recovery; Notes “Incorrect Premise”
of IC Doctrine, Deutsche Bank Power
Flash (Nov. 30, 2017) ............................................. 23
Mark Chediak & Kiel Porter, PG&E
Bankruptcy Looms, CEO to Exit as Fire
Costs Dwarf Cash, Bloomberg (Jan 14,
2019),
https://www.bloomberg.com/news/articles/2
019-01-14/pg-e-plans-bankruptcy-filing-ascalifornia-wildfires-costs-mount ........................... 24
xi
Melissa Pamer & Elizabeth Espinosa, ‘We
Don’t Even Call It Fire Season Anymore ...
It’s Year Round’: Cal Fire, KTLA5 News
(Dec. 11, 2017),
http://ktla.com/2017/12/11/we-dont-evencall-it-fire-season-anymore-its-year-roundcal-fire/ ................................................................... 26
Mike Yamamoto, Market Notes: Tuesday,
December 12, (Dec. 12, 2017),
https://investitute.com/activitynews/market-notes-tuesday-december-122017/ ....................................................................... 23
Moody’s Investors Service, Rating Action:
Moody’s Changes San Diego Gas &
Electric’s Rating Outlook to Negative From
Stable (Apr. 11, 2018),
http://www.moodys.com/research/Moodyschanges-San-Diego-Gas-Electric-ratingoutlook-to-negative-PR_380749 ............................ 23
Robinson Meyer, Has Climate Change
Intensified 2017’s Western Wildfires?, The
Atlantic (Sept. 7, 2017),
https://www.theatlantic.com/science/archiv
e/2017/09/why-is-2017-so-bad-for-wildfiresclimate-change/539130/ ......................................... 26
Sammy Roth, Edison CEO talks wildfires,
climate change and the utilities vanishing
monopoly, L.A. Times, (Mar. 13, 2019)
https://www.latimes.com/business/la-fisouthern-california-edison-sce-wildfiresclimate-change-20190313-story.html ................... 24
xii
William P. Barr, Henry Weissmann, & John
P. Fratz, The Gild that Is Killing the Lily:
How Confusion over Regulatory Takings
Doctrine Is Undermining the Core
Protections of the Takings Clause, 73 Geo.
Wash. L. Rev. 429 (2005) ....................................... 16
INTRODUCTION
California’s privately owned utilities face crippling liability for damage to private property from
wildfires that have become the “new normal” in California. The prospect of such liability has increased
insurance costs, weakened credit ratings, and discouraged investment in California’s privately owned
utilities, who supply power to the overwhelming bulk
of the State’s businesses and residents and provide a
vital aspect of California’s infrastructure. The catastrophic consequences of such liability are not hypothetical; they have already driven one privately
owned utility (Pacific Gas & Electric Co. (“PG&E”))
into a recent highly publicized bankruptcy.
This situation is almost entirely the creature of
law. In a series of California intermediate appellate
court decisions, California has imposed “inverse condemnation” liability on privately owned utilities for
damaging private property, just as if they were government actors. Because inverse condemnation is a
form of strict liability in California, it is far more attractive to plaintiffs and the plaintiffs’ bar than the
hard work of proving that the utilities’ negligence in
the operation of their powerlines proximately caused
any wildfires or other damage. But unlike government actors, privately owned utilities lack the coercive power of taxation and cannot unilaterally set
their own rates. To recover the costs of inverse condemnation liability, they must ask their regulator,
the California Public Utilities Commission (“CPUC”)
to allow them to pass the costs of that liability on to
their ratepayers.
2
The CPUC, affirmed by the California courts, has
now said no. In denying the application of petitioner
San Diego Gas & Electric Company (“SDG&E”) to
recover through rates the $379 million SDG&E was
forced to pay in unreimbursed inverse condemnation
costs from wildfires, the CPUC said that inverse
condemnation was “not relevant” to its decision. Instead, the CPUC applied its own administrative
“prudent manager” standard and deemed SDG&E
entitled to nothing.
This is an uncompensated taking of SDG&E’s
private property for public use in violation of the
Fifth and Fourteenth Amendments to the federal
Constitution. The well-settled purpose of compensation for takings in eminent domain is to ensure that
the costs of public improvements are borne by the
benefitted public. The same is true for inverse condemnation, which ensures that damage from public
improvements is not visited disproportionately on
particular private parties but rather is borne by the
benefitted public as a whole.
California law, in violation of these principles,
has now created a takings whipsaw in which the
State transfers the cost of damage from public improvements from one private party (the damaged
homeowners and businesses) to another private party (SDG&E and other privately owned utilities). It
thus does exactly what inverse condemnation is supposed to avoid: visits all the costs of damage from
public improvements on a single private party—here,
SDG&E. And in equal measure, California creates
an unconstitutional windfall for ratepayers, who are
the relevant public benefitted by the privately owned
3
utilities’ investment in electric power generation,
transmission and distribution facilities.
All three of California’s privately owned utilities
have tried in vain through repeated proceedings to
persuade the California court of appeal and California Supreme Court to grant discretionary review to
consider these issues. They have asked those courts
repeatedly without success to revisit the imposition
of inverse condemnation liability on privately owned
utilities. And from the other direction, SDG&E
asked those courts to review the CPUC decision
denying recovery, arguing that, assuming inverse
condemnation applies, denial of recovery is both an
unreasonable application of state law and an unconstitutional taking without just compensation. Again
without success.
In light of the California court of appeal’s and
California Supreme Court’s steadfast refusal to consider these important questions, this Court should
grant review. The decision of the California appellate court below takes privately owned utilities’
property for public use without just compensation, in
conflict with the Takings Clause as applied to the
States through the Due Process Clause, and in conflict with this Court’s settled takings jurisprudence.
And the question presented indisputably has grave
public importance: the legal whipsaw now created
by California’s appellate decisions threatens enormous and exponentially increasing financial and infrastructure harm to the largest economy in the
Nation and the fifth largest economy in the world.
Certiorari should be granted.
4
OPINIONS BELOW
The California court of appeal’s opinion is reproduced at App. 1a. The decision of the California Public Utilities Commission is reproduced at App. 6a and
its denial of rehearing is reproduced at App. 94a.
The California Supreme Court’s denial of the petition
for review is reproduced at App. 5a.
JURISDICTION
The California court of appeal issued its opinion
on November 13, 2018. App. 1a. On January 31,
2019, the California Supreme Court denied SDG&E’s
timely filed petition for review. App. 5a. This Court
has jurisdiction under 28 U.S.C. § 1257(2).
CONSTITUTIONAL PROVISIONS INVOLVED
The Fifth Amendment, U.S. Const. amend. V,
provides in pertinent part:
No person shall * * * be deprived of life,
liberty or property, without due process of
law; nor shall private property be taken
for public use, without just compensation.
The Due Process Clause of the Fourteenth
Amendment, U.S. Const. amend. XIV, § 1, provides:
No State shall * * * deprive any person of
life, liberty or property, without due
process of law.
STATEMENT
A. Factual Background
SDG&E is a private, investor-owned utility that
supplies gas and electricity to over 3.4 million customers in San Diego County and southern Orange
5
County, California. See Petitioner’s Appendix of Exhibits in Support of Writ of Review in the California
Court of Appeal (“Cal. Ptn’s App.”) 1 Cal. Ptn’s App.
497, 500. SDG&E owns and operates nearly 19,000
miles of electrical distribution and transmission
lines, including many in rural backcountry areas
that it is legally obligated to serve and where the
risk of wildfires is significant. 1 Cal. Ptn’s App. 500501. In keeping with CPUC regulations and utility
industry best practices, SDG&E has multiple programs to mitigate and reduce wildfire risk, and has
been lauded as a “potential example of excellence.” 2
Cal. Ptn’s App. 822-824.
In October 2007, Southern California experienced
severe Santa Ana winds with reported wind speeds
of 40 to 60 miles per hour and gusts up to 100 miles
per hour. 1 Cal. Ptn’s App. 382, 31 Cal. Ptn’s App.
11787, fn. 30. As these winds swept across Southern
California, they caused hundreds of fires, only some
of which the thinly stretched firefighting resources
were able to contain and which burned over 500,000
acres. 1 Cal. Ptn’s App. 149-150, 31 Cal. Ptn’s App.
11777. The Witch Fire combined with the Guejito
Fire burned nearly 200,000 acres, damaging over
1,140 homes. 31 Cal. Ptn’s App. 11786, 11789,
11804. The Rice Fire burned nearly 9,500 acres and
damaged over 200 homes. 13 Cal. Ptn’s App. 6142.
Property owners, insurers, and government entities alleging damage from the fires filed more than
2,500 lawsuits against SDG&E, bringing, among
others, claims for inverse condemnation.
6
B. California Law Of Inverse Condemnation
Under California law, inverse condemnation is a
form of strict liability that can be enforced whether
or not the damage from a public improvement was
foreseeable, and even if there was no fault or negligence. See, e.g., Marshall v. Department of Water
and Power of the City of Los Angeles, 219 Cal. App.
3d 1124, 1138-39 (1990); see also San Diego Gas &
Elec. Co. v. Sup. Ct., 13 Cal. 4th 893, 939-40 (1996).
All a plaintiff need establish is a causal relationship
between the government’s (or in this case, a privately
owned utility’s) activity and the alleged property
loss. Marshall, 219 Cal. App. 3d at 1138-39. And a
defendant can be held strictly liable for damages if
its public improvement was a substantial cause of
the damage, even if it is only one of several concurrent causes. See id.
The decisions of two intermediate California appellate courts have imposed inverse condemnation
liability on privately owned utilities to the same extent as such liability applies to government actors.
See Pacific Bell Tel. Co. v. S. Cal. Edison Co., 208
Cal. App. 4th 1400 (2012); Barham v. S. Cal. Edison
Co., 74 Cal. App. 4th 744 (1999). These decisions
and other decisions implementing them have never
been reviewed by the California Supreme Court.
Each decision imposed inverse condemnation liability on privately owned utilities on the express assumption that the resulting costs would be recovered
from ratepayers as the relevant benefitted public.
Pacific Bell expressly noted that there was no “evidence” that the CPUC would not allow a privately
owned utility to pass on inverse condemnation damages liability through adjustments “during its period-
7
ic reviews.” 208 Cal. App. 4th at 1407-08. Similarly,
Barham allowed a privately owned utility to be held
“liable in inverse condemnation” just the same “as a
public utility,” but in doing so recognized that the
key purpose of inverse condemnation is to “spread
among the benefiting community any burden disproportionately borne by a member of that community.”
74 Cal. App. 4th at 752-53.
C. Proceedings Below
Overruling a demurrer filed by SDG&E, the California superior court held that plaintiffs could bring
their inverse condemnation claims against SDG&E
even though it is a privately owned utility, not a government entity. See Minute Order, In re 2007 Wildfire Insurer Litig., p.2 (Super. Ct. San Diego County,
Jan. 29, 2009, No. 37-2008-0093083, CU-NP-CTL).
In light of the strict liability imposed by inverse
condemnation under California law, SDG&E decided
to settle the inverse condemnation claims against it
in order to reduce its exposure and avoid unnecessary litigation. 1 Cal. Ptn’s App. 141-42. As a result,
although plaintiffs asserted $5.6 billion in damages,
SDG&E resolved those claims with payments totaling $2.4 billion. 1 Cal. Ptn’s App. 57. SDG&E recovered $1.1 billion from its liability insurers and
another $824 million from settlements with third
parties based on cross-claims it had filed, leaving
SDG&E with $476 million in unrecovered settlement
payments and legal expenses. 31 Cal. Ptn’s App.
11778, fn. 2.
In 2012, SDG&E applied to the Federal Energy
Regulatory Commission (“FERC”), which regulates
the interstate transmission rates charged by utilities
8
like SDG&E, to include a portion of its unrecovered
payments in those rates. In 2014, FERC granted
SDG&E’s application, allowing immediate recovery
of $23 million and subsequent recovery of another
$67 million in settlement payments. See In re San
Diego Gas & Elec. Co., 146 FERC ¶ 63,017, 2014 WL
713556 (2014).
In so doing, FERC held that recovery was warranted without regard to the prudence of SDG&E’s
maintenance operations. Id. at ¶ 66,112-13. FERC
reasoned that SDG&E would have been held liable
under California inverse condemnation law without
regard to fault, and that, “[b]y settling, SDG&E
avoided facing considerable litigation risk and disposed of claims for significantly less than the amount
demanded by the claimants.” Id.
In 2015, SDG&E applied to the CPUC to include
in the rates under the CPUC’s jurisdiction $379 million—most but not all of the unrecovered settlement
payments.
App. 9a-10a.
The CPUC denied
SDG&E’s request, ruling that SDG&E had failed to
prove that its operation and management of the facilities connected with the fires satisfied the CPUC’s
own administratively developed “prudent manager”
standard. App. 81a-83a. Under the CPUC’s “prudent manager” standard, privately owned utilities
are allowed to recover costs only if they prove that
those costs were “prudently incurred by competent
management exercising the best practices of the era,
and using well-trained, well-informed, and conscientious employees who are performing their jobs
properly.” App. 13a.
The CPUC deemed the fact that SDG&E had
been subjected to strict liability for inverse condem-
9
nation “not relevant to a Commission reasonableness
review under the prudent manager standard.” App.
75a. According to the CPUC, “nothing” in prior judicial decisions extending inverse condemnation to private utilities “would supersede this Commission’s
exclusive jurisdiction over cost recovery/cost allocation issues involving CPUC regulated utilities,”
which the CPUC ruled required it to assess the prudence of SDG&E’s conduct before the fires ignited.
App. 76a.
The CPUC’s president and another commissioner
issued a joint concurrence expressing concern about
the application of inverse condemnation to privately
owned utilities, and deeming “unsound” the premise
that utilities would be able to “socialize[]” the cost of
such liability across ratepayers, as the prior California intermediate appellate court decisions in Barham and Pacific Bell had expressly assumed. App.
91a.
In addition, the concurrence noted that
applying inverse condemnation to privately owned
utilities that are not guaranteed to recover their
costs would increase those utilities’ capital costs and
insurance expenses, ultimately leading to higher
rates for ratepayers. App. 92a. The concurrence
urged the California legislature and courts to
reconsider whether inverse condemnation applies to
privately owned utilities. App. 92a-93a. Neither has
since done so.
SDG&E applied for rehearing, which the CPUC
denied.
App. 94a-137a.
The CPUC rejected
SDG&E’s argument that the “prudent manager”
standard should not apply under state law to inverse
condemnation costs, 127a-134a, and also rejected
SDG&E’s constitutional challenges to its application
10
of the “prudent manager” standard to bar recovery,
App. 134a-137a.
The CPUC declined to harmonize its ruling with
the judicial decisions in Barham and Pacific Bell,
even though those decisions had subjected private
utilities to inverse condemnation claims on the
express assumption that the CPUC would spread
inverse condemnation costs among the ratepayers.
App. 125a-131a. Deeming itself bound to apply its
“prudent manager” standard, the CPUC did not
consider whether applying the standard to inverse
condemnation costs created an unjust and
unreasonable whipsaw between contradictory legal
standards. App. 131a-134a. Finally, the CPUC
denied that applying the “prudent manager”
standard to inverse condemnation costs creates an
unconstitutional taking. App. 134a-137a.
D. The California Courts’ Denial Of Review
SDG&E filed a petition for a writ of review with
the California court of appeal, which denied review
in a summary three-page order. App. 1a-4a. The
court of appeal did not address the California judicial
decisions that had subjected privately owned utilities
to inverse condemnation or the cost-spreading rationale underlying those decisions.
Nor did it
address the unconstitutional taking created by the
CPUC decision or seek to avoid that serious
constitutional issue by interpreting section 451 of the
California public utilities code (which provides for
rate recovery for “just and reasonable” charges) to
afford rate recovery for inverse condemnation costs.
Instead the court of appeal rejected SDG&E’s
arguments without explanation:
11
The Commission’s determination that the
princip[les] of inverse condemnation did
not bar its prudent manager analysis under
section 451 was not in excess of its powers,
nor a violation of the law, including the
Constitutions of the United States and
California. Contrary to SDG&E’s assertion,
the Commission’s review was statutorily
mandated, and no legal authority
authorized it to forgo it obligations under
section 451. Of note, SDG&E settled the
inverse condemnation claims in the wildfire
litigation rather than continue to advance
its position that it could not be held strictly
liable as a non-governmental entity.
Further, had the Commission determined
that SDG&E acted as a prudent manager,
the costs could have been passed onto the
ratepayers regardless of any potential
strict liability in a civil litigation setting.
App. 3a-4a.
SDG&E then filed a petition for review in the
California Supreme Court, which the Court summarily denied. App. 5a.
REASONS FOR GRANTING THE WRIT
I. THE DECISION BELOW CONFLICTS WITH
THE
TAKINGS
CLAUSE
AND
THIS
COURT’S TAKINGS PRECEDENTS
This Court should grant certiorari because the
decision below conflicts with the fundamental right
to just compensation for takings of private property
for public use, as enshrined in the Fifth Amendment
12
as applied to the States through the Fourteenth
Amendment and embodied in this Court’s Takings
Clause jurisprudence.
The CPUC’s denial of
recovery, affirmed by the California court of appeal,
is a regulatory taking warranting just compensation.
The California courts’ decision to impose liability
without such compensation upends settled law in
this area, warranting this Court’s review.
A. The Decision Below Conflicts With The
Core Cost-Spreading Premise Of The
Takings Clause
California law now imposes an unconstitutional
whipsaw on privately owned utilities. Barham and
Pacific Bell, decisions whose holdings the California
Supreme Court has consistently declined to review or
reconsider, impose inverse condemnation liability on
privately owned utilities just as if they were
government actors with the unfettered ability to
spread the costs of such liability to the benefitted
public. They are not. As the CPUC’s refusal to allow
SDG&E to recover those costs starkly illustrates,
privately owned utilities, unlike government actors,
may not spread inverse condemnation costs across
the benefitted public—here the ratepayers who
benefit from electric power generation and
transmission. The decision below thus conflicts with
this Court’s precedent under the Takings Clause.
Inverse condemnation is a judicially developed
doctrine rooted in federal and state constitutional
provisions that “private property [shall not be] be
taken for public use, without just compensation.”
U.S. Const. amend. V, XIV; see Cal. Const. Art. I, sec.
19 (“Private property may be taken or damaged for
public use only when just compensation…has first
13
As this Court has consistently
been paid….”).
explained, the purpose of the Takings Clause is “to
bar Government from forcing some people alone to
bear public burdens which, in all fairness and
justice, should be borne by the public as a whole.”
Armstrong v. United States, 364 U.S. 40, 49 (1960).
In particular, “the just compensation requirement
spreads the cost of condemnations and thus ‘prevents
the public from loading upon one individual more
than his just share of the burdens of government.’”
Kelo v. City of New London, 545 U.S. 469, 497 (2005)
(O’Connor, J., dissenting) (quoting Monongahela
Nav. Co. v. United States, 148 U.S. 312, 325 (1960)).
This rationale applies equally to suits for inverse
condemnation. See, e.g., Arvo Van Alstyne, Statutory
Modification of Inverse Condemnation: The Scope of
Legislative Power, 19 Stan. L. Rev. 727, 738 (1967)
(explaining that the purpose of the California law of
inverse condemnation is to ensure that losses are
“distributed over taxpayers at large rather than be
borne by the injured individual”).
This rationale makes sense where the taking is
made by the government, which is then free to spread
that cost among the benefitted public through the
coercive power of taxation. A government entity
sued in inverse condemnation by an injured property
owner may draw from general funds or raise taxes in
the community, and a publicly owned utility may
unilaterally raise the rates that consumers pay for
the services the utility provides. See, e.g., Sultum v.
Tahoe Regional Planning Agency, 520 U.S. 725
(1997) (taking by regional government planning
agency); Babbitt v. Youpee, 519 U.S. 234 (1997)
(taking by federal government); Dolan v. City of
Tigard, 512 U.S. 374 (1994) (taking by city).
14
Unlike the government or a public utility,
however, a privately owned utility may not raise the
rates that it charges customers or pass the costs of
inverse condemnation liability on to ratepayers
without the approval of its regulator, the CPUC.
And the CPUC below treated SDG&E quite unlike a
public entity by barring its request to spread those
costs across the ratepayers who benefit from
electricity generation and transmission. In denying
SDG&E the ability to spread its inverse
condemnation costs, the CPUC applied a “prudent
manager” standard that does not apply when the
government seeks to spread liability for such costs.
Such a ruling conflicts with the foundational
premise
of
the
Takings
Clause.
Inverse
condemnation assumes that it is an unconstitutional
taking to require the property owner who lost his
home or business in a wildfire to “bear public
burdens which, in all fairness and justice, should be
borne by the public as a whole.” Armstrong, 364 U.S.
at 49. But by the same logic it is an unconstitutional
taking to shift that public loss to another private
entity—here, SDG&E—rather than to the ratepaying
electricity customers who benefit from the public
improvement of power generation and transmission
in the State. Either the destruction of property in a
wildfire is a taking or it is not; but it cannot be a
taking for some purposes (when compensating
property owners) but not others (allowing SDG&E
the right to recover from the rate-paying public).
This Court should grant review to clarify these basic
principles in this context.
15
B. The Decision Below Conflicts With This
Court’s Regulatory Takings Precedent
The imposition of inverse condemnation liability
on privately owned utilities without ensuring that
those costs are spread across the benefitted ratepaying public further conflicts with this Court’s precedent on regulatory takings. Such takings result
from government action that (as here) diminishes or
destroys economic value without the formal exercise
of the power of eminent domain. In evaluating regulatory takings, this Court has instructed courts to
examine three factors: (1) “[t]he economic impact of
the regulation on the claimant”; (2) “the extent to
which the regulation has interfered with distinct investment-backed expectations”; and (3) whether the
government action balances the “benefits and burdens of economic life to promote the common good.”
Lingle v. Chevron U.S.A. Inc., 544 U.S. 528, 538-39
(2005) (quoting Penn Central Transp. Co. v. New
York City, 438 U.S. 104, 124 (1978)).
As the decision below fails to recognize, those factors are all satisfied here. First, the economic impact
of imposing $379 million in inverse condemnation
costs on SDG&E without just compensation is selfevidently substantial. And notably, SDG&E’s total
liability from inverse condemnation from the Witch,
Guejito and Rice fires alone might have been much
greater, indeed in the billions, had it not exercised
foresight in settling cases and managing its insurance coverage so as to recover from third parties.
Second, requiring a privately owned utility to satisfy a “prudent manager” standard before it can recover the costs of inverse condemnation liability
clearly upsets its reasonable investment-backed ex-
16
pectations. As noted, the judicial precedents under
which California imposed inverse condemnation liability on privately owned utilities in the first place
expressly assumed that the resulting costs would be
spread across the benefitted rate-paying public. See
Pacific Bell, 208 Cal. App. 4th at 1407-08; Barham,
74 Cal. App. 4th at 752-53; see supra at pp. 6-7.
Thus, prior to the decision in this case, SDG&E’s investors reasonably believed that SDG&E would be
permitted to pass on the costs of inverse condemnation claims to ratepayers via adjustments in the ratesetting process. The CPUC decision negated these
reasonable, investment-backed expectations, triggering the just compensation requirement.
Moreover, privately owned utilities are compelled
by their regulatory obligations to sink significant investments into infrastructure and facilities, and are
compelled to continue providing services regardless
of profitability, without the option of exiting the
market. As one notable set of commentators has
thus suggested, “doctrinal confusion is nowhere more
apparent or more important than in the treatment of
takings principles applicable to public utilities.” See
William P. Barr, Henry Weissmann, & John P.
Fratz, The Gild that Is Killing the Lily: How Confusion over Regulatory Takings Doctrine Is Undermining the Core Protections of the Takings Clause, 73
Geo. Wash. L. Rev. 429, 431 (2005).
Third, far from balancing the benefits and burdens of economic life, the whipsaw created by uncompensated inverse condemnation liability here
would concentrate the entire burden of damage from
the electricity infrastructure on privately owned utilities like SDG&E. Indeed, it would simply shift the
17
disproportionate burden of property damage from
public improvements from one private member of the
community (the damaged property owner) to another
private member of the community (here, SDG&E)
without ever allowing it to spread those costs among
the relevant public that benefits from power generation and transmission. Cf. Eastern Enterprises v. Apfel, 524 U.S. 498, 529-30 (1998) (finding
unconstitutional regulatory taking where law requiring payments into health fund for coal workers, even
though the payor was no longer in the coal mining
business).
While the CPUC did not dispute the enormous
economic impact of its denial of any recovery, it erred
in arguing that there was no regulatory taking
because SDG&E had no “guaranteed expectation of
rate recovery under Section 451.” App. 136a. That
argument ignores the decisions of this Court and the
California court of appeal imposing inverse
condemnation liability on private utilities only on the
assumption that such liability would be recovered
through rate-making and thus spread among
ratepayers. The CPUC also argued that its actions
were in keeping with the CPUC’s statutory
obligations and established rate-making practice and
its interest in protecting ratepayers from unjust and
unreasonable rates.
Id.
The Takings Clause,
however, is a constitutional restriction that
supersedes statutes and agency practice. Moreover,
there is nothing “unjust or unreasonable” about
allowing a private utility to pass onto ratepayers the
cost of satisfying a burden that should be “borne by
the public as a whole,” Armstrong, 364 U.S. at 49,
and spread among those benefitted, Monongahela
Nav. Co., 148 U.S. at 325. Therefore, the CPUC
18
failed to dispel the constitutional taking effected by
applying the “prudent manager” standard to inverse
condemnation costs.
In light of the CPUC’s and court of appeal’s
failure to reconcile their decision with the Takings
Clause, the decision below will sow further confusion
in both state and federal courts regarding this
Court’s regulatory takings jurisprudence, and call
into question the important lines this Court has
drawn in explaining when a State’s imposition of a
new and expensive burden on a single private
individual has gone too far.
The principles set forth in Duquesne Light Co. v.
Barasch, 488 U.S. 299 (1989), do not suggest otherwise. There, the Court found there was no “confiscatory” taking from a public utility in the rate-setting
process because the rate permitted by the public utilities commission still allowed for a reasonable rate of
return on investment. Id. at 315. But that case did
not determine whether a particular state action
would constitute a regulatory taking. Nor did the
Court state, or even suggest, that an overall reasonable rate of return would insulate a State from any
and all takings challenges in the utilities context.
Surely, the State could not have police seize a parcel
of property or a building at SDG&E’s corporate
headquarters without compensation, and then argue
that its actions were constitutional because, even
without that property, SDG&E is still able to attract
capital and earn a reasonable rate of return on its
investments.
The same is true here: California has created a
judicial regime whereby SDG&E and other privately
owned utilities will be forced to absorb all of the costs
19
of inverse condemnation claims for wildfire-related
losses across the State, but will receive none of the
benefits that a government actor would receive in being able to spread the inverse condemnation costs to
the benefitted public by creating a new tax, drawing
from the public coffers, or increasing electricity rates.
Such a regime threatens core principles of the Fifth
and Fourteenth Amendments without regard to
whether the rate set by the CPUC would also be considered unconstitutionally confiscatory or not. This
Court’s guidance is therefore needed to resolve this
issue and provide much needed clarification in this
area of the law.
II. THIS CASE IS AN IDEAL VEHICLE TO
ADDRESS THE QUESTION PRESENTED
There is no reason why the question presented
here may not be fully and finally resolved by this
Court. First, unlike in many cases in which federal
unconstitutional takings questions arise from state
court proceedings, there is no question that SDG&E
has exhausted its state-law remedies. Specifically,
SDG&E has attempted to obtain “just compensation”
from the State by asking the CPUC for permission to
spread inverse condemnation liability across
ratepayers via the rate-setting process before seeking
this Court’s review. App. 6a. Thus, this case does
not present any of the procedural pitfalls of cases
like Williamson County v. Hamilton Bank of Johnson
City, 473 U.S. 172 (1985), or Knick v. Township of
Scott, 862 F.3d 310 (3d Cir. 2017), certiorari granted
138 S. Ct. 1262 (2018), where the plaintiff elected to
bring his Takings Clause claim in federal district
court without availing himself of potential state
court remedies first. See Williamson Cnty., 473 U.S.
20
at 194-96 (holding that Takings Claim action
brought under 42 U.S.C. § 1983 was not yet ripe
because plaintiff did not first seek compensation
through the procedures the state provided); Knick,
862 F.3d at 324-26 (same).
Second, the California court of appeal and
Supreme Court have repeatedly declined to grant
review of the issues raised here, suggesting that no
judicial resolution of the issues under state law will
be forthcoming so as to moot SDG&E’s federal
Takings Clause claim. The California appellate
courts have declined review of these issues despite
the CPUC’s members’ own repeated petitions for
judicial review, see supra, at p. 9, and in the face of
the
privately
owned utilities’ exponentially
increasing inverse condemnation liability from
wildfires.
Specifically, the California court of appeal and
Supreme Court have not only denied SDG&E’s
petitions for review in this case, but have also
summarily denied six related petitions for review. In
those petitions, PG&E and Southern California
Edison (“SCE”) questioned the California state-law
decisions imposing inverse condemnation on
privately owned utilities in light of the CPUC’s
decision denying recovery here. See, e.g., Pacific Gas
& Electric Co. v. Superior Court (Abu-Shumays) No.
C087071 (Cal. App. May 9, 2018), No. S249429 (Cal.
June 8, 2018) (2015 Butte Fire); Pacific Gas &
Electric Co. v. Superior Court (Abbott) No. A154847
(Cal. App. July 20, 2018), No. S251585 (Cal. Oct. 1,
2018) (2017 North Bay Fires); Edison International,
Southern California Edison Company v. Superior
Court (Abate) No. B294164 (Cal. App. Dec. 3, 2018),
21
No. S253094 (Cal. Dec. 17, 2018) (2017 Thomas
Fires).
The denial of those petitions strongly
suggests that no state judicial relief is forthcoming.
Finally, there is no near-term prospect of any
legislative relief or clarification of the California law
of inverse condemnation as applied to privately
owned utilities. Last summer, Governor Jerry
Brown, recognizing that wildfires are the “new
normal” in California, proposed legislation that
would have reformed inverse condemnation law as
applied to privately owned utilities by removing the
strict liability standard and replacing it with a
standard reflecting a utility’s proportionate fault.
But the Legislature declined to adopt the Governor’s
proposal, instead enacting a statute concerning
wildfire cost recovery, Cal. Stats. 2018, ch. 626,
§§ 26–27, 32, that disclaimed any change in civil
liability standards, Cal. Pub. Util. Code, §451.1,
subd. (c), and effectively reaffirmed the CPUC’s
“prudent manager” standard, id., § 451.1, subd.
(a)(1)–(12). The Legislature thus left the legal
whipsaw squarely in place, underscoring the
ripeness of the Takings Clause question presented
here.
III. THIS CASE PRESENTS A QUESTION OF
EXCEPTIONAL NATIONAL IMPORTANCE
The national importance of the takings question
presented here can hardly be overstated, and further
warrants the grant of certiorari. The California
courts’ imposition of uncompensated inverse
condemnation liability on privately owned utilities
threatens grave economic and infrastructure harm
not only to privately owned utilities in California,
but also to the California economy as a whole. And
22
because California is the largest economy among the
States and now the fifth largest economy in the
world, such risks inherently threaten the United
States’ economy as well.
California’s three largest privately owned
utilities—PG&E, SCE, and SDG&E—together
deliver power to 34.6 million of California’s nearly 40
million residents over 124,100 of California’s 163,696
square miles. These privately owned utilities not
only supply three-quarters of the State’s electricity,
but also employ nearly 40,000 California residents
and play a critical role in advancing environmental
goals. The threat of expansive inverse condemnation
liability against privately owned utilities has greatly
increased financial pressures on those utilities.
First, the threat of uncompensated inverse
condemnation liability in an era of escalating
wildfires has increased the cost of insurance and
eventually may render all California utilities
uninsurable.
According to one report, utilities’
insurance costs in California have “skyrocketed” and
sometimes
insurance
has
become
simply
“unavailable.”1
Second, the threat of uncompensated inverse
condemnation liability increases the costs of capital
for privately owned utilities. When the CPUC issued
the order below denying SDG&E recovery, market
analysts commented that California privately owned
utilities presented
a
“uniquely
unpalatable
proposition of socialized no-fault liability” with “no
Ethan Howland, Utilities to fight climate risk via
insurance upgrades, 2018 CQ Roll Call Was. Energy
Briefing 1673 (Nov. 14, 2018).
1
23
assurance of presumed recoverability,”2 and warned
that the utilities would experience a “material
increase in their cost of capital.”3 Indeed, Moody’s
changed SDG&E’s rating outlook from “stable” to
“negative,” noting that the CPUC’s decision denying
SDG&E rate recovery would cause “higher
regulatory risk for investor-owned utilities in
California due to inverse condemnation exposure and
the uncertainty that they will be able to recover
Following the
related costs from ratepayers.”4
CPUC’s decision in this case, another analyst wrote
that California utilities were “uninvestable right
now” because there were “too many unknowns and
significant risk.”5
Third, privately owned utilities have suffered
plunges in their stock prices in the aftermath of
every new wildfire, reflecting the exponentially
increasing costs and risks of inverse condemnation
Jonathan Arnold, CPUC Denies SDG&E Wildfire
Recovery; Notes “Incorrect Premise” of IC Doctrine,
Deutsche Bank Power Flash, at 3 (Nov. 30, 2017).
2
Greg Gordon & Kevin Prior, PCG Has Suspended
Dividends, Citing Uncertainty Regarding Wildfire-Related
Liabilities, Evercore ISI, at 2 (Dec. 21, 2017).
3
Moody’s Investors Service, Rating Action: Moody’s
Changes San Diego Gas & Electric’s Rating Outlook to
Negative
From
Stable
(Apr.
11,
2018),
http://www.moodys.com/research/Moodys-changes-SanDiego-Gas-Electric-rating-outlook-to-negative-PR_380749.
4
Mike Yamamoto, Market Notes: Tuesday, December 12,
2017 (Dec. 12, 2017), https://investitute.com/activitynews/market-notes-tuesday-december-12-2017/.
5
24
claims.6
In January 2019, PG&E filed for
bankruptcy in the face of an likely unrecoverable
estimated $30 billion in inverse condemnation
liability resulting from a series of wildfires.7 And
this may just be the tip of the iceberg. SCE recently
took a charge of $4.7 billion tied to wildfire events in
its service territory8 and both Edison International’s
CEO and analysts have opined that SCE could be
just one or two more fires away from bankruptcy.9
See Ivan Penn & Peter Eavis, Liability Claims From
Wildfires Threaten Utility, N.Y. Times, Nov. 14, 2018, at
A1,
available
at
https://www.nytimes.com/2018/11/14/business/energyenvironment/california-fire-utilities.html.
6
Mark Chediak & Kiel Porter, PG&E Bankruptcy
Looms, CEO to Exit as Fire Costs Dwarf Cash, Bloomberg
(Jan
14,
2019),
https://www.bloomberg.com/news/articles/2019-01-14/pge-plans-bankruptcy-filing-as-california-wildfires-costsmount.
7
Anne C. Mulkern, No silver bullet. Can Calif. Save its
utilities?,
E&E
News
(Apr.
1,
2019),
https://www.eenews.net/stories/1060137633.
8
Id.; Sammy Roth, Edison CEO talks wildfires, climate
change and the utilities vanishing monopoly, L.A. Times
(Mar. 13, 2019), https://www.latimes.com/business/la-fisouthern-california-edison-sce-wildfires-climate-change20190313-story.html; see J.D. Morris, California considers
wildfire insurance fund to avoid repeat of PG&E’s woes,
S.F.
Chronical
(Feb.
25,
2019),
https://www.sfchronicle.com/business/article/Californiamulls-wildfire-insurance-fund-to-avoid13641330.php?psid=oFzg.
9
25
The financial impact of inverse condemnation
liability on privately owned utilities has other ripple
effects on the national economy by harming
consumers and environmental goals. As the CPUC’s
own President warned legislators, “the financial
pressure on utilities from inverse condemnation may
lead to higher rates for ratepayers.”10 And as one
analysis recognized following the 2017 Wine Country
wildfires, “unless the law is changed regarding
application of inverse condemnation to investorowned utilities or the CPUC changes its position on
recovery under that law,” California utilities will
experience material increases in capital costs,
“stressing their ability to invest in CA infrastructure
and help the state meet its aggressive clean energy
agenda.”11 Most recently, Governor Newsom’s Strike
Force report explained that California’s “regime—
strict liability for wildfire damage coupled with
uncertain ability to recover those damages in rates—
increases the risk of bankrupt utilities, which in turn
drives up costs for consumers, threatens fair
recoveries for fire victims, undermines the state’s
ability to mitigate and adopt to climate change, and
creates uncertainty for utilities employees and
contractors.”12
Cal. Assembly Comm. on Utils. & Energy (Feb. 26,
2018),
http://assembly.ca.gov/media/assembly-utilitiesenergy-committee-20180226/video,
at
1:04:2-1:04:58
(testimony of CPUC President and Commissioner Michael
Picker).
10
11
Gordon & Prior, supra.
Governor Newsom’s Strike Force, Wildfires and Climate Change: California’s Energy Future (Apr. 12, 2019),
https://www.gov.ca.gov/wp-
12
26
These problems will only get worse as wildfires
(and wildfire litigation) increase exponentially with
climate change.
Officials from the California
Department of Forestry and Fire Protection (“Cal
Fire”) have warned that recent trends “’reflect a
major shift in wildfires, one … seen over the past 10
years” showing that “’[w]ildfires are becoming more
damaging and destructive.’”13
They also have
cautioned that fire season could now persist yearround.14 By the end of this century, temperatures in
the United States are expected to rise another 3.5
degrees Celsius,15 or over 6 degrees Fahrenheit. The
increase in the risk of wildfires caused by increased
temperatures is exponential, not linear, meaning
that each degree increase in temperature may herald
a much greater proportional increase in the number
and severity of wildfires.16 Indeed, of the twenty
content/uploads/2019/04/Wildfires-and-Climate-ChangeCalifornia%E2%80%99s-Energy-Future.pdf.
Melissa Pamer & Elizabeth Espinosa, ‘We Don’t Even
Call It Fire Season Anymore ... It’s Year Round’: Cal Fire,
KTLA5
News
(Dec.
11,
2017),
http://ktla.com/2017/12/11/we-dont-even-call-it-fireseason-anymore-its-year-round-cal-fire/.
13
14
Id.
Robinson Meyer, Has Climate Change Intensified
2017’s Western Wildfires?, The Atlantic (Sept. 7, 2017),
https://www.theatlantic.com/science/archive/2017/09/why
-is-2017-so-bad-for-wildfires-climate-change/539130/.
15
Chelsea Harvey, Here’s What We Know About
Wildfires and Climate Change, Scientific American (Oct.
13,
2017),
https://www.scientificamerican.com/article/heres-whatwe-know-about-wildfires-and-climate-change/.
16
27
most destructive wildfires in California since 1932,
five occurred in 2017, and thirteen after 2000,
including the five largest.17
These profound economic and infrastructure
consequences
of
wildfire-related
inverse
condemnation claims against privately owned
utilities underscore the need for the Court’s
intervention, especially in the face of inaction by the
California judicial and legislative branches. This
Court should grant review.
CONCLUSION
The petition for certiorari should be granted.
Respectfully submitted,
Kathleen M. Sullivan
Jeffrey N. Boozell
Counsel of Record
QUINN EMANUEL
URQUHART & SULLIVAN, Stephanie N. Solomon
LLP
QUINN EMANUEL URQUHART
865 S. Figueroa St.
& SULLIVAN, LLP
th
51 Madison Ave., 22nd Floor
10 Floor
Los Angeles, CA
New York, NY 10010
(212) 849-7000
(213) 443-3200
kathleensullivan@
quinnemanuel.com
Counsel for Petitioner
April 30, 2019
Cal. Dep’t of Forestry & Fire Prot., Top 20 Most
Destructive California Wildfires (Nov. 19, 2018),
http://www.fire.ca.gov/communications/downloads/fact_sh
eets/Top20_Destruction.pdf.
17
APPENDIX
1a
APPENDIX A
COURT OF APPEAL,
FOURTH APPELLATE DISTRICT
DIVISION ONE
STATE OF CALIFORNIA
————
D074417
(Public Utilities Commission No. 17-11-033)
————
SAN DIEGO GAS & ELECTRIC,
v.
Petitioner,
PUBLIC UTILITIES COMMISSION,
Respondent;
PROTECT OUR COMMUNITIES FOUNDATION et al.,
Real Parties in Interest.
————
THE COURT:
The petition for writ of review filed by San Diego
Gas & Electric Company (SDG&E) and the accompanying exhibits, the answers filed by real parties in
interest Protect Our Communities Foundation (POCF)
and Ruth Henricks, the answer filed by the California
Public Utilities Commission, and the reply to answers
filed by SDG&E have been read and considered by
Justices Benke, O’Rourke, and Dato.
SDG&E challenges the Commission’s decision denying its application to include $379 million in settlement
payments stemming from litigation involving wildfires
caused by its facilities in 2007. SDG&E asserts the
2a
Commission’s decision should be annulled because it
interpreted Public Utilities Code section 451 (further
statutory references are to the Public Utilities Code)
in a manner that unconstitutionally conflicts with the
strict liability the utility faced in the wildfire litigation
as a result of the plaintiffs’ inverse condemnation
claims. SDG&E also argues the Commission’s decision
must be annulled because insufficient evidence supported its determination that (1) SDG&E was an
imprudent manager and (2) SDG&E’s conduct caused
the Witch Fire.
“‘“[A]ny aggrieved party [to a decision of the
Commission] may petition for a writ of review in the
court of appeal . . . .”’” (SFPP, L.P. v. Public Utilities
Commission (2013) 217 Cal.App.4th 784, 793 (SFPP).)
“[W]hen ‘writ review is the exclusive means of appellate review of a final order or judgment, an appellate
court may not deny an apparently meritorious writ
petition, timely presented in a formally and procedurally sufficient manner, merely because, for example,
the petition presents no important issue of law or
because the court considers the case less worthy of
its attention than other matters.’ [Citation.] We are
not, however, ‘compelled to issue the writ if the
[Commission] did not err . . . .’” (Ibid.)
“The limited grounds and standards for our review
are set forth in section 1757, subdivision (a). ‘No new
or additional evidence shall be introduced upon review
by the court. In a complaint or enforcement proceeding, or in a ratemaking or licensing decision of specific
application that is addressed to particular parties, the
review by the court shall not extend further than to
determine . . . whether any of the following occurred:
(1) The commission acted without, or in excess of, its
powers or jurisdiction. (2) The commission has not
3a
proceeded in the manner required by law. (3) The
decision of the commission is not supported by the
findings. (4) The findings in the decision of the
commission are not supported by substantial evidence
in light of the whole record. (5) The order or decision
of the commission was procured by fraud or was an
abuse of discretion. (6) The order or decision of the
commission violates any right of the petitioner under
the Constitution of the United States or the California
Constitution.’” (SFPP, supra, 217 Cal.App.4th at
pp. 793-794.)
“‘There is a strong presumption favoring the validity of a Commission decision.’” (SFPP, supra, 217
Cal.App.4th at p. 794.) “‘Generally, we give presumptive value to a public agency’s interpretation of a
statute within its administrative jurisdiction because
the agency may have “special familiarity with satellite legal and regulatory issues,” leading to expertise
expressed in its interpretation of the statute. [Citation.]
Therefore, “the PUC’s ‘interpretation of the Public
Utilities Code should not be disturbed unless it fails to
bear a reasonable relation to statutory purposes and
language . . . .’”’” (Ibid.)
The Commission’s determination that the principals
of inverse condemnation did not bar its prudent
manager analysis under section 451 was not in excess
of its powers, nor a violation of the law, including the
Constitutions of the United States and California.
Contrary to SDG&E’s assertion, the Commission’s
review was statutorily mandated, and no legal authority authorized it to forego its obligation under section
451. Of note, SDG&E settled the inverse condemnation claims in the wildfire litigation rather than
continue to advance its position that it could not be
held strictly liable as a non-governmental entity.
4a
Further, had the Commission determined that SDG&E
acted as a prudent manager, the costs could have been
passed onto the ratepayers regardless of any potential
strict liability in a civil litigation setting.
In addition, the exhibits submitted by SDG&E do
not support its assertion that the Commission’s findings
under section 451 were not supported by sufficient
evidence. Specifically, the record contains substantial
evidence showing both that SDG&E’s facilities caused
all three of the wildfires at issue, and that SDG&E did
not meet its burden to show that it reasonably and
prudently operated and maintained those facilities.
(See Toward Utility Rate Normalization v. Public
Utilities Com. (1978) 22 Cal.3d 529, 537 [“The findings
of fact by the Commission are to be accorded the same
weight that is given to jury verdicts and the findings
are not open to attack for insufficiency if they are
supported by any reasonable construction of the
evidence.”].)
In sum, SDG&E has failed to demonstrate that the
Commission erred on the claims it asserts. Under
these circumstances, we decline to issue the writ of
review. (Pacific Bell v. PUC (2006) 140 Cal.App.4th
718, 729.) The petition is denied. The application of
Southern California Edison Company and Pacific Gas
and Electric Company for leave to file an amicus
curiae brief is denied as moot.
BENKE, Acting P. J.
Copies to: All parties
5a
APPENDIX B
IN THE SUPREME COURT OF CALIFORNIA
En Banc
————
S252748
————
SAN DIEGO GAS & ELECTRIC,
v.
Petitioner,
PUBLIC UTILITIES COMMISSION,
Respondent;
PROTECT OUR COMMUNITIES FOUNDATION et al.,
Real Parties in Interest.
————
Court of Appeal, Fourth Appellate District,
Division One - No. D074417
————
The request for judicial notice is granted.
The petition for review is denied.
CANTIL-SAKAUYE
Chief Justice
6a
APPENDIX C
ALJ/SPT/SL5/ek4
Date of Issuance 12/6/2017
Decision 17-11-033 November 30, 2017
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
————
Application 15-09-010
————
Application of San Diego Gas & Electric Company
(U902E) for Authorization to Recover Costs
Related to the 2007 Southern California
Wildfires Recorded in the Wildfire Expense
Memorandum Account (WEMA).
————
DECISION DENYING APPLICATION
————
7a
Table of Contents
Title
Page
DECISION DENYING APPLICATION ..................... 1
Summary...................................................................... 2
1.
Factual Background ............................................. 2
2.
Procedural Background ........................................ 3
3.
Legal Standards Applied...................................... 9
4.
Discussion and Analysis .................................... 11
4.1. Witch Fire ....................................................... 11
4.1.1. Witch Fire Background ........................... 11
4.1.2. SDG&E’s Position on its Operation
and Management of its Facilities
Prior to the Witch Fire ............................ 15
4.1.3 ORA’s Position on SDG&E’s Operation and Management of its Facilities Prior to the Witch Fire ..................... 21
4.1.4. Intervenors’ Position on SDG&E’s
Operation and Management of its
Facilities Prior to the Witch Fire ............ 24
4.1.5. Reasonableness Review: SDG&E’s
Operation and Management of its
Facilities Prior to the Witch Fire ............ 27
4.2. Guejito Fire ..................................................... 29
4.2.1. Guejito Fire Background ......................... 29
4.2.2. SDG&E’s Position on its Operation
and Management of its Facilities
Prior to the Guejito Fire .......................... 31
4.2.3. ORA’s Position on SDG&E’s Operation and Management of its Facilities Prior to the Guejito Fire ................... 33
8a
4.2.4. Reasonableness Review: SDG&E’s
Operation and Management of its
Facilities Prior to the Guejito Fire .......... 35
4.3. Rice Fire .......................................................... 36
4.3.1. Rice Fire Background .............................. 36
4.3.2. Legal Requirements................................. 37
4.3.3. Issues and Party Positions ...................... 38
4.3.3.1. FF1090’s Inspection and Trimming Schedule .................................. 38
4.3.3.2. FF1090’s latent defect and the
issue of Reliability Trees .................. 40
4.3.4. Discussion ................................................ 41
4.3.4.1. SDG&E’s Tree Inspection and
Trimming Schedule .......................... 42
4.3.4.2. FF1090’s Latent Defect and the
Issue of Reliability Trees .................. 47
4.4. Commission Precedent ................................... 49
4.5. Wind and Weather Conditions in October
2007 ................................................................. 55
4.6. Reconsideration of Threshold Issues ............. 61
5.
Conclusion .......................................................... 61
6.
Intervenor Compensation .................................. 64
7.
Comments on Proposed Decision ....................... 64
8.
Assignment of Proceeding .................................. 65
Findings of Fact ......................................................... 65
Conclusions of Law .................................................... 69
ORDER....................................................................... 72
9a
DECISION DENYING APPLICATION
Summary
This decision finds that San Diego Gas & Electric
Company did not reasonably manage and operate its
facilities prior to the 2007 Southern California Wildfires and therefore denies the utility’s request to
recover costs recorded in its Wildfire Expense Memorandum Account. Because we deny this application on
its merits, the issue preliminarily scoped for phase two
of this proceeding is moot.
This proceeding is closed.
1. Factual Background
Beginning on October 21, 2007, a fire storm ripped
through portions of Southern California. This fire
storm, which was comprised of more than a dozen
fires, spread over portions of Orange, San Diego, Los
Angeles, San Bernardino, Ventura, Santa Barbara,
and Riverside counties. These wildfires caused extensive damage to properties in the region, widespread
evacuations, and fatalities.1 Investigative reports issued
in the aftermath of the 2007 wildfires by the California
Department of Forestry and Fire Protection (Cal Fire)
and the Commission’s Consumer Protection and Safety
Division (CPSD) (now the Safety and Enforcement
Division), attributed the ignition of three of these
wildfires to San Diego Gas & Electric Company (SDG&E)
facilities. These three fires, the Witch, Guejito and
Rice wildfires (2007 Wildfires), are the subject of the
instant proceeding.
On September 25, 2015, SDG&E filed Application
(A.) 15-09-010 seeking Commission approval to recover
1
Application (A.) 15-09-010 at 2.
10a
$379 million recorded in its Wildfire Expense Memorandum Account (WEMA). The WEMA is an account
established per Resolution E-4311, to track costs
associated with the Witch, Guejito, and Rice wildfires.
The $379 million represents a portion of the total $2.4
billion in costs and legal fees incurred by SDG&E to
resolve third-party damage claims arising from the
Witch, Guejito and Rice Wildfires.2 When translated
into typical residential rates, the WEMA costs would
lead to an increase of $1.67 per month when amortized
over six years.
2. Procedural Background
The 2007 Wildfires were the subject of two prior
proceedings before the Commission. Investigation (I.)
08-11-0073 concluded with Decision (D.) 10-04-047,
which approved a settlement agreement between the
Commission’s CPSD and SDG&E. Pursuant to the
settlement agreement, SDG&E paid penalties ($14.75
million) but did not admit to any safety violation or
role in the cause of the 2007 wildfires.4 Subsequently,
SDG&E, alongside Southern California Gas Company
and Pacific Gas and Electric Company, filed A.09-08020 to seek authority to establish a Wildfire Expense
Balancing Account (WEBA) to record future recovery
2
A.15-09-010 at 1. Portions of the $2.4 billion were recovered
from liability insurance coverage ($1.1 billion) and settlement
payments from third parties (Cox Communications and three
contractors totaling $824 million). Other portions of the costs
were allocated to Federal Energy Regulatory Commission
jurisdictional rates. In addition, SDG&E proposes to voluntarily
contribute $42 million. (Id. at 7.)
3
Investigation on the Commission’s own Motion into the
Operations and Practices of SDG&E Regarding the Utility
Facilities linked to the Witch and Rice Fires in 2007.
4
D.10-04-047 at 5.
11a
costs associated with the 2007 Wildfires. D.12-12-029
ultimately denied the utilities’ request to open the
WEBA.5 D.12-12-029 additionally ordered the memorandum accounts (WEMA), authorized by Commission
Resolution E-4311, to remain open pending a reasonableness review6 in an appropriate proceeding.7 Following this order, SDG&E filed A.15-09-010 on
September 25, 2015.
Between October 23 and October 30, 2015, protests
were timely filed and served by San Diego Consumers’
Action Network (SDCAN), the Utility Consumers’
Action Network (UCAN), The Utility Reform Network,
Center for Accessible Technology (TURN/CforAT),
Protect Our Communities Foundation (POC), Office of
Ratepayer Advocates (ORA), and Mussey Grade Road
Alliance (MGRA). TURN/CforAT argued that the
proceeding should be phased, with the first phase
addressing whether SDG&E had prudently managed
its facilities and operations and the second phase
addressing the reasonableness of the and timing of the
5
Ordering Paragraph 1 of D.12-12-029.
6
There is usually a significant distinction between a balancing
account and a memorandum account as used by the Commission.
Both accounts are typically employed to ensure the accurate
recovery of the actual cost of a regulatory program. The goal is to
avoid the risk of over- or under-recovery in retail rates of
reasonably incurred program costs. Balancing accounts have an
associated expectation of recovery. They have been pre-authorized by the Commission, and it is the amounts -- and not the
creation of the accounts themselves -- that the Commission
reviews for reasonableness. Memorandum accounts, in contrast,
are accounts in which the utilities record amounts for tracking
purposes. While the utilities may later ask for recovery of the
amounts in those accounts, recovery is not guaranteed. See D.0306-013 at 4-5.
7
Ordering Paragraph 2 of D.12-12-029.
12a
amounts requested. Under this proposal, Phase 2
would only be reached if it was determined that
SDG&E had prudently managed its facilities. Ruth
Henricks (Henricks) filed and served a Motion for
Party Status on October 2, 2015 that was subsequently granted.
8
In its November 9, 2015 reply, SDG&E opposed
phasing A.15-09-010 and the protestors’ request to
incorporate the record from the prior proceedings
as part of the record for the instant proceeding.
Additionally, SDG&E stated that the reasonableness
standard should only be applied to: (1) its decision to
pursue the settlement of the claims stemming from the
2007 Wildfires litigation; (2) the process SDG&E
employed in settling the claims; and (3) its efforts in
reducing the costs.9
On February 19, 2016, a Joint Proposed Schedule
was served by MGRA, ORA, POC, Henricks, SDCAN,
TURN, and UCAN (collectively, the Joint Intervenors).
The Joint Proposed Schedule requested that A.15-09010 be litigated in phases as proposed by TURN/
CforAT, and that parties be provided with the opportunity to brief certain threshold legal and policy issues
in relation to the appropriateness of the rate recovery.
The assigned Administrative Law Judge (ALJ) convened a prehearing conference on February 22, 2016.
Subsequently the assigned Commissioner issued a
Scoping Memorandum and Ruling (Scoping Ruling) on
April 11, 2016.
The Scoping Ruling implemented a two-phase
approach for this proceeding with a separate reason8
TURN/CforAT Protest at 4.
9
SDG&E Reply at 3; Scoping Ruling at 3.
13a
ableness review for each phase. Phase 1 was to address
whether any threshold legal issues raised by the Joint
Intervenors should be a bar to the application and
prudent operation of the facilities. Specifically, Phase
1 was scoped as:
(1) Whether any of the Threshold Issues10
serves as a bar to recovery; and
(2) Whether SDG&E’s operation, engineering and management the facilities alleged
to have been involved in the ignition of
the fires was reasonable and prudent.
Each of the three fires should be
addressed separately.11
The Scoping Ruling stated that prior Commission
decisions indicate that a reasonableness standard
should entail a review of the prudency of SDG&E’s
actions leading up to the fire. The Scoping Ruling
specifically referenced D.14-06-007 in which the
Commission held that for costs to be found reasonable,
the utility must prove that they were:
prudently incurred by competent management exercising the best practices of the era,
and using well-trained, well-informed and
conscientious employees who are performing
their jobs properly . . . [T]he Commission can
10
The Threshold Issues are: Whether rate recovery would
create a moral hazards . . . the fairness of imposing rate increases
on San Diego customers, particularly those who were already
victims of the fires . . . , and whether SDG&E has already been
compensated for such risks in its rates and whether it warrants
special recovery outside of the normal general rate case
process . . . : (Scoping Ruling at 6 citing the Joint Intervenors
Joint Proposed Schedule).
11
Scoping Ruling at 6.
14a
and must disallow those costs: that is unjust
and unreasonable costs must not be recovered
in rates from ratepayers.12
The Scoping Ruling further stated that this standard is consistent with the Commission’s obligation
under Pub. Util. Code § 451 to ensure that resulting
rates will be just and reasonable and that service is
provided in a safe manner.
Opening briefs on Threshold Issues were filed by
SDG&E, ORA and UCAN on May 11, 2016. On May
26, 2016, Reply briefs were filed by SDG&E and
UCAN. The assigned ALJ reviewed the arguments
posed by the intervening parties to dismiss the
application on the basis of the Threshold Issues as a
motion for summary judgment. On August 11, 2016,
the assigned ALJ issued a ruling against the intervening parties and confirming the procedural schedule
set forth in the Scoping Ruling. The August 11, 2016
ruling allowed for the re-consideration of the arguments in the briefs after the development of an
evidentiary record.13
If the proceeding was not dismissed during the
first phase, the second of A.15-0-010 would have the
Commission consider whether SDG&E’s actions and
decision making in connection with settling of legal
claims and costs in relation to the wildfires were
reasonable.14
In October 2016, this proceeding was reassigned to
ALJ S. Pat Tsen and ALJ Pro Tem Sasha Goldberg.
12
Scoping Ruling at 6 citing D.14-06-007 at 31.
13
Ruling Confirming Procedural Schedule Following Briefs on
the Threshold Issues, August 11, 2016 at 4.
14
Id. at 5.
15a
Following this reassignment, ORA filed a motion for
change of venue, which was ultimately denied.15 In
accordance with the procedural schedule set by the
Scoping Ruling, the newly assigned ALJs and Commissioner scheduled and held two Public Participation
Hearings (PPHs) in Escondido, California, on January
9, 2017.16 Over 200 residents of San Diego County
attended the PPHs, as well as several local news
outlets.
Evidentiary Hearings for Phase 1 of this proceeding
were held at the Commission’s San Francisco hearing
rooms the week of January 23, 2017. In response to
requests from SDG&E and ORA, the assigned ALJs
issued a ruling on February 10, 2017 modifying the
post-hearing briefing schedule for Phase 1. In addition
to modifying due date(s) for briefs, this ruling directed
parties to obtain confirmation that the Cal Fire
investigative reports on the 2007 Wildfires were in fact
final and/or closed.17
On March 17, 2017, ORA served an affidavit from
the Unit Chief for Cal Fire’s MVU Unit affirming that
Cal Fire considers the investigative reports into the
2007 Wildfires final, with no plans to re-open or
supplement any of these investigations.18 Opening
briefs for Phase 1 were filed and served on March 24,
15
Administrative Law Judges’ Ruling Denying the Office of
Ratepayer Advocates’ Motion to Change Venue (December 21,
2016).
16
Administrative Law Judges’ Ruling
Participation Hearings (November 11, 2016).
Setting
Public
17
Ruling Administrative Law Judges’ Ruling Modifying Procedural Schedule and Requiring Supplemental Information at 4.
18
ORA Response regarding Cal Fire Affidavit (March 17,
2017).
16a
2017 by SDG&E, ORA, SDCAN, UCAN, POC, and
Henricks. Reply briefs were filed and served on
April 14, 2017 by SDG&E, ORA, MRGA, UCAN, and
SDCAN. The record for Phase 1 of this proceeding was
submitted19 for Commission consideration on July 6,
2017 after Henricks filed a motion to accept the late
filing of Henricks’ Opening Brief.
On August 22, 2017 a proposed decision (PD)
denying SDG&E’s recovery in this proceeding was
served on the service list to A.15-09-010. Opening
comments on the PD were filed on September 11, 2017,
along with motions by Pacific Gas and Electric
Company (PG&E) and Southern California Edison
Company (SCE) for party status. The filing of motions
by PG&E and SCE at this late juncture triggered
responses from the intervenors and ORA in this proceeding. After evaluating the motions and responses,
the assigned ALJs granted PG&E and SCE limited
party status20 on September 26, 2017. This limited
party status gave PG&E and SCE the opportunity to
comment on the legal issue of inverse condemnation.
PG&E and SCE filed joint comments on the issue of
inverse condemnation on October 4, 2017. SDG&E,
ORA, POC, UCAN and MGRA filed replies to the joint
comments on October 11, 2017.
In addition to the comment period for inverse
condemnation, on September 18, 2017, the assigned
ALJs noticed an All Party Meeting. The All Party
Meeting, held by Commissioner Liane Randolph, took
place in Chula Vista, California, immediately after the
19
20
Rules of Practice and Procedure, Rule 13.14(a).
See A.15-09-010 E-mail Ruling Granting Limited Party
Status to Southern California Edison Company; A.15-09-010 Email Ruling Granting Limited Party Status to PG&E.
17a
conclusion of the September 28, 2017 Commission
Meeting. The All Party meeting provided parties with
the opportunity to address the Commission. Participants in the All Party Meeting included SDG&E,
PG&E, SCE, ORA, MGRA, POC, SDCAN, Henricks,
and UCAN.
Due to the scheduling of the All Party Meeting,
and building in time for replies to PG&E and SCE’s
comments on inverse condemnation, the statutory
deadline for this proceeding was extended by D.17-09038 to April 11, 2018.
3. Legal Standards Applied
The appropriate standard in a ratesetting matter is
preponderance of the evidence.21 As the Applicant,
SDG&E bears the burden of proof. Preponderance of
the evidence usually is defined “in terms of probability
of truth, e.g., ‘such evidence, when weighed with that
opposed to it, has more convincing force and the
greater probability of truth’.”22 In short, SDG&E must
present more evidence that supports the requested
result than would support an alternative outcome.
The Commission’s standard for reasonableness
reviews, reaffirmed in a series of decisions, is as
follows:
The term reasonable and prudent means that
at a particular time any of the practices,
methods and acts engaged in by a utility
follows the exercise of reasonable judgment in
light of the facts known or which should have
been known at the time the decision was
made. The act or decision is expected by the
21
D.16-12-063 at 9, citing D.12-12-030 at 44.
22
D.12-12-030 at 42, aff’d D.15-07-044 at 28-30.
18a
utility to accomplish the desired result at the
lowest reasonable cost consistent with good
utility practices. Good utility practices are
based upon cost effectiveness, safety and
expedition.23
We have analyzed SDG&E’s management and
operation of its facilities prior to the ignition of the
Witch, Guejito and Rice Wildfires within the rubric
of the Commission’s prudent manager standard. In
comments to the proposed decision, SDG&E contends
that the Commission is imposing a perfection standard. That is not the case. Our decision today analyzes
the Witch, Guejito, and Rice fires separately, taking
into account extensive records submitted by the
parties, industry practice in 2007, and contemporaneous information available to SDG&E at the time
of the separate ignitions. Each analysis is fact specific
and has been reached after careful consideration of the
record. Contrary to SDG&E’s assertion, holding utilities
accountable under the reasonable and prudent manager standard in no way imposes a standard of
perfection. The Commission was prepared in this case,
as it will in the future, to find SDG&E’s conduct is
reasonable and prudent, if the facts warrant such a
conclusion.
4. Discussion and Analysis
In this section, the Commission analyzes the Witch,
Guejito, and Rice fires separately and determines
SDG&E’s prudency in managing its facilities. As the
Applicant seeking recovery, SDG&E must affirmatively satisfy the Commission that it acted prudently.
We weigh evidence presented by SDG&E that it acted
prudently, against evidence presented by the interve23
24 CPUC 2d 476, 486.
19a
nors that SDG&E did not act prudently. In each
analysis, we find SDG&E to have failed its burden of
proof to show by a preponderance of the evidence, that
it complied with the Commission’s prudent manager
standard.
4.1. Witch Fire
4.1.1. Witch Fire Background
The Witch Fire, which later merged with the Guejito
Fire, was the second largest fire to occur in San Diego
County in 2007.24 The SDG&E facility involved in the
ignition of the Witch Fire was Tie Line (TL) 637.25 TL
637 is a 69 kilovolt (kV) transmission line that connects the Santa Ysabel and Creelman substations.26
TL 637 is approximately 14 miles long and runs along
a remote backcountry section of San Diego County.27
Although there were no eyewitnesses to the ignition
of the fire, the Cal Fire investigator determined that a
fault on TL 637 between poles Z416675 and Z416676
on October 21, 2007 led to arcing of the lines, which
dispersed hot particles to land in the grassy field below
the powerlines.28 These particles were determined to
have ignited the Witch Fire which was then spread by
wind.29 There was a Red Flag Warning30 in place at
24
ORA-01 at 6.
25
SDGE-11-A at 2.
26
Id.
27
Id. at 3
28
Id. at 3; ORA-01 at 6 to 7.
29
SGDE-11-A at 3-4, citing Cal Fire Report (Witch) at 2, 14,
and 19.
30
ORA-01 at 45: The National Weather Service issues a Red
Flag Warning “to call attention to limited weather conditions of
particular importance that may result in extreme burning
20a
4:45 a.m., prior to the Witch Fire’s ignition on October
21, 2007.31
The following chart depicts a timeline of the events
occurring the day of the Witch Fire ignition:
Timeline of Events on October 21, 2007 on TL 63732
Time
8:53 a.m.
Description of Event
Fault 1 occurred on TL 637
The Transmission System Operator dispatched Electric Troubleshooters to either
9:05 a.m. and
end of TL 637(Santa Ysabel and Creelman
9:08 a.m.
substations) to gather additional information about the 8:53 a.m. fault
9:30 a.m.
SDG&E’s Grid Operations were responding to the Harris Fire which burned in
southern San Diego County near the
vicinity of SDG&E’s 500 kV transmission
line, the Southwest Powerlink
10:00 a.m.
Electric Troubleshooters reported back to
the Transmission System Operator at Grid
Operations
The Troubleshooters found that the protection devices at
each end of the line operated and opened the circuit
breakers, which remained opened for ten seconds, and then
conditions. It is issued when it is an on-going event or the fire
weather forecaster has a high degree of confidence that Red Flag
criteria will occur within 24 hours of issuance.” (Citing the
National Weather Service Glossary, Red Flag Warnings.)
31
32
ORA-02-A.
SDGE-11-A at 6-7, referencing Appendices 3 and 4
(Appendix 3 is the Operations Shift Supervisor Daily Log from
October 21, 2007), (Appendix 4 is the Electric Switching Order for
TL 637 on October 21, 2007).
21a
reclosed the line, because the faults had cleared within the
ten seconds The Troubleshooters learned that the faults
were temporary because they had cleared within 10
seconds, and so the flow of electricity was restored.33
11:22 a.m.
Fault 2 occurred on TL 637
11:42 a.m.
Cal Fire requests Grid Operations to deenergize the Southwest Powerlink to allow
air drops of fire retardant in the area.
12:01 p.m.
Electric Troubleshooters dispatched to the
Santa Ysabel and Creelman substations
12:15 p.m.
SDG&E’s Grid Operations opened the
Southwest Powerlink as a Forced Outage
12:19 p.m.
Electric Troubleshooter reported back to
Grid Operations from the Santa Ysabel
substation that the circuit breakers had
again operated and had reclosed.
12:23 p.m.
Fault 3 occurred on TL 637, while the
Troubleshooters were at the Santa Ysabel
and Creelman substations.
Under SDG&E’s Transmission Monitoring & Control
Procedure 1100, when a line faults and immediately
recloses and the cause for the trip is unknown, the line
should be patrolled by either a vehicle or aerially, via a
helicopter.
12:29 p.m.
Witch Fire observed by Air Tanker Pilot
(according to the Cal Fire Report)
12:33 p.m.
Patrolman was sent to patrol TL 637
12:39 p.m.
Patrolman informed the Grid Operations
Transmission System Operator that he
33
SDGE-11-A at 7.
22a
would go out to patrol TL 637 in person
rather than by air.
12:56 p.m.
Electric Troubleshooter reported back to
Grid Operations from the Creelman substation that the circuit breakers had again
operated and had reclosed.
1:10 p.m.
Grid Operations became aware of the
Witch Fire
1:14 p.m.
SDG&E’s Transmission Construction and
Maintenance Manager rerouted a Construction Supervisor to Santa Ysabel
1:59 p.m.
SDG&E’s Transmission Construction and
Maintenance Manager requested that Grid
Operations disable automatic reclosing on
TL 637
2:01 p.m.
Grid Operations Transmission System
Operator turned-off automatic reclosing at
the Santa Ysabel substation
2:05 p.m.
Grid Operations Transmission System
Operator requested a Troubleshooter be
dispatched to the Creelman substation to
turn-off automatic reclosing.
3:00 p.m.
An SDG&E Construction Supervisor with
SDG&E’s Transmission Construction and
Maintenance Manager met a Cal Fire crew
at the Santa Ysabel substation
3:25 p.m.
Fault 4 occurred on TL 637, automatically
reclosed at the Creelman substation
3:27 p.m.
TL 637 became de-energized by the Grid
Operations Transmission System Operator
23a
A series of four faults occurred on TL 637 on October
21, 2007: the first fault at 8:53 a.m.; the second fault
at 11:22 a.m.; the third fault at 12:23 p.m.; and the
fourth fault at 3:25 p.m.34 Cal Fire concluded that the
Witch Fire ignited after the third fault occurred on TL
637 at 12:23 p.m. on October 21, 2007 because an Air
Tanker Pilot first observed the fire at 12:29 p.m.35
SDG&E Grid Operations became aware of the Witch
Fire at 1:10 p.m., and de-energized TL 637 after the
fourth fault at 3:27 p.m.36
Ultimately, the Witch Fire led to the destruction of
1,141 homes, 509 outbuildings, and 239 vehicles.37
Once combined with the Guejito Fire, the Witch Fire
burned a total of 197,990 acres.38 The combination of
the Witch and Guejito Fires led to two fatalities and
injured 40 firefighters.39
4.1.2. SDG&E’s Position on its Operation
and Management of its Facilities
Prior to the Witch Fire
SDG&E maintains that its operation and management of its facilities linked to the Witch Fire prior to
October 21, 2007 were reasonable.40 SDG&E supports
its position by claiming: (1) SDG&E’s response to the
faults along TL 637 was reasonable given the information available at the time of the faults; (2) SDG&E’s
34
SDGE-11-A at 6 to7.
35
SDGE-11-A at 6 to 7.
36
SDGE-11-A at 6 to 7.
37
ORA-01 at 7, citing Cal Fire Report (Witch) at 2.
38
Id.
39
Id.
40
SDG&E Phase 1 Opening Brief at 30.
24a
recloser policy was reasonable and prudent; and
(3) the Witch Fire was not foreseeable.41
SDG&E’s Response to Faults along TL 637
SDG&E maintains that the facts surrounding the
Witch Fire do not show that SDG&E acted unreasonably or imprudently in its response to the four faults
occurring along TL 637 on October 21, 2007.42 SDG&E
does not dispute the fact that its facilities were directly
involved in the ignition of the Witch Fire, SDG&E put
forth Mr. Ali Yari (Mr. Yari), SDG&E’s Director of
Electric Grid Operations, to testify as to SDG&E’s
reasonable and prudent monitoring of the faults along
TL 637.43
First, SDG&E contends that its actions and
response to the faults occurring along TL 637 were
reasonable given the information it had available in
real time on October 21, 2007.44 Mr. Yari testified that
in 2007, SDG&E did not have the capability to
determine in real-time the exact location of the faults
occurring along the 14-mile stretch of TL 637.45
SDG&E maintains that the relay equipment at the
substation stores voltage and current information, and
not specific fault locations.46 Mr. Yari testified that it
would have taken at least one hour to get the
protection engineer in a position to dial into the relay,
plus about 30 additional minutes to download and
41
SDG&E Phase 1 Reply Brief at 30 to 31.
42
SDG&E Phase 1 Reply Brief at 37.
43
SDGE-11-A at 1.
44
SDG&E Phase 1 Reply Brief at 37.
45
Id.
46
Id. at 41.
25a
process the information. SDG&E asserts that this
need for engineering intervention to analyze the
data stored in the relay showed that SDG&E acted
prudently in responding to the faults on TL 637.48
SDG&E contends its response to the faults along TL
637 was reasonable because its interpretation of the
data stored in the relay along TL 637 was both analytical and appropriate, given the standards in 2007.49
47
Second, SDG&E maintains its Grid Operations’
response time to inspect TL 637 was reasonable given
the threat to the Southwest Powerlink on October 21,
2007.50 In his direct testimony, Mr. Yari explains how
the threat of the Harris Fire to the Southwest
Powerlink impacted SDG&E’s monitoring of TL 637.
Mr. Yari notes, the threat to the Southwest Powerlink
“was a major event consuming SDG&E resources –
including the attention of Grid Operations personnel
and the resources available to conduct patrols. . . .
SDG&E was particularly concerned about the outage
of this major transmission line since it was essential
to grid stability across Southern California. . . .
SDG&E was also taking seriously the faults on TL 637
but there was no indication of any kind of emergency
. . . since faults are not particularly unusual on a windy
day . . .”51 SDG&E maintains that even though its
Grid Operations de-energized the Southwest Powerlink at 12:15 p.m., Grid Operations was appropriately
monitoring the faults along TL 637.52 SDG&E argues
47
SDG&E Phase 1 Reply Brief at 43.
48
Id. at 42.
49
Id.
50
Id. at 37, SDGE-11-A at 1-13.
51
SDGE-11-A at 9.
52
Id.
26a
that its dispatch of troubleshooters to investigate
the faults on TL 637 was all that was required to be
reasonable.53
Third, SDG&E argues that, because it had not
previously experienced fires related to transmission
lines coming into contact with one another, SDG&E’s
level of concern about the faults along TL 637 was
appropriate.54 Through Mr. Yari, SDG&E stressed
that conductor-to-conductor activity is “relatively rare”
and on windy days a fault is not unusual given the
potential for debris to come into contact with a
conductor.55 Because of this “relatively rare” activity,
SDG&E asserts it was reasonable not to suspect that
hot particles were being emitted from the activity
along TL 637.56
As such, SDG&E maintains that its monitoring of
the faults on TL 637 was reasonable and prudent.
53
SDG&E Phase 1 Reply Brief at 37 to 38.
54
SDG&E Phase 1 Reply Brief at 38, citing SDGE-11-A at
15-16.
55
Id. and SDGE-11-A at 8.
56
SDGE-11-A 8 to 9.
27a
SDG&E’s Recloser Policy
SDG&E asserts its recloser policy57 in effect on
October 21, 2007 as both reasonable and prudent.58
SDG&E maintains ORA fails to show how SDG&E’s
awareness of the 2001 Power Line Fire Prevention
Field Guide (2001 Field Guide) put SDG&E on notice
of the risks of its recloser policy prior to October 2007.
SDG&E notes the 2001 Field Guides’ excerpt, “automatic reclosers re-energizing the line into the fault
may cause repeated arcing and increase the probability of igniting vegetation,” does not show SDG&E’s
imprudence in utilizing its recloser policy in response
to the faults along TL 637.59 SDG&E asserts that even
if it were possible to turn off TL 637’s automatic
reclosers after the second fault, such an action would
57
SDG&E Recloser Policy: Similar to all electric utilities across
the country, SDG&E uses protection devices on all of its transmission lines to ensure that the electric system detects and
responds to fault activity and isolates the faulted line. Those
protection devices measure currents and voltages and detect any
abnormal system conditions or faults, on the associated lines. If
a transmission system line faults, the protective relays operate to
open the circuit breakers (de-energizing the line), and the circuit
breakers remain open for ten seconds before the reclosers attempt
to reclose them. If the circuit breakers do not reclose successfully,
which would indicate that the fault has not cleared after 10
seconds, the recloser “locks out” and prevents further automatic
reclose attempts. If the circuit breakers reclose successfully, the
circuit is restored. As an additional protection, even if the circuit
breakers reclose successfully after 10 seconds, the recloser will
lockout if the lines faults again within 120 second of the initial
fault. If no additional faults occur within that 120-second period,
the recloser resets. ORA-18 at 2, citing Geier Testimony Excerpts
(I.08-11-006).
58
SDG&E Phase 1 Reply Brief at 49.
59
SDG&E Phase 1 Reply Brief at 49 to 50.
28a
not have avoided the Witch Fire’s ignition.60 Moreover,
Mr. Yari testified that disabling automatic reclosers
after the second fault would have been imprudent
“given the important of keeping [TL 637] in service to
serve the backcountry during a very windy day” and
that the recloser policy was industry practice.61
Foreseeability of Witch Fire
SDG&E maintains that the facts surrounding the
Witch Fire do not show that SDG&E acted unreasonably or imprudently based on what SDG&E knew at
the time.62 More specifically, SDG&E argues that
Henricks, MGRA, UCAN and POC fail to show how
the Witch Fire was foreseeable.63
First, SDG&E put forth Mr. David Geier (Mr. Geier)
to testify as to SDG&E’s fire preparedness in 2007.64
Mr. Geier, SDG&E’s Vice President of Electric Transmission and System Engineering, discussed the
2003 Wildfires65 in his direct testimony and the steps
SDG&E took in the aftermath of the 2003 Wildfires to
reduce the risk of wildfires in its service territory.66
Mr. Geier explained how post-2003 SDG&E focused on
improving the integrity and reliability of the utility’s
60
SDG&E Phase 1 Reply Brief at 50.
61
SDG&E Phase 1 Reply Brief at 51, citing Reporter’s Transcript Volume 3 at 384.
62
SDG&E Phase 1 Reply Brief at 30 to 31.
63
SDG&E Phase 1 Reply Brief at 30.
64
SDG&E Phase 1 Reply Brief at 31.
65
SDGE-05 at 15, 2003 Wildfires: In San Diego County alone,
the 2003 Wildfires burned over 400,000 acres, destroyed more
than 2,400 homes, and caused extensive damage to SDG&E
facilities.
66
SDG&E Phase 1 Reply Brief at 31.
29a
transmission and distribution systems, especially in
the areas subject to the extreme Santa Ana winds.67
Through Mr. Geier, SDG&E showed that it created a
full-time fire coordinator position to provide training
to its employees on fire risk, in addition to creating a
database to track fire causes and patterns.68 Despite
the newly created fire coordinator position and database, SDG&E maintains that there was no information available that could have been used to predict
the Witch Fire ignition.69
Second, SDG&E maintains that there has not been
a credible showing that there has ever been a comparable event to the 2007 Wildfires.70 SDG&E contends
that while the 2003 Wildfires were significant, the
2007 Wildfires happened under different circumstances.71 Specifically, SDG&E contends that the 2007
Wildfires involved over a dozen major fires igniting
over a short period of time, including ignitions
to powerlines, which was not the case in 2003.72
Accordingly, SDG&E maintains there was no way to
have foreseen what occurred in October 2007 based on
historical data.73
Third, SDG&E contends that the Witch Fire was not
foreseeable because SDG&E designed, engineered,
maintained and inspected TL 637 in compliance with
67
SDGE-05 at 16.
68
SDGE-05 at 16.
69
SDG&E Phase 1 Reply Brief at 32 citing SDGE-12 at 25.
70
SDG&E Phase 1 Reply Brief at 32.
71
SDG&E Phase 1 Reply Brief at 32.
72
SDG&E Phase 1 Reply Brief at 32.
73
SDG&E Phase 1 Reply Brief at 33.
30a
the Commission’s industry standards.74 General Order
(GO) 95 requires that all infrastructure be designed,
constructed, rebuilt and maintained to account for
known local conditions.75 And while MGRA and other
intervenors have raised SDG&E’s compliance with GO
95 in regards to the foreseeability of the Witch Fire,
SDG&E maintains those arguments fail to discredit
SDG&E’s showings of compliance and prudence.76
Specifically, SDG&E asserts MGRA fails to show how
rebuilding TL 637 to a higher wind loading standard
would have prevented the Witch Fire.77
As such, SDG&E maintains that its operation and
management of TL 637 was reasonable.
4.1.3 ORA’s Position on SDG&E’s Operation and Management of its Facilities
Prior to the Witch Fire
ORA maintains that SDG&E has not shown by a
preponderance of the evidence that SDG&E’s operation and management of its facilities prior to the
ignition of the Witch Fire were reasonable.78 ORA
argues that SDG&E’s response to the faults occurring
on TL 637 was unreasonable.79 Within this argument,
ORA contends: (1) the timing of SDG&E’s response to
the faults along TL 637 was not appropriate; and
(2) SDG&E did not effectively use fault location information available at the relays in response to the
74
SDG&E Phase 1 Reply Brief at 33.
75
MGRA Phase 1 Reply Brief at 8.
76
SDG&E Phase 1 Reply Brief at 33.
77
SDG&E Phase 1 Reply Brief at 33.
78
ORA Phase 1 Reply Brief at 13.
79
Id.
31a
faults. ORA additionally argues that SDG&E’s
recloser policy in effect on October 21, 2007 imprudently increased fire risk.81
80
SDG&E’s Response to Faults along TL 637
ORA contends that SDG&E has not shown it acted
prudently in connection to the ignition of the Witch
Fire.82 ORA maintains SDG&E’s failure to use fault
location information effectively demonstrates that the
utility failed to act reasonably regarding the faults
along TL 637.83
First, ORA maintains that SDG&E should have
responded sooner to investigate the faults occurring on
TL 637 on the morning of October 21, 2007.84 ORA
points to SDG&E’s dispatch of troubleshooters in
support of this argument: “the dispatch time for the
second trip was almost four times as long as for the
first trip that occurred less than three hours before.
Multiple line trips of TL 637 in a single day should
have been a concern to the utility, especially since this
was a rare event that had occurred only 9 times in
the previous 24 years.”85 ORA argues that SDG&E’s
response time was slow, noting that over 6 hours
passed from the time of the initial fault on TL 637 to
its de-energization.86 ORA argues that SDG&E should
have had the resources in place to communicate the
need for patrol; and that SDG&E’s failure to have
80
Id.
81
ORA Phase 1 Reply Brief at 28.
82
ORA Phase 1 Reply Brief at 13.
83
ORA Phase 1 Reply Brief at 13.
84
ORA Phase 1 Opening Brief at 10.
85
Id. citing ORA-03 at 1-3 (TL 637 Fault History).
86
ORA Phase 1 Opening Brief at 11.
32a
resources available constituted imprudent management.87 ORA maintains that this imprudent management lead to the ignition and spread of the Witch
Fire.88
Second, ORA maintains that SDG&E did not effectively use the fault location information it had
available to respond to the faults along TL 637.89 ORA
contends that SDG&E could have obtained the
location of faults in time to be in a better position to
respond to the faults on TL 637.90 Specifically, ORA
refers to the following fault time and location information obtained through discovery to rebut SDG&E’s
argument that it could not analyze the data stored in
the relay without engineering intervention.91
Fault Time
Fault Location
8:53 a.m.
2.73 miles / 2.74 miles
11:22 a.m.
2.73 miles / 2.75 miles
12:23 p.m.
2.79 miles /2.76 miles
3:25 p.m.
2.82 miles / 2.84 miles
ORA notes that SDG&E did not retrieve the above
mileage data until October 22, 2007, a day after the
ignition of the Witch Fire.92 Additionally, ORA highlights the testimony of Mr. Yari, that had SDG&E
looked at the mileage data, it would have been in a
87
ORA Phase 1 Opening Brief at 12.
88
ORA Phase 1 Opening Brief at 34.
89
ORA Phase 1 Reply Brief at 13.
90
Id. at 17.
91
ORA Phase 1 Opening Brief at 13.
92
ORA Phase 1 Opening Brief at 13 to 16, referencing ORA-19.
33a
better position to respond to the faults.93 In sum, ORA
asserts it was imprudent of SDG&E to not effectively
use data that was available at the relays in responding
to the faults. Moreover, ORA contends that had
SDG&E used the fault location data on October 21,
2007, rather than the day after ignition, it would have
assisted SDG&E in having a quicker response time.94
SDG&E’s Recloser Policy
ORA maintains SDG&E’s recloser policy in effect
during the faults along TL 637 imprudently increased
fire risk.95 Under cross-examination by ORA, Mr. Geier
acknowledged and essentially agreed with the 2001
Field Guide’s assertion, “Automatic reclosers reenergizing the line into the fault may cause repeated
arcing and increase the probability of igniting vegetation.”96 ORA contends this assertion put SDG&E on
notice of the risks posed by automatic reclosers to
ignite vegetation, as early as 2001.97 ORA asserts that
these risks and the fact that there was a Red Flag
Warning in place on October 21, 2007, and that there
were an unusual number of trips shows that SDG&E
was imprudent when it did not anticipate that its
facilities posed a fire risk on October 21, 2007.98
As such, ORA maintains the record established
SDG&E did not act prudently on October 21, 2007.
93
ORA Phase 1 Reply Brief at 17, citing Reporter’s Transcript
Volume 3 at 349.
94
ORA Phase 1 Opening Brief at 17.
95
ORA Phase 1 Opening Brief at 28.
96
Hearing Reporter’s Transcript Volume 2 at 197; ORA Phase
1 Opening Brief at 29, citing ORA-20.
97
ORA Phase 1 Opening Brief at 32.
98
ORA Phase 1 Reply Brief at 15.
34a
4.1.4. Intervenors’ Position on SDG&E’s
Operation and Management of its
Facilities Prior to the Witch Fire
Many of the intervenors to this proceeding contend
that SDG&E fails to prove by a preponderance of the
evidence that SDG&E’s operation and management of
its facilities prior to the ignition of the Witch Fire
were reasonable.99 Henricks, MGRA, UCAN and POC
assert that the fact that SDG&E had prior experience
with catastrophic fires, renders SDG&E imprudent
when SDG&E failed to adequately address the faults
on TL 637.100
Foreseeability of Witch Fire
Henricks, MGRA, UCAN and POC maintain that
the facts show SDG&E did not operate its facilities
reasonably prior to the ignition of the Witch Fire.101
Henricks asserts that SDG&E was familiar with the
2003 Wildfires, and thus was on notice that a fire could
spread to the extent to which the Witch Fire spread.102
Henricks highlights the testimony of SDG&E’s witness Lee Schavrien (Mr. Schavrien) to show that
SDG&E had knowledge of the catastrophic events
linked to 2003 Wildfires.103 Henricks maintains that
SDG&E’s knowledge of the 400,000 acres burned, 16
lives lost, and 2400 homes destroyed by the 2003
Wildfires put SDG&E on notice that such an event
99
Henricks Phase 1 Opening Brief at 5.
100
Henricks Phase 1 Opening Brief at 4; MGRA Phase 1 Reply
Brief at 13 to 15.
101
See generally Henricks Phase 1 Opening Brief.
102
Henricks Phase 1 Opening Brief at 4.
103
Henricks Phase 1 Opening Brief at 4, referencing Reporter’s
Transcript Volume 2 at 264 to 271.
35a
could occur again.
As such, Henricks maintains
SDG&E did not act reasonably because the 2007
Wildfires were foreseeable.105
104
MRGA argues that SDG&E fails to show it acted
reasonably in its operation and management of TL
637.106 MGRA contends that SDG&E fails to establish
it had no reason to suspect the faults occurring along
TL 637 were the result of unusual conductor to conductor contact.107 More specifically, MGRA contends that
had SDG&E applied SDG&E’s prior knowledge of load
standards and the Santa Ana wind conditions differently, the Witch Fire could have been prevented, or at
the very least foreseen.108
UCAN and POC maintain that SDG&E failed to act
reasonably prior to the Witch Fire’s ignition because
fires were foreseeable given the history in SDG&E’s
service territory.109 Although UCAN’s arguments as to
wind and weather conditions are addressed in more
detail in Section 4.4 of this decision (Wind and Weather
Conditions in October 2007), UCAN’s assertions touch
on how SDG&E failed to act reasonably in regards to
the Witch Fire.110 UCAN contends that the Santa Ana
wind conditions were a foreseeable, known local condition and SDG&E should have been prepared for the
104
Henricks Phase 1 Opening Brief at 5, referencing Reporter’s
Transcript Volume 2 at 264 to 271.
105
Henricks Phase 1 Opening Brief at 5.
106
MGRA Phase 1 Reply Brief at 13.
107
MGRA Phase 1 Reply Brief at 15 to 16.
108
MGRA Phase 1 Reply Brief at 16.
109
UCAN Phase 1 Opening Brief at 3; POC Phase 1 Opening
Brief at 3.
110
UCAN Phase 1 Opening Brief at 3.
36a
possibility that its electrical equipment might spark
wildfires during a Santa Ana windstorm.111 And although
UCAN does not dispute the fact that SDG&E’s
facilities were not linked to the 2003 Wildfires, UCAN
does contend that the events surrounding the 2003
Wildfires put SDG&E on notice of the fire potential
years prior to the ignition of the 2007 Wildfires.112 As
such, UCAN maintains that SDG&E cannot prove by
a preponderance of the evidence that its management
and operation of its facilities prior to the ignition of the
Witch Fire were reasonable.113
4.1.5. Reasonableness Review: SDG&E’s
Operation and Management of its
Facilities Prior to the Witch Fire
In evaluating SDG&E’s operation and management
of its facilities in connection with the Witch Fire,
the Commission must determine whether SDG&E
employed reasonable judgement in its operation and
management of its facilities in the period leading up to
the ignition of the Witch Fire.
SDG&E’s response to the faults along TL 637 was
unreasonable when viewed in light of the record of
this proceeding. The threat of the Harris Fire to
the Southwest Powerlink, does not excuse SDG&E’s
failure to monitor the faults on TL 637. The fact that
there are other wind related wildfires in the area
should put a prudent manager on notice to anticipate
wind related events to its facilities. Also, in the 24 year
history of FL 637, there were only nine days with
multiple faults. While compliance with industry
111
UCAN Phase 1 Opening Brief at 3.
112
UCAN Phase 1 Opening Brief at 3.
113
UCAN Phase 1 Reply Brief at 5.
37a
practice is relevant to our reasonableness review,
SDG&E must also show it acted reasonably in light of
the circumstances at the time. The Red Flag Warning
indicating high wind conditions, other fires in the
vicinity, the request by Cal Fire to de-energize another
transmission line, and three faults over a period of 3.5
hours, all alerted SDG&E to the potential for fires and
should have caused SDG&E to act more proactively on
October 21, 2007.114 Mr. Yari testified it would take 1.5
hours for a protective engineer and computer to
calculate the exact location of the fault(s) on TL 637.
Had SDG&E de-energized TL 637 or sent a protective
engineer out to either end of TL 637 before the third
fault occurred, it may have prevented the third fault
from igniting the Witch Fire at 12:23 p.m. Moreover,
it would have been more reasonable for SDG&E to
send a protective engineer to calculate the fault
mileage information on the date the faults occurred
and the fire ignited.
While SDG&E’s recloser policy was industry practice, it knew as early as 2001 that automatic reclosers
energizing into the fault may cause arcing and
increase fire risk. SDG&E fails to show how it was
reasonable for its Grid Operations to take 6.5 hours to
de-energize TL 637 after the initial 8:53 a.m. fault.
This 6.5 hour lapse does not show that SDG&E was
engaged in reasonable utility practice. It would have
been more reasonable to force an outage before the
Witch Fire ignited at 12:23 p.m. However, the fact that
SDG&E did not de-energize TL 637 until 3:27 p.m.,
does not show how SDG&E acted reasonably in its
decision to not de-energize the line immediately at
1:10 p.m. Even though SDG&E management was
114
ORA-01 at 10:13-15; ORA-03 at 1-3.
38a
aware of the 2001 Field Guide’s assertion that automatic reclosers increase the risk to ignite vegetation,
SDG&E still failed to take more proactive steps to
prevent the Witch Fire’s ignition.
There were multiple events happening on October
21, 2007 which show SDG&E was unreasonable not to
foresee the Witch Fire or to assert now that that it was
not foreseeable. The Red Flag Warning in effect on
October 21 2007 coupled with the 9:30 a.m. ignition of
the Harris Fire put SDG&E on notice that wind and
weather could cause the ignition of another fire in its
territory on October 21, 2007. The four faults on a line
that did not have a history of faults combined with
SDG&E’s knowledge of the destruction caused by the
2003 Wildfires, including the Cedar Fire, contradicts
the argument that the Witch Fire was unforeseeable.
As such, SDG&E fails to prove by a preponderance
of the evidence that it acted prudently in its operation
and management of its facilities linked to the ignition
of the Witch Fire.
4.2. Guejito Fire
4.2.1. Guejito Fire Background
The Guejito Fire was first reported by Cal Fire at
01:00 on October 22, 2007 near the City of Escondido,
in San Diego County.115 The SDG&E facility involved
in the ignition of the Guejito Fire was a 12 kV overhead conductor. CPSD and Cal Fire attributed the
ignition of the Guejito Fire to a Cox Communications
(Cox) lashing wire coming into contact with an
SDG&E 12 kV overhead conductor, between SDG&E
115
ORA-01 at 17.
39a
poles P196387 and P196394.116 The SDG&E conductors were located above the Cox lines.117
GO 95, within the California State Rules for
Overhead Electric Line Construction, sets the basic
minimum allowable clearance of wires from other
wires at crossings.118 Rule 38 of GO 95 specifies a
minimum clearance of 6 feet with a maximum reduction of ten percent under wind conditions.119 On
November 2, 2007 an SDG&E engineering contractor,
Nolte Associates, Inc. performed an engineering survey
on the facilities linked to the Guejito Fire’s ignition.120
The Nolte Survey documented a 3.3-foot clearance
between the SDG&E conductors and Cox lines prior to
any repair work being completed after the ignition of
the Guejito Fire.121
The Cox facilities involved in the Guejito Fire were
installed in August of 2001.122 SDG&E purports that it
is not known when the 3.3-foot clearance violation
occurred, as there were no pre-fire surveys completed
on the facilities in question.123 At hearings however,
SDG&E presented Mr. Greg Walters, a former manager of SDG&E’s Compliance Management Group and
Joint Facilities Department, to testify that it was his
belief that the Cox facilities involved in the Guejito
116
ORA Phase 1 Opening Brief at 34, citing ORA-05 at 926.
117
ORA Phase 1 Opening Brief at 34, citing ORA-50.
118
General Order 95 at Table 2.
119
Id.
120
Id.
121
Id. at 18-19.
122
ORA Phase 1 Reply Brief at 18.
123
SDG&E Phase 1 Reply Brief at 59.
40a
Fire were not in compliance with GO 95, Rule 38,
Table 2 at the time of installation.124
In its opening brief, ORA notes that CPSD found
SDG&E to be in violation of the following statutory
provisions at the time it conducted its post-fire survey
of the SDG&E facilities involved in the Guejito Fire:
• Public Utilities Code Section 451 (“Failing to
detect/repair a broken lashing wire and/or
failing to maintain required clearances.”);
• GO 95, Rule 31.1 (“Failing to detect/repair a
broken lashing wire and/or failing to maintain
required clearances, in consideration of the
given local conditions such as the well-known
Santa Ana winds.”); and
• GO 95, Rule 38 (“As supported by the Nolte
Survey, the clearances between Cox’s and
SDG&E’s facilities were noncompliant before/
during and after the Guejito [F]ire ignition,
which occurred during conditions that did not
justify the noncompliance.”)125
SDG&E’s expert, Mr. Darren Weim (Mr. Weim),
testified that detailed inspections prior to the Guejito
Fire were conducted on June 22, 2007 (for Pole
P196394) and April 8, 2005 (for Pole P196394).126 Mr.
Weim noted, “[o]ther than missing or damaged high
voltage or warning signs (which were repaired), no
[other] conditions were noted in these inspections.”127
124
A.15-09-010 at 15; Reporter’s Transcript Volume 5 at 793.
125
ORA Phase 1 Opening Brief at 25; citing ORA-05 at
1238:3-4.
126
SDGE-06 at 11.
127
SDGE-06 at 11.
41a
As referenced above, the Guejito Fire, which later
combined with the Witch Fire, burned a total of 197,990
acres before being contained.128 Once combined, the
Guejito and Witch Fires led to two fatalities and 40
injured firefighters.129
4.2.2. SDG&E’s Position on its Operation
and Management of its Facilities
Prior to the Guejito Fire
SDG&E does not dispute that GO 95 required a 6foot clearance; however, SDG&E maintains that its
operation and management of its facilities involved
in the Guejito Fire prior to October 22, 2007 were
reasonable.130 SDG&E argues that it appropriately
inspected the facilities linked to the ignition Guejito
Fire.131 Furthermore, SDG&E contends ORA fails to
show how a compliant clearance between the Cox line
and the SDG&E overhead conductors could have
prevented the ignition of the Guejito Fire.132
GO 95 Clearance Requirements and SDG&E’s
Inspections
At hearings, SDG&E presented Mr. Darren Weim
(Mr. Weim), SDG&E’s Manager of Northeast Construction & Operations, to discuss the utility’s design,
construction, and maintenance standards that were in
place prior to 2007.133 While SDG&E does not dispute
GO 95’s 6-foot clearance requirement, Mr. Weim’s
128
ORA-01 at 7.
129
ORA-01 at 18.
130
SDG&E Phase 1 Reply Brief at 59-60.
131
Id.
132
SDG&E Phase 1 Reply Brief at 3.
133
A.15-09-010 at 15.
42a
testimony was used to show the programmatic approach
SDG&E takes in its inspection and maintenance of its
facilities.134 Mr. Weim testified regarding SDG&E’s
Corrective Maintenance Program. He elaborated on
two of the inspections carried-out under SDG&E’s
Corrective Maintenance Program.135 A “patrol inspection” involves visual inspections, designed to identify
obvious structural problems and hazards.136 A
“detailed inspection” requires trained employees to
perform thorough checks on distribution poles and all
attachment facilities to identify GO 95 clearance
violations.137 Mr. Weim noted that the most recent
patrol inspection was completed on August 30, 2007,
with no hazards identified.138 The most recent detailed
overhead inspections were conducted on June 22, 2007
and April 8, 2005, but did not uncover design or
construction issues with respect to poles P196387 and
P196394.139
SDG&E maintains that “if the 3.3 foot clearance
pre-dated SDG&E’s inspections, and those inspections
did not uncover the problem, those facts merely show
that SDG&E was not perfect.”140 SDG&E maintains
that the Commission’s prudence standard “is not a
‘perfection’ standard: it is a standard of care that
demonstrates all actions were well planned, properly
134
SDG&E Phase 1 Reply Brief at 60.
135
SDGE-06 at 4.
136
SDGE-06 at 4 to 5.
137
SDGE-06 at 5.
138
SDGE-06 at 10.
139
SDGE-06 at 11.
140
SDG&E Phase 1 Reply Brief at 60.
43a
supervised and all necessary records retained.”141
Furthermore, SDG&E maintains that ORA failed to
show that the 3.3-foot clearance contributed to the
Guejito Fire’s ignition.142
As such, SDG&E maintains that its management
and control of its facilities prior to the ignition of the
Guejito Fire were reasonable.
4.2.3. ORA’s Position on SDG&E’s Operation and Management of its Facilities
Prior to the Guejito Fire
ORA maintains that SDG&E has failed to prove by
a preponderance of the evidence that SDG&E’s operation and management of its facilities linked to the
Guejito Fire were reasonable.143 ORA cites to the facts
surrounding the ignition of the Guejito Fire as well as
the applicable clearance requirements per GO 95.
GO 95 Clearance Requirements and SDG&E’s
Inspections
ORA argues that SDG&E’s failure to comply with
GO 95 renders the utility’s operation and management
of its facilities imprudent.144 ORA contends that the
lack of records documenting when the 3.3-foot clearance violation occurred does not mean that SDG&E
met the prudent manager standard.145 ORA maintains
that the fact that Mr. Walters testified, under oath,
that the clearance violation occurred at the time of the
2001 Cox line installation is evidence of imprudent
141
Id. citing D.14-06-007 at 36.
142
SDG&E Phase 1 Reply Brief at 63.
143
ORA Phase 1 Reply Brief at 18.
144
Id.
145
Id.
44a
utility management.
Additionally, ORA contends
that the longstanding clearance violation was a safety
risk, rendering SDG&E imprudent.147 Bolstering this
argument, ORA highlights the specific statutory violations CPSD found during its post-fire investigation
of the facilities linked to the Guejito Fire.148 ORA
contends that CPSD’s finding that SDG&E failed to
maintain its facilities in compliance with Public
Utilities Code § 451, GO 95 Rule 31.1, and GO 95 Rule
38 , shows SDG&E was imprudent in managing its
facilities linked to the Guejito Fire.149
146
As such, ORA maintains that SDG&E’s operation
and management of its facilities prior to the ignition
of the Guejito Fire were not reasonable.150
4.2.4. Reasonableness Review: SDG&E’s
Operation and Management of its
Facilities Prior to the Guejito Fire
In evaluating SDG&E’s operation and management
of its facilities in connection to the Guejito Fire, the
Commission must determine whether SDG&E employed
reasonable judgment in its operation and management of its facilities in the period leading up to the
ignition of the Guejito Fire.
The record shows that SDG&E utilized its Corrective
Maintenance Program to perform patrol and detailed
(overhead) inspections of P196387 and P196394 prior
to the Guejito Fire ignition. SDG&E asserts its failure
to identify the 3.3-foot clearance violation merely
146
Id. citing Reporter’s Transcript Volume 5 at 792.
147
Id. at 24.
148
ORA Phase 1 Opening Brief at 24.
149
ORA Phase 1 Opening Brief at 24.
150
ORA Phase 1 Reply Brief at 30.
45a
shows the utility was not perfect; we disagree. SDG&E’s
use of patrol and overhead inspection protocols may be
reasonable. The repeated failure of these patrols to
identify the clearance violation is not reasonable.
While SDG&E’s testimony highlights its Corrective
Maintenance Program, the existence of the Corrective
Maintenance Program is not sufficient to establish
that SDG&E fulfilled its duty to be a reasonable and
prudent manager. At the same time, the lack of
inspection records indicates a failure to act prudently.
The fact that the Cox line was installed in 2001, six
years before the fire, and that no inspection records
affirmatively reference compliance with GO 95 clearance requirements is problematic. Moreover, we find
the six-year gap in inspection records (from 2001 to
2007) to be indicative of imprudent management.
SDG&E asserts that to find its failure imprudent
would be to interpret the prudence standard as a
perfection standard. We disagree. Documentation of
compliance with objective clearance standards at some
point during the many years the Cox line was installed
is not equivalent to perfection.
As such, SDG&E fails to prove by a preponderance
of the evidence that it acted prudently in its operation
and management of its facilities prior to the ignition
of the Guejito Fire.
4.3. Rice Fire
4.3.1. Rice Fire Background
The Rice Fire ignited on October 22, 2007 in
Fallbrook, California.151 The Cal Fire Investigation
Report into the Rice Fire concluded that the cause of
151
SDGE-08 at 2.
46a
the fire was a downed powerline.152 CPSD determined
that a limb from sycamore Tree FF1090 (FF1090)
broke and fell onto SDG&E 12 kV overhead conductors
on October 22, 2007, which in turn caused the conductors to break and fall to the ground.153
In comments to the proposed decision, SDG&E
alleges that the weight of the evidence shows it could
not have prevented the Rice Fire, because it had no
way to know of a defect in the broken tree branch that
fell onto the conductors. SDG&E reiterates its claim
that the broken branch was not marked for trimming
and would not have been removed.154 We revise our
discussion below to address these comments with
further support from the evidentiary record of this
proceeding. The Commission finds that SDG&E failed
to trim FF1090 on a timely basis and failed to keep
adequate records for FF1090. SDG&E failed to show
that it was prudent in its management of FF1090, or
that it could not have identified the defective branch
with proper management. We find the evidence
inconclusive as to the growth direction and the growth
pattern of the broken branch.
4.3.2. Legal Requirements
The Commission’s GO 95, Rule 35 sets the general
clearance requirements for vegetation around powerlines.155 Rule 35 requires that where dead, rotten or
diseased trees or dead, rotten, or diseased portions of
otherwise healthy trees overhang or lean toward
power conductors, those trees or portions are to be
152
ORA-01 at 22.
153
SDGE-08 at 2.
154
See SDG&E’s Comment
155
SDGE-08 at 2.
47a
removed. In 2007, GO 95 required a radial clearance
of 18 inches, and Public Resources Code Section
4293156 required a radial clearance of 4 feet, between
vegetation and 12 kV conductors.157 To comply with
both Commission rules and State law, SDG&E designed
and implemented its Vegetation and Management
Program (VMP ) and Tree Pre-inspection procedures.158 In this decision, we review the VMP that was
in place on October 22, 2007. SDG&E’s VMP manual
describes SDG&E’s Tree Pre-inspection procedures in
156
Public Resources Code § 4293: Except as otherwise provided
in Sections 4294 to 4296, inclusive, any person that owns, controls, operates, or maintains any electrical transmission or
distribution line upon any mountainous land, or in forest-covered
land, brush-covered land, or grass-covered land shall, during
such times and in such areas as are determined to be necessary
by the director or the agency which has primary responsibility for
the fire protection of such areas, maintain a clearance of the
respective distances which are specified in this section in all
directions between all vegetation and all conductors which are
carrying electric current: (a) For any line which is operating at
2,400 or more volts, but less than 72,000 volts, four feet; (b) For
any line which is operating at 72,000 or more volts, but less than
110,000 volts, six feet; (c) For any line which is operating at
110,000 or more volts, 10 feet. In every case, such distance
shall be sufficiently great to furnish the required clearance at
any position of the wire, or conductor when the adjacent air
temperature is 120 degrees Fahrenheit, or less. Dead trees, old
decadent or rotten trees, trees weakened by decay or disease and
trees or portions thereof that are leaning toward the line which
may contact the line from the side or may fall on the line shall be
felled, cut, or trimmed so as to remove such hazard. The director
or the agency which has primary responsibility for the fire
protection of such areas may permit exceptions from the
requirements of this section which are based upon the specific
circumstances involved. (Amended by Stats. 1976, Ch. 1300.)
157
SDGE-08 at 16.
158
SDG&E-08, Appendix 3.
48a
detail. The document provides an overview of the
VMP, inventory criteria for vegetation, instructions to
the Vegetation Management System, factors affecting
reliability, procedure to escalate issues, updating
inventory of vegetation, tree growth rates and the
Vegetation Management Areas (VMAs). The manual
is comprehensive and indicates that SDG&E had a
robust VMP in 2007.
4.3.3. Issues and Party Positions
Although no party disputes that the Rice Fire
started when a broken limb from FF0190 fell onto
SDG&E’s conductors, parties dispute whether SDG&E
prudently marked, inspected and trimmed FF1090
pursuant to its VMP. Parties focused their litigation
efforts on the tree inspections, trimming schedule and
activities related to the clearance requirements. ORA
and SDG&E also introduced testimony and evidence
regarding Reliability Trees and FF1090’s latent defect.
4.3.3.1. FF1090’s Inspection
Trimming Schedule
and
FF1090 is a fast growing sycamore tree inventoried
by the VMP in its Vegetation Management System
(VMS) in 1999. The VMS is a software application
designed by SDG&E to record tree data within a
dynamic inventory of vegetation having the potential
to grow into or fall into SDG&E electric power lines
and facilities.159 SDG&E pre-inspectors update information contained within certain fields in the database
based on their evaluation of the tree. One of the fields
in the VMS database is called “Months to next trim”,
and the inspector can choose 0-3, 3-6, 6-9 months, etc.
from the drop down menu. SDG&E’s VMS considers
159
Ibid at 8.
49a
the tab “0-3 months” as setting a timeline that begins
during the subsequent trim cycle, which in this case
meant between September to November 2007.
The record shows that FF1090 was inspected on
July 18, 2007 and the SDG&E inspector chose the 0-3
months tab to remove direct overhang. On October 22,
2007, three months later, when the Rice Fire ignited,
FF1090 had not been trimmed. ORA and SDG&E
heavily litigated the issues of when FF1090 should
have been trimmed, whether FF1090 exhibited a
clearance violation, and whether the trim would have
prevented the branch from falling onto the conductors.
ORA argues that FF1090 should have been trimmed
before October 18, 2007, three months from the July
18, 2007 pre-inspection. ORA believes that failure to
trim FF1090 led directly to the branch breaking off
and falling on the conductors. SDG&E states that the
“Months to next trim” tab should be used to estimate
how many months will elapse before the tree grows out
of compliance. According to SDG&E, a selection of 0-3
months would mean that the tree should be trimmed
in the upcoming trim cycle, which in this case, would
have been between September and November of
2007.160 SDG&E further alleges that the broken off
branch was growing away from the power lines, and
as such would not necessarily have been subject to
trimming.
4.3.3.2. FF1090’s latent defect and
the issue of Reliability Trees
The parties did not focus on some other aspects of
the VMP manual that are nevertheless important in
160
See SDG&E-13 Prepared Rebuttal Testimony of Don Akau
at 10-11.
50a
determining whether SDG&E acted prudently prior to
the fire. Don Akau, SDG&E’s Vegetation Management
Program Manager, testified about the hidden defect he
observed in the broken branch after the fire. Mr. Akau
referred to “staining” at the point where the fallen
branch broke from the main trunk161 and proposed
that the staining could be an indicator of “included
bark”, or “internal structural stressing and cracking in
the branch union” which in his opinion contributed to
the failure of the limb in the winds.162
Throughout this proceeding, SDG&E claimed that
the included bark was hidden, and could not have been
discovered by its personnel during their inspections.
According to SDG&E’s VMP manual, a Reliability
Tree is “Any Tree, located inside or outside the utility
right-of-way, that has a reasonably good potential for
interrupting service to an overhead circuit (excluding
secondary) with the current routine cycle.”163 When a
pre-inspector identifies a Reliability Tree, it is
mandatorily marked in the VMS as a Reliability Tree
and for trimming.164 A Reliability Tree exhibits one or
more factors listed in the VMP manual, and per
SDG&E’s inspection procedures, must be marked,
pruned and inspected to ensure grid reliability.
FF1090 was not marked as a Reliability Tree before
the Rice Fire.
4.3.4. Discussion
In evaluating SDG&E’s operation and management
of its facilities in connection with the Rice Fire, the
161
SDG&E-08 at 19 and SDG&E-13 at 8.
162
Ibid.
163
SDG&E-08, Appendix 3 at 7.
164
Ibid. at 30.
51a
Commission must determine whether SDG&E
employed reasonable judgment in its operation and
management of its facilities in the period leading up to
the ignition of the Rice Fire. The general purpose of
routine pre-inspections is to identify vegetation for
pruning and removal that will not maintain required
clearance for a full cycle (fourteen months). As part of
the inspection process, the pre-inspector is also tasked
to identify and mark Reliability Trees. A Reliability
Tree is “Any Tree, located inside or outside the utility
right of way, that has a reasonably good potential for
interrupting service to an overhead circuit within the
current routine cycle.” According to the VMP manual,
“a majority of tree related outages that occur in the
utility right-of-way are the result of tree or limb
failure, not tree growth.”165 When a Reliability Tree is
identified the pre-inspector shall [emphasis added]
check both the reliability and trimming required box
in the tree tab.166
As part of its VMP, SDG&E relies on its inspectors
to select the appropriate fields in the VMS and to
identify potential Reliability Trees. It is essential for
SDG&E personnel and contractors to be well trained
in the procedures of the VMP so that they accurately
select the drop down menus in the VMS.167
Based on an exhaustive review of the record and
informed primarily by SDG&E’s own VMP manual,
165
Ibid.
166
Ibid.
167
The Vegetation Management System (VMS) is a database
which tracks all of the inventoried vegetation within SDG&E’s
territory. The VMS has various drop down menus which allow an
inspector to identify issues with a tree and recommend the proper
course of action.
52a
the Commission finds SDG&E acted imprudently in
its management of FF1090. First, we find SDG&E to
have deviated from its usual timeline in trimming
FF1090. Secondly, SDG&E’s pre-inspector mistook the
‘months to next trim’ menu to mean that a selection of
0-3 months means that an actual trimming would take
place within 0-3 months of the pre-inspection. The
contractor’s misunderstanding of the VMS led him to
incorrectly select a menu item that delayed the
trimming beyond three months from the inspection
date. Thirdly, SDG&E did not identify FF1090 as a
“Reliability Tree” even though FF1090 seems to have
exhibited at least two characteristics on the “Tree
Hazard Checklist.”168 Each of these elements of the
record is discussed below. In each of these instances,
SDG&E failed to demonstrate that it employed
reasonable judgment in its operation and
management of its facilities in the period leading up to
the ignition of the Rice Fire.
4.3.4.1. SDG&E’s Tree Inspection
and Trimming Schedule
The record shows that at the time of the Rice Fire’s
ignition, SDG&E had a VMP in place whereby FF1090
was inspected and trimmed. A summary of all
available pre-inspections and subsequent trim dates
recorded in the VMS Tree Information Sheet up to the
Rice Fire are shown in the table below:
168
Ibid.
53a
Tree FF1090 Inspection and Prune dates
Tree FF1090 Inspection Date Prune date
05/07/1999
05/01/2000
01/25/2001
No trim record
01/02/2002
04/29/2002
01/13/2003
05/07/2003
11/11/2003
02/17/2004
11/17/2004
02/11/2005
07/12/2005
No trim record
07/19/2006
No trim record
07/18/2007
(10/15/2007)*
(10/19/2007)*
10/22/2007
* SDG&E states that Davey Tree Surgery Company
and SDG&E personnel performed follow up inspections on October 15, 2007 and October 19, 2007
respectively, and that FF1090 was in compliance with
clearance requirements on those two visits. However,
these additional inspection dates are not shown in the
tree information sheet submitted by SDG&E. SDG&E
asserts the October 15, 2007 inspection by a data
request response submitted by Davey.169
The Tree Information Sheet identifies FF1090 as
a fast growing sycamore tree with a growth rate of
between four to six feet every year. FF1090 was
inventoried on May 7, 1999 and pruned on May 1,
169
See SDGE-08, Appendix 7.
54a
2000. It was inspected again on January 25, 2001 and
January 2, 2002. Having not been trimmed for 20
months, the January 2, 2002 inspection documents
FF1090 as having between 1.5 to 4 foot clearance to
the conductors and SDG&E pruned FF1090 on April
29, 2002.170 In 2002, SDG&E had notice that, because
of FF 1090’s growth rate, not trimming the tree
annually resulted in FF1090 being out of clearance
compliance. Subsequent to the 2002 violation, FF1090
was inspected and pruned annually until the
inspection on July 12, 2005. FF1090 was not trimmed
after July 12, 2005, nor was it trimmed after the
inspection on July 19, 2006. By the July 18, 2007
inspection, FF1090 had not been trimmed for over 29
months.171
There were only two instances in FF1090’s
inventoried history in which it was not trimmed on an
annual basis. The first instance in which SDG&E
failed to trim FF1090 annually was in 2002, when the
tree was recorded as being within 4 feet of conductors.
The Rice Fire marks the end of the second time period
during which SDG&E fell out of the annual trimming
schedule. At the time of the Rice Fire ignition, SDG&E
had not trimmed FF1090 for 29 months. The fact that
SDG&E deviated from its own standard time table,
and allowed more than two years to elapse without
pruning this fast-growing tree, shows that SDG&E
was not reasonable or prudent in its management of
FF1090.
170
SDGE-08 at Appendix 6. SDG&E argues that ORA failed to
prove FF1090 was out of compliance, we note that it is SDG&E
who carries the burden of proof to show it was acting prudently
and reasonably, not the other way around.
171
Ibid.
55a
ORA and SDG&E focus their arguments on the
definition of 0-3 months and whether it meant that
FF1090 should have been trimmed by October 18,
2007. The Commission reviews all available data as a
whole. SDG&E’s inspector described his reasoning in
selecting 0-3 months: “And I listed from zero months
to three months as when it should be trimmed. I chose
that option on the drop-down menu.” “[I]t had strong
growth towards the lines, and I felt it would encroach
in the 4 foot distance from the primary line in the
facilities within three months.”172
In light of this testimony, SDG&E’s claim that “0-3
months” did not set a deadline for trimming is
unpersuasive. SDG&E’s contract requires Davey to
train its pre-inspectors on many topics in the VMP
manual and to use the VMS. But, in this instance, the
pre-inspector did not have a clear understanding of the
drop down menu functions in the VMS. The inspector’s
misunderstanding of SDG&E’s tree trimming program
underscores the need for proper training. If the contractor made a mistake due to insufficient or improper
training, SDG&E is still responsible for acts, omissions, or failures of its agents under PUC Section
2109.173
In comments on the proposed decision, SDG&E
further asserted that the broken off branch grew away
from the powerline, and was not marked for trimming.
172
ORA-44, Transcript excerpts of the March 25, 2008
Examination Under Oath of Mark Clemens.
173
California Public Utilities Code section 2109: “In
construing and enforcing the provisions of this part relating to
penalties, the act, omission, or failure of any officer, agent, or
employee of any public utility, acting within the scope of his
official duties or employment, shall in every case be the act,
omission, or failure of such public utility.”
56a
SDG&E did not carry its burden to show that the
broken branch grew away from the powerline. Rather,
the growth direction of the broken branch is inconclusive from the record. Testimony from Mr. Akau states
that the branch was positioned toward the northeast,
growing away from the powerline;174 testimony from
Mr. Ronald Hay states that the broken branch grew to
the south, toward the utility lines;175 and testimony
from Mr. David Kracha states that broken limb grew
completely vertically and did not grow toward or away
from the powerlines.176
Next, assuming that the broken branch grew away
from the powerline, a second evidentiary issue emerges.
SDG&E presented multiple witnesses stating that the
broken branch was part of co-dominant leader growthwith two similar-sized branches growing from the
same union point. SDG&E has argued throughout
this proceeding that due to the co-dominant nature of
these branches, the breaking of one necessitated the
removal of the other. After observing the broken
branch on October 22, 2007, before Cal Fire could
inspect the ignition site, SDG&E’s Chris Thompson
ordered the removal of the remaining leader branch,
and reduction of FF1090’s entire canopy to prevent
additional failures.177 SDG&E justifies the reduction
of the entire canopy of FF1090 by stating it was
necessary to prevent further failures. Applying the
same rationale, the evidence indicates that that
174
See SDG&E-08 at 18.
175
See ORA-40, Transcript excerpts of May 28, 2008 examination under oath of Ronald Hay.
176
See ORA-41, Transcript excerpts of May, 28, 2008 Examination under oath of David Kracha.
177
See SDG&E-13, Appendix 4 at 4.
57a
trimming of FF1090’s overhang would have required
balanced trimming throughout the canopy. Thus, even
if the broken branch did not have clearance problems,
a prudent manager trimming on a regular schedule
likely would have trimmed FF1090 to balance the
other branches that did have clearance issues.
According to SDG&E, two additional inspections of
FF1090 took place on October 15, 2007 and October
19, 2007, and those inspections found FF1090 to be
in compliance with clearance requirements.178 The
October 19, 2007 inspection was conducted by SDG&E
personnel, but also is not shown in the Tree
Information sheet.
4.3.4.2. FF1090’s Latent Defect and
the Issue of Reliability Trees
In addition to FF1090’s inspection and trim history,
the Commission also considers whether SDG&E has
met the burden of showing that it could not have
identified the defect in FF1090. The Commission’s
analysis of the record and the VMP concludes that
SDG&E has not met its burden: There is insufficient
evidence to show that acting responsibly SDG&E
could not have identified the defect in FF1090. The
broken branch with included bark exhibited at least
two factors which could warrant FF1090 being marked
as a Reliability Tree.
To begin, Section 5 of SDG&E’s VMP manual
discusses Reliability Trees. The five-page section
defines Reliability Trees and provides a Hazard Tree
Checklist for evaluating trees for reliability and six
178
We note the October 15, 2007 inspection is not recorded on
SDG&E’s own Tree Information Sheet, but reported by Davey as
part of a data response in SDG&E-08, appendix 7.
58a
sample photos.
Two checklist items are relevant
to FF1090: 1) “are there multiple vertical branches
originating from one point that may indicate weak
attachment?” and 2) “are there narrow-angled branch
crotches that may indicate included bark?180”
179
Section 5 of SDG&E’s VMP manual is consistent
with General Order 95, Rule 35, which requires that
diseased and rotten portions of otherwise healthy
trees growing toward or hanging over powerlines be
removed.
SDG&E presents evidence of the included bark
and the limb’s growth direction through Mr. Akau’s
testimony, a hand drawn diagram by Mr. Akau, and
testimony from Ronald Matranga and Chris Thompson,
SDG&E arborists who visited the Rice Fire site after
the fire. According to SDG&E, the broken limb which
caused the ignition contained hidden ‘included bark’,
which could not be observed during routine inspections. In his direct and rebuttal testimony, Mr. Akau
referred to the presence of “staining” at the point
where the fallen branch broke from the main trunk.181
Mr. Akau proposes that the staining could be an
indicator of “included bark”, or “internal structural
stressing and cracking in the branch union” which in
his opinion contributed to the failure of the limb in the
winds.182
The record, however, does not clearly support that
SDG&E did not have advance notice of the structural
defect.
179
Ibid.
180
SDG&E-08, Appendix 3 at 30.
181
SDG&E-08 at 19 and SDG&E-13at 8.
182
Ibid.
59a
Mr. Akau testified regarding SDG&E’s Vegetation
Management Program and presented inspection protocol for “Reliability Trees,” and stated that no structural
defects were noted by SDG&E’s contractors during the
July 18, 2017 inspection 183 SDG&E’s Chris Thompson
testified in I.08-11-006 that the cause of the included
bark was co-dominant leader branches in FF1090.184
Mr. Thompson states in his testimony that FF1090’s
included bark occurred “when two separate leaders
start growing together and pushing against each other
as they grow in diameter.”185 Further corroboration of
FF1090’s growth pattern can be found in the transcribed testimony of Ronald Hay, which described the
broken branch as part of “a healthy clutter[spelling
per transcript] of branches that grew straight up.”186
While as discussed above, SDG&E personnel provided conflicting testimony on the growth direction of
the broken branch, in contrast SDG&E personnel have
been consistent in their recollection of the growth
pattern of the broken limb.
The testimony indicates that the broken branch was
part of at least two vertical branches, possibly more,
growing closely together. This testimony indicates
that the tree appeared to have some physical characteristics that would have warranted further attention.
Based on the testimony of SDG&E’s personnel, SDG&E
183
SDGE-13 at 9, citing “Direct Testimony of Ronald
Matranga” in I.08-11-006, June 6, 2009 at 3-5.
184
SDG&E-13, Appendix 4 at 4.
185
Ibid.
186
See ORA-40, Transcript excerpts of May 28, 2008 Examination under oath of Ronald Hay at 23.
60a
has not met its burden of showing that it could not
have identified the defect in FF1090.
4.4. Commission Precedent
The Commission has a long history of cases that
apply the reasonable and prudent manager standard
to after-the-fact reviews of costs incurred by utilities.
In each case, the facts showed that the costs the
Commission denied were directly attributable to clear
and identifiable utility failures or errors.
Mohave
The facts of I.86-04-002 have similarities to the facts
of the instant proceeding. On June 9, 1985, a weld in
a high-pressure steam pipe at the Mohave Coal Plant
(Mohave) ruptured, blasting steam hotter than 1,000
degrees Fahrenheit through an employee breakroom
and Mohave’s control room.187 As a result, six people
were killed and ten others were severely injured.188
The steam caused extensive damage to the control
room, as well as other portions of the plant.189 The
Commission ultimately concluded that Southern
California Edison Company (SCE) acted unreasonably
in failing to implement an inspection program to
ensure that the portion of the piping system that
ultimately failed was maintained in a safe condition.190
In reaching its decision, the Commission offered,
“[e]vidence of accepted industry practices will often be
relevant to a reasonableness inquiry, but compliance
with such practices will not relieve the utility of [its]
187
D.94-03-048 at 2.
188
D.94-03-048 at 2.
189
D.94-03-048 at 2.
190
D.94-03-048 at 2.
61a
burden of showing that its conduct was reasonable.”191
Furthermore, the Commission noted “guidelines are
only advisory in nature and do not relieve the utility
of its burden to show that its actions were reasonable.”
I.86-04-002 concluded with D.94-03-048, which held it
was not reasonable to pass costs resulting from the
accident to SCE’s ratepayers.
Similar to Mohave, where SCE’s facilities were
directly involved killing six people and injuring ten
others, SDG&E’s facilities were directly involved in
the ignition and subsequent destruction caused by the
2007 Wildfires. Although SDG&E had industry recognized policies and programs in place (recloser policy,
Corrective Maintenance Program, and Vegetation
Management Program) prior to October 2007, such
practices do not relieve SDG&E of its burden to show
that its actions were reasonable. As discussed above,
SDG&E fails to show its actions were reasonable when
SDG&E allowed 4 faults to occur on TL 637 over a
period of 6.5 hours; SDG&E failed to uncover the 3.3
feet clearance violation for 6 years after utilizing its
Corrective Maintenance Program’s patrol and detailed
inspections; and SDG&E did not show by a preponderance of the evidence that it properly monitored and
trimmed FF1090 before the ignition of the Rice Fire.
SDG&E did not train its contractors to properly mark
the VMS and has not shown it could not have
identified a defective limb. SDG&E is responsible for
its contractor’s failure to appropriately mark the VMS
and ensure that Tree FF1090 was trimmed on a timely
basis. The Commission is also concerned with records
suggesting that FF1090 may have been a Reliability
Tree warranting immediate attention.
191
D.94-03-048 at 37, citing D.88-03-036 at 527.
62a
Helms
In A.82-04-12 and I.82-01-01 (Helms), the Commission reviewed whether the costs incurred by Pacific
Gas & Electric Company (PG&E) in building the
Helms Project192 prior to the Lost Canyon pipe failure
constituted reasonable and prudent utility expenditures.193 On September 29, 1982, the Lost Canyon pipe
crossing failed during testing of the Helms Project.194
In April 1983, PG&E filed an amendment to A.82-0412 asking the Commission: (1) to place $738.5 million
cost for the Helms Project incurred before the Lost
Canyon pipe failure into rate base; and (2) to defer any
review of the additional reconstruction cost until
PG&E resolved all litigation arising from the Lost
Canyon pipe failure.195 In reaching its conclusion, the
Commission found PG&E failed to appreciate the risks
associated with the construction of the Helms Project,
192
D.85910 defines the Helms Project as: The Helms Pumped
Storage Project is a combination pumped storage and conventional hydroelectric project. The project allowed for the utilization
of the water power resources of the North Fork Kings River and
Helms Creek. The project completes development of the available
head between Courtright Lake, maximum water surface elevation 8,184 feet, and the U.S. Army Corps of Engineers’ Pine Flat
Reservoir, maximum water surface elevation 952 feet. The
maximum head developed by the project between Courtright
Lake and Lake Wishon is 1,744 feet. The power potential will be
developed by constructing a conduit consisting of two tunnels, a
short pipe section and a penstock between Courtright Lake and
an underground powerhouse. Total length of the conduit, which
is entirely underground except for the 140-foot pipe section, is
20,408 feet. The trailrace tunnel connects the underground powerhouse with Lake Wishon.
193
D.85-08-102 at 6 to 7.
194
D.85-08-102 at 5.
195
D.85-08-102 at 5 to 6.
63a
and that PG&E also failed “to take seriously the
repeated safety citations and work shutdowns issued
and ordered by the State Department of Occupational
Safety and Health.”196 Ultimately, the Commission
found PG&E failed to perform at the appropriate
standard of performance, rendering PG&E imprudent.197 D.85-08-102 specified that ratepayers would
not be required to indemnify PG&E for losses arising
from the Lost Canyon pipe failure.198
Similar to Helms, where the Commission found
PG&E failed to take into account the risks associated
with building the Helms Project, SDG&E failed to
take into account the risks associated with its
automatic recloser policy. As ORA showed, SDG&E
had knowledge of the 2001 Field Guide’s caution that
automatic reclosers increase the risk of igniting vegetation. As such, it was imprudent of SDG&E to not
take into account the risk factors associated with
re-energizing TL 637 after three faults occurred
within a span of 3.5 hours.
SONGS
D.84-09-120 addressed the reasonableness of SCE’s
cost of power purchased to replace power lost because
of the diesel generator fire at San Onofre Nuclear
Generating Station (SONGS) Unit 1.199 On July 14,
1981, a fire caused by a small oil leak in a section
of piping attached to a diesel engine caused two
emergency diesel generators at SONGS 1 to be out
196
D.85-08-102 at Findings of Fact 6 and 10.
197
D.85-08-102 at Conclusions of Law 5 and 6.
198
D.85-08-102 at Conclusion of Law 9.
199
D.84-09-120 at 2.
64a
from July 17, 1981 to August 16, 1981.200 Although a
small oil leak had been reported near the piping in
question, maintenance personnel could not find the
source of the leak, even with the diesel shutdown.201
Unfortunately, during the next monthly scheduled
load-test, the unidentifiable leak caused oil to spray
out and ignite a fire.202 The coordinated effort between
SONGS 1 control room operators and the fire personnel limited the fire to only 7 minutes, thereby reducing
damage to the diesel generator.203 In reviewing SCE’s
conduct, the Commission applied its reasonableness
standard, and found that the replacement energy costs
associated with the SONGS I diesel generator fire
were incurred on account of SCE’s unreasonableness
and were therefore unrecoverable.204
Similar to SONGS, where the Commission found
costs incurred for replacement energy costs were
unrecoverable due to the unreasonableness of SCE’s
actions, the costs of the 2007 Wildfires were incurred
due to unreasonable management by SDG&E. Even
though SCE limited the diesel fire to 7 minutes,
thereby substantially reducing the fire’s damage, the
Commission still found SCE’s actions leading up to
the diesel fire to be unreasonable. Similarly, it was
imprudent of SDG&E to allow a fourth fault to occur
on TL 637 more than two hours after SDG&E’s Grid
Operations became aware of the Witch Fire. Similar
to SONGS, where maintenance personnel could not
locate the oil leak, SDG&E’s Corrective Maintenance
200
D.84-09-120 at 72.
201
D.84-09-120 at 73 to 74.
202
D.84-09-120 at 74 to 75.
203
D.84-09-120 at 74 to 75.
204
D.84-09-120 at Conclusion of Law 2.
65a
Program failed to identify the almost 3-feet clearance
violation between SDG&E’s overhead conductors
and the below-installed Cox Communication Line.
While SONGS involved the prompt deployment of
maintenance personnel to address its oil leak, SDG&E
was unable to locate and address the clearance issue
for almost six years, even after personnel completed
inspections on April 8, 2005, June 22, 2007 and August
30, 2007.
Applying the above case analysis to the facts of the
instant proceeding, it is reasonable for the Commission to find SDG&E’s actions leading up to the 2007
Wildfires imprudent. Moreover, it is reasonable for the
Commission to deny those costs which were incurred
by SDG&E to resolve third-party damage claims
arising from the Witch, Guejito and Rice Wildfires.
4.5. Wind and Weather Conditions in October
2007
Per the Scoping Ruling, the Commission has analyzed
SDG&E’s operation and management of its facilities
prior to the ignition of the 2007 Wildfires by each fire.
Regardless of the varying facts surrounding the Witch,
Guejito and Rice wildfire ignitions, a common issue
amongst the three fires exists. While no party disputes
the fact that the Santa Ana winds are a known local
condition in San Diego County, dispute remains as to
whether the winds credited with the ignition and
spread of the 2007 Wildfires were unprecedented.205 If
the wind and weather patterns present in October of
2007 were not unprecedented, then a prudent
manager would have used the weather information to
reasonably manage and operate its facilities.
205
ORA-01 at 36; SDGE-05 at 3.
66a
The parties to this proceeding have put forth extensive arguments and expert witness testimony on the
issue of the wind and weather conditions in October
2007. While both SDG&E and UCAN presented highly
recognized wind and weather experts, the opinions
encompass a variety of the methodologies to estimate
the peak wind speeds during the ignition of each of the
2007 Wildfires. While reviewing the experts’ showings, we have applied the following principle:
[I]n administrative proceedings before an
agency composed of trained specialists and
before expert examiners or hearing officers,
the burden of evaluating the weight and
probity of testimony and evidence covering
technical subject matter is primarily that of
sifting and evaluating the evidence based
upon the agency's expertise. Expert opinion
does not bind the Commission. The Commission may form its own conclusions without
the aid of expert opinions.206
SDG&E’s Experts’ Showings
SDG&E put forth Mr. Steve Vanderburg (Mr.
Vanderburg) and Dr. Jon Peterka (Dr. Peterka) to
show that the October 2007 weather conditions were
unprecedented.
Mr. Vanderburg, a Senior Meteorologist with
SDG&E, testified that the 2007 Wildfires occurred
during the most severe weather event in San Diego
206
D.90642, 2 CPUC2d 89, 102 (1979), citing Market Street
Railway v. Railroad Commission, 324 U.S. 548, 560-561 (1945).
See City of Los Angeles v. Public Utilities Commission, 7 Cal. 3d
331, 351 [*34] (1972).
67a
County since 1984.
Mr. Vanderburg presented a
statistical analysis comparing wind gusts from the
Julian Remote Automated Weather Station (RAWS)
and the West Santa Ysabel weather station to show
that the wind gust speeds would have been 92 miles
per hour (mph) during the peak of October 2007
weather season.208 Mr. Vanderburg utilized data from
the West Santa Ysabel weather station because it was
the closest source to the Witch Fire ignition point.209 In
briefs, SDG&E stressed that even though the West
Santa Ysabel weather station did not exist in 2007,
“Mr. Vanderburg was still able to determine what the
wind gust speeds would have been at the West Santa
Ysabel weather station during the peak of the late
October 2007 wind event.”210
207
Dr. Peterka, a Professional Engineer and Professor
Emeritus in Fluid Mechanics and Wind Engineering
at the Department of Civil Engineering at Colorado
State University, testified as to the mean wind speeds
at the time and location of the ignition of each of the
2007 Wildfires.211 Dr. Peterka used a two-pronged
approach, WRF (Weather Researching and Forecasting)
Modeling and a model of the local terrain, to compute
peak wind gusts speeds of: 78 to 87 miles per hour
(mph) for the Witch fire ignition; 59 to 68 mph for the
Guejito fire ignition; and 70 to 75 mph for the Rice fire
ignition.212 In his direct testimony, Dr. Peterka elabo207
SDGE-09 at 2.
208
SDG&E Phase 1 Opening Brief at 91 to 92.
209
SDG&E Phase 1 Opening Brief at 91.
210
SDG&E Phase 1 Opening Brief at 91 to 92.
211
SDG&E Phase 1 Opening Brief at 98.
212
SDG&E Phase 1 Opening Brief at 98, citing SDGE-10 at 1
and Appendix 1.
68a
rated on his methodology. Essentially, Dr. Peterka
explained that he validated his WRF results with 2007
observed data from the Automated Surface Observing
System (ASOS) located at the Ramona Airport.213 Dr.
Peterka stated, “the largest 3-second gust measured at
the Ramona Airport during [October 2007] was 55
mph. Based on the ESDU procedure used to estimate
the 3-second gust from the WRF simulations, the gusts
are predicted to be between 60 and 76 mph, or 9 to
38 percent higher than the actual measurements.
The validation exercise is dependent on the overall
match between ASOS and WRF wind speeds and
directions . . . . as well as the comparison of peak gusts.
This validation supports my methodologies.”214 Dr.
Peterka explained that he believed the RAWS and
ASOS data were obtained from stations that were
improperly sited. Dr. Peterka asserts that the improper
siting resulted in recorded wind speeds that are too
low.215 For this reason, Dr. Peterka discarded the 2007
RAWS and ASOS and came up with a result that is 9
to 38 percent higher.216
In addition to providing analyses of the wind and
weather events surrounding the ignition of the 2007
Wildfires, SDG&E’s experts highlighted the utility’s
involvement in developing the Santa Ana Wildfire
Threat Index (SAWTI).217 SDG&E notes, “to develop
the SAWTI, SDG&E and UCLA worked to configure
the WRF model by calibrating it against actual observations of temperatures, winds, and dew points
213
Reporter’s Transcript Volume 5 at 735 to 740.
214
SDGE-10 at 12.
215
UCAN Phase 1 Opening Brief at 9.
216
Reporter’s Transcript Volume 5 at 739.
217
SDG&E Phase 1 Opening Brief at 94.
69a
collected from SDG&E weather stations during Santa
Ana wind events.”218 SDG&E highlights that the SAWTI
allows an individual to understand the fire potential
by comparing it to past and present conditions.219 As
such, SDG&E’s experts utilized the SAWTI in testifying that the wind and weather conditions in San Diego
County in 2007 had the largest fire potential since
1984.220 Because of this, SDG&E maintains that it had
no way to know how the strong winds in October 2007
would affect SDG&E’s service territory and fire
danger.221
UCAN’s Experts’ Showings
UCAN put forth Dr. Janice Coen (Dr. Coen) and Dr.
Alexander Gershunov (Dr. Gershunov) to rebut the
claims made by SDG&E’s weather experts. Dr. Coen,
a Project Scientist with the National Center for
Atmospheric Research in Colorado, and Dr. Gershunov,
from University of San Diego in the Climate, Atmospheric Science and Physical Oceanography Division at
the Scripps Institute of Oceanography, assert that
SDG&E’s experts’ analysis is flawed.222
Dr. Gershunov testified regarding his methodologies
in calculating the wind gust speeds for each of the
2007 Wildfires, and how his findings show that the
2007 Wildfires cannot be attributed to an unprecedented weather event.223 Dr. Gershunov’s estimates
218
SDG&E Phase 1 Opening Brief at 94.
219
SDG&E Phase 1 Opening Brief at 95.
220
SDG&E Phase 1 Opening Brief at 95.
221
SDG&E Phase 1 Opening Brief at 95.
222
UCAN Phase 1 Opening Brief at 8, 18; UCAN Phase 1 Reply
Brief at 8.
223
UCAN Phase 1 Reply Brief at 9.
70a
for the Witch fire ignition were 43.1 mph, 56.7 mph at
the time of the Guejito Fire’s ignition, and 34.4 mph at
the time of the Rice Fire’s ignition.224 UCAN argues
that “when looking at these numbers from both
SDG&E’s wind expert and UCAN’s wind expert, the
differences seem huge. However, as Dr. Gershunov
testified, the difference is that [Dr. Gershunov] used
the recorded data from 2007 to validate and bias
correct his model results and that SDG&E did not.”225
Dr. Gershunov utilized data recorded by the RAWS
and ASOS stations in calculating his wind speed
estimates.226 As noted by Dr. Gershunov, “not only was
there a stronger wind event on record [in San Diego
County], but there were 3 other wind events that were
within 10-percent of the wind speeds of the 2007 Santa
Ana event that occurred in the last 30 years.”227
Furthermore, UCAN notes that SDG&E’s use of the
SAWTI to advance its theory that the 2007 Wildfires’
ignition and spread were beyond the utility’s control is
not supported by SDG&E’s experts’ theories.228
Analysis of Parties’ Experts
The presentation of UCAN’s and SDG&E’s expert
witnesses added tremendous value to the record of
this proceeding. SDG&E’s attempt to explain why
the contemporaneous data collected from San Diego
County’s RAWS and ASOS should be discarded were
not persuasive. We find the wind estimates of Dr.
Gershunov to be more reflective of the actual wind and
224
UCAN Phase 1 Reply Brief at 9.
225
UCAN Phase 1 Reply Brief at 9.
226
UCAN Phase 1 Reply Brief at 9.
227
UCAN Phase 1 Opening Brief at 19, citing Reporter’s
Transcript at 1004 to 1005.
228
UCAN Phase 1 Opening Brief at 19.
71a
weather conditions during the ignitions of the Witch,
Guejito and Rice Wildfires in October 2007. We find
Dr. Gershunov’s utilization of the actual recorded
weather data from 2007 to validate his wind speed
estimates to be more reliable than Dr. Peterka’s
methodologies. Furthermore, the Commission is not
persuaded by SDG&E’s use of the SAWTI to try to
establish that the wind and weather conditions in San
Diego County in October 2007 created the largest
wildfire threat since 1984 because of more refined
testimony provided by the other parties.
Because we find the methodologies that UCAN’s
experts utilized in developing its testimony to be more
consistent with the actual wea
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