Petition for Writ of Certiorari — California Energy Co. v. Public Utilities Commission
Supreme Court brief1991
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In the Supreme Cobre OF THE CLERK
OF THE
United States
OCTOBER TERM, i991
CALIFORNIA ENERGY COMPANY, INC.,
Petitioner,
VS.
PUBLIC UTILITIES COMMISSION OF THE STATE OF
CALIFORNIA and SOUTHERN CALIFORNIA EDISON COMPANY,
Respondents.
PETITION FOR WRIT OF CERTIORARI
TO THE CALIFORNIA SUPREME COURT
BAKER & MCKENZIE
JOHN R. SHINER
N. GRANT MARTIN
Thirty-Seventh Floor
777 South Figueroa Street
Los Angeles, California 90017
(213) 892-7300
Attorneys for Petitioner
California Energy Company, Inc.
July 16, 1991
BOWNE OF SAN FRANCISCO. INC. + 190 NINTH ST. + S.F..CA 94103 + (415) 864-2300
QUESTIONS PRESENTED
Whether Respondent California Public Utilities Commission
(“Commission”) denied Petitioner’s constitutional right of due
process, under the 14th Amendment to the United States Consti-
tution, by rescinding, altering or amending its own final orders and
decisions without notice or opportunity to be heard? 28 U.S.C.
§ 1257(a).
PARTIES
The parties to this Petition are listed in the caption. Petitioner,
through its wholly owned subsidiary, Coso Hotspring: _Intermoun-
tain Power, Inc. is a genera! partner in Coso Energy Developers.
The other general partner is Caithness Coso Holdings. Petitoner,
through its wholy owned subsidiary, Coso Technology Corpora-
tion, Inc., is a general partner in Coso Power Developers. The
other general partner is Caithness Navy II Group, L.P. In
addition, the parties who actively participated in the proceedings
below were Southern California Edison Company (“SCE”), Luz
International Ltd. (“LUZ”), the Commission’s Division of Rate-
payer Advocates and the California Energy Commission.
TABLE OF CONTENTS
Page
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Reasons For Granting The Writ....................... 10
The Commission’s Failure To Afford Petitioner Notice That
It Intended To, And Could, Alter The 1985 Decision
Denied Petitioner Constitutional Procedural Due Process 11
I
Notwithstanding The Breadth Of Its Perceived Powers, The
Commission Was Compelled By The Fourteenth Amend-
ment To Afford Petitioner Adequate Notice And A
RR ie rrr po yee 13
II
The Notice Afforded Was Inadequate To Apprise Petitioner
Of The Nature Of The Proceedings Below............ 14
A. Petitioner Was On Notice Only That Costs Would
Be Allocated According To The 1985 Decision .... 14
B. Petitioner Prepared For And Participated In The
Proceedings On The Reasonable Assumption That
The 1985 Decision Was Final and Conclusive ..... 17
C. Notwithstanding The Limited Scope Of The Hear-
ing, The Commission Rescinded The Per Se Bulk
Line Rule And Thus Altered The Decision In Viola-
Can Ur Fe 6 eect dvcacedadiciecens 18
III
The Commission’s Rescission Of The Per Se Bulk Line
Rule, Without Adequate Notice To Petitioner, Rendered
Petitioner's Opportunity To Be Heard Meaningless .... . 19
GN as 6p cds hcccseneeveaenee oveseetereetess 20
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iii
TABLE OF AUTHORITIES
Cases
Boddie v. Connecticut, 401 U.S. 371, 91 S. Ct. 780, 28 L.
cee epee cctnere ews ss
Bowman Transp., Inc. v. Arkansas-Best Freight Sys., Inc.,
419 U.S. 281, 95 S. Ct. 438, 42 L. Ed. 2d 447 (1974), reh.
denied, 420 U.S. 956, 95 S. Ct. 1340, 43 L. Ed. 2d 433
ES ELGG nl eas bakin boa 8d coe nese
California Trucking Assn. v. Public Utilities Com., 19 Cal.
3d 240, 137 Cal. Rptr. 190, 561 P.2d 280 (1977) ......
Cleveland Bd. of Educ. v. Loudermill, 470 U.S. 532, 105 S.
eB ee
Consumers Lobby Agains: Monopolies v. Public Utilities
Com., 25 Cal. 3d 891, 160 Cal. Rptr. 124, 603 P.2d 41
td aacknn wig Kec 0p wie hs bape 0 00
Giaccio v. State of Pennsylvania, 382 U.S. 399, 86 S. Ct.
ee oe
Hannah v. Larche, 363 U.S. 420, 80S. Ct. 1502, 4 L. Ed. 2d
1307, reh. denied, 364 U.S. 855, 81 S. Ct. 33, 5 L. Ed. 2d
is od veacweeeusbeneeis
Hewitt v. Helms, 459 U.S. 460, 103 S. Ct. 864, 74 L. Ed. 2d
etc as ck een weakea ser tsecreraees
Morgan v. United States, 304 U.S. 1, 58 S. Ct. 773, 82 L.
rd Dove cei e cubase shaveuvdess
Mullane v. Central Hanover Bank & Trust Co., 339 U.S.
306, 70 S. Ct. 652, 94 L. Ed. 2d 865 (1950) ..........
Paul v. Davis, 424 U.S. 693, 96 S. Ct. 1155, 47 L. Ed. 2d
405, reh. denied, 425 U.S. 985, 96 S. Ct. 2194, 48 L. Ed.
i I ee
Pennsylvania v. Ritchie, 480 U.S. 39, 107 S. Ct. 989, 94 L.
Tee cel Ls ou Wadkea rae es exe's
Page
16
14
18
13
iV
TABLE OF AUTHORITIES
CASES
Page
People v. Western Air Lines, Inc., 42 Cal. 2d 621, 268 P.2d
723, appeal dism‘d, 348 U.S. 859, 75 S. Ct. 87, 99 L. Ed.
a se Ra ey tol rd a a A 2, 16
Withrow v. Larkin, 421 U.S. 35, 95 S. Ct. 1456, 43 L. Ed. 2d
pp SR ED Se BS Dee Ab eure hye ae a 13
California Public Utilities Commission Decisions:
Decision 84-08-031, 16 CPUC 2d 5 (1984) ........... 4
co AE SS a passim
Decision 87-05-060, 24 CPUC 2d 253 (1987) ......... 6, 15
Constitution, Statutes and Rules
United States Constitution:
Amendment XIV Section] ........................ 3,5
United States Code:
We I OTOL oo ci ccc cccccevscescccees i, 3
ee a i
California Public Utilities Code:
Te ora Sod oy a. oc cae dae ewes even passim
LON so daa kus deus woe ere saree eee passim
PS a 0-65 Ss Sh auoe cote eure een 12
California Public Utilities Commission General Orders:
RY ee Une Ae ager > eee eee 7
No.
In the Supreme Court
OF THE
United States
OCTOBER TERM, 1991
CALIFORNIA ENERGY COMPANY, INC.,
Petitioner,
vs.
PuBLic UTILITIES COMMISSION OF THE STATE OF
CALIFORNIA and SOUTHERN CALIFORNIA EDISON COMPANY,
Respondents.
PETITION FOR WRIT OF CERTIORARI
TO THE CALIFORNIA SUPREME COURT
Petitioner prays that a writ of certiorari issue to review Com-
mission Decision 90-09-059, entered September 12, 1990, and for
which the California Supreme Court denied review on April 18,
1991.
OPINIONS BELOW
The opinion of the Commission (D.90-09-059, the “Decision’’)
has been reported at 37 CPUC 2d 413 (1990). A copy of the
Decision and order denying review by the California Supreme
Court are attached as Appendix A and C, respectively.
2
JURISDICTION
The Decision' of the Commission is dated September 12, 1990.
The Commission’s order denying rehearing and reconsideration is
dated December 19, 1990, and was mailed December 27, 1990.
(Appendix B.) The California Supreme Court denied review on
April 18, 1991.”
The jurisdiction of this Court is invoked under 28 U.S.C.
§ 1257(a).
RELEVANT STATUTES
UNITED STATES CONSTITUTION
Amendment XIV Section 1. Aji persons born or naturalized
in the United States, and subject to the jurisdiction thereof, are
citizens of the United States and of the State wherein they reside.
No State shall make or enforce any law which shall abridge the
privileges or immunities of citizens of the United States; nor shall
any State deprive any person of life, liberty, or property, without
due process of law; nor deny to any person within its jurisdiction
the equal protection of the laws.
‘The Commission acknowledged that Petitioner, “argues that the
Commission cannot alter or rescind the 1985 Decision in this applica-
tion, because to do so would violate the notice and hearing requirements
of PU Code Section 1708 and the Fourteenth Amendment of the U.S.
Constitution.” (Decision at A-24.) Petitioner first raised this argument
in a motion for summary judgment before the proceedings commenced,
and asserted this position at each subsequent stage including in its
Petition to the California Supreme Court.
> A denial of review by the California Supreme Court of a Commis-
sion order, even without an accompanying opinion, constitutes a final
adjudication on the merits. People v. Western Air Lines, Inc., 42 Cal. 2d
621, 630-631, 268 P.2d 723, appeal dism'd, 348 U.S. 859, 75 S. Ct. 87,
99 L. Ed 2d 677 (1954).
3
CALIFORNIA PUBLIC UTILITIES CODE
Section 1708. Modification of orders or decisions by commis-
sion; Effect
The commission may at any time, upon notice to the parties, and
with opportunity to be heard as provided in the case of com-
plaints, rescind, alter, or amend any order or decision made by it.
Any order rescinding, altering, 0: amending a prior order or
decision shall, when served upon the parties, have the same effect
as an original order or decision.
Section 1709. Final orders as conclusive
In all collateral actions or proceedings, the orders and decisions of
the commission which have become final shall be conclusive.
STATEMENT OF THE CASE
Petitioner California Energy Company, Inc. produces electric-
ity from geothermal power plants. SCE is a utility regulated by
the Commission,’ transmitting and distributing both electricity
generated from its own plants and from alternative energy produc-
ers such as Petitioner. Under the Public Utilities and Regulatory
Policies Act of 1978 (“PURPA”), 16 U.S.C. §§ 824a-3, et seq.,
SCE is required to provide for interconnection with Petitioner,
and to compensate Petitioner for the power produced under
standard contracts previously executed between SCE and Peti-
tioner. PURPA describes energy suppliers such as Petitioner as a
“qualifying facility” or “QF.”
On March 20, 1989, SCE filed with the Commission an
Application (A.89-03-026) for a Certificate of Public Conve-
nience and Necessity to obtain permission to construct “a new,
> “The California Public Utilities Commission (CPUC) regulates the
service and rates of more than 25,000 privately-owned utilities and
transportation companies serving California including privately-owned
gas, electric, local and long distance telephone, radio-telephone, water
and steam heat utilities and sewer companies; railroads, buses, trucks,
and vessels transporting freight or passengers; and carloaders and pipe-
line operators.” (1989-90 Commission Annual Report, p. 3.)
4
double circuit, 220 kilovolt (“kV”) electric transmission line
connecting SCE’s Kramer Substation with its Victor Substation
in the Mojave Desert” (“Proposed Line”). (Decision at A-1 )
The Proposed Line was needed, among other reasons, to facilitate
SCE’s acceptance of energy supplied by Petitioner and Luz
International Ltd. (“Luz”), a similarly situated QF. The Com-
mission believed that part of its review process included a deter-
mination of what installation costs, if any, would be allocated to
Petitioner.
The applicable rules for such cost allocation were earlier
announced by the Commission in Decision 85-09-058 (“1985
Decision”), which was an outgrowth of proceedings initiated in
1984 (“1.84-04-077”) to examine limitations on various utilities’
transmission systems (including SCE’s) affecting QF develop-
ment. (Decision at A-19.) Among the issues sought to be
resolved was a methodology for determining what cost responsi-
bility, if any, QFs shouid bear for “bulk transmission line up-
grades.” (Decision 84-08-031, 16 CPUC 2d 5 (1984).)
1.84-04-077 was intended to be a generic proceeding in which
all parties potentially affected might participate in resolving the
issue of cost responsibility for transmission lines. In fact, it
expressly was provided that these issues, “either in the near future
or longer run, affect other California electric utilities and QF
development statewide,” and would have “policy implications”
for all electric utilities subject to the Commission’s jurisdiction.
(1.84-04-077 at p. 1.) The Commission ordered an investigation
“into the potential limitations of the transmission system in
California” for the purpose of determining, inter alia, “[w]hether
an electric corporation or QFs should have sole responsibility to
pay the costs of upgrades... or how such costs should be allo-
cated between them.” (1.84-04-077 at p. 4.)
“Luz and SCE previously had reached agreement regarding what
portion of interconnection costs would be allocated to Luz. Notwith-
standing such agreement, Luz joined Petitioner during the proceedings
below, as did the California Energy Commission, in asserting the
applicability of the prior Commission orders and decisions addressed
herein.
5
In September 1985, the portion of the 1.84-04-077 hearings
bearing on cost allocation was completed and the Commission
issued its findings and conclusions in the 1985 Decision.
The 1985 Decision established the following uncontroverted
rules with respect to cost allocation, which then were published
and thus made applicable to those within the Commission’s
jurisdiction:
“A QF is responsible only for interconnection and other
facilities that have no system-wide benefits and are solely
beneficial to the QF. This approach eliminates the need for a
difficult cost allocation among the various users of a trans-
mission facility.
“... Bulk transmission lines by definition have system-wide
benefits. And nearly all area lines probably have some
system-wide benefits. Thus, QFs will assume cost responsibil-
ity only on the rare occasion that an area line lacks any
perceptible system-wide benefit.
*“... We have not yet adopted consistent energy reliability
criteria for all utilities. The cost of transmission service is
just one piece to the puzzle of properly valuing QF power.
Thus, for the moment, we will allow utilities to follow the
general principle that as long as a transmission facility has
system-wide benefits, the utility's ratepayers are responsible
for the prudent and reasonable cost. The QF is responsible
only for interconnection cost and other special facilities
which have no system-wide benefits. Refinement of this
principal must await for our determination in the long-run
avoided cost proceedings.”
(Emphasis added, Devision at A-20-21.)
On February 20, 1990, Petitioner filed a motion (essentially for
summary judgment) asserting, inter alia, that based upon the
Commission’s earlier orders, it could not be charged with cost
responsibility and that not to follow the prior orders would deprive
Petitioner of its right to procedural due process guaranteed by the
14th Amendment to the United States Constitution. (Decision at
A-4.) Further, it argued, the 1985 Decision made clear that
application of the rules contained therein, “eliminated the need
6
for a difficult cost allocation among the various users of a
transmission facility” (see p. 5, supra), which was precisely what
the proceedings contemplated were designed, in part, to accom-
plish. Petitioner's motion relied primarily upon the applicable
rules of cost allocation announced in the Commission’s earlier
1985 Decision, and sought an order that if the Proposed Line were
a bulk transmission line, no costs could be allocated to Petitioner
in conformity with the 1985 Decision.
Because no “refinement” of the principles adopted in the 1985
Decision has yet taken place,° the “system-wide benefits” ap-
proach, including the per se bulk line rule announced in the 1985
Decision, had been relied upon by Petitioner (both in raising
capital for its projects and during the proceeding below) as the
test in effect for cost allocation of interconnection facilities.
Nevertheless, on March 5, 1990, the Administrative Law Judge
(“ALJ”) assigned to the proceedings denied Petitioner's motion
by summarily concluding that, “[t]he issue of whether or not the
1985 decision controls is for the Commission to decide when it
issues its final decision in the case.... Now, there is still a
lingering, broader question, is this a generic proceeding in which
the Commission will undertake a general study of the cost
allocation ‘ssue in an attempt to craft a formal rule. And I think
we can say with a fair amount of confidence that no, this is not
that type of proceeding.” Petitioner requested the ruling be
certified to the full Commission for an interim appeal, which also
was denied on March 19, 1990 (Decision at A-4), leaving the
parties to proceed without any notice of what standard would be
applied, the precedential effect of the 1985 Decision or the
* Petitioner also relied on a Conclusicn of Law contained in Commis-
sion Decision 87-05-060, a 1987 decision which reaffirmed the 1985
Decision’s cost allocation rules, by providing, “[t]he approach taken in
D.85-09-058 is the best available for allocating cost responsibility to
OFs....
* Indeed, it was incumbent upon the Commission to initiate such
proceedings; until termination of those proceedings, the 1985 and 1987
pronouncements were specified to continue in effect.
7
ultimate conclusions of the Commission reflected for the first
time in the Decision.
Beginning on March 19, 1990, hearings were held to explore,
among other things, issues of public necessity, environmental
impact and cost allocation.
Petitioner reiterated the applicability of the per se bulk line rule
and presented uncontested evidence through its expert witness
that the Proposed Line would be a “bulk” transmission line.
SCE’s expert witness agreed and no evidence was advanced to the
contrary.
Based on this showing, Petitioner argued that the entire cost of
the Proposed Line must be paid by the ratepayers, as dictated by
the 1985 Decision and reaffirmed in 1987. (See footnote 5,
supra.)
Following the March hearings, the ALJ issued a proposed
decision on June 15, 1990, which allocated cost responsibility of
21% (approximately $11 million) to Petitioner, 44.8% to Luz (per
the Luz/SCE agreement, see footnote 4, supra) and 34.2% to the
ratepayers.
The full Commission thereafter considered the entire matter
and, on September 12, 1990, issued the Decision which essen-
tially adopted the results, and much of the reasoning, contained in
the ALJ’s proposed decision.
” In addition to testifying as to the “bulk” rating of the Proposed Line,
substantial evidence pertaining to each of the eight system-wide benefit
criteria articulated in the 1985 Decision was submitted. For example,
Petitioner maintained that simply by satisfying the requirements prereq-
uisite to the issuance of a Certificate of Public Convenience and
Necessity, the Proposed Line, by definition, exhibited system-wide
benefits. The Commission’s General Order No. 131-C provides that a
Certificate is contingent upon:
... this Commission having first found that said facilities are
necessary to promote the safety, health, comfort, and conve-
nience of the public, and that they are required by the public
convenience and necessary.
(Emphasis added. )
8
The Decision itself represents an extraordinary bit of convo-
luted logic, patently designed to release the Commission from the
effect of its 1985 Decision while providing notice to the Petitioner,
for the first time, of how it intended to treat the 1985 Decision.
The Commission began by assuring the parties that it had “no
intention of altering, modifying, or rescinding D.85-09-058 in this
decision” (Decision at A-27),* and that, “[a]lthough we are not
legally bound to apply D.85-09-058 in determining [ Petitioner's }
cost responsibilities, we are left with the question of whether it
nonetheless should form the basis for our decision. The simple
answer is yes.” (Emphasis added, Decision at A-37.)
1. Unlike the Decision, the 1985 Decision had no disclaimer
that, “[a]ny cost allocation which is determined to be reasonable
in this case is based on the facts and circumstances specific to the
parties and testimony in this proceeding and have no further
reaching application.” (Decision at A-27.)
2. Thus, Petitioner assumed that the 1985 Decision would be
“conclusive” as to this or any other collateral proceeding. (€ ali-
fornia Public Utilities Code 1709, see p. 3, supra.)
3. However, the Commission construed Section 1708 as al-
lowing it to reconsider, “its earlier policy positions, so long as
adequate notice and opportunity to be heard is provided to those
who will be affected.” (Decision at A-28.) Those “affected”
would include Petitioner and the entire QF community, none of
whom had prior notice of the Commission’s intent in this regard.
4. In a radical departure from its prior stance, the Commission
continued, “/e]ven if the 1985 decision set forth a clear recipe for
determining who should pay for the proposed project, we would
not be legally bound by that order in this proceeding. None of the
authority cited by the participants in this case stands for the
proposition that this Commission is precluded from reconsidering
its earlier policy positions, so long as adequate notice and opportu-
nity to be heard is provided to those who will be affected. Thus,
we are free to determine that the policy set forth in the 1985
*To do so would require a specific procedure outlined in California
Public Utilities Code § 1708, set forth on p. 3, supra.
9
decision is no longer appropriate as it affects the parties in this
case.”’ (Emphasis added, Decision at A-28.)
5. And finally, buried in the course of some 100 pages, the
Commission states, “[e¢]ither some 220 kV lines are not bulk...
or it simply is not true that all bulk lines have system-wide
benefits” (emphasis added, Decision at A-23), and it “cannot be
legally bound to apply the 1985 decision to the facts at hand.”
(Emphasis added, Decision at A-31.)
6. The effect, of course, was to rescind the 1985 Decision, of
which Petitioner had no notice until after the proceedings were
complete and the Decision issued, notwithstanding the Commis-
sion’s commitment not to do so. The Commission provided no
authority that it could alter its prior decisions, and utterly failed to
apprise the parties prior to commencement of the proceedings
that it claimed to possess such authority and, indeed, might alter
or modify its 1985 Decision.
By this capricious sleight of hand, the Commission wriggled
away from assessing the facts before it within the limitations of
the 1985 Decision. In essence, the Commission was uncomforta-
ble with the result obtained by applying the 1985 Decision, and
simply chose not to follow it. None of this artifice, however, was
imparted to the parties in advance and directly contravened
Sections 1708 and 1709.
Petitioner filed an application for rehearing on October 12,
1990, again arguing that Petitioner’s due process rights had been
violated by the Commission, which was denied December 19,
1990.
The California Supreme Court denied review on April 18,
1991.”
* The Commission now intends to press forward with what has been
identified as “Phase II” of these proceedings, over the objections of
Petitioner. In Phase II, the Commission will allocate additional costs
with respect to ancillary facilities associated with the project. Because
Phase II will be governed by the Decision, the federal questions
presented therein will not be re-examined. Under these circumstances,
10
REASONS FOR GRANTING THE WRIT
Daily throughout the nation, a variety of administrative bodies
act on requests from individuals and, in so doing, grant or deny
rights and obligations frequently with far reaching effect. Those
same tribunals, perhaps because of their number and the fre-
quency with which they adjudicate, operate at every level of a
person’s interaction with government and often with more impact
on the average citizen than the courts. Yet, because of their “lay”
character, they sometimes act arbitrarily, or in the furtherance of
interests never revealed to the participants, and are allowed to
function in a virtually uncontrolled manner knowing that in most
instances their actions will not be reviewed by, or challenged
before, a higher authority.
Administrative agencies, as with the Commission, are often
composed of political appointees who may arrive with a bias or
prejudice which seeps into the ultimate decision making process.
The danger, in such an environment, is that the rights of partici-
pants may be subsumed within the private agendas of those who
rule on matters before them, and who may feel compelled to
sacrifice the parties’ rights to what they believe to be a more
compelling interest. So common is this conduct, and so alarming
the actions outlined in this Petition, that it is critical for the Court
to declare that administrative bodies are not immune from the
Constitution and must act with certainty, not whimsy, insuring
that parties may rely with reasonable predictability upon a set
course.
Indeed, for example, this Court long ago recognized the impor-
tance of due process in administrative proceedings of a quasi-
judicial character, in which:
the liberty and property of the citizen shall be protected by
the rudimentary requirements of fair play. These demand “a
fair and open hearing,” essential alike to the legal validity of
the administrative regulation and to the maintenance of
public confidence in the value and soundness of this impor-
those questions are ripe for review by this Court. See Pennsylvania v.
Ritchie, 480 U.S. 39, 46, 107 S. Ct. 989, 996, 94 L. Ed. 2d 40 (1987).
ll
tant governmental process. Such a hearing has been de-
scribed as an “inexorable safeguard.”
Morgan v. United States, 304 U.S. 1, 14-15, 58 S. Ct. 773, 775, 82
L. Ed. 1129 (1938) (citations omitted). It is precisely, “the
maintenance of public confidence in the value and soundness of
this important governmental process,” which demands swift ac-
tion by this Court.
For this Court not to act, and act with dispatch, will be to
sanction by implication the continued deprivation of due process
within one of the nation’s most active judicial forums—adminis-
trative proceedings.
THE COMMISSION’S FAILURE TO AFFORD PETI-
TIONER NOTICE THAT IT INTENDED TO, AND
COULD, ALTER THE 1985 DECISION DENIED PETI-
TIONER CONSTITUTIONAL PROCEDURAL DUE
PROCESS.
The Commission is allowed by statute to alter its decisions, but
only after application of a procedure which affords notice of its
intention to do so. (California Public Utilities Code § 1708.) The
Commission specifically indicated that was not its intention in the
proceedings below. Thus, with its 1985 Decision in place, the
Petitioner had the right to rely upon it as conclusive. (California
Public Utilities Code § 1709.)
The Commission, however, without ever advising the parties
(and in the absence of any precedent that might have supplied
such notice), maintained:
1. the rules in the 1985 Decision would remain in effect until
a “broader proceeding, with more expansive notice to affected
parties” (Decision at A-27);
2. that although the Commission did not intend to alter the
1985 Decision, it was not legally bound to apply it (Decision at A-
31);
3. it was free to determine that the policy in the 1985
Decision was no longer appropriate (directly contrary to its
statement in the 1985 Decision that the principles cited would
12
remain in effect until further refinement in long-run avoided cost
proceedings) (Decision at A-28); and
4. it may depart from the rules embodied in the 1985 Deci-
sion in this case (despite unconditional language in the 1985
Decision and the California Public Utilities Code which give no
hint that the Commission is free to ignore its promulgated rules
on a case-by-case basis). (Decision at A-31.)
At issue is not some technical analysis of transmission line
interconnection, but whether the Commission, without notifying
those before it, will be allowed to render a decision, specified to be
a controlling rule affecting a multitude of parties, interests and
ratepayers, and then reverse itself by characterizing its earlier
pronouncement simply as “policy” which it is free to alter as
subsequent facts, in its singular view, may warrarit.
The essence of constitutional due process is raised by this
Petition. If administrative bodies are allowed to set standards for
those who may fit within their jurisdiction (and who act in
reliance upon such direction), only later to decree that what was
earlier said can be altered in a subsequent proceeding, there are
absent even the most fundamental of due process guaranties. Yes,
the parties had an opportunity to present their views, however
Petitioner was never advised the Commission would be altering its
earlier rules.
The case presented herein is a classic example of overreaching
and, indeed, is accentuated by the fact Commission action may be
reviewed only by the California Supreme Court,'° and so it is left
with virtually unrestricted license to ignore the constitutional
° California Public Utilities Code § 1759 provides, “[n]o court of this
State, except the Supreme Court to the extent specified in this article,
shall have jurisdiction to review, reverse, correct, or annul any order or
decision of the commission or to suspend or delay the execution or
operation thereof, or to enjoin, restrain, or interfere with the commission
in the performance of its official duties, except that the writ of manda-
mus shall lic from the Supreme Court to the commission in all proper
cases.
13
rights of those who appear before it.'' The California Supreme
Court has demonstrated a general unwillingness to accept matters
on appeal from the Commission, thus leaving the Commission to
act as it wishes.'*
Notwithstanding The Breadth Of Its Perceived Powers, The
Commission \. as Compelled By The Fourteenth Amendment
To Afford Petitioner Adequate Notice And A Meaningful
Hearing.
Not even the Commission can dispute that, “a ‘fair trial in a
fair tribunal is a basic requirement of due process’... [which]
applies to administrative agencies which adjudicate’? as well as to
courts.” Withrow v. Larkin, 421 U.S. 35, 46, 95 S. Ct. 1456, 1464,
43 L. Ed. 2d 712 (1975) (citations omitted). This Court has
consistently recognized that, when governmental agencies such as
the Commission act in a judicial capacity, “it is imperative that
those agencies use the procedures which have traditionally been
associated with the judicial process.” Hannah v. Larche, 363 US.
420, 442, 80 S. Ct. 1502, 1514, 4 L. Ed. 2d 1307, 1321, reh.
denied, 364 U.S. 855, 81 S. Ct. 33, 5 L. Ed. 2d 79 (1960).
'' This although paying lip service to the requirement that it, “must
constantly make its decisions within the constraints and opportunities
provided by the state and federal constitutions and applicable statutory
law but with an eye toward setting the course for the future.” (Decision
at A-30.)
'? Petitioner is informed that between the years 1950-59, 15 petitions
for review of Commission actions were granted by the California
Supreme Court, whereas in the 1980-1989 decade, only 7 such petitions
were granted. Over the past five years, the Commission issued approxi-
mately 900 decisions annually.
'? The Commission functions judicially, as it did in the proceedings
below, when it “acts as trier of fact, applies rules of law to those facts,
and renders a decision adjudicating vested interests in which there are
clear prevailing and losing parties.” Consumers Lobby Against Monopo-
lies v. Public Utilities Com., 25 Cal. 3d 891, 908, 160 Cal. Rptr. 124,
134, 603 P.2d 41 (1979).
14
The “essential requirements of due process” are notice and an
opportunity to be heard. Cleveland Bd. of Educ. v. Loudermill,
470 U.S. 532, 546, 105 S. Ct. 1487, 1495, 84 L. Ed. 2d 494
(1985). The Constitution requires that “notice” be:
reasonably calculated, under all the circumstances, to apprise
interested parties of the pendency of the action and afford
them an opportunity to present their objections.
Mullane v. Central Hanover Bank & Trust Co., 339 U.S. 306,
314, 70 S. Ct. 652, 657, 94 L. Ed. 2d 865 (1950). The Constitu-
tion further provides that the “opportunity to be heard” consists
of:
“an opportunity... granted at a meaningful time and in a
meaningful manner,” . . . “for [a] hearing appropriate to the
nature of the case.”
Boddie v. Connecticut, 401 U.S. 371, 378, 91 S. Ct. 780, 786, 28
L. Ed. 2d 113 (1971) (citations omitted).
The Commission utterly failed to afford Petitioner these “es-
sential requirements of due process” by rescinding the per se bulk
line rule without adequate notice and hearing.
The Notice Afforded Was Inadequate To Apprise Petitioner Of
The Nature Of The Proceedings Below.
Certainly, as the Commission argues, Petitioner was given
notice and a hearing; but that notice, as the Commission con-
cedes, did not apprise Petitioner that the scope of the proceedings
would include the rescission or alteration of the Commission’s
prior orders and decisions promulgating the per se bulk line rule.
As such, the procedures followed by the Commission in depriving
Petitioner of its property rights were constitutionally inadequate.
A. Petitioner Was On Notice Only That Costs Would Be
Allocated According To The 1985 Decision.
Because SCE is required to provide for interconnection with
Petitioner, the Commission believed that part of its review pro-
cess included a determination of what installation costs, if any,
15
would be allocated to Petitioner. The 1985 Decision set forth the
applicable standards for such cost allocation, including the per se
bulk line rule.
Petitioner had an absolute right to expect that the scope of the
hearings, as they related to Petitioner, would be limited to
application of the 1985 Decision (including the per se bulk line
rule) to the facts addressed during the proceedings. Petitioner had
no notice (and could not reasonably have anticipated) that the
scope of the proceedings would be expanded to encompass rescis-
sion or alteration of the 1985 Decision.
First, Petitioner could not reasonably have expected that the
1985 Decision would not be applied, because that Decision, by its
very terms, was made applicable to the cost allocation issues in
the proceedings below:
“Thus, for the moment, ... [t]he QF is responsible only for
interconnection cost and other special facilities which have
no system-wide benefits. Refinement of this principal must
await for our determination in the long-run avoided cost
proceedings.”
(Emphasis added, Decision at p. A-21.) No such determination,
as yet, has been made in the course of any long-run avoided cost
proceedings.
Second, the Commission reaffirmed the applicability of the cost
allocation methodology in 1987. Petitioner, therefore, was entitled
to rely on the applicability of the 1985 Decision in the wake of
that ruling, which stated, “[t]he approach taken in D.85-09-058
is the best available for allocating cost responsibility to QF’s....”
(Decision 87-05-060, Finding of Fact No. 22, 24 CPUC 2d 253
(1987).) The Commission affirmed the applicability of the 1985
Decision’s cost allocation rules. The proceedings in question
began only two years later and nothing occurred in the interim
which served to change the existence or application of the
Commission’s rules for cost allocation.
Third, the State of California has enacted a statutory frame-
work, California Public Utilities Code §§ 1708 and 1709, which
mandates the applicability of the 1985 Decision to the proceed-
16
ings below. Section 1709 applies, on its face, to the 1985 Decision
because that Decision is an order or decision of the Commission
which had become final. Moreover, the proceedings below clearly
were collateral to the 1985 Decision—the 1985 Decision estab-
lished the overall cost methodology applicable to all subsequent
QF interconnections until such time as the Commission could
reconsider the entire matter in the long-run avoided cost proceed-
ings. Under Section 1709, then, the 1985 Decision, including the
per se bulk line rule, was conclusive as to the parties. See People
v. Western Air Lines, Inc., supra, 42 Cal. 2d at 630.
Section 1708 also provides a method by which the Commission
may rescind, alter or amend its prior orders and decisions, “upon
notice to the parties, and with opportunity to be heard as provided
in the case of complaints.” Like Section 1709, Section 1708
applies to the 1985 Decision because that Decision is an “order or
decision made by” the Commission. Indeed, Section 1708 pro-
vides the exclusive method by which the Commission is able to
rescind, alter or amend its prior decisions, including the 1985
Decision. See California Trucking Assn. v. Public Utilities Com.,
19 Cal. 3d 240, 245, 137 Cal. Rptr. 190, 193, 561 P.2d 280
(1977).
Accordingly, Petitioner had a statutory right to rely upon the
applicability of the 1985 Decision, until reevaluated by a pre-
scribed method, and could not have remotely foreseen that the
scope of the proceedings below would be expanded, or essentially
converted, into a Section 1708 procedure allowing for the rescis-
sion or alteration of the per se bulk line rule.
Fourth, the ALJ specifically represented that the 1985 Decision
was applicable and refused to certify the question to the full
Commission for clarification or stay of the proceedings pending
the long-run avoided cost proceedings. The ALJ specifically
stated that, “the 1985 Decision is applicable te our consideration
in this case,” and unequivocally ordered that the scope of the
proceedings would not encompass a generic reevaluation of the
cost allocation issue.
Because the ALJ nevertheless denied Petitioner's summary
judgment motion, Petitioner requested the matter be referred to
17
the Commission on an interim appeal to clarify the Commission’s
position. That request was denied. This, in the face of the ALJ’s
determination that it would be left to the Commission to decide
the application, if any, of the 1985 Decision. Petitioner again
could not possibly have expected that the hearing on the cost
allocation issue would be expanded to include a rescission or
alteration of the 1985 Decision or the per se bulk line rule.
Further, the Commission certainly was free to conduct its long-
run avoided cost proceedings first, resolving whatever ambiguities
it determined to exist in the 1985 Decision, thereafter applying its
conclusions to matters at hand.
Fifth, even the Commission concedes the notice afforded was
insufficient to apprise Petitioner that the scope of the hearings
would include rescission or alteration of the 1985 Decision:
We have no intention of altering, modifying, or rescinding
D.85-09-058 in this decision. While it may be appropriate to
reexamine some of the assumptions behind that decision or
to explore in more detail how it should be implemented,
those questions should be addressed in a broader proceeding,
with more expansive notice to affected parties.
(Emphasis added, Decision at A-27, footnote omitted.)
B. Petitioner Prepared For And Participated In The Proceed-
ings On The Reasonable Assumption That The 1985 Deci-
sion Was Final And Conclusive.
Petitioner, then, was on notice on/y that costs would be allo-
cated in the proceeding below according to the 1985 Decision.
Clearly, Petitioner did not have notice that the scope of the
hearing, which was neither convened nor conducted pursuant to
Section 1708, would involve the rescission or alteration of the per
se bulk line rule. Based on such notice, Petitioner made a simple,
uncontroverted showing at the hearing that the Proposed Line
would be “bulk” in nature and, accordingly, urged the Commis-
sion to allocate the entire cost of the Proposed Line to the
ratepayers in accordance with the 1985 Decision, which the ALJ
stated would apply and which Petitioner had an absolute right to
expect would apply.
,
18
C. Notwithstanding The Limited Scope Of The Hearing, The
Commission Rescinded The Per Se Bulk Line Rule And
Thus Altered The Decision In Violation Of Section 1708.
Instead of applying its previously announced cost allocation
rules, the Commission rescinded the per se bulk line rule ex-
tracting approximately $11 million from Petitioner.
The Commission declared that the per se bulk line rule was too
ambiguous to apply and, therefore, refused to apply it—a de facto
rescission of the rule. (Decision at A-37-38.)'* By refusing to
apply its own rules regarding the cost methodology which the
1985 Decision mandates will be in effect until long-run avoided
cost proceedings are conducted, the Commission effectively re-
scinded those rules without due process of law.
The Commission’s position that it merely was “reconsidering
its earlier policy positions,” rather than rescinding the per se bulk
line rule, is unmistakable mockery. It is well-established that the
Commission’s characterization of its conduct deserves no weight
on review by this Court:
[b]Joth liberty and property are specifically protected by the
Fourteenth Amendment against any state deprivation which
does not meet the standards of due process, and this protec-
tion is not to be avoided by the simple label a State chooses
to fasten upon its conduct or its statute.
Giaccio v. State of Pennsylvania, 382 U.S. 399, 402, 86 S. Ct.
518, 520, 15 L. Ed. 2d 447 (1966). Labeling an established rule
“ambiguous” and refusing on those grounds to apply it, is tanta-
mount to rescission; and a rescission of the per se bulk line rule is
clearly an alteration of the 1985 Decision.
'* Additionally, although the Decision purports to undertake a system-
wide benefits analysis, it also holds that the criteria for that analysis as
set forth in the 1985 Decision are too ambiguous to apply. (Decision at
A-38.)
19
The Commission’s Rescission Of The Per Se Bulk Line Rule,
Without Adequate Notice To Petitioner, Rendered Peti-
tioner’s Opportunity To Be Heard Meaningless.
By expanding the scope of the hearing without providing
adequate notice, the Commission rendered Petitioner’s opportu-
nity to be heard meaningless. Petitioner prepared for and partici-
pated in a hearing that could be reasonably anticipated only to
include the determination of facts and application of the 1985
Decision, including the per se bulk line rule, to those facts. The
Commission, however, changed the rules mid-course and failed to
notify Petitioner. This Court has stated that:
[a] party is entitled, of course, to know the issues on which
[the] decision will turn and to be apprised of the factual
material on which the agency relies for decision so that he
may rebut it.
Bowman Transp., Inc. v. Arkansas-Best Freight Sys., Inc., 419
U.S. 281, 288 n.4, 95 S. Ct. 438, 443 n.4, 42 L. Ed. 2d 447
(1974), reh. denied, 420 U.S. 956, 95 S. Ct. 1340, 43 L. Ed. 2d
433 (1975). Without any knowledge of the theory upon which the
issues would be viewed or evaluated, Petitioner was denied fair
notice of the standard by which its evidence might be judged.’
'* Indeed, Petitioner has a property interest, sufficient to invoke due
process protection, in the Section 1708 procedure because of its
mandatory nature. See Paul v. Davis, 424 U.S. 693, 710-711, 96 S. Ct.
1155, 1165, 47 L. Ed. 2d 405, reh. denied, 425 U.S. 985, 96 S. Ct. 2194,
48 L. Ed. 2d 811 (1976), and Hewitt v. Helms, 459 U.S. 460, 471-472,
103 S. Ct. 864, 871, 74 L. Ed. 2d 675 (1983) (While the “mere fact
[of] a careful procedural structure” does not alone amount to an interest
requiring due process protection under the Fourteenth Amendment, the
mandatory nature of the procedures, coupled with “substantive predi-
cates” or criteria “demands a conclusion that the State has created a
protected ... interest.”) (Citations omitted.)
20
CONCLUSION
1. Our country is increasingly governed by administrative
regulation, a trend of probably long duration.
2. The wisdom or caprice by which such regulation is admin-
istered is of vital importance to the efficacy of government and the
best interests of its citizens.
3. The proceedings below present a vivid example of regula-
tion by sophistry rather than by law, specifically, in the absence of
notice to the parties, the pretense of retroactive conversion of the
agency’s own established rule, specified as definitive and dependa-
ble, to some sort of flexible “policy,” alterable at will.
4. Here then is a distinctive opportunity for the Supreme
Court to speak directly to the thousands of state and federal
agencies concerning the responsibility entrusted to them for
probity and consistency in the enforcement of law.
Dated: July 16, 1991
Respectively submitted,
BAKER & MCKENZIE
JOHN R. SHINER
N. GRANT MARTIN
Attorneys for Petitioner
California Energy Company, Inc.
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Appendix A
Decision 90-09-059
September 12, 1990
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
In the Matter of the Application of Southern California Edison
Company (U 338-E) for a Certificate that the Present and Future
Public Convenience and Necessity Requires or Will Require
Edison to Construct and Operate a 220 kV Double-Circuit
Transmission Line Between the Kramer Substation and the
Victor Substation in San Bernadino County, California.
Application 89-03-026
(Filed March 20, 1989)
Richard K. Durant, Carol B. Henningson, James M. Lehrer,
Carol A. Schmid-Frazze, and Michael D. Mackness, Attor-
neys at Law, for Southern California Edison Company,
applicant.
Messrs. Jackson, Tufts, Cole & Black, by William H. Booth,
Joseph S. Faber, and Evelyn K. Elsesser, Attorneys at Law,
for Luz Partnership Management, Inc. and Luz Interna-
tional, Limited; Messrs. Baker & McKenzie, by John R.
Shiner and Gordon F. Dickson, Attorneys at Law, for Cali-
fornia Energy Company, Inc.; Dick Ratliff, by David Mund-
stock, Attorneys at Law, Gary C. Heath and Al McCuen, for
the California Energy Commission; Messrs. Roberts and
Kerner by Douglas K. Kerner, Attorney at Law, for Indepen-
dent Energy Producers’ Association; and Roger Peters,
Douglas A. Oglesby, Kathleen B. Welsh, Attorneys at Law,
and Gary G. Gauthier, for Pacific Gas and Electric Com-
pany; interested parties.
Jason Zeller, Attorney at Law, for the Division of Ratepayer
Advocates and Jo Anna Bullock, for the Commission Advi-
sory and Compliance Division.
; i
Index
Subject Page
ie eek soo oe o.0-6) 64 0a 8 A-l
lL. SW idee een d 60s 64406 $0608 8 n8¥. A-|l
rR ae A-2
Sane RN I ES gg cc ence cccsenes A-5
IV. The Need for a New Transmission Line........ A-7
V. Description of the Proposed Project ........... A-9
VI. Cost Caps and Cost Estimates for the Proposed
ee aes Cewe bao ate anceacns ee ve A-11
Te A-12
ceric cd scccccedseses A-15
VII. Ratepayer Cost Responsibilities ............... A-16
A. The SCE/Luz Agreement ............... A-18
B. Proposals for Allocating the Remainder of the
SE A-18
C. D.85-09-058 and Its Significance.......... A-19
1. Is the Decision Clear on its Face? ..... A-21
2. Is the Decision Binding? ............. A-24
a. Positions of the Parties........... A-24
i a igs bo ono 004006 A-27
3. Cal Energy’s Claims of Reliance on the
ERG A-31
4. Should D.85-09-058 Be Applied In this
SON alae edu eke scenrccens A-37
D. System-Wide Benefits................... A-37
1. The Lack of Clear Criteria ........... A-38
BE te BID. coe cco cccess A-38
3. Providing for Future Growth.......... A-42
4. System Security and Reliability ....... A-43
5. Emergency Support ...............-. A-45
6. Tramsler Capavility ................-. A-46
7. Firm Resources at System Peak Condi-
eee eee Pupeareskseeexks A-47
S. CeO . gn cece cevese A-48
9. QF Generation and Better Air Quality.. A-48
10. Conclusions to be Drawn About System
Ae a a ee A-50
E. Aliocation of Project Costs............... A-52
Subject Page
F. Cal Energy’s Obligation to Pay its Share ... A-56
Viti. Environmental Considerations ................ A-57
A. PUBPUPREON GE GRP EME occ ccc cccuses A-57
DB. Peg occ occteccnccceess A-58
©. ARBRE I vo cass ccs vccccccecss A-59
D. Environmental Impacts.................. A-60
|. Qs obi 66s kasdnaeeaes A-60
2. TRGHORICRD RROSOUICOS.. 0... cc cccc cscs A-60
D. . Sieh as bess ddessscaees A-61
4, FR erpccccccdeneecuces A-62
a — ERE I CR EE A-63
6. Paleontological Resources ............ A-63
1. QR ao pice carscvecccce> A-63
8. Comparison to Alternative Corridors ... A-63
E. Comments on the DEIR................. A-64
F. Mitigation and Mitigation Monitoring ...... A-68
EX. Prem Be tee tees cee ec ess tp cces es A-70
A. Motion of DRA to Admit Additional Evi-
dence Related to Exhibit 48.............. A-70
B. Motion Re Supplemental Brief of Luz Inter-
eR eS ree Pee rr eC eee A-71
C. Motion of SCE to Establish Phase II of A.89-
03-026 to Determine Cost Allocation of In-
terconnection and Integration Facilities Not
dg ke errr A-71
a Og Re ee rs Serr A-72
Cometh OF BAW ois cnceecdeteeee ee A-84
GH distorts seuckudsepee aetna ekahar A-88
a Fe errr ee ete Ra A-91
A-|l
OPINION
I. Summary
In this decision, we grant a Certificate of Public Convenience
and Necessity (CPCN) to the Southern California Edison Com-
pany (SCE or Edison) for the construction of a new, double
circuit, 220 kilovolt (kV) electric transmission line connecting
SCE’s Kramer Substation with its Victor Substation in the
Mojave Desert. The CPCN also includes related facilities at the
Kramer, Victor, and Lugo Substations needed to handle the
power to be transmitted over the new line.
The line is needed to facilitate the delivery into the SCE load
center of electricity from two types of small qualifying facilities
(QFs) located in the Mojave Desert: geothermal power plants
developed by California Energy Company, Inc. (Cal Energy),
and solar thermal power plants developed by Luz International
Limited (Luz). Under state and federal law, SCE is required to
provide for the interconnection of these generating units with the
SCE electric system and to pay the QFs for the power they
produce under the terms of standard contracts offered by SCE
and agreed to by the QFs.
In this decision, we also determine how the costs of the
proposed project will be allocated. Luz’s cost obligations will be
governed by an agreement which it has undertaken with SCE,
under which Luz will be responsible for 44.8% of the project cost.
Cal Energy will be required to pay for 21% of the cost of the
project. The remaining 34.2% of the cost will be borne by SCE’s
ratepayers.
As a condition for the receipt of the CPCN, SCE will be
required to undertake numerous mitigation measures, designed to
limit the impact of otherwise significant and potentially significant
effects which would stem from the construction and operation of
the new facility. In keeping with recent Commission practice,
SCE will be required to pay for a third-party mitigation monitor-
ing program to be managed by the Commission’s Advisory and
Compliance Division (CACD). The mitigation monitoring staff
will oversee SCE’s implementation of the mitigation measures
and other activities required in this decision.
A-2
II. Procedural History
SCE filed its application for a CPCN and the accompanying
Proponent’s Environmental Assessment (PEA) on March 20,
1989. The scheduled operating date for the proposed project is
September |, 1992, with construction planned to begin Septem-
ber 1, 1991.' The application was accepted for filing on April 20,
1990.
A meeting was held in the City of Adelanto on July 26, 1989, to
determine public concerns related to the scope of the Environ-
mental Impact Report (EIR). The alternative transmission route
proposed for this project travel through and around the City of
Adelanto. On August 3, 1989, a prehearing conference was held
in San Francisco. The Draft EIR was distributed to interested
parties and places of public access in the vicinity of the project on
November 30, 1989. The Draft EIR indicated that written com-
ments could be filed no later than January 17, 1990. On that date,
a Public Participation Hearing was held in the City of Adelanto.
The second prehearing conference was held in Adelanto on that
date as well.
In the meantime, other events had occurred which affected the
scope of this proceeding. On November 17, 1989, SCE and Luz
signed an agreement (SCE/Luz Agreement), which is discussed
in greater detail below. Generally, the agreement allocates be-
tween Luz and SCE’s ratepayers costs related to the proposed 220
kV line and other interconnection and integration facilities. Spe-
cifically, Luz agrees to pay 44.8% of the cost of the proposed
project. Cal Energy, the other QF developer seeking use of the
proposed 220 kV line, has not entered into a cost sharing agree-
ment with SCE, although negotiations continued while this case
was pending. SCE asked that the Commission approve the
agreement with Luz as part of its review of the application for a
CPC&N. Both SCE and Luz filed testimony in support of the
agreement.
' Pursuant to the SCE/Luz Agreement signed after the filing of this
application and discussed below, Luz would construct the transmission
line with the goal of having it in operation before the end of 1991.
| ~
Division of Ratepayer Advocates’ (DRA) testimony, released
on December 19, 1989, included a recommendation that the
SCE/Luz Agreement be rejected. The essence of DRA’s position
was that there are no apparent system benefits to be derived from
this line and that under such circumstances the full cost of the
line should be borne by the QFs. On January 8, 1990, SCE and
Luz filed a joint motion asking the Commission to declare that it
could approve the SCE/Luz Agreement without considering the
system benefits issue. The California Energy Commission (CEC)
filed a Staff Prehearing Conference Statement on January 18,
1990, which included comments in support of the motion. DRA
responded to the motion on January 19, 1990 and Luz filed an
additional response on January 22, 1990.
Under the Permit Streamlining Act (Government Code Sec-
tion 65950) the Commission has one year from the date that the
application was filed to approve or disapprove the project. If the
Commission fails to act within that time frame, the project could
be deemed approved (Government Code Section 65956(b)). The
one-year deadline for this project was April 20, 1990. Since the
evidentiary hearings were scheduled to begin on January 22, 1990,
SCE and Luz acknowledged that the pendency of the joint
motion might delay resolution of the application. This is because
SCE and Luz expressed a desire to file rebuttal testimony on the
issue of system benefits, if the motion were to be denied. Govern-
ment Code Section 65957 allows for one extension of the ap-
proval/disapproval deadline for a period of up to 90 days with the
consent of the public agency and the applicant. Since it was likely
that any necessary rebuttal hearings could not be held until
March, SCE requested a 90-day extension. We concur with this
request, which results in a final decision deadline of July 20, 1990.
At the hearing held January 22, 1990, the assigned administra-
tive law judge (ALJ) denied the joint motion. Hearings to
consider evidence relevant to the issue of system benefits were set
to begin March 5, 1990. Luz was given a deadline of February 6,
1990 for the filing of rebuttal testimony on the subject of system
benefits. SCE and DRA were given until March 20, 1990 to file
their rebuttal on that subject. In addition, SCE and Cal Energy
were instructed to notify the Commission by February 6, 1990 as
A-4
to whether or not a cost allocation agreement between those
parties had been achieved. On that date, the parties reported that
no agreement had been reached. The parties were directed to file,
by February 20, 1990, testimony proposing the appropriate alloca-
tion of transmission line costs among SCE and Cal Energy.
On February 20, 1990, in addition to distributing its written
testimony, Cal Energy filed a motion which, in effect, sought
summary judgment on the issues of system benefits and cost
allocation. On February 26, 1990, the CEC filed a Motion for
Declaration of Applicable Law which complemented the Cal
Energy motion. Subsequently, SCE and DRA responded to the
motions in writing.
In addition, Luz raised a discovery matter concerning the
timeliness of SCE’s responses to Luz data requests related to the
system benefits issue. In a telephone conference, the parties
agreed to a schedule for the completion of discovery. Luz indi-
cated that the timing of discovery would make it unable to
prepare for cross-examination in the further hearings set to begin
on March 5, 1990 and requested a delay of the evidentiary
hearings. As a result, hearings on March 5, 1990 were limited to
oral argument of the pending Cal Energy and CEC motions. On
March 5, 1990, both motions were denied. Cal Energy requested
that the March 5 rulings be certified to the full Commission for
interim appeal. On March 19, 1990, that request was denied.
Evidentiary hearings were held on March 19, 20, 21, 22, 26, 27,
and 28, 1990. On the last day of hearings, the proceeding was
submitted, pending receipt of late-filed Exhibit 48 (addressing
business relationships between Luz and SCE and between Cal
Energy and SCE other than those stemming from the standard
offer agreements) and final briefs. The ALJ issued a ruling on
April 18, 1990 which, among other things, admitted Exhibit 48
into evidence. The exhibit is comprised of copies of four contracts
signed by SCE and its affiliates and by either Cal Energy or Luz
with certain portions redacted by SCE under a claim of confiden-
tiality. On April 20, 1990, DRA filed a motion requesting that all
of the redacted portions of the contracts be admitted into evi-
dence and that Exhibit 48 be supplemented with selected materi-
als from Exhibit 87 in Application (A.) 88-02-016. Concurrent
A-5
opening briefs were filed on April 16, 1990 and reply briefs were
filed on May 1, 1990.
Comments on the Proposed Decision were filed by SCE, DRA,
Luz, Cal Energy, and IEP. Some changes have been made to this
decision in response to comments. The CEC moved for accept-
ance of a late filing of its Opening Comments. According to the
motion, the CEC inadvertently neglected to file the comments,
although they were mailed in a timely manner to all parties. DRA
opposes the motion not only because the comments were not filed
in a timely manner, but because they substantially exceeded the
prescribed page limit and consisted largely of reargument, instead
of focusing on factual and legal error. The motion is denied,
primarily due to the CEC’s failure to comply with Rule 77.3 of
the Commission’s Rules of Practice and Procedure which limits
the scope of comments to a proposed decision.
Ill. The CPCN/CEOA Process
Two different regulatory schemes define this Commission’s
responsibilities in reviewing requests for the approval of new
electric transmission projects. Public Utilities (PU) Code Section
1001, et seq. states that a utility must receive a CPCN from the
Commission before it can begin the construction of a new line.
Public Resources (PR) Code Section 21000 et seq. (CEQA)
requires that the CPUC, as lead agency for this type of project,
prepare an EIR assessing the environmental implications of the
proposed project for its use in considering the request for a
CPCN.
The CPCN requirements go beyond a determination that a new
project is necessary. Before granting a CPCN, the Commission
must consider an analysis of the financial impacts of the proposed
project on the utility’s ratepayers and shareholders. The Commis-
sion must review the expected cost of the project and for those
projects estimated to cost more than $50 million, it must set a
cap, Or maximum amount which can be spent by the utility on the
project without seeking further Commission approval. In addition,
the Commission has a statutory obligation, even in the absence of
A-6
CEQA, to give consideration to the following factors as a basis for
granting any CPCN:
1. Community values.
2. Recreational and park areas.
3. Historical and aesthetic values.
4. Influence on the environment.
CEQA requires the preparation of an EIR where there is
substantial evidence that a project may have a significant effect on
the environment. The determination as to whether or not an EIR
must be prepared is to be made by the lead agency, which is also
responsible for the preparation and certification of the EIR. The
lead agency is the governmental body with primary authority over
the proposed project. For transmission lines that would carry
power from a thermal generating facility to the first point of
interconnection with the utility system, the CEC is the lead
agency. For all other transmission lines, such as the one proposed
here, this commission is the lead agency.’
In preparing the EIR, the lead agency must consider the full
range of alternatives to the proposed project, including the alter-
native that there be no new project at all. The lead agency must
identify all significant and potentially significant impacts of the
proposed project, identify the mitigation measures available to
lessen those impacts, and determine whether those measures
would reduce the impacts to an insignificant level. If it is
determined that the project will still have a significant impact on
the environment even after all reasonable mitigation measures are
applied, the CPCN must be accompanied by a statement of
overriding consideration explaining why the project should still be
approved. In any event, the lead agency cannot approve the
CPCN until it has certified that the Final EIR is complete. The
? Although the Commission’s statutory jurisdiction includes all trans-
mission lines that are part of the integrated utility system, the CPUC
has chosen to limit its review to those lines that are designed for
immediate or eventual operation at any voltage in excess of 200 kV. See
General Order 131-C.
ooo oem dill
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permit that is finally issued must be conditioned on completion of
the adopted mitigation measures.
IV. The Need for a New Transmission Line
Cal Energy has constructed its BLM and Navy 2 facilities at
China Lake in the Mojave Desert. They have a combined net
capacity of 150 megawatts (MW). These units are located
approximately 43 miles north of the Kramer Substation. Cal
Energy contracted with an SCE affiliate for the construction cf a
220 kV line to SCE’s Inyokern Substation where the conductor
loops around the substation and is strung on the formerly vacant
side of a series of SCE towers which carry the line down to the
Kramer Substation.
Luz has constructed and brought on line its Solar Energy
Generating Station (SEGS) Unit VIII at its Harper Lake facility
in the Mojave Desert. Each SEGS unit at Harper Lake is
designed to have an installed generating capacity of 80 MW. Luz
plans to bring SEGS IX on-line in September, 1990 and another
unit on-line by the end of each year from 1991 through 1993. In
an agreement with SCE to be discussed in more detail later, Luz
has also committed to sell to the utility another 20 MW of output
from one of its Harper Lake units. Altogether, the SEGS genera-
tion from Harper Lake is expected to have a maximum capacity
of 480 MW. While the other units are all under contract for sales
to SCE, the last unit, SEGS XIII, is under contract to San Diego
Gas and Electric Company (SDG&E). Power from SEGS XIII
would be wheeled across SCE lines for delivery to the SDG&E
service territory if the merger between SCE and SDG&E, which
is the subject of A.88-12-035, is not approved.’ Luz has con-
structed a 12-mile 220 kV transmission line to deliver power from
Harper Lake to the Kramer Substation.
’ As of the date of submission of this case, SCE and Luz had not
entered into an agreement governing the transmission of power from
SEGS XIII.
i
A-8
No one disputes the fact that SCE is required under the federal
Public Utilities Regulatory Policies Act (PURPA)* to intercon-
nect with and purchase power from the QFs developed by Cal
Energy and Luz.’ In addition, all parties appear to agree that SCE
needs to add additional 220 kV transmission capacity in order to
move all of the power from these QFs as far south as the Victor
Substation. It is agreed that if the QF generation is to be
delivered to the Kramer Substation, it will be necessary for the
additional 220 kV transmission line to interconnect at Kramer.
Figure | is a map indicating the location of transmission lines
and substations related to this project.
Cal Energy has lodged Figure | with the Court under separate
cover.
Power moving from the Kramer Substation toward the SCE
load center is delivered to the Lugo Substation, from which it can
be routed on existing 500 kV lines. The Victor Substation is
between Kramer and Lugo. SCE has two 220 kV lines which
currently carry power directly from Kramer to Lugo. James G.
Kritikson, SCE’s Transmission Planning Manager, testified that
these two circuits and the related transformers will be fully loaded
when all existing and previously committed SCE and QF genera-
tion resources come on line. Kritikson’s load flow diagrams
indicate that power is currently imported to Victor from Lugo.
SCE will be able to serve load in the Victor area with power
heading south from Kramer by interconnecting additional trans-
mission capacity at Victor. The remaining power will continue to
flow from Victor toward Lugo on existing lines.
*16 U.S.C. 824a-3; 18 CFR 292.303.
* Throughout this discussion, it should be remembered that SCE is
not under contract to purchase power from SEGS XIII. Nor has it been
specifically asserted that SCE is under any obligation to interconnect
with SEGS XIII. However, since only one point of interconnection will
allow for the transfer of the power anticipated to be delivered by all units
II1V-XIII, we will not repeatedly allude to this distinction. In addition,
no one has argued that the need for new transmission facilities would be
in any way different if SEGS XIII was not part of the consideration.
A-9
Kritikson calculates that if all of the generating sources which
are already committed to use the existing Kramer to Lugo lines
were to operate at full strength, they would fill those lines to 102%
of their capacity. It is evident that the existing Kramer to Lugo
lines cannot be committed to carry the output of any more
generating facilities.
The record indicates that while it is possible to carry more than
100% of capacity on a given line, it is not advisable to do so. Line
losses would be great and the conductors would be in danger of
accelerated deterioration. However, Kritikson testifies that, with-
out the addition of the Cal Energy and Luz facilities, there is very
little danger of ever taxing the existing lines to this extent. First,
to do so would require that all the facilities which are to rely on
these lines be in operation at full strength at the same time. This
is unlikely. Second, as demand grows in the Kramer area, more
power will be diverted to serve local load, leaving less power to be
transmitted to Lugo. At the same time, all parties appear to agree
that there is a need to add more transmission capacity if addi-
tional generating sources are to deliver power through Kramer.
Even if the power from the Cal Energy and Luz facilities that
are the subject of this proceeding was to be delivered not to the
Kramer Substation but directly to Victor or Lugo, there seems to
be agreement among the parties that new transmission lines
would be needed. As will be discussed below, the only other
technically feasible means of delivering this power to the SCE
grid reflected in the record would involve building radial lines
from the China Lake and Harper Lake areas directly to Victor or
Luz. Regardless of the merits of that approach, it clearly would
not obviate the necessity of adding new transmission facilities.
V. Description of the Proposed Project
SCE proposes to construct a new, 38-mile long, double-circuit®
220 kV transmission line connected in the north to the Kramer
° A double circuit line is one which allows for the stringing of two sets
of one circuit conductors on the same towers. One circuit is a set of
3-phase conductors.
on rere
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Substation, located at the small community of Kramer Junction
at the intersection of U.S. Highway 395 and State Highway 58.
The proposed route would be parallel to Highway 395 for the first
22.2 miles. SCE seeks to build this portion of the line immedi-
ately west of the existing transmission lines that are also roughly
parallel to Highway 395. As proposed, the line would continue to
run parallel to one set of existing lines or another all the way to its
southern terminus at the Victor Substation, which is located on
the south side of State Highway 18 near Abode Corners. Along
the way, the proposed route is diverted to avoid running through
the small commercial and civic center which hugs Highway 395
in the town of Adelanto.
As explained in the EIR, to accommodate the new line, the
existing right-of-way between the Kramer and Victor substations
would need to be increased by 75-100 feet, depending on the
specific locations of the transmission towers. Most of the proposed
project would be constructed on conventional double-circuit lat-
tice steel towers. In two areas, however, different towers would be
used. One instance would be where four single circuit towers
would be used to enable the line to cross under an existing 500 kV
line owned by the Los Angeles Department of Water and Power.
The other instance is where single-pole tubular steel towers would
be used to enable the new line to pass within an existing 150 foot
right-of-way through an industrial park in Adelanto. SCE pro-
poses buying and moving two existing homes which sit in the
proposed right-of-way on the northwest side of Adelanto.
The proposed project also includes certain modifications and
additions to the Kramer, Victor, and Lugo substations. At the
Kramer Substation those changes include:
1. the construction of two additional positions in the existing
220 kV switchyard to terminate the new circuits,
2. the installation of one 115 kV capacitor bank, and
3. the installation of necessary protection equipment.
At Victor, those changes include:
1. the construction of four new 220 kV line positions in a new
220 kV switchrack which will form the termination of the new
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transmission line and the two existing Lugo-Victor 220 kV
circuits,
2. the installation of two 220 kV bank positions,
3. the installation of two 220 kV capacitor banks, and
4. the installation of necessary protection equipment.
Finally, additional protection equipment will be required at the
Lugo Substation as a result of increased loading caused by the
proposed project.
VI. Cost Caps and Cost Estimates
for the Proposed Project
In compliance with PU Code Section 1003(C), SCE included
in its application in this proceeding “an appropriate cost estimate”
for the project. The Commission is required by PU Code Section
1005(b) to specify the estimated cost in the certificate which it
issues for the project. Further, for facilities estimated to cost more
than $50 million, PU Code Section 1005.5 requires that the
Commission specify, in the certificate, a maximum cost deter-
mined to be reasonable and prudent for the facility. This cost cap
can be increased by the Commission after the certificate is issued
if the utility applies for an increase and if the Commission finds
both that the project will actually cost more than was initially
anticipated and that the project is necessary and convenient even
at the higher cost.
DRA argues that a limit, or cap should be placed on the
amount that SCE can spend on this project on behalf of its
ratepayers without seeking further Commission approval. SCE
opposes this proposal. In addition, SCE and DRA disagree as to
how much the proposed project should be expected to cost.
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A. Project Cost Estimates
Table 1 provides a comparison of the SCE and DRA cost
estimates:
Table |
Project Cost Estimates
(in $million)
SCE DRA
Pe ho dw bev e dus cvekevereeus 32.225 30
Substation Improvements ................. 18.155 13
po eee 50.38 43
DRA’s transmission cost expert, Ray Valaitis, prepared DRA’s
cost estimate for the new transmission line by using the Bonne-
ville Power Administration’s (BPA) generic cost-per-mile esti-
mates. SCE’s expert, Alexander Mateuchev, tried to develop a
more project-specific forecast by estimating labor and material
needs and applying current costs.
SCE argues that the DRA approach is too imprecise and does
not take into account various peculiarities of the proposed project.
For instance, Mateuchev points out that Valaitis did not add costs
related to the replacement of % mile of existing steel lattice
towers with steel poles through the Adelanto Industrial Park. He
estimates that process to add another $1.3 million to the project
cost.’ In addition, SCE’s estimate for permitting and regulatory
expenses exceeds that of DRA by $644,000. According to
Mateuchev, these regulatory costs include support of the CPCN
process, CPUC application fees, preparation of environmental
studies and reports, and BLM and Edwards Air Force Base
approval. Mateuchev argues that the DRA estimate, which is
based on BPA costs, does not reflect the difference between
regulatory practices in BPA country (Washington and Oregon)
and those in California. Finally, Mateuchev argues that DRA
neglected to include sales tax which would be paid for the
’ The EIR indicates that SCE subsequently proposed to double the
length of the segment that will consist of steel poles. This presumably
would increase the project cost in a manner not reflected in the SCE
estimate.
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construction materials. He estimates those taxes to total
$690,000.
DRA argues that the proposed line is very simple to construct,
the terrain in the area is flat and open, and anticipated mitigation
expenses are relatively low. DRA argues that SCE has provided
virtually no justification as to why costs for this line should exceed
the average. Valaitis acknowledges that SCE’s cost estimating
approach “has the inherent capability of being more precise than
the one the I prepared,” but that SCE’s approach does not always
represent the only reality. DRA agrees that its estimate did not
include the sales tax figures or the added costs resulting from the
removal of % mile of lattice work towers and their replacement
with steel poles. However, DRA argues that its $2 million
contingency provides the cushion necessary to cover these costs.
DRA also points out that SCE may have been able to avoid the
need to replace lattice towers if it had bought a wider right-of-way
through the Adelanto Industrial Park at an earlier date. As for the
estimate of regulatory expenses, DRA argues that SCE has not
demonstrated the existence of any difference between California
regulatory requirements and those in the Pacific Northwest which
would make it more expensive to license a facility in this state.
Finally, DRA argues that SCE was unreasonable in assuming that
overheads would add another 30% to the project costs. DRA says
that, since most of the project will be built by Luz and since Luz
is a smaller organization, it is more realistic to expect that
overheads would add only 20% to the project cost.
In its rebuttal testimony, SCE takes exception to several
aspects of DRA’s estimate of the costs of substation improve-
ments. In preparing its estimate of Kramer Substation costs,
DRA used 1978 cost data which was then escalated to 1991 value.
SCE argued that DRA should have started 1987 cost data and
should have made allowance for the added cost of making
changes on an energized substation such as Kramer. SCE says
that these changed assumptions would have added $1 million to
DRA’s cost estimate. SCE argued that, in considering Victor
Substation costs, DRA failed to use updated 220 kV circuit
breaker costs, failed to include the cost of overhauling and
refurbishing eight system breakers, and omitted the added cost of
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station grounding, site grading, relay equipment, station light and
power, crushed rock, and line and bank conductoring. According
to SCE, these factors account for $5 million in additional ex-
penses. Finally, SCE argues that DRA did not include $245,000
for specific protection improvements for the Lugo Substation,
plans for which were finished after the application for this matter
was filed.
DRA did not respond to each of these concerns, but instead
emphasized that its estimate included a $2 million dollar contin-
gency figure and that SCE used a very high factor for overheads.
We will adopt SCE’s estimate of project costs. While the
provision of a detailed cost estimate does not guarantee accuracy,
it appears that SCE has used a reasonable approach to assembling
its prediction of project costs. We assume that when DRA added
a $2 million contingency amount to its original estimate, it
intended for that amount to be applied to unexpected expenses,
not to be absorbed as a means of covering predictable expenses
that DRA failed to identify. According to SCE, the sales taxes
and lattice tower replacement costs total about $2 million. If the
contingency amount is considered to include these figures, then
there is no contingency left to cover unexpected costs.
The parties simply disagree about the expected regulatory costs
and overheads. SCE has offered us little guidance as to how it
arrived at its estimate of regulatory costs. The DRA has provided
an estimate that can more easily be explained, since it relies on a
cost estimate methodology that is used by the BPA. We are
nonetheless, for the reasons discussed below, willing to adopt
SCE’s estimate for these expenses.
Neither SCE nor DRA has adequately explained its estimate of
overhead expenses. Both parties applied a 30% rate. Nonetheless,
DRA argued that a lower rate is more applicable to a smaller firm
such as Luz, which is expected to construct most of the project.
Unfortunately, DRA offered little support for its assertion that
smaller firms face lower overhead costs.
While the proposed project is relatively straightforward, we are
imposing mitigation requirements and other permit conditions
which may not have been anticipated when SCE made its
be ented Sa
A-15
estimate. The mitigation monitoring program and other condi-
tions placed on the construction of the project may add to
regulatory and other costs.
At the same time, DRA’s cost estimate demonstrates that SCE
has taken a very conservative approach in developing its estimate.
SCE should be able to complete the project within its projected
budget.
In adopting a cost estimate, it should be remembered that this
figure is used for placing the application in a financial context and
does not give SCE license to pass any particular amount of money
on to ratepayers. As is true with ail capital additions, SCE will be
required to demonstrate the reasonableness of all of its expendi-
tures related to this project before ratepayers will bear these costs.
B. Cost Cap
PU Code Section 1005.5(a) states:
“Whenever the commission issues to an electrical or gas
corporation a certificate authorizing the new construction...
of the corporation’s plant estimated to cost greater than fifty
million dollars, the commission shall specify in the certificate
a maximum cost determined to be reasonable and prudent
for the facility...”
If the project later proves to cost more than the amount specified
in the certificate, the utility is required to ask the Commission to
increase the maximum cost (cost cap).
When the Commission considers whether or not to issue a
certificate, it normally must compare the estimated cost of the
facility with the expected benefits and with the cost of other
feasible project alternatives. The cost cap process set forth in PU
Section 1005.5 allows the Commission to ensure that a project
which appeared to be cost-effective when it was certified does not
move forward unchecked if subsequent cost escalation makes
completion of the project economically unwise. The fact that the
Commission is required to establish a cost cap for projects
expected to cost more that $50 million assures that, at a mini-
mum, cost caps will be applied to al! new major projects.
A-16
The estimated cost of this project is slightly more than $50
million. DRA proposes that a cost cap be established, regardless
of estimated cost. SCE argues that since the ratepayers’ share of
the cost is likely to be far less than $50 million, the cost cap
provision of Section 1005.5 does not apply. DRA responds that
Section 1005.5, in establishing the cost cap requirement, is blind
to cost allocation. It simply requires that a cost cap be set
whenever the cost of the project as a whole is expected to exceed
$50 million. We agree. By adopting the highest estimate of
project cost, we have helped to assure that the project can be
completed within the limits of the cost cap. In addition, this is a
short duration project (to be completed before the end of 1991)
which is, therefore, less vulnerable than other projects to severe
inflation of other unexpected cost effects.
In its comments on the Proposed Decision, SCE argues that
the conditions placed on the certificate, outlined below, may add
to the cost of the project. SCE asked for permission to file an
updated cost cap estimate within 90 days of the date at which this
decision becomes final. SCE proposes that its revised estimate
then become the cost cap. The request is denied. Section 1005.5
says that the utility can apply for an increase in the cost cap at any
time after the application is approved. This is approach that SCE
should follow if it determines at any point the the cost of the
project will exceed $50.3 million. Following this approach will
help to assure that SCE properly justifies any request for an
increase in the cap.
VII. Ratepayer Cost Responsibilities
Traditionally, utilities apply for CPCN for new projects which
will be placed into the utility’s rate base, allowing the utility to
earn a rate of return on its investment and to depreciate its capital
investment over a reasonable period of time. It is the ratepayers
who usually pay these costs. The provisions of the PU Code
related to CPCN request the Commission to consider the cost-
effectiveness of a proposed project as a means of meeting a
perceived need before saddling ratepayers with the economic
burden of new investments. PU Code Section 1003(d) requires
that the applicant for a CPCN demonstrate, among other things,
bit ea:
A-17
the financial impact of the new project on the company’s ratepay-
ers. In order to understand the ratepayer impacts, it is necessary
to estimate how much ratepayers will be asked to spend for the
project. This requirement applies regardless of the reasons that
the project is needed. Section 1005(b) states that the certificate
granted by the Commission must specify all of the characteristics
of the plant set forth for the applicant to address in Section 1003.
Thus, in order to grant a certificate for a proposed project, we
must determine, among other things, the portion of the project
cost which will be borne by ratepayers.
In November 1988, SCE signed integration and interconnec-
tion facilities agreements with Luz and Cal Energy. The agree-
ments called for the construction of the proposed project. As an
interim means of carrying Luz and Cal Energy power between
Kramer and Victor, the parties agreed to the rebuilding of an
existing 115 kV line. This strategy was pursued because the 115
kV project could be accomplished without coming to this Com-
mission for a CPCN. It was agreed that Luz and Cal Energy
would split the cost of the rebuild of the 115 kV line. Further, it
was agreed that Luz, Cal Energy, and SCE would evenly share
the cost of the proposed project pending our determination of the
proper cost responsibility for each party.
When it filed its application in March of 1989, SCE indicated
that it was negotiating separately with Luz and Cal Energy in an
effort to agree on a final proposed allocation of the cost of the
proposed project among Luz, Cal Energy, and SCE’s ratepayers.
On November 17, 1989, SCE and Luz signed an agreement
allocating costs for the proposed project and other related facili-
ties between Luz’ and SCE’s ratepayers. SCE has asked us to
approve the SCE/Luz agreement in this application. Initially,
DRA opposed this agreement. It has since removed its opposition
and no one is currently arguing against adoption of the agreement.
SCE and Cal Energy apparently continued to work toward an
allocation agreement until well into this proceeding, but failed to
come to terms. At one point, counsel for Cal Energy asserted that
his client had no interest in negotiating an allocation of the project
costs. SCE has proposed that all project costs not allocated to Luz
under the terms of their agreement be allocated to Cal Energy.
A-18
Cal Energy argued that all such costs should be borne by
ratepayers. The CEC supported Cal Energy’s position. The DRA
proposed a hybrid approach to cost allocation. Before considering
issues related to Cal Energy’s share of the project costs, we will
look in more detail at the SCE/Luz Agreement.
A. The SCE/LUZ Agreement
SCE has asked the Commission to approve its agreement with
Luz under which Luz would bear the following costs:
1. 44.8% of the cost of the proposed project.
2. 100% of the cost of the 220 kV transmission line from
Harper Lake (site of the SEGS VIII-XIII units) to the Kramer
Substation and the cost of the line’s termination at the Kramer
Substation.
3. Ali operation and maintenance (O&M) costs related to the
Kramer Substation termination facilities for the Luz 220 kV line.
4. 52% of the cost of the Kramer-Victor 115 kV transmission
line rebuild which provides an interim means for transmitting Luz
and Cal Energy power.
5. 100% of the cost of metering and telemetering equipment.
The two parties further agreed that while SCE would engineer,
design, and provide equipment specifications for the proposed 220
kV line, ".uz would procure the needed equipment and construct
the line for a fixed cost. Under this arrangement, Luz and SCE
expect that the line can be built as much as a year earlier than
was previously planned. That is because Luz is willing to bear the
risk of planning and procurement costs while the CPCN is
pending. Luz would deed ownership of the line to SCE. SCE
would be fully responsible for planning and constructing the other
facilities included in the proposed project. SCE agreed to pay all
of the cost of upgrading the Lugo substation and all O&M costs
for facilities south of the Kramer Substation.
B. Proposals for Allocating the Remainder of the Project Cost
If the SCE/Luz Agreement were to be approved, it would still
be necessary to determine what portion, if any, of the remaining
55.2% of the project cost should be borne by Cal Energy. SCE
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argues that since the new line is being built exclusively to serve
the new QFs, all costs for the project not paid by Luz should be
paid by Cal Energy. Cal Energy, on the other hands, says that
ratepayers should pay all of the remaining project costs. The CEC
agrees with Cal Energy. The DRA proposes that Cal Energy be
required to pay the same amount as Luz (44.8%) and that the
remainder (10.4%) be paid by SCE’s ratepayers. In support of its
position that all remaining costs should be borne by ratepayers,
Cal Energy has relied almost exclusively on its interpretation of a
1985 decision by this Commission. Because of the weight given
this decision by Cal Energy, we will now explore the decision and
the arguments related to it.
C. D.85-09-058 and Its Significance
In early 1984, the Commission was approached by Pacific Gas
and Electric Company (PG&E) and various QFs about limita-
tions in the near-term availability of transmission capacity in
portions of Northern California. As more and more QF develop-
ers sought to enter into standard offer agreements with PG&E for
the sale of power, it was becoming evident that transmission
limitations could constrain PG&E’s ability to bring new facilities
on line. On April 18, 1984, the Commission issued Order Institut-
ing Investigation (I.) 84-04-077 to examine these alleged trans-
mission constraints. The Commission also wanted to assess the
extent of any limitations in other utilities’ transmission systems
which would affect QF development.
The respondent utilities filed statements of anticipated limita-
tions on their transmission systems over the following ten years
which might affect QF development. In those statements, only
PG&E predicted that it would have significant constraints in its
northern transmission system.
After submission of the utilities’ statements, the Public Staff
Division (now DRA) held several workshops in which an interim
solution was developed to address the PG&E constraints specifi-
cally. In addition, in the workshops, parties formulated a mile-
stone procedure for tracking the development of individual QF
projects and discussed various approaches for allocating costs
related to new transmission projects. Hearings were held in April,
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1985, on three subjects, which included the utilities’ transmission
constraints and cost allocation approaches.
In September of that year, the Commission issued D.85-09-058
which addressed these issues. That decision contained the follow-
ing language, which has been carefully dissected and analyzed by
all of the parties to the current proceeding:
“QF deliveries are a significant part of each utility’s resource
plan. Accordingly, utilities must plan for and otherwise
enable QF facilities to interconnect with their transmission
systems in an expeditious manner. We recognize that both
the diversity and the number of emerging QFs in PG&E’s
system have created new problems for the company’s trans-
mission planners. However, PG&E along with the other
utilities must learn to facilitate the addition of QF power as it
already has learned to accept power deliveries from all other
resources.
“The parties have agreed among themselves that QFs should
not be responsible for the cost of transmission facilities which
serve multiple purposes. The parties find since the ratepayers
in the past have paid for these transmission facilities, the
ratepayers should continue to absorb the cost as long as the
transmission facility has system-wide benefits. A QF is
responsible only for interconnection and other facilities that
have no system-wide benefits and are solely beneficial to the
QF. This approach eliminates the need for a difficult cost
allocation among the various users of a transmission facility.
“System-wide benefits, can mean many things as shown in
SDG&E’s list of factors affecting its transmission planning.
Thus, we believe that nearly all transmission facilities argua-
bly may have some system-wide benefits. Bulk transmission
lines by definition have system-wide benefits. And nearly all
area lines probably have some system-wide benefits. Thus,
QFs will assume cost responsibility only on the rare occasion
that an area line lacks any perceptible system-wide benefit.
“On occasion, a transmission facility’s cost may outweigh its
system-wide benefits. In this event, the QF perhaps should
be responsible for any excessive cost caused by the intercon-
A-21
nection of its facility to the utility’s system. A rigorous cost-
benefit analysis, however, touches upon many as yet unde-
fined criteria. We have yet to determine a long-run avoided
cost methodology for QFs. We have not yet adopted consis-
tent energy reliability criteria for all utilities. The cost of
transmission service is just one piece to the puzzle of
properly valuing QF power. Thus, for the moment, we will
allow utilities to follow the general principle that as long as a
transmission facility, has system-wide benefits, the utility’s
ratepayers are responsible for the prudent and reasonable
cost. The QF is responsible only for interconnection cost and
other special facilities which have no system-wide benefits.
Refinement of this principle must wait for our determination
in the long-run avoided cost proceedings.”
Cal Energy has argued that the above language is clear on its
face, that, as a matter of definition under D.85-09-058, the
proposed project has system-wide benefits, that the Commission
is bound by law to adhere to the principles set forth in that
decision and that Cal Energy relied on its interpretation of the
decision while developing its projects. Cal Energy further argues
that a detailed analysis of the proposed project would demonstrate
that the new line would provide substantial system benefits. For
that reason as well, Cal Energy asserts that we are bound by law
to absolve thie QF from all cost responsibility for this project. The
CEC and Luz agree with Cal Energy’s position. SCE argues that
the 1985 decision allows for a case-by-case examination of the
system-wide benefits question, that the Commission is not bound
by law to adhere to the 1985 decision in any event, and that a
detailed analysis demonstrates that the proposed project has no
system-wide benefits. SCE also argues that Cal Energy’s claimed
reliance on its interpretation of the 1985 decision was unjustified,
was not genuine, and does not prevent the Commission from
reinterpreting the decision. In all significant respects, DRA agrees
with SCE. We will now address each of these arguments in
greater detail.
1. Is the Decision Clear on its Face?
The 1985 decision cited above established a Commission policy
which favors having ratepayers bear the cost of new transmission
ae ere a ee ee
A-22
lines which serve beneficial purposes other than allowing for the
interconnection of QFs. This policy is set forth clearly in the
Conclusions of Law and Ordering Paragraphs of the decision. The
1985 decision provides far less clarity as to how to determine
whether or not those other beneficial purposes exist in a given
instance. Cal Energy and the CEC argue that the 1985 decision
provides no room for misinterpretation; the discussion section
contains the statement that “Bulk transmission lines, by defini-
tion, have system-wide benefits.” This statement is repeated as a
Finding of Fact in the decision. SCE appropriately points out that
this finding is not an element of any of the conclusions which
follow.
The statement about “bulk lines” leaves us little to go on. The
decision does not define the term.* Cal Energy and CEC suggest
that any line of 220 kV or higher voltage is a bulk line and,
therefore, that any line of such a size produces system-wide
benefits by definition. However, it is not logical to suggest that
size alone produces system-wide benefits. For instance, Cal En-
ergy’s witness Lewis stated that, in his opinion not all radial lines
produce system-wide benefits, for reasons that don’t necessarily
relate to the size of the conductors. He drew a distinction between
the line strung by Cal Energy on existing SCE towers which could
at least produce future system-wide benefits if it was intercon-
nected at the Inyokern Substation, and a more typical radial line.
A more typical radial line cannot usually add to system reliability
since it does not contribute redundancy to the transmission
system and usually does not provide excess capacity, since it is
likely to be sized appropriately to carry the anticipated load.
Lewis suggests that the latter type of line does not produce
system-wide benefits. The 220 kV line built by Luz to carry power
from Harper Lake to the Kramer Substation seems to fit the
* Cal Energy argues to the contrary by referring to mimeo pp. 7 and 8
of the decision. However, those pages merely set forth data supplied by
parties to the case and provide little guidance as to how the Commission
intended to use the term “bulk power.” Simply because, some 220 kV or
230 kV lines were referred to as bulk lines doesn’t mean that all such
lines are “bulk” by definition.
287 OR A
A-23
latter description. No party has argued that this line produces
system-wide benefits. To the contrary, as part of its agreement
with SCE, Luz has agreed to pay for the full cost of that line.
Either some 220 kV lines are not bulk lines as the Commission
used that term in 1985, or it simply is not true that all bulk lines
have system-wide benefits. In either event, the 1985 decision is
not as clear as some have argued. Cal Energy argues that all
parties to Commission proceedings understand that all lines over
200 kV are bulk lines. Cal Energy cites a prior SCE statement in
an earlier proceeding as proof. However, PG&E adds that bulk
lines can be distinguished by a number of characteristics other
than voltage rating. In its opening brief, PG&E argues:
“For example, the specific proposed upgrades discussed by
the Commission in D.85-09-058 can be distinguished by
their function. These proposed upgrades had a generalized
function of supporting power transmission throughout the
utility electric system. In contrast despite their voltage rat-
ing, the primary function of the lines that are the subject of
Edison’s application is to gather output from remote QF
projects.
“The developers of these QF projects had their own reasons
for siting them in locations remote from Edison’s load center.
Edison’s ratepayers should not automatically be responsible
for all costs of system upgrades necessary to accept this
power merely because 220 kV lines and associated equip-
ment are involved.”
Finally, SCE offers evidence that the Commission had a
broader definition in mind when it issued its decisions addressing
the allocation of bulk transmission line costs. SCE points out that
D.84-08-031 states that it modified D.83-10-093 to conform to
PG&E’s position, and then argues that PG&E does not distin-
guish between bulk and area lines on the basis of voltage. D.84-
03-092 (issued in the same proceeding as D.83-10-093) quotes a
letter from PG&E’s attorney in which 230 kV lines areas are
described as both bulk and area lines: “Bulk transmission capacity
limitations occur on PG&E’s 230 and 500 kV transmission
system, and area transmission limitations occur on PG&E’s 230,
115 and 60 kV system.” (D.84-03-092, p. 61.) We are left
eee
A-24
without clear guidance from prior Commission decisions as to
what constitutes a bulk line. This is a matter which should be
resolved in a generic proceeding, not in a certification forum with
limited parties.
As will be discussed further below, the 1985 decision also fails
to set forth criteria for iudging the existence of system-wide
benefits. It refers to a list of factors used by SDG&E to assess the
benefits of 2 proposed line, but does not assess the merits of that
list, or suggest that it sets forth the appropriate criteria for SCE or
any other utility to employ. For this reason as well, the 1985
decision does not lend itself to ministerial application.
2. Is the Decision Binding?
a. Positions of the Parties
Cal Energy asserts that D.85-09-058 constitutes the definitive
approach to cost allocation, that the Commission is bound by law
to follow that approach in subsequent proceedings, and that the
Commission is reduced in the current application to the ministe-
rial task of applying the findings from the 1985 decision.
Cal Energy argues that the Commission cannot alter or rescind
the 1985 decision in this application, because to do so would
violate the notice and hearing requirements of PU Code Section
1708 and the Fourteenth Amendment of the U.S. Constitution.
Section 1708 says that the Commission may rescind, alter, or
amend any order or decision upon notice to the parties and with
opportunity to be heard. In support of this argument, Cal Energy
cites California Trucking Association v. PUC, (1977) 19 Cal. 3d
240, a case in which the California Supreme Court held that this
Commission cannot issue an ex parte decision in a matter for
which a formal protest has been filed requesting hearing. SCE
responds that there was an adequate opportunity for the affected
parties in this case (Luz and Cal Energy) to be heard and that
the Commission is not restricted in its ability to depart from the
policy set forth in earlier decisions at least so far as it would affect
these parties. Independent Energy Producers argued that a lim-
ited proceeding such as this should not be used as the forum for
changing the cost allocation policy as it applies to all utilities and
OFs.
ee ee ee es
OO ED LAO ON Ste OF PR Rete oe dale)
YN Ein UR Dated a a, Se
A-25
Cal Energy also argues that because of the existence of D.85-
09-058, the Commission has no interpretative discretion as to how
costs should be allocated in this proceeding. Instead, Cal Energy
claims, the Commission is bound by a ministerial duty to simply
enforce and apply the law. In support of this point, Cal Energy
cites Great Western Savings and Loan Assn. v. City of Los
Angeles, (1973) 31 Cal. App. 3d 403, 413, a case in which a state
appeals court said that a local agency must approve a tract map if
it conforms to state statutes and local ordinances. SCE argues
that there is no such ministerial duty here.
Cal Energy argues that if the Commission applied any interpre-
tive discretion to D.85-09-058, it would necessarily have to
produce inconsistent findings that would render any resulting
order subject to annulment. In support of this assertion, Cal
Energy cites Cal. Portland Cement Company v. PUC, (1957) 49
Cal. 2d 171, 176, a case which said that the Commission cannot
issue a valid decision which contains internally inconsistent find-
ings of fact which go to the principal issue involved in the case.
SCE points out that, in Cal. Portland, the Commission was held
to be at fault for having looked at precisely the same facts and
reached two opposite conclusions within the same decision. SCE
argues that there is no relevant similarity between that fact
pattern and the situation faced in this case.
Finally, Cal Energy argues that while D.85-09-058 was the
result of a quasi-legislative proceeding, a CPCN is a quasi-
judicial proceeding and that the Commission cannot do anything
in a quasi-judicial proceeding which is inconsistent with findings
in an earlier quasi-legislative proceeding.
In its Reply Brief, the CEC emphasized its support of the
quasi-legislative/ quasi-judicial argument and analogized the find-
ings in D.85-09-058 to statutes which an administrative agency is
compelled to uphold. The CEC cited Comite de Padres de
Familia, (1987) 192 Cal. App. 3d 528, 535 in which the State
Department of Education and Board of Education inappropriately
failed to comply with a statutory mandate; and County of Orange
v. Flournoy, (1974) 42 Cal. App. 3d 908, 912, in which an agency
was found at fault for assuring an effective date for new legislation
a
A-26
which was inconsistent with the effective date found applicable as
a result of a plain reading of provisions in the state constitution.
While arguing for the sanctity of D.85-09-058, Luz did not
offer an opinion as to whether or not we are bound in any way by
that earlier decision.
SCE argued that, since no Commission can bind a future
Commission, this Commission is not bound to adhere to the
findings in D.85-09-058. The CEC responded that, while it is true
that a later Commission can alter or reverse the course of an
earlier Commission, it must follow the rules of notice and oppor-
tunity to be heard before doing so. The implication is that the
findings in ihe 1985 decision cannot be altered without prior
notice to all the parties to the underlying proceeding, perhaps with
hearings held under the prior docket. SCE responds that it is
sufficient that the parties to the current proceeding have notice
that their nghts might be affected in a manner inconsistent with
the earlier order. SCE also points out that the finding of fact in
the 1985 decision referring to bulk transmission lines was not
essential to the conclusions of law or ordering paragraphs which
followed, and therefore is fair game for reconsideration in any
subsequent proceeding.
DRA argues that it is valid for the Commission to determine
how or if it will apply the findings of D.85-09-058 in this
proceeding. DRA cites the testimony of SCE’s witness Ronald
Luza ihat in 1986, the amount of potential QF resources that had
signed contract to deliver power in the Kramer-Victor area was
more than double that which had been forecasted in the proceed-
ing underlying the 1985 decision. DRA argues that in the field of
administrative law, the doctrine of changed circumstances has
long been applicable, in recognition of the fact that regulatory
agencies with continual jurisdiction are free to change course and
policies as circumstances change. DRA quoted our D.89-04-081,
in the QF complaint case of Colmac Energy v. SCE in which we
said, “our decisions typically rely more on policy concerns, fair-
ness, and common sense than on a detailed study of pertinent
legal precedent.”
Aastha Schl 5 at at dats a SIE dae AB Nh) ip NPR til ts
ee ae
3
i
4
iM
|
2
§
j
b. Discussion
We have no intention of altering, modifying, or rescinding
D.85-09-058 in this decision. While it may be appropriate to
reexamine some of the assumptions behind that decision or to
explore in more detail how it should be implemented, those
questions should be addressed in a broader proceeding, with more
expansive notice to affected parties.’ Here, we must decide how
the cost of one proposed transmission project should be allocated
among those who serve to benefit from its construction. Consider-
ation of the cost allocation of electric transmission facilities,
generically, is beyond the scope of this instant CPCN proceeding.
Any cost allocation which is determined to be reasonable in this
case is based on the facts and circumstances specific to the parties
and testimony in this proceeding and have no further reaching
application.
This appears to be the first time we have been asked to examine
the policy set forth by the Commission in D.85-09-058 in the
context of a specific application for CPCN. That decision said
that utilities should have their ratepayers pay for new transmis-
sion lines that are built to carry QF power and at the same time
provide other system benefits.'° What that decision did not
explain is how those benefits should be measured. The arguments
outlined above were shaped largely by the debate generated when
Cal Energy filed a motion which, in effect, sought summary
judgment on the questions of system benefits and cost allocation.
Cal Energy asserted that we are bound as a matter of law, by
language in the decision to relieve Cal Energy of all cost responsi-
bility. The ALJ denied that motion and stated that it was for the
full Commission to determine how, if at all, the 1985 decision
should be applied to the facts at hand. We agree with the ALJ.
* The Commission will address transmission line cost allocation in a
new, generic investigation on QF transmission issues. This new investi-
gation will be closely coordinated with the ongoing Biennial Resource
Pian Update (BRPU) proceeding.
'° D.85-09-058 also included the proviso that at some future time, a
means might be developed to limit ratepayer contnbutions in a way
which reflects the benefits being received.
A-28
Cal Energy’s arguments were dependent on the assumption
that a 220 kV line can be nothing but a bulk line. As discussed
earlier, the language concerning bulk lines provides little assis-
tance to us because it is ambiguous.
Even if the 1985 decision set forth a clear recipe for determin-
ing who should pay for the proposed project, we would not be
legally bound by that order in this proceeding. None of the
authority cited by the participants in this case stands for the
proposition that this Commission is precluded from reconsidering
its earlier policy positions, so long as adequate notice and opportu-
nity to be heard is provided to those who will be affected. Thus,
we are free to determine that the policy set forth in the 1985
decision is no longer appropriate as it affects the parties in this
case.
The California Supreme Court’s decision in California Truck-
ing, cited by Cal Energy, does not apply to the current situation.
In that case, the Commission had denied a hearing to a party that
filed a formal protest and requested a hearing. The Supreme
Court held that it was a denial of due process for the Commission
to reach a decision in the absence of the requested hearing. In the
current application, the QFs who will be affected by our decision
had adequate notice and opportunity to be heard. In Great
Western Savings decision, which was also cited by Cal Energy, an
appellate court held that a local agency exceeded its discretion
when it disapproved a tract map which complied with state
statutes and local ordinances. There would be no violation of
applicable state laws if this Commission determined that the cost
of the proposed transmission line should be allocated in a manner
not addressed in D.85-09-058 as long as adequate notice and
opportunity to be heard was provided.
In Cal. Portland Cement, a Commission decision was annulled
because it contained conflicting findings that went to a principal
issue in the case. Cal Energy has attempted to suggest that this
decision would preclude the Commission from issuing apparently
conflicting findings in any two cases. In a regulatory environment
where realities are constantly shifting, it would be unrealistic to
hold the Commission to such a standard.
siiess
tO) pes oti
A-29
The effort by Ca! Energy and the CEC to sort our proceedings
and responsibilities into quasi-legislative and quasi-judicial
cubby-holes is similarly nonpersuasive. Virtually every matter
before the Commission is quasi-legislative to the extent to which
it requires commissioners to draw upon a generalized understand-
ing of the subtleties of regulation and of the industries that we
regulate. With the exception of complaint proceedings, every
matter is quasi-legislative in that each proceeding provides an
opportunity to establish or refine Commission policy. At the same
time, each proceeding is quasi-judicial to the extent to which it
depends on an adjudicatory process (focusing on evidence in a
formal record, with sworn witnesses, etc.) and the narrow applica-
tion of facts to law as the basis for a Commission decision. As
such, the legislative/ judicial labels do not form a meaningful basis
for determining when the Commission must rely on prior deci-
sions and when it can formulate new policy.
The CEC cites two cases in an effort to outline the Commis-
sion’s quasi-judicial responsibilities (Comite de Padres, and
County of Orange). In each instance, an agency decision was
overturned because it was inconsistent with statutory law. A
decision by this Commission would be similarly vulnerable if it
conflicted with provisions of the PU Code. For instance, a
decision in a CPCN proceeding might be overturned if it failed to
meet the requirements of PU Code Section 1001, et seq. How-
ever, neither of these cases suggests that the Commission would
have committed legal error if it questioned or interpreted its
earlier policy in a subsequent proceeding.
In addition, we are not ready to agree with Cal Energy and the
CEC that a CPCN proceeding is “obviously” quasi-judicial in
nature. See, for instance, D.93724, a 1981 proceeding that consid-
ered the availability of attorney’s fees for participation in a CPCN
proceeding. After a lengthy discussion of the attributes of various
parts of a CPCN proceeding, the Commission concluded:
“Our decisionmaking process in certification proceedings
involves more than a narrow application of facts to law in the
classical judicial mode. Once we have made the benchmark
quasi-judicial decision that a proposed project conforms to
the officially adopted forecast, there remain many facts that
A-30
are considered on a quasi-legislative basis. These include the
cost of the project, its likely impact on rates, operating and
reliability factors, safety, and environmental impacts. The
range for exercise of our discretion is very broad. There is no
fixed framework of narrow factual issues which governs the
decision-making process. Our process is quasi-legislative on
these questions.”
What this language demonstrates is that the Commission does not
function with a stoplight that signals the nature of its responsibili-
ties in a given proceeding: green light means one can make
legislative determinations, red light means one cannot. Instead,
the Commission must constantly make its decisions within the
constraints and opportunities provided by the state and federal
constitutions and applicable statutory law but with an eye toward
setting the course for the future.
The flexibility allowed the Commission for these purposes was
set forth in a 1925 California Supreme Court decision with an
oddly relevant fact pattern. Postal Telegraph-Cable Company v.
Railroad Commission of the State of California, (1925) 197 Cal.
426, involved:
review of a portion of an order made by the Railroad
Commission whereby [Postal Telegraph-Cable Company]
was allowed one-half of the cost of relocating a portion of its
telegraph line in certain areas in which it is closely paralleled
by a high power transmission line operated by the Pacific
Gas and Electric Company, in order to prevent induction
interferences to [Postal’s] telegraph line which, by reason of
its close proximity to the power line of Pacific Gas and
Electric Company, renders induction unavoidable.
The Postal telegraph line had been built in 1886. In approxi-
mately 1904, PG&E began building a 50 kV transmission line
which, in some places, closely paralleled the Postal line. Because
surges in the PG&E line interfered with the transmission of
telegraph signals, portions of the telegraph line had to be rebuilt
or relocated. The proceeding before the Commission was a
complaint in which Postal sought to have the full cost of the
changes borne by PG&E.
Me Deda 3
SD te, ae dts abet
ots pret anaatien BEES
4 me nme al
A-31
Up to that time, it was Commission policy to levy all such
charges against the owner of the second line to arrive in the
corridor (in this case, PG&E’s). However, in the Postal com-
plaint, the Commission said:
“The evidence in this proceeding shows that both the power
and communication circuits have been in operation for many
years and long before the question of inductive interference
was given serious consideration. Since that time changes
have been made by both utilities in their circuits. In view of
the history of the lines involved in this matter, it does not
appear that the question of priority of construction should be
given material weight in determining the responsibility of
payment of costs resulting in the mitigation of interference.”
On appeal, Postal asked the Court to nullify the Commission
decision because it was inconsistent with established policy. The
Court said (at p. 436):
“The departure by the Commission from its own precedent
or its failure to observe a rule ordinarily respected by it is
made the subject of criticism, but our reply is that this is not
a matter under the control of this court. We do not perceive
that such a matter either tends to show that the Commission
had not regularly pursued its authority, or that said departure
violated any right of the petitioner guaranteed by the state or
federal constitution. Circumstances peculiar to a given situa-
tion may justify such a departure.”
The need for the Commission to be able to adapt its ordinarily
applicable rules to the peculiarities of a given situation is just as
great today as it was 65 years ago. This is one of the reasons that
the Commission cannot be legally bound to apply the 1985
decision to the facts at hand. Later, we will explore some of the
peculiar circumstances which would justify a departure from the
1985 rule in this case.
3. Cal Energy’s Claims of Reliance on the Decision
Regardless of the Commission’s legal responsibility to adhere
to precedent, there are strong reasons for the Commission to
avoid arbitrary departure from established policy. In no area is
this more true than in the QF market. Those considering the
A-32
development of a QF need assistance that their investment
decisions are made with reasonable knowledge of the conditions
which will apply when the power is brought to market.
Cal Energy presented General Donald M. 0’Shei to testify that
the company relied on its interpretation of D.85-09-58. That
decision was issued in September, 1985. Cal Energy signed its
power purchase agreements with SCE the preceding February.
O’Shei says that Cal Energy relied on what he felt to be the plain
meaning of D.85-09-058 and assumed that Cal Energy would face
no cost related to the improvement of SCE’s transmission system
in order to receive power. He said that it is with this understand-
ing that Cal Energy secured financing for its projects. O’Shei says
that when Cal Energy was informed by SCE that the utility
expected Cal Energy to pay for the additional transmission costs it
was “like a bolt out of the blue.”
SCE argues that the facts do not support Cal Energy’s claims
of reliance on the September, 1985 decision. First, the decision to
site the plants at China Lake was made in 1981. Second, the
power purchase contracts were signed before the 1985 decision
was issued. SCE argues that the 1985 decision could not have
affected the choice of plant location. It only could have affected
the decision to proceed with the projects at the sites previously
selected. However, SCE argues that the facts do not support a
claim that financing decisions were related to D.85-09-058 at all.
Table 2 presents SCE’s chronology of significant events related to
the financing decision.
Table 2
Decision or Activity Date
Cal Energy decides to locate at China
Lake (O’Shei, Tr. 8/526) .......... i981
PPAs signed specifying location at China
MO cane ue veh eCeeee see eeeebers Feb.-June, 1985 (O’Shei,
. Tr. 8/525 and 8/539)
First Method of Service (MOS) pro-
vided to Cal Energy for 115 kV lines Nov., 1985 (Luxa,
Tr. 10/815)
A-33
Decision or Activity
Cal Energy commits “substantial funds”
ag 2 § 2. eee
Cal Energy commits “substantial funds”
8. Bet.)
Second MOS to Cal Energy for two 115
gg NERS Se ot oo aa ee ar
First discussion between Edison and Cal
Energy about interconnection at 220
Dl idsc cutie Genie ca waaene seed
Edison told Cal Energy 220 kV upgrades
south of Kramer would be needed to
accept Cal Energy power at 220 kV
and they would be responsible for
Edison agrees to investigate 220 kV in-
terconnection; told Cal Energy they
would be responsible for costs of any
facilities solely beneficial to QFs ....
MOS proposed by Edison for Proposed
Project at QF’s expense ...........
Execution of IIFAs providing for BLM
and Navy II interconnection at 220
kV—$30-352 committed to Navy 2
—$150 M2 committed to BLM.....
Navy II and BLM projects on-line Total
investment = $380 million .........
Date
Mid-1986 (O’Shei,
Tr. 8/529-530)
Mid-1987 (O’Shei,
Tr. 8/529-530)
Aug., 1987 (Luxa,
Tr. 10/815)
Oct., 1987 (Luxa,
Tr. 10/813, 815-816)
Oct., 1987 (Luxa,
Tr. 10/816)
Dec., 1987 (Luxa,
Tr. 10/813-814)
April, 1988 (Ex. 1,
pp. 10-11)
Dec., 1988
(Luxa, Tr. 10/814)
(O’Shei, Tr. 8/535)
Dec., 1989
(O’Shei, Tr. 8/531)
SCE argues that this chronology shows that prior to October,
1987, SCE had offered Cal Energy Methods of Service (MOS)
which contemplated interconnection and integration using 115 kV
lines. SCE asserts that until October, 1987, Cal Energy had no
A-34
basis for even anticipating that it would interconnect and integrate
its facilities at 220 kV levels. Thus, SCE concludes, Cal Energy
could not have been relying upon its belief that D.85-09-058
would require all bulk line upgrades to be paid for by ratepayers in
making any decision to commit substantial funds before that date.
SCE says that when it learned that Cal Energy wanted to
interconnect at 220 kV, it informed Cal Energy that a 220 kV
upgrade south of Kramer Substation would be needed and that
Cal Energy would be responsible for those costs. SCE says that by
the time a contractual agreement to interconnect was signed in
December, 1988, Cal Energy had already spent approximately
$180 million on the two projects.
It is SCE’s position that only one conclusion can be drawn from
this course of conduct. Cal Energy proceeded with construction of
the BLM and Navy II plants regardless of what the ultimate
interconnection and integration costs would be. SCE argues that
Cal Energy purely and simply assumed the risk for those costs,
and they must now accept that risk.
Cal Energy responded by saying that it not only expected that
ratepayers would pay for all new bulk lines, but that they would
pay for all but the most rare area lines as well. Thus, from Cal
Energy’s perspective, it did not matter what size a new transmis-
sion line might be. The company expected that ratepayers would
pay for it.
O’Shei was asked to explain the significance of any reliance Cal
Energy might have placed on its interpretation of the 1985
decision. He said that that reliance affected the structure of the
financing for the project and that any subsequent assignment of
transmission co.‘ td Cal Energy would reduce the profitability of
the projection: in a manner which the company did not anticipate.
Then, he added:
“T suppose, without getting philosophical, that the Commis-
sion would also be interested in the reliance that the citizenry
in general places on its orders and when its orders are issued,
and if the Commission attempts, and in this case succeeded
in an unusual fashion to make those orders crisp and clear,
and the folks rely upon those orders, I would think that the
A smh ENN Mes mnt sn Liles bin Wile 4 Me obit a ioe
A-35
Utility Commission would take a responsibility for the out-
come of that reliance.”
We could not agree more with General O’Shei’s assertion that
the Commission should carefully communicate its policies and
attempt to develop in the marketplace reasonable expectations as
to the conditions which will apply when projects are brought on
line. However, for several reasons, we are not swayed by Cal
Energy’s claims of reliance on the 1985 decision. First, as SCE
has demonstrated, the need and responsibility for transmission
additions to serve these projects was sufficiently ambiguous at the
crucial decision-making points to make it unlikely that Cal
Energy could have reasonably relied on any particular transmis-
sion cost allocation in deciding to go forward. Second, as dis-
cussed above, we cannot agree that the 1985 decision provided the
clear and crisp allocation method that Cal Energy perceived.
Finally, Cal Energy had no reasonable basis for relying on its
assumption that the ratepayers would pay for the transmission
addition regardless of whether it was a bulk or area line.
Fourteen months prior to the time when Cal Energy signed its
power purchase agreement, the Commission issued D.83-10-93,
which discussed the terms applicable to standard offer contracts
for the purchase of electricity from QFs. In that decision, the
Commission voiced many of the same concerns expressed by
General O’Shei about the need for a solid basis upon which a QF
developer can make its investment decisions. In that decision, the
Commission stated:
“The staff has suggested that the applicable tariff rules in
effect at the time the contract is executed should be included
in the standard offer so that the agreement will not be
affected by future Commission-approved revisions of those
tariffs with the exception of costs of facilities ownership
charges. The reason for this recommendation is clear—to
provide maximum contract certainty and to define from the
outset the QFs and the utility’s responsibilities for intercon-
nection costs throughout the life of the contract. This cer-
tainty could prove vital to a QF’s obtaining financing. While
recognizing that such a requirement could impose an admin-
istrative burden on the utility due to the number of QFs
A-36
which might sign standard offers over the years, we believe
that such a step should be undertaken to preserve the
sanctity and certainty of each contract. We will therefore
direct all of the utilities to append to each standard offer the
applicable tariff rules governing interconnection costs, cost-
sharing and refunds, in the form existing at the time the
contract is signed. By doing so, both the QF and utility will
have reference to the exact rules which will govern their
transaction.”
Ordering Paragraph 22 in D.83-10-93, which addressed the then-
applicable approach to new transmission cost allocation, con-
tained the following language:
“12. The utilities’ tariff rules and standard offer provisions
governing interconnection costs and special facilities agree-
ments shall require the following:
oe
a. The QF shall pay for new or additional line capac-
ity if the upgrade is necessary for the utility to receive the
QF’s power.
“b. The cost of any line upgrade undertaken to serve
additional customers or QFs shall be borne by the utility.
“
c. For two or more QFs seeking to use an existing
line, a first come first served approach shall be used... If
two QFs establish the right of first-in-time simultaneously,
the two QFs shall share the costs of any additional line
upgrade necessary to facilitate their cumulative capacity
requirements. Costs shall be shared based on the relative
proportion capacity each QF will add to the line.”
On January 13, 1984, SCE filed with the Commission its
revision to its Rule 21, which mirrors the language contained in
the ordering paragraph cited above. The revised Rule 21 went into
effect on February 12, 1984 «ad was still in effect when Cal
Energy’s power purchase agreements were signed the following
February.
Ten months later, the Commission issued D.84-08-031, which
resolved an Order to Show Cause which had been issued to
PG&E. Although other utilities and QFs were not parties to the
—— ne ee
A-37
proceeding that led to the 1984 decision, the Commission took
the opportunity offered by the issuance of that decision to modify
Ordering Paragraph 12(a) of D.83-10-093 to read as follows:
“The QF shall apply for new or additional area distribution or
transmission line capacity if the upgrade is necessary for the
utility to receive the QF’s power.”
This modification reaffirmed the notion that ratepayers would pay
for bulk line additions but also left the clear signal that area line
additions prompted by the QFs would be paid for by the QFs.
Whether Cal Energy was paying attention to SCE’s Rule 21 or to
the modification of the 1983 decision in D.84-08-031, it should
have expected to be held responsible for the cost of any new area
lines prompted by its transmission needs. Since it could not have
formed a final opinion as to whether the added line would be a
bulk or area line until after it had formed a strong financial
commitment to completing the project, Cal Energy could not
reasonably have relied on an expectation that ratepayers would
have borne all of the expense of any needed transmission
additions.
4. Should D.85-09-058 Be Applied In This Case?
Although we are not legally bound to apply D.85-09-058 in
determining Cal Energy’s cost responsibilities, we are left with the
question of whether it nonetheless should form the basis for our
decision. The simple answer is yes. The 1985 decision has served
us well, because it has provided balance to the negotiating stance
of QFs and utilities who are attempting to resoive transmission
cost allocation issues. Prior to the current application, parties have
largely been able to work out their differences at the bargaining
table. The universal application of D.85-09-058 and subsequent
decisions which interpret that order is the best way to preserve
that balance.
D. System-Wide Benefits
Because the bulk/area line ambiguity does not provide us with
a very simple way of resolving the cost allocation question, we
have carefully examined issues related to system-wide benefits.
We have encountered two major difficulties. First, D.85-09-058 in
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its current form remains ambiguous as to what criteria should be
applied to define the parameters of system-wide benefits. Second,
even if the criteria offered by parties to the proceeding are
assumed applicable, the record does not clearly demonstrate that
the line would create system-wide benefits.
1. The Lack of Clear Criteria
The lack of established criteria for analyzing system-wide
benefits caused the parties in this proceeding to argue as much
about definition as about the nature of the proposed project. In
D.85-09-058, the Commission referred to a set of criteria on
which SDG&E said it relies in assessing the potential benefits of a
new project. However, the Commission did not adopt these
criteria, or comment on their merits. With few specific parame-
ters or criteria available to sharpen the focus, the parties in this
proceeding attempted to apply the SDG&E criteria. However, it
is not clear that ali of the SDG&E criteria are applicable to the
matter of cost allocation. It is also unclear as to what some of the
criteria may entail.
2. Lowering Line Losses
In its opening brief, the CEC stated:
“The proposed 220 kV line is adding substantiai new trans-
mission Capacity to a system that is constrained and subject
to increasingly heavy loads. All of the energy carried on this
- system, whether QF or utility generated, is being transmitted
to serve SCE load. Line losses, currently high, will continue
to increase as new QF generation is added. Adding the new
220 kV line will unquestionably greatly reduce SCE’s line
losses, with the result that SCE will receive at its load center
significantly more capacity and energy than if it did not build
the line. This may seem simple, but it is also irrefutable
common sense. Logic provides this conclusion without com-
puter analyses and expert witnesses.
“Simple logic and common sense are, of course, the first
casualties when lawyers and engineers meet in administrative
hearings to argue about who should pay. So we leave logic at
A-39
the door and enter the arcane world of transmission planning
and computer modeling.”
While CEC’s argument may be appealing and while we share
CEC’s instinct that logic apply, we are not convinced that the new
line will “unquestionably greatly reduce” SCE’s line losses. It
would be extremely useful for someone to present the simple
calculations which would support this logic. However, none of the
analysts, including CEC’s, has taken such a straightforward
approach."'
In considering whether the proposed line decreases system
transmission losses, as with other possible systemwide benefits, we
must separate the effects of the line from the effects of the QFs.
For example, the additional QF generation may offset oil and gas
generation in the LA Basin, which could reduce NOx emissions
in the Basin. This is the type of societal benefit which justifies the
existence of PURPA and the entire QF program. It is part of the
reason that QFs can receive full avoided cost payments. Nonethe-
less, it is irrelevant to a determination of the benefits created by
adding the new line to transport the QF power.
Major studies of line losses were performed by Luz’s witness,
Rupp, and Edison’s witness Kritikson. In Rupp’s Surrebuttal
Testimony, Exhibit 20, he described an analysis of the reduced
losses from the proposed line based on Edison’s response to DRA
Data Request 2. At DRA’s request, Edison had analyzed the
effects of adding another 220 kV line from Kramer to Lugo, in
lieu of the proposed project. Edison’s response indicated that the
line would reduce losses in the area at a present value of $42
million. (Ex. 20 pp. 10-12.)
'' In their Opening Comments, both Luz and Cal Energy claimed
that their respective experts offered this calculation. However, the
record does not provide assurance that either witness provided the
simple calculation which we describe. Rupp, testifying for Luz, offered
an estimate of line loss savings in the Kramer-Victor area, but did not
explain what comprises that area, or specify its other underlying assump-
tions. Lewis, testifying for Cal Energy, assumed 530 MW of QF
capacity instead of 630 MW) and assumed an average load condition,
instead of considering the maximum expected line losses.
A-40
Rupp stated that Edison’s response to Luz’s Data Request 5
showed that the losses on the existing system should be 129.3
MW, not the 118.9 MW used in Edison’s response to DRA Data
Request 2. (Ex. 20 p. 11.) However, Kritikson testified that
Edison sent a correction to its response to Luz’s Data Request,
explaining that 118.9 MW was the correct figure. (Tr. p. 737.)
Rupp later states that the correct amount of losses on the existing
system is 132.1 MW. (Ex. 20 p. 15.) Kritikson testified that Rupp
appeared to have derived this amount by linear extrapolation
which would be inaccurate because line losses vary exponentially.
(Tr. p. 741.)
Rupp also believed that Edison improperly modeled the gener-
ation at the Coolwater facility. He claimed that Edison improp-
erly increased Coolwater’s generation after the addition of the
proposed project and QF generation. (Ex. 20 p. 17.) Kritikson
argued that if QF production increased, other production would
logically decrease. Kritikson responded that Edison wanted an
equitable comparison of losses in the area. (Tr. p. 745.) Edison
used a 22-24 capacity factor for Coolwater in its models. (Tr. p.
746.)
Rupp also stated that Edison used “unreasonably low” Cool-
water capacity factors in analyzing both the existing and proposed
cases. (Ex. 20 p. 18.) Rupp modeled the Coolwater facilities at
32% capacity, which Kritikson believes is improperly based on
data for another proceeding which did not include the additional
Luz and Cal Energy generation. (Tr. p. 744.) Kritikson also noted
that the Coolwater capacity for the years 1985 through 1988 had
been 7%, less than 2%, 7%, and 27%. (Tr. p. 746.)
Rupp also found fault with Edison’s analysis of reactive power
support. He says that Edison shows Coolwater providing reactive
power even during periods it is not generating power. (Ex. 20 p.
19.) Edison’s Kritikson explained that this representation is a
feature of the modeling technique and does not imply that
Coolwater generates reactive power when off-line. (Tr. p. 747.)
Rupp analyzed two types of loss savings attributable to the new
line. The first is capacity loss savings, which he defines as the
savings created by the reduction in capacity needed due to
A-41
reduced losses at peak load. (Ex. 19 p. 7.) He calculated the
capacity loss savings by adding the 11 MW reduction in losses in
Kramer-Victor area indicated by Edison in its response to DRA’s
Data Request 11.4 and imputing an additional 5 MW for the rest
of the Edison testimony. (Ex. 19 p. 8.) In Rupp’s surrebuttal
testimony he raised the total from 16 to 16.4 MW based on the
flaws he found in Edison’s analysis. (Ex. 20 p. 24.)
According to Rupp, the second loss savings are avoided energy
losses, i.e. energy that is saved because the system has fewer
losses. Again, based on his corrections to Edison’s modeling,
Rupp arrived at annual savings of 92.4 gigawatt-hours (gWh). He
translates the total (energy and capacity savings) into a present
value of $69.3 million. (Ex. 20 p. 24.)
Kritikson disagreed with Rupp about the proper way to evalu-
ate capacity losses. He believed they shouid be evaluated over the
entire peak period. Thus, while at the instantaneous peak this may
be a savings of 11 MW, over the entire peak period, the losses
would actually increase, at a value of $7.1 million. (Ex. 38 p. 7, as
corrected at Tr. p. 715.)
Cal Energy’s witness Lewis testified that the savings would be
approximately 80,000 MWh (90 gWh) per year, using Edison’s
1990 base case generation and loads. (Ex. 23 p. 11.) This was
performed with loads at 80% of peak. The Energy Commission’s
witness McCuen testified that the line appears to offer significant
benefits with respect to reducing line losses. However, he believed
that Edison improperly calculated losses on the proposed project
with the additional generation from Cal Energy and Luz, which
causes line losses to “appear” to increase. (Ex. 35 p. 8.)
Finally, DRA’s witness Flores stated that she could not deter-
mine whether the line would decrease system losses. (Tr. p. 623.)
She noted the sensitivity of the power flow program to the input
assumptions, such as those for Coolwater. (Tr. p. 625.)
The parties disagreed as to whether change in losses should be
measured across the entire SCE network, or on a basis which is
isolated to the Kramer-Victor area. They disagreed as to whether
the analysis should be done with the new QF generation included
or not included. In addition, they disagreed as to whether or not
A-42
the line loss credits included in utility payments to QFs should
influence the analysis in any way.
Some preliminary conclusions can be drawn. It is not logical to
measure the change in losses in the absence of the new QFs. The
construction of the new line has been prompted by the need to
transport electricity generated by the QFs into the system and is a
natura! part of the expanded transmission system. Neither should
the change in losses because of the QF generation displacing
generation closer to Edison’s load center be considered: this is not
a result of the proposed line. It appears that the relevant question
is: How will line losses between Kramer and Lugo be affected by
the addition of the new line and 630 MW of QF power? Since the
existing lines from Kramer to Lugo are heavily loaded, it appears
logical that a new line will cause some of the power on the
Kramer-Lugo lines to flow on the new Kramer-Victor line in-
stead. That should lower losses on the existing lines, but increase
the losses on the new line. What is the net change? No one has
offered that relatively simple calculation.
Finally, SCE’s argument that the line loss credit included in
QF payments may offset some or all of the perceived line loss
benefit must be seriously considered. It might entail double
counting if line loss savings for which QFs are already given credit
are included in an assessment of system-wide benefit of the new
line.
3. Providing for Future Growth
SCE states that the existing transmission system in the
Kramer-Victor area is adequate for the next 20 years. (Ex. 38
p. 5.) Luz believes that the load growth predicted in the Propo-
nent’s Environmental Assessment (PEA)’? for the area will leave
SCE with a load of 400 MW or more which would not be served
if the existing Victor-Lugo line should fail. Luz claims, “the new
line ensures that future load growth will be accommodated within
the guidelines of Edison’s reliability criteria.” Edison counters
'2 The PEA is the environmental documentation which an applicant is
required to submit with a request for a CPCN pursuant to Rule 17.1! of
. the Commissions Rules of Practice and Procedure.
Nid a Caran S
A-43
that Luz has neglected to consider an important element of SCE’s
transmission planning criteria, which states that a major load
cannot be unserved for a “protracted” period. Edison submits that
because of Luz’s omission and the lack of testimony on its Major
Load Criteria there is no support for Luz’s statement.
The CEC argues that the line is needed to carry electricity
from new generating plants it believes will be built in the Mojave
area. McCuen states “It is highly probable that there will eventu-
ally be new generation sources developed by Luz International in
the Mojave. It is also possible, or even likely, that more geother-
mal generation will be developed at the Coso Naval Weapons
Center.” However, the SCE’s Electricity Report 7 (ER7) does
not project any additional QF or other new generation in this area.
This discussion seems to assume that the proposed project
could serve future growth by carrying electricity beyond the 630
MW that is already planned. While the lines would be physically
capable of carrying more power, SCE and Cal Energy seem to
agree that it would be inappropriate to plan for the line to carry
substantial additional generation. In addition, even if the new line
is considered capable of carrying additional power, there is no
benefit unless it is likely to to be used. The CEC’s own planning
documents seem to conflict with McCuen’s prediction that more
Luz and geothermal facilities are likely to be buit. Both Luz and
Cal Energy offered witnesses who could have easily provided that
information if it were true. While it is perfectly conceivable that
more plants will be built in the Mojave, the evidence must be
more solid than that before the ratepayers should be asked to pay
for the line.
4. System Security and Reliability
An addition to an electric transmission system makes that
system more reliable if it enhances the likelihood that the system
will be able to meet the demand of all of its customers. Parties
agree that the new line adds N-1 capability to the Kramer-Lugo
transmission path. N-1 capability is the ability to continue opera-
tions when one line fails. SCE argues that it doesn’t require the
N-1 capability along the Kramer-Lugo path because it has a
generation tripping scheme in place. In the current transmission
i Fe a eee ~~ Serra Oo ae eee ee, ee ee eee ee el ee ee eS eee ee ee” 7 eee ee oe ee ee
A-44
configuration, without a tripping scheme in place, an outage along
one of the Kramer-Lugo lines would cause a severe overload on
the remaining line, causing it to go out of service as well. By
tripping generation to prevent overloading the lines, SCE says
that it can currently serve all its load under N-1 conditions. (Ex.
38 p. 7.) SCE states that the proper way to evaluate the reliability
of a transmission system is in terms of service to the load: “The
ratepayers are not benefited by uninterrupted transmission of the
output from any given generator as long as load continues to be
served.” (Edison Reply Brief p. 44.) Edison’s witness Kritikson
said that if Edison required N-1 capability for serving every
generation sources then Luz and Cal Energy would have been
required to build two new lines to Kramer. (Tr. 756.)
DRA agrees with SCE. Because Kramer is a net generation
area, DRA finds the N-1 capability supplied by the line to be
insignificant. (DRA Reply Brief pp. 12-13.)
Luz asserts that the N-1 capability is “obviously” a system
benefit. (Luz Reply Brief p. 12.) In his testimony, Rupp stated
that “dropping generation to ensure overloads will be avoided is
not an acceptable measure for dealing with an N-1 outage. It
simply does not make sense to invest large amounts of money in
generation resources which would be dropped for ordinary N-|
transmission system failures.” (Ex. 20 p. 5.)
Cal Energy’s witness, Lewis, said that the N-1 capability
provided by the line would improve the firm transfer of energy
from the area. (Ex. 23 p. 12.) However, he also testified that
Edison’s generation tripping scheme is “a perfectly classical way”
of projecting the area. (Tr. p. 474.)
The CEC argues that neither SCE’s transmission reliability
Criteria nor any other utilities’ make a distinction for “net genera-
tion areas.” (Ex. 35 pp. 6-7.) The CEC maintains that, although
one can legitimately argue about its value, the N-1 capability is
desirable and creates a better, more reliable system than one
which relies on generation tripping. (CEC Reply Brief pp. 6-7.)
Just as was the case when considering the line loss question,
there is an attractive logic which applies here. SCE’s overall
electric system should be more reliable whenever it adds a new
ogee en SS ny, Tee eee eee
A-45
transmission line which connects generating sources to the load
center. However, an increase in reliability does not necessarily
provide a tangible benefit. Is there a tangible benefit to providing
N-1 reliability in a net generating area when the absence of N-I
capability does not appear to threaten the utility’s ability to meet
its load? In D.84-10-034, in which the Commission issued
CPCNs for the Devers-Valley, Serrano-Valley, and Serrano-Villa
Park transmission lines, the Commission discussed SCE’s relia-
bility criteria:
“Edison’s transmission reliability criteria basically require
that the outage of a single transmission or substation compo-
nent will not interrupt service to customers nor load compo-
nents in excess of their normal thermal ratings.
“It also requires (“N-2’ standard) that outages of two trans-
mission lines will not (1) cause a protracted interruption of
major load which is defined as 400 MW or more, (2) cause
line loadings on other system components in excess of their
emergency thermal ratings, nor (3) cause uncontrolled cas-
cading outages of additional electrical facilities.” (16 CPUC
2d 310, 324.)
This language suggests that SCE does consistently measure its
system reliability in terms of its ability tc meet load. While the
addition of the proposed project would provide N-! reliability to
Kramer, it is a “benefit” that is invisible to the ratepayers, who
would be no better served during an N-! outage than they are
now.
5. Emergency Support
SCE’s witness defines emergency support as reserve support
provided from other utilities. Because the proposed line does not
connect with another utility, SCE argues that it does not provide
any emergency support. (Tr. p. 785.) The CEC appears to
suggest that a project provides benefit to the electric system if it
improves the utility’s ability to serve load. Based on the testimony
of SCE’s Kritikson, the CEC claims that if the San Onofre
Nuclear Generating Station (SONGS) and Kramer had simulta-
neous failures, Edison could have problems serving load. (Reply
Brief p. 5.) However, in the testimony cited by the CEC,
= LL ee oe. ee eee oe PE ere Te tae ee eS ee ee eee eS Cee ee ee ee
- AP PUA A eS ee ee ee ee? Ree Pe Ue erage ae eee ee eo
A-46
Kritikson says that Edison would have less margin if it lost
Kramer, as indeed it would during any N-1 contingency. The
CEC’s own witness did not submit testimony on this issue.
Cal Energy’s witness, Lewis, states that QF generation is very
well suited to supplying emergency support. The proposed project
would allow all of the Kramer area generation to be available for
an emergency that affected generation in the LA Basin. (Ex. 23
p. 13.)
The definition of emergency support apparently relied upon by
the CEC and Cal Energy seems to make the concept of emer-
gency support virtually indistinguishable from system reliability.
If emergency support comprises a separate potential system-wide
benefit, then it must be somehow distinguishable. Based on the
record before us, we are not in a position to either agree that this
criterion is applicable, or to demand it. However, it is worth
noting that Cal Energy’s position on this issue emphasizes the
benefits of the QF power to be carried on the new line as opposed
to the benefits stemming from the line itself. Since QF benefits
are captured in the avoided cost payment, it would be inappropri-
ate to consider them when determining how to aliocate transmis-
sion costs.
6. Transfer Capability
SCE defines transfer capability as the ability to allow for
economy energy transactions or other support between utilitixs.
Since the Kramer-Lugo system is not interconnected with oth:r
utilities, the proposed project does not enhance transfer capability
of the type described by SCE. Cal Energy claims that Edison’s
definition is too narrow, that one should properly consider the
benefits from intra-utility support, e.g. during a gas curtailment
when nongas generation is increased, as well. (Cal Energy Reply
Brief p. 64.) For example during a recent natural gas curtailment,
Edison asked Kramer QFs to go to maximum generation. (Tr.
p. 382.)
DRA’s position is that transmission lines inherezitly increase
transfer capability and therefore that transfer carability should
not be characterized as a system benefit. (Tr. p. 665.) Cal Energy
says that DRA’s argument fails to recognize that there will be
Sy = Sa ee
So oe lt
capacity on the new line that will not be used by the currently
planned QFs. (Cal Energy Reply Brief p. 65.) DRA responds:
“Given the lack of surplus capacity on the Kramer-Victor line
once the additional QF generation has been added, it is evident
that the proposed project will not ‘by its very nature’ improve the
transfer capability of SCE’s Kramer-area transmission network.”
(DRA Reply Brief p. 40.)
CEC says that the proposed line will increase power transfer
capability from the Mojave area, which it characterizes as the
“area with the greatest generation growth within the SCE sys-
tem.” (Ex. 35 p. 9.) McCuen believes DRA was incorrect to say
that the transfer capability of the project is not a system benefit
because it is a “purpose of a transmission line.” He believes the
transfer capability provided by the line is a system benefit because
the project was built pursuant to a standard offer, the CEC
determined the generation resource was needed and because
DRA, SCE, and the CEC agreed that the increased transfer
capability is necessary to reliably transmit the QF power. (Ex. 35
p. 10.)
With this suggested criterion, as with others, experts disagree
as to what the term means, let alone whether or not a line which
enhances transfer capability would be creating a system-wide
benefit for that reason. Clearly, the proposed project will not
enhance transfers between utilities and will not enhance access to
economy energy. Beyond that, the evidence is insufficient for us to
find the existence of a system-wide benefit related to this
criterion.
7. Firm Resources at System Peak Conditions
Whether the line provides additional firm resources depends on
one’s definition. SCE states: “Firm generation is merely genera-
tion that is counted toward meeting Edison’s load and spinning
reserve requirements. Under contingency conditions, generation
that is iost is replaced by spinning reserves. This does not mean
that any generation which can be lost as a result of an N-1! cannot
be counted as firm.” (Edison Reply Brief p. 47; cf Tr. 759.) The
CEC’s witness, McCuen, defines firm generation as that having a
reasonably reliability, usually N-1. (Ex. 35 p. 11.)
it
A-48
Cal Energy’s Lewis witness describes firm resources as those
that are available with “100 percent reliability.” (Ex. 23 p. 14.)
He goes on to explain that “the implication is that there is no
constraint on maximum generation resources being applied to
meet a system peak condition as a consequence of the loss of a
transmission circuit, (i.e., an N-1 transmission contingency).”
Therefore, he finds that the line provides a benefit by increasing
the firm transfer capability from 500 MW to 1000 MW. (Ex. 23,
pp. 14-15.)
The discussion appears to treat this issue as a question of
system reliability. As such, it is not clear that this criterion adds to
the earlier analysis of reliability.
8. Cost Effectiveness
SCE argues that any analysis of cost-effectiveness must logi-
cally include cost-benefit studies. (Edison Reply Brief pp. 58-59.)
Because SCE believes that losses will increase, it does not find the
line cost-effective. Edison’s witness Kritikson testified that Edison
typically requires a 2:1 benefit to cost ratio for a loss reduction
project. (Tr. 736, 868.) Kritikson found Luz’s witness Rupp’s
calculations of benefit-cost ratios to be incorrect, because Rupp
used a project cost of $27 million instead of $50 million. This
reduces the benefit cost ratio from 2.56:1 to 1.39:1, assuming $69
million in loss savings. (Tr. 750.)
While basically this issue hinges on whether one believes the
line will decrease system losses, it is worth noting that even given
savings of $70 million, the benefit cost ratio is far from Edison’s
2:1 criteria.
Using a different definition of cost-effectiveness, CEC’s witness
McCuen finds the line to be cost-effective because it would be
more expensive if the QFs had to build lines to Edison’s loads.
McCuen also states that the settlement agreement also adds to
the cost-effectiveness of the line. (Ex. 35 p.11.)
9. QF Generation and Better Air Quality
Some parties argued that QF generation is intrinsically “better”
than utility generation and that any transmission line which
delivers QF generation to the load must therefore have system-
——————EEE =
A-49
wide benefits. For example Cal Energy notes that “the availability
and the cost of fossil fuels are uncertain, whereas with solar and
geothermal steam resources there are no such uncertainties, and
utilization is environmentally benign.” (Cal Energy Opening
Brief p. 37.) DRA counters that the Commission should be
technology neutral, as it has been in the past. (DRA Opening
Brief pp. 19-20.) DRA believes the environmental benefits of the
QFs are irrelevant. (DRA Reply Brief p. 7.)
Cal Energy argues that the line is a benefit because geothermal
production has lower incremental cost than conventional thermal
generation. Therefore the line enhances operating economies.
(Cal Energy Opening Brief p. 37; cf Tr. pp. 418-419.)
DRA replies that if it is appropriate to consider QF technology
a benefit, then one should also consider the higher cost of QF
power. (DRA Reply Brief p. 22.) SCE offers a comparison of the
utility’s marginal cost calculated in SO | rates to the higher SO 2
and SO 4 rates Luz and Cal Energy will be paid and notes that
the ratepayers are paying more for the QF generation than they
would for Edison’s. (Edison Opening Brief p. 63.)
In terms of environmental benefits, Cal Energy states that the
new line will improve air quality by providing clean energy to
displace fossil generation in LA Basin. (Ex. 23 p. 15.) The new
line will also reduces losses, also improving air quality. (Ex. 19
pp. 12-13.) The CEC also finds that the reduction in line losses
means less fossil fired generation which means better air quality,
which is a significant benefit. (CEC Reply Brief pp. 11-12.) The
CEC witness also stated that Luz and Cal Energy generation has
significant air quality benefits. (Ex. 22, pp. 9-13.) Kritikson
agreed that generation imported to the LA Basin reduces emis-
sions from plants within the Basin. (Tr. 911.)
Some parties (e.g. Rupp Ex. 19 p. 12) found that the reduction
in line losses means less generation and therefore less air pollu-
tion. Because Edison does not believe there is a loss reduction, it
does not believe there is an associated air quality benefit. (Ex. 38
p. 9.)
As we have mentioned in response to earlier system-wide
benefits arguments, for the purpose of allocating transmission
A-50
costs, benefits inherent in the QFs themselves should not be
considered. The Commission certainly encourages the develop-
ment of QFs which use renewable energy sources and reduce
pollution. That encouragement is in the form of avoided cost
payments. In the Biennial Plan Update (BRPU) proceeding
(1.89-07-004) we are considering whether or not environmental
benefits of potential QFs should be given weight in the bidding
process. However, the question before us here is entirely different.
Obviously, the new line is needed to transmit QF power. The
question affecting cost allocation is whether or not the new line
itself provides system-wide benefits that go beyond the fact that
the power being delivered is generated by QFs.
Air quality benefits from the line itself might be significant. If
the new line reduces overall transmission losses, then less genera-
tion will be needed and less fossil fuel will be burned. Unfortu-
nately, the line loss analysis provided in this record is
inconclusive. Thus, we cannot find that this line will produce
system-wide benefits in the form of air quality improvements.
10. Conclusions to be Drawn About System Benefits
We are left with only a small number of firm conclusions. First,
there is no clear answer as to whether the new line creates
system-wide benefits. Second, the policy set forth in D.85-09-058
may be in need of clarification in a generic proceeding.
There are aspects of this project which militate against a clear
finding of system-wide benefits. First, the cumulative size of the
QFs being developed by these operators is too great to allow us to
simply fal! back on a generalized notion of cost responsibility. We
are not faced, here, with a single facility which wil! occupy a small
fraction of the useful capacity of a transmiss:o: line which can
serve many other purposes. These projects are large enough to
need their own 220 kV transmission system. Although the new
line might prove useful to the SCE system in other ways, those
uses are clearly subordinate to the need to transmit as much as
630 MW of QF generation. SCE ciaims, and Cal Energy seems to
agree, that there will be very little, if any, room for other users on
the new line.
ee — oe a ee a ae ee
A-51
Second, the remoteness of the QFs from the SCE load center
takes much of the system-wide benefits analysis alluded to in the
1985 decision into the realm of conjecture. Will a more substan-
tial localized demand ever develop in the Mojave Desert? Will
more firms try to construct additional QFs in the area? Is there
any chance that SCE will ever seek to interconnect its northern
desert transmission system with other utilities to the east or
north? Transmission lines in this area are not easily categorized
and there is no tidy formula for measuring potential system-wide
benef
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