United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued December 7, 2007 Decided May 23, 2008
No. 06-1178
COGENERATION ASSOCIATION OF CALIFORNIA AND
ENERGY PRODUCERS AND USERS COALITION,
PETITIONERS
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
CALIFORNIA ELECTRICITY OVERSIGHT BOARD AND
PACIFIC GAS & ELECTRIC COMPANY,
INTERVENORS
On Petition for Review of Orders of the
Federal Energy Regulatory Commission
Donald E. Brookhyser argued the cause for petitioners.
With him on the briefs was Michael Alcantar.
Jeffery S. Dennis, Attorney, Federal Energy Regulatory
Commission, argued the cause for respondent. With him on
the brief were John S. Moot, General Counsel, and Robert H.
Solomon, Solicitor.
2
Mark D. Patrizio argued the cause for intervenors Pacific
Gas & Electric Company and California Electricity Oversight
Board in support of respondent. With him on the brief were
Erik N. Saltmarsh and Jeffrey A. Diamond.
Before: RANDOLPH, GRIFFITH, and KAVANAUGH, Circuit
Judges.
Opinion for the Court filed by Circuit Judge GRIFFITH.
Opinion dissenting by Circuit Judge RANDOLPH.
GRIFFITH, Circuit Judge: Pacific Gas & Electric
Company (“PG&E”) provides electricity transmission
services for customers in northern and central California. A
small fraction of the company’s users are “standby
customers”: entities that generate their own electricity, but
contract with PG&E for back-up supply in the event of power
outages. The petitioners in this case, two unincorporated
associations comprised of PG&E standby customers,
challenge how the utility determines the price for their
service. At issue is whether the Federal Energy Regulatory
Commission reasonably approved the unique rates PG&E
applies to standby customers. We hold that the agency’s
decision was reasonable and therefore deny the petition for
review.
I.
A.
Under the Federal Power Act (“Act”), 16 U.S.C. § 791 et
seq., the Federal Energy Regulatory Commission (“FERC” or
“Commission”) has exclusive authority to regulate the
transmission and sale of electricity in interstate commerce. Id.
3
§ 824(b). Every utility must file with the Commission a copy
of its rates and charges. Id. § 824d(c). If a utility wants to
change its pricing, the company must give sixty days’ notice
to the Commission, id. § 824d(d), which has the authority to
hold hearings on the proposed change, id. § 824d(e), and the
responsibility to ensure that all rates are “just and
reasonable,” id. § 824d(a). If the Commission does not
intervene, the rate goes into effect after the sixty days pass.
See Papago Tribal Util. Auth. v. FERC, 723 F.2d 950, 952–53
(D.C. Cir. 1983); Me. Pub. Utils. Comm’n v. FERC, 454 F.3d
278, 282–83 (D.C. Cir. 2006).
This litigation involves a proposed rate change filed by
PG&E on January 13, 2003 that sought to boost its annual
revenue from $379 million to $545 million. For all customers
except the standby class, PG&E applied what is called the
“12-coincident peak method” (“12-CP”) to determine the new
rate. Because of the unpredictable nature of the demand of
standby customers, however, the utility determined the
proposed rate for that class using a formula called the
“probabilistic method.”
Both formulas set prices on the basis of past demand. The
12-CP method looks to the share of each customer class when
demand is at its zenith. The utility begins by identifying the
“system peak,” the hour in a given month when the system
experiences its greatest demand for electricity. It then
determines the percentage of peak usage that each class draws
during that hour, averages the results over the course of a
year, and divides the revenue pie accordingly.
The probabilistic method PG&E applies to the standby
customers is more complex. Under this method, rates are
based on the percentage of “contract demand” the standby
class is likely to use, rather than usage at the time of system
4
peak. Contract demand is the maximum amount of electricity
a standby customer can draw under the terms of its contract.
For example, a standby customer may contract for up to 100
megawatts (“MW”), which means the customer can draw up
to that amount of power at any time. Because standby
customers typically generate electricity for their own use and
only draw electricity from PG&E because of power outages,
PG&E does not charge them the full amount of contract
demand. Instead, using data reflecting historical usage by the
standby customers, PG&E determines what percentage of
contract demand that class must shoulder. This percentage
represents the “cost allocation factor.” For example, if
contract demand is 100 MW and past usage yields a cost
allocation factor of 10%, the standby customer only pays for
10 MW of service, even though it has a right to draw up to
100 MW.
This cost allocation factor, moreover, is made up of two
parts: a regional transmission allocation factor and a local
transmission allocation factor. This division reflects the
different pricing factors that apply at different stages in the
transmission of electricity. PG&E assesses the standby
customers’ share of regional and local transmission costs,
identifies an allocation factor for each, and then takes the
weighted average of those two factors to produce the overall
cost allocation factor. A witness for PG&E testified that the
company originally developed the regional factor for
allocating the cost of generating electricity and then
determined that this factor would reasonably reflect the costs
of regional transmission as well. As for the local allocation
factor, PG&E randomly selected several standby customers,
calculated their total contract demand, and then took note of
their actual usage for each hour during the “peak period”
(Monday through Friday, 8:30 a.m. to 9:30 p.m., May through
October) to produce a curve. The company then identified the
5
ninetieth percentile point on that curve: the hour where
electricity usage by the sample of standby customers was
greater than nine out of every ten hours during the peak
period. PG&E chose this point regardless of when system
peak occurred. Finally, the company calculated the demand at
the ninetieth percentile point as a percentage of the sample’s
total contract demand to produce the local allocation factor.
Contract demand for the standby class is 600 MW. In its
proposed allocation, PG&E assigned a 12% factor for the
regional costs and a 38% factor for the local costs, producing
a weighted average of approximately 27%.1 That is to say, the
standby class would pay 27% of the cost for 600 MW. Under
the proposal, the standby class went from paying $0.26 per
kilowatt to $0.35 for the same.
B.
After PG&E filed its proposed rate increase, the
Commission suspended the new rates and scheduled a hearing
to determine whether they were “just and reasonable.” Pac.
Gas & Elec. Co., 102 F.E.R.C. ¶ 61,270 (2003). The
administrative law judge (“ALJ”) issued a summary
disposition on one issue and the parties resolved their dispute
as to all other issues, except for the question now before us.
See Pac. Gas & Elec. Co., 110 F.E.R.C. ¶ 63,026, at 65,049
(2005) (describing procedural history). The ALJ concluded in
principle it was reasonable to assign unique rates to standby
customers based on contract demand because they were not
similarly situated to other classes. The ALJ found that
demand by standby customers is random; they typically
1
PG&E adopted these regional and local allocation factors for its
standby class, as well as the percentages for producing a weighted
average, in a previous rate settlement.
6
cannot predict when their generating units will go offline and
require electricity from PG&E. Id. at 65,053 (“Having PG&E
standing ready to provide service on demand is a valuable
service and rates based on this potential use of power, rather
than actual use are not per se unreasonable.”).
Turning to the particular method PG&E used to
determine the standby customers’ share of regional and local
transmission costs, however, the ALJ held that recent data did
not support the methodology PG&E used for its standby
customers. Id. at 65,054–56. Instead, the ALJ concluded that
more recent data supported applying the 12-CP method, id. at
65,055, and observed that “[w]hile standby service is
unpredictable, the relatively small size of the standby class in
this case mitigates this difficulty,” id. at 65,056. PG&E and
FERC both filed exceptions to the decision, which the
standby customers also opposed.
On review, the Commission agreed with the ALJ that the
standby class is not similarly situated to the other classes and
that a rate based on contract demand may be lawful if
supported by sufficient data on past demand. Pac. Gas &
Elec. Co., 113 F.E.R.C. ¶ 61,084, at 61,323 (2005). The
Commission, however, reversed the ALJ’s conclusion that the
12-CP method was appropriate and instead held that
substantial and persuasive evidence supported PG&E’s
proposed allocation of costs to the standby customers based
on the application of the probabilistic method to contract
demand. Id. at 61,326. FERC denied a subsequent request for
rehearing, Pac. Gas & Elec. Co., 114 F.E.R.C. ¶ 61,324
(2006), and the standby class filed a timely petition for review
in this court challenging both the methodology and the overall
cost allocation factor that PG&E proposed.
We have jurisdiction under 16 U.S.C. § 825l(b) and
7
review the Commission’s order under the arbitrary and
capricious standard of the Administrative Procedure Act, 5
U.S.C. § 706(2)(A). See Sithe/Independence Power Partners
v. FERC, 165 F.3d 944, 948 (D.C. Cir. 1999). The
Commission’s factual findings will stand if supported by
substantial evidence. 16 U.S.C. § 825l(b); see also Fla. Mun.
Power Agency v. FERC, 315 F.3d 362, 365 (D.C. Cir. 2003).
Moreover, we “will affirm the Commission’s orders so long
as FERC ‘examine[d] the relevant data and articulate[d] a . . .
rational connection between the facts found and the choice
made.’ ” Midwest ISO Transmission Owners v. FERC, 373
F.3d 1361, 1368 (D.C. Cir. 2004) (citing Motor Vehicle Mfrs.
Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43
(1983)). Where the evidence might support more than one
rational interpretation, “the question we must answer . . . is
not whether record evidence supports [the petitioner’s]
version of events, but whether it supports FERC’s.” Fla. Mun.
Power Agency, 315 F.3d at 368.
II.
Petitioners’ sundry arguments advance one simple claim:
The Commission’s decision to approve PG&E’s proposed
rate increase violates the “cost-causation principle.” “[U]nder
section 205(a) of the Federal Power Act, a utility may charge
only rates that are ‘just and reasonable.’ Interpreting that
mandate, we have explained that such rates should be based
on the costs of providing service to the utility’s customers,
plus a just and fair return on equity. We have consistently
upheld rates based on such a cost-causation principle.”
Sithe/Independence Power Partners v. FERC, 285 F.3d 1, 5
(D.C. Cir. 2002) (internal quotation marks and citations
omitted). The standby customers argue that the Commission’s
decision to approve PG&E’s methodology based on contract
demand, and the weighted 27% allocation factor that
8
methodology produced, violated the cost-causation principle
and lacked the support of substantial evidence in the record.
We disagree.
A.
The probabilistic methodology is a reasonable means to
account for the special costs that standby customers impose
on PG&E. The Commission concluded and the petitioners do
not contest that the standby customers are not similarly
situated to the company’s other customer classes. As James
Ross, a witness for the petitioners, stated:
PG&E provides standby service to replace the
generation ordinarily serving the customer during
periods when that customer generation is out of
service due to unscheduled and scheduled outages.
Thus, the supply of standby service during periods of
system coincident peaks differs from full requirements
service, because it is typically a function of random
outages associated with the customer generation
equipment failure.
Prepared Direct Testimony of James A. Ross, 3–4. Moreover,
petitioners concede that PG&E incurs costs by standing ready
to serve the random demands of standby customers.
Petitioners’ Reply Br. at 2 (“[The petitioners] do[ ] not
contest the judge’s finding that PG&E incurs costs to stand by
ready to serve.”). They cite to the ALJ’s finding at ¶ 40 of the
initial decision, which reads: “PG&E incurs costs (a ‘capacity
requirement’) to be prepared and to ‘stand ready’ to provide
service to the standby class at the contract demand level when
needed, but only when needed.” 110 F.E.R.C. ¶ 63,026, at
65,053 (internal quotation marks omitted).
9
Despite this concession, petitioners argue that standby
customers only impose costs on PG&E insofar as they
contribute to the system peak and that the 12-CP method,
which apportions costs according to usage at system peak, is
therefore the reasonable allocation method. To support this
claim, the petitioners principally rely on the testimony of Ben
Morris, a PG&E expert witness who testified on transmission
planning at the company. Tr. of Aug. 31, 2004 Hr’g at 268–
82. Morris testified that transmission planners measure the
adequacy of the system by assessing its ability to meet
demand at system peak. To make this assessment, planners
forecast both anticipated load and the generation necessary to
satisfy that load. With these results in hand, the planners also
model “contingencies” — failures of either generation or
transmission facilities. If the results show that the
transmission system may fail to satisfy demand at system
peak, then the planners propose additions and improvements
to the system.
We conclude that the Commission reasonably approved
as “just and reasonable” the rate for standby customers based
on the probabilistic method because substantial evidence in
the record shows that the unpredictability of standby customer
demand imposes costs not captured by measuring that class’s
contribution to system peak. To reach this conclusion, the
Commission relied primarily on the testimony of Andrew
Bell, a rate expert who testified on behalf of PG&E. Bell
explained that the standby class is different from other classes
because the demand it places on the system is both variable
and unpredictable. Tr. of Aug. 31, 2004 Hr’g at 190.
Nonetheless, under the contract PG&E must provide service
to the standby customers on demand. Id. at 193, 244–45.
Because standby service customers’ usage of utility-
supplied backup power is by its very definition subject
10
to unpredictable and fundamentally random variations,
the utility must make adequate reserve capacity
available to serve foreseeable potential loads of the
standby class. In any given month, the standby class’
maximum demand might or might not occur
coincident with system peak. PG&E has accounted for
this inherent uncertainty by using statistical methods
to estimate what fraction of the total contract capacity
should be treated as a reserve against the contingency
of multiple on-peak outages for individual standby
customers’ generation equipment.
Prepared Rebuttal Testimony of Andrew M. Bell, Exhibit
PGE 45-5.
The 12-CP method does not sufficiently allocate costs to
the standby class because the probability of that class’s
maximum demand coinciding with system peak is statistically
low, but not so low that PG&E can ignore that possibility in
its capacity planning.2 Assigning cost responsibility to the
standby class on the basis of its share of system peak — in
most months quite low — would not capture all the costs that
class imposes on PG&E, which must plan for the possibility
2
The standby class is not the only class whose maximum demand
does not often coincide with system peak. As one example, Bell
mentioned the street lights rate class, which has a similar overall
load to the standby class. Tr. of Aug. 31, 2004 Hr’g at 191–92. The
demand this class places upon the system, however, is predictable.
PG&E does not have to plan for the possibility that this class might
place significant demand on the system at or near the time of
system peak. Id. at 192 (“I know when the street lights are going to
come on, they’re going to come on when it gets dark. The standby
class, there’s . . . no physical predictability or reason for when the
maximum demand will be higher than the coincident peak demand
during the coincident peak.”).
11
that the standby customers could draw up to contract demand
at the time of system peak. See Tr. of Aug. 31, 2004 Hr’g at
238–47.
The petitioners claim that Morris’s testimony about how
PG&E undertakes system transmission planning undermines
this rationale. Id. They suggest that only a method that
measures contribution to system peak is reasonable because
PG&E incurs its costs by expanding to meet demand at that
point. The purpose of such planning, however, is to identify
the need for incremental additions and improvements to the
system. Id. at 268, 275, 278. As the Commission concluded,
this account of planning at the macro level does not provide a
complete picture of how PG&E incurs costs to meet the
random demand of the standby customer class. See Pac. Gas
& Elec. Co., 114 F.E.R.C. ¶ 61,324, para. 11 & n.16 (2006).
Moreover, FERC has approved a methodology based on
contract demand in the past. For example, in Central Power
& Light Company, 47 F.E.R.C. ¶ 61,339 (1989), the
Commission considered a similar challenge to cost allocation
based on contract demand brought by a standby customer.
The agency upheld the methodology: “[The utility] is
contractually obligated to provide service to [the standby
customer] and [the utility] incurs costs to stand ready to
provide service. . . . Therefore, allocating demand related
costs to [the standby customer] based on its contract demand
is reasonable.” Id. at 62,166. Citing testimony that the
demand imposed by the standby customer is “inherently
unpredictable,” the Commission further held: “We believe
that [the utility] properly allocated costs differently for its
partial requirements class customers because they are not
similarly situated to [the utility’s] full requirements
customers. Consequently, we find that [the utility’s] use of
contract demands for its partial requirements class customers
12
in this case did not constitute undue discrimination.” Id. at
62,166–67.3
B.
Having decided that FERC did not act arbitrarily and
capriciously in approving a method based on contract demand
to determine the rate for the standby class, we must still
decide whether the specific 27% cost allocation factor PG&E
proposed was reasonable and supported by substantial
evidence in the record. As mentioned, this percentage
represents the weighted average of the 12% regional
allocation factor and the 38% local allocation factor. Data in
the record shows that this regional allocation reflects the
standby customers’ actual usage. As Bell testified,
The 12 percent factor, after being applied to 600 MW
of contracted standby demand, provides cost recovery
3
The ALJ in Central Power & Light Company found that the utility
“was at all times either serving [the standby customer’s] contract
demand or was maintaining spinning reserves to allow it to serve . .
. contract demand if called upon to do so.” 47 F.E.R.C. at ¶ 62,165.
In the present case, the agency did not find that PG&E had to
maintain the full amount of contract demand as a spinning reserve
on line at all hours. Rather, as Bell testified, “PG&E has accounted
for this inherent uncertainty by using statistical methods to estimate
what fraction of the total contract capacity should be treated as a
reserve against the contingency of multiple on-peak outages for
individual standby customers’ generation equipment.” Prepared
Rebuttal Testimony of Andrew M. Bell, Exhibit PGE 45-5. The
different rates reflect this variance: the standby customer in Central
Power paid 100% of contract demand, 47 F.E.R.C. at ¶ 62,163,
whereas the standby customers in the present case pay 27% of
contract demand.
13
for somewhat less than an 80 MW share of regional
transmission facilities. The table at page 13 of Mr.
Ross’ testimony shows that the maximum non-
coincident peak demand of the standby class exceeded
this level during five of the twelve calendar months of
2001 . . . and that at least two of these occurrences
were during the weekday partial-peak time-of-use
period . . . and thus were at or near times when this
level of standby usage would coincide with the system
peak.
Prepared Rebuttal Testimony of Andrew M. Bell, Exhibit
PGE 45-5, 6. The standby customers dismiss this evidence
because it refers to usage at times other than system peak, but,
as we have already explained, FERC did not act unreasonably
in approving a method that does not rely upon usage at
system peak to set the standby customer rate.
Although PG&E first arrived at the 38% local allocation
factor in 1993, Bell testified that more recent data supports
this calculation. Dividing PG&E’s service territory into six
broadly defined geographic areas and drawing on data from
2001, he explained that “the single largest individual standby
customer within each zone typically accounts for between 29
and 48 percent of the total contracted standby load in that
zone,” and that the “weighted average . . . is 37 percent, when
expressed as a fraction of the total standby load within each
zone.”4 Id. at 45-6, 7. This weighted average is comparable to
4
As the intervenors clarify, 37% represents the “weighted average
share across all six areas for the largest standby load in each area as
a percentage of total contracted demand in each area.” Intervenors’
Br. at 7 n.3. In his testimony, Bell went on to explain that if the
company had performed the same analysis but considered the two
largest customers in each zone, the figure would have been even
14
the 38% allocation factor PG&E proposed.
III.
For the reasons stated in this opinion, we deny the
petition for review.
So ordered.
higher. Prepared Rebuttal Testimony of Andrew M. Bell, Exhibit
PGE 45-7.
RANDOLPH, Circuit Judge, dissenting: I agree with majority’s
statement of the cost causation standard that governs the
Commission’s ratemaking decisions. Maj. Op. at 6-7. But I
disagree that the Commission has satisfied that standard.
Commission counsel admitted at oral argument that nowhere in
the record is there a calculation of PG&E’s costs for standing
ready to serve petitioners. Without that number or even a rough
approximation of it, the Commission could not determine
whether the rate PG&E proposed related to the costs these
standby customers imposed. It is no answer to say that the
standby customers must be imposing some cost on PG&E or that
the 12-CP system may not adequately account for the standby
customer’s unpredictable usage. The questions remain – what
is the amount of the cost and does that amount justify a rate four
times higher than the rate PG&E would have charged under its
12-CP system. The Commission never answers either question
and neither does the majority opinion.