In the
United States Court of Appeals
For the Seventh Circuit
____________________
Nos. 13–1674, –1676, –2052, –2262
ILLINOIS COMMERCE COMMISSION, et al.,
Petitioners,
v.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent.
__________________________
Petitions for Review of an Order of the
Federal Energy Regulatory Commission.
Nos. EL05‐121‐006, ‐008.
____________________
ARGUED APRIL 22, 2014 — DECIDED JUNE 25, 2014
____________________
Before CUDAHY, POSNER, and TINDER, Circuit Judges.
POSNER, Circuit Judge. It’s been almost five years since we
remanded this case to the Federal Energy Regulatory Com‐
mission. Illinois Commerce Commission v. FERC, 576 F.3d 470
(7th Cir. 2009). The petitioners who persuaded us to remand
the Commission’s order, which allocated costs for certain
new high‐voltage network transmission lines (consisting of
the transmission lines themselves plus transformers, capaci‐
tors, and other ancillary equipment—for simplicity we’ll
2 Nos. 13–1674, –1676, –2052, –2262
generally refer to the entire facility as a “transmission line”),
are not satisfied with the order that the Commission issued
on remand. For that order reinstated without change the or‐
der that we had vacated.
The petitioners are primarily the midwestern members of
a Regional Transmission Organization (plus the Illinois
Commerce Commission, which essentially is appearing on
behalf of Commonwealth Edison, the largest electrical utility
in Illinois) called PJM Interconnection. A Regional Transmis‐
sion Organization is a voluntary association primarily of
utilities that either own electrical transmission lines that
comprise a regional electrical grid or generate electricity that
is transmitted to the customers in the region. The association
operates the grid on behalf of the members.
PJM has the largest peak load (the amount of electrical
power expected to be provided for a sustained period of
above‐average demand) of any Regional Transmission Or‐
ganization—also the largest population and the most trans‐
mission mileage. Its region stretches east and south from the
Chicago area (northeastern Illinois) to western Michigan,
eastern Indiana, Ohio, Kentucky, Tennessee, West Virginia,
Pennsylvania, New Jersey, Delaware, Maryland, the District
of Columbia, North Carolina, and Virginia. Most midwest‐
ern utilities, however, belong not to PJM but to an Inde‐
pendent System Operator (which is similar to a Regional
Transmission Organization, however) called Midcontinent
Independent System Operator, Inc. (MISO). As shown on the
map (prepared by the ISO/RTO Council, www.isorto.org/
about/default, visited June 23, 2014, as were the other web‐
sites cited in this opinion), MISO operates in the Midwest,
South, and some of the Great Plains states, in contrast to
Nos. 13–1674, –1676, –2052, –2262 3
PJM, which operates mainly in the mid‐Atlantic region but
also, though to a considerably lesser extent, in the Midwest.
The Federal Energy Regulatory Commission’s order is ad‐
dressed only to PJM, but MISO will play a bit role in our
analysis.
REGIONAL TRANSMISSION ORGANIZATIONS
What we’ll refer to as the western region of PJM consists
of the parts of Michigan, Illinois, and Indiana shown on the
map as being in PJM’s domain, along with all of Ohio. Elec‐
trical generating plants in the western region usually are
close to the customers—Chicago, for example, a major elec‐
tricity market, is ringed by power plants—and so in that re‐
gion relatively low‐voltage transmission lines (typically 345‐
4 Nos. 13–1674, –1676, –2052, –2262
kilovolts) are adequate for serving most customers, although
the region also has a number of high‐voltage—765‐kV—lines
for transmitting electricity with greater efficiency, mainly
from Indiana to customers in Chicago. The cities in the east‐
ern region use even lower voltage (230‐kV lines) than the cit‐
ies in the western region, but most of the power plants are
farther away from the customers than in PJM’s western re‐
gion and therefore 500‐kV lines are preferred even though
more expensive; the reason is that higher voltage reduces the
amount of electricity that is lost as a function of the distance
over which it is transmitted.
The question presented by the petition for review is the
extent to which the members of PJM in its western region
(we’ll call these the “western utilities”) can be required to
contribute to the costs of newly built or to‐be‐built 500‐kV
lines (we’ll call these the “new transmission lines”) even
though the lines are primarily in the eastern part of PJM.
Originally at issue were 18 such lines and related projects,
expected to cost $6.6 billion in toto. The number of new lines
has dwindled to 12 (11 already built, the other under con‐
struction; but 3 more are under study). The current estimate
of the total cost of the projects that have been or will be
completed is $2.7 billion.
PJM’s western utilities are unlikely to obtain a significant
additional supply of electricity from the new transmission
lines. The capacity of the western utilities to generate elec‐
tricity is already ample—so ample that they transmit a great
deal of their electricity to the eastern members of PJM to
help them meet the heavy eastern demand for electricity. Be‐
cause the demand for electricity is so much greater in PJM’s
eastern subregion, it’s unlikely that much electricity will be
Nos. 13–1674, –1676, –2052, –2262 5
transmitted from the eastern to the western utilities via the
new transmission lines.
Still, the western utilities may benefit from the new high‐
voltage transmission lines in PJM’s eastern region, and to the
extent they do they can be required to contribute to the cost
of building the new lines. The Commission’s order that we
set aside five years ago made no effort to quantify those
benefits, however; instead it allocated the costs of the new
transmission lines among all the members of PJM in propor‐
tion to each utility’s electricity sales, a pricing method
analogous to a uniform sales tax. The Commission acknowl‐
edged that this was a crude method of cost allocation—
which is to put it mildly, because without quantifying the
benefits of the eastern projects to the western utilities it is
impossible to determine what those utilities should be
charged: charging costs greater than the benefits would
overcharge the utilities, and charging costs less than the
benefits would undercharge them. The Commission de‐
fended its approach by appealing to the difficulty of measur‐
ing the benefits that the western utilities would derive from
the new lines. We considered that a feeble defense. We said
that “FERC is not authorized to approve a pricing scheme
that requires a group of utilities to pay for facilities from
which its members derive no benefits, or benefits that are
trivial in relation to the costs sought to be shifted to its
members.” 576 F.3d at 476. We acknowledged that “if [the
Commission] cannot quantify the benefits to the midwestern
utilities from new 500 kV lines in the East, … but it has an
articulable and plausible reason to believe that the benefits
are at least roughly commensurate with those utilities’ share
of total electricity sales in PJM’s region, then fine; the Com‐
mission can approve PJM’s proposed pricing scheme on that
6 Nos. 13–1674, –1676, –2052, –2262
basis.” Id. at 477. But the Commission hadn’t met that stan‐
dard either. So we remanded.
Almost three years elapsed before the Commission is‐
sued its order on remand. PJM Interconnection, L.L.C., 138
FERC 61230 (March 30, 2012). A year later the Commission
supplemented the order on rehearing, PJM Interconnection,
L.L.C., 142 FERC 61216 (March 22, 2013), and now, a year
farther on, the western utilities are back before us, challeng‐
ing the order on remand—which like the order we set aside
prescribes “a region‐wide postage‐stamp allocation of the
costs of new transmission facilities that operate at and above
500 kV.” PJM Interconnection, L.L.C., supra, 138 FERC 61230,
¶ 49. This is FERC‐speak for allocating the costs of the high‐
voltage lines across all the PJM utilities, east or west, in pro‐
portion to each utility’s respective sales. Just as the price of
sending a letter anywhere within the United States is the
same, so the cost that an electrical utility must contribute to a
500‐kV transmission line will, if FERC has its way, be inde‐
pendent of the utility’s location relative to the location of the
transmission line.
The postal analogy is forced. Distance doesn’t figure in
the price of a letter, because most of the costs of postal ser‐
vice are incurred in the postal facilities in which mail is
sorted and in local pick‐up and delivery service, rather than
in the transportation of the letter between distant locations.
Here we’re talking about the allocation of the huge costs of
building high‐voltage transmission lines that do not provide
uniform benefits to all the utilities in the region in which the
lines are built.
Much of the Commission’s order on remand is devoted
to hand‐wringing over how difficult it is to estimate the
Nos. 13–1674, –1676, –2052, –2262 7
benefits to PJM’s western utilities of the new 500‐kV lines in
the east (thus reprising its original order). Yet at the same
time the opinion contains detailed dollar estimates of many
of the benefits—but without explaining the basis of the esti‐
mates. Studies are cited from time to time, but the evidence
and analysis on which they’re based are not described. Even‐
tually the Commission threw up its hands and said in its or‐
der on rehearing that “500 kV and above transmission facili‐
ties provide a broad range of benefits, including reduced
congestion, reduced outages, reduced operating reserve re‐
quirements, and reduced losses. These benefits radiate from
the upgraded facility, and thus are spread throughout the
PJM region.” PJM Interconnection, L.L.C., supra, 142 FERC
61216, ¶ 67 (footnote omitted). But how far they “radiate,”
and how equally, and with what loss of effect as the distance
grows are critical questions not answered in the Commis‐
sion’s order. The benefits may “spread throughout” the en‐
tire domain of PJM without spreading equally, or even ap‐
proximately equally, among the utilities that comprise PJM.
Of the four types of benefit listed by the Commission in
the passage we just quoted, at least two—reduced electrical
outages and reduced electricity losses—will definitely not be
equally distributed between the utilities in the eastern region
and the utilities in the western region. Outages in the eastern
region will be reduced because the high‐voltage transmis‐
sion facilities will enable electricity to be transmitted with
greater reliability within the region. But outages in the west‐
ern region will be reduced only trivially. The flow of electric‐
ity in PJM’s domain is west to east except there is some flow
the other way from eastern Indiana to the Chicago area. And
the typical blackout or brownout occurs because of an out‐
age in an individual transmission line or transformers, often
8 Nos. 13–1674, –1676, –2052, –2262
because of an overload or weather damage, and the outages
will persist until those lines can be repaired, rather than be‐
ing offset by a new supply of electricity, whether from west
or east.
As for reducing losses of electricity attributable to the
distance over which it is transmitted, the new high‐voltage
transmission lines will do that in the eastern region because
high voltage is more efficient than low for transmitting elec‐
tricity over long distances. The western utilities will benefit
too, because they won’t have to generate as much electricity
to satisfy the eastern demand. And because PJM requires the
western utilities to maintain reserve capacity (just as hospi‐
tals are required to install generators to provide a back‐up
supply of electricity should there be an outage) to make up
for interruptions in the supply of electricity to the eastern
utilities, a reduction in those interruptions as a result of the
new high‐voltage transmission facilities will enable the
western utilities to reduce their reserve capacity.
Another benefit to the western utilities will be a reduc‐
tion in congestion in their transmission lines if interruptions
in transmission to the eastern utilities are reduced because
transmission lines in the east will be transmitting electricity
at a higher voltage. Transmission congestion occurs when
customers’ demand for electricity exceeds transmission ca‐
pacity, resulting in what is called “curtailment”: the grid op‐
erator does not allow additional supply to enter the grid be‐
cause it would overload the lines. Curtailment is costly to
the utilities because it means they’re producing electricity
that cannot be sold to their customers because it cannot be
transmitted to them.
Nos. 13–1674, –1676, –2052, –2262 9
So some of the benefits of the new high‐voltage transmis‐
sion facilities will indeed “radiate” to the western utilities, as
the Commission said, but “some” is not a number and does
not enable even a ballpark estimate of the benefits of the new
transmission lines to the western utilities. Consider two utili‐
ties, one in northern Illinois and one in southern New Jersey,
whose peak‐load capacity is the same. How likely is it that
they benefit even roughly equally from a new 500‐kV trans‐
mission facility in New Jersey? The New Jersey utility would
obtain or deliver electricity using that facility; the Illinois
utility could reduce its reserve capacity slightly because it
would be less likely to have to help the New Jersey utility
overcome an outage, as an outage would be less likely.
Those are not equivalent benefits, though treated by the
Commission as equivalent. The only explanation for why it
did that is that having failed to conduct a cost‐benefit analy‐
sis, it had no basis for treating the benefits as other than
equivalent.
The western utilities go to the opposite extreme, arguing
that their obligation to contribute to the cost of the new fa‐
cilities should be limited to the percentage of their (that is,
the western utilities’) electricity that flows through what is
called a “constrained” transmission facility (one likely to ex‐
perience an outage). This is called the “distribution factor”
or “beneficiary pays” approach, in contrast to the Commis‐
sion’s postage‐stamp approach. The western utilities ac‐
knowledge that by enlarging transmission capacity the new
facilities in the east will confer a benefit on them by reducing
the constraint factor and consequent outage danger in the
western subregion. They assign a very low dollar figure to
this benefit, however, and the Commission has shown that
10 Nos. 13–1674, –1676, –2052, –2262
the figure is an underestimate. But it failed to come up with
its own estimate.
One of the attorneys for the utilities remarked at oral ar‐
gument that “utility executives and regulators have long
struggled with how to quantify reliability benefits.” If one
may judge from its opinions in the present case, FERC has
given up the struggle. But it has done so prematurely, with‐
out demonstrating that even a rough estimate of the benefits
to be conferred by the new eastern transmission facilities is
impossible. Cost‐benefit analysis is the standard method of
valuing large public or commercial projects, and is hardly
alien to the electric power industry. PJM for example in 2011
conducted a cost‐benefit analysis of a $100 million project to
enlarge a 500‐kV transmission line. It estimated costs and
benefits over the first 15 years of the project’s life, dis‐
counted them to present value at an annual rate of 7.7 per‐
cent, determined the ratio of the present value of the benefits
to the present value of the costs at 14.76, and approved the
project. PJM, “MEP‐B‐11 Cost/Benefit Analysis” 3 (Nov. 3,
2011), www.pjm.com/~/media/committees‐groups/committe
es/teac/20111103/20111103‐2011‐market‐efficiency‐analysis‐r
esults‐update.ashx. (On the methodology of cost‐benefit
analysis generally, see, e.g., Cost‐Benefit Analysis (Richard
Layard & Stephen Glaister eds. 1994), and for a short intro‐
duction, see Thayer Watkins, “An Introduction to Cost Bene‐
fit Analysis,” www.sjsu.edu/faculty/watkins/cba.htm.) Of
course it’s often difficult to obtain reliable predictions of
costs and benefits, as long recognized in the extensive aca‐
demic literature on cost‐benefit analysis of big public infra‐
structure projects with long expected lives. See, e.g., Bent
Flyvbjerg, “Policy and Planning for Large‐Infrastructure
Projects: Problems, Causes, Cures,” 34 Environment & Plan‐
Nos. 13–1674, –1676, –2052, –2262 11
ning B: Planning and Design 578 (2007); Bert van Wee, “Large
Infrastructure Projects: A Review of the Quality of Demand
Forecasts and Cost Estimations,” in id. at 611; Roger Vicker‐
man, “Cost‐Benefit Analysis and Large‐Scale Infrastructure
Projects: State of the Art and Challenges,” in id. at 598. But
the literature does not infer impossibility from difficulty, as
FERC apparently does. Indeed, cost‐benefit analysis has
been used in more difficult cases than this one, for example
where some of the costs or benefits are nonmonetary, see,
e.g., John Rolfe, “Cost‐Benefit Analysis—Some Practical Ex‐
amples,” www.cqu.edu.au/__data/assets/powerpoint_doc/00
14/23009/Rolfe‐AGSIP‐CBA‐April‐2007.ppt, or where the
costs are impossible to pinpoint but catastrophic risks exist.
See index references to “cost‐benefit analysis” in Richard A.
Posner, Catastrophe: Risk and Response 316 (2004).
We do not suggest that postage‐stamp pricing is appro‐
priate only for the postal service. Our concern is with the ab‐
sence from the Commission’s orders of even an attempt at
empirical justification. The Commission assumes—it does not
demonstrate—that the benefits of the eastern 500‐kV lines
are proportionate to the total electric‐power output of each
utility, no matter how remote the utility is from the eastern
projects that the utility is to be made to contribute to the
costs of. It is a method guaranteed to overcharge the western
utilities, as they will benefit much less than the eastern utili‐
ties from eastern projects that are designed to improve the
electricity supply in the east, though the western utilities
will derive an incidental consequence that the Commission
hasn’t tried to quantify. Contrast our wind‐power decision,
Illinois Commerce Commission v. FERC, 721 F.3d 764 (7th Cir.
2013), which upheld postage‐stamp pricing of the transmis‐
sion lines required to bring western wind‐generated electri‐
12 Nos. 13–1674, –1676, –2052, –2262
cal power to the MISO utilities. There was evidence that the
lines would not yield highly disparate benefits to the utilities
asked to contribute to their costs. See id. at 774–75. Indeed,
the Commission had determined that the benefits from the
new lines would be spread almost evenly across all the utili‐
ties. Midwest Independent Transmission System Operator, Inc.,
133 FERC 61221, ¶¶ 54–56 (Dec. 16, 2010). It made no such
determination in the present case; as a practical matter, all it
did was express a hope that things might turn out that way.
As an example of the unreality of that hope, consider the
500‐kV project (eventually abandoned) called Branchburg‐
Roseland‐Hudson, which was to be built in New Jersey at an
expected cost of $946 million. PJM refers to “20 thermal and
reactive reliability criteria violations in Northern New Jer‐
sey,” and these are the only reasons given for the project.
Under the Commission’s cost allocation, only about 12 per‐
cent of the cost of the project would have been paid by the
two principal New Jersey utilities, while Commonwealth
Edison would have had to pay almost 16 percent even
though there was no suggestion that it had contributed more
than trivially (1.26 percent was its estimate, though probably
an underestimate because based on its “beneficiary pays”
analysis) to those thermal and reactive reliability criteria vio‐
lations.
The Commission relied heavily for its postage‐stamp ap‐
proach on an “ISO/RTO Metrics Report” published in 2011
by the Regional Transmission Organizations and their cous‐
ins the Independent System Operators. Only two pages of
the report, however, refer to possible cost savings from
PJM’s plans, which include the new 500‐kV projects, to im‐
prove its grid. The discussion of those savings is cursory and
Nos. 13–1674, –1676, –2052, –2262 13
conclusional, as where the report says that “by planning for
future reliability needs on a region‐wide rather than a util‐
ity‐by‐utility or state‐by‐state basis, PJM’s Regional Trans‐
mission Expansion Planning (RTEP) process helps focus on
transmission upgrades that meet reliability criteria and in‐
crease economic efficiency. Annual savings: $390 million.”
Not only are the calculations that yield the $390 million fig‐
ure not disclosed, but there is no indication of how the bene‐
fits of the increased efficiency are likely to be distributed
across PJM’s region. Some of the savings that the report at‐
tributes to the new projects, such as greater generation ca‐
pacity, appear to be irrelevant to utilities in the western sub‐
region, such as Commonwealth Edison, because those utili‐
ties don’t need additional generation capacity; the need is in
the east.
In denying the petition of Dayton Power & Light (one of
the western utilities challenging the Commission’s postage‐
stamp approach) for rehearing of the Commission’s order on
remand, the Commission had repeated the statement in our
opinion that “if [the Commission] cannot quantify the bene‐
fits to the []western utilities from new 500 kV lines in the
east” it can nevertheless reinstate the order that we had va‐
cated if it “has an articulable and plausible reason to believe
that the benefits are at least roughly commensurate with”
the western utilities’ share of electricity sales in the entire
PJM region. PJM Interconnection, L.L.C., supra, 142 FERC
61216, ¶ 38. But even the modest goal of rough commensu‐
rability requires some effort by the Commission, as we in‐
sisted, to quantify the benefits. It hasn’t responded to that
directive. Instead it says such things as that the western utili‐
ties “will make use of and benefit from” the new eastern 500‐
kV transmission lines. Id. ¶ 37. The Commission doesn’t ex‐
14 Nos. 13–1674, –1676, –2052, –2262
plain how much use or how much benefit. Instead it points
out unhelpfully that “flows on the transmission facilities that
operate at or above 500 kV also can change over time.” Id.
¶ 47. Yes, but how likely is such change, when is it likely to
occur, and how great is it likely to be? These questions the
Commission ignores.
The Commission refers repeatedly to the fact that 500‐kV
transmission lines have an estimated useful life of 40 years,
and it emphasizes that much can change over 40 years. That
is indeed true—indeed a truism—but again unhelpful, as it
offers no insight into the likely character or direction of
change over that period. A lot of wind blows over the Atlan‐
tic Ocean, and maybe some day, as the Commission notes,
that wind will generate electricity for Chicago, or for that
matter Seattle. There are plans to build a large wind farm in
the Atlantic Ocean off Cape Cod. See “Cape Wind
Completing Geophysical Surveys; Aided by Four
Massachusetts Companies,” May 12, 2014, www.cape
wind.org/node/1751. But there is nothing in the Commis‐
sion’s opinions on remand concerning when the wind farm
(which is controversial, and has been repeatedly delayed
since it was first proposed in 2001, Katharine Q. Seelye,
“Funds and New Timetable for Offshore Wind Farm in
Massachusetts,” New York Times, Feb. 27, 2014, p. A16) will
be built or whether any of its power is likely to be transmit‐
ted to PJM’s western utilities. We don’t see how the prospect
of such a wind farm justifies making Commonwealth Edison
pay more for a transmission facility designed to reduce out‐
ages in New Jersey than the two primary utilities serving
New Jersey are required to pay.
Nos. 13–1674, –1676, –2052, –2262 15
Furthermore, the Commission, underlining what appears
to be an aversion to cost‐benefit analysis, ignores the need to
discount future to present value in order to value a future
benefit. Suppose it were certain (obviously it is not certain)
that in 2060 Commonwealth Edison will derive a $100 mil‐
lion benefit from an eastern transmission facility completed
in 2020 (and thus reaching the end of its useful life in 2060)
for which it was charged $100 million that year. At a dis‐
count rate of 5 percent the present value of that future bene‐
fit would be only $14.2 million.
The Commission states that since Exelon now owns not
only Commonwealth Edison but also an eastern PJM utility
(Baltimore Gas & Electric), Exelon’s “views of the benefits
that these subsidiaries receive from the new high voltage
connection lines will change over time as corporate struc‐
tures change, blurring distinctions between Eastern and
Western PJM.” Id. ¶ 48. But “corporate structure” has noth‐
ing to do with the benefits that the two subsidiaries will or
won’t receive from the Commission’s cost‐allocation system.
Exelon will be delighted by the benefits that its eastern sub‐
sidiary receives but distressed at the costs that its western
subsidiary will incur without corresponding benefits.
The Commission notes Dayton Power & Light’s argu‐
ment “that all of the 500 kV and above lines at issue are
hundreds of miles away from [Dayton Power & Light’s] sys‐
tem, and that it would be a near impossibility for lines lo‐
cated so far away to provide any meaningful role in reduc‐
ing the number of momentary [outages] or outages of less
than an hour experienced on the Dayton system.” Id. ¶ 58.
(For remember that when electricity is transmitted over long
distances, some of it is lost.) Dayton Power & Light adds that
16 Nos. 13–1674, –1676, –2052, –2262
“neither it, ComEd, nor AEP’s [American Electric Power’s]
Ohio subsidiaries own any 500 kV facilities, yet these com‐
panies do not experience abnormally high outage rates on
their transmission systems.” Id. To this the Commission’s
only reply is that “Dayton admits that the Western PJM
zones received some benefit from their integration into
PJM.” Id. ¶ 79. But will any of the benefit from the new
transmission facilities be in the western subregion? And if
so, how much? We’d settle for a rough estimate. The Com‐
mission made no estimate.
In similar vein the Commission, while acknowledging
that “western regions of PJM generally have sufficient gen‐
eration,” quotes ComEd as saying that it “sought member‐
ship in PJM first of all because of the reliability benefits that
membership would bring … and the most likely source from
which ComEd could import energy to prevent loss of load
during system emergencies is PJM.” Id. ¶ 76. True. But from
where in PJM?
By now it should be apparent that the basic fallacy of the
Commission’s analysis is to assume that the 500‐kV lines
that have been or will be built in PJM’s eastern region are
basically for the benefit of the entire regional grid. Not true;
their purpose is to address specific reliability violations in
the eastern part of PJM. No electric‐power company would
spend billions of dollars just to improve reliability in the ab‐
sence of reliability violations that required fixing. There are
bound to be benefits to the entire grid and therefore to the
utilities connected to it, but they are incidental, just as re‐
pairing a major pothole in a city would incidentally benefit
traffic in the city’s suburbs, because some suburbanites
commute to the city. So they should pay a share of the cost
Nos. 13–1674, –1676, –2052, –2262 17
of repair, but a share proportionate to their use of the street
with the pothole rather than proportionate to their popula‐
tion. The incidental‐benefits tail mustn’t be allowed to wag
the primary‐benefits dog.
The order on rehearing was approved by a 3 to 2 vote of
the FERC commissioners. Commissioner Clark’s dissent is
particularly pointed. He denies that “there is sufficient evi‐
dence or reasoning in the record to find that benefits for util‐
ities in the Midwest are even roughly commensurate to the
costs incurred under the postage stamp methodology. Inas‐
much as this is the case, I believe the Commission’s decision
has largely ignored the [Seventh Circuit’s] clear directive.”
He notes that the new “transmission facilities were ap‐
proved to resolve specific anticipated reliability violations in
the East, not to increase the general system‐wide benefits
discussed in the Order on Remand or the Order on Rehear‐
ing.” He points out that the Commission confuses benefits
from belonging to PJM, which accrue to all the members (a
member who doesn’t benefit quits—this happens from time
to time), with benefits from specific projects, noting suc‐
cinctly that “avoiding overloads in northern New Jersey re‐
duces outages first and foremost for those living in New Jer‐
sey.”
We conclude, with regret given the age of this case, that
the Commission failed to comply with our order remanding
the case to it. It must try again. If it continues to argue that a
cost‐benefit analysis of the new transmission facilities is in‐
feasible, it must explain why that is so and what the alterna‐
tives are. It has presented no evidence that postage‐stamp
pricing is an acceptable, or the only possible, alternative.
18 Nos. 13–1674, –1676, –2052, –2262
We acknowledge that the benefits of the new facilities to
the western utilities may prove unquantifiable because they
depend on the likelihood and magnitude of outages and
other contingencies, and that likelihood and that magnitude
may for all we know baffle the best analysts. If the Commis‐
sion after careful consideration concludes that the benefits
can’t be quantified even roughly, it can do something like
use the western utilities’ estimate of the benefits as a starting
point, adjust the estimate to account for the uncertainty in
benefit allocation, and pronounce the resulting estimate of
benefits adequate for regulatory purposes. If best is unat‐
tainable second best will have to do, lest this case drag on
forever.
To summarize, the lines at issue in this case are part of a
regional grid that includes the western utilities. But the lines
at issue are all located in PJM’s eastern region, primarily
benefit that region, and should not be allowed to shift a
grossly disproportionate share of their costs to western utili‐
ties on which the eastern projects will confer only future,
speculative, and limited benefits.
The petitions for review are granted and the matter once
again remanded to the Commission for new proceedings.
Nos. 13–1674, –1676, –2052, –2262 19
CUDAHY, Circuit Judge, dissenting. The issues presented
here are practically identical with those that we dealt with in
Illinois Commerce Comm’n v. FERC, 576 F.3d 470 (7th Cir.
2009)(“Illinois Commission I”). I filed a dissent in that case
and I emphatically reiterate its contents here.
The majority has expressed a need for more precise
numbers about benefits, burdens and a variety of other as-
pects. Now it has enhanced that need by suggesting the use
of cost-benefit analysis (a method, some think, of dressing
up dubious numbers to reach more impressive solutions). I
will say preliminarily that I think the majority is under the
impression that somehow there is a mathematical solution to
this problem, and I think that this is a complete illusion. De-
spite the frequency with which cost-benefit analysis is used,
it does not resolve the difficulty of accurately or meaningful-
ly measuring the costs and benefits involved with these grid
strengthening projects. Cost allocation, particularly at these
extraordinarily high voltages, is far from a precise science,
and there are no mathematical solutions to determining ben-
efits region by region or subregion by subregion. See PJM
Interconnection, L.L.C., 142 FERC ¶ 61,216 (2013) (“Remand
Rehearing Order”)(noting the difficulty of precisely quanti-
fying future benefits); see also Illinois Commerce Comm’n v.
FERC, 721 F.3d 764, 774 (7th Cir. 2013) (“Illinois Commission
II”)(same). Both parties acknowledged this much at argu-
ment. Cost allocation is a judgmental matter and should be
treated as such. E.g., Alabama Elec. Co-op., Inc. v. FERC, 684
F.2d 20, 27 (D.C. Cir. 1982) (explaining the cost causation
principle in a different context). Cost allocation produces
approximate results and requires selection of the most ap-
propriate methodology among many, none of which are nec-
essarily “right.” This is one reason courts should generally
20 Nos. 13–1674, –1676, –2052, –2262
be deferential to FERC’s technical analysis; and, I think
somewhat heretically, because the majority’s notions of cost-
causation and related technical concepts were not developed
in a context of extra-high voltage projects forming a back-
bone framework, judicial precedents involving radically dis-
tinguishable arrangements, especially those involving lower
voltages, are dubious guides to developing an appropriate
methodology here.
In addition, the majority indulges in descriptions of
many elements of the PJM grid and their functions without
reference to any engineering evidence in support. For exam-
ple, the majority claims that “the cities in the eastern region
(of PJM) use even lower voltage (230 kv lines) than the cities
in the western region, but most of the power plants are far-
ther away from the customers than in PJM’s western region
and therefore 500 kv lines are preferred even though more
expensive; the reason is that higher voltage reduces [line
loss].” Such a statement is at best a vast oversimplification,
and the comment that “it’s unlikely that much electricity will
be transmitted from the eastern to the western utilities via
the new transmission lines” is based on ignoring the poten-
tial for future developments of generation and transmission.
In fact, the entire thrust of the majority is toward precise
cost causation, even in the present case, where that is inde-
terminate or at least obscure. The effect of the majority opin-
ion is to emphasize functional relationships of the fragments
of PJM rather than its value as a unique whole. I do not
agree with the majority (or the Commission) that postage
stamp cost distribution is “crude.” The reason ascribed by
the majority for this deficiency assumes that some other
methodology, like DFAX, can trace the benefits of additions
Nos. 13–1674, –1676, –2052, –2262 21
with precision—an ability convincingly rejected by the
Commission. In fact, the postage stamp methodology is the
only one that can be mathematically verified. Thus, if one
knows the total cost of the improvements and the total
amount of the electrical output, one divided by the other
provides an unarguable dividend representing the uniform
burden of the various segments. Other methodologies pro-
vide approximations, but no more. The majority cites Illinois
Commerce Comm’n v FERC, 721 F.3d 764,774 (7th Cir. 2013), the
“wind power decision,” as evidence of tolerance for postage
stamp allocation but fails to indicate why that decision is not
more broadly precedential for this one. In an elaborate effort
to distinguish the very similar wind power decision, the ma-
jority underestimates the role of a ultra high-voltage back-
bone in equalizing benefits for all grid members. Why
should not uniformity of benefit as provided by the postage
stamp approach be the starting point in both cases?
In its critical analysis of an abandoned project in New
Jersey the majority cites the alleged single reason for build-
ing the project (rather than benefits derived from it). The ma-
jority then, by recourse to a Distribution Factor Analysis
(DFAX) approach, claims that the New Jersey utilities have
been virtually unscathed while Commonwealth Edison has
been grossly overcharged. Since this example does not even
purport to measure respective benefits (but focuses on mo-
tives for construction), I am afraid that it compares apples to
(abandoned) oranges. The majority apparently seeks to
compare an a priori reason for building the line with benefits
(a posteriori) derived from it.
In the next paragraph the majority repeats that our earli-
er opinion asked for an “articulable and plausible reason” to
22 Nos. 13–1674, –1676, –2052, –2262
believe that certain benefits exist, but rejects the Commis-
sion’s efforts to provide one for alleged lack of obviously ob-
scure detail. This goes far beyond the proper scope of judi-
cial review. The majority derogates the prospect of harness-
ing ocean winds, minimizing the well-known efforts to es-
tablish a wind farm in the Cape Cod area on the grounds
that that transmission project (like many, many others) is
controversial. More importantly, the majority seems to de-
value future impacts of projects lasting for a half century by
improperly discounting future benefits.
I could go on reciting in the case of Dayton Power and
Light the drumbeat for “precision,” which is simply beyond
human capability. I have the impression that the majority is
charging the Commission with lack of commitment in pur-
suing a “two plus two equals four” solution, but the Com-
mission is dealing with incommensurable forces and condi-
tions as skillfully and honestly as it can. It has my sympathy
as well as my respect.
The majority casually concedes the central point that
Commonwealth Edison joined PJM for the dominant reason
of improving its reliability, but in its unremitting pursuit of
fragmentation it insists on identifying exactly the source of
the reliability instead of recognizing PJM as an extraordi-
narily sophisticated centrally dispatched unit acting as a
whole. Nowhere does Commonwealth Edison, in its pursuit
of reliability, request a strengthening of some part of the grid,
but apparently relies on the reliability that the entire grid
provides. It should be no surprise that the Commission split
on how to respond to the demands of the majority for more
and more precision—specious or otherwise—and in the end
the majority concedes that its demand for numbers may be
Nos. 13–1674, –1676, –2052, –2262 23
unobtainable and we may have to accept whatever the
Commission can produce–whether second best, third best,
or whatever. The majority even approves rejection of DFAX,
but this was the very basis on which the protesters brought
this lawsuit. The only inescapable requirement of the majori-
ty seems to be finality and an end to litigation; in that respect
I certainly agree with the majority.
At one point the majority complains because the Com-
mission fails to specify the degree of “radiation” from an
upgraded facility and then recites with apparent authority a
difference in benefits and lack of uniformity between the
eastern and western utilities. Much of this is an effort to
supply various details of electrical phenomena, much more
the business of the Commission than of this court. The ma-
jority seems willing to pursue these details, as speculative
and unsupported conclusions, and faults the Commission
for not attaching precise magnitudes to its own bottom lines.
This is not judicial review; it is manufacturing its own “evi-
dence” as a substitute for the Commission’s but still seeking
greater exactitude. In any event, since the majority seems to
feel free to second guess the Commission, I will indulge in
the same freedom (hopefully without too much violence to
the Chenery principle) in proposing my own rationale for
upholding the FERC proposal.
First of all, I think it makes a great deal of sense to start
with the presumption that the costs of these extraordinarily
high voltage lines ought to be allocated on a shared cost or
postage stamp or Asocialized@ basis. 1 These extraordinarily
Indeed, the majority in Illinois Commission I acknowledged that a pre-
1
sumption of grid-wide benefits is appropriate for new projects because
the grid is integrated and the benefits are inherently spread over the en-
24 Nos. 13–1674, –1676, –2052, –2262
high voltages are not commonly found in electrical transmis-
sion systems generally and, if they are found, they constitute
what seems to be the backbone of an electrical grid. See PJM
Interconnection L.L.C., 138 FERC ¶ 61,230 (Mar. 30, 2012)
(“Remand Order”). By that, I mean that they are capable of
transmitting large quantities of bulk power long distances to
make the entire grid more reliable and more efficient. Id. By
their very nature their impacts are broader both geograph-
ically and temporally; that is, it=s much more difficult to pin-
point their exact benefits to some other part of the system or
to confine them to what is going on today rather than tomor-
row. See Remand Rehearing Order ¶ 67. In this proceeding,
the Commission considered the application of cost allocation
by Distribution Factor Analysis (DFAX) but rejected this ap-
proach for, I think, adequate reasons 2Bessentially that precise
tire grid. 576 F.3d at 477 (“[FERC] can presume that new transmission
lines benefit the entire network by reducing the likelihood or severity of
outages.”); see also Entergy Servs., Inc. v. FERC, 319 F.3d 536, 543 (D.C.
Cir. 2003)(noting that upgrades intended to preserve reliability are pre-
sumed to benefit the system as a whole). Given the backbone nature of
these extra high-voltage projects, I think this presumption is even more
compelling.
Under the DFAX methodology, PJM selects the single most severe reli-
2
ability violation for each project, models it on a 5-year period, and does
not revisit the allocation even if changes occur to the system before or
during construction. See Remand Order ¶ 41, 44. This method also bases
allocations solely on who causes the need for the new project, and does
not consider who will use the new line once it is built. See id. In other
words, the DFAX method is based on limited and temporally inflexible
information. Conversely, FERC found that the regional allocation meth-
od was adjusted every year to account for changes to the system, as well
as use a 15-year projection which allows for greater planning for future
developments affecting the grid. See id. ¶¶ 97, 117.
Nos. 13–1674, –1676, –2052, –2262 25
benefits and temporally limited impacts were impossible to
determine with this approach. See Remand Order ¶ 37. On
the other hand, the petitioners here base their entire case up-
on an application of this methodology. This is the essence of
the case; I think the so-called DFAX methodology is appro-
priate for relatively lower voltage transmission, but it is un-
suitable for the extraordinarily high voltage backbone for the
reasons I have mentioned above. Id.
If we start with a presumption that the cost of extraordi-
narily high voltage transmission lines should be allocated on
a shared cost or postage stamp basis, I see no reason to de-
part from that presumption here. The reasons on which the
protesters rely are based on an application of the DFAX
methodology, which the Commission has found to be inap-
propriate for reasons that no court should intervene to reject.
See id. ¶¶ 36–47. In fact, I think that the rejection here illus-
trates the dangers of substituting the court=s findings in
these technical matters for the Commission=s. In general, my
view of starting with a presumption (rebuttable, of course)
of shared costing for extraordinarily high voltage lines corre-
sponds to the reality of the situation reflecting why the line
is there and what its basic function is, namely to make the
entire grid more functional. 3 See id. ¶ 21. The protests here
Reliability is not a middling concern—power outages and the more se-
3
rious “cascading” outages are not uncommon. In 2003 a cascading out-
age in Ohio spread across several states, left over 50 million people and
resulted in economic losses in the billions. E.g., Mike Edmonds, 10 Years
Later, Power Outages Still Cost U.S. Billions Each Year, GridTalk (Aug. 14,
2013), available at http://www.sandc.com/blogs/index.php/2013/08/10-
years-later- power-outages- still-cost-u-s-billions-each-year. Estimates
put the annual cost of outages upwards of $80 billion. See Kristina
Hamachi LaCommare & Joseph H. Eto, Understanding the Cost of Power
26 Nos. 13–1674, –1676, –2052, –2262
are based on the approach of measuring the impact of the
backbone network and attempting to target its broad effect
to some subregion of the grid.
As a matter of equity, many tears have been shed here
over the plight of Dayton Power & Light, and particularly,
Commonwealth Edison (which, as the power supplier of the
forum is singled out), but these utilities joined the system
only a few years ago, even though they are many hundreds
of miles away from the original PJM (which has been in
business for many, many years and was unusually sophisti-
cated as a centrally dispatched grid). Interestingly, neither
Commonwealth Edison nor its parent Exelon is a party to
this proceeding, which may reflect a less intense degree of
objection to the outcome. Commonwealth Edison was well
aware of the reliance on ultra high voltage transmission as a
basic element in improving reliability in PJM, and Com-
monwealth Edison is significantly quoted by the majority as
having been motivated to join PJM by its need for reliability
benefits. Perhaps, Commonwealth Edison was surprised that
the cost of any additions would follow a postage stamp basis
rather than a DFAX basis, but I doubt that that possibility
escaped them completely and I see nothing inequitable
about requiring them to participate in the costs of these ad-
ditions, which are basically for the benefit of the entire grid.
Interruptions to U.S. Electricity Consumers, Lawrence Berkeley National
Laboratory, (Sept. 2004), available at http://certs.lbl.gov/pdf/ 55718.pdf.
Experts have estimated that the reliability savings from strengthening
the transmission backbone, and thus the entire grid, could be as much as
$49 billion, annually. See Massoud Amin, U.S. Electrical Grid Gets Less
Reliable, IEEE Spectrum (Dec. 30, 2010), available at http://spe-
ctrum.ieee.org/energy/policy/us-electrical-grid-gets-less-reliable.
Nos. 13–1674, –1676, –2052, –2262 27
This is the essence of my difference with the majority, which
says the Commission’s “basic fallacy” is to assume that the
500 kv lines are for the benefit of the entire grid. I do not
think this is a fallacy, and even Commonwealth Edison
seems to recognize that reality. Commonwealth Edison came
late to the party, and I think it is not unfair that they partici-
pate on a pro rata basis in these developments.
The majority also seems to be totally convinced of the po-
sition that, since the electrical flows at the moment are pri-
marily from east to west, almost the entire burden should be
placed on the eastern utilities; and in that regard my col-
leagues were very skeptical of the development of off-shore
wind farms in the Atlantic Ocean or other such future devel-
opments in electrical generation and transmission, as a pos-
sible basis for reversing the flow of power in the future. I can
only guess the specific prospects of offshore wind farms or
other developments, or how these specific developments
might affect the situation, but I certainly don=t think it is un-
likely that there will be significant changes in electrical flows
over these new facilities during the next 40 or 50 years when
the facilities will be in operation. Confining the Commission
to the DFAX methodology, which substantially restricts con-
siderations of grid development over time, the protesters’
approach ignores the function and outlook of a high voltage
backbone. See Remand Order ¶¶ 39, 41, 43, 111.
I suppose that the next version of things that we may get
from back from FERC will be some sort of hybrid system,
which would bow in the direction of what I think should be
presumptive (namely, a postage stamp methodology for
these extremely high voltage facilities), while maintaining
some aspects of an approach that superficially conforms to
28 Nos. 13–1674, –1676, –2052, –2262
various radically distinguishable judicial precedents. In my
opinion this will be unfortunate, since I firmly believe we
should allow the FERC to be creative in addressing these
unprecedented problems.
For these reasons I respectfully dissent.
Illinois Commerce Commission v. Federal Energy Regulatory Commission
Court: Court of Appeals for the Seventh Circuit
Date filed: 2014-06-25
Citations: 756 F.3d 556, 44 Envtl. L. Rep. (Envtl. Law Inst.) 20137, 2014 U.S. App. LEXIS 11961, 2014 WL 2873936
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