Benton County Wind Farm LLC v. Duke Energy Indiana, Inc.
Filing
Filed opinion of the court by Judge Easterbook. The judgment is REVERSED, and the case is REMANDED with instructions to determine the relief to which Benton is entitled. Richard A. Posner, Circuit Judge; Joel M. Flaum, Circuit Judge and Frank H. Easterbrook, Circuit Judge. [6802459-1] [6802459] [15-2632]
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In the
United States Court of Appeals
For the Seventh Circuit
____________________
No. 15-‐‑2632
BENTON COUNTY WIND FARM LLC,
Plaintiff-‐‑Appellant,
v.
DUKE ENERGY INDIANA, INC.,
Defendant-‐‑Appellee.
____________________
Appeal from the United States District Court for the
Southern District of Indiana, Indianapolis Division.
No. 1:13-‐‑cv-‐‑01984-‐‑SEB-‐‑TAB — Sarah Evans Barker, Judge.
____________________
ARGUED FEBRUARY 26, 2016 — DECIDED DECEMBER 6, 2016
____________________
Before POSNER, FLAUM, and EASTERBROOK, Circuit Judges.
EASTERBROOK, Circuit Judge. In 2005 Duke Energy Indiana
offered to buy 100 megawatts of renewable energy at a price
high enough to enable potential sellers to finance the con-‐‑
struction of wind turbines. As part of the deal Duke would
acquire renewable-‐‑energy credits that buyers or generators
of wind energy can trade or sell to other utilities that lack
wind generation. Benton County Wind Farm (Benton) ac-‐‑
cepted Duke’s offer and built a 100-‐‑megawatt facility that
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became operational in 2008. The contract between Duke and
Benton requires Duke to pay Benton for all power delivered
during the next 20 years. Duke does not have its own trans-‐‑
mission lines in Benton County, and the contract requires
Benton to deliver to lines owned by Northern Indiana Public
Service Company (NIPSCO) or some other place designated
by the regional transmission organization, the Midcontinent
Independent System Operator (MISO).
Electrical grids throughout North America are connected,
and it is essential to ensure that none of the transmission
lines becomes overloaded or fails to convey power to cus-‐‑
tomers that are counting on it. The ten regional transmission
organizations in North America develop technical standards
for how smaller networks connect with each other. They also
employ tools to monitor networks in order to prevent over-‐‑
loads or imbalances, which can cause blackouts. Our opinion
in MISO Transmission Owners v. FERC, 819 F.3d 329 (7th Cir.
2016), describes some of this regulatory and coordination
function, and it includes a map showing MISO’s territory,
which spans the middle of the continent from Manitoba
through Louisiana—all or part of 15 states plus one prov-‐‑
ince. It shares Indiana with PJM Interconnection, a regional
transmission organization whose territory includes Chicago,
New York City, and all or part of 13 states plus the District
of Columbia. Only MISO’s decisions affect this case.
Regional transmission organizations have concluded that
the price system is the best tool to balance loads on the net-‐‑
works. Potential buyers of energy bid for power to be deliv-‐‑
ered over the network (this is done principally through utili-‐‑
ties such as Duke and NIPSCO, which aggregate end-‐‑users’
demands); potential sellers such as Duke (on behalf of Ben-‐‑
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ton) also submit bids for sale, and the regional transmission
organization accepts the bid that clears the market.
When Benton’s wind farm started producing, the bidding
was conducted once a day. Now it is conducted every five
minutes—necessarily by computers. MISO uses a variant of
a Vickrey auction to decide which bids are accepted at what
price. Here’s a simple illustration. Buyer 1 bids $60 per meg-‐‑
awatt-‐‑hour (MWh) for 200 megawatts of power; Buyer 2 bids
$40 for another 200; Buyer 3 bids $30 for a further 200. If the
transmission grid in the area can carry 300 megawatts, then
Buyer 1 gets 200 megawatts and Buyer 2 gets 100; Buyer 3
gets nothing. The bid price is set at $40 per MWh, which is
what the marginal buyer is willing to pay; in a Vickrey auc-‐‑
tion, all buyers and sellers receive the same price. (Treasury
securities are sold using a similar system.) Meanwhile Seller
1 offers 100 megawatts at $20 per MWh, Seller 2 offers 100
megawatts at $30, Seller 3 100 megawatts at $40, and Seller 4
100 megawatts at $50. The market-‐‑clearing price and quanti-‐‑
ty are $40 for 300 megawatts. MISO accepts the bids from
Sellers 1, 2, and 3, and all three receive $40 per megawatt-‐‑
hour.
For some kinds of suppliers, such as wind farms, the
marginal cost of generating any unit of output is small, even
though the capital cost of building wind turbines is high. Ra-‐‑
ther than accept no sales, Seller 4 may cut its price to $10 per
MWh. Then the prevailing offer would be $30 (enough to
attract a total of 300 megawatts, the most the local grid can
carry), and all three buyers would pay $30. Sellers 1, 2, and 3
may not take this lying down. They may cut their own bids.
If all sellers bid only enough to cover their marginal costs,
the price in such a market could fall to, say, $1 per MWh,
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and even at that price one of the four potential sellers would
be unable to make a sale.
This is roughly what has happened in central Indiana.
When Benton started operating it was the only wind farm in
the area, and NIPSCO’s facilities could carry its entire out-‐‑
put. Duke purchased and paid for everything Benton could
produce, and MISO cleared the transfers to the regional grid.
But central Indiana has excellent conditions for generating
power from wind, and by 2015, when the district court is-‐‑
sued its opinion, aggregate capacity of local wind farms was
not 100 megawatts but 1,745 megawatts. More wind farms
are being built. The capacity of the local transmission grid
has been exceeded. It is no longer possible for all of the local
wind farms to generate power at the same time, because the
grid cannot accept their full output. And because local gen-‐‑
eration capacity substantially exceeds local transmission ca-‐‑
pacity, the market-‐‑clearing price in MISO’s auction has fall-‐‑
en—indeed, the price sometimes is negative, and then
would-‐‑be producers must pay MISO to take the power off
their hands, and buyers get free electricity. Prices near or be-‐‑
low zero induce some producers to stop supplying electrici-‐‑
ty and thus reduce output to what the grid can carry.
Until the end of February 2013 MISO allowed wind farms
to deliver to the grid no matter what other producers (coal,
nuclear, solar, hydro, and so on) were doing, which meant
that other classes of producers had to cut back. Sometimes
the market price in this must-‐‑carry-‐‑wind-‐‑power system fell
below zero, which meant that wind generation alone had
overtaxed the local grid. When that happened Duke paid a
negative price, displacing other wind farms to ensure that
Benton ran at capacity. So if the auction price was minus
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$10/MWh, Duke would pay MISO that amount and pay Ben-‐‑
ton for the power; it would receive nothing for this power
(save the potential value of renewable-‐‑energy credits) and
charge the loss to its customers. Duke could recover some of
the loss in its role as a buyer of power from MISO’s grid, be-‐‑
cause even if the power on NIPSCO’s grid goes north
(Duke’s operations are in southern Indiana), a lower price on
NIPSCO’s network will depress prices on other grids, which
will buy from NIPSCO and tell other sources to curtail their
own output. But Duke believes that it loses more in its role
as seller of Benton’s power than it gains in its role as buyer
from MISO.
On March 1, 2013, the rules changed to put wind farms
constructed after 2005 on a par with other classes of produc-‐‑
ers. Benton lost its status as a must-‐‑run facility. Duke re-‐‑
sponded to the new system by deciding to bid exactly $0, all
the time, to put Benton’s power on the grid. When this bid is
accepted, Duke gets the market-‐‑clearing price (usually posi-‐‑
tive but sometimes zero) and pays Benton the contract price
(roughly $52 per MWh). But when the market-‐‑clearing price
in MISO’s auction falls below $0, and Duke’s bid therefore is
rejected, MISO instructs Benton not to deliver any power.
Once Benton generates power it must deliver it (otherwise it
would fry its own equipment), so an order not to deliver
power equates to an order not to generate power, and Ben-‐‑
ton must stop its turbines from rotating. Under MISO’s new
system, with Duke’s standing bid of $0/MWh, Benton has
gone from delivering power 100% of the time the wind al-‐‑
lowed to delivering (and being paid) only 59% of the time
that the weather can drive its turbines at their capacity.
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In this litigation Duke takes the position that, when
MISO tells Benton to stop delivering power, it does not owe
Benton anything. Benton takes the position that Duke could
put Benton’s power on the grid by making a lower bid
(MISO accepts bids as low as negative $500 per MWh),
thereby displacing other producers’ power, and that when
Duke elects not to do this it owes liquidated damages under
the contract. Sometimes for load-‐‑balancing or other technical
reasons MISO tells Benton to stop delivering power even
when the market price exceeds zero and Duke’s bid nomi-‐‑
nally has been accepted. Benton acknowledges that in this
situation Duke need not pay damages.
The district court sided with Duke, ruling that it need
pay only for power delivered to the “Point of Metering”
where it is measured and passes to the local grid; when
MISO issues a stop order that quantity is zero. 2015 U.S.
Dist. LEXIS 181563 (S.D. Ind. Oct. 9, 2015). The parties have a
second contract that requires Duke to cooperate, reasonably,
in marketing Benton’s power; the district judge found that
bidding $0 is “reasonable” cooperation because it usually
leads Duke to suffer an out-‐‑of-‐‑pocket loss, since the market
price will be less than what Duke must pay Benton. Indeed,
on this understanding Duke might be entitled to bid $52 in
MISO’s auction and ensure that it makes a profit on reselling
every megawatt-‐‑hour that it buys from Benton.
This is a contract dispute, so we must set out the contrac-‐‑
tual clauses that matter. We have tried to be parsimonious;
interested readers can find more details in the district court’s
opinion. There are two contracts—the first requiring Duke to
buy Benton’s power, the second requiring Duke to cooperate
with Benton. The parties call the first the Renewable Wind
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Energy Purchase Power Agreement or PPA; they call the se-‐‑
cond the Joint Energy Sharing and Operating Agreement or
JESOA. We discuss the second contract briefly at the end of
this opinion. For now, we refer to the first contract as “the
contract.”
We have already mentioned one clause. The contract re-‐‑
quires Duke to purchase Benton’s output, which it defines as
“the entire electrical output of the Plant delivered to the
Point of Metering” (emphasis added). A separate clause de-‐‑
fines that point as where Benton connects with the local grid
(either NIPSCO’s or another designated by MISO). Benton
relies principally on §4.6(a) of the contract, a liquidated-‐‑
damages clause captioned “Buyer’s Failure to Accept Deliv-‐‑
ery of Electrical Output”:
In the event that Buyer fails to accept delivery of all of the Elec-‐‑
trical Output at the Point of Metering, whether due to Buyer’s
failure to obtain Transmission Service (if applicable) or for any
reason other than Seller’s failure to perform, an Emergency
Condition, a Force Majeure Event that prevents such acceptance
pursuant to Article 14 or the proper exercise by Buyer of its sus-‐‑
pension rights pursuant to Section 15.2(a), then Buyer shall pay
to Seller as liquidated damages an amount equal to the positive
difference, if any, between (i)(x) the amount that would have
been payable by Buyer to Seller hereunder if such Electrical
Output had been accepted by Buyer plus (y) additional trans-‐‑
mission charges, if any, reasonably incurred by Seller in deliver-‐‑
ing the Electrical Output to such third party purchaser and (ii)
the net amount, if any, that Seller using Commercially Reasona-‐‑
ble Efforts, actually realizes through remarketing of such Electri-‐‑
cal Output to Persons other than Buyer, provided that in the event
Seller is unable to remarket such Electrical Output, then the net
amount described in clause (ii) shall be $0 and the damages
owed by Buyer shall also include the then-‐‑current amount of the
PTC (on a per MWh basis) on an After-‐‑Tax Basis for each MWh
of such Electrical Output that Seller was unable to remarket. The
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damages provided in this Section 4.6 shall be the sole and exclu-‐‑
sive remedy of Seller for any failure of Buyer to accept delivery
of Electrical Output that it is required to accept hereunder.
One more long clause matters. It is §6.4, captioned “Trans-‐‑
mission”:
Buyer represents that it intends to deliver and sell all of the Elec-‐‑
trical Output to [MISO] at the Point of Metering and does not in-‐‑
tend to utilize any Transmission Services. If Buyer nevertheless
utilizes Transmission Services for the Electrical Output during
the Term or is required (due to a change in the applicable trans-‐‑
mission rules) to use Transmission Services in order to accept de-‐‑
liveries of the Electrical Output at the Point of Metering, then
Buyer shall be responsible for arranging for all Transmission
Services required to effectuate Buyer’s acceptance of delivery of
and purchase of Electrical Output, including, without limitation,
obtaining Transmission Service, in an amount of capacity equal
to the Designated Nameplate Capacity Rating, and shall be re-‐‑
sponsible for the payment of any charges related to such Trans-‐‑
mission Services hereunder, including, without limitation,
charges for transmission or wheeling services, ancillary services,
imbalance, control area services, congestion charges, location
marginal pricing, transaction charges and line losses. The Parties
acknowledge that the purchase price of Electrical Output does
not include charges for such Transmission Services, all of which
shall be paid by Buyer.
Finally, there is a definition of “transmission services” as:
all transmission or wheeling services, scheduling services, im-‐‑
balance services, OASIS, congestion and congestion manage-‐‑
ment services, tagging services, dispatch services, ancillary ser-‐‑
vices, control area services, and other transmission services nec-‐‑
essary for Buyer to accept Electrical Output at the Point of Me-‐‑
tering and transmit, and deliver Electrical Output from the Point
of Metering, using the highest priority transmission service
available.
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Many other clauses and definitions potentially have some
bearing, but we think that these few decide the case. The
parties agree that Indiana law governs, but they do not rely
on any principles unique to Indiana. The dominant principle
is that courts follow contractual language unless ambiguity
permits the use of parol evidence. The parties agree that this
contract is clear (though not on what it means), and we too
think it unnecessary to go beyond the document’s language.
Benton tells us that §4.6(a) is a take-‐‑or-‐‑pay clause, requir-‐‑
ing Duke to pay for energy whether taken or not. The district
court was not persuaded, and neither are we, for then it
would require Duke to pay Benton even if the reason for
non-‐‑delivery is an instruction that MISO issues independent
of how much Duke bid in the auction and independent of
how much transmission capacity is available. MISO might
issue such an order if, for example, there is a decline in de-‐‑
mand on the buyers’ side of the market or a technical fault in
some other grid, which cannot accept as much power from
NIPSCO’s lines.
Yet Benton concedes that Duke need not pay when it re-‐‑
ceives such a stop order. Duke says, without contradiction
from Benton, that the market-‐‑clearing price is positive 80%
of the time and Duke’s $0 bid thus is accepted (just as a neg-‐‑
ative $500/MWh bid would have been), but that MISO al-‐‑
lowed Benton to generate power only 59% of the time; the
difference between 80% and 59% must be attributable to
MISO’s decisions rather than Duke’s bid. If Duke need not
pay Benton for energy when MISO’s choices, alone, account
for non-‐‑generation, §4.6(a) can’t be a standard take-‐‑or-‐‑pay
clause. Nor does it call itself a take-‐‑or-‐‑pay requirement; it
calls itself a liquidated-‐‑damages clause.
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But the opposite view—that if energy is not generated
and so does not cross the Point of Metering, and never
counts toward actual output, for any reason at all (including
Duke’s entry of a standing $52/MWh bid), then Benton need
not be paid—also is unfaithful to the contractual language.
Section 4.6(a) makes it clear that some reasons for Duke’s
failure to take energy excuse payment; and from the limited
range of reasons that justify nonpayment it follows that oth-‐‑
er reasons are inadequate and that payment remains due.
The key to resolving the parties’ dispute lies toward the
beginning of §4.6(a), which requires Duke to pay if it “fails
to accept delivery of all of the Electrical Output at the Point
of Metering, whether due to Buyer’s failure to obtain Trans-‐‑
mission Service (if applicable) or for any reason other than
… [a list].” This covers the sort of situation that prevailed
after MISO changed its dispatch rules at the end of February
2013 and no longer deemed Benton a must-‐‑carry generator.
As of March 2013, Benton was being told to stop 41% of the
time because transmission was unavailable at the price Duke
was willing to offer—and could have been unavailable even
if Duke had bid negative $500/MWh, if owners of the re-‐‑
maining local wind farms had made the same negative bid.
With insufficient transmission capacity, someone (or a lot of
someones) had to stop delivering energy to NIPSCO’s facili-‐‑
ties no matter what price Duke offered.
But the contract provides what is to happen when the
stoppage is “due to Buyer’s failure to obtain Transmission
Services”. Duke is to pay for power not taken. Duke could
build its own transmission lines or buy extra capacity from
NIPSCO or some other firm. (Our opinion in MISO Trans-‐‑
mission Owners describes the process by which MISO allo-‐‑
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cates the rights to build new lines or augment existing ones.)
If there is a market for transmission services, as there surely
is in central Indiana where more and more wind power is
becoming available, then there will be a supply of transmis-‐‑
sion lines. It is only a matter of time until more capacity is
built, whether by Duke or someone else. And §4.6(a) tells us
that, until this happens, Duke must pay Benton. The risk of
inadequate transmission was contemplated by the contract-‐‑
ing parties and allocated to Duke. By accepting this risk,
Duke enabled Benton to finance its project; otherwise poten-‐‑
tial investors might have feared exactly the overcapacity sit-‐‑
uation that has come to pass. Duke wanted Benton’s facili-‐‑
ties to exist and called them into existence by promising to
pay even if a shortfall of transmission services should lead to
curtailment of deliveries.
Duke resists that conclusion by pointing to the opening
of §6.4, and some equivalent language elsewhere in the con-‐‑
tract, which relate that Duke did not plan or want to operate
transmission lines, contemplated immediately handing Ben-‐‑
ton’s power to MISO at the Point of Metering, “and does not
intend to utilize any Transmission Services.” That’s fine as a
statement of Duke’s goal; maybe it believed that extra
transmission capacity would be unnecessary or that NIPSCO
would add to its own capacity as wind farms were built. But
§6.4 does not say that Duke will never need to add transmis-‐‑
sion capacity itself or that it is excused from paying Benton if
it chooses not to.
To the contrary, three parts of the contract strongly imply
that Duke must do what is needed to make transmission ca-‐‑
pacity available. One is the contract’s definition of “trans-‐‑
mission services” to include “other transmission services
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necessary for Buyer to accept Electrical Output at the Point of
Metering” (emphasis added). The second is in §4.6(a), which
says that Duke must pay if the failure to deliver power is
caused by “Buyer’s failure to obtain Transmission Service (if
applicable)”. Now go back to the second sentence of §6.4 for
the third, which tells us that “[i]f Buyer nevertheless utilizes
Transmission Services for the Electrical Output during the
Term or is required (due to a change in the applicable
transmission rules) to use Transmission Services in order to
accept deliveries of the Electrical Output at the Point of Me-‐‑
tering” then Buyer (Duke) must pay the full cost. What
would be the point of this clause, if Duke never has an obli-‐‑
gation to obtain transmission service for the power Benton is
able to generate? Sections 4.6(a) and 6.4 read together tell us
that Duke must arrange for new transmission services if they
prove to be necessary for Duke to accept all of Benton’s
power after a “change in [MISO’s] applicable transmission
rules”.
The district court rejected this line of reasoning, 2015 U.S.
Dist. LEXIS 181653 at *71–73, because MISO has not required
Duke to add transmission capacity. In other words, the court
understood the word “required” in §6.4 to mean “required
by MISO” and the parenthetical clause “if applicable” in
§4.6(a) to mean “if required under §6.4.” Yet §6.4 does not
say “required by MISO”. It says “required (due to a change
in the applicable transmission rules) … in order to accept de-‐‑
liveries of the Electrical Output at the Point of Metering.”
And “Electrical Output” is defined, as we have already
quoted, as all of the power that Benton generates, not just the
power that can coexist on NIPSCO’s lines with all other
wind-‐‑generated power in the area. MISO’s role in §6.4 is not
to require Duke to build transmission capacity, but to
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change the rules of dispatching power over whatever trans-‐‑
mission capacity happens to exist. MISO did that; the upshot
was that it no longer accepted all of Benton’s output; and the
consequence under §4.6(a) and §6.4 is that Duke must either
build (or arrange for) more transmission capacity or pay
Benton the amount specified in §4.6(a).
Potential buyers and sellers of electricity could and did
foresee when negotiating this contract (and others like it)
that electrical grids may be swamped by new sources of re-‐‑
newable power, which usually is located far from the centers
of demand. They needed to allocate the risk of that devel-‐‑
opment, which predictably would compel MISO to alter its
rules for which sources could put power on the grid. Allo-‐‑
cating the risk to Benton would have made it hard, perhaps
impossible, to finance the project’s construction, while leav-‐‑
ing Duke and similar utilities no incentive to expand the re-‐‑
gional grids as wind power became available. Allocating the
risk to Duke facilitates both construction of renewable-‐‑
energy sources and better incentives to match the size of the
transmission grid to the capacity for local generation. We
read this contract as allocating the risk to Duke, which
means that Benton receives the compensation provided by
§4.6(a) and Duke has the right incentives to build or buy ex-‐‑
tra transmission capacity.
Duke contended in the district court that MISO’s 2013
rules are an “Emergency Condition” for the purpose of
§4.6(a) and prevent any recovery. It has not renewed that ar-‐‑
gument on appeal, perhaps because it is hard to think of a
long-‐‑term set of rules for pricing and dispatching power as
an “emergency.” We could imagine an argument that an un-‐‑
anticipated change in MISO’s rules is enough of an “emer-‐‑
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gency” to give Duke time to build or acquire new transmis-‐‑
sion capacity without needing to compensate Benton in the
interim, but MISO announced the new rules years in ad-‐‑
vance and phased them in slowly. Duke did not attempt to
add transmission capacity in the time between the rules’ an-‐‑
nouncement and their 2013 application to post-‐‑2005 wind
farms—and as far as we can tell it has not attempted to build
or buy new transmission capacity in Benton County since
then. This line of argument therefore is unavailable.
We have so far not discussed the terms of the second con-‐‑
tract, which the parties call JESOA. Because we have con-‐‑
cluded that Benton prevails under the first contract, the se-‐‑
cond would be important only if it entitles Benton to a larger
recovery. The damages clauses of the two contracts differ (as
do the clauses that determine each party’s responsibilities),
so that it is possible in principle that Duke could be liable
under one, the other, or both, and owe different damages
under each. But we do not understand Duke to contend that
its recovery under the second contract would exceed its re-‐‑
covery under the first. Indeed, Benton’s briefs in this court
mention the second contract only once, in passing, and make
nothing of it substantively. We therefore think it unneces-‐‑
sary to decide whether Duke is liable under the second con-‐‑
tract and, if so, what damages that contract would provide.
The judgment is reversed, and the case is remanded with
instructions to determine the relief to which Benton is enti-‐‑
tled.
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POSNER, Circuit Judge, concurring. I agree with the deci‐
sion to reverse the judgment of the district court and remand
for a calculation of damages. But I think the majority opin‐
ion’s analysis could be simplified, and in addition I disagree
with the majority’s discussion of damages for the breach of
the second contract.
This is a diversity suit that presents issues of Indiana con‐
tract law. Benton County Wind Farm, the plaintiff and ap‐
pellant, operates a plant in northwestern Indiana that uses
wind to push turbines that generate electricity, which it sells.
In 2006, before construction of the wind farm had begun,
Duke Energy, a large electrical company also in Indiana,
signed a 20‐year contract with Benton in which Duke agreed
either to pay a fixed price for the output of the wind‐
powered electrical plant that Benton was planning to build,
or to refuse to accept the output and instead pay liquidated
damages to compensate Benton for the loss of business. In
2007 Benton proposed to construct additional turbines,
which would increase the wind farm’s capacity to generate
electricity; and Duke and another buyer, called Vectren
Power Supply (not a party to this case), agreed to split the
purchase of the additional power. A second contract, this
one between Benton on the one hand and both Duke and
Vectren on the other, defined the amounts Vectren and Duke
would each purchase, resolved certain issues arising from
the fact that there would be two buyers for Benton’s output,
and forbade Duke to take steps to reduce Benton’s output.
The first contract is the “Renewable Wind Energy Project
Purchase Power Agreement” (I’ll call it just the “Purchase
Power Agreement”) and the second (discussed in the majori‐
ty opinion only for its relevance to liability) is the “Joint En‐
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ergy Sharing and Operating Agreement.” I’ll discuss the two
contracts in that order.
MISO (Midcontinent Independent System Operator)—
the Regional Transmission Organization that coordinates
and to a considerable extent controls the transmission of
electricity in a number of midwestern and southern states,
including Indiana, and also in a chunk of Canada—buys en‐
ergy from producers like Benton. It had begun acquiring
wind‐powered electricity on the basis of competitive offers
instead of buying all the wind energy offered to it. Some‐
times producers of wind energy would even have to pay
MISO to induce it to accept their energy, which they were
willing to do because even if they lost money on the sale
they’d get a valuable tax credit for producing renewable en‐
ergy.
Duke would be an intermediary between Benton and
MISO, buying from Benton and selling to MISO. It offered
the energy it was buying from Benton to MISO at a price of
$0/MWh (that is, at a zero price for each unit of energy equal
to the amount of electricity that a megawatt of output would
transmit to MISO over one hour). Obviously that offer price
was not a market price, and MISO paid Duke (as it did the
other suppliers of electricity to the transmission grid) the
market price if it exceeded the offer price. If however the
market price happened to be zero, Duke still would deliver
the energy to MISO at the free offer price (i.e., $0/MWh), but
it would never sell to MISO at a negative price, as that
would mean that Duke was paying both Benton (for the en‐
ergy) and MISO (for accepting delivery of the energy).
It might seem that a market price would never be nega‐
tive, but actually it could be because of an excessive supply
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17
of wind energy and/or inadequate transmission capacity.
And when it was negative, and Duke therefore wouldn’t pay
MISO to take Benton’s energy, MISO would tell Benton to
stop producing; otherwise the electricity could keep coming,
even though MISO was surfeited with electricity, which is
why it wouldn’t accept any more wind‐powered electricity
unless paid to take it.
The Purchase Power Agreement, the first of the two
agreements between Benton and Duke at issue in this case,
requires that “Buyer [Duke] shall accept and purchase from
Seller [Benton] Electrical Output of the Plant,” and “Seller
will not have the right to sell to third parties any of the Elec‐
trical Output” unless Duke has refused to accept it. The con‐
tract goes on to provide that “in the event that Buyer fails to
accept delivery of all of the Electrical Output at the Point of
Metering, whether due to Buyer’s failure to obtain Transmis‐
sion Service … or for any [other] reason” (with some excep‐
tions), Duke must pay Benton liquidated damages unless
Benton can find some other company to buy the power that
Duke is refusing to accept from it. The liquidated damages
are to consist of the contract price for the power plus the
production tax credit that Benton would have earned by
producing the power. The credit is a tax break that the fed‐
eral government provides to producers of renewable energy
sources, such as wind power, to encourage efficiency in the
production and transmission of electricity. U.S. Department
of Energy, “Renewable Electricity Production Tax Credit
(PTC),” http://energy.gov/savings/renewable‐electricity‐prod
uction‐tax‐credit‐ptc (visited December 5, 2016).
Duke argues and the district court ruled that because the
contract defines “Electrical Output” as “the entire electric
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energy output of the [Benton] Plant delivered to the Point of
Metering,” Duke has no liability for refusing power not de‐
livered to that point. The district court’s ruling ignores,
however, the fact—not contested by Duke, and surely
known by senior staff in the electrical‐generation and trans‐
mission industry of Indiana and therefore implicit in any
contract made by the electrical firms in that market—that it’s
physically impossible for Duke to reject electricity that has
reached the Point of Metering. Electricity dispatched by Ben‐
ton flows to the Point of Metering but doesn’t stop there, be‐
cause traveling as it does at upwards of half the speed of
light it enters almost instantaneously into the transmission
grid.
It’s not that electricity can’t be stopped because of the
speed at which it travels; every time one turns off an appli‐
ance that draws electricity the electrical flow to the appliance
is stopped. But a flow of electricity can’t be stopped at the
Point of Metering, because it’s merely the point at which
electricity flowing from the Benton Wind Farm enters the
grid (the Purchase Power Agreement refers to it as an “inter‐
connection point”). There is no switch at that point, which
could be turned off to stop the flow of electricity. Once ener‐
gy is generated by Benton and transmitted to the Point of
Metering, Duke has no way to prevent it from flowing into
the grid.
This is not to say that points of metering are unim‐
portant; they play an important role in billing and more gen‐
erally in managing the flow of electricity between electrical
companies. See New York Independent System Operator,
“Revenue Metering Requirements Manual” p. 1‐1 (August
2013), www.nyiso.com/public/webdocs/markets_operations/
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documents/Manuals_and_Guides/Manuals/Administrative/
rev_mtr_req_mnl.pdf (also visited on December 5, 2016). But
a point of metering is not a wall or an on‐off switch. Article 8
of the Purchase Power Agreement is explicit that the equip‐
ment at the point of metering consists of meters (measuring
devices), not on‐and‐off switches or shut‐off valves.
Because there is no such equipment at the Point of Meter‐
ing, the only way Duke can refuse to receive Benton’s elec‐
tricity is to tell it not to send its output to (which also means
beyond) the Point of Metering. Unless required to pay liqui‐
dated damages to Benton when it tells Benton not to send
electricity to the Point of Metering, Duke would be avoiding
all liability simply by telling Benton not to send electricity
Duke’s way; the liquidated‐damages clause in the contract
would thus be a nullity.
Benton further appeals to a provision in the contract
which states that “the Parties will reasonably cooperate with
each other with respect to the bidding and scheduling with
… the RTO [i.e., MISO] of the Electrical Output to be sold
and delivered by Seller [Benton] and accepted and pur‐
chased by Buyer [Duke]. Buyer will be responsible for all
such bidding and scheduling.” Reasonable cooperation
would appear to require that Duke not block Benton from
supplying power to MISO without compensating Benton in
accordance with the liquidated‐damages provision. This in‐
terpretation is reinforced by section 6.3 of the contract,
which provides that “nothing in Section 6.2 … shall require
Seller [i.e., Benton] to take any action effecting … any reduc‐
tion in the Electrical Output.” By ordering and thus compel‐
ling Benton to reduce its delivery of energy to the Point of
Metering, Duke could be thought to be violating section 6.3
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by requiring Benton to reduce its output, and therefore to be
required to pay liquidated damages to compensate Benton
for the loss of revenue resulting from the reduction in deliv‐
ery.
Another provision in the Purchase Power Agreement
states, however, that the “Seller [i.e., Benton] will not have
the right to sell to third parties any of the Electrical Output”
unless Duke “fails to accept delivery.” The clause we’ve itali‐
cized frees Benton to sell to other electrical companies if
Duke refuses to buy from it, and if Benton sells to other
companies at the same price that Duke would pay, it would
not be entitled to liquidated damages, because it wouldn’t
have suffered a loss (aside from extra transmission expenses,
which the contract covers). Similarly, if Benton finds another
buyer willing to buy its energy but only at a lower price than
Duke is willing to pay, the liquidated damages owed by
Duke to Benton will fall by the amount of revenue that Ben‐
ton is able to recoup from the new buyer.
That the Purchase Power Agreement itself does not men‐
tion that electricity generated by Benton and fed into Duke’s
transmission line does not stop at the Point of Metering, but
continues unaltered into the transmission grid, is not fatal to
Benton’s argument for liquidated damages. A court cannot
decide a suit for breach of contract by ignoring facts critical
to the alleged breach. Krieg v. Hieber, 802 N.E.2d 938, 944
(Ind. App. 2004). “This is upon the principle that the court
may be placed, in regard to the surroundings and circum‐
stances, as nearly as possible in the position of the parties
whose writings are to be interpreted.” Ransdel v. Moore, 53
N.E. 767, 769 (Ind. 1899). The district judge indicated aware‐
ness of the physics of transmission, how a wind turbine
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works, and how MISO structures its bidding process. All
these were uncontested facts essential to understanding the
contracts at issue, facts of which the judges on this panel can
take judicial notice. And though hardly necessary we can
also appeal to the familiar analogy of the medieval law re‐
garding “blood letting” in the streets of the Italian city of Bo‐
logna—the law that, as famously explained in William
Blackstone’s Commentaries on the Laws of England, vol. 2, p. 60
(1765), stated that “whoever drew blood in the streets should
be punished with the utmost severity.” Blackstone asked
whether the law should have been interpreted to make pun‐
ishable a surgeon “who opened the vein of a person that fell
down in the street with a fit.” He thought not, saying that
“the fairest and most rational method to interpret the will of
the legislator, is by exploring his intentions at the time when
the law was made, by signs the most natural and probable.
And these signs are either the words, the context, the subject
matter, the effects and consequence, or the spirit and reason of
the law … . As to the effects and consequence, the rule is,
where words bear either none, or a very absurd signification,
if literally understood, we must a little deviate from the received
sense of them” (emphases added). The law did not mention
surgeons, but Blackstone thought it obvious that the legisla‐
tors, who must have known something about surgeons (ac‐
tually “barber surgeons”), had not intended the law to apply
to them. It is likewise obvious that firms engaged in the pro‐
duction and transmission of electricity know that it doesn’t
stop at a “Point of Metering,” as if it were water stopped by
a dam.
Another factor to be considered, however, is the duration
of the contract—20 years. As pointed out in an amicus curiae
brief submitted by the American Wind Energy Association
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“in Support of Neither Party,” wind energy entrepreneurs
must make a large investment in creating wind farms, and
having a predictable flow of revenue is important in ena‐
bling the entrepreneurs to attract the needed investment.
Benton County Wind Farm will have lost that predictable
flow if the district court’s decision is affirmed. Cutting the
other way, however, is the pincers that Duke Energy has
been placed in as a result of developments apparently not
foreseen by the parties when they drafted the Purchase
Power Agreement back in 2006—namely the sprouting of a
number of other wind energy farms in Indiana where once
Benton had been one of only a few. The electrical energy
transmitted by the growing Indiana wind energy industry
crowded the transmission grid and led to efforts by MISO to
reduce the flow. The electricity that Duke buys from Benton
is sold to MISO at the Point of Metering at what is called the
Locational Marginal Price (LMP), which is based on energy
costs, congestion costs, and line losses. The price is set uni‐
laterally by MISO rather than negotiated with Duke. As ad‐
ditional wind energy farms came on line, the congestion
component of the LMP soared to the point at which sellers to
MISO, such as Duke, had to pay MISO to take their electrici‐
ty; that is, the price to MISO had turned negative. That
meant that for electricity bought from Benton and sold to
MISO at the point of metering, Duke would be losing money
because it would be paying both Benton for the electricity
and MISO for accepting the electricity forwarded to it by
Duke.
Duke could avoid such a loss by bidding $0/MWh to
MISO, so that upon receiving a negative‐price offer from
MISO (that is, being told by MISO that MISO would not pay
a positive price for electricity generated by Benton for resale
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by Duke to MISO), MISO would direct Benton not to trans‐
mit electricity to Duke. The result was to curtail Benton’s
output and revenues, except insofar as Benton was able to
find other buyers for its electricity—an issue not illuminated
by the parties’ submissions in this litigation.
Duke is arguing that the change in the market caused by
wind energy congestion, which in turn caused MISO often to
refuse to accept transmission of such energy without being
paid to accept it, altered Duke’s obligations under the con‐
tract, which had not contemplated Duke’s having to pay
both Benton and MISO for the same electricity—Benton to
transmit the electricity at the Point of Metering and MISO to
receive it there from Duke. Recall the provision in Duke’s
contract with Benton that requires the parties to “reasonably
cooperate with each other with respect to the bidding and
scheduling with … [MISO] of the Electrical Output to be
sold and delivered by [Benton] and accepted and purchased
by [Duke].” One possible interpretation of reasonable coop‐
eration is that Duke must buy all the electricity that Benton
wants to sell it, but another is that Benton must accept a re‐
duction in the amount of electricity bought from it by Duke
in recognition that “reasonable cooperation” requires a com‐
promise in which both parties accept a reduction in compen‐
sation as a result of a development beyond their control—
that development in this case being the advent of an unex‐
pected number of new wind energy farms, requiring in turn
an alteration in MISO’s purchasing policies. But it’s unlikely
that this provision was intended to place limits on the finan‐
cial obligations of the parties to each other in the bidding
process—the clause is terribly fuzzy and the liquidated
damages clauses deal adequately with the problem.
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Yet some years ago, Wisconsin Electric Power Co. v. Union
Pacific R.R., 557 F.3d 504 (7th Cir. 2009), noted that “the doc‐
trine of impossibility in the common law of contracts excuses
performance when it would be unreasonably costly (and
sometimes downright impossible) for a party to carry out its
contractual obligations. If the doctrine is successfully in‐
voked, the contract is rescinded without liability. The stand‐
ard explanation for the doctrine is that nonperformance is
not a breach if it is caused by a circumstance ‘the non‐
occurrence of which was a “basic assumption on which the
contract was made.”’” Id. at 505, quoting Restatement (Second)
of Contracts, introductory note to ch. 11, preceding § 261
(1981), quoting UCC § 2–615. Conceivably, to require Duke
to pay a positive price to Benton for wind‐powered energy
and receive a negative price for the same energy from MISO
(that, or pay liquidated damages), resulting in Duke’s ob‐
taining zero or negative revenue, could be regarded as “un‐
reasonably costly” to Duke, requiring a modification of its
contract with Benton. But neither in the district court nor in
this court has Duke argued impossibility. It did plead as an
affirmative defense a provision in the contract which states
that enforcement is to be limited by general principles of eq‐
uity, including “concepts of … reasonableness.” But it can’t
be that the mere fact that additional wind farms were built
in Indiana after the contract was signed made enforcement
of the contract, and in particular invocation of the liquidat‐
ed‐damages provision by Benton, unreasonable.
So Duke violated the Purchase Power Agreement, and
therefore I agree with the majority that the judgment of the
district court regarding that branch of the case must be re‐
versed and the case remanded for a determination of the
amount of liquidated damages to which Benton is entitled.
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The second agreement between Duke and Benton is the
Joint Energy Sharing and Operating Agreement. This
agreement requires Duke to buy part of the additional out‐
put of the Benton wind farm resulting from its increasing its
production capacity by 30 megawatts, and (in this respect
much like the Purchase Power Agreement) denies Duke “the
right to curtail or reduce [Benton’s] Total Facility Output,”
defined as “the total electrical energy produced by [Benton]
… as measured at the Delivery Point,” which is another
name for the Point of Metering. Duke violated the contract
by using MISO’s competitive bidding process to curtail Ben‐
ton’s production whenever market prices are negative. Since
Duke can curtail Benton’s output only as “expressly provid‐
ed” in the Purchase Power Agreement, and the only express
provision for reducing output requires Duke to pay liqui‐
dated damages, Duke’s curtailment of Benton’s output
without paying liquidated damages is a breach of the second
contract between the parties as well as of the first.
This is clear enough to require reversal of the district
court’s rejection of Benton’s argument that Duke breached
the second contract. The majority opinion treats Duke’s
breach of the second contract as a duplicate source of the
same damages as required by the breach of the first contract.
But the second contract determines how much of the ex‐
panded output of the Benton wind farm Duke is required to
pay for, and if it fails to pay, how much in damages it will
owe Benton.
Regarding the second point, the issue of damages, the
second contract (the Joint Energy Sharing and Operating
Agreement) provides that “each party’s liability hereunder
shall be limited to direct actual damages only,” and “neither
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party shall be liable for … lost profits or other business inter‐
ruption damages.” There is no definition of “direct actual
damages,” and the meaning of the term has not been briefed
on appeal. Duke may owe Benton less in “direct actual dam‐
ages” for its failure to buy any of the expanded output of the
Benton wind farm than it would owe were there a liquidat‐
ed‐damages clause in the second contract. Benton’s losses
from not operating its wind farm seem most like “lost profits
or other business‐interruption damages.” The amount of
damages to which Benton is entitled by Duke’s breach of the
second agreement therefore remains to be determined on
remand. A further complication is that although there’s no
liquidated‐damages clause in the second contract, the con‐
tract refers to the Purchase Power Agreement throughout in
such a way as to indicate that the parties may have expected
the liquidated‐damages clause to apply, for otherwise, given
that direct actual damages are likely to be zero or close to
zero, the purpose of the Joint Energy Sharing and Operating
Agreement would be defeated. Benton wanted to secure a
steady income stream before it began constructing the new
turbines, just as it had wanted before constructing the plant
in the first place. It had the incentive under both contracts to
have fallback protection in the form of a liquidated‐damages
clause.
I trust that on remand the district judge will be conscious
of the “long tradition in contract law of reading contracts
sensibly,” not as “parlor games but [as] the means of getting
the world’s work done.” Beanstalk Group, Inc. v. AM General
Corp., 283 F.3d 856, 860 (7th Cir. 2002), quoting Rhode Island
Charities Trust v. Engelhard Corp., 267 F.3d 3, 7 (1st Cir. 2001).
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