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 construction 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) accepted Duke’s offer and built a 100-megawatt facility that 
2 No. 15-2632

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 transmission 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 customers 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 overloads 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 province. 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 networks. Potential buyers of energy bid for power to be delivered over the network (this is done principally through utilities such as Duke and NIPSCO, which aggregate end-users’

demands); potential sellers such as Duke (on behalf of Ben-
No. 15-2632 3

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 megawatt-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 auction, 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 quantity are $40 for 300 megawatts. MISO accepts the bids from 

Sellers 1, 2, and 3, and all three receive $40 per megawatthour.

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. Rather 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, 
4 No. 15-2632

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 output. 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 issued 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 generation capacity substantially exceeds local transmission capacity, the market-clearing price in MISO’s auction has fallen—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 below zero induce some producers to stop supplying electricity 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 
No. 15-2632 5

$10/MWh, Duke would pay MISO that amount and pay Benton 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, because 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 producers. Benton lost its status as a must-run facility. Duke responded 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 positive 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 Benton 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 allowed to delivering (and being paid) only 59% of the time 

that the weather can drive its turbines at their capacity.
6 No. 15-2632

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 nominally 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 contractual 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 
No. 15-2632 7

Energy Purchase Power Agreement or PPA; they call the second 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 requires 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 defines 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 liquidateddamages clause captioned “Buyer’s Failure to Accept Delivery of Electrical Output”:

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 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 suspension 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 transmission charges, if any, reasonably incurred by Seller in delivering the Electrical Output to such third party purchaser and (ii) 

the net amount, if any, that Seller using Commercially Reasonable Efforts, actually realizes through remarketing of such Electrical 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 
8 No. 15-2632

damages provided in this Section 4.6 shall be the sole and exclusive 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 “Transmission”:

Buyer represents that it intends to deliver and sell all of the Electrical Output to [MISO] at the Point of Metering and does not intend 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 transmission rules) to use Transmission Services in order to accept deliveries 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 responsible for the payment of any charges related to such Transmission 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, imbalance services, OASIS, congestion and congestion management services, tagging services, dispatch services, ancillary services, control area services, and other transmission services necessary for Buyer to accept Electrical Output at the Point of Metering and transmit, and deliver Electrical Output from the Point 

of Metering, using the highest priority transmission service 

available.
No. 15-2632 9

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, requiring 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 demand 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 receives 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 negative $500/MWh bid would have been), but that MISO allowed 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.
10 No. 15-2632

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 other 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 Transmission 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 remaining 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 facilities 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 Transmission Owners describes the process by which MISO allo-
No. 15-2632 11

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 transmission 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 contracting parties and allocated to Duke. By accepting this risk, 

Duke enabled Benton to finance its project; otherwise potential investors might have feared exactly the overcapacity situation that has come to pass. Duke wanted Benton’s facilities 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 contract, which relate that Duke did not plan or want to operate 

transmission lines, contemplated immediately handing Benton’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 transmission 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 capacity available. One is the contract’s definition of “transmission services” to include “other transmission services 
12 No. 15-2632

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 Metering” then Buyer (Duke) must pay the full cost. What 

would be the point of this clause, if Duke never has an obligation 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 deliveries 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 
No. 15-2632 13

change the rules of dispatching power over whatever transmission 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 renewable power, which usually is located far from the centers 

of demand. They needed to allocate the risk of that development, which predictably would compel MISO to alter its 

rules for which sources could put power on the grid. Allocating the risk to Benton would have made it hard, perhaps 

impossible, to finance the project’s construction, while leaving Duke and similar utilities no incentive to expand the regional grids as wind power became available. Allocating the 

risk to Duke facilitates both construction of renewableenergy 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 extra 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 argument 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 unanticipated change in MISO’s rules is enough of an “emer-
14 No. 15-2632

gency” to give Duke time to build or acquire new transmission capacity without needing to compensate Benton in the 

interim, but MISO announced the new rules years in advance and phased them in slowly. Duke did not attempt to 

add transmission capacity in the time between the rules’ announcement 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 contract, which the parties call JESOA. Because we have concluded that Benton prevails under the first contract, the second 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 recovery 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 unnecessary to decide whether Duke is liable under the second contract 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 entitled.
No. 15‐2632 15

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‐
16 No. 15‐2632

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
No. 15‐2632 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
18 No. 15‐2632

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/
No. 15‐2632 19

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
20 No. 15‐2632

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
No. 15‐2632 21

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
22 No. 15‐2632

“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
No. 15‐2632 23

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.
24 No. 15‐2632

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.
No. 15‐2632 25

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
26 No. 15‐2632

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).