                                        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  
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  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-­‐‑
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  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,  
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   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  
No.  15-­‐‑2632                                                                    5  

$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.  
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   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  
No.  15-­‐‑2632                                                                              7  

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  
8                                                                               No.  15-­‐‑2632  

      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.  
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,  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.  
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  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-­‐‑
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  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  
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  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  
No.  15-­‐‑2632                                                               13  

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-­‐‑
14                                                                 No.  15-­‐‑2632  

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.  
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). 
