Utilizing  PURPA  in  Today’s   Deregulated  Wholesale   Market   June  5,  2012   12:00-­1:30  pm  EDT   Peter  Richardson,  Esq Richardson  &  O’Leary

   

 Ken  Kaufmann,  Esq.    Lovinger  Kaufmann  LLP  

Presented  by  EUCI  

Natural  Gas  prices  have     fallen  sharply  .  .  .  

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Summer  Reserve  Margins  are  healthy  .  .  .  .  

Source:  U.S.  Energy  Information  Administration,  based  on  North  American  Electric  Reliability   Corporation,  2012  Summer  Short-­‐Term  Reliability  Assessment.    

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BPA  can’t  give  away  enough  energy  .  .  .  

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With  depressed  natural  gas  prices,  meager  load  growth,  ample   summer  capacity  reserves,  and  seasonal  overabundance  of   energy,  some  of  you  may  be  asking  whether  PURPA  remains   relevant  to  the  United  States’  energy  policy  framework.         For  the  next  90  minutes,  we  will  talk  about  how  PURPA  shaped   national  energy  policy  during  the  last  30  years;  current  legal   issues  involving  PURPA,  and  Vinally,  how  PURPA  likely  will   remain  relevant  in  the  future.  

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Overview     I. 

PURPA  101-­‐What  is  PURPA?  (10  min)-­‐Peter  

II. 

How  Avoided  Costs  are  calculated  (10  min)-­‐Ken  

III.  PURPA’s  Evolution-­‐-­‐1980  to  EPAct’05  (20  min)-­‐Peter   IV. 

Current  PURPA  legal  issues  (20  min)-­‐Ken  

V. 

PURPA  Opportunities  and  Risks  Going  Forward  (15  min)-­‐P/K  

VI. 

Q&A  

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I.  What  is  PURPA?   •  Public  Utilities  Regulatory  Policies  Act  of  1978  

Pub.  L.  No.  95-­‐617,  92  Stat.  3117)     •  Part  of  the  National  Energy  Act  (Vive  pieces  of  major  

legislation)   •  Congress’  primary  policy  objectives:   –  Reduce  demand  on  fossil  fuels   –  Overcome  utilities’  reluctance  to  purchase  power  from,  

and  sell  power  to,  non-­‐utility  generators  

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I.  What  is  PURPA?  

Obstacles  prior  to  PURPA:   Problem:  

PURPA  solution  for  “Qualifying   Facilities”  

Utilities  not  willing  to  purchase  electric   output/pay  reasonable  price  for  non-­‐ utility  generation  

Each  electric  utility  must  offer  to   purchase  available  energy  and  capacity   from  QFs  at  just  and  reasonable,  non-­‐ discriminatory  rates.  

Utilities  charged  discriminatorily  high   rates  for  back-­‐up  service  to  non-­‐utility   generators  

Each  electric  utility  must  offer  to   provide  electric  service  to  QFs  at  just   and  reasonable,  non-­‐discriminatory   rates.    

Non-­‐utility  generator  still  subject  to   extensive  state  and  federal  utility   regulation    

QFs  exempted  from  FPA,  PUHCA,  and   State  utility-­‐type  regulations    

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I.  What  is  PURPA?  

QF  defined   Cogeneration  Facility  

or  

Small  Power   Production  Facility

and  

Not  owned  by  persons   primarily  engaged  in   generation  or  sale  of   electric  power*   June  5,  2012  

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*repealed  by  EPAct  ‘05   9  

I.  What  is  PURPA?  

CogeneraHon  Facility     •  A  facility  which  produces  electric  energy  and  steam  or  

forms  of  useful  energy  (such  as  heat)  which  are  used   for  industrial,  commercial,  heating,  or  cooling  purposes.       •  Policy:    Cogeneration  facilities  use  signiVicantly  less  fuel  

to  produce  electricity  and  steam  (or  other  energy)  than   would  be  needed  to  produce  the  two  separately.   •  No  maximum  size  for  PURPA  eligibility   •  SpeciVic  requirements  at  18  CFR  §§  292.202-­‐205    

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I.  What  is  PURPA?  

Small  Power  ProducHon  Facility   •  A  facility  which  uses  biomass,  waste,  or  renewable  

resources,  including  wind,  solar  energy  and  water,  to   produce  electric  power;  which,  together  with  any  other   facilities  located  at  the  same  site,  has  capacity  ≤80MW.      

•  Policy:    Reliance  on  these  sources  of  energy  can  reduce  

the  need  to  consume  fossil  fuels  to  generate  electric   power.  

•  SpeciVic  requirements  at  18  CFR  §§  292.202-­‐204  

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I.  What  is  PURPA?  

Ownership  limitaHon     •  A  small  power  production  facility  or  cogeneration  

facility   •  “which  is  owned  by  a  person  not  primarily  engaged  in  

the  generation  or  sale  of  electric  power,  (other  than   electric  power  solely  from  [QFs])”   •  Policy:  Congress  didn’t  want  PURPA’s  regulatory  

exemptions  to  apply  to  utilities.  

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I.  What  is  PURPA?  

To  Whom  does  PURPA  apply?    (A)  The  term  "electric  utility"  means  a  person  or  Federal  or   State  agency  (including  an  entity  described  in  section  201(f)   of  this  title)  that  sells  electric  energy.    (B)  The  term  "electric  utility"  includes  the  Tennessee  Valley   Authority  and  each  Federal  power  marketing   administration.    -­‐-­‐FPA  §3(22),  16  U.S.C.  §796(22).  

PURPA  must-­‐buy  obligation  applies  to  IOUs,  Munis,   PUDs,  Co-­‐Ops,  water  districts,  etc.  [unless  FERC   grants  a  waiver  or  excuses  utility  under  §210(m)].   June  5,  2012  

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I.  What  is  PURPA?  

Purchase  Price  defined   PURPA  §  210(b)  

FERC  Implementation  (292.101(b)(6)):  

Rates:   (1) shall  be  just  and  reasonable  to  the   electric  consumers  of  the  electric   utility  and  in  the  public  interest,   and     (2) Shall  not  discriminate  against   cogenerators  or  small  power   producers.       Rates  also  must  not  exceed  the   incremental  cost  to  the  electric  utility   of  alternative  electric  energy.    

Rates  must  equal  the  utility’s  “full  avoided   costs”:    “the  incremental  costs  to  the   electric  utility  of  electric  energy  or  capacity   or  both  which,  but  for  the  purchase  from   the  QF  or  QFs,  such  utility  would  generate   itself  or  purchase  from  another  source.”  

In  implemenHng  PURPA,  FERC  opted  to  require  uHliHes  to  pay  the  full   avoided  cost.    However,  PURPA  is  not  intended  to  subsidize  QFs.   June  5,  2012  

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I.  What  is  PURPA?  

QF  regulatory  exempHons   •  Congress  authorized  FERC  to  exempt  some  QFs  from  

parts  of  the  FPA,  PUHCA  of  1935,  and  state  regulations —FERC  exercised  this  power  broadly  in  1980:   –  FPA:    §§  205,  206  (rate  regulation)   –  Also  exempt  from  FPA  §§203,  204,  208,  301,  302,  304,  305   –  PUHCA:  “electric  utility  company”  does  not  include  QFs   –  No  state  regulation  of  QFs  if  inconsistent  with  PURPA  

•  Exemptions  do  not  apply  to  QFs  >  30MW  except  for  

biomass  projects  

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I.  What  is  PURPA?  

Recap     •  PURPA  created  a  new  regulatory  status  called  

Qualifying  Facilities,  or  QFs   •  QFs  have  a  right  to  be  served  by,  and  sell  to  electric  

utilities  at  the  utility’s  avoided  cost   •  QFs  have  a  right  to  interconnect  and  wheel  to  any  

electric  utility   •  QFs  exempt  from  many  federal  and  state  regulations  

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II.    How  are  Avoided  Costs  calculated?   • 

PURPA  is  the  only  area  where  States  get  to  regulate   wholesale  power  sales  rates  

• 

States  have  tried  many  different  approaches.  

• 

Methods  include:   –  1.  Proxy   –  2.  Peaker   –  3.  Partial  Displacement,  Differential  Revenue  Requirement    

 (PDDRR)   –  4.  Fueled  rates   –  5.  Auction   • 

June  5,  2012  

Generic  examples  follow  (every  state  varies)   Utilizing  PURPA  in  Today’s  Deregulated  Wholesale  Market  

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II.  How  Avoided  Costs  are  Calculated  

Proxy  Resource  methodology   Avoided  Cost  :=                

 Cost    of  utility’s  next  planned      resource  addition  (called  the    “Proxy  Resource”;  usually  a        Combustion  Turbine)    

 Energy  cost          =  

 f(heat  rate,  gas  price  forecast,      variable  O&M,  capacity  factor,  etc.      of  the  Proxy  plant)  

   

   

 Capacity  cost    =  

  June  5,  2012  

   

 f(plant  cost,  Vixed  O&M,  taxes,    etc.  of  the  Proxy  plant)  

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II.  How  Avoided  Costs  are  Calculated  

Peaker  methodology   Avoided  Cost  :=    value  of  the  QF  operated  as  a        peaker,   Energy  cost        =                                

 marginal  system  energy  cost    (lambda)*QF  gen  pattern      

Capacity  cost  =          

 f(plant  cost,  Vixed  O&M,  taxes,    etc.)  of  least  cost  capacity      (typically  a  CT)  

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II.  How  Avoided  Costs  are  Calculated  

ParHal  Displacement  (PDDRR)   methodology   Avoided  Cost  :=                  

 System  revenue        requirement  (without  QF)  –    System  revenue        requirement  (with  QF)  

Energy  cost    =    difference  in  system  revenue          requirement  with  and  without          the  (zero  cost,  must  run)  QF.  

   

Capacity  cost  =  difference  in  capacity              acquisition  costs  with  and              without  the  QF  

   

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II.  How  Avoided  Costs  are  Calculated  

Fueled  Rates   Avoided  Cost  :=  avoided  capacity  +  indexed  energy   Energy  cost  =    Vixed  component  and  variable                monthly  gas  index  price   Capacity  cost  =  On-­‐peak  energy  paid  an  avoided                capacity  cost  adder  based  on  avoided              capacity  

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II.  How  Avoided  Costs  are  Calculated  

AucHon/RFP  Rates   •  Utility  issues  a  Request  for  Proposals.   •  Selection  based  on  price  only  or  other  

factors.   •  Successful  bidders  receive  capacity  

contracts.   •  Unsuccessful  bidders  may  sell  energy  but  

not  capacity.   June  5,  2012  

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II.  How  Avoided  Costs  are  Calculated  

Standard  Avoided  Cost  Rates   •  FERC  requires  for  QFs  100  kW  and  less   •  States  may  allow  standard  rates  for  larger  

QFs   •  May  be  based  on:   –  Replacement  cost  (Proxy)   –  Displacement  value  (Peaker,  PDDRR)   –  Other  

June  5,  2012  

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II.  How  Avoided  Costs  are  Calculated  

Avoided  Cost  methodologies  compared:   Proxy  

Peaker  

PDRR  

Standard  

Fueled  

Auction  

Pro:  

Simple;   transparent  

Better  match   to  QF  than  the   Proxy;  simpler   than  PDRR  

Theoretically   correct;  unit   speciVic  

Simple;  low   transaction   cost  

Eliminates   risk  of  fuel   price   forecast   error  

Market   determines   appropriate   price  

Con:  

QF  might  be   very  different   from  the  proxy   unit;  timing  of   QF  output  not   taken  into   account  

Ignores  impact   of  the  QF  on   utility’s   marginal  cost  

Black  Box;  lack   of  regulator  and   QF  buy-­‐in;  time-­‐ consuming    

Risk  of   oversupply  if   rate  is  set   too  high;   Inaccurate  if   not  timely   updated  

Ratepayers   remain   exposed  to   fossil  fuel   price   Vluctuations    

Smaller  QFs   might  be   non-­‐ competitive  

Basis:  

Admin.  

Admin.  

Admin.  

Admin.  

Market   index.  

Market  

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II.  How  Avoided  Costs  are  Calculated  

Summary:   • 

Administratively  Determined  Avoided  Costs:   Used  initially  because  of  lack  of  established  market   •  Use  continued  because  smaller  QFs  not  competitive  in  an  all-­‐ source  bidding   •  Can  be  harmful  if  rates  set  too  high   • 

• 

Auction-­‐based  pricing     May  yield  lower  prices  for  ratepayer   •  May  be  impracticable  for  small  suppliers   • 

• 

Today  most  states  use:   Competitive  procurement  for  large  facilities   •  Administratively  determined,  or  managed  competition,  for   small  QFs   • 

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III.    PURPA  evoluHon  milestones   •  Early  years  of  success  and  excess   •  Energy  Policy  Act  of  1992  and  Southern  Cal  Edison   •  Energy  Policy  Act  of  2005     •  CPUC  decision  133  FERC  ¶  61,059  (2010)  

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III.    PURPA  evolution  milestones  

Early  PURPA  capacity  installed   exceeded  expectaHons   •  In  1980,  FERC  predicted  2,636  MW  of  installed  QF  

capacity  by  1985;  actual  total  in  1985  estimated  at   12,120  MW.   •  California  IOUs  scrapped  plans  for  22  coal  plants   •  In  some  cases,  QF  response  to  standard  rates  was   overwhelming:   •  New  York:    $60/MWh  price  Vloor  led  to  massive  

oversupply  and  subsequent  buyout  of  14  QF  contracts   totaling  $3.9  billion  and  23%  of  Niagara  Mohawk  equity   •  California:  Standard  Offer  4  (SO4)  contract—more  than  

16,000  MW  subscribed  in  15  months     June  5,  2012  

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III.    PURPA  evolution  milestones  

Energy  Policy  Act  of  1992     •  PURPA  demonstrated  the  likely  feasibility  of  

competitive  wholesale  generation  market   •  EPAct  ‘92  expanded  some  of  the  beneVits  of  PURPA  to  

non-­‐  QFs   •  created  Exempt  Wholesale  Generator     •  • 

exempt  from  PUHCA  of  1935   Allowed  to  sell  output  under  market  based  rate  tariff  

•  authorized  Open  Access   • 

June  5,  2012  

FERC  implemented  with  Order  888  and  its  progeny

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III.    PURPA  evolution  milestones  

So.  Cal  Edison-­‐70  FERC  ¶61,215  (1995)   •  California  IOUs  challenged:   •  CPUC  order  to  exclude  non-­‐QFs  from  their  RFPs  (QF  bids  

at  $66  over  non-­‐QF  bids  at  $40)   •  CPUC  order  to  pay  QFs  an  “environmental  adder”  based   on  their  lack  of  harm  to  air  quality    

•  FERC  (concerned  about  stranded  costs)  agreed  

with  the  IOUs:   •  In  determining  the  avoided  cost  rate,  the  electric  utility  

must  take  into  account  all  sources  including  non-­‐QFs   •  Adders  violate  PURPA  if  they  exceed  avoided  cost  

June  5,  2012  

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III.    PURPA  evolution  milestones  

So.  Cal  Edison-­‐ctd.     • 

“Congress  .  .  .  Did  not  in  any  way  limit  the  sources  to  be   considered.    The  consequence  is  that  regardless  of  whether   the  State  regulatory  authority  determines  the  cost   administratively,  through  competitive  solicitation  (bidding)   or  some  combination  thereof,  it  must  in  its  process  reVlect   prices  available  from  all  sources  able  to  sell  to  the  utility   whose  avoided  cost  is  being  determined.”  

• 

“[If  O]nly  QFs  were  then  permitted  to  bid  against  the   benchmark,  such  a  procedure  could  not  properly  determine   avoided  costs  because  it  excluded  potential  sources  of   capacity  from  which  utilities  could  purchase,  in   contravention  of  the  requirements  of  Section  210  of  PURPA   and  our  regulations.”  

June  5,  2012  

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III.    PURPA  evolution  milestones  

Low  gas  prices  in  the  ’90s  limited   PURPA  growth  

June  5,  2012  

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III.    PURPA  evolution  milestones  

Comparison  between  QFs  and  EWGs   circa  1995   QF  

EWG  

Right  to  Sell  at  Avoided  Cost:  

X  

Right  to  wheel  to  another  utility:  

X  

X  

Exempt  from  utility-­‐like  regulation:  

X  

X  

Sales  price:  

≈CCCT  price   ≈CCCT  price  

During  the  mid-­‐1990s,  avoided  costs  for  EWGs  largely  were  derived  from  the   cost  of  CCCT  or  SCT.    QFs  largely  could  not  Vinance  their  projects  at  such   avoided  costs  until  gas  prices  rose  and  the  capital  cost  of  renewables  fell.  

June  5,  2012  

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III.    PURPA  evolution  milestones  

Backdrop  to  Energy  Policy  Act  of  2005     •  Gas  prices  tripled  from  1999-­‐2005     •  RECs,  PTCs,  Accelerated  Depreciation  subsidize  cost  of  

renewable  projects   •  Large  scale  wind  turbine  technology  maturing   •  Open  Access  to  transmission  largely  accomplished   •  Wind  developers,  and  other  QFs,  have  Vinance-­‐able  

projects;  market  barriers  that  prompted  enactment  of   FERC  largely  remedied  by  Open  Access   June  5,  2012  

Utilizing  PURPA  in  Today’s  Deregulated  Wholesale  Market  

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III.    PURPA  evolution  milestones  

EPAct  ’05  rolled  back  PURPA  privileges:   •  New  restrictions  to  limit  “PURPA  machines”   •  Repeal  of  prohibition  on  utility  ownership   •  Repeal  of  PUHCA   •  Partial  repeal  of  FPA  §205  and  §206  exemption   •  New  §  210(m)  requires  FERC  to  excuse  purchase  

obligation  if  there  is  access  to  a  sufSiciently   competitive  market  for  QFs  to  sell  its  power.  

June  5,  2012  

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III.    PURPA  evolution  milestones  

EPAct  ‘05  created  new  PURPA  §210(m):   §210(m)  is  a  BIG  DEAL,  made  bigger  by  FERC’s   election  to  implement  via  rulemaking  rather  than   case  by  case.   No  utility  purchase  obligation  if  the  Commission  Vinds   that  the  [QF]  has  nondiscriminatory  access  to:   (1)  [independently  administered,  auction-­‐based  day  ahead   and  real  time  wholesale  markets  and  wholesale  markets   for  long-­‐term  sales  of  capacity  and  energy]  or   •  e.g.  Midwest  ISO,  PJM,  ISO-­‐NE,  NYISO   •  (2)  [RTO  with  competitive  wholesale  markets]  or   •  (3)  wholesale  markets  that  are  comparable  to  (1)  or  (2).   • 

June  5,  2012  

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III.    PURPA  evolution  milestones  

UHliHes  excused  from  PURPA  must-­‐buy   obligaHon     •  PURPA  must-­‐buy  obligation  excused  for  QFs  >  20  MW  in:   –  Midwest  ISO  (Describe  areal  extent)   –  PJM   –  ISO-­‐NE   –  NYISO   –  SPP   –  Cal  ISO  

•  Utilities  in  at  least  26  states  already  affected   •  In  other  regions,  and  for  QFs  under  20MW,  PURPA  must-­‐buy  

obligation  remains   June  5,  2012  

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III.    PURPA  evolution  milestones  

PURPA  advantages  acer  EPAct  ’05  apply   mainly  to  QFs  under  20  MW   QF    (under   20MW)       Right  to  sell  to   utility  

X  

Right  to   interconnect/   wheel  

X  

Exempt  from     FPA  205/206  

X*  

Sale  price  

Administrative*  

QF  (over  20MW,   with  access  to   market)  

Non-­QF   generator  

X  

X  

Market  based/IRP  

Market  

*exceptions  may  apply   June  5,  2012  

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III.    PURPA  evolution  milestones  

California  Public  U4li4es  Commission   (July  15,  2010  Order)  132  FERC  ¶  61,047       •  California  PUC  adopted  competitive  procurement  program  for  

CHP  facilities  ≤  20  MW  meeting  speciVied  efViciency  and   environmental  standards  that  excluded  non-­‐renewables.    IOUs   challenged  because  this  was  contrary  to  FERC’s  holding  in  So  Cal   Edison  that  all  eligible  sources  be  considered.    CPUC  petitioned   FERC  for  guidance.   •  FERC  declared  that:   •  State’s  only  authority  to  set  wholesale  rates  is  PURPA.  Therefore:   •  • 

Bidders  must  be  QFs:   Price  must  not  exceed  the  avoided  cost  of  the  utility.  

•  FERC  invited  CPUC  to  seek  further  guidance  on  setting  QF  rates.   June  5,  2012  

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III.    PURPA  evolution  milestones  

California  Public  U4li4es  Commission     133  FERC  ¶  61,059  (October  21,  2010)      

•  CPUC    accepted  FERC’s  invitation  and  sought  clariVication  on:     •  (1)  whether,  in  determining  QF  rates,  it  could  exclude  resources  that  

did  not  satisfy  state  law  procurement  requirements  (e.g.  carbon   emitting  resources),  and   •  (2)    whether  it  could  include  a  pricing  adder  for  CHP  facilities  sited   where  they  will  cause  the  utility  to  avoid  or  postpone  transmission   upgrades.   •  FERC  found  that:   •  CPUC  need  not  consider  sources  not  eligible  to  sell  to  the  utilities,  

and   •  CPUC  may  take  into  account  actual  procurement  requirements,  and  

resulting  costs,  imposed  on  utilities  in  California.       June  5,  2012  

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IV.    Current  PURPA  legal  issues-­California  

California’s  Distributed  GeneraHon  (DG)   Feed-­‐in  Tariff   •  FERC’s  Order  on  ClariVication  (“ClariSication  Order”)  

effectively  overruled  So.Cal  Edison.       •  Utilities  still  cannot  pay  more  than  full  avoided  cost;     •  however  “avoided  cost”  may  include  actual,  non-­‐power  

costs,  and  need  not  consider  alternative  sources  that  are   not  eligible  under  state’s  procurement  rules.   •  This  order  gives  states  great  new  Vlexibility  to  use  

PURPA  to  help  utilities  achieve  RPS  and  other  state   procurement  mandates.  

June  5,  2012  

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IV.  Current  PURPA  legal  issues     A.  Incremental  Transmission  Costs  

in  Oregon   B.  Administrative  Avoided  Cost  

Rates  in  Idaho   C.  California’s  Distributed  

Generation  Feed-­‐in  Tariff   June  5,  2012  

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IV.    Current  PURPA  legal  issues-­Oregon  

A.  Incremental  Transmission  Costs  in   Oregon   •  In  the  PaciVic  Northwest,  IOUs  rely  on  BPA-­‐owned  

transmission  to  interconnect  their  systems.   •  QFs  sited  at  remote  locations  on  an  IOU’s  system  may  

exceed  local  load.   •  IOU  must  buy  a  wheel  from  BPA  to  move  the  excess  QF  

generation  to  load  elsewhere  on  its  system.   •  The  cost  of  the  wheel  is  not  modeled  in  the  

administratively  determined  avoided  cost  rate.  

June  5,  2012  

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IV.    Current  PURPA  legal  issues-­Oregon  

A.  Incremental  Transmission  Costs  in   Oregon-­‐  ctd   •  Are  these  incremental  transmission  costs  paid  by  the  

utility  to  BPA  directly  assignable  to  the  QF?   •  Pro:   •  • 

Not  included  in  administrative  Avoided  Cost  methodology.   Costs  are  certain  and  quantiViable.  

•  Con:   •  • 

June  5,  2012  

Savings  in  avoided  transmission  offsets  additional  wheeling   costs;  or   Direct  assignment  of  these  costs  will  undercut  a  primary   objective  of  standard  rates:    transparent,  efVicient   negotiations.  

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IV.    Current  PURPA  legal  issues-­Oregon  

A.  Incremental  Transmission  Costs  in   Oregon-­‐  ctd   •  Administrative  Avoided  Cost  determinations  can’t  

account  for  every  factor  in  setting  costs  (some  are   unknown  or  de  minimis).   •  FERC  has  said  that:     •  (1)  states  have  wide  latitude  in  determining  avoided  

costs,  but   •  (2)  rates  that  exceed  avoided  cost  are  void  ab  initio!   •  Regardless  the  outcome,  the  new  order/tariff  should  

include  a  process  for  PUC  review  (prior  to  signing  of   new  QF  contracts)  if  unanticipated  facts  come  to  light.   June  5,  2012  

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IV.    Current  PURPA  legal  issues-­Idaho  

B.  AdministraHve  Avoided  Cost  Rates  in  Idaho • 

Idaho  PUC  (IPUC)  established  standard  avoided  cost  rates  for   projects  10aMW  and  less  (≈  25MW  nameplate  wind  QF).  

• 

Did  not  anticipate  that  developers  would  develop  large  sites  in   clusters  of  10  aMW  QFs  (“dis-­‐aggregation”).   •  • 

Dis-­‐aggretation  effectively  made  the  published  rate  the  Vloor  price   for  Idaho  utility  RFPs   Resulted  in  exponential  growth  in  Idaho  QF  wind  

• 

IPUC  suspended  standard  rates  for  wind  and  solar  QFs  over  100   kW  while  it  investigated  reasonableness  of  the  administrative   methodologies.  

• 

Between  time  IOUs  sought  relief  and  time  IPUC  suspended  rates,   nearly  600  MW  of  new  wind  QFs  sought  to  obligate  IOUs  under   the  standard  rates.  

June  5,  2012  

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IV.    Current  PURPA  legal  issues-­Idaho  

B.  AdministraHve  Avoided  Cost  Rates  in  Idaho • 

After  suspension  of  standard  rates,  Idaho  Power’s  project   speciVic  administrative  methodology  also  exhibited  suspect   results.   Between  June  8,  2011  and  March  9,  2012,  Idaho  Power   submitted  and  the  Idaho  PUC  approved  Vive  QF  PPAs   comprising  83  MW  of  new  capacity.       •  In  each  case  the  IPUC  staff  recommended  disapproval  of  the   PPAs  because  it  believed  that  the  avoided  cost  pricing   methodology  resulted  in  prices  that  were  excessive.   • 

• 

Requests  for  PPAs  with  project  speciVic  rates  poured  in.  

• 

On  March  21,  2012,  the  IPUC  ordered  Idaho  Power  to  refer  all   PPAs  to  it  prior  to  execution  pending  completion  of  the   IPUC’s  investigation.  

June  5,  2012  

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IV.    Current  PURPA  legal  issues-­Idaho  

Recent  QF  contracts  with  Idaho  Power   Company  

June  5,  2012  

Utilizing  PURPA  in  Today’s  Deregulated  Wholesale  Market  

Source:    Aff.  of  Randy  Allphin,  Idaho  PUC  Case  No.  GNR-­‐E-­‐11-­‐03  

47  

IV.    Current  PURPA  legal  issues-­Idaho  

Suspected  causes  of  erroneous  avoided  cost   price  determinaHons  idenHfied  by  IPUC  staff:   •  Outdated  fuel  price  forecast   •  Outdated  choice  of  Proxy  Resource   •  Outdated  assumptions  regarding  capacity  needs   •  Outdated  cost  of  capital  assumption   •  Failure  to  capture  integration  costs  of  non-­‐dispatchable  

QFs  (except  for  wind)  

June  5,  2012  

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IV.    Current  PURPA  legal  issues-­Idaho  

Errors  in  AdministraHve  Avoided  Cost   determinaHons  are  inevitable.   •  Inputs  are  outdated  the  day  after  they  are  made.   •   E.g.  the  2010  natural  gas  price  forecast:  

• 

June  5,  2012  

$/mmBtu   (2010)  

2010   2011   2012  

2013  

2014  

2015  

2016  

2017  

2018  

3/16/10  

4.56  

4.86  

5.19  

5.48  

5.79  

6.11  

6.22  

6.32  

6.44  

8/30/11  

3.93  

4.05  

4.18  

4.28  

4.37  

4.47  

4.58  

4.7  

4.58  

Tariff/Orders  need  to  be  written  with  safeguards  to  limit   unintended  consequences  of  PURPA  implementation.  

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IV.    Current  PURPA  legal  issues-­Idaho  

Safeguards  for  Standard  Rate  Pricing:     •  Preset  cap  on  MW  between  price  updates   •  Stair-­‐step  Avoided  Cost  schedule   •  Limit  QF’s  ability  to  participate  in  RFP  and  standard  price  

programs  

•  Limit  size  of  QF  eligible  for  standard  rates   •  Empower  utility  to  refer  “gamers”  to  Commission   •  PUC  reasonableness  review  at  time  of  execution   •  Prompt  PUC  suspension  of  rates  when  needed   June  5,  2012  

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IV.    Current  PURPA  legal  issues-­California  

C.  California’s  Distributed  GeneraHon   Feed-­‐in  Tariff   •  On  May  24,  2012,  California  PUC  adopted  ALJ’s  decision  

implementing  a  distributed  generation  Feed-­‐in  Tariff   required  by  California’s  legislature.  Decision  12-­‐05-­‐035.  

•  The  Feed-­‐in  Tariff  (FiT)  fulVils  state  law  requiring  

utilities  to  purchase  750  MW  from  generators  3MW  or   less  located  at  strategic  locations  on  the  electric   distribution  system.  

•  CPUC  relies  on  FERC  Clari]ication  Order  in  establishing  

a  framework  for  setting  FiT  rates  that  are  both  market-­‐ based  and  focused  to  meet  the  speciVic  requirements  of   the  legislature.  

June  5,  2012  

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IV.    Current  PURPA  legal  issues-­California  

C.  California’s  Distributed  GeneraHon     Feed-­‐in  Tariff-­‐  ctd.     California  Public  Utilities  Commission  relied  on  the  FERC  ClariVication   Order  to  implement  its  DG  Feed-­‐in  Tariff    In  [the  FERC  ClariVication  Order],  FERC  clariVied  that  the  state  has  a   wide  degree  of  latitude  in  setting  avoided  cost,  can  utilize  a  multi-­‐ tiered  avoided  cost  rate  structure,  and  that  this  approach  is   consistent  with  the  avoided  cost  requirements  set  forth  in  Section   210  of  PURPA.    FERC  also  clariSied  that  state  procurement   obligations  can  be  considered  when  calculating  avoided  cost,   and  it  speciVically  overruled  its  prior  holding  from  SoCal  Edison  to  the   extent  its  current  determination  was  inconsistent  with  that   clariVication.   -­‐-­‐California  Public  Utilities  Commission,  Decision  12-­‐05-­‐035  at  11   (emphasis  added;  internal  citations  omitted).   June  5,  2012  

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IV.    Current  PURPA  legal  issues-­California  

 C.  California’s  DG  Feed-­‐in  Tariff-­‐ctd.   •  PUC  §399.11  et  seq.  declares  a  state  goal  to  develop  

eligible  renewable  energy  resources  3MW  or  less   at  strategic  locations  on  the  grid.   •  CPUC  opted  not  to  use  the  gas-­‐based  Market  Price  

Referent  (MPR)  because  legislation  did  not  so   require.   •  CPUC  decided  to  base  the  price  on  market  price  of  

renewables,  Vinding  that  a  healthy  market  existed.  

June  5,  2012  

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IV.    Current  PURPA  legal  issues-­California  

   C.  California’s  DG  Feed-­‐in  Tariff-­‐ctd.   •  FiT  uses  Renewable  Auction  Mechanism  (RAM)  

Program  prices  as  starting  price  for  FiT   •  Adjusts  the  RAM  to  account  for  differences  in  

pricing  from  the  RAM  Program  (“Re-­‐MAT”)   •  10,  15,  or  20  year  term   •  Baseload,  peaking  as-­‐available,  and  non-­‐peaking   as-­‐available  

June  5,  2012  

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IV.    Current  PURPA  legal  issues-­California  

 C.  California’s  DG  Feed-­‐in  Tariff-­‐ctd.   •  Re-­‐MAT  starting  price  based  on  weighted  average  

of  PG&E’s,  SCE’s,  and  SDG&E’s  highest  executed   contract  resulting  from  the  RAM  auction  held   November,  2011.   •  Adjustments  for:   Time  of  delivery   •  Up  to  every  two  months,  based  on  QF  response  to  offer.   • 

•  Available  allotment  allocated  equally  among  

baseload,  peaking  as-­‐available,  and  non-­‐peaking   as-­‐available.   June  5,  2012  

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IV.    Current  PURPA  legal  issues-­California  

 C.  California’s  DG  Feed-­‐in  Tariff-­‐ctd.   •  Other  FiT  selection  criteria:   •  “Strategically  located”—QF  must  

interconnect  to  the  distribution  system   and  cost  no  more  than  $300,000  for   necessary  system  upgrades.   •  Only  one  project  per  seller  per  parcel  or   contiguous  parcel   •  QFs  eligible  for  FiT  program  are  not   eligible  for  RAM  Program   June  5,  2012  

Utilizing  PURPA  in  Today’s  Deregulated  Wholesale  Market  

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IV.    Current  PURPA  legal  issues-­California  

 C.  California’s  DG  Feed-­‐in  Tariff-­‐ctd.   •  FiT  program  also  has  “viability”  criteria:   •  Interconnection  feasibility   •  Legal  control  of  proposed  site   •  Prior  experience  in  at  least  one  similar  project   •  Online  date