Disclaimer:  The  views  and  opinions  expressed  in  this  paper  are  those  of  the  author  and  do  not  necessarily  reflect  the  views  of  the  American  Council  on  Renewable  Energy  (ACORE).  

The  Challenges  and  Opportunities  Posed  by  Distributed  Solar  and  Net  Energy  Metering    Torrey  Beek,  ACORE  Intern,  Winter/Spring  2014    

Globally,  the  outlook  for  the  solar  energy  sector  is  bright.  In  2013,  for  the  first  time  since  at  least  2000,  solar  surpassed  wind  energy  in  the  amount  of  new  generating  capacity  installed,  with  capacity  additions  totaling  36.5  gigawatts  (GW)1.  Longer  term  projections  indicate  that  in  terms  of  capacity  and  investment,  solar  will  continue  as  the  dominant  renewable  energy  technology.2  This  worldwide  trend  was  also  mirrored  in  the  U.S.,  where  according  to  the  Federal  Energy  Regulatory  Commission  (FERC),  solar  accounted  for  29%  of  all  new  electricity  generation  capacity  in  2013,  second  only  to  natural  gas;3  through  the  end  of  March  2014,  solar  energy  has  accounted  for  over  51%  of  new  capacity  additions  year  to  date.4    

A  significant  portion  of  the  growth  of  the  solar  industry  is  due  to  the  uptake  of  solar  photovoltaic  (PV)  technology.5  Solar  PV  saw  a  41%  increase  in  2013,  installing  4,751  megawatts  (MW),6  to  bring  total  U.S.-­‐wide  PV  installations  to  just  under  10GW.7  The  PV  sector  is  braced  for  continued  expansion  with  estimates  for  6.6GW  of  installations  in  2014  (a  33%  gain  from  2013),  and  could  grow  to  12GW  by  the  end  of  2016.8  The  confluence  of  decreasing  costs  of  solar  panels  and  installations,9  availability  of  federal  and  state  tax  credits  for  solar  PV  systems,10  and  attractive  rate  schedules,  such  as  net  energy  metering  (NEM),  have  driven  robust  expansion  of  small-­‐scale  applications  of  solar  PV,  particularly  for  residential  buildings.11  In  2013  alone,  residential  homeowners  installed  792MW  of  solar  PV  capacity,  a  60%  increase  from  2012.12  Through  the  first  quarter  of  2014,  residential  installations  of  solar  PV  exceeded  commercial  installations  for  the  first  time  since  2002,  with  232MW  installed.13    

The  proliferation  of  the  residential  PV  market  can  be  attributed  in  large  part  to  the  popularity  of  the  NEM  tariff.  Adopted  in  43  states  in  the  U.S.,  NEM  tariffs  are  designed  to  encourage  the  growth  of  distributed  generation  (DG),  or  generation  of  small  amounts  of  electricity  at  the  point  of  consumption  (such  as  the  customer’s  home).14  NEM  allows  the  renewable  energy  produced  by  a  customer-­‐owned  system  that  is  not  used  by  the  customer  to  feed  into  the  electric  grid,  offsetting  the  grid  electricity  consumed  by  the  customer  at  other  times  (i.e.  the  customer  is  only  billed  for  their  “net”  energy  use).15,16  State  NEM  rules,  such  as  which  types  of  renewable  energy  systems  qualify  and  how  they  are  credited,  vary  widely.  With  photovoltaic  generation  being  responsible  for  85.8%  of  the  electricity  sold  back  to  utilities  through  NEM  in  2012,17  the  program  has  served  as  an  important  catalyst  for  enabling  the  growth  of  distributed  solar  PV  in  the  residential  sector.18    

However,  in  recent  years  NEM  has  also  proved  to  be  a  politically  contentious  issue,  stirring  conflicts  between  the  regulated  electric  utility  industry  and  solar  power  advocates.  The  U.S.  electricity  grid  is  an  enormous,  $840  Bn  machine  comprised  of  2.7  Mn  miles  of  labyrinthine  transmission  wires  delivering  $400  Bn  worth  of  electricity  each  year  (and  requiring  substantial  and  continual  maintenance).  The  capitally  intensive  nature  of  the  grid’s  functionality  and  operation  and  maintenance  (O&M)  is  under  the  purview  of  a  regulated  utility  for  the  portions  of  the  grid  in  their  

respective  territory.19  Given  that  electricity  supply  and  demand  must  be  perfectly  balanced  every  moment  of  every  day,  these  entities  must  ensure  that  all  aspects  of  the  sprawling  grid  are  in  perfect  working  order  and  that  generating  facilities  are  able  to  instantaneously  respond  to  changes  in  customer  demand.  As  the  density  of  distributed  solar  PV  increases  on  the  distribution  system,  greater  uncertainty  in  grid  reliability  has  emerged  as  an  obstacle  for  the  growth  of  the  solar  energy  industry  in  the  U.S.20  

Regulated  utilities  have  traditionally  obtained  the  funds  necessary  for  grid  O&M  and  service  provision  as  fixed  costs  from  customers.21  Some  utilities  regard  NEM  policies  as  a  cross-­‐subsidy:  residential  customers  who  install  distributed  solar  PV  are  able  to  reduce  their  monthly  electricity  bills,  shifting  an  increasing  proportion  of  the  charges  associated  with  grid  O&M  onto  non-­‐solar  customers.22  The  roots  of  the  conflict,  however,  may  be  more  deeply-­‐seated  than  the  issue  of  cross-­‐subsidies.  The  rise  of  residential  net-­‐metered  distributed  solar  PV  has  led  to  a  potential  existential  crisis  for  the  regulated  electric  utility  industry.  In  its  seminal  publication,  Disruptive  Challenges:  Financial  Implications  and  Strategic  Responses  to  a  Changing  Retail  Electric  Business,  the  Edison  Electric  Institute  (EEI),  an  association  of  U.S.  shareholder-­‐owned  electric  companies,  noted:  

The  threats  posed  to  the  electric  utility  industry  from  disruptive  forces,  particularly  from  distributed  resources,  have  serious  long-­‐term  implications  for  the  traditional  electric  utility  business  model  and  investor  opportunities.  While  the  threat  of  disruptive  forces  on  the  utility  industry  has  been  limited  to  date,  economic  fundamentals  and  public  policies  in  place  are  likely  to  encourage  significant  future  disruption  to  the  utility  business  model.23  

In  February  2014,  the  Rocky  Mountain  Institute  (RMI)  published  a  report  on  the  possibility  of  “grid  defection”,  a  concept  wherein  customers  detach  from  the  centralized  grid  that  was  fundamental  to  the  development  of  the  U.S.  society  and  economy  in  the  20th  century,  and  operate  autonomous,  individual  or  community-­‐level  systems.  The  report  noted  that  the  confluence  of  inexorably  increasing  utility  bills  (exacerbated  by  greater  numbers  of  customers  leaving  utility  service  plans),  increasing  grid  charges  for  those  customers  remaining  with  the  utilities,  decreasing  costs  of  solar  PV  systems  and  battery/energy  storage  systems,  and  increasing  sophistication  of  off-­‐grid  solutions  available  for  customers  to  become  autonomous  energy  service  entities  could  result  in  mass  “grid  defection”  in  the  coming  years  or  decades.24    

Recent  recognition  of  the  threats  posed  to  the  regulated  utility  business  model  by  distributed  solar  PV,  net-­‐metered  and  otherwise,  and  battery  storage  technology  from  investment  banking  firms  like  Bank  of  America  Merrill  Lynch25  and  Barclays26  speaks  to  the  heart  of  the  debate  surrounding  utilities  and  distributed  solar  PV:  what  is  the  most  effective,  efficient,  and  fair  way  to  assess  the  value  that  distributed  solar  generation  provides  to  the  electricity  grid?  While  solar  supporters  have  championed  the  retail  rate  compensation  commonly  employed  through  NEM  tariffs,  others  have  proposed  alternative  rate  schedules  and  strategies  to  ensure  the  continued  survival  of  the  investor-­‐owned  utilities  (IOUs)  while  also  continuing  the  growth  of  the  solar  industry  in  the  U.S.  Even  more  long-­‐term  challenges  exist  beyond  rate  allocations,  namely  the  attendant  regulatory  and  technical  challenges  of  a  transforming  electricity  grid.27    

This  white  paper  will  delve  into  the  heart  of  the  debate  over  distributed  solar  PV  and  NEM,  from  the  impact  on  the  regulated  utility  business  model;  to  the  counter-­‐arguments  from  solar  PV  advocates;  to  the  technical  and  regulatory  challenges  that  could  stymie  continued  growth  of  the  residential  

distributed  solar  PV  sector;  and  finally  to  the  potential  approaches  that  exist  to  address  the  concerns  of  both  the  regulated  utilities  and  of  solar  advocates.  A  case  study  of  how  California,  presently  the  nation’s  leader  in  annual  installations  and  total  capacity  of  solar  PV,  is  reconciling  the  debate  over  the  growth  of  distributed  solar  PV  and  NEM,  and  even  embracing  new  forms  of  distributed  generation  and  energy  storage,  is  included  to  evaluate  best  practices  and  important  first-­‐mover  strategies.    

 

1. Setting  the  stage    

In  order  to  gain  a  proper  context  for  the  debate  around  distributed  solar  PV  and  NEM,  it  is  first  necessary  to  understand  how  the  regulated  utility  business  model  is  affected  by  the  technology  and  NEM,  and  how  utilities  and  solar  supporters  advocate  for  the  technology  to  be  valued.    

The  Investment  Background  of  the  Regulated  Electric  Utility  Industry  For  over  one  hundred  years,  the  regulated  electric  utility  industry  has  driven  economic  growth  and  societal  development  in  the  U.S.  As  American  society  became  increasingly  electrified,  the  utility  industry  benefited  greatly  from  a  constant  demand  of  electricity  and  the  inelasticity  of  short-­‐term  power  demand,  helping  to  make  it  one  of  the  safest  and  most  investor-­‐friendly  industries.28  In  fact,  regulated  utilities  have  been  classified  as  a  defensive  industry:  one  which  has  a  proven  product,  stable  demand  for  that  product,  and  low  volatility  in  its  revenue  streams  and  cash  flows.29  

This  historically  stable  regulatory  environment  has  allowed  the  industry  to  maintain  higher  amounts  of  debt  relative  to  cash  flow  (termed  debt  leverage)  than  other  industries.30  High  debt  leverage,  enabled  by  the  confidence  investors  place  in  the  utility  industry,  provided  the  industry  with  the  means  to  access  low-­‐cost  capital.  This  low-­‐cost  capital  was  necessary  to  maintain  generation  facility  and  grid  functionality  to  provide  customers  with  reliable  and  safe  services.  Within  the  traditional  cost-­‐of-­‐service  ratemaking  paradigm,  this  access  to  low-­‐cost  capital  has  also  allowed  utilities  to  provide  a  lower  cost  of  service,  and  in  turn  lower  rates  to  customers.31  

The  emergence  of  distributed  energy  resources,  particularly  distributed  solar  PV  on  residential  rooftops,  has  introduced  risk  into  the  traditionally  stable  utility  business  model.32  The  worry  among  utility  executives  is  that  as  net-­‐metered  distributed  solar  PV  grows,  these  customers’  PV  will  be  able  to  offset  portions  of  their  monthly  electricity  bills  as  the  PV  panels  produce  electricity.  In  jurisdictions  where  customer  rates  are  a  function  of  usage  sales,  these  decreased  electricity  bills33  would  force  the  incumbent  utilities  to  increase  customer  rates  to  earn  their  requisite  cost  of  capital.  If  the  utilities  are  unable  to  make  up  this  lost  revenue,  they  risk  credit  erosion  and  the  concomitant  reductions  in  debt  leverage.34  

In  recent  years,  a  multitude  of  economic,  political,  and  societal  factors  have  increased  pressure  on  the  regulated  electric  utility  industry.  The  industry  has  seen  returns  on  equity  decline  to  a  multi-­‐decade  low  of  10%,  while  at  the  same  time  seeing  its  cost  of  procuring  new  sources  of  equity  increase.35  The  pervasive  need  for  capital  expenditures  to  address  crucial  grid  and  system  upgrades  (often  times  at  almost  twice  the  rate  of  depreciation)  to  comply  with  various  regulatory  and  environmental  mandates  have  exacerbated  the  fears  of  revenue  shortfall.36  Some  have  argued  that,  with  forecasts  for  anemic  electricity  demand  growth  of  less  than  one%  per  year  from  2012  to  2040,37  

regulators  may  be  reluctant  to  approve  a  utility’s  capitally-­‐intensive  investment  plan.38  These  factors,  coupled  with  the  aforementioned  rapid  decrease  in  price  of  solar  PV  systems,  have  raised  the  prospect  that  NEM  may  “destabilize  the  entire  utility  industry,”  pushing  it  into  a  “death  spiral.”39  

The  Arguments  from  Both  Sides  The  electric  utility  industry  maintains  that  its  foremost  responsibility  is  to  deliver  safe  and  reliable  electricity  supply,  and  to  ensure  that  the  rates  customers  pay  for  service  are  fair  and  affordable  for  all  customers.40  The  notion  of  fair  and  affordable  rate  schedules  for  all  customer  classes  has  become  a  focal  point  of  the  debate  over  NEM.  Historically,  the  creation  of  qualifying  facilities  under  the  Public  Utilities  Regulatory  Policy  Act  (PURPA)  entitled  homeowners  to  host  a  generation  device  on  their  property,  interconnect  with  the  electricity  grid,  and  receive  the  avoided  cost41  of  generation  from  the  incumbent  utility  for  any  generation  they  provided.42  In  a  sense,  PURPA  provided  a  federal  “floor”  for  benefits  given  to  distributed  energy  resources.    

Some  NEM  policies  have  moved  beyond  avoided-­‐cost  compensation  to  allow  net-­‐metered  distributed  solar  PV  customers  to  receive  the  full  retail  rate  for  the  electricity  their  panels  produce  and  send  back  to  the  electricity  grid.  Often,  utilities  argue  that  compensation  at  the  retail  electricity  rate  allows  net-­‐metered  customers  to  avoid  paying  the  costs  of  maintaining  the  electricity  grid;  these  customers  procure  significant  benefits  from  connection  to  the  electricity  grid  and  should  be  compensated  at  the  wholesale  electricity  rate  (a  rate  lower  than  the  retail  rate).43  

Utilities  further  argue  that  distributed  solar  PV  customers  procure  several  benefits  from  grid  connectivity.44  At  the  most  basic  level,  as  Figure  1  illustrates,  grid  connection  provides  solar  PV  customers  with  the  opportunity  to  engage  in  transactions  through  a  NEM  program:  

 

Figure  1:  Grid  interaction  between  rooftop  distributed  solar  PV  system  and  electricity  grid45  

Further  benefits,  such  as  increased  reliability,  startup  power,46  voltage  quality,  and  increased  efficiency,  not  only  incentivize  installation  of  distribution  solar  PV  systems  on  residential  property:  they  also  make  these  systems  far  more  affordable.  A  study  by  the  Electric  Power  Research  Institute  (EPRI)  found  that  without  the  grid-­‐level  services  that  these  customers  now  enjoy,  grid-­‐connection  costs  would  increase  in  the  range  of  $275-­‐$430  per  month  above  the  cost  of  the  original  array.47    

Solar  advocates  argue  for  either  continued  compensation  at  the  retail  rate  or  to  have  compensation  be  designed  based  on  marginal  costs  (vide  infra).48  In  some  cases,  solar  advocates  have  recommended  a  higher  rate,  which  in  their  view  accurately  conveys  the  holistic  benefits  of  distributed  solar  PV  generation.49  The  disagreements  over  adequate  and  fair  compensation  for  distributed  solar  customers  on  NEM  schedules  threaten  a  bifurcation  of  utility  customers  into  solar  and  non-­‐solar  classes.  EEI  predicted  that  with  a  compounded  annual  growth  rate  of  22%,  distributed  solar  PV  could  grow  to  10%  of  available  capacity  in  key  markets.  If  this  growth  occurs,  non-­‐solar  customers  would  experience  a  cross-­‐subsidy  in  the  form  of  an  increase  in  their  electricity  rates,  in  excess  of  20%.50  A  study  performed  by  the  Vermont  Public  Service  Department  contested  that  notion  when  it  found  that  net  metered  systems  did  not  impose  significant  net  cost  to  non-­‐solar  customers.51  Furthermore,  Moody’s,  a  bond  credit  rating  agency,  found  that  in  California,  presently  the  nation’s  leader  in  NEM  participation,  the  cost  shifts  onto  these  customers  in  2013  equaled  just  0.73%  of  the  combined  revenue  of  the  state’s  three  IOUs.52  

Understanding  the  value  of  solar  Codifying  the  true  value  of  distributed  solar  PV  to  the  electricity  grid  has  emerged  as  a  critical  issue  in  evaluating  the  efficacy  of  programs  like  NEM.  While  the  regulated  utility  industry  utilizes  a  cost-­‐based  approach  obtained  from  ratepayer-­‐impact  studies,53  solar  advocates  argue  for  a  totality  approach  to  determine  the  impact  of  distributed  solar  on  the  electricity  grid.  The  impetus  for  the  totality  approach  is  the  variety  of  benefits  they  see  distributed  solar  providing  to  aspects  of  a  regulated  utility’s  portfolio.  In  October  2013,  the  Interstate  Renewable  Energy  Council  (IREC)  published  a  guidebook  designed  to  assist  regulators  in  properly  assessing  the  benefits  and  costs  that  can  be  associated  with  distributed  solar  PV.  The  guidebook  highlights  nine  criteria  that  a  regulator  should  consider  when  performing  a  totality  approach  of  the  impacts  of  the  technology:  

1. The  extent  to  which  distributed  solar  PV  would  contribute  to  the  utilities’  avoided  cost  of  generation  by  offsetting  some  production  from  the  next  marginal  generator54  in  the  merit  order,  and  in  the  process  offset  O&M  costs  and  the  cost  of  the  fuel  used  to  supply  the  generating  unit;55  

2. The  ability  of  distributed  solar  PV  generation  to  reduce  transmission  line  losses,  as  locally-­‐produced  solar  generation  can  be  exported  to  the  grid  and  consumed  by  neighboring  customers  on  the  same  circuit;56    

3. The  need  to  assign  capacity  credits  to  distributed  solar  generators  based  on  their  actual  generation,  and  the  ability  for  these  credited  generators  to  reduce  utility  load  demand;57  

4. Potential  deferment  of  transmission  and  distribution  system  upgrades;58    5. The  value  utilities  and  regulators  place  upon  the  ancillary  services  provided  to  the  grid  by  

distributed  solar  PV  systems,  such  as  volt-­‐ampere  reactive  (VAR)  support  and  low  voltage  and  low  frequency  ride-­‐through;59    

6. The  inclusion  of  a  fuel  hedge  price;60  7. The  impacts  of  distributed  solar  PV  generation  on  the  dynamics  of  market  prices  through  a  

reduction  in  overall  electricity  demand  (particularly  in  peak  demand  usage  times)  and  reductions  in  the  number  and  amount  of  purchases  a  utility  has  to  make  on  the  capacity  and  wholesale  markets;61    

8. How  distributed  solar  PV  increases  the  resiliency  and  reliability  of  the  electricity  grid  through  decreased  risk  of  blackouts;62  and  

9. The  level  of  environmental  and  societal  benefits  associated  with  distributed  solar  PV.63  

When  viewed  in  totality,  some  solar  advocacy  groups  contend  that  the  benefits  of  solar  not  only  outweigh  the  costs,  they  also  justify  compensation  above  the  retail  rate  guaranteed  in  most  NEM  policies.    

The  Solar  Energy  Industries  Association  (SEIA),  the  leading  solar  trade  group  in  the  U.S.,  articulated  what  it  believes  are  the  “best  practices”  for  net  metering  and  rate  design  for  distributed  solar  generation.  They  argue  that  each  customer  has  a  right  to  self-­‐generate  via  distributed  solar  PV,  and  that  this  generation  should  not  be  imputed  as  a  cost  to  the  utility.64  The  generation  should  be  designed  according  to  a  marginal  cost  that  emphasizes  the  “long-­‐run  perspective  in  which  a  utility  can  gradually  replace  its  current  energy  infrastructure”  with  more  efficient  technologies.65  While  they  argue  that  the  entire  array  of  benefits  distributed  solar  PV  provide  should  be  considered,  they  maintain  the  need  for  utilities  to  “recover  [their]  cost  of  providing  service  and  earn  a  return  on  investments  as  determined  by  regulators,”  and  that  efforts  should  be  undertaken  to  minimize  cross-­‐subsidizing  and  cost-­‐shifts  within  and  among  customer  classes.66    

SEIA  maintains  that  externalities,  such  as  those  relating  to  the  environmental  impacts  of  utility  power  generation,  should  be  borne  by  market  participants;67  rate-­‐setting  should  be  based  on  how  the  costs  were  incurred  in  the  first  placed  or  how  they  will  likely  be  incurred  in  the  future;  and  that  the  focus  should  be  on  reductions  of  utility  peak  load.68  Overall,  utilities  should  act  transparently  with  regard  to  rate-­‐setting  and  price  signaling:  customers  should  be  informed  of  how  the  rates  set  by  regulators  and  enforced  by  utilities  impact  them,  and  the  rate  schedules  themselves  should  be  understandable  to  all  customers.69    

Reconciling  competing  motivations    Many  regulated  utilities  already  understand  that  their  customers  want  access  to  distributed  solar  PV:  the  technology  offers  an  opportunity  to  democratize  energy  production.  However,  the  crux  of  the  debate  lies  in  the  cost-­‐accounting  performed  to  determine  how  to  compensate  these  customers.  The  utilities  contend  that  while  the  generation  should  be  compensated  for  what  it  supplies,  there  is  no  clear  set  of  metrics  to  determine  what  exactly  these  technologies  are  adding  to  the  grid.  Utilities  prefer  ratepayer  impact  studies  that  exclude  externalities  such  as  fuel  costs,  job  benefits,  and  environmental  compliance  costs  in  the  rate-­‐valuation  of  distributed  solar  PV.70  Long  the  industry  standard,  this  analysis  often  leads  to  compensation  at  the  avoided  cost  of  generation  or  wholesale  rate  rather  than  the  retail  rate  desired  by  solar  customers  and  advocates.  Conversely,  solar  advocates  believe  that  a  totality  approach  that  takes  all  externalities  into  account  is  the  fairest  way  to  determine  adequate  compensation;  reductions  in  customers’  electricity  bills  should  not  be  imputed  as  a  cost  to  the  utilities.  The  roots  of  issues  over  a  proper  valuation  of  distributed  solar  PV,  however,  may  lie  in  the  way  this  resource  is  evaluated  by  utilities:  either  as  a  net  load  reduction  or  as  a  net  resource.    

How  best  to  integrate  solar  With  the  ubiquity  of  electricity  in  everyday  life,  regulated  utilities  must  exercise  due  diligence  in  the  planning  process  to  ensure  they  can  reliably  meet  the  needs  of  customers  for  a  long-­‐term  period.  The  integrated  resource  plan  (IRP)  is  a  utility  function  that  is  designed  to  find  a  least-­‐cost  strategy  to  “evaluate  a  wide-­‐range  of  potential  supply  and  demand-­‐side  resources  to  meet  energy  requirements  and  peak  demand,  plus  a  reserve  margin,”  including  forecasted  price  swings  of  fossil  fuel,  risk  and  uncertainties  associated  with  near-­‐term  construction  of  generation  facilities,  and  potential  

environmental  mandates  and  regulations.71  IRPs  enable  utilities  to  model  potential  uncertainties  in  load  forecasting  and  generation  fleet  performance  and  best  assess  how  the  full  range  of  resources  available  in  their  portfolio  can  facilitate  a  least-­‐cost  approach  to  providing  service.72  Historically,  utility  IRPs  have  focused  on  supply-­‐side  options,  such  as  new  generation  units  to  meet  a  growth  in  demand.  The  implementation  of  state  renewable  energy  standards  and  natural  gas  market  disruptions,  coupled  with  increases  in  the  number  of  installations  of  distributed  solar  PV  systems,  has  begun  shifting  the  analysis  to  include  demand-­‐side  resources.73    

Residential  distributed  solar  PV  systems  are  often  classified  by  utilities  as  a  “behind-­‐the-­‐meter”  resource:  the  incumbent  utility  does  not  own  or  operate  it,  providing  them  with  zero  transparency  into  the  system’s  operation.74  Distributed  solar  PV  is  often  used  to  reduce  on-­‐site  electricity  demand,  in  which  case  the  lower  load  growth  projections  made  by  a  utility  in  its  IRP  would  likely  have  already  incorporated  this  localized  demand  reduction.75  Heretofore,  distributed  solar  PV  has  constituted  such  a  small  portion  of  the  electricity  generation  mix  that  utilities  have  had  little  incentive  to  view  it  as  a  supply-­‐side  resource;  as  such,  a  majority  of  utilities  have  considered  it  as  a  net  load  reduction,  not  as  a  resource  contributor.76  However,  PricewaterhouseCooper’s  2013  survey  indicated  that  82%  of  respondents  in  North  America  predict  that  future  energy  needs  will  be  met  with  a  mix  of  centralized  generation  and  distributed  generation,  including  sources  like  distributed  solar  PV,  suggesting  this  classification  may  soon  be  changing.77    

A  questionnaire  of  several  utilities,  regulated  and  unregulated,  conducted  by  the  National  Renewable  Energy  Laboratory  (NREL),  on  the  evaluation  of  solar  (both  distributed  and  utility-­‐scale)  in  IRPs  found  that  most  utilities  were  concerned  not  only  with  the  rapid  adoption  of  distributed  solar  PV:  some  expressed  anxiety  that  they  underestimated  the  popularity  of  incentives  and  programs  like  NEM  to  spur  demand  for  the  technology.  Most  utilities  have  indicated  that  they  see  the  groundswell  of  support  among  customers  in  their  territories  for  distributed  solar  and  plan  on  evaluating  solar  as  a  resource  in  future  IRPs.78  

Consideration  of  distributed  solar  PV  as  a  supply-­‐side  resource  would  complicate  the  modeling  analyses  performed  in  the  IRP  process,  as  load  assumptions  borne  out  of  the  models  would  have  difficulties  accounting  for  this  distributed  generation  on  the  system  at  the  distribution  or  bulk  levels.79  For  most  of  the  utilities  polled,  a  key  factor  was  determining  the  “threshold  level”  where  distributed  solar  PV  proliferated  to  the  point  where  it  must  be  considered  a  net  resource  contributor.  Several  factors  confound  clearly  identifying  the  threshold  level,  such  as  uncertainty  among  utility  executives  over  future  solar  PV  panel  prices,  what  capacity  credit  and  value  to  attribute  to  the  systems,  and  how  to  properly  account  for  the  integration  costs  associated  with  distributed  solar  PV.80  

Several  approaches  are  available  to  utilities  to  plan  for  the  expected  growth  of  the  solar  PV  sector,  and  the  results  from  the  NREL  survey  indicate  that  utilities  themselves  are  adjusting  their  business-­‐practices  to  accommodate.  As  uptake  of  the  technology  continues,  utilities  and  solar  PV  customers  alike  need  to  work  together  through  cooperation  and  robust  planning  to  ensure  grid  reliability  functionality  and  reliability.  In  order  to  gain  a  more  robust  understanding  of  the  engineering  challenges  ahead,  it  is  worth  considering  the  attendant  technological  impacts  of  distributed  solar  PV.    

Technical  Difficulties  Presently,  the  contribution  of  distributed  solar  to  the  overall  U.S.  generation  mix  is  negligible,  accounting  for  less  than  2%  of  total  installed  generation  capacity.81  As  the  density  of  solar  approaches  the  “threshold  level”,  it  will  likely  be  important  from  a  grid  reliability-­‐standpoint  for  utilities  to  have  the  ability  to  monitor  the  performance  of  distributed  solar  PV  systems  and  have  the  capacity  when  needed  to  affect  some  degree  of  control  over  the  output  of  these  systems.82    

By  virtue  of  the  technology’s  connection  on  distribution  feeders,83  inverter-­‐connected  distributed  solar  resources  are  often  located  without  attention  to  the  design  of  the  electricity  grid  or  consideration  of  potential  limitations  in  its  power  flow  capabilities.84  As  the  deployment  of  distributed  solar  PV  resources  increases  apace,  distinct  technical  challenges  that  impinge  on  the  reliability  of  the  electricity  grid  may  arise,  including:  

1. The  location  of  distributed  solar  PV  systems  at  less-­‐than-­‐optimal  points  on  the  network  from  a  grid-­‐operator  perspective;  

2. The  risk  of  over-­‐voltage  or  reverse  power  flows85  at  the  point  of  common  coupling  (PCC)86  leading  to  potential  overloading  of  the  components  of  the  circuit  and  an  exceedance  of  the  thermal  capacity  of  the  network  lines;87    

3. Immediate  disconnection  of  several  distributed  solar  generators  in  the  event  that  frequency  variations  exceed  the  acceptable  limits  set  out  in  the  grid  code(s),  potentially  forcing  the  utility  to  reduce  demand  by  cutting  service  to  particular  loads;88  

4. General  instability  in  generation  dispatch  to  meet  anticipated  demand;  and  5. Loss  of  stabilizing  inertia  as  increasing  amounts  of  inverter-­‐based  distributed  solar  PV  

generation  come  online.89  

Without  robust  technical  planning,  utilities,  and  by  extension  utility  customers,  could  be  left  with  the  financial  burden  of  upgrading  their  existing  infrastructure  to  mitigate  these  issues  similar  to  what  has  occurred  in  Germany.90  Recently,  some  utilities  have  portended  the  emergence  of  the  “duck  curve”  as  a  harbinger  for  the  unprecedented  impacts  of  high  integrations  of  distributed  solar  PV.91    

The  “Duck  Curve”  The  “duck  curve”  was  first  identified  in  Hawaii  and  California,  two  states  with  high  penetration  of  solar  (both  utility-­‐scale  and  distributed,  generation),  and  has  been  likened  to  a  “worst-­‐case  scenario”  in  which:  

1. A  sunny  but  cool  day  in  spring  or  fall  where  generation  from  the  distributed  solar  PV  systems  drives  demand  for  electricity  down  during  the  mid-­‐day  periods;92  

2. Larger  (i.e.  baseload93)  generation  units  markedly  decrease  their  output,  forcing  these  units  to  operate  below  their  normal  efficiencies;  and  

3. In  the  late  afternoon,  as  the  electricity  generation  of  the  distributed  solar  PV  systems  tapers  off  and  residential  end-­‐user  demand  increases  as  these  users  return  home,  flexible  generating  resources  (such  as  natural  gas-­‐fired  generation  units)  are  required  to  come  online  very  quickly,  and  in  large  numbers,  to  ensure  that  the  supply  perfectly  matches  demand.94  

The  curve  is  shown  below  in  Figure  2,  using  a  load  profile  in  California  in  202095  for  illustrative  purposes:  

 

Figure  2:  The  “duck  curve”96    

As  the  figure  illustrates,  the  curve  presents  two  distinct  challenges:  a  ramp-­‐down  in  baseload  generation  between  08:00  and  11:00  A.M.,  and  a  ramp-­‐up  of  flexible  generation  capacity  between  05:00  and  08:00  P.M.  These  changes  in  the  load  profile  from  high  penetration  of  distributed  solar  PV  resources  no  longer  allow  the  utilities  to  service  the  more  traditional  load  profiles  (the  trace  labeled  “2013  Net  Load”)  that  operated  on  the  least-­‐cost  mix  of  baseload,  intermediate,  and  peaking  generation  resources.  Instead  they  are  forced  to  respond  to  variations  in  the  curve’s  intensity  in  line  with  the  generation  from  the  distributed  solar  PV  resources  on  the  system.97  The  California  Independent  System  Operator  (CAISO)  believes  that  system-­‐balancing  issues,  the  first  sign  of  the  “duck  curve,”  may  be  manifest  as  early  as  2015,  with  the  threat  of  demand  becoming  lower  than  baseload  supply  (due  to  over-­‐generation  from  the  distributed  solar  PV  resources)  occurring  in  2018.98    

Two  studies  analyzed  strategies  that  could  be  employed  to  mitigate  the  technical  challenges  presented  by  the  “duck  curve.”  The  two  studies  proposed  a  mix  of  complementary  technologies,  demand-­‐side  management  (DSM)  programs,  and  O&M  strategies  to:  

1. Minimize  the  scale  of  the  ramp-­‐down  by  limiting  over-­‐generation  of  the  distributed  solar  PV  resources;  

2. Decrease  the  fast  ramp-­‐up  period;  and  3. Flatten  the  peak  demand  periods  (i.e.  in  the  early  evening  periods  when  distributed  solar  PV  

generation  is  effectively  zero).99  

Both  approaches  highlighted  innovative  strategies  that  could  be  used  to  minimize  some  of  the  technical  impacts  to  grid  from  high  penetration  of  distributed  solar  PV  systems  (including  the  potential  for  battery  storage  to  be  deployed  to  ease  the  intensity  of  the  ramp  rates  for  grid  operators;  see  section  ‘Interconnection  and  Storage’  below).  The  authors  of  each  study  noted  that  some  or  all  of  the  strategies  would  require  close  cooperation  between  utilities,  regulators,  system  operators,  and  distributed  solar  PV  customers.  While  some  states  are  mired  in  contentious  conflicts  

over  distributed  solar  PV  and  NEM,  California  has  emerged  as  a  vanguard  by  actively  working  to  placate  the  concerns  of  both  the  regulated  utilities  and  solar  advocates,  and  in  the  process  encouraging  the  continued  growth  of  the  technology.    

 

2. Sunny  California    By  almost  any  metric,  California  is  the  king  of  solar  in  the  U.S.  The  state  ranks  first  in  terms  of  total  solar  energy  jobs,100  has  over  50%  of  the  total  solar  rooftop  installations  with  over  100,000  systems  connected  to  the  grid,101  and  accounted  for  38%  of  all  net-­‐metered  solar  capacity  in  the  U.S.102  The  state’s  NEM  policy,  established  in  1995,  has  served  as  an  important  catalyst  for  the  growth  of  California’s  distributed  solar,  rooftop  solar,  and  utility-­‐scale  solar  PV  markets.103  On  a  single  day,  March  16,  2014,  4,143MW  of  solar  energy,  enough  to  power  3  M  homes,  was  recorded  by  the  CAISO.  The  record-­‐setting  figure,  which  accounted  for  16.5%  of  total  demand,  did  not  even  include  the  estimated  1,100MW  of  distributed  solar  PV  capacity  installed  throughout  the  state.  From  a  grid  operational  standpoint,  the  magnitude  of  solar  output  indicated  that  California’s  grid  is  ready  for  a  high  integration  of  renewable  energy  capacity,  and  that  solar  energy  is  likely  to  lead  the  charge.104    

A  brief  history  of  solar  energy  in  California  California’s  status  as  a  leader  in  the  solar  energy  space  can  be  traced  to  its  commitment  to  renewable  energy.  In  December  2011,  the  California  Public  Utilities  Commission  (CPUC)  updated  the  state’s  renewable  portfolio  standard  (RPS)  in  Senate  Bill  X1-­‐2,  stipulating  that  33%  of  the  sales  from  each  retail  seller  of  electricity  in  2020  must  come  from  RPS-­‐eligible  resources  like  solar  power.105  Moreover,  the  solar  boom  in  California  has  been  promulgated  by  a  mix  of  government  drivers,  incentives,  and  regulatory  policies.  The  California  Solar  Initiative  (CSI),  borne  out  of  the  “Million  Solar  Roofs”  vision  and  launched  in  January  2007,  provides  upfront  incentives  in  the  form  of  solar  rebates  to  customers  of  California’s  three  investor  owned  utilities  (IOUs)  under  the  direction  of  the  CPUC.106  Through  the  CSI,  the  Go  Solar  California  program  was  created  pursuant  to  a  statewide  goal  to  install  3,000MW  of  distributed  solar  capacity  by  2017.107  

The  Self-­‐Generation  Incentive  Program  was  developed  to  provide  incentives  for  qualifying  technologies  like  distributed  solar  PV  systems  installed  on  the  customer’s  side  of  the  meter  (i.e.  “behind-­‐the-­‐meter”).108  In  2012,  California  Governor  Brown  further  galvanized  the  growth  of  the  state’s  solar  industry  when  he  called  for  12,000MW  of  distributed  generation  to  be  in  place  by  2020.  Solar  energy,  and  distributed  solar  PV  in  particular,  is  expected  to  play  a  large  role  in  meeting  the  mandate.  

2013  was  an  active  year  for  the  state’s  solar  PV  sector:  California  led  the  nation  with  an  increase  in  PV  capacity  of  2,621MW,  and  placed  second  with  400MW  of  residential  distributed  solar  PV  installations;109  the  technology  alone  suppressed  electricity  demand  growth  by  an  estimated  47%.110  The  first  few  months  of  2014  are  continuing  that  trend,  as  California  accounted  for  more  than  55%  of  nationwide  residential  solar  PV  installations.111  As  of  April  30,  2014,  Pacific  Gas  &  Electric  (PG&E)  and  Southern  California  Edison  (SCE),  two  of  the  state’s  three  IOUs,  had  572.6MW  of  residential  distributed  solar  PV  energy  on  their  grids,  with  an  additional  41.3MW  pending.112  

 

AB-­‐327  Although  distributed  solar  PV  only  accounted  for  0.4%  of  the  state’s  2013  demand,  California  was  the  scene  of  a  contentious  debate  over  electricity  rate-­‐setting,  NEM,  and  the  role  of  distributed  solar  PV  in  meeting  a  utility’s  peak  load.113  For  years,  California  employed  a  tiered-­‐pricing  structure  that  charged  customers  rates  depending  on  their  monthly  electricity  consumption  (i.e.  the  more  electricity  a  customer  consumes,  the  higher  price  they  pay  per  kilowatt-­‐hour).  The  tiered-­‐pricing  scheme  proved  unpopular,  leading  to  the  drafting  of  Assembly  Bill  327  (AB  327)  to  reduce  the  number  of  customer  rate  tiers  from  four  to  “at  least  two.”114    

California’s  three  IOUs  and  the  CPUC  had  noted  the  destabilizing  potential  of  net-­‐metered  distributed  solar  PV  in  advance  of  AB  327:  a  September  2013  study  drafted  by  the  CPUC  estimated  that  by  2020,  NEM  generation  (both  residential  and  non-­‐residential)  would  impose  a  “direct  cost  to  ratepayers”  of  $1.1  Bn,  an  amount  equal  to  3.2%  of  the  forecasted  revenue  for  the  state’s  IOUs,  and  an  annual  “cost  shift”  of  $359  M  from  distributed  solar  PV  customers  to  non-­‐solar  customers.115  However,  several  critiques  and  inconsistencies  within  the  study  were  quickly  noted,  namely  the  oversight  that  the  figures  the  CPUC  used  for  direct-­‐cost  and  the  cost-­‐shift  attributable  to  NEM  were  based  on  the  very  tiered-­‐pricing  schedule  that  AB  327  will  alter.116    

Although  AB  327  was  designed  to  address  rate-­‐setting  for  all  customer  classes,  solar  advocates  quickly  highlighted  aspects  of  the  proposed  legislation  that  would  abrogate  several  benefits  provided  to  distributed  solar  PV  customers  and  the  possibility  that  the  legislation  could  end  the  state’s  NEM  program  at  the  end  of  2014.117  Governor  Brown  and  California  state  legislators  offered  a  novel  approach  to  the  conflict  when  they  amended  AB  327.  The  amended  bill  removed  the  threat  of  an  end  to  NEM  and  developed  a  procedure  to  standardize  the  process  by  which  each  IOU  would  calculate  its  individual  statutory  cap  for  accepting  NEM  applications.  In  the  process,  they  laid  the  foundation  stone  for  the  development  of  a  more  long-­‐term  program  that  would  ensure  “customer-­‐sited  renewable  distributed  generation  continues  to  grow  sustainably”.118      

On  March  27,  2014,  the  CPUC  handed  down  a  decision  on  AB  327  that  identified  two  potential  “trigger  level”  dates  when  a  “Standard  Contract”  conveying  a  new  level  of  NEM  compensation  will  come  into  effect:  July  1,  2017,  or  the  date  at  which  a  particular  customer’s  IOU  reaches  its  5%  of  nameplate  capacity  statutory  cap.  Furthermore,  the  ruling:  

1. Establishes  a  20-­‐year  transition  period,  beginning  on  the  date  the  solar  customer  is  interconnected  with  the  grid,  during  which  a  customer  will  be  included  on  the  current  NEM  policy  provided  the  date  in  question  is  on  the  earlier  of  July  1,  2017  or  the  date  on  which  the  customer’s  utility  reaches  its  cap;  

2. Mandates  that  customers  who  interconnect  with  their  incumbent  utility  on  the  earlier  of  one  of  the  transition-­‐dates  must  be  given  a  “reasonable  opportunity  to  recoup  the  costs  of  their  investment”  in  a  distributed  generation  system;  and  

3. Mandates  that  by  the  end  of  2015  the  CPUC  must  decide  what  rules  will  apply  to  solar  customers  who  wish  to  net  meter  after  the  earlier  of  the  two  transition-­‐dates  and  to  existing  net-­‐metered  customers  after  their  20-­‐year  transition  period  expires.    

The  CPUC’s  decision  was  significant  in  that  it  provided  certainty  for  both  customers  who  are  interested  in  installing  a  distributed  solar  PV  system  with  the  benefit  of  a  NEM  incentive  and  the  state’s  IOUs  working  to  accommodate  the  popularity  of  NEM,  bolster  their  electricity  grid  to  handle  

increasing  amounts  of  intermittent  generation,  and  comply  with  the  state’s  aggressive  RPS  mandate.  The  20-­‐year  transition  period  was  selected  due  to  the  expected  life  of  most  solar  PV  systems  and  reflects  the  terms  of  a  typical  power  purchase  agreement  that  distributed  solar  PV  customers  often  enter  into  with  a  solar  development  company.119  

Figure  3  illustrates,  the  policy  and  regulatory  decisions  affecting  California’s  NEM  policy  from  2013  to  the  “trigger  level”  dates  on  the  earlier  of  July  1,  2017  or  the  reaching  of  an  IOU’s  cap:  

 

Figure  3:  Timeline  for  NEM  in  California,  2013  to  2017120  

The  Impact  of  the  closure  of  SONGS  In  January  2012,  the  2.2GW  San  Onofre  Nuclear  Generating  Station  (SONGS)  was  initially  shut  down  due  to  premature  wear  on  the  tubes  in  the  plant’s  replacement  steam  generators.  The  closure  of  SONGS,  owed  to  regulatory  uncertainty  following  the  initial  shutdown,  was  not  only  a  heavy  financial  burden  for  SCE  and  San  Diego  Gas  and  Electric  (SDG&E),  at  an  estimated  price  tag  of  $4.1  Bn,  it  also  represented  the  loss  of  generation  capacity  capable  of  powering  2.3  M  homes  in  between  the  massive  load  centers  of  Los  Angeles  and  San  Diego.121  Worse  yet,  the  costs  associated  with  the  plant’s  closure  and  generation  shortfall  risked  a  potential  bifurcation  of  the  California  market  from  large  price  differentials  between  Northern  California  (largely  unaffected  by  SONGS)  and  Southern  California  (whose  customers  would  experience  significantly  increased  energy  prices  from  the  closure).122  

Following  the  closure  of  SONGS,  the  CPUC  had  to  ensure  that  all  customers  in  California  received  reliable  electricity  service  without  unduly  burdening  one  segment  of  the  state’s  customers  with  the  closure  and  clean-­‐up  costs.  The  Commission  ruled  that  approximately  1.0GW  –1.5GW  of  generation  would  be  required  to  make  up  the  shortfall  in  generation,123  and  that  600MW  would  come  from  “preferred  sources,”  or  those  that  have  lower  environmental  impacts  and  lower  public  health  costs  vis-­‐à-­‐vis  fossil-­‐fuel  generation.124  The  emphasis  on  preferred  sources,  combined  with  Governor  Brown’s  mandate  for  12,000MW  of  distributed  generation,  provided  further  opportunity  for  the  growth  of  distributed  solar  PV  energy.  However,  the  impact  of  the  SONGS  closure  also  demonstrated  that  research  and  innovation  in  the  development  of  smart  inverters,  the  interconnection  application  

process,  and  battery  storage  technologies  will  prove  crucial  to  addressing  the  manifold  technical  and  regulatory  challenges  facing  California’s  push  for  increased  integration  of  distributed  solar  PV  and  renewable  energy  resources.  One  example  of  a  technological  solution  is  the  smart  inverter.  

The  Smart  Inverter  Working  Group  California’s  Smart  Inverter  Working  Group  (SIWG)  was  formed  in  January  2013  in  response  to  growing  interest  in  the  potential  of  smart  inverter  technology.  Smart  inverters  have  the  potential  to  mitigate  some  of  the  localized  voltage  issues  and  other  technological  challenges125  that  could  arise  as  the  density  of  sources  like  distributed  solar  PV  increases,  and  in  the  process  further  strengthen  the  grid  to  accommodate  increasing  amounts  of  other  forms  of  distributed  energy  resources.126  They  are  unique  in  that  they  allow  for  communication  between  the  distribution  system  (where  the  solar  PV  systems  are  installed)  and  grid  operators  charged  with  monitoring  the  balance  between  electricity  supply  and  demand.  Incorporation  of  smart  inverters  into  the  larger  Information  and  Communication’s  Technology  platform  can  allow  utility  and  retail  energy  providers  to  communicate  with  distributed  solar  PV  systems  to  override  autonomous  functionalities  in  response  to  several  factors,  including:    

1. Demand-­‐response  price  signals;  2. Real  and  reactive  power  requirements  for  grid  stability;  3. Schedules  for  energy  and  ancillary  services;  4. Increasing  cyber  security;  5. Utility  load-­‐shedding  and  safety  settings;  and    6. More-­‐efficient  operation  of  expensive  distribution  equipment  like  capacitor  banks.127    

 The  SIWG  is  tasked  with  researching  and  modeling  the  ability  for  smart  inverters  to  ease  the  transition  from  the  traditional  uni-­‐directional  power  flow  from  a  centralized  generating  plant  to  the  bi-­‐directional  power  flows  that  characterizes  a  grid  replete  with  distributed  energy  resources.128  The  group’s  goal  is  to  technically  evaluate  the  ability  for  smart  inverters  to  improve  the  autonomous  functions129  that  distributed  energy  resources  like  solar  PV  may  be  required  to  perform,  define  and  propose  various  communication  standards  that  will  be  necessary  for  these  systems  to  communicate  with  grid  operators,130  and  analyze  the  specific  technical  challenges131  that  smart  inverters  may  face  on  the  road  to  deployment  and  grid-­‐integration.  As  experience  in  Germany  has  shown,  where  the  cost  of  retrofits  for  existing  inverters  to  have  “smart”  functionalities  is  estimated  to  total  $300  M,  the  financial  penalties  of  delaying  the  deployment  of  smart  meters  as  the  density  of  distributed  solar  PV  increases  can  be  sizeable.132      Presently,  smart  inverters  are  not  code-­‐compliant  with  the  U.S.  national  standards,133  and  with  the  often  significant  timespans  between  revisions  of  grid  code  standards,134  it  appears  unlikely  that  full-­‐scale  adoption  of  smart  inverters  into  the  U.S.  grid  code  will  occur  in  the  near  future.  Despite  the  slow  gears  of  change  on  the  federal  level,  California  amended  its  grid  code  standard  in  2000  in  response  to  the  influence  of  NEM  on  the  uptake  of  distributed  solar  PV  systems,  and  expects  the  first  phase  of  the  SIWG’s  results  to  be  published  in  October  2015.135  While  the  state  continues  to  pioneer  development  of  legislative,  regulatory,  and  technological  solutions  to  the  impacts  of  net-­‐metered  distributed  solar  PV,  it  has  also  been  forced  to  address  even  more  fundamental,  and  potentially  paradigm-­‐shifting,  changes  to  the  relationship  between  regulated  utilities  and  their  customers.    

Interconnection  and  Storage  As  the  popularity  of  NEM  has  driven  growth  in  residential  distributed  solar  PV,  California’s  three  IOUs  have  been  faced  with  almost  consistent  increases  in  the  volume  of  interconnection  requests  they  receive  from  their  customers.  SDG&E  saw  a  108%  increase  in  NEM  authorizations  from  2012  to  2013,  with  over  11,000  new  customer-­‐projects  interconnected  to  the  grid  in  2013  alone,  and  a  73%  growth  rate  predicted  from  2013  to  2014.  PG&E,  which  currently  services  25%  of  rooftop  distributed  solar  PV  systems  in  the  U.S.  with  107,680  systems  installed  to  date,  has  seen  increasing  numbers  of  customers  applying  for  their  NEM  program,  with  2,790  applications  per  month  expected  in  2014.136  In  an  April  2014  NREL-­‐sponsored  webinar,  both  IOUs  discussed  how  the  deluge  of  interconnection  applications  and  requests  they  have  seen  in  recent  years  have  forced  them  to  develop  new  interconnection  application  processes  designed  to  handle  the  breadth  and  volume  of  requests.  At  the  same  time,  both  SDG&E  and  PG&E  are  refining  methods  to  more  effectively  allocate  the  human  and  technical  resources  necessary  to  adequately  retrofit  their  grid  in  line  with  the  increasing  amounts  of  distributed  generation  coming  on-­‐line.137  

Concurrent  with  the  growth  of  NEM-­‐interconnection  requests,  the  California  legislature  approved  Assembly  Bill  2514  (AB  2514),138  a  first-­‐of-­‐its-­‐kind  storage  mandate,  in  October  2013.  The  mandate  required  the  state’s  three  IOUs  to  install  1.325GW  of  storage  by  2020,139  with  the  goals  of  the  mandate  focusing  on  how  to  better  interconnect  renewable  energy  resources  and  meet  the  state’s  aggressive  RPS  mandate.140  From  the  perspective  of  distributed  solar  PV,  the  mandate  included  some  aspects  of  behind-­‐the-­‐meter  storage  and  encouraged  more  third-­‐party  ownership,  two  points  of  emphasis  that  feed  into  the  nascent  distributed  solar-­‐plus-­‐battery  storage  movement  already  underway  in  the  state.141      

The  prospect  of  distributed  solar-­‐plus-­‐battery  storage,  referred  to  as  the  “utility-­‐in-­‐a-­‐box”,  could  allow  a  residential  customer  to  completely  sever  its  ties  with  the  utility:  customers  can  utilize  distributed  energy  systems  like  solar  PV  to  meet  on-­‐site  electricity  demand,  use  the  battery  storage  system  to  store  excess  generation,  and  finally  use  this  stored  energy  to  meet  on-­‐site  demand  when  the  solar  PV  system  is  not  producing  enough  electricity.  Although  the  economics  of  energy  storage  are  at  least  several  decades  away  from  being  a  viable  option  for  residential  customers  in  the  U.S.,  RMI’s  report  found  that  California  is  one  state  that  could  see  the  predicted  price  declines  of  the  “utility-­‐in-­‐a-­‐box”  model  allow  residential  customers  to  pursue  this  option  within  the  next  30  years.142    

The  state’s  IOUs  noted  that  although  storage  would  be  beneficial  in  easing  the  ramp-­‐up  rates  and  that  the  locational  value  of  storage  on  distribution  feeders  could  ease  some  of  the  technological  challenges  associated  with  the  growth  of  distributed  solar  PV  systems,  the  prospect  of  these  customers  could  store  both  grid  and  solar-­‐produced  electricity  in  their  battery  systems  and  then  sell  this  electricity  back  to  the  utility  at  higher  rates  than  it  cost  to  produce  would  further  threaten  their  revenue  recovery  mechanisms.143  Despite  the  risk  of  customers  going  off-­‐grid  with  the  aid  of  storage  systems,  RMI’s  study  found  that  the  greatest  benefit  for  both  distributed  solar  customers  and  utilities  exists  when  these  solar-­‐plus-­‐storage  systems  are  integrated  into  the  grid,  not  divorced  from  it.144    

The  tension  between  the  IOUs  and  residents  seeking  interconnection  agreements  for  distributed  solar-­‐plus-­‐battery  storage  reached  a  head  in  early  2014,  when  SolarCity,  a  leading  solar  PV  system  provider,  discontinued  its  applications  for  storage  systems  amidst  what  it  saw  as  excessive  utility  

interconnection  fees.145  Customers  who  had  already  applied  for  interconnection  complained  of  long-­‐wait  times  for  approval  and  protested  what  they  saw  as  exorbitant  and  unjust  fees  imposed  on  them  by  the  incumbent  IOUs.146  The  conflict  forced  the  CPUC  to  address  the  unprecedented  changes  to  customer  empowerment  and  electricity  provision  associated  with  interconnection  and  battery  storage,  and  once  again  thrust  California  to  the  forefront  of  the  debate.    

In  response,  the  CPUC  began  considering  the  issue  of  the  imposition  of  interconnection  fees  on  residential  customers  seeking  solar-­‐plus-­‐battery  storage  systems.  The  utilities  noted  in  their  comments  leading  up  to  a  proposed  decision  that  these  systems  would  accelerate  the  cost-­‐shift  for  grid  maintenance  to  non-­‐solar  customers  and  could  even  impose  safety  hazards  to  the  function  of  the  distribution  system.147  Furthermore,  SDG&E  contended  that  the  existing  NEM  subsidy,  combined  with  AB  2514,  was  sufficient  to  incent  the  deployment  of  distributed  storage  technologies.  Solar  advocacy  groups  countered  that  storage  combined  with  renewables  provided  the  highest  operational  value  for  utilities  by  giving  them  the  opportunity  to  manage  loads  more  effectively  (and  locally)  and  to  smooth  power  quality  issues  on  the  distribution  circuits.148    

In  April  2014,  the  CPUC  issued  a  proposed  decision  declaring  that  storage  devices  paired  with  NEM-­‐eligible  generation  facilities  like  solar  PV  were  exempt  from  the  interconnection  application  fees,  supplemental  review  fees,  costs  for  distribution  upgrades,  and  standby  charges  when  interconnecting.  It  did  not  consider  storage  to  be  a  “Generator”  as  defined  in  and  subject  to  Rule  21  Interconnection  tariffs;  rather,  it  considered  a  “generation  facility”  to  include  a  generator  (distributed  solar  PV)  plus  an  addition  or  enhancement  (i.e.  battery  storage).  The  Commission’s  decision  openly  criticized  the  state’s  IOUs,  noting  that  they  “disagree  with  IOUs’  conclusions  [regarding  interconnection  fees  and  storage]  and  would  have  preferred  that  the  IOUs  had  taken  a  more  proactive  and  collaborative  approach  to  avoid  creating  barriers”  in  the  interconnection  process.149  Although  the  proposed  decision  was  not  an  out-­‐right  win  for  solar  advocacy  groups,  it  did  result  in  SolarCity  restarting  its  interconnection  applications.150      

The  basic  economics  of  storage  need  to  improve,  although  the  potential  for  falling  costs  and  regulatory  mandates  like  FERC  Order  755151  provide  opportunities  for  storage  to  become  more  economical  for  residential  customers.  Overall,  California  has  recognized  the  need  to  support  the  nascent  storage  industry  with  the  prescience  to  see  that  distributed  solar  combined  with  battery  storage  is  a  powerful  development  to  democratize  energy  production.  In  a  broader  sense,  the  emphasis  the  state  has  placed  on  crafting  legislation  that  mandates  and  incentivizes  the  uptake  of  renewable  energy  and  storage  technologies,  seeking  regulatory  decisions  that  take  the  concerns  of  all  parties  into  account,  and  undertaking  detailed  studies  on  the  technological  impacts  associated  with  distributed  solar  PV  and  storage  systems,  demonstrates  its  commitment  to  stand  at  the  vanguard  of  the  growing  distributed  energy  revolution.    

Heretofore,  this  white  paper  has  examined  the  impact  of  net-­‐metered  distributed  solar  PV  on  the  utility  business  model,  the  regulatory  processes  evolved  in  ascribing  a  value  of  the  services  distributed  solar  PV  supplies  to  the  grid,  and  the  general  technological  function  of  the  electricity  grid.  Regulated  utility  customers  are  actively  seeking  to  democratize  the  production  of  energy,  and  as  evidenced  by  the  popularity  of  NEM  in  parts  of  the  country,  this  movement  has  proved  popular.  The  regulated  utility  industry,  cognizant  of  their  history  as  a  defensive  industry  that  recoups  both  fixed  and  variable  costs  through  customer  rates,152  has  tended  to  view  distributed  solar  PV,  NEM,  

and  even  battery  storage  as  the  potential  beginning  steps  towards  a  new  paradigm  wherein  customers  could  disintermediate  themselves  from  utilities.    

 

3. Alternatives  to  NEM    

With  a  raft  of  legislative  and  regulatory  filings  regarding  NEM  emerging  in  states  across  the  U.S,  significant  interest  has  been  shown  and  research  undertaken  from  both  regulated  utilities  and  solar  advocacy  groups  to  determine  possible  alternatives  to  than  NEM.  When  NREL  asked  a  sample  of  utilities  throughout  the  U.S.  what  options  other  than  NEM  they  would  consider,  the  questionnaire  returned  three  potential  options:  fixed  cost  recovery,  a  value  of  solar  tariff  (VOST)  rate  schedule,  and  a  reframing  of  the  cost-­‐of-­‐service  framework.153    

A  fixed  cost  recovery  system  could  involve  the  use  of  demand  charges,  customer  chargers,  or  standby  charges  to  recover  portions  of  the  fixed  costs  that  utilities  claim  distributed  solar  PV  could  shift  from  one  rate  class  to  another.  This  revenue-­‐recovery  model  was  implemented  in  Arizona  in  January  2014,154  while  Oklahoma  is  presently  considering  the  option  of  imposing  a  fixed  cost  to  distributed  generation  customers.155  However,  utilities  have  been  reticent  to  implement  such  charges  for  fear  it  could  be  viewed  as  cost  for  “going  solar.”156    

A  VOST  is  a  rate  schedule  in  which  a  utility  customer  pays  all  applicable  charges  on  their  monthly  electricity  bill  while  the  utility  purchases  all  of  the  distributed  solar  PV  system’s  output  at  a  rate  that  represents  the  value  provided  to  the  utility  by  the  distributed  energy  resource.  157  In  other  words,  the  tariff  separates  an  end-­‐user’s  consumption  of  energy  from  the  compensation  they  receive  from  the  utility,  allowing  the  utility  to  pay  a  transparent  and  market-­‐based  price  for  the  system’s  output.158  In  March  2014,  Minnesota  established  the  nation’s  first  VOST  as  a  potential  alternative  to  NEM.  The  Minnesota  Department  of  Commerce  developed  a  framework  for  the  VOST  based  on  the  annually-­‐adjusted  savings  from  several  of  the  benefits  that  IREC  argued  can  be  attributed  to  distributed  solar  PV  generation.159  The  state’s  VOST  is  designed  to  reflect  the  monetary  value  that  solar  provides  to  utilities,  power  producers,  and  society  and  ultimately  reduce  the  need  for  incentives  to  drive  the  continued  growth  of  the  technology.  160      

The  VOST  provides  utilities  with  an  economic  equation  specified  in  the  tariff-­‐framework  to  define  the  level  of  market  price  that  should  be  provided  to  distributed  solar  PV  power  producers,  levelized  over  25  years  (the  estimated  life  of  a  solar  PV  panel)  at  a  discount  rate  of  3%,  adjusted  for  inflation,  and  updated  annually.161  The  transparency  of  the  market  price  would  uncouple  the  compensation  from  the  retail  electricity  rate,  helping  to  mitigate  the  potential  for  a  cross-­‐subsidy  for  non-­‐solar  customers.162  Several  addition  benefits  were  identified,  including:  

1. The  ability  for  the  utility  to  recover  the  infrastructure  costs  associated  with  the  grid’s  functionality  and  O&M  through  the  separate  billing  structure,  

2. The  obviating  of  any  standby  charges  for  residential  customers  who  install  net-­‐metered  PV  systems,163  and  

3. The  opportunity  for  the  Minnesota  Public  Utilities  Commission  to  adjust  future  VOS  rates  according  to  the  previous  year’s  inflation  rate,  as  noted  above.164  

The  tariff  would  be  set  at  $0.145/kWh,  higher  than  the  state’s  NEM  level  of  $0.115/kWh.  Using  these  rates,  a  customer  with  a  5-­‐kilowatt  solar  PV  system  under  the  VOST  would  earn  $200  above  the  compensation  they  would  receive  using  the  state’s  NEM  program,  although  the  cost  of  NEM  is  expected  to  increase  substantially  in-­‐line  with  future  increases  in  the  retail  cost  of  electricity.165  

The  VOST  model  approved  by  Minnesota  has  faced  critique  from  both  sides.  Utility  advocates  objecting  to  calculation  of  the  environmental  benefits  associated  with  distributed  solar  PV,166  while  solar  advocates  objected  to  the  limits  on  on-­‐site  consumption  and  the  forfeiture  of  solar  renewable  energy  credits  to  the  customer’s  incumbent  utility.167  Further  criticism  has  highlighted  the  possibility  that,  due  to  the  separation  of  consumption  and  production,  net-­‐metered  solar  PV  customers  could  have  their  production  rebates  considered  as  taxable  ordinary  income,  and  that  these  customers  may  be  ineligible  for  the  investment  tax  credit  to  help  finance  the  system.168    

Finally,  utilities  could  consider  an  overhaul  of  the  cost-­‐of-­‐service  framework  wherein  they  would  line-­‐up  all  of  the  services  a  utility  provides  to  its  customers  and  all  of  the  services  a  distributed  solar  PV  system  provides  to  the  utility  and  the  grid.  Such  a  “line  item”  cost  review  is  very  complex,  not  in  the  least  due  to  the  disagreement  over  the  specific  services  provided  by  distributed  solar  PV  to  the  utility  and  the  grid.169    

 

4. Moving  forward    

As  the  growth  of  net-­‐metered  distributed  solar  PV  has  focused  attention  on  the  future  of  the  regulated  utility  industry,  much  has  been  made  of  comparisons  between  the  industry  and  the  events  that  befell  the  telecommunications  industry  beginning  in  the  1970s.  The  telecommunications  industry,  once  fully  regulated  and  dominated  by  monopolies,  was  completely  overhauled  by  the  introduction  of  new,  “disruptive”  technologies  and  upstart  market  entrants  eager  to  erode  the  legacy  of  the  sector’s  stalwarts.170  Although  important  distinctions  exist,  regulated  utilities,  like  the  telecommunications  industry,  may  be  forced  to  shift  their  regulatory  strategies  to  focus  on  setting  long-­‐term  goals  to  meet  changing  customer  demands.  Such  performance-­‐based  regulation  would  augment  the  cost-­‐of-­‐service  regulatory  design  by  inserting  an  upside  for  utilities  willing  to  innovate  to  improve  the  service  provided  to  their  ratebase,171  and  potentially  shift  their  role  more  towards  that  of  grid  service  providers.172    

As  investors  are  hinting  at  divesting  pension  funds  from  electric  utility  stocks,  citing  the  revenue-­‐erosion  and  introduction  of  new  risk  from  distributed  generation  sources,173  and  as  electric  sector  stocks  are  being  downgraded,  the  optics  appear  to  be  shifting  towards  a  radically  new  view  of  the  regulated  utility  industry  and  the  very  nature  of  electricity  supply  and  demand.174  The  confluence  of  several  complimentary  factors  increasing  demand  for  distributed  solar  PV  energy  have  led  some  to  argue  for  regulated  utilities  to  abandon  the  ad  hoc  approaches  focused  on  cost-­‐recovery  mechanisms  or  incentives  schemes.175  

In  fact  there  is  nothing  preventing  the  development  of  a  model  that  financially  rewards  a  utility  for  considering  distributed  solar  PV  and  distributed  energy  generation  in  general  as  opportunities  for  the  industry  to  grow  and  change.  As  NEM  spurs  the  further  growth  of  distributed  solar  PV,  regulated  utilities  must  find  a  way  to  work  with,  rather  than  compete  against  customers  adopting  these  

technologies.176  The  electrical  generating  system  of  the  future,  one  of  greater  complexity  at  the  behind-­‐the-­‐meter  distribution,  wholesale  distribution,  and  transmission  levels  than  today’s  current  formulation,  may  indeed  necessitate  the  transformative  and  “disruptive”  changes  envisaged  by  EEI.177    

 

   

Endnotes                                                                                                                              1    See  Pernick,  Ron,  Clint  Wilder,  and  James  Belcher.  Clean  Energy  Trends  2014.  Review,  Clean  Edge,  2014,  (2).    2    See  The  Pew  Charitable  Trusts.  Who's  Winning  the  Clean  Energy  Race  2013.  Review,  Washington:  The  Pew  Charitable  Trusts,  2014,  (31).    3    See  The  American  Council  on  Renewable  Energy.  The  Outlook  for  Renewable  Energy  in  America  2014.  Review,  Washington:  The  American  Council  on  Renewable  Energy,  2014,  (16).    4    Solar  added  47  new  generation  units  (either  new  build  or  expansion)  through  January,  February,  and  March  2014,  totaling  584MW  of  installed  capacity.  Total  installed  capacity  additions  through  March  2014  for  all  energy  sources  totaled  1,150MW.  See  The  Federal  Energy  Regulatory  Commission.  Energy  Infrastructure  Update  for  March  2014.  Update,  Washington:  The  Federal  Energy  Regulatory  Commission,  2014,  (3).  In  terms  of  nameplate  capacity  additions,  solar  energy  of  all  types  (see  footnote  5)  accounted  for  74%  of  new  electric  generating  capacity  additions  in  2013.  See  Solar  Energy  Industries  Association.  U.S.  Solar  Market  Insight  Report:  Q1  2014  Executive  Summary.  Executive  Summary,  SEIA,  2014,  available  at:  http://www.greentechmedia.com/research/ussmi,  (3).    5    Solar  energy  technologies  include  photovoltaic  (PV),  solar  hot  water,  solar  electricity  (usually  involving  concentrated  solar  power),  passive  solar  heating  and  daylighting,  and  solar  process  space  heating  and  cooling  technologies.  This  paper  will  focus  exclusively  on  solar  PV.  See  Types  of  Solar  Energy.  n.d.  http://www.renewableenergyworld.com/rea/tech/solar-­‐energy  (accessed  April  7,  2014).      6    See  The  American  Council  on  Renewable  Energy.  The  Outlook  for  Renewable  Energy  in  America  2014.  Review,  Washington:  The  American  Council  on  Renewable  Energy,  2014,  (16).    7    See  Electric  Power  Research  Institute.  (2014).  The  Integrated  Grid:  Realizing  the  Full  Value  of  Central  and  Distributed  Energy  Resources.  Palo  Alto:  EPRI,  (10).    8    See  Stromsta,  Karl-­‐Erik.  Solar  tops  US  Q1  power  additions.  May  29,  2014.  http://www.rechargenews.com/solar/article1363739.ece  (accessed  May  29,  2014).    9    The  cost  of  residential  PV  systems  decreased  by  8.8%  in  2013,  from  $5.03  per  watt  in  2012  to  $4.59  per  watt.  See  Solar  Energy  Industries  Assocation.  U.S.  Solar  Market  Insight  Report:  2013  Year-­‐In-­‐Review  Executive  Summary.  Review,  Washington:  Solar  Energy  Industries  Assocation,  2013,  (16).  As  Figures  A.1  illustrates,  the  nationally  averaged  price  of  a  PV  panel  has  decreased  by  60%  since  the  beginning  of  2011.    

                                                                                                                                                                                                                                                                                                                                                                                         

 Figure  A.1:  Average  PV  System  Price,  2001-­‐2013  

 See  Solar  Energy  Industries  Association.  "Solar  Energy  Facts:  2013  Year  In  Review."  U.S.  PV  Market  Installs  4751MW;  Largest  Year  On  Record.  Washington:  Solar  Energy  Industries  Assocation,  March  5,  2014.  For  a  more  complete  discussion  of  the  declining  price  of  solar  PV  systems  in  the  U.S.,  See  Barbose,  Galen,  Naim  Darghouth,  Samantha  Weaver,  and  Ryan  Wiser.  Tracking  the  Sun  VI:  An  Historical  Summary  of  the  Installed  Price  of  Photovoltaics  in  the  United  States  from  1998  to  2012.  Report,  Washington:  Lawrence  Berkeley  National  Laboratory,  2013.    10    The  primary  federal  tax  credit  is  the  Investment  Tax  Credit  (ITC),  which  provides  a  30%  tax  credit  for  solar  PV  systems  to  residential  (under  Section  25D)  and  commercial  (under  Section  48)  properties.  The  ITC  has  been  credited  with  driving  a  1,600%  growth  in  annual  solar  installations  since  2016.  See  Solar  Investment  Tax  Credit  (ITC).  n.d.  http://www.seia.org/policy/finance-­‐tax/solar-­‐investment-­‐tax-­‐credit  (accessed  April  7,  2014).  Several  state-­‐specific  tax  credits  exist  to  encourage  installation  and  build-­‐out  of  solar  energy  projects  and  systems.  For  a  comprehensive  database,  See  Database  of  State  Incentives  for  Renewables  &  Efficiency.  Tax  Credits.  2013-­‐2014.  http://www.dsireusa.org/solar/solarpolicyguide/?id=13  (accessed  April  7,  2014).    11    See  Bloomberg  New  Energy  Finance  and  The  Business  Council  for  Sustainable  Energy.  2014  Sustainable  Energy  in  America  Factbook.  Washington:  Bloomberg  New  Energy  Finance,  2014,  (53-­‐54).    12    See  Doom,  Justin.  Crowdfunding  Seen  Topping  $5  Billion  for  Rooftop  Solar.  April  8,  2014.  http://www.bloomberg.com/news/2014-­‐04-­‐08/crowdfunding-­‐seen-­‐topping-­‐5-­‐billion-­‐for-­‐rooftop-­‐solar.html  (accessed  April  8,  2014).    13    See  Solar  Energy  Industries  Association.  U.S.  Solar  Market  Insight  Report:  Q1  2014  Executive  Summary.  Executive  Summary,  SEIA,  2014,  available  at:  http://www.greentechmedia.com/research/ussmi.    14    In  theory  this  eliminates  the  transmission  and  distribution  losses  associated  with  the  generation  of  large  amounts  of  power  from  a  centralized  location.  See  U.S.  Energy  Information  Administration.  "Policies  for  compensating  behind-­‐the-­‐meter  generation  vary  by  State."  Today  in  Energy,  May  9,  2012.    15    See  Solar  Energy  Industries  Association.  Issues  &  Policies:  Net  Metering.  n.d.  http://www.seia.org/policy/distributed-­‐solar/net-­‐metering  (accessed  April  7,  2014).    16    Strictly  speaking,  NEM  tariffs  were  introduced  to  provide  a  customer  who  installs  a  qualifying  facility  (QF),  such  as  a  solar  rooftop  PV  array,  with  greater  compensation  than  would  be  provided  to  them  through  the  

                                                                                                                                                                                                                                                                                                                                                                                         Public  Utility  Regulatory  Policies  Act  of  1978  (PURPA).  Under  PURPA,  a  customer  who  installed  a  QF  on  their  property  would  be  compensated  at  the  utility’s  avoided  cost  of  energy,  a  rate  historically  below  the  retail  rate.  NEM  tariffs  increased  the  compensation  given  to  solar  customers  by  remunerating  them  at  the  retail  rate  for  any  generation  in  excess  of  their  on-­‐site  consumption.  See  Wan,  Yih-­‐huei,  and  H.  James  Green.  "Current  Experience  with  Net  Metering  Programs."  Windpower  '98.  Bakersfield:  NREL,  1998.  1-­‐9.    17    90.7%  of  NEM  customers  were  residential.  See  Marcacci,  Silvio.  Fitch  Ratings:  Net  Metering  Can  Destabilize  Entire  Utility  Industry.  December  27,  2013.  http://theenergycollective.com/silviomarcacci/321161/fitch-­‐ratings-­‐net-­‐metering-­‐can-­‐destabilize-­‐entire-­‐utility-­‐industry  (accessed  April  10,  2014).  Figure  A.2  shows  the  quarterly  growth  in  U.S.  residential  PV  installations  from  Q2  2010-­‐Q4  2013:    

 

Figure  A.2:  Growth  of  U.S.  residential  solar  PV,  Q2  2010-­‐Q4  2013    See  Solar  Energy  Industries  Assocation.  U.S.  Solar  Market  Insight  Report:  2013  Year-­‐In-­‐Review  Executive  Summary.  Review,  Washington:  Solar  Energy  Industries  Assocation,  2013,  (11).    18    As  the  U.S.  Energy  Information  Administration  notes  in  its  Short-­‐term  Energy  Outlook  2014,  “customer-­‐sited  photovoltaic  capacity  growth  is  projected  to  exceed  [the  52%]  utility-­‐scale  solar  growth  between  2013  and  2015.”  See  U.S.  Energy  Information  Administration.  Short-­‐term  Energy  Outlook:  Renewables  and  CO2  Emissions.  March  11,  2014.  http://www.eia.gov/forecasts/steo/report/renew_co2.cfm  (accessed  April  7,  2014).    19    See  Martin,  Christopher,  and  Will  Wade.  America’s  Power  Machine:  Hulking,  Creaky,  and  Losing  Its  Grip.  December  26,  2013.  http://www.bloomberg.com/quicktake/u-­‐s-­‐electrical-­‐grid/  (accessed  April  7,  2014).    20    See  International  Energy  Agency.  Insights  Series  2012:  Securing  Power  during  the  Transition.  Paris:  IEA,  2012,  (36-­‐44).    21    The  analysis  contained  in  this  white  paper  will  focus  exclusively  on  the  impacts  of  distributed  solar  PV  and  NEM  on  the  regulated  electric  utilities.      22  See  Martin,  Christopher,  and  Will  Wade.  America’s  Power  Machine:  Hulking,  Creaky,  and  Losing  Its  Grip.  December  26,  2013.  http://www.bloomberg.com/quicktake/u-­‐s-­‐electrical-­‐grid/  (accessed  April  7,  2014).    

                                                                                                                                                                                                                                                                                                                                                                                         23    See  Kind,  Peter.  Disruptive  Challenges:  Financial  Implications  and  Strategic  Responses  to  a  Changing  Retail  Electric  Business.  White  Paper,  Washington:  Edison  Electric  Institute,  2013,  (17,  19).    24    See  Creyts,  Jon,  and  Leia  Guccione.  The  Economics  of  Grid  Defection:  When  and  Where  Distributed  Solar  Generation  Plus  Storage  Competes  with  Traditional  Utility  Service.  White  Paper,  Boulder:  Rocky  Mountain  Institute,  2014,  (17).    25    In  March  of  2014,  Bank  of  America  Merrill  Lynch  noted  that  they  were  “downgrading  shares”  of  regulated  utilities  held  by  Pinnacle  West  Corporation  because  of  “challenging”  rate  cases  resulting  from  “the  continued  adoption  of  distributed  generation”  such  as  solar  PV  in  Arizona,  noting  that  the  $5  fixed  charge  for  solar  PV  installations  instigated  in  January  2014  did  “little  to  stem  the  spread  of  distributed  generation”  in  the  state.  See  Chin,  Brian,  and  Robert  Koryl.  A  Difficult  Regulatory  Cycle  Ahead  Prompts  Neutral  Rating.  March  28,  2014.  http://dontkillsolar.com/tusk/wp-­‐content/uploads/2014/03/BOA-­‐Pinnacle-­‐West-­‐Downgrade-­‐3.28.14-­‐with-­‐highlights.pdf  (accessed  May  30,  2014).      26    In  May  2014,  the  Barclays  credit  strategy  team  downgraded  shares  of  U.S.  high-­‐grade  corporate  bonds  of  the  entire  electric  sector  due  to  the  challenges  facing  the  regulated  utility  industry  from  distributed  solar  PV  and  residential  energy  storage,  noting  that  this  combination  could  for  the  first  time  in  over  100  years  “reconfigure  the  organization  and  regulation  of  the  electric  power  business  over  the  coming  decade.”  See  Aneiro,  Michael.  Barclays  Downgrades  Electric  Utility  Bonds,  Sees  Viable  Solar  Competition.  May  23,  2014.  http://blogs.barrons.com/incomeinvesting/2014/05/23/barclays-­‐downgrades-­‐electric-­‐utility-­‐bonds-­‐sees-­‐viable-­‐solar-­‐competition/  (accessed  May  30,  2014)  and  Wile,  Rob.  Barclays  Has  The  Best  Explanation  Yet  Of  How  Solar  Will  Destroy  America's  Electric  Utilities.  28  2014,  May.  http://www.businessinsider.com/barclays-­‐downgrades-­‐utilities-­‐on-­‐solar-­‐threat-­‐2014-­‐5  (accessed  May  30,  2014).    27    A  survey  conducted  in  2013  by  PricewaterhouseCoopers  revealed  that  only  six%  of  international  industry  representatives  expect  the  utility  business  model  to  remain  “more  or  less  the  same.”  See  PricewaterhouseCoopers.  Energy  transformation:  The  impact  on  the  power  sector  business  model.  Survey,  PricewaterhouseCoopers,  2013  quoted  in  Sklar,  Scott.  Utility  Nightmares:  Distributed  Generation  and  Halving  Electricity  Consumption.  April  16,  2014.  http://www.renewableenergyworld.com/rea/news/article/2014/04/utility-­‐nightmares-­‐halving-­‐electricity-­‐consumption-­‐and-­‐distributed-­‐generation  (accessed  April  28,  2014).      28    Utility  stocks  were  once  considered  to  be  the  quintessential  “window  and  orphan”  stock,  carrying  low  risk  and  paying  out  high  dividends  to  shareholders.  See  Investopedia  Staff.  The  Industry  Handbook:  The  Utilities  Industry.  n.d.  http://www.investopedia.com/features/industryhandbook/utilities.asp  (accessed  April  9,  2014).  Furthermore,  utility  stocks  and  bonds  have  been  the  preferred  asset  classes  for  U.S.  pension  funds  due  to  the  absence  of  virtually  all  market  risks  and  competitions,  and  almost  assured  guaranteed  rates  of  return  and  revenue  recovery.  See  Peterson,  Lee.  Pension  Funds  Hold  a  Key  to  Renewable  Energy  Finance.  April  30,  2014.  http://www.renewableenergyworld.com/rea/news/article/2014/04/pension-­‐funds-­‐hold-­‐a-­‐key-­‐to-­‐renewable-­‐energy-­‐finance?cmpid=rss  (accessed  April  30,  2014).    29    By  virtue  of  its  stability,  a  defensive  industry  does  not  require  the  same  expected  returns  as  compared  to  investments  in  less  mature  or  more  volatile  industries.  This  expectation  of  lower  returns  in  turn  leads  to  lower  borrowing  costs  and  higher  relative  share  values  for  shareholders/investors.  See  Kind,  Peter.  Disruptive  Challenges:  Financial  Implications  and  Strategic  Responses  to  a  Changing  Retail  Electric  Business.  White  Paper,  Washington:  Edison  Electric  Institute,  2013,  (8).      30    See  Investopedia.  Leverage.  n.d.  http://www.investopedia.com/terms/l/leverage.asp  (accessed  April  9,  2014).    31    See  Kind,  Peter.  Disruptive  Challenges:  Financial  Implications  and  Strategic  Responses  to  a  Changing  Retail  Electric  Business.  White  Paper,  Washington:  Edison  Electric  Institute,  2013,  (7,  8).    

                                                                                                                                                                                                                                                                                                                                                                                         32    See  Peterson,  Lee.  Pension  Funds  Hold  a  Key  to  Renewable  Energy  Finance.  April  30,  2014.  http://www.renewableenergyworld.com/rea/news/article/2014/04/pension-­‐funds-­‐hold-­‐a-­‐key-­‐to-­‐renewable-­‐energy-­‐finance?cmpid=rss  (accessed  April  30,  2014).    33    That  is,  the  distributed  solar  PV  customer’s  total  monthly  usage  less  the  output  of  their  PV  panel.    34    As  Figure  A.3  illustrates,  the  evolution  of  the  utility  industry’s  credit  ratings  has  been  towards  progressively  lower  levels.    

 

Figure  A.3:  Evolution  of  Electric  Utility  Industry  Credit  Ratings,  1970-­‐2011    

If  the  credit  rating  continues  to  erode  beyond  the  BBB  ratings  currently  held  by  a  majority  of  the  industry,  utilities  would  face  “a  significant  rerating  of  capital  costs,  credit  availability,  and  investor  receptivity  to  the  sector.”  See  Kind,  Peter.  Disruptive  Challenges:  Financial  Implications  and  Strategic  Responses  to  a  Changing  Retail  Electric  Business.  White  Paper,  Washington:  Edison  Electric  Institute,  2013,  (8,  10).  

35    As  John  Whitlock  of  S&P  notes,  “Favorable  borrowing  costs  are  essential  for  regulated  utilities’  ability  to  meet  the  industry’s  high  capital  demands.”  See  Graf,  Bill,  Pauline  M.  Ahern,  Ellen  Lapson,  and  Branko  Terzic.  "Standard  &  Poor's."  Regulated  Utilites:  Access  to  Capital.  Deloitte,  May  2013.    36    See  Kind,  Peter.  Disruptive  Challenges:  Financial  Implications  and  Strategic  Responses  to  a  Changing  Retail  Electric  Business.  White  Paper,  Washington:  Edison  Electric  Institute,  2013,  (11,  13).    37    See  U.S.  Energy  Information  Administration.  Electricty  Explained:  Use  of  Electricity.  April  26,  2012.  http://www.eia.gov/energyexplained/index.cfm?page=electricity_use  (accessed  April  9,  2014)  and  Martin,  Laura.  Implications  of  low  electricity  demand  growth.  Annual  Energy  Outlook  2014,  Washington:  U.S.  Energy  Information  Administration,  2014.    38    See  Denning,  Liam.  Lights  Flicker  for  Utilities.  December  22,  2013.  http://online.wsj.com/news/articles/SB10001424052702304773104579270362739732266  (accessed  March  31,  2014).    

                                                                                                                                                                                                                                                                                                                                                                                         39    See  Marcacci,  Silvio.  Fitch  Ratings:  Net  Metering  Can  Destabilize  Entire  Utility  Industry.  December  27,  2013.  http://theenergycollective.com/silviomarcacci/321161/fitch-­‐ratings-­‐net-­‐metering-­‐can-­‐destabilize-­‐entire-­‐utility-­‐industry  (accessed  April  10,  2014).    40    See  Edison  Electric  Institute.  Straight  Talk  About  Net  Metering.  Washington:  Edison  Electric  Institute,  (1).    41    The  avoided  cost  of  generation  is  the  “incremental  costs  of  electric  energy  or  other  services,  if  a  utility  did  not  purchase  from  the  existing  power  seller;  the  focus  is  on  the  cost  of  the  alternatives  available  to  the  buyer/utility.”  See  National  Renewable  Energy  Laboratory.  (2013).  Treatment  of  Solar  Generation  in  Electric  Utility  Resource  Planning.  Golden:  NREL,  (46).    42    See  Union  of  Concerned  Scientists.  (n.d.).  Public  Utilities  Regulatory  Policies  Act  (PURPA).  Retrieved  April  10,  2014,  from  Union  of  Concerned  Scientists:  http://www.ucsusa.org/clean_energy/smart-­‐energy-­‐solutions/strengthen-­‐policy/public-­‐utility-­‐regulatory.html.    43    The  retail  electricity  rate  is  the  “final  rate  charged  to  customers  by  an  electricity  company,  based  on  all  of  the  costs  involved  in  generating,  transporting,  and  delivering  power.”  As  such,  it  “includes  not  only  the  cost  of  power  but  also  the  fixed  costs  of  the  poles,  wires,  meters,  advanced  technologies,  and  other  infrastructure  that  make  the  electric  grid  safe,  reliable,  and  able  to  accommodate  solar  panels  and  other  DG  systems.”  Generation  facilities  that  are  connected  “behind-­‐the-­‐meter”,  such  as  residential  distributed  solar  PV  systems,  sell  their  electricity  into  a  retail  market  rather  than  the  wholesale  market.    The  wholesale  electricity  rate  includes  the  cost  of  the  fuel  required  to  generate  electricity  and  the  cost  of  purchasing  power  on  the  competitive  wholesale  electricity  market.  Unlike  the  retail  electricity  rate,  the  wholesale  electricity  rate  does  not  include  the  cost  of  transporting  and  delivering  electricity  through  the  grid  to  customers.  The  utility  industry  maintains  that,  as  the  solar  panels  are  producing  power  directly  into  the  distribution  system  (hence  the  nomenclature  “distributed”  generation),  they  should  be  compensated  at  the  wholesale  rate  and  not  the  retail  rate.  See  Kind,  Peter.  Disruptive  Challenges:  Financial  Implications  and  Strategic  Responses  to  a  Changing  Retail  Electric  Business.  White  Paper,  Washington:  Edison  Electric  Institute,  2013,  (1,  2).    44    See  Edison  Electric  Institute.  Straight  Talk  About  Net  Metering.  Washington:  Edison  Electric  Institute,  (2)  and  Edison  Electric  Institute.  (2014).  EEI  Comments  on  Value  and  Cost  of  Distributed  Generation  (Including  Net  Metering)  E-­‐00000J-­‐14-­‐0023.  Phoeniz:  EEI,  (5).    45    See  Parkinson,  Giles.  Rooftop  Solar:  Does  it  really  need  the  grid?  April  23,  2014.  http://reneweconomy.com.au/wp-­‐content/uploads/2014/04/bernstein-­‐solar-­‐day.jpg  (accessed  April  25,  2014).    46    For  motor-­‐based  devices,  startup  power  can  be  orders  of  magnitude  higher  than  the  power  that  is  consumed  during  normal  running  operation.      47    See  Electric  Power  Research  Institute.  (2014).  The  Integrated  Grid:  Realizing  the  Full  Value  of  Central  and  Distributed  Energy  Resources.  Palo  Alto:  EPRI,  (16,  23).    48    See  Solar  Energy  Industries  Association.  Rate  Design  Guiding  Principles  for  Solar  Distributed  Generation.  Washington:  SEIA,  (1).    49    See  Keyes,  J.  B.,  &  Rabago,  K.  R.  (2013).  A  Regulator's  Guidebook:  Calculating  the  Benefits  and  Costs  of  Distributed  Solar  Generation.  Latham:  Interstate  Renewable  Energy  Council,  (36).    50    EEI  notes,  “Lost  revenues  from  distributed  energy  resources  are  being  recovered  from  non-­‐distributed  energy  resource  customers  in  order  to  encourage  distributed  generation  implementation.  This  type  of  lost  revenue  recovery  drives  up  prices  of  those  non-­‐participating  customers  and  leads  to  higher  rates  of  customer  loss.”  See  Kind,  Peter.  Disruptive  Challenges:  Financial  Implications  and  Strategic  Responses  to  a  Changing  Retail  Electric  Business.  White  Paper,  Washington:  Edison  Electric  Institute,  2013,  (5,  13,  17).    

                                                                                                                                                                                                                                                                                                                                                                                         51    Furthermore,  the  study  found  that  net  benefits,  either  positive  or  negative,  depend  on  the  discount  rate  chosen  and  whether  non-­‐internalized  greenhouse  gas  emissions  are  considered  in  the  analysis,  particularly  if  these  costs  are  assumed  to  be  stagnant  in  the  longer  term  (i.e.  for  up  to  20  years).  See  Vermont  Public  Service  Department.  (2013).  Evaluation  of  Net  Metering  in  Vermont  Conducted  Pursuant  to  Act  125  of  2012.  Montpelier:  Vermont  Public  Service  Department,  (31).    52    See  Denning,  L.  (2013,  December  22).  Lights  Flicker  for  Utilities.  Retrieved  March  31,  2014,  from  http://online.wsj.com/news/articles/SB10001424052702304773104579270362739732266.    53    See  Edison  Electric  Institute.  (2014).  EEI  Comments  on  Value  and  Cost  of  Distributed  Generation  (Including  Net  Metering)  E-­‐00000J-­‐14-­‐0023.  Phoeniz:  EEI,  (3-­‐5).    54    The  next  marginal  generator  in  the  merit  order  would  likely  be  a  natural  gas  combined-­‐cycle  combustion  turbine.      55    See  Keyes,  J.  B.,  &  Rabago,  K.  R.  (2013).  A  Regulator's  Guidebook:  Calculating  the  Benefits  and  Costs  of  Distributed  Solar  Generation.  Latham:  Interstate  Renewable  Energy  Council,  (21,  36).    56    As  the  authors  note:  “Considering  losses  on  a  marginal  basis…reflects  the  likely  correlation  of  solar  PV  to  heavy  loading  periods  where  congestion  and  transformer  thermal  conditions  tend  to  exacerbate  losses.”  In  this  arrangement,  the  use  of  transformers  to  step-­‐up  voltage  for  long-­‐range  transmission  is  obviated,  decreasing  marginal  loss  rates,  reducing  the  utility’s  peak  load,  generation  capacity,  and  ultimately  lowering  customer  rates.  Ibid,  (23).      57    The  capacity  credit  assigned  to  a  generator  is  related  to  its  effective  load  carrying  capability  (ELCC).  ELCC  is  “the  ability  of  a  power  generator  to  support  additional  peak  load  without  reducing  the  reliability  of  the  electrical  system  (in  terms  of  loss  of  load  probability  or  loss  of  load  expectation).”  See  National  Renewable  Energy  Laboratory.  (2013).  Treatment  of  Solar  Generation  in  Electric  Utility  Resource  Planning.  Golden:  NREL,  (47).  If  the  distributed  solar  panel’s  output  has  high  coincidence  with  a  utility’s  peak  demand,  the  panel  will  earn  a  high  capacity  credit.  Conversely,  the  panel  would  receive  a  lower  capacity  credit  when  demand  is  low.  Strictly  speaking,  the  capacity  credit  can  be  calculated  as  “the  capital  cost  ($/MWh)  of  the  displaced  unit  times  the  effective  capacity  provided  by  PV.”  For  a  more  complete  explanation  of  capacity  credit  and  ELCC,  see  Keyes,  J.  B.,  &  Rabago,  K.  R.  (2013).  A  Regulator's  Guidebook:  Calculating  the  Benefits  and  Costs  of  Distributed  Solar  Generation.  Latham:  Interstate  Renewable  Energy  Council,  (24-­‐26).    58    The  study  pointed  out  the  ability  for  distributed  solar  PV  to  reduce  absolute  peak  utility  load,  and  in  the  process  avoid  overloading  transformers  and  distribution  system  components.  Furthermore,  aggregation  of  distributed  solar  PV  systems  on  a  circuit,  per  interconnection  procedures,  would  obviate  transmission  system  upgrades  by  reducing  the  need  to  service  these  circuits.  Ibid,  (26-­‐28).  That  being  said,  prediction  of  any  transmission  and  distribution  deferment  is  complicated  and  unlikely  to  be  incorporated  into  any  rate-­‐setting  studies.      59    Ibid  (29-­‐30).  While  many  states  at  the  moment  lack  a  centralized  market  for  ancillary  services,  FERC  Order  784  may  open  the  door  for  storage  systems,  and  potential  distributed  solar  PV  systems,  to  participate  in  these  markets  in  the  future  by  requiring  transmission-­‐owning  utilities  to  consider  the  “speed  and  accuracy”  of  resources  providing  ancillary  services.  See  NRDC  Switchboard.  FERC  Affirms  Support  for  Removing  Market  Barriers  to  Energy  Storage,  Other  Clean  Energy  Resources.  February  28,  2014.  http://theenergycollective.com/nrdcswitchboard/346136/ferc-­‐affirms-­‐support-­‐removing-­‐market-­‐barriers-­‐energy-­‐storage-­‐other-­‐clean-­‐ener  (accessed  April  28,  2014).    60    The  inclusion  of  a  fuel  hedge  is  complicated  by  the  assumed  volatility  of  the  price  of  the  fuel  used  in  the  generating  units  in  a  utility’s  portfolio.  Some  utilities,  on  the  other  hand,  have  a  long-­‐term  contract  to  purchase  fuel  at  a  fixed  price.  See  Keyes,  Jason  B.,  and  Karl  R.  Rabago.  A  Regulator's  Guidebook:  Calculating  the  Benefits  and  Costs  of  Distributed  Solar  Generation.  Latham:  Interstate  Renewable  Energy  Council,  2013,  (30).  

                                                                                                                                                                                                                                                                                                                                                                                           61    An  exact  valuation  of  the  cost  reductions  is  hypothetical  at  best,  and  therefore  must  be  modeled.  Ibid,  (31).      62    Ibid.    63    The  authors  note  that  the  societal  benefits  could  include  avoided  water  usage  and  local  economic  development  through  construction  and  locally-­‐circulated  tax  revenue;  environmental  benefits  include  avoided  carbon  emissions  from  fossil  fuel  power  plants,  avoided  renewable  portfolio  standard  compliance  costs,  and  reduced  costs  of  complying  with  various  regulatory  and  statutory  environmental  regulations  (such  as  stipulations  on  airborne  pollutants  and  air  quality  pursuant  to  the  Clean  Air  Act  of  1970).  Ibid,  (32-­‐35).  In  June  2014,  the  EPA  proposed  the  Clean  Power  Plan  Proposed  Rule  aimed  at  “maintaining  an  affordable,  reliable  energy  system,  while  cutting  pollution  and  protecting  our  health  and  environment”  by  lowering  the  carbon  intensity  of  existing  power  plants  in  the  U.S.  The  Proposed  Rule  serves  as  a  compliment  to  the  rule  for  new  power  plants  unveiled  in  early  2014.  See  Environmental  Protection  Agency.  Carbon  Pollution  Emission  Guidelines  for  Existing  Stationary  Sources:  Electric  Utility  Generating  Units.  Proposed  Rule,  Washington:  Federal  Register,  2014.      64    See  Solar  Energy  Industries  Association.  (n.d.).  Net  Energy  Metering  Guiding  Principles.  Retrieved  April  10,  2014,  from  Research  &  Resources:  http://www.seia.org/research-­‐resources/net-­‐energy-­‐metering-­‐guiding-­‐principles.    65    See  Solar  Energy  Industries  Association.  Rate  Design  Guiding  Principles  for  Solar  Distributed  Generation.  Washington:  SEIA,  (1).    66    See  Solar  Energy  Industries  Association.  (n.d.).  Net  Energy  Metering  Guiding  Principles.  Retrieved  April  10,  2014,  from  Research  &  Resources:  http://www.seia.org/research-­‐resources/net-­‐energy-­‐metering-­‐guiding-­‐principles.    67    “Utility  ratemaking  (and  other  regulatory  policies)  should  strive  to  minimize  negative  externalities.”  See  Solar  Energy  Industries  Association.  Rate  Design  Guiding  Principles  for  Solar  Distributed  Generation.  Washington:  SEIA,  (2).    68    In  its  comments  to  the  Arizona  Corporation  Commission  in  February  2014  pursuant  to  their  evaluation  of  distributed  generation  and  NEM,  EEI  asserted  that,  “…”value”  of  service  propositions  are  inherently  uncertain  and  speculative,”  and  that  no  consideration  of  environmental  or  societal  externalities  should  be  considered  in  rate-­‐setting  for  distributed  solar  PV  generation.  See  Edison  Electric  Institute.  (2014).  EEI  Comments  on  Value  and  Cost  of  Distributed  Generation  (Including  Net  Metering)  E-­‐00000J-­‐14-­‐0023.  Phoeniz:  EEI.    69    See  Solar  Energy  Industries  Association.  Rate  Design  Guiding  Principles  for  Solar  Distributed  Generation.  Washington:  SEIA,  (2).    70    See  Edison  Electric  Institute.  (2014).  EEI  Comments  on  Value  and  Cost  of  Distributed  Generation  (Including  Net  Metering)  E-­‐00000J-­‐14-­‐0023.  Phoeniz:  EEI.    71    See  National  Renewable  Energy  Laboratory.  (2013).  Treatment  of  Solar  Generation  in  Electric  Utility  Resource  Planning.  Golden:  NREL,  (v,  4).    72    One  of  the  aims  of  the  IRP  structure  is  to  minimize  total  costs,  not  simply  the  average  rates  incident  on  customers.  Moreover,  “equity  necessitates  the  additional  balancing  of  the  interests  of  the  various  customer  classes  as  well  as  the  interests  of  present  and  future  generations.”  A  robust  IRP  would  evaluate  the  full  suite  of  options  available  to  meet  forecasted  load  demand,  including:  power  purchases,  renewable  energy  resources,  demand-­‐side  management  strategies/programs,  cogeneration,  and  independent  power  plants.  See  Kushler,  Marty,  and  Dan  York.  Utility  Initiatives:  Integrated  Resource  Planning.  Policy  Brief,  Washington:  American  Council  for  an  Energy-­‐Efficient  Economy,  2010.  Most  IRPs  involve  six  steps:  

1. An  evaluation  of  state  policies  and  mandates;  

                                                                                                                                                                                                                                                                                                                                                                                         2. A  review  of  the  existing  generation  fleet  in  the  utility’s  portfolio;  3. A  forecast  of  load  demand  (with  built-­‐in  flexibility  to  prepare  for  unexpected  demand  growth  or  

decline);  4. Plans  for  capacity  expansion  to  meet  predicted  increases  in  load;  5. Production-­‐cost  modeling;  and  6. A  select  portfolio  based  on  metrics  such  as  revenue  requirements,  capital  expenditures,  water  usage,  

emissions,  average  system  cost,  and  fuel  diversity.  See  National  Renewable  Energy  Laboratory.  (2013).  Treatment  of  Solar  Generation  in  Electric  Utility  Resource  Planning.  Golden:  NREL,  (vi-­‐vii).    73    Ibid,  (4);  and  See  Kushler,  Marty,  and  Dan  York.  Utility  Initiatives:  Integrated  Resource  Planning.  Policy  Brief,  Washington:  American  Council  for  an  Energy-­‐Efficient  Economy,  2010.    74    See  Rosenbaum,  Eric.  A  dirty  clean  energy  battle  becoming  a  utility  war.  March  6,  2014.  http://www.cnbc.com/id/101472289  (accessed  April  10,  2014).    75    See  National  Renewable  Energy  Laboratory.  (2013).  Treatment  of  Solar  Generation  in  Electric  Utility  Resource  Planning.  Golden:  NREL,  (25).    76    See  Rosenbaum,  Eric.  A  dirty  clean  energy  battle  becoming  a  utility  war.  March  6,  2014.  http://www.cnbc.com/id/101472289  (accessed  April  10,  2014).    77    See  Sklar,  Scott.  Utility  Nightmares:  Distributed  Generation  and  Halving  Electricity  Consumption.  April  16,  2014.  http://www.renewableenergyworld.com/rea/news/article/2014/04/utility-­‐nightmares-­‐halving-­‐electricity-­‐consumption-­‐and-­‐distributed-­‐generation  (accessed  April  28,  2014).      78    See  National  Renewable  Energy  Laboratory.  (2013).  Treatment  of  Solar  Generation  in  Electric  Utility  Resource  Planning.  Golden:  NREL,  (18).  EEI  advocates  “revision(s)  of  NEM  programs  in  all  states  so  that  self-­‐generated  distributed  energy  resource  sales  to  utilities  are  treated  as  supply-­‐side  purchases  at  a  market-­‐derived  price.  From  a  load  provider’s  perspective,  this  would  support  the  adoption  of  distributed  resources  on  economically  driven  bases,  as  opposed  to  being  incentivized  by  cross  subsidies.”  See  Kind,  Peter.  Disruptive  Challenges:  Financial  Implications  and  Strategic  Responses  to  a  Changing  Retail  Electric  Business.  White  Paper,  Washington:  Edison  Electric  Institute,  2013,  (18).    79    Because  solar  is  an  intermittent  resource,  if  the  utility  seeks  to  meet  its  future  load  demand  needs  with  greater  build-­‐outs  of  solar,  it  may  risk  over-­‐building  its  capacity  due  to  the  mismatch  of  solar  output  and  system  load  profiles.  See  National  Renewable  Energy  Laboratory.  (2013).  Treatment  of  Solar  Generation  in  Electric  Utility  Resource  Planning.  Golden:  NREL,  (34,  5).    80    The  analysis  notes,  “One  risk  associated  with  solar  generation  without  storage  is  adequately  integrating  its  production  fluctuations  into  the  overall  resource  mix”  (most  estimates  from  the  questionnaires  were  in  the  $2-­‐$11/MWh  range).  33%  of  utilities  do  not  incorporate  an  integration  cost  adder  for  solar  resources,  while  10%  say  that  they  do  not  at  present  but  plan  on  adding  one  into  the  next  IRP  process.  The  remaining  57%  do  not  and  do  not  plan  to  include  an  adder  for  solar.  Ibid,  (vii,  25,  67).    81    See  Electric  Power  Research  Institute.  (2014).  The  Integrated  Grid:  Realizing  the  Full  Value  of  Central  and  Distributed  Energy  Resources.  Palo  Alto:  EPRI,  (10).    82    See  Greentech  Media  Staff.  (2014,  April  8).  Enphase  CEO  on  Solar  Growth  Markets  and  New  Microinverter  Features.  Retrieved  April  14,  2014,  from  Greentech  Solar:  http://www.greentechmedia.com/articles/read/Enphase-­‐CEO-­‐on-­‐Solar-­‐Growth-­‐Markets-­‐and-­‐New-­‐Microinverter-­‐Features.    GTM  Research  noted  that  distributed  solar  PV  could  become  technically-­‐disruptive  to  grid  reliability  at  levels  of  20-­‐25%  of  total  power,  or  at  a  point  where  capacity  equals  25%  of  daytime  minimum  load  demand  on  a  particular  distribution  feeder.  See  Munsell,  Mike.  3  Solar  Integration  Questions  Utility  Executives  Must  

                                                                                                                                                                                                                                                                                                                                                                                         Confront.  April  28,  2014.  http://www.greentechmedia.com/articles/read/three-­‐questions-­‐utility-­‐executives-­‐will-­‐face-­‐regarding-­‐pv-­‐integration  (accessed  April  28,  2014).  It  has  been  noted  that  the  some  of  the  benefits  of  distributed  solar  PV  resources,  such  as  capacity  credit  attributed  to  the  solar  generating  units,  are  reduced  as  the  penetration  of  this  technology  eclipses  a  certain  level  (i.e.  15%  of  generation  capacity).  See  Keyes,  J.  B.,  &  Rabago,  K.  R.  (2013).  A  Regulator's  Guidebook:  Calculating  the  Benefits  and  Costs  of  Distributed  Solar  Generation.  Latham:  Interstate  Renewable  Energy  Council,  (41).    83    Electrical  feeders  are  parts  of  the  primary  distribution  system;  they  “run  along  the  streets  and  supply  the  distribution  transformers  that  step  the  voltage  down  to  the  secondary  level”  for  distribution  to  residential  and  commercial  users.  See  Karady,  G.  G.  (1997).  Energy  Distribution.  In  R.  C.  Dorf,  The  Electrical  Engineering  Handbook,  Second  Edition  (pp.  1435-­‐1445).  Boca  Raton:  CRC  Press  LLC,  (1435).  Connection  of  residential  solar  PV  systems  at  the  low  voltages  seen  in  the  distribution  system  is  the  industry  standard  due  to  the  proximity  to  residential  electrical  loads  (on-­‐site  consumption)  and  the  increased  costs  of  connecting  to  higher  voltage  levels  (due  to  the  increased  costs  of  transformers  and  switchgears  and  the  need  for  longer  transmission  lines  to  connect  to  the  existing  network).  See  Freris,  L.,  &  Infield,  D.  (2008).  Renewable  Energy  in  Power  Systems.  Chichester:  John  Wiley  &  Sons,  Ltd,  (177).    84    Distributed  solar  resources  are  connected  to  the  grid  through  inverters:  these  “brains”  of  the  solar  PV  system  provide  the  interface  between  the  electricity  grid,  the  PV  system,  and  the  utility.  In  addition  to  their  ability  to  facilitate  the  conversion  of  DC-­‐produced  electricity  to  the  AC  waveform  needed  for  transmission  and  distribution,  inverters  also  enable  the  crucial  bi-­‐directional  communication  capabilities  between  the  solar  system  and  the  utility  required  for  a  well-­‐functioning  electricity  grid.  See  Greentech  Media  Staff.  (2014,  April  8).  Enphase  CEO  on  Solar  Growth  Markets  and  New  Microinverter  Features.  Retrieved  April  14,  2014,  from  Greentech  Solar:  http://www.greentechmedia.com/articles/read/Enphase-­‐CEO-­‐on-­‐Solar-­‐Growth-­‐Markets-­‐and-­‐New-­‐Microinverter-­‐Features.      85    See  Smart  Inverter  Working  Group.  (2014).  Recommendations  for  Updating  the  Technical  Requirements  for  Inverters  in  Distributed  Energy  Resources.  Sacramento:  Smart  Inverter  Working  Group,  (9).    86    The  point  of  common  coupling  (PCC)  is  the  closest  point  on  the  distribution  network  where  a  customer  with  a  load  demand  is  or  could  be  located.  See  Freris,  L.,  &  Infield,  D.  (2008).  Renewable  Energy  in  Power  Systems.  Chichester:  John  Wiley  &  Sons,  Ltd,  (176).    87    Ibid;  and  See  Electric  Power  Research  Institute.  (2014).  The  Integrated  Grid:  Realizing  the  Full  Value  of  Central  and  Distributed  Energy  Resources.  Palo  Alto:  EPRI,  (13).        88    Frequency  can  be  understood  as  an  instantaneous  measure  of  the  imbalance  between  the  supply  of  electricity  and  the  demand  at  various  load  points  on  the  network.  If  frequency  drifts  downward,  demand  for  electricity  exceeds  supply,  and  vice  versa.  In  the  case  of  distributed  solar  PV  resources,  it  is  likely  that  electricity  production  from  the  systems  exceeds  the  demand,  creating  the  possibility  that  the  frequency  may  rise  to  values  outside  of  the  acceptable  range.  The  setting  of  exact  frequency  operating  envelope  is  in  the  purview  of  distribution  system  operators,  although  individual  utilities  may  set  their  own,  stricter  limits  on  frequency  variation.  Ibid,  (15);  and  See  Freris,  L.,  &  Infield,  D.  (2008).  Renewable  Energy  in  Power  Systems.  Chichester:  John  Wiley  &  Sons,  Ltd,  (56).    89    As  the  frequency  begins  to  drift  downwards  due  to  a  shortfall  in  electricity  supply,  for  example,  large  rotating  machines,  hallmarks  of  centralized  generation,  are  able  to  supply  inertia  to  soften  the  destabilizing  effects  of  frequency  dips.  The  inertial  qualities  of  large  rotating  machines,  which  are  important  for  maintaining  voltage  control  and  dynamic  behavior  of  generation  units,  are  often  absent  in  inverter-­‐based  generation  units.  See  Freris,  L.,  &  Infield,  D.  (2008).  Renewable  Energy  in  Power  Systems.  Chichester:  John  Wiley  &  Sons,  Ltd,  (87-­‐88)  and  Electric  Power  Research  Institute.  (2014).  The  Integrated  Grid:  Realizing  the  Full  Value  of  Central  and  Distributed  Energy  Resources.  Palo  Alto:  EPRI,  (13).        

                                                                                                                                                                                                                                                                                                                                                                                         90    Germany  was  faced  with  these  challenges  which  ultimately  necessitated  an  upgrade  to  all  inverters  with  capacities  greater  than  3.68  kilo  volt-­‐amperes  (kVA).  The  upgrades  are  estimated  to  cost  over  $300  million.  Ibid,  (15).    91    A  load  profile  recorded  on  March  18,  2014,  reproduced  below  in  Figure  A.4,  illustrates  that  the  state  may  already  be  experiencing  the  early  stages  of  a  possible  “duck  curve”:    

 

Figure  A.4:  Load  curve  in  California,  recorded  on  March  18,  2014    

See  Wesoff,  Eric.  Slideshow:  Solar  Disrupting  Wholesale  Energy  Markets.  April  16,  2014.  http://www.greentechmedia.com/articles/read/Slideshow-­‐Solar-­‐Disrupting-­‐Wholesale-­‐Energy-­‐Markets  (accessed  April  25,  2014).    92    Cool  days  reduce  the  need  for  air  conditioning  (a  high-­‐demand  appliance/service);  the  mid-­‐afternoon  period  is,  on  a  workday,  generally  one  of  the  lowest  demand  periods  of  the  day.    93    Baseload  resources  are  those  that  contribute  to  the  portion  of  the  electricity  demand  load  that  is  always  present.  Baseload  resources  are  usually  incapable  of  responding  in  timeframes  shorter  than  a  few  hours.  See  Freris,  L.,  &  Infield,  D.  (2008).  Renewable  Energy  in  Power  Systems.  Chichester:  John  Wiley  &  Sons,  Ltd,  (22).    94    John,  J.  S.  (2014,  March  24).  Retired  CPUC  Commissioner  Takes  Aim  at  CAISO's  Duck  Curve.  Retrieved  April  10,  2014,  from  GreentechGrid:  http://www.greentechmedia.com/articles/read/retired-­‐cpuc-­‐commissioner-­‐takes-­‐aim-­‐at-­‐caisos-­‐duck-­‐curve.    95    2020  is  the  deadline  for  implementation  of  California’s  mandate  to  procure  33%  of  its  electricity  demand  from  renewable  sources,  and  as  such  represents  a  period  of  high  distributed  generation  penetration.      96    See  The  Clean  Coalition.  (2013,  December  16).  Flattening  the  Duck:  Dynamic  Grid  Solutions  for  Integrating  Renewables.  The  Clean  Coalition.    97    See  Lazar,  J.  (2014).  Teaching  the  "Duck"  to  Fly.  Montpelier:  The  Regulatory  Assistance  Project,  (1).    98    See  The  Clean  Coalition.  (2013,  December  16).  Flattening  the  Duck:  Dynamic  Grid  Solutions  for  Integrating  Renewables.  The  Clean  Coalition.    99    The  Clean  Coalition’s  study,  Flattening  the  Duck:  Dynamic  Grid  Solutions  for  Integrating  Renewables,  proposed  the  following  strategies:  

                                                                                                                                                                                                                                                                                                                                                                                         1. Strategically  schedule  the  O&M  of  baseload  power  plants  in  a  given  utility’s  portfolio  during  the  

shoulder  months  (i.e.  months  when  power  plants  are  typically  shut  down  for  periods  of  O&M)  to  limit  the  effects  of  over-­‐generation;  

2. Instigate  DSM  programs  that  shift  consumption  from  high-­‐demand  periods  to  periods  of  lower  demand,  with  a  concomitant  emphasis  on  informing  policymakers  as  to  which  DSM  programs  and  resources  could  be  used  to  address  the  need  for  innovative  pricing  schedules  that  incentivize  customer  participation.  Some  of  these  strategies  could  involve  use  of  electrical  vehicle  batteries  as  storage  devices;  and  

3. Curtail  solar  generation  during  periods  of  potential  over-­‐generation.  Figure  A.5  shows  the  resultant  change  in  load  profile  with  these  three  strategies;  the  bolded  red  line  is  the  load  profile  after  the  three  strategies  are  implemented:    

 

Figure  A.5:    Utility  load  profile  before  and  after  implementation  of  The  Clean  Coalition’s  strategies    See  The  Clean  Coalition.  (2013,  December  16).  Flattening  the  Duck:  Dynamic  Grid  Solutions  for  Integrating  Renewables.  The  Clean  Coalition.  The  strategy  advocated  by  The  Regulatory  Assistance  Project  (RAP)  doesn’t  evolve  any  curtailment  of  distributed  solar  resources  on  the  part  of  grid  operators.  They  suggested  ten  strategies:  

1. Target  energy  efficiency  programs  to  the  hours  around  the  ramp-­‐up.  RAP’s  modeling  indicated  that  this  strategy  could  save  5%  of  total  electricity  usage  during  the  targeted  peak  hours.  

2. Orient  solar  panels  on  residential  roofs  towards  the  west,  shifting  their  peak  electricity  production  periods  to  later  in  the  day.  Although  solar  panels  maximize  output  when  oriented  towards  the  south,  western-­‐orientation  helps  to  align  their  generation  profiles  with  the  utility  load  profile  (i.e.  maximum  generation  closer  to  the  ramp-­‐up  period).    

3. Divert  some  of  the  production  from  the  distributed  solar  PV  systems  during  periods  of  low  demand  to  heat  water.  This  use  of  solar  PV  as  a  solar  thermal  resource  provides  an  opportunity  for  the  heated  water  to  serve  as  a  storage  tool  for  the  evening  ramp-­‐up.  

4. Update  service  standards  so  that  grid  operators  are  allowed  to  deploy  the  roughly  45  million  electric  water  heaters  in  the  U.S.  to  reduce  peak  demand  (“shave  demand”).  

5. Utilize  ice  and  chilled  water  as  storage  by  pre-­‐chilling  the  fluid  in  air  conditioning  and  cooling  systems  when  distributed  solar  PV  generation  is  prevalent  and  discharging  the  cooling  in  the  high-­‐demand,  early  evening  period.  This  strategy  would  in  effect  require  air  conditioning  units  and  cooling  systems  to  include  two  hours  of  thermal  storage.  

6. Retire  older,  more  inflexible  generating  plants,  such  as  older  coal,  nuclear,  and  gas  steam  units.  7. Target  demand  charges  during  the  ramp-­‐up  periods.  Demand  charges  were  instituted  when  the  utility  

generation  fleet  was  characterized  by  similar  cost  levels  across  all  types  of  capacity;  they  were  employed  to  ensure  that  commercial  and  industrial  customers  with  lower-­‐than-­‐average  consumption  

                                                                                                                                                                                                                                                                                                                                                                                         paid  a  higher  price  relative  to  users  with  higher  demand  to  encourage  all  users  to  improve  their  load  factors  (the  ratio  of  average  electricity  consumption  to  peak  electricity  usage).  

8. Strategic  placement  of  electrical  energy  storage  in  targeted  locations,  such  as  those  that  would  require  expensive  transmission  and  distribution  system  upgrades  in  response  to  increased  generation  from  distributed  solar  PV  resources,  by  utilizing  the  storage  devices  to  reduce  over-­‐generation  during  ramp-­‐down  or  provide  electricity  during  ramp-­‐up  periods.  Placement  of  storage  systems  in  these  locations  would  also  open  up  the  opportunity  for  the  provision  of  ancillary  services  to  the  electricity  grid.    

9. Implementation  of  aggressive  demand-­‐response  programs,  such  as  those  that  encourage  customers  to  change  their  electricity-­‐use  patterns.    

10. Use  of  inter-­‐regional  power  exchanges  with  neighboring  states  to  employ  diversity  of  load  and  resources.  This  strategy  utilizes  the  geographic  diversity  of  renewable  energy  resources,  both  distributed  and  other,  as  a  means  of  smoothing  out  generation  profiles.  Although  the  analysis  focused  on  California,  almost  any  state  in  the  contiguous  U.S.  would  be  able  to  engage  in  some  form  of  regional  power  exchange.      

Figure  A.6  shows  the  resultant  change  in  load  profile  with  these  ten  strategies;  the  convention  total  load  refers  to  the  situation  with  no  renewable  energy  resources  included,  while  net  load  refers  to  the  total  load  less  the  input  from  renewable  energy  resources:    

 

Figure  A.6:  Utility  load  profile  before  and  after  implementation  of  RAP’s  strategies    RAP’s  model  incorporating  all  ten  strategies  highlighted  above  showed  that  the  load  factor  was  improved  (i.e.  the  discrepancy  between  average  usage  and  peak  usage  decreased),  the  maximum  hourly  ramp  rate  was  decreased  from  500MW  to  350MW,  and  the  total  difference  between  highest  and  lowest  demand  was  reduced  from  1800MW  to  950MW.  See  Lazar,  J.  (2014).  Teaching  the  "Duck"  to  Fly.  Montpelier:  The  Regulatory  Assistance  Project,  (1-­‐22).    100    California  has  over  47,100  people  employed  in  the  solar  energy  sector.  See  Solar  Energy  Industries  Association.  2013  Top  10  Solar  States.  2014.  http://www.seia.org/sites/default/files/resources/Top-­‐10-­‐Solar-­‐States-­‐Infographic.pdf  (accessed  April  15,  2014).    101    See  Miller,  Peter.  Celebrating  a  Solar  Energy  Milestone  with  Big  Clean  Energy  Implications.  March  31,  2014.  http://theenergycollective.com/nrdcswitchboard/361211/celebrating-­‐solar-­‐milestone-­‐big-­‐clean-­‐energy-­‐implications  (accessed  April  15,  2014).  

                                                                                                                                                                                                                                                                                                                                                                                           102    See  Energy  Information  Agency.  Electricity  Monthly  Update:  Solar-­‐electric  Generating  Capacity  Increases  Drastically  in  the  Last  Four  Years.  April  22,  2014.  http://www.eia.gov/electricity/monthly/update/  (accessed  April  29,  2014).    103    See  California  Public  Utilities  Commission.  Decision  Establishing  a  Transition  Period  Pursuant  to  Assembly  Bill  327  For  Customers  Enrolled  in  Net  Energy  Metering  Tariffs.  Proposed  Decision,  San  Francisco:  California  Public  Utilities  Commission,  2014,  (2-­‐3).    104    See  Trabish,  Herman.  Solar  Energy  Usage  Shattering  Records  in  California  as  New  Capacity  Comes  On-­‐Line.  March  22,  2014.  http://theenergycollective.com/hermantrabish/356771/solar-­‐usage-­‐shattering-­‐records-­‐california-­‐new-­‐capacity-­‐comes-­‐line  (accessed  April  15,  2014).    105    See  California  Public  Utilities  Commission.  Order  Instituting  Rulemaking  to  Continue  Implementation  and  Administration  of  California  Renewables  Portfolio  Standard  Program,  Rulemaking  11-­‐05-­‐005.  Decision  11-­‐12-­‐020,  San  Francisco:  California  Public  Utilities  Commission,  2011,  (2-­‐3).    106    The  program  continued  the  momentum  started  with  the  state’s  Emerging  Renewables  Program  and  the  Self-­‐Generation  Incentive  Program  (two  programs  which  no  longer  provide  investment  support  for  distributed  solar  PV  systems).  The  incentives  provided  within  the  program  are  demand-­‐driven  and  designed  to  step-­‐down  in  line  with  expected  cost  declines  of  solar  PV  systems  and  the  local  solar  market  conditions.  See  California  Public  Utilities  Commission.  About  the  California  Solar  Initiative.  January  31,  2014.  http://www.cpuc.ca.gov/puc/energy/solar/aboutsolar.htm  (accessed  April  15,  2014).  The  CSI  program  also  provides  a  rebate  system  for  low-­‐income  residents  who  own  their  single-­‐family  homes.  See  California  Solar  Initiative.  About  the  California  Solar  Initiative  (CSI).  2013.  http://www.gosolarcalifornia.ca.gov/about/csi.php  (accessed  April  15,  2014).    107    Ibid.    108    See  California  Public  Utilities  Commission.  Self-­‐Generation  Incentive  Program.  http://www.cpuc.ca.gov/PUC/energy/DistGen/sgip/  (accessed  April  15,  2014).    109    See  Solar  Energy  Industries  Assocation.  U.S.  Solar  Market  Insight  Report:  2013  Year-­‐In-­‐Review  Executive  Summary.  Review,  Washington:  Solar  Energy  Industries  Assocation,  2013,  (9).    110    See  Wesoff,  Eric.  Slideshow:  How  to  Really  Disrupt  the  Retail  Energy  Market  With  Solar.  April  17,  2014.  http://www.greentechmedia.com/articles/read/Slide-­‐Show-­‐How-­‐to-­‐Really-­‐Disrupt-­‐the-­‐Retail-­‐Energy-­‐Market-­‐with-­‐Solar  (accessed  April  17,  2014).    111    See  Solar  Energy  Industries  Association.  U.S.  Solar  Market  Insight  Report:  Q1  2014  Executive  Summary.  Executive  Summary,  SEIA,  2014,  available  at:  http://www.greentechmedia.com/research/ussmi,  (8).    112    See  California  Solar  Initiative.  Program  Totals  by  Administrator.  April  30,  2014.  http://www.californiasolarstatistics.ca.gov/reports/agency_stats/  (accessed  May  5,  2014).    113    See  Wesoff,  Eric,  and  Shayle  Kann.  Capital  Keeps  Pouring  Into  Booming  US  Residential  Solar  Market.  April  7,  2014.    114    See  Paulos,  Bentham.  Surpassing  Milestone  of  100,000  Solar  Roofs,  PG&E  Calls  for  'Sustainable'  Solar  Policy.  April  21,  2014.  http://www.greentechmedia.com/articles/read/pge-­‐hits-­‐100000-­‐solar-­‐roofs  (accessed  April  28,  2014).    115    The  study  also  noted  that  because  “rates  are  adjusted  over  time  such  that  utilities  meet  their  revenue  requirement,  this  revenue  reduction  ($1.1  billion  by  2020)  will  be  made  up  by  ratepayers.”  See  California  Public  Utilities  Commission  Energy  Division.  California  Net  Energy  Metering  (NEM)  Draft  Cost-­‐Effectiveness  Evaluation:  NEM  Study  Introduction.  San  Francisco:  CPUC,  2013,  (6,  42).  

                                                                                                                                                                                                                                                                                                                                                                                           116    See  Trabish,  Herman  K.  New  California  Net  Metering  Study  Appears  to  be  DOA.  September  30,  2013.  http://www.greentechmedia.com/articles/read/new-­‐california-­‐net-­‐metering-­‐study-­‐appears-­‐doa  (accessed  April  7,  2014).  The  CPUC  study  itself  noted:  “The  bill  savings  for  NEM  customers  are  entirely  a  function  of  the  retail  rate  designs  for  each  customer  class  and  utility…possible  changes  to  the  residential  rate  structure  could  have  significant  impacts  on  the  costs  associated  with  residential  NEM  generation.”  See  California  Public  Utilities  Commission  Energy  Division.  California  Net  Energy  Metering  (NEM)  Draft  Cost-­‐Effectiveness  Evaluation:  NEM  Study  Introduction.  San  Francisco:  CPUC,  2013,  (7-­‐8).    117    Solar  advocates  noted  that  an  abandonment  of  the  tiered-­‐pricing  schedule  would  erode  the  benefits  that  the  highest  electricity  consumers  (and  thus  those  who  pay  the  most  per  month  for  their  electricity)  enjoy  by  using  the  electricity  produced  from  distributed  solar  PV  systems  to  decrease  their  monthly  bills,  and  that  the  monthly  flat  charges  proposed  in  AB  327  would  add  costs,  they  argued,  to  each  customer’s  bill  that  no  amount  of  distributed  solar  PV  generation  could  reduce.  The  state’s  IOUs,  on  the  other  hand,  had  been  seeking  a  transition  period  from  NEM  to  some  other  form  of  compensation  based  on  the  “breakeven  point”,  or  the  point  where  the  average  customer  recoups  their  cost  of  investment  in  a  distributed  solar  PV  system.  See  John,  Jeff  St.  AB  327:  From  California  Solar  Killer  to  Net  Metering  Savior?  September  3,  2013.  http://www.greentechmedia.com/articles/read/ab-­‐327-­‐from-­‐california-­‐solar-­‐killer-­‐to-­‐net-­‐metering-­‐savior  (accessed  April  7,  2014).    118    The  amended  bill  addressed  uncertainty  regarding  how  each  IOU  would  calculate  its  individual  cap  on  the  level  of  NEM  generation.  The  amended  bill  established  a  5%  cap  of  each  IOU’s  nameplate  capacity  equivalent  to:  

1. 607MW  for  San  Diego  Gas  and  Electric  (SDG&E);  2. 2,240MW  for  SCE;  and  3. 2,409  for  PG&E  

The  bill  called  for  a  new  study  to  be  finished  by  the  end  of  2015  that  would  serve  as  the  basis  for  each  IOU  to  develop  a  new  NEM  program  by  2017.  See  California  Legislative  Information.  "AB-­‐327  Electricity:  natural  gas:  rates:  net  energy  metering:  California  Renewables  Portfolio  Standard  Program."  October  7,  2013.  http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201320140AB327  (accessed  April  17,  2014).  The  amended  bill  also  granted  the  CPUC  authority  to  include  a  $5  surcharge  on  monthly  electricity  bills  for  low-­‐income  customers  and  a  $10  surcharge  for  all  other  customers  in  an  IOU’s  territory.  This  aspect  provides  some  measure  of  protection  against  cross-­‐subsidies  for  “residential  customers  in  disadvantaged  communities”  in  forthcoming  NEM  rate  schedules.  See  American  Public  Power  Association.  Distributed  Generation:  An  Overview  of  Recent  Policy  and  Market  Developments.  White  paper,  APPA,  2013,  (23)  and  Kaufmann,  K.  How  long  will  solar-­‐paneled  homes  keep  their  current  deals?  March  1,  2014.  http://www.desertsun.com/story/tech/science/energy/2014/03/02/how-­‐long-­‐will-­‐solar-­‐paneled-­‐homes-­‐keep-­‐their-­‐current-­‐deals/5943343/  (accessed  April  17,  2014).    119    See  California  Public  Utilities  Commission.  Decision  Establishing  a  Transition  Period  Pursuant  to  Assembly  Bill  327  For  Customers  Enrolled  in  Net  Energy  Metering  Tariffs.  Proposed  Decision,  San  Francisco:  California  Public  Utilities  Commission,  2014,  (3-­‐4).    120    See  The  Solar  Report.  Cenergy  Alert:  Update  on  Assembly  Bill  327:  Proposed  Decision  on  Net-­‐Metering  Transition  Period.  February  26,  2014.  http://cenergypower.com/blog/wp-­‐content/uploads/2014/04/nem-­‐transition-­‐timeline.jpg  (accessed  April  1,  2014).    121    While  the  plant’s  nameplate  capacity  was  only  2.2GW,  SONGS  effectively  left  a  2.502GW  hole  in  California’s  electricity  grid  due  to  its  location,  its  role  as  a  supplier  of  one-­‐tenth  of  the  state’s  overall  energy  demand,  and  the  need  to  meet  demand  locally  due  to  transmission  system  constraints.  In  the  first  twelve  months  alone,  the  plant’s  closure  was  estimated  to  have  increased  the  cost  of  electricity  generation  by  $370  million,  an  amount  equivalent  to  a  15%  of  overall  generation  costs.  See  Lifsher,  Mark.  Public  sounds  off  on  San  Onofre  shutdown  costs.  October  2,  2013.  http://articles.latimes.com/2013/oct/02/business/la-­‐fi-­‐mo-­‐public-­‐san-­‐onofre-­‐20131001  (accessed  April  20,  2014)  and  Martinez,  Sierra.  It's  Official:  Efficiency,  Clean  Energy  to  

                                                                                                                                                                                                                                                                                                                                                                                         Help  Fill  California's  Nuclear  Generation  Gap.  March  13,  2014.  http://switchboard.nrdc.org/blogs/smartinez/its_official_efficiency_clean_energy.html  (accessed  April  20,  2014).  Furthermore,  the  loss  of  the  low-­‐carbon  generation  risked  an  increase  in  California’s  carbon  emissions  of  8  million  metric  tons  per  annum.  See  The  Breakthrough  Institute.  San  Onofre  Nuclear  Closure  to  Boost  State  Carbon  Emissions  by  8  Million  Tons.  June  7,  2013.  http://thebreakthrough.org/index.php/programs/energy-­‐and-­‐climate/san-­‐onofre-­‐nuclear-­‐closure-­‐to-­‐boost-­‐state-­‐carbon-­‐emissions-­‐by-­‐8-­‐million-­‐tons  (accessed  April  20,  2014).    122    See  Lifsher,  Mark.  Public  sounds  off  on  San  Onofre  shutdown  costs.  October  2,  2013.  http://articles.latimes.com/2013/oct/02/business/la-­‐fi-­‐mo-­‐public-­‐san-­‐onofre-­‐20131001  (accessed  April  20,  2014).    123    An  additional  400MW–900MW  would  come  from  any  new  type  of  energy  resource  as  needed  (e.g.  natural  gas-­‐fired  generation).  The  decision  suggested  that  energy  efficiency  and  demand-­‐response  programs  would  preclude  the  need  for  a  complete  replacement  of  SONGS’  output  of  2.2GW.  See  Martinez,  Sierra.  It's  Official:  Efficiency,  Clean  Energy  to  Help  Fill  California's  Nuclear  Generation  Gap.  March  13,  2014.  http://switchboard.nrdc.org/blogs/smartinez/its_official_efficiency_clean_energy.html  (accessed  April  20,  2014).    124    The  state  considers  preferred  sources  to  include  “energy  efficiency  and  demand  response  [sources]  first,  followed  by  renewable  sources  and  clean  distributed  generation.  To  the  extent  that  these  efforts  are  unable  to  satisfy  increasing  energy  and  capacity  needs,  the  state  supports  clean  and  efficient  fossil-­‐fired  generation.”  See  California  Public  Utilities  Commission.  Aggressive  Renewable  Power  Targets.  n.d.  http://www.cpuc.ca.gov/NR/rdonlyres/1F71A749-­‐6424-­‐4F49-­‐B7CA-­‐C7C58A181722/0/EnergyLeadership1pagers_v13.pdf  (accessed  April  20,  2014).    125    The  technology  could  provide:  

1. Voltage  and  frequency  support  in  the  form  of  localized  voltage  reduction  to  improve  hosting  capacity  (the  amount  of  generation  that  a  distribution  circuit  can  handle  to  meet  localized  demand);    

2. Alteration  of  the  power  output  and  power  factor  (the  ratio  of  real  power  output  to  total  power  output,  which  is  the  sum  of  real  power  and  reactive  power)  of  the  distributed  solar  PV  system  to  improve  power  quality  and  efficiency;    

3. Monitoring  of  voltage  and  frequency  levels,  increasing  the  grid’s  stability  by  allowing  for  low-­‐voltage  and  low-­‐frequency  ride-­‐through  capabilities;  and    

4. Greater  ease  with  ramping-­‐down  solar  generation  in  the  afternoon  periods  of  low-­‐demand  and  high  distributed  solar  output.  

High  or  low  frequency  ride-­‐through  refers  to  a  situation  when  a  distributed  solar  resource  may  cause  a  momentary  disturbance  in  the  local  voltage  level  on  a  distribution  feeder  outside  of  the  levels  currently  allowed  in  the  national  standard  for  voltage  regulation,  ANSI  C84.1.  In  normal  operation,  this  voltage  disturbance  would  force  the  system  to  instantly  trip-­‐off  (resulting  in  a  loss  of  the  generation  source).  Smart  inverters  would  instead  allow  the  distributed  solar  PV  system  to  continue  to  run  until  the  voltage  can  be  brought  within  an  acceptable  range  (usually  within  a  few  percentage  points  of  60  Hz).    See:  

1. Electric  Power  Research  Institute.  The  Integrated  Grid:  Realizing  the  Full  Value  of  Central  and  Distributed  Energy  Resources.  Palo  Alto:  EPRI,  2014,  (5,  14)  

2. California  Public  Utilities  Commission.  Biennial  Report  on  Impacts  of  Distributed  Generation:  Prepared  in  Compliance  with  AB  578.  FInal  Report,  San  Francisco:  CPUC,  2013,  (6-­‐1)  

3. Smart  Inverter  Working  Group.  Recommendations  for  Updating  the  Technical  Requirements  for  Inverters  in  Distributed  Energy  Resources.  White  Paper,  San  Francisco:  California  Public  Utilities  Commission,  2014,  (9-­‐10)  

   126    See  California  Public  Utilities  Commission.  Biennial  Report  on  Impacts  of  Distributed  Generation:  Prepared  in  Compliance  with  AB  578.  FInal  Report,  San  Francisco:  CPUC,  2013,  (6-­‐1).    

                                                                                                                                                                                                                                                                                                                                                                                         127    See  Smart  Inverter  Working  Group.  Recommendations  for  Updating  the  Technical  Requirements  for  Inverters  in  Distributed  Energy  Resources.  White  Paper,  San  Francisco:  California  Public  Utilities  Commission,  2014,  (10-­‐11).    128    Ibid,  (7,  13).    129    Autonomous  functionalities  could  include  actions  like  the  production  of  electricity  to  serve  an  on-­‐site  load.      130    The  three  phases  are:  

1. autonomous  functionalities  of  smart  inverters  on  the  grid  (Phase  1),  2. communication  standards  for  smart  inverters  (Phase  2),  3. advanced  functionalities  of  smart  inverters  utilizing  the  communication  standards  developed  under  

Phase  2  (Phase  3).  Ibid,  (7,  14).    131    As  was  outlined  above,  the  SIWG  noted  the  following  technical  challenges:  

1. The  location  of  distributed  energy  resources  like  solar  is  usually  chosen  for  the  convenience  of  the  system  owner  (i.e.  a  residential  customer  on  a  utility’s  network);  

2. The  size  and  purpose  of  a  particular  distributed  energy  system  can  vary  greatly  from  customer  to  customer,  making  a  standardized  approach  for  integrating  the  entire  suite  of  systems  complicated;  and  

3. The  potential,  without  coordination,  for  distributed  energy  resources  to  induce  voltage  oscillations  in  response  to  variable  power  output  and  reverse  power  flows  on  circuits  normally  designed  for  uni-­‐directional  energy  flow  (i.e.  centralized  generating  facility  sending  electricity  to  a  distant  load  demand).    

Ibid,  (9).    132    Ibid,  (11).  As  San  Diego  Gas  &  Electric  notes,  “estimated  benefits  [from  the  introduction  of  new  utility  and  technology  investments  such  as  smart  inverters]  are  expected  to  be  realized  over  the  life  of  the  investment,  which  in  nearly  all  cases  is  long  beyond  the  time  period  in  which  costs  are  incurred.  However,  some  Smart  Grid  projects  with  phased  implementations  such  as  Smart  Meters  or  Condition-­‐Based  Maintenance  may  also  accrue  benefits  during  the  course  of  project  implementation.”  See  San  Diego  Gas  &  Electric.  Smart  Grid  Deployment  Plan.  2013  Annual  Report,  San  Diego:  San  Diego  Gas  &  Electric,  2013,  (14).    133    The  relevant  standards  for  inverters  on  the  grid  are  IEEE-­‐1457,  which  pertains  to  the  technical  abilities  of  inverters  on  the  grid,  and  UL  1741,  which  deals  with  the  safety  and  reliability  issues  resulting  from  the  introduction  of  smart  grid  technologies.  Ibid;  and  See  California  Public  Utilities  Commission.  Biennial  Report  on  Impacts  of  Distributed  Generation:  Prepared  in  Compliance  with  AB  578.  FInal  Report,  San  Francisco:  CPUC,  2013.    134    Both  the  CPUC  and  the  California  Energy  Commission  noted  that  the  gears  of  IEEE  standardization,  required  to  ensure  the  flexibility  of  manifold  systems  across  the  entire  U.S.,  turn  far  slower  than  the  pace  of  technological  change  and  popularity  of  NEM  policies.    The  national  grid  code  was  recently  updated  to  IEEE-­‐1547a,  allowing  some  distributed  energy  systems  to  actively  regulate  voltage  at  the  PCC,  and  for  incidents  of  high/low  voltage  or  frequency  to  be  extended  for  specific  time  periods  to  avoid  shortfall  in  generation  via  mass  trip-­‐off.  See  Smart  Inverter  Working  Group.  Recommendations  for  Updating  the  Technical  Requirements  for  Inverters  in  Distributed  Energy  Resources.  White  Paper,  San  Francisco:  California  Public  Utilities  Commission,  2014,  (12-­‐13).    135    In  California,  all  interconnection,  operational,  and  metering  aspects  of  a  generating  facility  are  governed  according  to  Electric  Tariff  Rule  21.  Ibid,  (7-­‐8).    136    PG&E  expects  that  solar  generation,  both  utility-­‐scale  and  distributed,  will  grow  from  its  current  8%  contribution  to  their  generation  portfolio  in  2012  to  45%  in  2020.  See  Parks,  Ken,  and  Bob  Woerner.  

                                                                                                                                                                                                                                                                                                                                                                                         "Distributed  Generation  Interconnection  Collaborative  (DGIC)."  Innovation  in  the  Interconnection  Application  Process.  Golden:  NREL,  April  2,  2014.      137    Ibid.    138    For  the  decision,  See  California  Public  Utilities  Commission.  Order  Instituting  Rulemaking  Pursuant  to  Assembly  Bill  2514  to  Consider  the  Adoption  of  Procurement  Targets  for  Viable  and  Cost-­‐Effective  Energy  Storage  Systems.  Decision  13-­‐10-­‐040  October  17,  2013,  Sacremento:  CPUC,  2014.    139    Each  utility  is  responsible  for:  

1. SCE:  580MW  2. PG&E:  580MW  3. SDG&E:  165MW  

of  storage.  See  Sweet,  Bill.  California's  First-­‐in-­‐Nation  Energy  Storage  Mandate.  October  25,  2013.  http://spectrum.ieee.org/energywise/energy/renewables/californias-­‐firstinnation-­‐energy-­‐storage-­‐mandate  (accessed  April  21,  2014).    140    Strictly  speaking,  the  mandate’s  goals  are  to  optimize  the  grid  via  peak  electricity  reduction,  increase  the  reliability  of  the  electricity  grid  as  increasing  amounts  of  intermittent  generation  come  on-­‐line,  defer  transmission  and  distribution  system  upgrade  investments,  and  reduce  greenhouse  gas  emissions  to  80%  below  1990  levels  by  2050.  See  Hornbrook,  Chuck.  "The  benefits  of  the  California  storage  procurement  framework."  ACORE  Advisory  Committee  Call.  Washington:  ICFI,  April  16,  2014.    141    The  mandate  stipulated  that  each  IOU  cannot  claim  ownership  of  more  than  50%  of  the  storage  projects  they  propose,  and  that  the  burden  of  proof  with  regard  to  cost-­‐effectiveness  rests  on  the  owners  of  the  storage  project(s).    142    See  Creyts,  Jon,  and  Leia  Guccione.  The  Economics  of  Grid  Defection:  When  and  Where  Distributed  Solar  Generation  Plus  Storage  Competes  with  Traditional  Utility  Service.  White  Paper,  Boulder:  Rocky  Mountain  Institute,  2014,  (6).    143    As  the  Rocky  Mountain  Institute  study  noted:    “The  coming  grid  parity  of  solar-­‐plus-­‐battery  systems  in  the  foreseeable  future,  among  other  factors,  signals  the  eventual  demise  of  traditional  utility  business  models…[utilities]  could  also  see  solar-­‐plus-­‐battery  systems  as  an  opportunity  to  add  value  to  the  grid  and  their  business.  When  solar-­‐plus-­‐battery  systems  are  integrated  into  a  network,  new  opportunities  open  up  that  generate  even  greater  value  for  customers  and  the  network  (e.g.  potentially  better  customer-­‐side  economics,  additional  sizing  options,  ability  of  distributed  systems  to  share  excess  generation  or  storage).  [emphasis  added]”  Ibid,  (17,  39).    144    Ibid;  and  See  John,  Jeff  St.  SolarCity  Halts  Battery-­‐Grid  Connect  Apps  Until  CA  Utilities  Open  Bottleneck.  March  21,  2014.  http://www.greentechmedia.com/articles/read/solarcity-­‐to-­‐ca-­‐utilities-­‐no-­‐more-­‐batteries-­‐until-­‐grid-­‐opens-­‐up  (accessed  April  22,  2014).    145    The  fees  were  reported  to  be:  

1. an  $800  application  fee  and  a  $600  fee  for  a  new  meter  installation  and  operations  cost  for  customers  in  the  PG&E  territory,  and  

2. $2,900  in  total  fees  for  customers  in  the  SCE  territory.  The  costs  for  customers  in  the  SDG&E  territory  were  not  disclosed.  Ibid.    146    SolarCity  reported  that  since  2011,  out  of  a  total  of  500  applications  it  received,  only  11  PG&E,  one  SDG&E,  and  zero  SCE  customers  were  approved  for  interconnection.  Ibid.    147    See  Martin,  Christopher.  SolarCity  Resumes  Applications  for  California  Batteries.  April  16,  2014.  http://www.bloomberg.com/news/2014-­‐04-­‐16/solarcity-­‐resumes-­‐applications-­‐for-­‐california-­‐batteries.html  (accessed  April  21,  2014).  

                                                                                                                                                                                                                                                                                                                                                                                           148    See  California  Public  Utilities  Commission.  Decision  Regarding  Net  Energy  Metering  Interconnection  Eligibility  for  Storage  Devices  Paired  with  Net  Energy  Metering  Generation  Facilities.  Proposed  Decision,  San  Franciso:  CPUC,  2014,  (9).    149    The  proposed  decision  did  place  some  limitations  on  the  size  of  the  storage  system,  as  requested  by  the  IOUs,  but  also  removed  the  potential  for  penalties  relating  to  de  minimis  consumption  (i.e.  when  a  storage  system  consumes  some  amounts  of  power  to  maintain  system  services),  in  line  with  the  requests  from  solar  advocacy  groups.  Ibid,  (10,  11,  12-­‐13,  18).      150    See  Martin,  Christopher.  SolarCity  Resumes  Applications  for  California  Batteries.  April  16,  2014.  http://www.bloomberg.com/news/2014-­‐04-­‐16/solarcity-­‐resumes-­‐applications-­‐for-­‐california-­‐batteries.html  (accessed  April  21,  2014).    151    FERC  Order  755  “revises  the  regulations  to  remedy  undue  discrimination  in  the  procurement  of  frequency  regulation  in  the  organized  wholesale  electric  markets  and  ensure  that  providers  of  frequency  regulation  receive  just  and  reasonable  and  not  unduly  discriminatory  or  preferential  rates,”  effectively  opening  the  door  for  fast-­‐reacting  battery  devices  to  contribute  to  ramping-­‐up  and  ramping-­‐down  challenges  for  the  generation  fleet  and  respond  automatically  to  grid  operators’  requests  for  frequency  regulation.  See  Federal  Energy  Regulatory  Commission.  Frequency  Regulation  Compensation  in  the  Organized  Wholesale  Power  Markets.  Final  Rule,  Washington:  FERC,  2011.    152    “…the  cost  of  supply  and  delivery  capacity  can  account  for  almost  50%  of  the  overall  cost  of  electricity  for  an  average  residential  customer.  Traditionally,  residential  rate  structures  are  based  on  metered  energy  usage.  With  no  separate  charge  for  capacity  costs,  the  energy  charge  has  traditionally  been  set  to  recover  both  costs.  Customers  that  use  distributed  resources  to  reduce  their  grid-­‐provided  energy  consumption  significantly  but  remain  connected  to  the  grid  may  pay  significantly  less  than  the  costs  incurred  by  the  utility  to  provide  capacity  and  grid  connectivity.  In  effect,  the  burden  of  paying  for  that  capacity  can  potentially  shift  to  consumers  without  distributed  energy  resources.”  See  Electric  Power  Research  Institute.  The  Integrated  Grid:  Realizing  the  Full  Value  of  Central  and  Distributed  Energy  Resources.  Palo  Alto:  EPRI,  2014,  (24).    153    Several  other  options  exist,  including  revenue  decoupling,  time-­‐of-­‐use  pricing,  and  real-­‐time  pricing  (such  as  day-­‐ahead  hourly  pricing)  mechanisms.  See  Solar  Energy  Industries  Association.  Utility  Rate  Structure.  n.d.  http://www.seia.org/policy/distributed-­‐solar/utility-­‐rate-­‐structure  (accessed  April  24,  2014).  California  is  currently  considering  implementing  time-­‐of-­‐use  rates  to  better  match  customer  rates  with  marginal  costs.  The  docket  item,  R.12-­‐06-­‐013,  would  implement  a  winter  off-­‐peak  rate  of  $0.114/kWh,  a  summer-­‐peak  rate  of  $0.466/kWh,  and  an  average  customer  rate  of  approximately  $0.19/kWh.  An  analysis  performed  by  the  Institute  for  Local  Self  Reliance  found  that  the  application  of  time-­‐of-­‐use  rates  to  net  metering  could  increase  the  value  of  solar  to  the  customer  by  as  much  as  250%  when  compared  to  the  normal  rate  schedule.  See  Paulos,  Bentham.  Surpassing  Milestone  of  100,000  Solar  Roofs,  PG&E  Calls  for  'Sustainable'  Solar  Policy.  April  21,  2014.  http://www.greentechmedia.com/articles/read/pge-­‐hits-­‐100000-­‐solar-­‐roofs  (accessed  April  28,  2014).    154    Arizona’s  fixed  charge  is  $0.70/kW  of  system  capacity;  for  an  average  system  this  works  out  to  roughly  $5  per  month.  See  Cardwell,  Diane.  Compromise  in  Arizona  Defers  a  Solar  Power  Fight.  November  15,  2013.  http://www.nytimes.com/2013/11/16/business/energy-­‐environment/compromise-­‐in-­‐arizona-­‐defers-­‐a-­‐solar-­‐power-­‐fight.html?_r=0  (accessed  April  24,  2014).    155    Oklahoma’s  Governor  Mary  Fallin  issued  an  order  following  the  passage  of  Senate  Bill  1456,  which  authorizes  utilities  to  apply  for  the  authority  to  impose  higher  base-­‐rates  for  customers  with  distributed  generation  facilities  on  their  property.  Governor  Fallin’s  executive  order  mandates  that  the  utilities  must  consider  distributed  generation  sources  like  solar  PV  as  integral  to  Oklahoma’s  energy  policy  moving  forward.  See  Colthorpe,  Andy.  US  governor  rules  in  favour  of  distributed  generation.  April  24,  2014.  http://www.pv-­‐tech.org/news/us_governor_rules_in_favour_of_distributed_generation  (accessed  April  24,  2014).    

                                                                                                                                                                                                                                                                                                                                                                                         156    See  National  Renewable  Energy  Laboratory.  (2013).  Treatment  of  Solar  Generation  in  Electric  Utility  Resource  Planning.  Golden:  NREL,  (37).    157    Ibid.    158  See  Farrell,  John.  The  Method  and  Meaning  of  Minnesota's  New  Value  of  Solar  Policy.  April  09,  2014.  http://www.renewableenergyworld.com/rea/blog/post/2014/04/the-­‐method-­‐and-­‐meaning-­‐of-­‐minnesotas-­‐new-­‐value-­‐of-­‐solar-­‐policy  (accessed  April  24,  2014).      159    See  Minnesota  Department  of  Commerce,  Division  of  Energy  Resources.  Minnesota  Value  of  Solar:  Methodology.  St.  Paul:  Minnesota  Department  of  Commerce;  Clean  Power  Research,  2014,  (ii).    160    These  benefits  include:  

1. Fuel  savings;  2. O&M  savings;  3. Deferment  of  generation  and  reserve  capacity  additions;  4. Deferment  in  transmission  and  distributed  system  upgrades;  and  5. Environmental  benefits,  including  the  estimated  avoided  cost  of  climate  change-­‐related  impacts.  

The  environmental  benefit  component  of  the  VOST  was  controversial  due  to  its  use  of  the  Social  Cost  of  Carbon  (SCC)  calculator.  The  SCC,  developed  in  May  2013,  ascribes  a  cost  to  carbon  dioxide  emissions  based  upon  the  human  health  problems,  property  damage,  and  agricultural  disruptions  that  can  be  attributed  to  increasing  carbon  dioxide  emissions  and  climate  change.  The  SCC  is  set  to  increase  from  $39  in  2015  to  $76  in  2050  using  a  3%  discount  rate.  See  Friedrich,  Kat.  Minnesota  May  Reward  Solar  Producers  for  Climate  Change  Reduction.  March  21,  2014.  http://www.renewableenergyworld.com/rea/news/article/2014/03/minnesota-­‐may-­‐reward-­‐solar-­‐producers-­‐for-­‐climate-­‐change-­‐reduction  (accessed  April  24,  2014).    161    Ibid.    162    See  Farrell,  John.  The  Method  and  Meaning  of  Minnesota's  New  Value  of  Solar  Policy.  April  09,  2014.  http://www.renewableenergyworld.com/rea/blog/post/2014/04/the-­‐method-­‐and-­‐meaning-­‐of-­‐minnesotas-­‐new-­‐value-­‐of-­‐solar-­‐policy  (accessed  April  24,  2014).    163    See  Brandt,  Yann.  Does  VOST=FIT,  What  is  a  Value  of  Solar  Tariff  (VOST)?  February  25,  2014.  http://www.solarwakeup.com/2014/02/25/does-­‐vostfit-­‐what-­‐is-­‐a-­‐value-­‐of-­‐solar-­‐tariff-­‐vost/  (accessed  May  30,  2014).    164    See  Minnesota  Department  of  Commerce,  Division  of  Energy  Resources.  Minnesota  Value  of  Solar:  Methodology.  St.  Paul:  Minnesota  Department  of  Commerce;  Clean  Power  Research,  2014,  (6).    165    See  Friedrich,  Kat.  Minnesota  May  Reward  Solar  Producers  for  Climate  Change  Reduction.  March  21,  2014.  http://www.renewableenergyworld.com/rea/news/article/2014/03/minnesota-­‐may-­‐reward-­‐solar-­‐producers-­‐for-­‐climate-­‐change-­‐reduction  (accessed  April  24,  2014)  and  Vartabedian,  Ralph.  U.S.  electricity  prices  may  be  going  up  for  good.  April  25,  2014.  http://www.latimes.com/nation/la-­‐na-­‐power-­‐prices-­‐20140426,0,6329274.story  -­‐  axzz3024QCO00  (accessed  April  28,  2014).    166    Critics  have  focused  their  ire  on  the  use  of  the  SCC,  noting  that  Minnesota  does  not  impose  a  monetary  penalty  on  a  utility  for  carbon  emissions,  nor  are  the  cost  metrics  and  cost  of  carbon  dioxide  known  and  measureable.  In  short,  Minnesota  residents  should  not  be  charged  for  externalities  that  have  yet  to  be  quantified  or  societal  benefits  that  have  yet  to  be  realized.  See  Friedrich,  Kat.  Minnesota  May  Reward  Solar  Producers  for  Climate  Change  Reduction.  March  21,  2014.  http://www.renewableenergyworld.com/rea/news/article/2014/03/minnesota-­‐may-­‐reward-­‐solar-­‐producers-­‐for-­‐climate-­‐change-­‐reduction  (accessed  April  24,  2014).    167    See  Farrell,  John.  The  Method  and  Meaning  of  Minnesota's  New  Value  of  Solar  Policy.  April  09,  2014.  http://www.renewableenergyworld.com/rea/blog/post/2014/04/the-­‐method-­‐and-­‐meaning-­‐of-­‐minnesotas-­‐new-­‐value-­‐of-­‐solar-­‐policy  (accessed  April  24,  2014).  

                                                                                                                                                                                                                                                                                                                                                                                           168    See  Brandt,  Yann.  Does  VOST=FIT,  What  is  a  Value  of  Solar  Tariff  (VOST)?  February  25,  2014.  http://www.solarwakeup.com/2014/02/25/does-­‐vostfit-­‐what-­‐is-­‐a-­‐value-­‐of-­‐solar-­‐tariff-­‐vost/  (accessed  May  30,  2014).    169    See  National  Renewable  Energy  Laboratory.  (2013).  Treatment  of  Solar  Generation  in  Electric  Utility  Resource  Planning.  Golden:  NREL,  (37).    170    See  Kind,  Peter.  Disruptive  Challenges:  Financial  Implications  and  Strategic  Responses  to  a  Changing  Retail  Electric  Business.  White  Paper,  Washington:  Edison  Electric  Institute,  2013,  (14-­‐15).    171    See  Lehr,  Ron,  and  Ron  Binz.  New  Utility  Business  Models:  Implications  of  a  High-­‐Penetration  Renewable  Energy  Future.  Presentation,  Western  Governors  Association,  2013,  (18).    172    See  Wesoff,  Eric.  EPRI  Reveals  Its  Worldview  on  the  Integrated  Electrical  Grid.  April  22,  2014.  http://www.greentechmedia.com/articles/read/EPRI-­‐Reveals-­‐Its-­‐Worldview-­‐on-­‐The-­‐Integrated-­‐Electrical-­‐Grid  (accessed  April  25,  2014).    173    See  Peterson,  Lee.  Pension  Funds  Hold  a  Key  to  Renewable  Energy  Finance.  April  30,  2014.  http://www.renewableenergyworld.com/rea/news/article/2014/04/pension-­‐funds-­‐hold-­‐a-­‐key-­‐to-­‐renewable-­‐energy-­‐finance?cmpid=rss  (accessed  April  30,  2014).    174    See  Aneiro,  Michael.  Barclays  Downgrades  Electric  Utility  Bonds,  Sees  Viable  Solar  Competition.  May  23,  2014.  http://blogs.barrons.com/incomeinvesting/2014/05/23/barclays-­‐downgrades-­‐electric-­‐utility-­‐bonds-­‐sees-­‐viable-­‐solar-­‐competition/  (accessed  May  30,  2014)  and  Wile,  Rob.  Barclays  Has  The  Best  Explanation  Yet  Of  How  Solar  Will  Destroy  America's  Electric  Utilities.  28  2014,  May.  http://www.businessinsider.com/barclays-­‐downgrades-­‐utilities-­‐on-­‐solar-­‐threat-­‐2014-­‐5  (accessed  May  30,  2014).    175    Ron  Lehr  and  Ron  Binz  label  this  the  “Grand  Bargain”  model,  where  “the  direction  from  the  commission  would  be  to  negotiate  a  multi-­‐year  agreement  concerning  rates,  cost  recovery  mechanisms,  quality  of  service  goals,  environmental  performance,  energy  efficiency  goals,  incentives,  etc.”  Lehr,  Ron,  and  Ron  Binz.  New  Utility  Business  Models:  Implications  of  a  High-­‐Penetration  Renewable  Energy  Future.  Presentation,  Western  Governors  Association,  2013,  (20).  In  April  2014,  the  New  York  State  Department  of  Public  Service  published  a  report  entitled  Reforming  the  Energy  Vision  detailing  the  state’s  plans  to  rebrand  the  electric  utility  sector  (and  the  distribution  system  in  particular)  to  reflect  the  entrance  of  new  distributed  generation,  energy  storage,  and  customer  preferences.  While  the  report  itself  notes  the  prodigious  challenges  that  accompany  such  a  paradigm  shift,  the  strategies  outlined  closely  mirror  the  “Grand  Bargain”  model  proposed  by  Ron  Lehr  and  Ron  Binz.  See  New  York  State  Department  of  Public  Service.  Reforming  the  Energy  Vision.  Staff  Report  and  Proposal,  Albany:  New  York  State  Department  of  Public  Service,  2014.    176    See  Rosenbaum,  Eric.  A  dirty  clean  energy  battle  becoming  a  utility  war.  March  6,  2014.  http://www.cnbc.com/id/101472289  (accessed  April  10,  2014).    177    See  National  Renewable  Energy  Laboratory.  (2013).  Treatment  of  Solar  Generation  in  Electric  Utility  Resource  Planning.  Golden:  NREL,  (37).