GRID TALK

2014 Advocacy and Engagement Forum
On Distributed Generation

 

BRIEFING BOOK

 

News Clips

 

 

US 
  vs. 
  Europe: 
  Energy 
  Battle 
  Heats 
  Up 
    
  CNBC 
    
  Daniel 
  Yergin 
    
  1/27/14 
  
http://www.cnbc.com/id/101365772 
   
  

One 
  of 
  the 
  biggest 
  themes 
  at 
  Davos 
  this 
  year 
  — 
  and 
  one 
  that 
  was 
  not 
  there 
  last 
  year 
  — 
  was 
  
"competitiveness." 
  You 
  encountered 
  it 
  whether 
  in 
  the 
  public 
  sessions 
  in 
  the 
  Congress 
  Center, 
  or 
  in 
  the 
  
private 
  sessions, 
  and 
  at 
  the 
  various 
  dinners 
  in 
  the 
  hotels 
  strung 
  along 
  the 
  Davos 
  Platz. 
  
This 
  particular 
  rivalry 
  pits 
  the 
  United 
  States 
  head-­‐on 
  against 
  Europe. 
  And, 
  no 
  question 
  — 
  at 
  Davos 
  this 
  
year, 
  the 
  United 
  States 
  was 
  judged 
  the 
  clear 
  winner, 
  much 
  to 
  the 
  dispirit 
  of 
  the 
  Europeans 
  trudging 
  back 
  
along 
  the 
  icy, 
  snowy 
  streets 
  of 
  this 
  mountain 
  village. 
  
This 
  concern, 
  however, 
  was 
  hardly 
  limited 
  to 
  the 
  annual 
  conclave 
  in 
  the 
  Swiss 
  Alps. 
  It 
  reverberated 
  with 
  
simultaneous 
  developments 
  in 
  both 
  Brussels 
  and 
  Berlin 
  that 
  point 
  to 
  the 
  beginning 
  of 
  a 
  major, 
  if 
  
difficult, 
  rethink 
  of 
  Europe's 
  energy 
  policies. 
   
  
Of 
  course, 
  competitiveness 
  among 
  nations 
  gets 
  measured 
  in 
  many 
  different 
  ways. 
  Sometimes, 
  it 
  is 
  in 
  
terms 
  of 
  rule 
  of 
  law 
  and 
  sanctity 
  of 
  contracts, 
  regulatory 
  predictability, 
  risks 
  of 
  litigation 
  and 
  class-­‐
actions 
  suits 
  — 
  or 
  even 
  the 
  length 
  of 
  time 
  it 
  takes 
  to 
  start 
  a 
  new 
  business. 
  
But 
  this 
  year 
  at 
  Davos, 
  it 
  was 
  calibrated 
  along 
  only 
  one 
  axis 
  — 
  energy. 
  And 
  that 
  measure 
  is 
  creating 
  
great 
  angst 
  for 
  European 
  industry. 
  It 
  is 
  also 
  emerging 
  as 
  a 
  challenging 
  issue 
  for 
  policy 
  makers, 
  who, 
  until 
  
now, 
  have 
  been 
  quite 
  assured 
  that 
  Europe 
  was 
  on 
  the 
  right 
  course 
  when 
  it 
  came 
  to 
  energy 
  policy. 
   
  
It 
  all 
  comes 
  down 
  to 
  shale 
  gas 
  and 
  the 
  energy 
  revolution 
  it 
  has 
  triggered 
  in 
  the 
  United 
  States. 
  As 
  a 
  result 
  
of 
  the 
  rapid 
  advance 
  of 
  shale 
  technology, 
  the 
  United 
  States 
  now 
  has 
  an 
  abundance 
  of 
  low-­‐cost 
  natural 
  
gas 
  — 
  at 
  one-­‐third 
  the 
  price 
  of 
  European 
  gas. 
  European 
  industrial 
  electricity 
  prices 
  are 
  twice 
  as 
  high 
  as 
  
those 
  in 
  some 
  countries 
  and 
  are 
  much 
  higher 
  than 
  those 
  in 
  the 
  United 
  States. 
  To 
  a 
  significant 
  degree, 
  
this 
  is 
  the 
  result 
  of 
  a 
  pell-­‐mell 
  push 
  toward 
  high-­‐cost 
  renewable 
  electricity 
  (wind 
  and 
  solar), 
  which 
  is 
  
imposing 
  heavy 
  costs 
  on 
  consumers 
  and 
  generating 
  large 
  fiscal 
  burdens 
  for 
  governments. 
  In 
  Germany, 
  it 
  
was 
  further 
  accentuated 
  by 
  the 
  premature 
  shutdown 
  of 
  its 
  existing 
  nuclear 
  industry 
  after 
  the 
  2011 
  
Fukushima 
  nuclear 
  accident 
  in 
  Japan. 
  
All 
  this 
  puts 
  European 
  industrial 
  production 
  at 
  a 
  heavy 
  cost 
  disadvantage 
  against 
  the 
  United 
  States. 
  The 
  
result 
  is 
  a 
  migration 
  of 
  industrial 
  investment 
  from 
  Europe 
  to 
  the 
  United 
  States 
  — 
  what 
  one 
  CEO 
  called 
  
an 
  "exodus." 
  It 
  involves, 
  not 
  only 
  energy-­‐intensive 
  industries 
  like 
  chemicals 
  and 
  metals, 
  but 
  also 
  
companies 
  in 
  the 
  supply 
  chains 
  that 
  support 
  such 
  industries. 
  
A 
  year 
  ago 
  at 
  Davos, 
  this 
  question 
  was 
  hardly 
  evident. 
  I 
  can 
  recall 
  only 
  one 
  discussion 
  on 
  the 
  topic 
  last 
  
year, 
  and 
  it 
  was 
  over 
  a 
  cup 
  of 
  coffee 
  in 
  the 
  cramped 
  lounge 
  halfway 
  up 
  the 
  main 
  staircase. 
  But 
  this 
  year, 
  
the 
  issue 
  was 
  at 
  the 
  top 
  of 
  the 
  agenda. 
  In 
  one 
  session 
  I 
  attended, 
  a 
  senior 
  European 
  official 
  declared 
  
that 
  Europe 
  needs 
  to 
  wake 
  up 
  to 
  the 
  "strategic 
  reality" 
  that 
  shale 
  gas 
  in 
  the 
  United 
  States 
  is 
  a 
  "total 
  
game 
  changer." 
  Without 
  a 
  change 
  in 
  policies 
  at 
  both 
  the 
  European 
  and 
  national 
  levels, 
  he 
  warned, 
  
Europe 
  "will 
  lose 
  our 
  energy 
  intensive 
  industries 
  — 
  and 
  we 
  will 
  lose 
  our 
  economy 
  long 
  term." 
   
  
Yet 
  the 
  competitiveness 
  gap 
  will 
  continue 
  to 
  expand 
  as 
  Europe 
  remains 
  locked 
  in 
  a 
  path 
  of 
  still-­‐higher 
  
costs 
  — 
  unless 
  there 
  is 
  a 
  change 
  in 
  policy. 
  And 
  the 
  first 
  signs 
  of 
  a 
  potential 
  change 
  of 
  policy 
  abruptly 
  
emerged 
  in 
  both 
  Brussels 
  and 
  Berlin 
  during 
  Davos 
  week. 
  European 
  policy 
  makers, 
  struggling 
  with 
  already 
  
high 
  unemployment, 
  have 
  begun 
  to 
  visualize 
  the 
  further 
  job 
  loss 
  that 
  will 
  result 
  from 
  shutting 
  down 
  
1 
  
 
  

 European 
  plants. 
  They 
  have 
  also 
  started 
  to 
  pay 
  attention 
  to 
  the 
  2.1 
  million 
  jobs 
  in 
  in 
  the 
  United 
  States 
  
supported 
  by 
  the 
  unconventional 
  oil 
  and 
  gas 
  revolution. 
  
In 
  Brussels, 
  coinciding 
  with 
  the 
  first 
  day 
  of 
  Davos, 
  the 
  European 
  Commission 
  released 
  a 
  new 
  policy 
  paper 
  
on 
  energy 
  and 
  climate. 
  It 
  reiterated 
  the 
  commitment 
  to 
  substantial 
  growth 
  in 
  renewable 
  electricity 
  and 
  
a 
  "low-­‐carbon 
  economy." 
  But, 
  for 
  the 
  first 
  time, 
  it 
  put 
  heavy 
  emphasis 
  on 
  the 
  price 
  of 
  such 
  policies 
  and 
  
called 
  for 
  a 
  "more 
  cost-­‐efficient 
  approach" 
  to 
  renewables. 
  It 
  warned 
  of 
  the 
  mortal 
  risk 
  facing 
  "industries 
  
that 
  have 
  high 
  share 
  of 
  energy 
  costs 
  and 
  which 
  are 
  exposed 
  to 
  international 
  competition." 
  It 
  declared 
  
that 
  policies 
  have 
  to 
  promote 
  "competitive" 
  as 
  well 
  as 
  "sustainable 
  energy" 
  — 
  a 
  juxtaposition 
  that 
  was 
  
not 
  heard 
  before. 
  It 
  even 
  warned 
  that 
  "the 
  rapid 
  development 
  of 
  renewable 
  energy 
  sources 
  now 
  poses 
  
new 
  challenges 
  for 
  the 
  energy 
  system." 
  
Notably, 
  the 
  new 
  policy 
  statement 
  went 
  out 
  of 
  its 
  way 
  to 
  observe 
  that 
  "the 
  availability 
  of 
  shale 
  gas 
  in 
  
the 
  USA 
  has 
  substantially 
  lowered 
  natural 
  gas 
  prices 
  there 
  as 
  well 
  as 
  electricity 
  generated 
  from 
  natural 
  
gas." 
  Despite 
  the 
  fervent 
  opposition 
  to 
  shale 
  gas 
  in 
  some 
  quarters 
  in 
  Europe, 
  it 
  pointedly 
  included 
  shale 
  
gas 
  as 
  among 
  the 
  domestic 
  low-­‐carbon 
  energy 
  sources 
  that 
  member 
  countries 
  can 
  pursue. 
  
This 
  was 
  all 
  the 
  more 
  significant 
  in 
  that 
  the 
  commission 
  is 
  acknowledging 
  the 
  reality 
  of 
  the 
  shale 
  
revolution 
  and 
  rejecting 
  the 
  view 
  of 
  Europe's 
  anti-­‐shale 
  activists 
  that 
  America's 
  shale 
  gas 
  abundance 
  is 
  
only 
  a 
  "bubble," 
  destined 
  to 
  soon 
  disappear. 
  
A 
  similar 
  message 
  resounded 
  at 
  exactly 
  the 
  same 
  time 
  from 
  Berlin. 
  Sigmar 
  Gabriel, 
  the 
  social 
  democratic 
  
minister 
  of 
  economy 
  and 
  energy 
  in 
  Germany's 
  coalition 
  government, 
  called 
  for 
  reform 
  in 
  Germany's 
  
Energiewende 
  — 
  or 
  "energy 
  turn" 
  policy 
  — 
  which 
  has 
  heavily 
  subsidized 
  the 
  rapid 
  growth 
  in 
  renewable 
  
electricity. 
  He 
  warned 
  that 
  the 
  "anarchy" 
  in 
  renewable 
  energy 
  and 
  its 
  costs 
  in 
  Germany 
  had 
  to 
  be 
  reined 
  
in: 
  "The 
  whole 
  economic 
  future 
  of 
  our 
  country 
  is 
  riding 
  on 
  this," 
  he 
  said. 
  "We 
  have 
  reached 
  the 
  limits 
  of 
  
what 
  we 
  can 
  ask 
  of 
  our 
  economy." 
  
Up 
  until 
  now, 
  the 
  Energiewende 
  in 
  its 
  present 
  form 
  has 
  been 
  sacrosanct, 
  supported 
  not 
  just 
  by 
  the 
  
Greens 
  but 
  all 
  across 
  the 
  political 
  spectrum. 
  Gabriel 
  — 
  and 
  Chancellor 
  Angela 
  Merkel 
  — 
  aim 
  to 
  maintain 
  
the 
  commitment, 
  but 
  reduce 
  subsidies, 
  focus 
  more 
  on 
  costs, 
  and, 
  as 
  Gabriel 
  said, 
  "control 
  the 
  expansion 
  
of 
  renewable 
  energy." 
  
His 
  comments 
  reflect 
  the 
  recognition 
  that, 
  if 
  the 
  course 
  remains 
  unchanged, 
  Germany 
  could 
  be 
  facing 
  
what 
  Gabriel 
  called 
  "a 
  dramatic 
  deindustrialization." 
  And 
  that 
  would 
  threaten 
  Germany's 
  prosperity, 
  
which 
  hinges 
  to 
  a 
  considerable 
  degree 
  on 
  Germany's 
  international 
  competitiveness. 
  Exports 
  are 
  
responsible 
  for 
  over 
  50 
  percent 
  of 
  German 
  GDP, 
  compared 
  to 
  27 
  percent 
  for 
  China, 
  which 
  is 
  generally 
  
considered 
  to 
  be 
  the 
  workshop 
  of 
  the 
  world. 
  
Gabriel's 
  comments 
  stirred 
  up 
  criticism 
  from 
  environmentalists; 
  indeed, 
  they 
  may 
  seem 
  strange 
  words 
  
coming 
  from 
  the 
  leader 
  of 
  the 
  Social 
  Democrats 
  (the 
  SPD). 
  But 
  the 
  Social 
  Democrats 
  are 
  very 
  close 
  to 
  
the 
  trade 
  unions, 
  for 
  which 
  loss 
  of 
  competitiveness 
  translates 
  into 
  loss 
  of 
  jobs. 
  
And 
  it 
  is 
  jobs, 
  as 
  much 
  the 
  specter 
  of 
  "deindustrialization," 
  the 
  disinvestment 
  in 
  industry, 
  that 
  is 
  now 
  
making 
  competitiveness 
  a 
  significant 
  part 
  of 
  Europe's 
  energy 
  debates, 
  especially 
  on 
  a 
  continent 
  where 
  
unemployment 
  is 
  so 
  high. 
  The 
  risk 
  of 
  major 
  job 
  loss 
  could 
  well 
  provide 
  the 
  political 
  stimulus 
  to 
  moderate 
  
energy 
  policies 
  in 
  order 
  to 
  narrow 
  the 
  trans-­‐Atlantic 
  gap 
  that 
  was 
  so 
  evident 
  a 
  theme 
  this 
  year 
  at 
  Davos. 
  
2 
  
 
  

  
  
 
  
Hawaii’s 
  Solar 
  Energy 
  Revolution 
    
  Honolulu 
  Magazine 
    
  David 
  Thompson 
    
  February 
  2014 
    
   
  
http://www.honolulumagazine.com/Honolulu-­‐Magazine/February-­‐2014/Hawaiis-­‐Solar-­‐Energy-­‐
Revolution/ 
   
  

It 
  wasn’t 
  long 
  ago 
  that 
  a 
  company 
  called 
  Hawaiian 
  Telcom 
  reigned 
  supreme 
  over 
  phone 
  calls 
  in 
  Hawaii. 
  If 
  
you 
  talked 
  on 
  the 
  telephone, 
  your 
  voice 
  traveled 
  through 
  Hawaiian 
  Telcom’s 
  copper 
  wires. 
  But 
  as 
  
cellphones 
  became 
  more 
  affordable, 
  demand 
  for 
  phones 
  tied 
  to 
  walls 
  plummeted. 
  By 
  2009 
  the 
  once-­‐
mighty 
  phone 
  company 
  was 
  in 
  bankruptcy, 
  reorganizing 
  itself 
  and 
  trying 
  to 
  figure 
  out 
  how 
  to 
  be 
  relevant 
  
in 
  a 
  world 
  where 
  everybody 
  and 
  their 
  teenagers 
  were 
  awaiting 
  the 
  release 
  of 
  the 
  latest 
  iPhone. 
  
A 
  similar 
  shake-­‐up 
  is 
  underway 
  with 
  another 
  old-­‐line 
  utility, 
  Hawaiian 
  Electric 
  Co. 
  It’s 
  being 
  driven 
  by 
  
people 
  such 
  as 
  Donald 
  Jay, 
  a 
  retired 
  civil 
  service 
  worker 
  who 
  lives 
  in 
  a 
  cul 
  de 
  sac 
  in 
  Mililani. 
  Last 
  April, 
  
Jay 
  put 
  a 
  solar 
  photovoltaic 
  system 
  on 
  his 
  rooftop. 
  It 
  generates 
  more 
  electricity 
  than 
  Jay 
  uses, 
  and 
  he’s 
  
slashed 
  his 
  electric 
  bill 
  to 
  HECO’s 
  minimum 
  $17 
  charge. 
  “I 
  was 
  paying 
  about 
  $850 
  a 
  month, 
  because 
  I 
  
have 
  air 
  conditioning 
  and 
  a 
  lot 
  of 
  appliances,” 
  says 
  Jay. 
  “I 
  hardly 
  pay 
  anything 
  anymore. 
  That 
  really 
  
makes 
  me 
  happy.” 
  
 
  
That 
  kind 
  of 
  happiness, 
  multiplied 
  by 
  the 
  26,000 
  other 
  Oahu 
  homeowners 
  with 
  PV 
  on 
  their 
  rooftops, 
  
threatens 
  to 
  undo 
  HECO 
  in 
  the 
  same 
  way 
  that 
  cellphones 
  in 
  everyone’s 
  pockets 
  undid 
  Hawaiian 
  Telcom. 
  
 
  
In 
  the 
  world 
  of 
  cheap 
  photovoltaics 
  and 
  other 
  emerging 
  home 
  energy 
  technologies, 
  you, 
  the 
  ratepayer, 
  
are 
  no 
  longer 
  helpless 
  in 
  the 
  face 
  of 
  sky-­‐high 
  electric 
  bills, 
  unable 
  to 
  do 
  anything 
  beyond 
  using 
  Energy 
  
Star 
  appliances 
  and 
  yelling 
  at 
  the 
  kids 
  to 
  shut 
  off 
  the 
  lights. 
  The 
  power 
  to 
  make 
  and 
  store 
  power 
  is 
  
shifting 
  to 
  your 
  court. 
  The 
  dawn 
  of 
  the 
  age 
  of 
  energy 
  democracy 
  is 
  upon 
  us. 
  The 
  grid 
  is 
  flipping. 
  And 
  if 
  
HECO 
  doesn’t 
  reinvent 
  itself 
  in 
  a 
  big 
  way—and 
  soon—it 
  could 
  go 
  the 
  way 
  of 
  the 
  landline. 
  
 
  
That 
  might 
  sound 
  like 
  the 
  ravings 
  of 
  technology 
  futurists 
  or 
  the 
  wishful 
  thinking 
  of 
  HECO 
  haters, 
  but 
  it’s 
  
actually 
  what 
  the 
  electric 
  utility 
  industry 
  itself 
  is 
  saying. 
  
 
  
The 
  Edison 
  Electric 
  Institute, 
  the 
  trade 
  group 
  for 
  investor-­‐owned 
  electric 
  companies, 
  such 
  as 
  HECO, 
  
warns 
  that 
  solar 
  panels 
  and 
  other 
  emerging 
  technologies 
  pose 
  a 
  serious 
  threat 
  to 
  the 
  industry’s 
  health, 
  
well-­‐being 
  and 
  shareholders. 
  In 
  a 
  landmark 
  report 
  that 
  made 
  a 
  big 
  splash 
  in 
  wonky 
  energy-­‐policy 
  circles 
  
last 
  year, 
  the 
  Institute 
  said: 
  
 
  
“One 
  can 
  imagine 
  when 
  battery 
  storage 
  technology 
  or 
  micro 
  turbines 
  could 
  allow 
  customers 
  to 
  be 
  
electric 
  grid 
  independent. 
  To 
  put 
  this 
  in 
  perspective, 
  who 
  would 
  have 
  believed 
  10 
  years 
  ago 
  that 
  
traditional 
  wire 
  line 
  telephone 
  customers 
  could 
  economically 
  ‘cut 
  the 
  cord?’” 
  
 
  
See? 
  
 
  
The 
  Institute 
  warned 
  of 
  a 
  death-­‐spiral 
  scenario, 
  in 
  which 
  utilities 
  make 
  up 
  for 
  the 
  revenue 
  lost 
  on 
  their 
  
PV-­‐owning 
  customers 
  by 
  raising 
  the 
  rates 
  on 
  their 
  other 
  customers. 
  That 
  encourages 
  some 
  of 
  them 
  to 
  
get 
  PV, 
  which 
  sends 
  rates 
  even 
  higher, 
  which 
  makes 
  PV 
  even 
  more 
  attractive. 
  Edison 
  suggested 
  that 
  a 
  
short-­‐term 
  solution 
  is 
  for 
  utilities 
  to 
  go 
  after 
  their 
  free-­‐riding 
  PV 
  customers, 
  who 
  are 
  enjoying 
  all 
  the 
  
3 
  
 
  

 benefits 
  of 
  having 
  the 
  grid 
  as 
  their 
  backup 
  battery 
  while 
  barely 
  paying 
  a 
  thing 
  for 
  the 
  privilege. 
  In 
  the 
  
long 
  run, 
  utilities 
  must 
  deal 
  with 
  “the 
  threat 
  of 
  disruptive 
  forces” 
  and 
  assess 
  “new 
  business 
  models 
  
where 
  utilities 
  can 
  add 
  value 
  to 
  customers 
  and 
  investors 
  by 
  providing 
  new 
  services.” 
  In 
  other 
  words, 
  
figure 
  out 
  how 
  to 
  remain 
  relevant 
  while 
  they 
  still 
  can. 
  What 
  that 
  would 
  look 
  like, 
  Edison 
  didn’t 
  say. 
  
 
  
For 
  its 
  part, 
  HECO 
  says 
  it 
  is 
  well 
  aware 
  of 
  Hawaii’s 
  rapidly 
  changing 
  energy 
  landscape, 
  and 
  it 
  is 
  adapting. 
  
“We 
  are 
  engineering 
  the 
  ‘reinvention’ 
  you 
  ask 
  about 
  right 
  now 
  while 
  we 
  keep 
  service 
  to 
  our 
  customers 
  
as 
  safe, 
  reliable 
  and 
  low-­‐cost 
  as 
  possible,” 
  said 
  Scott 
  Seu, 
  HECO’s 
  vice 
  president 
  of 
  energy 
  resources 
  and 
  
operations, 
  in 
  a 
  written 
  statement 
  to 
  HONOLULU 
  Magazine. 
  What 
  that 
  reinvention 
  will 
  look 
  like, 
  Seu 
  
didn’t 
  say. 
  
 
  
Energy 
  experts 
  fear 
  that 
  HECO 
  isn’t 
  moving 
  fast 
  enough, 
  and 
  that 
  if 
  the 
  utility 
  ever 
  fails, 
  taxpayers 
  will 
  be 
  
on 
  the 
  hook. 
  “We’re 
  all 
  looking 
  for 
  HECO 
  to 
  lay 
  out 
  a 
  clear 
  pathway 
  in 
  which 
  it 
  can 
  possibly 
  operate 
  and 
  
prosper 
  in 
  this 
  new 
  energy 
  climate,” 
  says 
  Mark 
  Glick, 
  head 
  of 
  the 
  state 
  Energy 
  Office. 
  “We 
  haven’t 
  seen 
  
that 
  yet.” 
  
 
  
Last 
  fall, 
  state 
  Rep. 
  Chris 
  Lee, 
  chair 
  of 
  the 
  House 
  Committee 
  on 
  Energy 
  and 
  Environmental 
  Protection, 
  
put 
  HECO 
  executives 
  on 
  the 
  spot 
  at 
  a 
  legislative 
  briefing 
  when 
  he 
  asked 
  how 
  the 
  utility 
  planned 
  to 
  adapt 
  
if 
  customers 
  started 
  leaving 
  the 
  grid 
  altogether. 
  HECO 
  executives 
  could 
  not 
  give 
  him 
  an 
  answer. 
  
 
  
“I 
  really 
  think 
  HECO 
  is 
  on 
  a 
  very 
  short 
  timeline,” 
  Lee 
  says. 
  “They 
  probably 
  have 
  a 
  few 
  years 
  left 
  to 
  
radically 
  change 
  their 
  business 
  model 
  and 
  the 
  way 
  they 
  operate 
  to 
  keep 
  up 
  with 
  the 
  changing 
  
technology 
  and 
  the 
  marketplace, 
  which 
  could 
  very 
  well 
  leave 
  them 
  in 
  irrelevancy.” 
  
Even 
  without 
  the 
  gloomy 
  forecasts 
  of 
  its 
  demise, 
  HECO 
  had 
  a 
  rough 
  2013. 
  The 
  utility’s 
  five-­‐year 
  plan 
  for 
  
meeting 
  the 
  state’s 
  ambitious 
  renewable 
  energy 
  goals 
  was 
  harshly 
  critiqued 
  by 
  the 
  state. 
  HECO’s 
  
regulator, 
  the 
  Public 
  Utilities 
  Commission, 
  filled 
  by 
  Gov. 
  Neil 
  Abercrombie 
  with 
  fresh 
  appointees, 
  
asserted 
  that 
  it 
  would 
  no 
  longer 
  play 
  the 
  traditional 
  role 
  of 
  rubber 
  stamp. 
  Robbie 
  Alm, 
  the 
  long-­‐time 
  
public 
  face 
  of 
  HECO, 
  stepped 
  down 
  in 
  July, 
  and 
  by 
  the 
  end 
  of 
  the 
  year 
  he 
  had 
  yet 
  to 
  be 
  replaced. 
  On 
  top 
  
of 
  all 
  that, 
  Hawaii’s 
  booming 
  solar 
  industry 
  continued 
  to 
  load 
  the 
  electric 
  grid 
  with 
  unprecedented 
  
amounts 
  of 
  intermittent 
  PV 
  power, 
  enabling 
  an 
  increasing 
  number 
  of 
  HECO 
  customers 
  to 
  slash 
  their 
  
electric 
  bills. 
  
 
  
The 
  solar 
  industry 
  in 
  Hawaii 
  has 
  quickly 
  grown 
  into 
  a 
  force 
  to 
  be 
  contended 
  with, 
  roughly 
  doubling 
  in 
  
size 
  each 
  year 
  from 
  2008 
  to 
  2012. 
  Rapidly 
  dropping 
  PV 
  prices 
  combined 
  with 
  generous 
  tax 
  credits, 
  the 
  
highest 
  electricity 
  rates 
  in 
  the 
  nation 
  and 
  the 
  abundance 
  of 
  Hawaii 
  sunshine 
  drove 
  this 
  meteoric 
  growth 
  
and 
  drew 
  hundreds 
  of 
  contractors 
  and 
  other 
  businesses—some 
  more 
  reputable 
  than 
  others—to 
  the 
  
gold 
  rush. 
  
 
  
Installations 
  peaked 
  in 
  2012, 
  when 
  more 
  PV 
  was 
  installed 
  than 
  in 
  all 
  the 
  previous 
  years 
  combined. 
  The 
  
industry 
  slowed 
  a 
  bit 
  as 
  it 
  entered 
  2013, 
  thanks 
  in 
  part 
  to 
  new 
  Department 
  of 
  Taxation 
  rules 
  that 
  closed 
  
a 
  loophole 
  allowing 
  homeowners 
  to 
  claim 
  multiple 
  tax 
  credits 
  for 
  the 
  same 
  PV 
  project. 
  Then, 
  last 
  
September, 
  it 
  slammed 
  into 
  a 
  wall. 
  
 
  
That’s 
  when 
  HECO 
  announced 
  that 
  so 
  much 
  PV 
  had 
  been 
  connected 
  to 
  parts 
  of 
  Oahu’s 
  electric 
  grid, 
  
some 
  circuits 
  simply 
  couldn’t 
  take 
  anymore. 
  Of 
  the 
  416 
  individual 
  circuits 
  the 
  grid 
  comprises, 
  81 
  of 
  
them, 
  or 
  19 
  percent, 
  were 
  saturated 
  with 
  solar, 
  the 
  utility 
  said 
  at 
  the 
  time. 
  Adding 
  more 
  PV 
  to 
  maxed-­‐
out 
  circuits 
  raised 
  the 
  potential 
  for 
  voltage 
  spikes, 
  which 
  could 
  cause 
  problems 
  ranging 
  from 
  flickering 
  
4 
  
 
  

 lights 
  to 
  electrocuted 
  powerline 
  workers. 
  
 
   
  
From 
  that 
  point 
  onward, 
  HECO 
  declared, 
  would-­‐be 
  PV 
  customers 
  must 
  contact 
  the 
  utility 
  to 
  find 
  out 
  
whether 
  or 
  not 
  there 
  was 
  room 
  on 
  the 
  circuit 
  for 
  them 
  before 
  they 
  installed 
  their 
  solar 
  systems. 
  If 
  there 
  
was 
  room, 
  the 
  customer 
  might 
  have 
  to 
  foot 
  the 
  bill 
  for 
  equipment 
  upgrades 
  to 
  protect 
  the 
  grid. 
  
Furthermore, 
  studies 
  would 
  have 
  to 
  be 
  done 
  before 
  PV 
  projects 
  could 
  proceed. 
  How 
  much 
  the 
  upgrades 
  
might 
  cost 
  or 
  how 
  long 
  the 
  studies 
  might 
  take, 
  HECO 
  couldn’t 
  say. 
  But 
  according 
  to 
  reports 
  from 
  the 
  
Neighbor 
  Islands, 
  where 
  HECO’s 
  sister 
  companies 
  have 
  implemented 
  similar 
  policies, 
  customers 
  were 
  
waiting 
  12 
  to 
  18 
  months 
  to 
  find 
  out 
  if 
  they 
  could 
  even 
  hook 
  their 
  solar 
  systems 
  onto 
  the 
  grid, 
  and 
  
equipment 
  upgrades 
  cost 
  them 
  thousands 
  of 
  dollars. 
  
 
  
Homeowners 
  hoping 
  to 
  put 
  PV 
  on 
  their 
  roofs 
  were 
  thrown 
  into 
  solar 
  limbo, 
  with 
  hundreds 
  of 
  planned 
  
installations 
  put 
  on 
  hold. 
  Solar 
  contractors 
  screamed 
  foul. 
  Legislators 
  held 
  briefings. 
  
 
  
A 
  group 
  of 
  stakeholders 
  was 
  assembled 
  to 
  explore 
  workarounds 
  that 
  might 
  allow 
  the 
  utility 
  to 
  scooch 
  up 
  
the 
  PV 
  saturation 
  threshold 
  a 
  bit. 
  By 
  the 
  end 
  of 
  the 
  year, 
  though, 
  no 
  scooching 
  had 
  been 
  announced. 
  
 
  
In 
  the 
  meantime, 
  the 
  solar 
  industry 
  found 
  its 
  own 
  workaround: 
  batteries. 
  
 
  
Off-­‐the-­‐grid 
  hippies 
  on 
  the 
  Neighbor 
  Islands 
  have 
  been 
  using 
  them 
  with 
  their 
  PV 
  systems 
  for 
  decades. 
  
Why 
  not 
  Oahu 
  residents 
  in 
  solar-­‐saturated 
  neighborhoods? 
  As 
  long 
  as 
  excess 
  energy 
  is 
  stored 
  in 
  the 
  
batteries 
  and 
  not 
  pushed 
  back 
  onto 
  the 
  grid, 
  the 
  reasoning 
  went, 
  the 
  voltage 
  spike 
  problem 
  was 
  solved. 
  
So 
  too 
  was 
  the 
  problem 
  of 
  marketing 
  PV 
  in 
  solar-­‐saturated 
  neighborhoods. 
  A 
  PV 
  owner 
  opting 
  for 
  
batteries 
  wouldn’t 
  be 
  able 
  to 
  participate 
  in 
  HECO’s 
  net-­‐energy-­‐metering 
  program, 
  in 
  which 
  the 
  excess 
  
solar 
  watts 
  a 
  home 
  produces 
  are 
  credited 
  against 
  whatever 
  watts 
  the 
  home 
  draws 
  from 
  the 
  grid 
  when 
  
it’s 
  dark 
  or 
  cloudy. 
  But 
  that 
  would 
  hardly 
  matter 
  to 
  someone 
  on 
  a 
  maxed-­‐out 
  circuit 
  who 
  wanted 
  solar 
  
badly 
  enough. 
  
 
  
With 
  encouragement 
  from 
  the 
  Hawaii 
  Solar 
  Energy 
  Association, 
  which 
  held 
  battery 
  seminars 
  last 
  fall 
  to 
  
bring 
  its 
  members 
  up 
  to 
  speed, 
  solar 
  contractors 
  began 
  touting 
  batteries 
  as 
  the 
  solution 
  to 
  HECO’s 
  
roadblocks. 
  “Get 
  solar 
  now,” 
  one 
  full-­‐page 
  newspaper 
  ad 
  read. 
  “No 
  waiting 
  for 
  utility 
  approval. 
  No 
  
added 
  grid 
  upgrade 
  costs.” 
  
 
  
“We 
  are 
  so 
  much 
  more 
  flexible 
  than 
  the 
  utility,” 
  says 
  Rolf 
  Christ, 
  HSEA’s 
  secretary 
  and 
  owner 
  of 
  
Hawaiian 
  Island 
  Solar. 
  “If 
  they 
  throw 
  one 
  rule 
  at 
  us, 
  we 
  throw 
  a 
  solution 
  back. 
  Nobody 
  can 
  afford 
  to 
  just 
  
stop 
  installing.” 
  
 
  
Then 
  HECO 
  cleared 
  its 
  throat 
  and 
  clarified 
  the 
  rules. 
  In 
  the 
  final 
  days 
  of 
  2013 
  it 
  began 
  running 
  its 
  own 
  
newspaper 
  ads 
  to 
  explain 
  that, 
  as 
  long 
  as 
  a 
  home 
  is 
  still 
  attached 
  to 
  the 
  grid, 
  batteries 
  don’t 
  change 
  a 
  
thing. 
  “PV 
  systems 
  with 
  battery 
  backup 
  must 
  also 
  get 
  an 
  initial 
  review 
  by 
  your 
  utility 
  to 
  ensure 
  the 
  
interconnection 
  is 
  done 
  right,” 
  the 
  ad 
  stated. 
  “PV 
  systems 
  that 
  are 
  prematurely 
  interconnected 
  could 
  be 
  
turned 
  off 
  by 
  your 
  utility.” 
  
While 
  demand 
  for 
  battery 
  systems 
  on 
  Oahu 
  has 
  hardly 
  been 
  overwhelming, 
  there 
  have 
  been 
  a 
  few 
  
takers. 
  Bernie 
  Boltz, 
  who 
  lives 
  in 
  a 
  PV-­‐saturated 
  Aina 
  Haina 
  neighborhood, 
  is 
  one 
  of 
  them. 
  His 
  $43,000 
  
system 
  (before 
  tax 
  credits) 
  features 
  a 
  dozen 
  12-­‐volt 
  lead 
  batteries, 
  which 
  look 
  a 
  lot 
  like 
  ordinary 
  car 
  
batteries 
  and 
  fit 
  into 
  an 
  outdoor 
  utility 
  closet. 
  The 
  system 
  was 
  so 
  new 
  it 
  was 
  being 
  installed 
  in 
  December 
  
as 
  HONOLULU 
  Magazine 
  watched, 
  right 
  before 
  HECO 
  clarified 
  the 
  rules. 
  “I 
  don’t 
  think 
  it 
  was 
  a 
  great 
  leap 
  
5 
  
 
  

 of 
  faith 
  to 
  do 
  this,” 
  Boltz 
  said 
  at 
  the 
  time. 
  “I 
  couldn’t 
  get 
  solar 
  any 
  other 
  way.” 
  
 
  
Not 
  everyone 
  in 
  the 
  industry 
  jumped 
  on 
  the 
  battery 
  bandwagon. 
  Mark 
  Duda, 
  vice 
  president 
  of 
  
RevoluSun, 
  believes 
  the 
  daily 
  attention 
  to 
  voltage 
  and 
  other 
  hassles 
  that 
  current 
  battery 
  technology 
  
entails 
  are 
  more 
  than 
  most 
  customers 
  are 
  ready 
  for. 
  “In 
  our 
  judgment, 
  it’s 
  not 
  the 
  right 
  answer 
  for 
  most 
  
people,” 
  he 
  says. 
  
 
  
Duda 
  is 
  part 
  of 
  the 
  working 
  group 
  that’s 
  been 
  exploring 
  ways 
  to 
  raise 
  the 
  PV 
  saturation 
  threshold. 
  He’s 
  
optimistic 
  that 
  a 
  fix 
  can 
  be 
  found 
  and 
  that 
  HECO 
  will 
  eventually 
  embrace 
  more 
  widespread 
  use 
  of 
  home 
  
PV. 
  “Hopefully, 
  this 
  is 
  the 
  point 
  where 
  they 
  get 
  on 
  the 
  path 
  to 
  living 
  with 
  PV 
  in 
  a 
  meaningful 
  way, 
  
accepting 
  it 
  as 
  a 
  large 
  share 
  of 
  generation, 
  and 
  starting 
  to 
  work 
  really 
  seriously 
  on 
  a 
  business 
  model 
  that 
  
works 
  in 
  that 
  context 
  for 
  them 
  and 
  all 
  of 
  the 
  ratepayers,” 
  he 
  says. 
  
 
  
Still, 
  he 
  can 
  envision 
  a 
  day 
  when 
  the 
  technology 
  and 
  the 
  economics 
  of 
  severing 
  your 
  ties 
  to 
  HECO 
  
altogether 
  start 
  to 
  make 
  sense. 
  Says 
  Duda: 
  “I 
  think 
  that 
  at 
  some 
  point 
  we’ll 
  be 
  in 
  a 
  situation 
  where 
  the 
  
customer 
  will 
  be 
  able 
  to 
  say 
  to 
  the 
  utility, 
  ‘What’s 
  in 
  it 
  for 
  me? 
  Convince 
  me 
  to 
  stay.’ 
  That 
  will 
  be 
  a 
  really 
  
interesting 
  time.” 
  
SOLAR 
  BY 
  THE 
  NUMBERS 
  
Hawaii’s 
  historically 
  sky-­‐high 
  cost 
  of 
  conventional 
  electricity 
  has 
  fueled 
  a 
  boom 
  in 
  residents 
  and 
  
businesses 
  investing 
  in 
  photovoltaic 
  systems 
  to 
  get 
  away 
  from 
  fossil 
  fuels. 
  The 
  steep 
  increase 
  slowed 
  last 
  
year 
  in 
  the 
  wake 
  of 
  tougher 
  tax 
  credits 
  and 
  saturated 
  neighborhoods. 
  Expect 
  more 
  proposed 
  changes 
  to 
  
the 
  state’s 
  renewable 
  energy 
  tax 
  credit 
  as 
  lawmakers 
  learn 
  how 
  much 
  the 
  credits 
  have 
  cost 
  the 
  general 
  
fund 
  coffers 
  so 
  far. 
  
KNOW 
  YOUR 
  RENEWABLES 
  
Hawaii 
  has 
  a 
  rich 
  variety 
  of 
  potential 
  renewable 
  energy 
  sources. 
  Here's 
  a 
  quick 
  guide. 
  
SOLAR 
  
Nearly 
  one 
  out 
  of 
  10 
  residential 
  rooftops 
  on 
  Oahu 
  is 
  now 
  adorned 
  with 
  solar 
  photovoltaic 
  panels. 
  
There’s 
  so 
  much 
  PV 
  out 
  there 
  that 
  Hawaiian 
  Electric 
  Co. 
  has 
  slapped 
  a 
  virtual 
  moratorium 
  on 
  adding 
  any 
  
more 
  in 
  some 
  neighborhoods 
  while 
  it 
  studies 
  the 
  technical 
  issues 
  involved 
  with 
  having 
  unprecedented 
  
amounts 
  homemade 
  power 
  on 
  the 
  grid. 
  (See 
  main 
  story.) 
  
 
  
Meanwhile, 
  HECO 
  is 
  seeking 
  fast-­‐track 
  approval 
  from 
  the 
  Public 
  Utilities 
  Commission 
  to 
  have 
  nine 
  large-­‐
scale 
  solar 
  farms 
  developed. 
  They 
  would 
  produce 
  about 
  240 
  megawatts 
  of 
  power 
  and 
  offer 
  some 
  relief 
  
to 
  ratepayers 
  from 
  the 
  high 
  cost 
  of 
  fuel 
  oil. 
  The 
  utility 
  says 
  power 
  from 
  the 
  solar 
  farms 
  would 
  cost 
  about 
  
15.8 
  cents 
  per 
  kilowatt 
  hour, 
  compared 
  with 
  rates 
  as 
  high 
  as 
  22.7 
  cents 
  per 
  kilowatt 
  hour 
  at 
  its 
  fossil-­‐
fuel-­‐fired 
  power 
  plants. 
  
 
  
What 
  to 
  watch: 
  Where 
  will 
  all 
  of 
  these 
  solar 
  farms 
  be 
  built? 
  How 
  much 
  land 
  will 
  they 
  need? 
  And 
  which—
if 
  any—of 
  HECO’s 
  fossil-­‐fuel-­‐run 
  power 
  stations 
  will 
  be 
  decommissioned 
  when 
  the 
  solar 
  farms 
  come 
  
online? 
  So 
  far, 
  HECO’s 
  not 
  saying. 
  
WIND 
  
A 
  proposed 
  wind 
  farm 
  on 
  Molokai 
  was 
  defeated 
  by 
  intense 
  local 
  resistance. 
  A 
  similar 
  project 
  on 
  Lanai 
  
appears 
  all 
  but 
  dead. 
  Kauai 
  might 
  have 
  too 
  many 
  endangered 
  native 
  birds 
  to 
  introduce 
  the 
  giant, 
  bird-­‐
killing 
  blades 
  of 
  wind 
  turbines 
  into 
  the 
  environment. 
  But 
  successful 
  wind 
  farms 
  have 
  been 
  built 
  on 
  Oahu, 
  
6 
  
 
  

 Maui 
  and 
  the 
  Big 
  Island. 
  Their 
  combined 
  output 
  accounts 
  for 
  some 
  30 
  percent 
  of 
  all 
  the 
  renewable 
  
energy 
  in 
  the 
  state. 
  
 
  
While 
  Maui 
  and 
  the 
  Big 
  Island 
  have 
  Hawaii’s 
  best 
  wind-­‐farm-­‐quality 
  wind, 
  O‘ahu 
  is 
  doing 
  its 
  part 
  with 
  
two 
  wind 
  farms 
  on 
  the 
  North 
  Shore. 
  The 
  30-­‐megawatt, 
  12-­‐turbine 
  Kahuku 
  Wind 
  Farm 
  began 
  generating 
  
electricity 
  in 
  2011. 
  A 
  2012 
  battery 
  fire 
  knocked 
  it 
  out 
  of 
  commission 
  for 
  more 
  than 
  a 
  year, 
  but 
  it 
  went 
  
back 
  online 
  in 
  late 
  2013. 
  Also 
  in 
  2012, 
  the 
  69-­‐megawatt 
  Kawailoa 
  
 
  
Wind 
  project 
  on 
  the 
  hills 
  outside 
  of 
  Haleiwa 
  came 
  online. 
  Its 
  30 
  enormous 
  turbines 
  can 
  be 
  seen 
  for 
  miles 
  
around, 
  outraging 
  some 
  North 
  Shore 
  residents 
  who 
  object 
  to 
  the 
  visual 
  impact. 
  A 
  third 
  wind 
  farm 
  has 
  
been 
  proposed 
  for 
  development 
  in 
  Kahuku, 
  but 
  it’s 
  far 
  from 
  a 
  done 
  deal. 
  
 
  
What 
  to 
  watch: 
  The 
  Oahu-­‐Maui 
  grid 
  tie-­‐in. 
  Oahu 
  doesn’t 
  have 
  the 
  best 
  wind 
  or 
  many 
  more 
  suitable 
  sites 
  
for 
  wind 
  farms, 
  but 
  Maui’s 
  got 
  wind 
  to 
  spare. 
  If 
  the 
  interisland 
  cable 
  connection 
  that 
  the 
  state 
  is 
  pushing 
  
becomes 
  reality, 
  wind 
  power 
  could 
  light 
  up 
  more 
  Honolulu 
  homes 
  than 
  ever. 
  
GEOTHERMAL 
  
The 
  development 
  of 
  geothermal 
  energy, 
  which 
  taps 
  volcanic 
  steam 
  found 
  a 
  mile 
  or 
  more 
  beneath 
  the 
  
earth’s 
  surface, 
  is 
  a 
  high 
  priority 
  among 
  state 
  energy 
  planners. 
  Hawaii’s 
  only 
  existing 
  geothermal 
  plant, 
  
Puna 
  Geothermal 
  Venture, 
  produces 
  about 
  20 
  percent 
  of 
  all 
  the 
  renewable 
  energy 
  generated 
  in 
  the 
  
state—every 
  watt 
  of 
  which 
  stays 
  on 
  the 
  Big 
  Island. 
  The 
  Island’s 
  electric 
  utility, 
  the 
  Hawaii 
  Electric 
  Light 
  
Co., 
  wants 
  to 
  up 
  the 
  Island’s 
  current 
  38 
  megawatts 
  of 
  production 
  to 
  88 
  megawatts. 
  The 
  state 
  and 
  Hawaii 
  
County 
  are 
  battling 
  over 
  who 
  gets 
  to 
  decide 
  where 
  that 
  future 
  development 
  would 
  occur. 
  Meanwhile, 
  
an 
  anti-­‐geothermal 
  movement 
  in 
  Puna 
  is 
  trying 
  to 
  block 
  further 
  development 
  there, 
  and 
  former 
  Native 
  
Hawaiian 
  opponents 
  of 
  geothermal—including 
  Mililani 
  Trask—are 
  now 
  part 
  of 
  a 
  venture 
  seeking 
  to 
  land 
  
the 
  next 
  geothermal 
  
development 
  contract. 
  
 
  
What 
  to 
  watch: 
  The 
  interisland 
  cable 
  grid 
  tie. 
  Ultimately, 
  the 
  state 
  wants 
  to 
  connect 
  the 
  electrical 
  grids 
  
of 
  Oahu, 
  Maui 
  and 
  the 
  Big 
  Island 
  via 
  undersea 
  cables. 
  If 
  it 
  succeeds, 
  Big 
  Island 
  volcanoes 
  could 
  one 
  day 
  
illuminate 
  Honolulu’s 
  skyline. 
   
  
BIOMASS 
  
Basically, 
  anything 
  that 
  can 
  be 
  burned 
  to 
  produce 
  power 
  counts 
  as 
  biomass. 
  In 
  Hawaii 
  that 
  ranges 
  from 
  
the 
  municipal 
  waste 
  incinerated 
  at 
  Honolulu 
  County’s 
  HPOWER 
  plant 
  to 
  the 
  eucalyptus 
  trees 
  Hawaii 
  
Electric 
  Light 
  Co. 
  plans 
  to 
  burn 
  on 
  the 
  Big 
  Island. 
  
 
  
What 
  to 
  watch: 
  A 
  Mainland 
  company 
  called 
  Zilkha 
  Biomass 
  Energy 
  is 
  vying 
  to 
  supply 
  HECO’s 
  Kalaeloa 
  
power 
  plant 
  with 
  “black 
  pellets” 
  made 
  from 
  diseased 
  trees 
  harvested 
  from 
  the 
  pine-­‐bark-­‐beetle-­‐infested 
  
forests 
  of 
  British 
  Columbia. 
  
HYDROELECTRIC 
  
Hawaii’s 
  granddaddy 
  of 
  renewables 
  dates 
  to 
  1888, 
  when 
  the 
  newfangled 
  electric 
  light 
  bulbs 
  of 
  Honolulu 
  
were 
  powered 
  by 
  turbines 
  spun 
  by 
  the 
  flowing 
  water 
  of 
  Nuuanu 
  Stream. 
  Hydro 
  no 
  longer 
  lights 
  the 
  city, 
  
but 
  it 
  still 
  has 
  a 
  place 
  on 
  Neighbor 
  Island 
  electric 
  grids. 
  Eight 
  hydro 
  plants 
  on 
  rainy 
  Kauai 
  (including 
  one 
  
dating 
  to 
  1908) 
  generate 
  nearly 
  10 
  percent 
  of 
  the 
  Island’s 
  power. 
  According 
  to 
  a 
  2013 
  study 
  by 
  the 
  Oak 
  
Ridge 
  National 
  Laboratory 
  National 
  Hydropower 
  Asset 
  Assessment 
  Program, 
  Hawaii 
  has 
  the 
  potential 
  to 
  
develop 
  145 
  megawatts 
  of 
  new 
  hydropower. 
  
7 
  
 
  

  
  
What 
  to 
  watch: 
  Molokai. 
  A 
  proposed 
  project 
  there 
  would 
  use 
  excess 
  solar 
  power 
  to 
  pump 
  water 
  to 
  an 
  
uphill 
  storage 
  reservoir 
  during 
  the 
  day. 
  At 
  night, 
  the 
  water 
  would 
  flow 
  to 
  a 
  lower 
  reservoir, 
  generating 
  
hydropower 
  along 
  the 
  way. 
  This 
  “pumped 
  storage 
  hydro” 
  project 
  is 
  in 
  the 
  early 
  stages 
  of 
  development, 
  
but 
  if 
  all 
  goes 
  as 
  planned, 
  it 
  could 
  produce 
  80 
  to 
  90 
  percent 
  of 
  Molokai’s 
  electricity. 
  
OCEAN 
  
Experiments 
  in 
  harnessing 
  wave 
  energy 
  have 
  been 
  underway 
  in 
  the 
  waters 
  off 
  Marine 
  Corps 
  Base 
  
Hawaii 
  since 
  2004. 
  A 
  milestone 
  was 
  reached 
  in 
  2010 
  when 
  the 
  first 
  wave-­‐generated 
  electricity 
  ever 
  
transmitted 
  to 
  a 
  U.S. 
  electrical 
  grid 
  was 
  produced 
  by 
  a 
  yellow, 
  40-­‐kilowatt 
  buoy 
  bobbing 
  off 
  the 
  base. 
  
The 
  research 
  continues. 
  
 
  
Meanwhile, 
  at 
  Keahole 
  Point 
  on 
  the 
  Big 
  Island, 
  research 
  continues 
  into 
  ocean 
  thermal 
  energy 
  conversion 
  
(OTEC), 
  which 
  generates 
  power 
  using 
  the 
  temperature 
  differences 
  between 
  deep 
  sea 
  water 
  and 
  warm 
  
surface 
  waters. 
  OTEC 
  has 
  been 
  in 
  development 
  since 
  the 
  1970s, 
  but 
  no 
  commercial 
  OTEC 
  plant 
  has 
  been 
  
built. 
  Yet. 
  
 
  
What 
  to 
  watch: 
  HECO 
  has 
  been 
  in 
  talks 
  with 
  a 
  handful 
  of 
  developers 
  to 
  build 
  an 
  OTEC 
  plant 
  on 
  O‘ahu’s 
  
west 
  side. 
  Look 
  for 
  a 
  possible 
  deal 
  to 
  be 
  announced 
  this 
  year. 
  
BIOFUEL 
  
Biofuels 
  offer 
  the 
  promise 
  of 
  replacing 
  or 
  blending 
  liquid 
  fossil 
  fuels 
  with 
  liquid 
  fuel 
  made 
  from 
  plant 
  
oils. 
  Biodiesel, 
  for 
  instance, 
  has 
  long 
  been 
  made 
  in 
  the 
  Islands 
  from 
  used 
  cooking 
  oil 
  and 
  grease 
  trap 
  
waste 
  from 
  restaurants. 
  Fuel 
  oil 
  and 
  jet 
  fuel 
  can 
  also 
  be 
  produced 
  from 
  vegetable 
  oils. 
  According 
  to 
  the 
  
Hawaii 
  State 
  Energy 
  Office, 
  Hawaii 
  has 
  136,000 
  acres 
  of 
  unused 
  farm 
  land 
  that 
  could 
  be 
  planted 
  in 
  
biofuel 
  crops—enough 
  to 
  produce 
  roughly 
  160 
  million 
  gallons 
  of 
  oil 
  per 
  year. 
  If 
  industrial 
  scale 
  
production 
  of 
  biofuel 
  crops 
  on 
  agricultural 
  land 
  ever 
  takes 
  off, 
  it 
  will 
  require 
  massive 
  amounts 
  of 
  water, 
  
which 
  will 
  inevitably 
  lead 
  to 
  conflicts. 
  
 
  
What 
  to 
  watch: 
  Algae. 
  Are 
  these 
  fast-­‐growing 
  aquatic 
  life 
  forms 
  the 
  biofuel 
  crop 
  of 
  the 
  future? 
  A 
  pilot 
  
project 
  using 
  marine 
  algae 
  to 
  produce 
  biofuel 
  is 
  underway 
  on 
  the 
  Big 
  Island, 
  and 
  another 
  is 
  planned 
  for 
  a 
  
34-­‐acre 
  site 
  near 
  Wahiawa. 
  

Solar 
  Panel 
  Installations 
  Push 
  Electric 
  Utilities 
  to 
  the 
  Brink 
    
  West 
  Hawaii 
  Today 
    
  Colin 
  
Stewart 
    
  2/2/14 
  

http://westhawaiitoday.com/news/local-­‐news/solar-­‐panel-­‐installations-­‐push-­‐electric-­‐utilities-­‐brink 
   
  

As 
  a 
  result 
  of 
  the 
  high 
  number 
  of 
  rooftop 
  solar 
  photovoltaic 
  installations 
  in 
  2013, 
  Hawaii’s 
  electric 
  
utilities 
  are 
  warning 
  that 
  some 
  areas 
  are 
  reaching 
  the 
  saturation 
  point. 
  
Meanwhile, 
  Big 
  Island 
  PV 
  system 
  installers 
  say 
  they’re 
  beginning 
  to 
  see 
  demand 
  for 
  their 
  services 
  slow 
  
as 
  competition 
  mounts. 
   
  
A 
  total 
  of 
  17,609 
  installations 
  were 
  performed 
  statewide 
  last 
  year, 
  adding 
  more 
  than 
  129 
  megawatts 
  in 
  
capacity 
  to 
  the 
  Hawaiian 
  Electric, 
  Maui 
  Electric 
  and 
  Hawaii 
  Electric 
  Light 
  Co. 
  grids. 
  That 
  represents 
  a 
  39 
  
percent 
  increase 
  compared 
  to 
  what 
  was 
  added 
  to 
  the 
  system 
  in 
  2012. 
   
  
As 
  of 
  Dec. 
  31, 
  Hawaiian 
  Electric 
  companies’ 
  grids 
  had 
  taken 
  on 
  a 
  total 
  of 
  40,159 
  photovoltaic 
  system 
  
interconnections, 
  generating 
  a 
  total 
  capacity 
  of 
  300 
  MW. 
  That 
  includes 
  5,355 
  installations 
  on 
  Hawaii 
  
Island, 
  producing 
  up 
  to 
  38 
  MW 
  of 
  electric 
  capacity. 
  That 
  number 
  represents 
  7 
  percent 
  of 
  Big 
  Island 
  
HELCO 
  customers. 
  
8 
  
 
  

 According 
  to 
  Hawaiian 
  Electric, 
  96 
  percent 
  of 
  the 
  state’s 
  solar 
  installations 
  use 
  net 
  metering, 
  a 
  program 
  
begun 
  in 
  2001 
  with 
  the 
  intention 
  of 
  encouraging 
  the 
  adoption 
  of 
  rooftop 
  solar. 
  The 
  program 
  allows 
  
customers 
  with 
  rooftop 
  solar 
  to 
  receive 
  full 
  retail 
  credit 
  for 
  energy 
  they 
  generate 
  and 
  send 
  to 
  the 
  
electric 
  grid. 
  They 
  use 
  that 
  credit 
  to 
  offset 
  the 
  costs 
  associated 
  with 
  energy 
  they 
  take 
  from 
  the 
  grid 
  
when 
  solar 
  power 
  doesn’t 
  meet 
  their 
  needs, 
  such 
  as 
  at 
  night 
  or 
  on 
  cloudy 
  days. 
   
  
The 
  “unprecedented 
  rapid 
  growth” 
  in 
  rooftop 
  solar 
  has 
  created 
  a 
  situation 
  where 
  some 
  neighborhood 
  
circuits 
  host 
  large 
  amounts 
  of 
  PV 
  systems, 
  with 
  an 
  increasing 
  number 
  of 
  those 
  circuits 
  reaching 
  points 
  
where 
  the 
  connected 
  PV 
  systems 
  generate 
  more 
  capacity 
  than 
  is 
  used 
  by 
  the 
  entire 
  circuit. 
   
  
“We 
  have 
  this 
  past 
  year 
  encountered 
  a 
  situation 
  where 
  the 
  amount 
  of 
  PV 
  that 
  people 
  are 
  applying 
  to 
  
connect 
  to 
  the 
  circuit 
  reaches 
  a 
  point 
  where 
  we 
  have 
  concerns, 
  either 
  with 
  the 
  voltage 
  quantity 
  or 
  
safety 
  issues,” 
  said 
  Jay 
  Ignacio, 
  HELCO 
  president. 
  “We’re 
  currently 
  at 
  the 
  level 
  (on 
  Hawaii 
  Island) 
  where 
  
10 
  percent 
  of 
  our 
  circuits 
  have 
  reached 
  that 
  point, 
  where 
  we 
  have 
  to 
  tell 
  people 
  applying 
  to 
  add 
  PV 
  that 
  
they 
  need 
  to 
  wait.” 
   
  
Ignacio 
  explained 
  that 
  circuits 
  that 
  generate 
  more 
  electricity 
  than 
  is 
  being 
  used 
  by 
  customers 
  can 
  create 
  
situations 
  where 
  voltage 
  is 
  increased 
  and 
  damage 
  can 
  be 
  done 
  to 
  electronic 
  equipment 
  in 
  homes 
  and 
  
businesses, 
  including 
  computers 
  and 
  other 
  appliances 
  that 
  may 
  contain 
  sophisticated 
  electronics. 
   
  
“If 
  there’s 
  more 
  generation 
  than 
  energy 
  being 
  used, 
  the 
  energy 
  needs 
  to 
  go 
  some 
  place. 
  … 
  This 
  is 
  a 
  
difficult 
  technical 
  issue, 
  and 
  we’re 
  not 
  aware 
  of 
  another 
  utility 
  in 
  the 
  world 
  that 
  has 
  addressed 
  it. 
  
There’s 
  no 
  model 
  for 
  us 
  to 
  follow, 
  no 
  resource 
  for 
  us 
  to 
  tap 
  into. 
  We’re 
  really 
  creating 
  new 
  frontiers 
  on 
  
this,” 
  he 
  said. 
   
  
Ignacio 
  admitted 
  that 
  delays 
  caused 
  by 
  “transient 
  over-­‐voltage” 
  can 
  be 
  very 
  frustrating 
  to 
  customers, 
  
but 
  said 
  that 
  as 
  of 
  right 
  now, 
  it’s 
  the 
  only 
  way 
  to 
  ensure 
  the 
  electric 
  grid 
  remains 
  safe 
  for 
  all 
  customers. 
   
  
HELCO 
  engineers 
  are 
  entertaining 
  several 
  different 
  ideas 
  to 
  handle 
  the 
  problem, 
  but 
  have 
  yet 
  to 
  settle 
  
on 
  anything 
  concrete. 
   
  
One 
  way 
  might 
  be 
  to 
  set 
  up 
  a 
  system 
  where 
  HELCO 
  can 
  use 
  appliances 
  connected 
  to 
  the 
  circuit 
  to 
  create 
  
more 
  of 
  a 
  load 
  when 
  it 
  encounters 
  an 
  over-­‐voltage. 
  By 
  transferring 
  the 
  excess 
  energy 
  into 
  something 
  
such 
  as 
  a 
  water 
  heater, 
  the 
  system 
  can 
  balance 
  itself 
  out. 
  But, 
  he 
  said, 
  many 
  of 
  those 
  appliances 
  were 
  
never 
  designed 
  for 
  such 
  a 
  purpose, 
  and 
  setting 
  them 
  up 
  to 
  be 
  used 
  in 
  such 
  a 
  way 
  could 
  be 
  problematic. 
   
  
Another 
  concept 
  being 
  explored 
  is 
  a 
  large 
  battery 
  bank 
  that 
  can 
  store 
  excess 
  energy. 
  That 
  too, 
  has 
  its 
  
drawbacks. 
   
  
“The 
  economics 
  of 
  such 
  a 
  system 
  just 
  may 
  not 
  play 
  out,” 
  he 
  said. 
   
  
Marco 
  Mangelsdorf, 
  president 
  of 
  Hilo-­‐based 
  photovoltaic 
  system 
  installer 
  ProVision 
  Solar, 
  said 
  that 
  
delays 
  customers 
  are 
  experiencing 
  have 
  not 
  yet 
  made 
  a 
  major 
  impact 
  on 
  his 
  business, 
  but 
  he 
  can 
  see 
  the 
  
writing 
  on 
  the 
  wall. 
   
  
“I 
  have 
  maybe 
  a 
  handful 
  of 
  clients 
  who 
  have 
  been 
  put 
  on 
  hold 
  because 
  of 
  a 
  saturated 
  circuit, 
  with 
  a 
  
number 
  of 
  customers 
  who 
  have 
  been 
  waiting 
  a 
  year,” 
  he 
  said. 
  “I’m 
  not 
  able 
  to 
  proceed 
  with 
  a 
  sale 
  
because 
  of 
  saturated 
  circuits. 
  But, 
  I 
  have 
  a 
  couple 
  of 
  colleagues 
  on 
  Oahu, 
  areas 
  with 
  much 
  higher 
  
population, 
  where 
  they’re 
  running 
  into 
  this. 
  They 
  say 
  that 
  it 
  could 
  be 
  50 
  or 
  60 
  percent 
  of 
  their 
  sales 
  are 
  
getting 
  the 
  red 
  light 
  from 
  HECO.” 
   
  
Meanwhile, 
  he 
  said, 
  last 
  year’s 
  boom 
  in 
  solar 
  sales 
  has 
  attracted 
  a 
  lot 
  of 
  competition. 
   
  
“When 
  we 
  started 
  in 
  1998, 
  we 
  had 
  maybe 
  five 
  or 
  10 
  competitors. 
  Now 
  there 
  are 
  dozens 
  and 
  dozens, 
  
including 
  a 
  number 
  of 
  folks 
  from 
  other 
  islands. 
  The 
  competition 
  is 
  beyond 
  fierce. 
  And 
  as 
  the 
  PV 
  pie 
  
9 
  
 
  

 continues 
  to 
  shrink, 
  which 
  is 
  what 
  we’re 
  witnessing, 
  we 
  know 
  that 
  the 
  competition 
  is 
  going 
  to 
  be 
  
unsustainable 
  at 
  this 
  profit 
  level. 
  I 
  think 
  we’re 
  going 
  to 
  see 
  a 
  consolidation 
  in 
  the 
  industry, 
  where 
  a 
  
number 
  of 
  major 
  and 
  minor 
  players 
  will 
  be 
  necessarily 
  dropping 
  out 
  because 
  of 
  the 
  contracting 
  pie,” 
  he 
  
said. 
   
  
Despite 
  the 
  gloomy 
  outlook, 
  however, 
  Mangelsdorf 
  said 
  he 
  has 
  been 
  impressed 
  with 
  HELCO’s 
  response 
  
to 
  the 
  technical 
  issues 
  that 
  are 
  helping 
  to 
  slow 
  his 
  industry’s 
  growth. 
   
  
“The 
  utility 
  companies 
  have 
  been 
  having 
  a 
  more 
  and 
  more 
  challenging 
  time 
  to 
  be 
  able 
  to 
  accommodate 
  
this 
  explosive 
  growth 
  in 
  PV,” 
  he 
  said. 
  “What 
  HELCO’s 
  been 
  doing, 
  and 
  I 
  salute 
  them 
  for 
  this, 
  is 
  they 
  are 
  
pushing 
  the 
  limits 
  as 
  to 
  just 
  how 
  much 
  an 
  isolated 
  island 
  utility 
  can 
  actually 
  accommodate 
  in 
  terms 
  of 
  
nonfirm 
  power 
  being 
  generated 
  and 
  fed 
  into 
  the 
  grid 
  — 
  not 
  just 
  big 
  plants, 
  but 
  including 
  mom-­‐and-­‐pop, 
  
residential 
  systems. 
   
  
“We 
  are 
  all 
  participating 
  in 
  a 
  grand 
  experiment. 
  How 
  far 
  can 
  a 
  utility 
  go 
  in 
  accepting 
  nonfirm 
  power? 
  As 
  
of 
  last 
  year, 
  more 
  than 
  40 
  percent 
  of 
  the 
  kilowatt 
  hours 
  sold 
  by 
  HELCO 
  came 
  from 
  renewable 
  resources. 
  
And 
  that 
  has 
  progressively 
  been 
  going 
  up.” 
   
  

In 
  Solar-­‐Energy 
  Debate, 
  Colorado 
  Homeowners, 
  Business 
  Get 
  Their 
  Say 
  at 
  PUC 
    
  The 
  Denver 
  
Post 
    
  Mark 
  Jaffe 
    
  2/3/14 
  
http://www.denverpost.com/business/ci_25054726/sides-­‐get-­‐their-­‐say-­‐solar-­‐energy-­‐
debate?IADID=Search-­‐www.denverpost.com-­‐www.denverpost.com 
   
  

Homeowners, 
  solar 
  installers 
  and 
  representatives 
  of 
  the 
  business 
  community 
  sparred 
  over 
  a 
  key 
  credit 
  
for 
  rooftop 
  solar 
  panels 
  at 
  a 
  Colorado 
  Public 
  Utilities 
  Commission 
  hearing 
  Monday. 
  
Xcel 
  Energy, 
  the 
  state's 
  largest 
  utility, 
  has 
  said 
  the 
  so-­‐called 
  net-­‐metering 
  credit, 
  currently 
  equal 
  to 
  
about 
  10.5 
  cents 
  for 
  each 
  kilowatt-­‐hour 
  a 
  residential 
  solar 
  system 
  puts 
  on 
  the 
  grid, 
  is 
  too 
  high. 
  
In 
  its 
  renewable-­‐energy 
  compliance 
  plan, 
  it 
  said 
  the 
  value 
  was 
  less 
  than 
  5 
  cents 
  a 
  kilowatt-­‐hour 
  and 
  
called 
  for 
  a 
  reduction 
  in 
  the 
  credit 
  since 
  non-­‐solar 
  customers 
  were 
  carrying 
  the 
  extra 
  cost. 
  
The 
  solar 
  industry 
  and 
  solar 
  advocates 
  challenged 
  Xcel's 
  figures, 
  saying 
  they 
  understated 
  solar's 
  value. 
  
Last 
  week, 
  the 
  commission 
  decided 
  to 
  create 
  a 
  separate 
  case 
  to 
  review 
  net 
  metering. 
  
At 
  Monday's 
  hearing, 
  held 
  by 
  Administrative 
  Law 
  Judge 
  Harris 
  Adams, 
  the 
  public 
  got 
  to 
  weigh 
  in 
  on 
  the 
  
issue. 
  
James 
  Hoffmeister, 
  a 
  retiree, 
  said 
  his 
  rooftop 
  installation 
  is 
  saving 
  him 
  $150 
  a 
  month. 
  
"It 
  is 
  a 
  big 
  mistake 
  if 
  the 
  energy 
  associated 
  with 
  rooftop 
  solar 
  is 
  not 
  valued," 
  Hoffmeister 
  said. 
  
Business 
  groups, 
  however, 
  voiced 
  concerns 
  about 
  the 
  cost 
  of 
  solar 
  and 
  its 
  impact 
  on 
  rates. 
  
"Keeping 
  energy 
  affordable 
  is 
  essential 
  to 
  the 
  economy 
  of 
  the 
  state," 
  said 
  Carly 
  West, 
  a 
  spokeswoman 
  
for 
  the 
  Colorado 
  Association 
  of 
  Commerce 
  and 
  Industry. 
  
Mizraim 
  Cordero, 
  director 
  of 
  the 
  Colorado 
  Competitive 
  Council, 
  said 
  net 
  metering 
  had 
  a 
  "hidden 
  subsidy 
  
— 
  not 
  everyone 
  is 
  paying 
  their 
  fair 
  share." 
  
Solar-­‐industry 
  representatives 
  countered 
  that 
  Colorado's 
  solar 
  policies 
  had 
  built 
  a 
  vibrant 
  industry 
  in 
  the 
  
state. 
  
The 
  industry 
  employs 
  3,600 
  Coloradans 
  with 
  a 
  private 
  investment 
  of 
  $187 
  million 
  in 
  the 
  state 
  in 
  2012, 
  
Hilary 
  Pearson, 
  a 
  representative 
  for 
  national 
  solar 
  installer 
  Sungevity, 
  testified. 
  
10 
  
 
  

 Another 
  recurring 
  point 
  raised 
  by 
  people 
  testifying 
  was 
  that 
  solar 
  provides 
  a 
  energy 
  source 
  free 
  of 
  
carbon, 
  which 
  is 
  released 
  in 
  burning 
  fossil 
  fuels, 
  and 
  has 
  been 
  linked 
  to 
  climate 
  change 
  in 
  scientific 
  
studies. 
  
"Net 
  metering 
  helps 
  us 
  move 
  to 
  a 
  clean 
  energy 
  grid," 
  said 
  Chris 
  Hoffman, 
  a 
  Boulder 
  resident 
  who 
  has 
  
solar 
  panels 
  on 
  his 
  roof. 
  

Path-­‐Breaking 
  Agreement 
  to 
  Get 
  More 
  Clean 
  Energy 
  into 
  Our 
  Electric 
  System 
    
  Energy 
  
Collective 
    
  Ralph 
  Cavanagh 
    
  2/13/14 
  

http://theenergycollective.com/nrdcswitchboard/340221/path-­‐breaking-­‐agreement-­‐get-­‐more-­‐clean-­‐
energy-­‐our-­‐electric-­‐system 
   
  
 
  
NRDC 
  and 
  the 
  Edison 
  Electric 
  Institute, 
  the 
  association 
  that 
  represents 
  all 
  of 
  the 
  nation’s 
  investor-­‐owned 
  
electric 
  utilities, 
  are 
  releasing 
  a 
  joint 
  statement 
  this 
  week 
  that 
  recommends 
  significant 
  changes 
  to 
  how 
  
the 
  utilities 
  providing 
  our 
  light 
  and 
  heat 
  are 
  regulated. 
  Our 
  aim 
  is 
  to 
  get 
  more 
  clean 
  energy 
  into 
  
America’s 
  electric 
  system, 
  while 
  offering 
  a 
  new 
  perspective 
  on 
  utilities’ 
  business 
  models. 
   
   
  
 
  
Why 
  is 
  it 
  a 
  big 
  deal 
  that 
  NRDC 
  has 
  reached 
  agreement 
  on 
  these 
  core 
  regulatory 
  issues 
  with 
  
an 
  association 
  that 
  represents 
  the 
  utilities 
  that 
  serve 
  more 
  than 
  220 
  million 
  Americans? 
   
  
 
  
Because 
  our 
  nation’s 
  utilities 
  have 
  the 
  opportunity 
  to 
  make 
  vital 
  contributions 
  to 
  clean 
  energy 
  progress 
  
as 
  investors 
  and 
  also 
  as 
  partners 
  with 
  innovators, 
  entrepreneurs 
  and 
  their 
  customers. 
  
 
  
We’re 
  releasing 
  the 
  statement 
  at 
  the 
  winter 
  meetings 
  of 
  the 
  National 
  Association 
  of 
  Regulatory 
  Utility 
  
Commissioners 
  in 
  Washington, 
  D.C., 
  for 
  the 
  reason 
  that 
  the 
  nation’s 
  utility 
  commissioners 
  make 
  key 
  rate 
  
decisions 
  that 
  can 
  support 
  utility 
  efforts 
  to 
  integrate 
  more 
  clean 
  energy 
  into 
  the 
  nation’s 
  electricity 
  grid. 
  
NRDC 
  believes 
  regulators 
  should 
  make 
  sure 
  that 
  utilities 
  that 
  do 
  well 
  with 
  clean 
  energy 
  are 
  rewarded 
  
appropriately 
  – 
  as 
  opposed 
  to 
  losing 
  money 
  automatically 
  when 
  electricity 
  sales 
  go 
  down, 
  which 
  is 
  too 
  
often 
  the 
  norm 
  today. 
   
  
 
  
No 
  longer 
  about 
  selling 
  more 
  electricity 
   
   
  
 
  
NRDC 
  and 
  EEI 
  agree 
  that 
  the 
  electric 
  utility 
  business 
  can 
  no 
  longer 
  be 
  about 
  selling 
  more 
  electricity. 
  
Instead, 
  it 
  needs 
  to 
  be 
  about 
  ensuring 
  that 
  people 
  have 
  reliable 
  and 
  steadily 
  
improving 
   
  electricityservices 
  (starting 
  with 
  heating, 
  lighting 
  and 
  cooling) 
  and 
  better 
  environmental 
  
quality. 
   
   
  
 
  
That, 
  in 
  turn, 
  will 
  require 
  getting 
  more 
  work 
  out 
  of 
  less 
  electricity 
  through 
  energy 
  efficiency 
  and 
  also 
  
creating 
  diversified 
  clean 
  energy 
  resource 
  portfolios 
  – 
  such 
  as 
  wind, 
  solar 
  and 
  geothermal 
  –that 
  are 
  
second 
  to 
  none 
  in 
  overall 
  reliability. 
  And 
  we 
  will 
  need 
  to 
  make 
  our 
  grid 
  more 
  robust 
  to 
  take 
  full 
  
advantage 
  of 
  these 
  clean 
  technologies 
  in 
  both 
  their 
  distributed 
  and 
  remote 
  forms. 
  
 
  
Clean 
  energy 
  benefits 
  all 
  of 
  us, 
  led 
  by 
  the 
  No. 
  1 
  cleanest, 
  cheapest 
  resource 
  of 
  energy 
  efficiency: 
  helping 
  
customers 
  use 
  less 
  electricity 
  so 
  there’s 
  less 
  need 
  to 
  buy 
  or 
  generate 
  power, 
  or 
  build 
  new 
  expensive 
  
power 
  plants. 
  That 
  also 
  means 
  less 
  of 
  the 
  carbon 
  pollution 
  warming 
  our 
  planet 
  and 
  hurting 
  our 
  health. 
  
 
  
Why 
  a 
  statement? 
  
 
  
11 
  
 
  

 NRDC 
  has 
  worked 
  with 
  EEI 
  before, 
  and 
  the 
  latest 
  agreement 
  amends 
  earlier 
  versions 
  from 
  2003 
  and 
  
2008, 
  which 
  both 
  emphasized 
  strategies 
  for 
  promoting 
  energy 
  efficiency 
  and 
  clean 
  energy 
  investment 
  
more 
  generally. 
   
  
 
  
This 
  joint 
  statement 
  retains 
  that 
  emphasis, 
  and 
  also 
  takes 
  into 
  account 
  recent 
  advances 
  in 
  technology 
  
related 
  to 
  distributed 
  generation 
  (DG) 
  involving 
  onsite 
  generation 
  of 
  electricity 
  from 
  small 
  sources 
  such 
  
as 
  solar 
  panels 
  – 
  along 
  with 
  a 
  clear 
  trend 
  in 
  reduced 
  electricity 
  sales 
  growth 
  for 
  utilities 
  nationwide 
  
(which 
  has 
  mostly 
  been 
  driven 
  by 
  changes 
  in 
  consumption, 
  influenced 
  strongly 
  by 
  energy 
  efficiency 
  
gains, 
  rather 
  than 
  by 
  DG 
  installations). 
  
 
  
For 
  NRDC, 
  the 
  need 
  for 
  the 
  statement 
  begins 
  with 
  our 
  longstanding 
  belief 
  that 
  energy 
  efficiency 
  and 
  DG 
  
advances, 
  if 
  properly 
  integrated, 
  should 
  be 
  seen 
  as 
  grid 
  enhancements 
  rather 
  than 
  
grid 
  replacements,and 
  that 
  America’s 
  utilities 
  can 
  be 
  partners 
  in 
  clean 
  energy 
  progress. 
  
 
  
This 
  agreement 
  affirms 
  NRDC’s 
  enduring 
  support 
  for 
  energy 
  efficiency 
  and 
  renewable 
  energy 
  resources, 
  
including 
  in 
  particular 
  distributed 
  solar 
  power. 
   
  
 
  
Energy 
  efficiency 
  and 
  DG 
  vs. 
  outdated 
  regulation 
  
 
  
In 
  some 
  states, 
  the 
  significant 
  progress 
  of 
  innovative, 
  clean 
  distributed 
  technologies 
  has 
  clashed 
  with 
  
outdated 
  theories 
  of 
  regulation, 
  pitting 
  utilities 
  against 
  clean 
  energy 
  companies. 
  The 
  joint 
  statement 
  
reflects 
  NRDC’s 
  belief 
  that 
  clean-­‐energy-­‐oriented 
  business 
  model 
  changes 
  will 
  come 
  faster 
  and 
  more 
  
successfully 
  to 
  the 
  utility 
  sector 
  if 
  the 
  utilities 
  themselves 
  are 
  in 
  support, 
  and 
  that 
  these 
  reforms 
  
represent 
  a 
  better 
  way 
  forward. 
  
 
  
We 
  know 
  that 
  it’s 
  possible 
  to 
  continue 
  to 
  speed 
  the 
  deployment 
  of 
  solar 
  power, 
  energy 
  efficiency, 
  
electricity 
  storage, 
  electric 
  vehicles, 
  and 
  other 
  distributed 
  resources 
  while 
  making 
  important 
  
investments 
  to 
  improve 
  resiliency 
  of 
  the 
  grid 
  and 
  create 
  opportunities 
  for 
  all 
  to 
  enjoy 
  the 
  benefits 
  of 
  
these 
  technologies. 
  We’re 
  committed 
  to 
  working 
  with 
  all 
  the 
  stakeholders 
  involved 
  to 
  continue 
  to 
  try 
  to 
  
achieve 
  these 
  goals. 
   
   
   
   
   
  
 
  
The 
  statement 
  describes 
  a 
  bright 
  future 
  for 
  both 
  utilities 
  and 
  their 
  customers, 
  built 
  around 
  energy 
  
efficiency 
  and 
  a 
  host 
  of 
  other 
  cost-­‐effective 
  and 
  environmentally 
  preferred 
  resource 
  and 
  grid 
  
enhancements. 
  
 
  
Now 
  the 
  really 
  difficult 
  work 
  begins, 
  because 
  none 
  of 
  this 
  can 
  happen 
  without 
  state-­‐by-­‐state 
  
engagement, 
  involving 
  all 
  who 
  share 
  a 
  stake 
  in 
  the 
  transition 
  to 
  a 
  clean 
  energy 
  future, 
  with 
  state 
  utility 
  
commissions 
  getting 
  the 
  final 
  say. 
   
  
 
  
There 
  are, 
  of 
  course, 
  a 
  range 
  of 
  important 
  issues 
  on 
  which 
  NRDC 
  and 
  EEI 
  still 
  differ, 
  and 
  that 
  will 
  not 
  
change 
  anytime 
  soon. 
  But 
  productive 
  engagement 
  is 
  always 
  welcome, 
  and 
  our 
  agreement 
  on 
  the 
  need 
  
for 
  these 
  utility 
  business 
  model 
  changes 
  is 
  an 
  important 
  step 
  forward 
  for 
  clean 
  energy 
  and 
  the 
  
environment. 
   
  
 
  

New 
  electricity 
  tariffs 
  to 
  focus 
  on 
  service 
  not 
  kilowatts 
    
  Reuters 
    
  John 
  Kemp 
    
  2/13/14 
  
http://www.reuters.com/article/2014/02/13/electrciity-­‐smart-­‐meters-­‐idUSL5N0LI2ZB20140213 
   
  
 
  
12 
  
 
  

 Electricity 
  suppliers 
  should 
  be 
  paid 
  according 
  to 
  the 
  services 
  they 
  provide, 
  including 
  reliable 
  and 
  
environmentally 
  friendly 
  heat, 
  light 
  and 
  power, 
  rather 
  than 
  the 
  quantity 
  of 
  electricity 
  they 
  supply, 
  
according 
  to 
  green 
  groups 
  and 
  retailers 
  themselves. 
  
 
  
"The 
  retail 
  electricity 
  distribution 
  business 
  should 
  not 
  be 
  viewed 
  or 
  regulated 
  as 
  if 
  it 
  were 
  acommodity 
  
business," 
  the 
  Edison 
  Electric 
  Institute 
  (EEI) 
  and 
  Natural 
  Resources 
  Defense 
  Council 
  (NRDC) 
  said 
  in 
  a 
  joint 
  
statement 
  on 
  Wednesday. 
  
 
  
"Instead 
  utility 
  businesses 
  should 
  focus 
  on 
  meeting 
  customers' 
  energy 
  service 
  needs." 
  
 
  
Edison 
  is 
  an 
  association 
  that 
  lobbies 
  on 
  behalf 
  of 
  investor-­‐owned 
  power 
  companies 
  in 
  the 
  United 
  States, 
  
while 
  NRDC 
  is 
  one 
  of 
  the 
  country's 
  most 
  prominent 
  green 
  groups 
  campaigning 
  for 
  action 
  to 
  reduce 
  
global 
  warming. 
  
 
  
In 
  their 
  joint 
  statement, 
  EEI 
  and 
  NRDC 
  called 
  on 
  regulators 
  to 
  break 
  the 
  link 
  between 
  utility 
  revenues 
  
and 
  the 
  amount 
  of 
  electricity 
  sold 
  so 
  suppliers 
  have 
  an 
  incentive 
  to 
  provide 
  heat, 
  light 
  and 
  power 
  in 
  the 
  
most 
  efficient 
  and 
  environmentally 
  friendly 
  way 
  -­‐ 
  even 
  if 
  that 
  means 
  selling 
  less 
  electricity. 
  
NEW 
  BUSINESS 
  MODEL 
  
 
  
There 
  is 
  a 
  broad 
  consensus 
  that 
  the 
  power 
  industry 
  needs 
  to 
  update 
  its 
  century-­‐old 
  business 
  model. 
  But 
  
achieving 
  that 
  shift 
  is 
  proving 
  unexpectedly 
  difficult, 
  as 
  it 
  runs 
  into 
  obstacles 
  from 
  regulators 
  and 
  some 
  
of 
  the 
  power 
  companies 
  themselves. 
  
 
  
In 
  many 
  instances, 
  regulated 
  tariffs 
  still 
  reward 
  companies 
  for 
  the 
  amount 
  of 
  power 
  they 
  supply, 
  and 
  
penalise 
  them 
  financially 
  if 
  their 
  customers 
  take 
  less 
  power 
  from 
  the 
  grid. 
  
 
  
In 
  others, 
  utilities 
  appear 
  unenthusiastic 
  about 
  customers 
  generating 
  their 
  own 
  power 
  from 
  micro 
  wind 
  
turbines 
  and 
  rooftop 
  solar 
  panels, 
  or 
  cutting 
  consumption 
  by 
  investing 
  in 
  energy 
  efficiency 
  measures. 
  
 
  
Lack 
  of 
  enthusiasm 
  among 
  electricity 
  suppliers 
  prompted 
  Britain's 
  energy 
  minister 
  to 
  write 
  to 
  the 
  
country's 
  utility 
  regulator 
  on 
  Feb 
  10 
  complaining 
  that 
  "energy 
  suppliers 
  still 
  see 
  their 
  role 
  as 
  selling 
  gas 
  
and 
  electricity 
  rather 
  than 
  having 
  a 
  different 
  business 
  model 
  where 
  the 
  value 
  proposition 
  is 
  to 
  save 
  
households 
  energy." 
  
 
  
SAM 
  INSULL'S 
  INSIGHTS 
  
 
  
The 
  modern 
  electricity 
  business 
  owes 
  its 
  form 
  to 
  Samuel 
  Insull, 
  chief 
  of 
  Commonwealth 
  Edison, 
  who 
  
built 
  the 
  first 
  large-­‐scale 
  power 
  distribution 
  company 
  in 
  the 
  U.S. 
  Midwest 
  more 
  than 
  a 
  century 
  ago 
  
("Smart 
  power: 
  climate 
  change, 
  the 
  smart 
  grid 
  and 
  the 
  future 
  of 
  electric 
  utilities," 
  Peter 
  Fox-­‐Penner, 
  
2010). 
  
 
  
Insull's 
  crucial 
  insight 
  was 
  that 
  it 
  was 
  cheaper 
  to 
  provide 
  electric 
  service 
  by 
  combining 
  power 
  plants 
  and 
  
customers 
  over 
  a 
  grid 
  rather 
  than 
  trying 
  to 
  supply 
  different 
  groups 
  of 
  users 
  from 
  separate 
  power 
  
stations. 
  
 
  
He 
  also 
  recognised 
  there 
  were 
  enormous 
  economies 
  of 
  scale 
  in 
  both 
  power 
  generation 
  and 
  distribution 
  
that 
  made 
  them 
  natural 
  monopolies. 
  The 
  more 
  power 
  supplied 
  the 
  lower 
  the 
  unit 
  costs. 
  
 
  
13 
  
 
  

 And 
  in 
  an 
  industry 
  with 
  some 
  characteristics 
  of 
  a 
  natural 
  monopoly 
  and 
  requirements 
  for 
  heavy 
  capital 
  
investment, 
  Insull 
  realised 
  suppliers 
  could 
  benefit 
  from 
  accepting 
  regulation 
  in 
  exchange 
  for 
  restrictions 
  
on 
  competition 
  and 
  guarantees 
  they 
  would 
  be 
  able 
  to 
  recover 
  their 
  capital 
  and 
  operating 
  costs 
  from 
  
customers. 
  
 
  
For 
  the 
  last 
  century, 
  employing 
  Insull's 
  model, 
  electric 
  utilities 
  have 
  generally 
  offered 
  multi-­‐part 
  tariffs 
  
and 
  bulk 
  discounts 
  to 
  encourage 
  their 
  customers 
  to 
  use 
  more 
  power. 
  The 
  more 
  kilowatts 
  a 
  customer 
  
uses, 
  the 
  cheaper 
  they 
  are 
  on 
  average. 
  
 
  
Regulators, 
  too, 
  have 
  generally 
  based 
  rate 
  rises 
  on 
  the 
  amount 
  of 
  electricity 
  generated 
  and 
  transmitted 
  
over 
  the 
  network. 
  Utilities 
  have 
  been 
  rewarded 
  for 
  investing 
  in 
  more 
  generation 
  and 
  transmission 
  
capacity 
  to 
  supply 
  more 
  power 
  to 
  their 
  customers. 
  
 
  
In 
  the 
  traditional 
  model, 
  there 
  is 
  no 
  incentive 
  to 
  help 
  customers 
  take 
  less 
  power 
  from 
  the 
  grid. 
  
Customers 
  who 
  cut 
  their 
  consumption 
  or 
  generate 
  their 
  own 
  power 
  depress 
  revenues, 
  undermine 
  the 
  
economies 
  of 
  scale 
  inherent 
  in 
  central 
  generation 
  and 
  distribution, 
  and 
  leave 
  utilities 
  with 
  under-­‐used 
  
power 
  plants 
  and 
  transmission 
  lines. 
  
GREENING 
  ELECTRICITY 
  
 
  
To 
  cut 
  greenhouse 
  emissions, 
  policymakers 
  in 
  most 
  U.S. 
  states 
  and 
  other 
  countries 
  have 
  required 
  
utilities 
  to 
  purchase 
  a 
  certain 
  quantity 
  of 
  their 
  power 
  from 
  clean 
  sources 
  like 
  wind, 
  solar, 
  nuclear 
  and 
  
hydro. 
  
 
  
In 
  addition, 
  utilities 
  have 
  often 
  been 
  required 
  or 
  encouraged 
  to 
  help 
  their 
  customers 
  make 
  homes 
  and 
  
offices 
  more 
  energy 
  efficient 
  by 
  installing 
  more 
  insulation 
  and 
  weatherising. 
  
 
  
Finally, 
  many 
  utilities 
  have 
  been 
  required 
  to 
  allow 
  customers 
  to 
  generate 
  their 
  own 
  power 
  from 
  rooftop 
  
turbines 
  and 
  solar 
  panels, 
  and 
  even 
  sell 
  surplus 
  power 
  back 
  to 
  the 
  grid. 
  
 
  
Instead 
  of 
  power 
  flowing 
  one 
  way 
  across 
  the 
  grid, 
  from 
  central 
  generating 
  stations 
  to 
  homes 
  and 
  offices, 
  
it 
  increasingly 
  flows 
  in 
  two 
  directions, 
  with 
  customers 
  sometimes 
  taking, 
  and 
  sometimes 
  supplying, 
  
electricity 
  to 
  the 
  network. 
  
 
  
Bi-­‐directional 
  net 
  meters 
  record 
  the 
  time, 
  direction 
  and 
  amount 
  of 
  electricity 
  flowing 
  between 
  the 
  
customer 
  and 
  the 
  network. 
   
  
 
  
Customers 
  are 
  charged 
  only 
  for 
  the 
  power 
  they 
  take, 
  and 
  credited 
  for 
  power 
  they 
  supply, 
  according 
  to 
  
the 
  time 
  of 
  day 
  and 
  time 
  of 
  year. 
  
 
  
"Micro-­‐generation" 
  or 
  "distributed 
  generation", 
  as 
  the 
  system 
  is 
  known, 
  is 
  popular 
  among 
  green 
  groups, 
  
customers, 
  politicians 
  and 
  some 
  utility 
  regulators. 
  Power 
  retailers 
  are 
  understandably 
  less 
  enthusiastic 
  
since 
  it 
  threatens 
  every 
  aspect 
  of 
  their 
  traditional 
  business 
  model. 
  
 
  
RECOVERING 
  GRID 
  COSTS 
  
 
  
Net 
  metering 
  is 
  not 
  a 
  panacea. 
  Even 
  with 
  micro-­‐generation, 
  most 
  customers 
  still 
  want 
  a 
  connection 
  to 
  
the 
  grid 
  to 
  even 
  out 
  their 
  electricity 
  demand 
  and 
  production. 
  
 
  
14 
  
 
  

 On 
  a 
  sunny 
  or 
  windy 
  day, 
  a 
  home-­‐generator 
  may 
  want 
  to 
  sell 
  excess 
  power 
  back 
  to 
  the 
  grid. 
  On 
  a 
  cold, 
  
overcast 
  and 
  still 
  day, 
  a 
  home 
  generator 
  may 
  still 
  need 
  to 
  take 
  some 
  power 
  from 
  the 
  network. 
  
 
  
The 
  problem 
  is 
  how 
  much 
  to 
  charge 
  micro-­‐generators 
  for 
  the 
  network 
  services 
  that 
  they 
  continue 
  to 
  rely 
  
on. 
  
 
  
"Although 
  (distributed) 
  generation 
  can 
  reduce 
  a 
  grid's 
  needs 
  for 
  central 
  station 
  generation 
  and 
  other 
  
infrastructure, 
  it 
  typically 
  does 
  not 
  eliminate 
  its 
  owners' 
  needs 
  for 
  grid 
  services," 
  EEI 
  and 
  NRDC 
  
explained 
  in 
  their 
  statement. 
  
 
  
Grid 
  services 
  include 
  everything 
  from 
  basic 
  transmission 
  to 
  voltage 
  and 
  frequency 
  control 
  and 
  providing 
  
back 
  up 
  power 
  when 
  the 
  sun 
  does 
  not 
  sunshine 
  and 
  the 
  wind 
  does 
  not 
  blow. 
  
 
  
The 
  question 
  is 
  how 
  much 
  to 
  charge 
  micro-­‐generators 
  for 
  all 
  these 
  services 
  they 
  continue 
  to 
  use 
  even 
  as 
  
they 
  cut 
  the 
  number 
  of 
  kilowatts 
  they 
  take 
  from 
  the 
  network. 
  
 
  
In 
  many 
  cases, 
  early 
  net 
  metering 
  programmes 
  have 
  been 
  very 
  generous. 
  If 
  net 
  metering 
  was 
  extended 
  
to 
  a 
  much 
  larger 
  group 
  of 
  customers, 
  as 
  policymakers 
  hope, 
  on 
  the 
  same 
  terms, 
  utilities 
  would 
  be 
  left 
  
with 
  lots 
  of 
  under-­‐used 
  power 
  plants 
  and 
  transmission 
  lines 
  and 
  a 
  "revenue 
  adequacy" 
  problem. 
  
 
  
While 
  some 
  power 
  plants 
  and 
  transmission 
  lines 
  could 
  be 
  permanently 
  closed, 
  others 
  would 
  still 
  be 
  
needed 
  to 
  provide 
  back-­‐up 
  and 
  other 
  grid 
  services. 
  
 
  
REDESIGNING 
  POWER 
  TARIFFS 
  
 
  
There 
  is 
  a 
  risk 
  that 
  customers 
  who 
  continue 
  to 
  rely 
  on 
  the 
  grid 
  will 
  end 
  up 
  subsidising 
  micro-­‐generators 
  
who 
  produce 
  most 
  of 
  their 
  own 
  but 
  still 
  expect 
  the 
  grid 
  to 
  be 
  available 
  as 
  back-­‐up. 
  
 
  
The 
  same 
  problem 
  occurs 
  with 
  energy 
  efficiency. 
  Reducing 
  consumption 
  cuts 
  some 
  but 
  not 
  all 
  of 
  the 
  
costs 
  of 
  supplying 
  customers. 
  As 
  less 
  power 
  is 
  supplied, 
  average 
  unit 
  costs 
  tend 
  to 
  rise 
  because 
  some 
  
costs 
  are 
  basically 
  fixed. 
  
 
  
In 
  their 
  declaration, 
  EEI 
  and 
  NRDC 
  agree 
  there 
  is 
  a 
  "vital 
  need 
  for 
  regulatory 
  policies 
  that 
  will 
  support 
  
fair 
  and 
  adequate 
  cost 
  recovery 
  for 
  maintaining 
  the 
  evolving 
  grid." 
  
 
  
From 
  the 
  moment 
  Thomas 
  Edison 
  opened 
  the 
  first 
  power 
  plant 
  at 
  Pearl 
  Street 
  on 
  Manhattan 
  in 
  1882, 
  
cost 
  recovery 
  and 
  tariff 
  design 
  has 
  been 
  central 
  to 
  the 
  development 
  of 
  the 
  electricity 
  industry. 
  
 
  
It 
  is 
  a 
  technical 
  subject 
  which 
  receives 
  far 
  less 
  media 
  and 
  public 
  attention 
  than 
  smart 
  metering 
  and 
  
renewables. 
  But 
  no 
  issue 
  is 
  more 
  important. 
  
 
  
Updating 
  cost 
  recovery 
  and 
  tariff 
  systems 
  will 
  be 
  essential 
  to 
  integrating 
  more 
  home-­‐generation 
  over 
  
the 
  next 
  20 
  years 
  while 
  ensuring 
  electricity 
  remains 
  reliable 
  and 
  affordable 
  for 
  all 
  customers. 
  (Editing 
  
by 
  Jason 
  Neely) 
  
 
  

Stakeholders 
  see 
  a 
  'sea 
  change' 
  in 
  attitudes 
  over 
  business 
  model 
    
  Energy 
  & 
  Environment 
  
Publishing 
    
   
  Rod 
  Kuckro 
    
  2/13/14 
  
 
  

15 
  
 
  

 The 
  midwinter 
  meeting 
  of 
  the 
  nation's 
  utility 
  czars 
  ended 
  yesterday 
  with 
  a 
  surprising 
  kumbaya 
  moment 
  
when 
  the 
  lobby 
  for 
  investor-­‐owned 
  electric 
  utilities 
  and 
  the 
  Natural 
  Resources 
  Defense 
  Council 
  issued 
  a 
  
joint 
  statement 
  in 
  support 
  of 
  new 
  state-­‐level 
  rate 
  regimes 
  that 
  allow 
  continuing 
  expansion 
  of 
  solar 
  
power 
  while 
  keeping 
  utilities 
  financially 
  whole 
  and 
  able 
  to 
  maintain 
  the 
  grid. 
  
 
  
The 
  agreement 
  by 
  the 
  Edison 
  Electric 
  Institute 
  and 
  NRDC 
  reflects 
  a 
  consensus 
  that 
  seemed 
  to 
  be 
  jelling 
  
in 
  real 
  time 
  over 
  the 
  course 
  of 
  the 
  National 
  Association 
  of 
  Regulatory 
  Utility 
  Commissioners' 
  five-­‐day 
  
meeting. 
  
 
  
In 
  practical 
  terms, 
  the 
  agreement 
  may 
  reflect 
  two 
  realities: 
  resignation 
  that 
  the 
  drive 
  for 
  cleaner 
  energy 
  
technologies 
  is 
  here 
  to 
  stay, 
  and 
  that 
  consumers 
  are 
  in 
  the 
  lead 
  as 
  they 
  exploit 
  technologies 
  they 
  can 
  
afford 
  to 
  put 
  themselves 
  in 
  more 
  control 
  of 
  their 
  energy 
  use. 
  
 
  
"The 
  old 
  way 
  of 
  doing 
  business, 
  the 
  centralized 
  generator, 
  the 
  distribution 
  company 
  and 
  the 
  customer 
  -­‐-­‐ 
  
that's 
  just 
  not 
  where 
  the 
  future's 
  going 
  to 
  be," 
  said 
  David 
  Cash, 
  a 
  commissioner 
  with 
  the 
  Massachusetts 
  
Department 
  of 
  Public 
  Utilities, 
  just 
  one 
  day 
  before 
  the 
  EEI-­‐NRDC 
  agreement. 
  
 
  
"The 
  utilities 
  and 
  regulators 
  need 
  to 
  figure 
  out 
  what's 
  the 
  business 
  model 
  that 
  can 
  make 
  the 
  utilities 
  
economically 
  healthy 
  players 
  in 
  this 
  field 
  at 
  the 
  same 
  time 
  that 
  it 
  gives 
  the 
  consumers 
  all 
  of 
  the 
  kind 
  of 
  
benefits 
  that 
  we're 
  going 
  to 
  get 
  from 
  all 
  of 
  these 
  new 
  technologies," 
  Cash 
  said 
  in 
  an 
  interview. 
  
 
  
At 
  session 
  after 
  NARUC 
  session, 
  despite 
  each 
  one's 
  advertised 
  focus 
  on 
  topics 
  such 
  as 
  an 
  integrated 
  grid, 
  
energy 
  efficiency 
  or 
  new 
  business 
  models, 
  the 
  conversation 
  among 
  the 
  regulated, 
  the 
  regulators 
  and 
  
stakeholders 
  evolved 
  into 
  an 
  emphasis 
  on 
  the 
  need 
  for 
  détente. 
  
 
  
"Rate 
  design 
  is 
  where 
  it's 
  at," 
  said 
  Rob 
  Caldwell, 
  vice 
  president 
  for 
  renewable 
  generation 
  development 
  
at 
  Duke 
  Energy 
  Corp. 
  "The 
  key 
  is 
  to 
  get 
  a 
  handle 
  on 
  what 
  are 
  utilities' 
  fixed 
  costs 
  and 
  variable 
  costs 
  and 
  
design 
  rates 
  that 
  reflect 
  fixed 
  revenue 
  and 
  variable 
  revenue," 
  he 
  said 
  at 
  one 
  session. 
  
 
  
Time-­‐varying 
  rates 
  for 
  customers 
  could 
  be 
  one 
  solution, 
  said 
  Janet 
  Besser, 
  vice 
  president 
  of 
  the 
  New 
  
England 
  Clean 
  Energy 
  Council 
  and 
  a 
  former 
  regulator. 
  "We 
  have 
  to 
  do 
  the 
  analysis 
  and 
  know 
  where 
  the 
  
costs 
  and 
  benefits 
  are," 
  especially 
  when 
  it 
  comes 
  to 
  valuing 
  energy 
  efficiency 
  and 
  demand 
  response, 
  she 
  
said. 
  
 
  
"There 
  are 
  ways 
  that 
  we 
  can 
  improve 
  [utilities'] 
  risk 
  profile 
  in 
  terms 
  of 
  the 
  mechanism 
  of 
  rate 
  recovery. 
  
In 
  our 
  state, 
  we 
  have 
  trackers 
  [that 
  collect 
  from 
  ratepayers 
  a 
  charge 
  for 
  specific 
  utility 
  spending], 
  and 
  
that's 
  one 
  way 
  to 
  reduce 
  risk," 
  Cash 
  said. 
  
 
  
EEI 
  softens 
  its 
  approach 
  
 
  
"The 
  electric 
  power 
  industry's 
  mission 
  is 
  to 
  provide 
  safe, 
  reliable, 
  affordable 
  and 
  increasingly 
  clean 
  
electricity," 
  said 
  EEI 
  Executive 
  Vice 
  President 
  David 
  Owens. 
  "Today 
  utilities 
  are 
  partnering 
  with 
  
customers, 
  regulators 
  and 
  all 
  stakeholders 
  to 
  transform 
  the 
  way 
  they 
  generate 
  and 
  deliver 
  electricity. 
  
This 
  agreement 
  helps 
  chart 
  a 
  path 
  to 
  success." 
  
 
  
It 
  was 
  just 
  a 
  year 
  ago, 
  in 
  a 
  landmark 
  report 
  on 
  "disruptive 
  challenges" 
  facing 
  the 
  retail 
  electric 
  business, 
  
that 
  EEI 
  identified 
  the 
  "falling 
  costs 
  of 
  distributed 
  generation" 
  such 
  as 
  solar 
  panels 
  and 
  "political 
  interest 
  
16 
  
 
  

 in 
  demand-­‐side 
  management 
  technologies" 
  such 
  as 
  energy 
  efficiency 
  as 
  threats 
  to 
  the 
  long-­‐established 
  
utility 
  business 
  model. 
  
 
  
Within 
  the 
  year, 
  to 
  drive 
  home 
  its 
  point, 
  EEI 
  was 
  sponsoring 
  television 
  ads 
  critical 
  of 
  state 
  net-­‐metering 
  
programs 
  by 
  raising 
  the 
  fact 
  that 
  under 
  most 
  net-­‐metering 
  designs, 
  customers 
  with 
  rooftop 
  solar 
  panels 
  
get 
  to 
  sell 
  their 
  surplus 
  electricity 
  back 
  to 
  the 
  utility, 
  cutting 
  their 
  electric 
  bills 
  and 
  as 
  a 
  result 
  not 
  paying 
  
as 
  much 
  for 
  the 
  upkeep 
  of 
  the 
  grid 
  as 
  a 
  nonsolar 
  customer. 
  
 
  
The 
  campaign 
  was 
  widely 
  criticized 
  for 
  pitting 
  those 
  who 
  could 
  afford 
  solar 
  against 
  the 
  majority 
  of 
  
customers 
  who 
  cannot. 
   
  
 
  
That 
  became 
  an 
  often-­‐repeated 
  argument 
  by 
  executives 
  who 
  fear 
  an 
  inexorable 
  decline 
  in 
  power 
  sales 
  
would 
  erode 
  their 
  ability 
  to 
  serve 
  what 
  former 
  Great 
  Plains 
  Energy 
  CEO 
  Michael 
  Chesser 
  described 
  
recently 
  as 
  the 
  "higher 
  purpose" 
  to 
  society 
  inherent 
  in 
  a 
  utility's 
  monopoly 
  franchise 
  to 
  provide 
  reliable 
  
electric 
  service. 
  
 
  
Time 
  will 
  tell 
  if 
  it's 
  really 
  a 
  'sea 
  change' 
  
 
  
"It's 
  been 
  an 
  effort 
  of 
  months 
  done 
  in 
  anticipation 
  of 
  the 
  NARUC 
  meeting," 
  Ralph 
  Cavanagh, 
  co-­‐director 
  
of 
  NRDC's 
  energy 
  program, 
  said 
  in 
  an 
  interview. 
  
 
  
"I 
  think 
  it 
  marks 
  a 
  sea 
  change 
  in 
  the 
  attitude 
  in 
  particular 
  of 
  the 
  leadership 
  of 
  the 
  utility 
  industry 
  
regarding 
  the 
  promise 
  of 
  the 
  technology 
  revolution 
  that 
  energy 
  efficiency 
  and 
  [distributed 
  generation] 
  
represents. 
  
 
  
"It 
  is 
  a 
  very 
  welcome 
  expression 
  of 
  optimism 
  about 
  the 
  role 
  of 
  the 
  utility 
  sector 
  as 
  a 
  partner 
  in 
  making 
  
this 
  happen, 
  and 
  that 
  there's 
  a 
  way 
  forward 
  that 
  will 
  work 
  for 
  everyone 
  involved." 
  
 
  
Cash 
  agreed. 
  "It 
  does 
  feel 
  to 
  me 
  like 
  there 
  is 
  a 
  big 
  sea 
  change 
  happening, 
  and 
  that 
  sea 
  change 
  is 
  that 
  
[public 
  utility 
  commissions] 
  and 
  utilities 
  are 
  realizing 
  this 
  huge 
  change 
  in 
  how 
  energy 
  is 
  delivered, 
  how 
  
it's 
  stored, 
  how 
  it's 
  priced 
  [with] 
  all 
  of 
  these 
  new 
  technologies 
  that 
  allow 
  for 
  information 
  to 
  be 
  used 
  and 
  
shared 
  and 
  pricing 
  signals 
  to 
  be 
  done 
  correctly," 
  he 
  said. 
  
 
  
The 
  agreement, 
  which 
  EEI 
  and 
  NRDC 
  describe 
  as 
  following 
  a 
  2008 
  joint 
  campaign 
  to 
  encourage 
  
efficiency, 
  calls 
  for 
  state 
  regulators 
  to 
  "rethink 
  how 
  utility 
  costs 
  are 
  recovered" 
  and 
  view 
  retail 
  
distribution 
  as 
  a 
  business 
  that 
  delivers 
  energy 
  services, 
  not 
  just 
  electricity. 
  
 
  
Among 
  its 
  eight 
  recommendations 
  are 
  that 
  "customers 
  deserve 
  the 
  opportunity 
  to 
  interconnect 
  
distributed 
  generation 
  to 
  the 
  grid 
  quickly 
  and 
  easily" 
  through 
  net-­‐metering 
  programs, 
  and 
  that 
  "utilities 
  
deserve 
  assurances 
  that 
  recovery 
  of 
  their 
  authorized 
  non-­‐fuel 
  costs 
  will 
  not 
  vary 
  with 
  fluctuations" 
  in 
  
electricity 
  use. 
  
 
  
"Obviously, 
  this 
  is 
  not 
  a 
  mission 
  accomplished 
  moment 
  -­‐-­‐ 
  there's 
  a 
  great 
  deal 
  to 
  do 
  at 
  the 
  state 
  level 
  to 
  
realize 
  this 
  promise," 
  Cavanagh 
  said. 
  "But 
  I 
  emerged 
  from 
  this 
  process 
  heartened 
  at 
  the 
  likelihood 
  that 
  
we'll 
  find 
  a 
  way 
  forward 
  together. 
  It 
  has 
  to 
  happen 
  on 
  a 
  state-­‐by-­‐state 
  basis, 
  a 
  lot 
  more 
  people 
  have 
  to 
  
be 
  involved." 
  
 
  
17 
  
 
  

 US 
  Should 
  Heed 
  Renewable 
  Integration 
  Lessons 
  from 
  Europe 
  or 
  Face 
  Consequences, 
  Says 
  
NARUC 
  Panelist 
    
  Renewable 
  Energy 
  World 
    
  Corina 
  Rivera-­‐Linares 
    
  2/13/14 
  
http://www.renewableenergyworld.com/rea/news/article/2014/02/us-­‐should-­‐heed-­‐renewable-­‐
integration-­‐lessons-­‐from-­‐europe-­‐or-­‐face-­‐consequences-­‐says-­‐naruc 
   
  

WASHINGTON, 
  D.C. 
  -­‐-­‐ 
  In 
  integrating 
  renewable 
  energy 
  to 
  the 
  electric 
  grid, 
  the 
  United 
  States 
  has 
  a 
  
unique 
  opportunity 
  to 
  assess 
  lessons 
  learned 
  in 
  Europe 
  and 
  not 
  replicate 
  the 
  disequilibrium 
  that 
  has 
  
occurred 
  overseas 
  to 
  consumers, 
  power 
  producers 
  and 
  capital 
  markets, 
  according 
  to 
  Jeffrey 
  Altman, 
  
senior 
  advisor, 
  Finadvice 
  GmbH. 
   
  
“A 
  new 
  transparent, 
  ubiquitous, 
  reliable 
  regulatory 
  framework 
  needs 
  to 
  be 
  established 
  in 
  order 
  to 
  
correctly 
  build 
  and 
  support 
  the 
  nation’s 
  developing 
  renewable 
  power 
  portfolio, 
  which 
  ensures 
  a 
  long-­‐
term 
  responsibility 
  for 
  the 
  whole 
  power 
  system, 
  as 
  well 
  as 
  the 
  appropriate 
  pricing 
  to 
  the 
  American 
  
consumer,” 
  he 
  said 
  during 
  a 
  Feb. 
  10 
  panel 
  as 
  part 
  of 
  the 
  National 
  Association 
  of 
  Regulatory 
  Utility 
  
Commissioners 
  (NARUC) 
  Winter 
  Committee 
  Meetings 
  in 
  Washington, 
  D.C. 
  “The 
  net 
  impact 
  to 
  the 
  U.S. 
  
economy 
  and 
  its 
  future 
  strategic 
  competitiveness 
  can 
  be 
  significant. 
  The 
  U.S., 
  therefore, 
  needs 
  to 
  
appropriately 
  restructure 
  its 
  regulatory 
  framework 
  and 
  prioritize 
  this 
  effort 
  now, 
  or 
  face 
  similar 
  
challenges 
  as 
  Europe 
  in 
  the 
  future.” 
  
Altman 
  noted 
  that 
  there 
  are 
  several 
  benefits 
  of 
  having 
  high 
  penetration 
  levels 
  of 
  renewable 
  energy 
  on 
  
the 
  grid, 
  including 
  the 
  diversification 
  of 
  the 
  power 
  portfolio 
  and 
  lower 
  wholesale 
  prices. 
  
Speaking 
  of 
  the 
  European 
  experience, 
  he 
  noted 
  that 
  due 
  to 
  massively 
  subsidized 
  feed-­‐in 
  tariffs, 
  new 
  
additional 
  capacity 
  is 
  driving 
  down 
  wholesale 
  prices 
  of 
  power 
  as 
  renewables 
  with 
  lower 
  marginal 
  
production 
  costs 
  than 
  thermal 
  plants 
  get 
  dispatched 
  first. 
  
Other 
  benefits 
  include 
  reductions 
  of 
  greenhouse 
  gas 
  emissions, 
  he 
  said, 
  noting 
  that 
  the 
  European 
  Union 
  
(EU) 
  has 
  set 
  a 
  target 
  of 
  a 
  20 
  percent 
  reduction 
  of 
  greenhouse 
  gases 
  from 
  1990 
  levels, 
  with 
  a 
  20 
  percent 
  
renewable 
  target 
  and 
  a 
  20 
  percent 
  increase 
  in 
  energy 
  efficiency 
  for 
  2020. 
  So 
  far, 
  he 
  said, 
  the 
  EU 
  is 
  on 
  
target 
  with 
  most 
  of 
  its 
  members. 
  
Also 
  a 
  benefit 
  is 
  energy 
  independence, 
  which 
  is 
  critical 
  for 
  every 
  country, 
  Altman 
  said. 
  Employment 
  
gains, 
  the 
  development 
  of 
  more 
  efficient 
  renewable 
  technologies 
  and 
  greater 
  efficiency 
  in 
  scale 
  and 
  
scope 
  are 
  also 
  benefits 
  stemming 
  from 
  higher 
  levels 
  of 
  renewable 
  energy, 
  he 
  said. 
  
Unintended 
  Consequences 
  in 
  Europe 
  
Despite 
  the 
  benefits, 
  there 
  have 
  been 
  unintended 
  consequences 
  in 
  Europe 
  as 
  it 
  pertains 
  to 
  advancing 
  
renewable 
  energy, 
  including 
  a 
  misunderstanding 
  of 
  required 
  subsidies 
  and 
  appropriate 
  regulation, 
  he 
  
said, 
  adding 
  that 
  European 
  regulators 
  grossly 
  underestimated 
  the 
  cost 
  of 
  subsidies 
  and 
  the 
  necessary 
  
build-­‐out 
  requirements. 
  
Some 
  estimate 
  that 
  Germany’s 
  feed-­‐in 
  tariff 
  subsidy 
  program, 
  for 
  instance, 
  could 
  exceed 
  $1.3bn 
  by 
  the 
  
time 
  it 
  expires. 
  
Many 
  European 
  regulatory 
  regimes 
  were 
  inappropriately 
  structured 
  and 
  there 
  have 
  been 
  efforts 
  to 
  
correct 
  those 
  by, 
  for 
  instance, 
  initiating 
  retroactive 
  taxes 
  or 
  new 
  regimes 
  that 
  resulted 
  in 
  significant 
  
value 
  destruction 
  to 
  various 
  renewable 
  companies. 
  
“This 
  continued 
  regulatory 
  uncertainty 
  across 
  Europe 
  is 
  increasing 
  the 
  cost 
  of 
  capital 
  for 
  European 
  
renewable 
  companies, 
  which 
  Fitch, 
  the 
  rating 
  agency, 
  recently 
  highlighted 
  as 
  the 
  most 
  likely 
  sector 
  in 
  
the 
  European 
  energy 
  markets 
  to 
  receive 
  a 
  downgrade 
  in 
  2014,” 
  Altman 
  said. 
  
18 
  
 
  

 The 
  enormous 
  amount 
  of 
  subsidies 
  and 
  the 
  speed 
  of 
  build-­‐up 
  have 
  created 
  disruption 
  to 
  the 
  power 
  
markets, 
  he 
  said, 
  adding, 
  “As 
  the 
  EU 
  is 
  a 
  liberalized 
  market, 
  government 
  actions 
  regarding 
  subsidies 
  are 
  
currently 
  being 
  allowed 
  by 
  international 
  law 
  in 
  favor 
  of 
  the 
  perceived 
  requirements 
  of 
  the 
  consumer 
  and 
  
the 
  environment.” 
  
For 
  instance, 
  wholesale 
  prices 
  in 
  Germany 
  have 
  fallen 
  from 
  €90/MW 
  to 
  €95/MW 
  in 
  2008 
  to 
  €37/MW 
  in 
  
2013. 
  
Altman 
  also 
  noted 
  that 
  the 
  EU 
  will 
  be 
  required 
  to 
  pay 
  subsidies 
  for 
  the 
  build-­‐out 
  and 
  enhancements 
  of 
  
power 
  networks 
  to 
  manage 
  the 
  dynamic 
  flows. 
  Germany, 
  he 
  said, 
  is 
  planning 
  to 
  spend 
  some 
  €40bn, 
  or 
  
around 
  US$60bn, 
  to 
  reinforce 
  the 
  grid 
  from 
  where 
  it 
  was 
  in 
  2012 
  to 
  where 
  it 
  will 
  be 
  in 
  2023. 
  
“You’re 
  effectively 
  taking 
  all 
  of 
  the 
  power 
  … 
  from 
  the 
  north 
  and 
  bringing 
  it 
  down 
  to 
  the 
  south,” 
  he 
  said. 
  
“[That 
  is] 
  a 
  huge 
  effort 
  and 
  no 
  one 
  was 
  ever 
  considering 
  those 
  costs 
  early 
  on.” 
  
In 
  addition 
  to 
  that, 
  the 
  German 
  government 
  is 
  also 
  now 
  — 
  as 
  others 
  are 
  starting 
  to 
  do 
  — 
  looking 
  at 
  
ensuring 
  capacity 
  payments 
  for 
  thermal 
  power 
  stations 
  that 
  are 
  being 
  closed 
  down 
  to 
  ensure 
  the 
  
reliability 
  of 
  the 
  grid 
  and 
  prevent 
  blackouts 
  and 
  brownouts, 
  he 
  said. 
  
Another 
  challenge 
  is 
  that 
  many 
  European 
  utilities 
  underestimated 
  the 
  growth 
  of 
  renewables 
  as 
  well 
  as 
  
the 
  impact 
  to 
  wholesale 
  prices 
  in 
  the 
  entire 
  system, 
  leading 
  to 
  the 
  continued 
  build-­‐out 
  of 
  thermal 
  plants 
  
over 
  the 
  last 
  decade, 
  many 
  of 
  which 
  were 
  made 
  obsolete, 
  particularly 
  with 
  respect 
  to 
  natural 
  gas-­‐fired 
  
plants, 
  by 
  the 
  end 
  of 
  the 
  decade. 
  
“As 
  a 
  result, 
  the 
  utilities 
  had 
  to 
  shore 
  up 
  their 
  balance 
  sheets 
  by 
  undertaking 
  large 
  divestitures 
  of 
  some 
  
of 
  their 
  holdings, 
  as 
  well 
  as 
  reducing 
  their 
  operating 
  costs,” 
  Altman 
  said. 
  
Europe’s 
  top 
  20 
  utilities 
  that 
  were 
  worth 
  around 
  €1tr 
  in 
  2008 
  are 
  now 
  less 
  than 
  half 
  that 
  amount 
  due 
  to 
  
the 
  global 
  financial 
  crisis 
  and 
  other 
  factors, 
  including 
  those 
  involving 
  renewable 
  energy 
  development, 
  he 
  
said. 
  
Another 
  important 
  matter 
  that 
  has 
  occurred 
  is 
  that 
  prices 
  to 
  energy 
  users 
  have 
  increased 
  significantly, 
  
as 
  has 
  the 
  backlash 
  against 
  energy 
  companies, 
  he 
  said. 
  
In 
  Germany, 
  household 
  prices 
  have 
  more 
  than 
  doubled 
  from 
  18 
  cents/kWh 
  in 
  2000 
  to 
  more 
  than 
  37 
  
cents/kWh. 
  In 
  the 
  United 
  Kingdom, 
  there 
  has 
  been 
  a 
  call 
  to 
  freeze 
  prices 
  for 
  up 
  to 
  20 
  months, 
  Altman 
  
added. 
  
Well-­‐meaning 
  European 
  governments 
  and 
  regulators 
  embarked 
  upon 
  an 
  effort 
  to 
  reduce 
  carbon 
  
emissions 
  and 
  “unintentional 
  consequences 
  resulted 
  from 
  those 
  policies 
  that 
  were 
  not 
  ultimately 
  fully 
  
vetted 
  by 
  industry 
  [including] 
  renewable 
  companies 
  and 
  utilities 
  and 
  other 
  stakeholders,” 
  he 
  said. 
  “The 
  
results 
  of 
  these 
  policies 
  have 
  required 
  enormous 
  subsidies, 
  which 
  have 
  created 
  disequilibrium 
  and 
  value 
  
destruction 
  to 
  both 
  renewable 
  companies 
  and 
  utilities 
  via 
  regulatory 
  interventions.” 
  
It 
  is 
  now 
  envisioned 
  that 
  further 
  subsidies 
  will 
  be 
  required 
  for 
  emission 
  targets, 
  the 
  support 
  of 
  thermal 
  
plants 
  and 
  storage, 
  via 
  capacity 
  payments 
  and 
  a 
  build-­‐out 
  of 
  grids. 
  
Accordingly, 
  Altman 
  added, 
  those 
  policies, 
  combined 
  with 
  large 
  subsidies 
  “are 
  destroying 
  what 
  was 
  
essentially 
  a 
  free 
  market 
  and, 
  as 
  such, 
  the 
  influence 
  of 
  government 
  in 
  the 
  power 
  sector 
  will 
  ultimately 
  
have 
  no 
  real 
  market 
  correction 
  mechanisms 
  as 
  European 
  governments 
  capriciously 
  determine 
  the 
  fuel 
  
mix, 
  technology 
  choice 
  and 
  capacity 
  price 
  levels 
  with 
  detrimental 
  effect 
  to 
  the 
  efficiency, 
  investment 
  
and, 
  most 
  importantly, 
  prices 
  to 
  consumers.” 
  

19 
  
 
  

 Lessons 
  Learned 
  as 
  the 
  U.S. 
  Moves 
  Forward 
  
In 
  the 
  U.S., 
  Altman 
  said, 
  “now 
  is 
  the 
  time 
  to 
  fully 
  assess 
  the 
  implications 
  of 
  transitioning 
  to 
  a 
  partial 
  
renewable 
  portfolio 
  and 
  structure 
  the 
  appropriate 
  regulation.” 
  
The 
  current 
  U.S. 
  net 
  metering 
  and 
  regulation, 
  which 
  has 
  allowed 
  for 
  renewables 
  to 
  come 
  on 
  the 
  grid, 
  
does 
  not 
  take 
  into 
  consideration 
  the 
  future 
  requirements 
  of 
  grid 
  enhancements 
  as 
  well 
  as 
  what 
  will 
  be 
  
required 
  to 
  maintain 
  a 
  reliable 
  power 
  system, 
  he 
  said. 
  
“There 
  needs 
  to 
  be 
  a 
  well-­‐coordinated 
  assessment 
  between 
  federal 
  and 
  state 
  regulators, 
  regulated 
  and 
  
non-­‐regulated 
  power 
  producers, 
  renewable 
  companies, 
  consumers 
  and 
  other 
  important 
  stakeholders 
  to 
  
develop 
  ubiquitous 
  regulation,” 
  he 
  said. 
  “Otherwise, 
  the 
  U.S. 
  will 
  ultimately 
  face 
  an 
  analogous 
  situation 
  
relative 
  to 
  Europe 
  with 
  balkanized 
  energy 
  markets.” 
  
On 
  whether 
  regulators 
  should 
  wait 
  for 
  there 
  to 
  be 
  overcapacity 
  and 
  strains 
  on 
  the 
  systems 
  to 
  set 
  new 
  
regulations, 
  he 
  said, 
  “I 
  suggest 
  what 
  we 
  have 
  learned 
  from 
  Europe, 
  this 
  would 
  indeed 
  be 
  imprudent.” 
  
Regulators 
  should 
  consider 
  creating 
  a 
  new 
  framework 
  whereby 
  a 
  structure 
  be 
  agreed 
  upon 
  as 
  to 
  how 
  
much 
  capacity 
  will 
  be 
  allowed 
  in 
  each 
  state/region 
  over 
  a 
  20-­‐year 
  period, 
  looking 
  into 
  five-­‐year 
  
increments 
  with 
  review 
  every 
  two 
  years, 
  he 
  said. 
  In 
  parallel, 
  there 
  should 
  also 
  be 
  an 
  agreement 
  as 
  to 
  
how 
  much 
  thermal 
  capacity 
  will 
  be 
  retired 
  during 
  that 
  time, 
  whereby, 
  collectively, 
  an 
  assessment 
  will 
  be 
  
made 
  with 
  respect 
  to 
  the 
  mix 
  of 
  power 
  production, 
  the 
  network 
  upgrade 
  costs, 
  the 
  overall 
  reliability 
  of 
  
the 
  network 
  and 
  the 
  ultimate 
  price 
  to 
  consumers, 
  he 
  said. 
  
Special 
  attention 
  should 
  be 
  paid 
  to 
  require 
  flexibility 
  in 
  storage. 
  Upon 
  this 
  analysis, 
  he 
  added, 
  all 
  new 
  
generation 
  coming 
  online 
  should 
  be 
  bid 
  at 
  an 
  auction 
  to 
  meet 
  the 
  lowest 
  economic 
  costs, 
  highest 
  
reliability 
  standards, 
  as 
  well 
  as 
  environmental 
  standards, 
  Altman 
  said. 
  
This 
  article 
  was 
  originally 
  published 
  on 
  GenerationHub 
  and 
  was 
  republished 
  with 
  permission. 
  

EEI, 
  Wall 
  Street 
  Talks 
  Include 
  Policy, 
  Environment 
    
  Fierce 
  Energy 
    
   
  Barbara 
  Vergetis 
  Lundin 
    
  
2/14/14 
  

http://www.fierceenergy.com/story/eei-­‐wall-­‐street-­‐talks-­‐include-­‐policy-­‐environment/2014-­‐02-­‐14 
   
  
 
  
In 
  2014, 
  policy, 
  consumers 
  and 
  the 
  environment 
  are 
  on 
  the 
  top 
  of 
  the 
  Edison 
  Electric 
  Institute's 
  (EEI) 
  list 
  
of 
  key 
  issues, 
  which 
  EEI 
  executives 
  talked 
  about 
  in 
  a 
  recent 
  briefing 
  with 
  Wall 
  Street 
  analysts, 
  executives, 
  
bankers 
  and 
  investors. 
  
 
  
Just 
  days 
  prior, 
  EEI 
  and 
  the 
  Natural 
  Resources 
  Defense 
  Council 
  (NRDC) 
  joined 
  forces 
  to 
  advance 
  utility 
  
policies 
  that 
  affect 
  the 
  electric 
  power 
  grid 
  for 
  the 
  benefit 
  of 
  all 
  electricity 
  customers 
  and 
  the 
  
environment, 
  encouraging 
  state 
  utility 
  regulators 
  to 
  implement 
  policies 
  that 
  balance 
  the 
  promotion 
  of 
  
innovation 
  while 
  supporting 
  fair 
  and 
  adequate 
  cost 
  recovery 
  for 
  maintaining 
  the 
  evolving 
  grid. 
  The 
  two 
  
groups 
  will 
  urge 
  state 
  utility 
  regulators 
  to 
  adopt 
  a 
  number 
  of 
  policies, 
  such 
  as 
  employing 
  new 
  rate 
  
designs 
  to 
  ensure 
  utilities 
  remain 
  financially 
  whole 
  when 
  they 
  help 
  customers 
  adopt 
  distributed 
  
generation 
  technologies 
  and 
  use 
  energy 
  more 
  efficiently 
  or 
  assuring 
  customers 
  that 
  costs 
  will 
  not 
  be 
  
shifted 
  unreasonably 
  to 
  them 
  from 
  other 
  customers. 
  
 
  
In 
  the 
  briefing, 
  EEI 
  Senior 
  Vice 
  President 
  Brian 
  Wolff 
  outlined 
  the 
  key 
  policy 
  issues 
  the 
  industry 
  will 
  face 
  
in 
  2014. 
  At 
  the 
  state 
  level, 
  one 
  of 
  the 
  most 
  critical 
  policy 
  debates 
  is 
  "the 
  expanding 
  role 
  that 
  distributed 
  
generation 
  (DG) 
  -­‐-­‐ 
  and 
  the 
  net 
  metering 
  policies 
  that 
  support 
  it 
  -­‐-­‐ 
  is 
  having 
  on 
  the 
  electric 
  grid." 
  
 
  
20 
  
 
  

 Wolff 
  emphasized 
  that 
  most 
  rooftop 
  solar 
  customers 
  rely 
  on 
  the 
  grid 
  around 
  the 
  clock. 
  However, 
  
because 
  of 
  the 
  way 
  that 
  state 
  net 
  metering 
  programs 
  are 
  structured, 
  rooftop 
  solar 
  customers 
  pay 
  less 
  
for 
  the 
  costs 
  of 
  the 
  grid 
  than 
  they 
  did 
  before 
  they 
  installed 
  their 
  DG 
  systems, 
  despite 
  their 
  continued 
  
reliance 
  on 
  the 
  grid 
  and 
  its 
  services. 
  
 
  
"It's 
  critical 
  -­‐-­‐ 
  and 
  fair 
  -­‐-­‐ 
  that 
  all 
  electricity 
  consumers 
  who 
  use 
  the 
  electric 
  power 
  grid 
  share 
  equitably 
  in 
  
the 
  costs 
  of 
  maintaining 
  it 
  and 
  keeping 
  it 
  operating 
  reliably 
  at 
  all 
  times. 
  The 
  cost 
  shifting 
  caused 
  by 
  
current 
  net 
  metering 
  policies 
  must 
  be 
  eliminated," 
  Wolff 
  said. 
  
 
  
Transforming 
  the 
  grid 
  requires 
  a 
  significant 
  investment. 
  In 
  2013, 
  the 
  industry 
  was 
  projected 
  to 
  spend 
  a 
  
record-­‐setting 
  $95.2 
  billion 
  in 
  capital 
  expenditures. 
  
 
  
EEI 
  continues 
  to 
  advocate 
  that 
  the 
  Federal 
  Energy 
  Regulatory 
  Commission 
  "provide 
  compensatory 
  
returns 
  on 
  equity 
  that 
  reflect 
  the 
  risks 
  of 
  development 
  and 
  the 
  long 
  asset 
  lives 
  of 
  transmission 
  facilities," 
  
according 
  to 
  EEI 
  Vice 
  President 
  of 
  Energy 
  Supply 
  and 
  Finance 
  Richard 
  McMahon. 
  
 
  
In 
  the 
  energy 
  supply 
  area, 
  McMahon 
  said 
  that 
  "as 
  energy 
  markets 
  change, 
  and 
  with 
  them, 
  our 
  industry's 
  
generation 
  fleet, 
  preserving 
  fuel 
  diversity 
  and 
  flexibility 
  remains 
  at 
  the 
  forefront 
  of 
  the 
  industry's 
  
priorities." 
  
 
  
On 
  the 
  environmental 
  front, 
  EEI 
  Vice 
  President 
  of 
  Environment 
  Quin 
  Shea 
  outlined 
  the 
  industry's 
  
regulatory 
  challenges 
  for 
  2014 
  and 
  beyond, 
  stressing 
  that 
  the 
  "electric 
  power 
  sector 
  has 
  made 
  
impressive 
  reductions 
  in 
  its 
  air 
  emissions 
  over 
  the 
  past 
  20 
  years, 
  during 
  a 
  time 
  when 
  electricity 
  use 
  grew 
  
by 
  almost 
  40 
  percent." 
  He 
  added 
  that 
  the 
  industry 
  continues 
  to 
  "support 
  achieving 
  the 
  nation's 
  
environmental 
  goals 
  in 
  a 
  manner 
  that 
  minimizes 
  costs 
  to 
  customers 
  and 
  is 
  consistent 
  with 
  the 
  industry's 
  
investment 
  in, 
  and 
  transition 
  to, 
  an 
  increasingly 
  cleaner, 
  safer, 
  and 
  more 
  reliable 
  generation 
  fleet 
  and 
  
enhanced 
  electric 
  grid." 
  
 
  
Among 
  the 
  pending 
  Environmental 
  Protection 
  Agency 
  (EPA) 
  regulations 
  affecting 
  the 
  industry 
  is 
  the 
  
section 
  316(b) 
  rule 
  under 
  the 
  Clean 
  Water 
  Act 
  (for 
  cooling 
  water 
  intake 
  structures), 
  which 
  Shea 
  calls 
  
"one 
  of 
  the 
  most 
  significant 
  rulemakings 
  facing 
  the 
  industry 
  this 
  year." 
  
 
  
The 
  rule 
  would 
  apply 
  to 
  all 
  existing 
  steam-­‐electric 
  facilities 
  and 
  could 
  cause 
  a 
  $100 
  billion 
  cost 
  impact 
  if 
  
all 
  affected 
  units 
  were 
  required 
  to 
  retrofit 
  with 
  cooling 
  towers, 
  which 
  could 
  threaten 
  reliability 
  and 
  lead 
  
to 
  premature 
  plant 
  closures. 
  
 
  
With 
  regard 
  to 
  the 
  proposed 
  greenhouse 
  gas 
  New 
  Source 
  Performance 
  Standards 
  (NSPS) 
  for 
  existing 
  
sources, 
  Shea 
  said, 
  "EPA 
  should 
  provide 
  states 
  with 
  maximum 
  flexibility 
  when 
  creating 
  compliance 
  plans 
  
and 
  that 
  there 
  should 
  be 
  credit 
  given 
  for 
  a 
  wide 
  range 
  of 
  actions 
  taken 
  to 
  date 
  that 
  have 
  resulted 
  in 
  GHG 
  
emission 
  reductions." 
  
 
  
This 
  year 
  will 
  be 
  critical 
  for 
  environmental 
  regulations. 
  
 
  
"While 
  we 
  do 
  not 
  fully 
  know 
  what 
  the 
  cumulative 
  effects 
  of 
  all 
  these 
  regulations 
  will 
  be 
  on 
  the 
  electric 
  
power 
  sector," 
  Shea 
  said, 
  "it 
  is 
  certain 
  that 
  they 
  will 
  have 
  a 
  significant 
  economic 
  impact 
  on 
  our 
  industry 
  
and 
  our 
  future 
  generation 
  fleet, 
  while 
  also 
  impacting 
  our 
  mission 
  to 
  keep 
  electricity 
  affordable 
  and 
  
reliable 
  for 
  all 
  customers." 
  
 
  
21 
  
 
  

 EEI, 
  NRDC 
  Launch 
  Common 
  Agenda 
  for 
  Structural 
  and 
  Regulatory 
  Reform 
    
  Electricity 
  Policy 
    
  
Ken 
  Maize 
    
  2/14/14 
  

http://www.electricitypolicy.com/news/6508-­‐eei,-­‐nrdc-­‐launch-­‐common-­‐agenda-­‐for-­‐structural-­‐and-­‐
regulatory-­‐reform 
   
  
 
  
The 
  lobbying 
  group 
  for 
  the 
  nation’s 
  investor-­‐owned 
  electric 
  utilities 
  and 
  one 
  of 
  the 
  country’s 
  leading 
  
environmental 
  groups 
  have 
  agreed 
  to 
  work 
  together 
  on 
  “ways 
  to 
  advance 
  support 
  for 
  utility 
  policies 
  that 
  
enhance 
  the 
  electric 
  power 
  grid 
  for 
  the 
  benefit 
  of 
  all 
  electricity 
  customers 
  and 
  the 
  environment.” 
  The 
  
Edison 
  Electric 
  Institute 
  and 
  the 
  Natural 
  Resources 
  Defense 
  Council 
  unveiled 
  their 
  accord 
  at 
  the 
  National 
  
Association 
  of 
  Regulatory 
  Utility 
  Commissioners’ 
  meeting 
  in 
  Washington 
  on 
  Wednesday. 
  
 
   
  
EEI”s 
  executive 
  vice 
  president 
  David 
  Owens 
  and 
  NRDC’s 
  Ralph 
  Cavanagh 
  touted 
  their 
  kumbaya 
  accord 
  as 
  
calling 
  on 
  “state 
  utility 
  regulators 
  to 
  adopt 
  a 
  number 
  of 
  policies 
  that 
  range 
  from 
  employing 
  new 
  rate 
  
designs 
  to 
  ensure 
  utilities 
  remain 
  financially 
  whole 
  when 
  they 
  help 
  customers 
  adopt 
  distributed 
  
generation 
  technologies 
  and 
  use 
  energy 
  more 
  efficiently 
  to 
  assuring 
  customers 
  that 
  costs 
  will 
  not 
  be 
  
shifted 
  unreasonably 
  to 
  them 
  from 
  other 
  customers.” 
  
 
   
  
Both 
  Owens 
  and 
  Cavanagh 
  are 
  veterans 
  of 
  the 
  long 
  and 
  sometimes 
  collaborative, 
  sometimes 
  
contentious, 
  relationship 
  between 
  electric 
  utilities 
  and 
  environmentalists. 
  At 
  the 
  NARUC 
  roll-­‐out 
  of 
  the 
  
agreement, 
  Owens 
  said, 
  “Today, 
  utilities 
  are 
  partnering 
  with 
  customers, 
  regulators 
  and 
  all 
  stakeholders 
  
to 
  transform 
  the 
  way 
  they 
  generate 
  and 
  deliver 
  electricity. 
  This 
  agreement 
  helps 
  chart 
  a 
  path 
  to 
  
success.” 
  Cavanagh, 
  who 
  has 
  been 
  at 
  the 
  forefront 
  of 
  electric 
  policy 
  as 
  long 
  as 
  Owens, 
  said, 
  “This 
  path-­‐
breaking 
  agreement 
  steers 
  us 
  toward 
  new 
  and 
  innovative 
  ways 
  to 
  increase 
  and 
  speed 
  the 
  development 
  
of 
  clean 
  energy 
  resources.” 
  
 
   
  
The 
  recommendations 
  of 
  the 
  joint 
  statement 
  – 
  aimed 
  squarely 
  at 
  the 
  state 
  regulators 
  at 
  the 
  NARUC 
  
Washington 
  meeting 
  – 
  make 
  eight 
  points, 
  mostly 
  related 
  to 
  issues 
  involving 
  decoupling 
  electricity 
  sales 
  
and 
  revenues, 
  supporting 
  net 
  metering 
  for 
  customers 
  with 
  their 
  own 
  generation, 
  rewarding 
  energy 
  
efficiency, 
  and 
  boosting 
  deployment 
  of 
  “smart 
  grid” 
  technologies. 
  
 
   
  
The 
  crux 
  of 
  the 
  EEI/NRDC 
  agreement: 
  
 
   
  
—Electricity 
  distribution 
  is 
  not 
  “a 
  commodity 
  business 
  dependent 
  on 
  growth 
  in 
  electricity 
  usage 
  to 
  keep 
  
its 
  owners 
  financially 
  whole.” 
  This 
  is 
  a 
  clear 
  pitch 
  for 
  decoupling 
  of 
  sales 
  and 
  rates. 
  
 
   
  
—If 
  regulators 
  agree 
  to 
  decoupling, 
  “they 
  should 
  provide 
  for 
  reasonable 
  and 
  predictable 
  annual 
  
adjustments 
  in 
  utilities” 
  authorized 
  non-­‐fuel 
  revenue 
  requirements.” 
  
 
   
  
—Net 
  metering 
  programs 
  for 
  distributed 
  generation 
  such 
  as 
  rooftop 
  solar, 
  are 
  positive 
  for 
  society. 
  But 
  
that 
  does 
  not 
  “reduce 
  a 
  grid’s 
  need 
  for 
  central 
  station 
  generation 
  and 
  other 
  infrastructure,” 
  and 
  
“typically 
  does 
  not 
  eliminate” 
  the 
  owner 
  of 
  the 
  generating 
  assets 
  need 
  for 
  “grid 
  services. 
  For 
  example, 
  
solar 
  generation 
  at 
  a 
  residence 
  typically 
  does 
  not 
  align 
  perfectly 
  with 
  the 
  occupants” 
  energy 
  use, 
  
requiring 
  some 
  use 
  of 
  the 
  grid 
  as 
  the 
  equivalent 
  of 
  a 
  battery.” 
  
 
   
  
—Rate 
  designs 
  should 
  “reward 
  customers 
  for 
  using 
  electricity 
  more 
  efficiently. 
  Examples 
  include, 
  but 
  
are 
  not 
  limited 
  to, 
  real-­‐time 
  pricing 
  and 
  variable 
  demand 
  charges 
  that 
  take 
  advantage 
  of 
  digital 
  meter 
  
capabilities 
  where 
  available.” 
  This 
  is 
  based 
  on 
  the 
  principle 
  that 
  utilities 
  “deserve 
  assurances 
  that 
  
recover 
  of 
  their 
  authorized 
  non-­‐fuel 
  costs 
  will 
  not 
  vary 
  with 
  fluctuations 
  in 
  electricity 
  use.” 
  
22 
  
 
  

  
   
  
—Tying 
  IOU 
  earnings 
  to 
  “benefits 
  delivered 
  to 
  their 
  customers 
  by 
  cost-­‐effective 
  initiatives 
  to 
  improve 
  
energy 
  efficiency, 
  integrate 
  clean 
  energy 
  generation, 
  and 
  improve 
  grids” 
  should 
  be 
  part 
  of 
  regulatory 
  
practice. 
  
 
   
  
—The 
  parties 
  will 
  work 
  “together 
  to 
  ensure 
  that 
  energy 
  efficiency 
  services 
  reach 
  underserved 
  
populations, 
  including 
  the 
  increased 
  deployment 
  of 
  utility 
  programs 
  focused 
  on 
  affordable 
  multi-­‐family 
  
housing.” 
  
 
   
  
—EEI 
  and 
  NRDC 
  “reaffirm 
  their 
  goal” 
  of 
  advancing 
  “cost-­‐effective 
  energy 
  efficiency 
  opportunities 
  
through 
  an 
  integrated 
  combination 
  of 
  financial 
  incentives 
  to 
  customers 
  and 
  minimum 
  standards 
  
governing 
  the 
  performance 
  of 
  buildings 
  and 
  equipment….” 
  
 
   
  
—State 
  regulators 
  should, 
  “when 
  presented 
  with 
  a 
  reasonable 
  business 
  case 
  by 
  utilities,” 
  support 
  utility 
  
cost 
  recovery 
  of 
  “significantly 
  enhanced 
  investment” 
  in 
  smart 
  meters 
  and 
  smart 
  grid 
  technologies. 
  
 
  
Utilities 
  And 
  Greenies 
  Try 
  To 
  Cool 
  Off 
  Grid 
  Disputes 
    
  Forbes 
    
  Ken 
  Silverstein 
    
  2/20/14 
  
http://www.forbes.com/sites/kensilverstein/2014/02/20/utilities-­‐and-­‐greenies-­‐try-­‐to-­‐cool-­‐off-­‐grid-­‐
disputes/ 
   
  
The 
  heated 
  discussion 
  between 
  utilities 
  that 
  maintain 
  the 
  wires 
  and 
  rooftop 
  solar 
  users 
  that 
  have 
  
“detached” 
  from 
  the 
  grid 
  is 
  sweeping 
  the 
  nation. 
  But 
  a 
  cooling 
  period 
  may 
  be 
  in 
  the 
  offing 
  now 
  that 
  the 
  
two 
  sides 
  have 
  agreed 
  that 
  utility 
  services 
  aren’t 
  free 
  and 
  that 
  those 
  costs 
  must 
  be 
  “fairly” 
  shared. 
  
Both 
  the 
  Edison 
  Edison 
  Electric 
  Institute 
  and 
  the 
  Natural 
  Resources 
  Defense 
  Council 
  realize 
  that 
  if 
  the 
  
grid 
  is 
  not 
  modernized 
  and 
  expanded 
  then 
  it 
  would 
  jeopardize 
  economic 
  growth 
  and 
  renewable 
  energy 
  
expansion. 
  That’s 
  why 
  they 
  have 
  issued 
  a 
  position 
  paper 
  that 
  says 
  distributed 
  generation 
  owners 
  — 
  
erstwhile 
  rooftop 
  solar 
  customers 
  — 
  must 
  pay 
  their 
  utilities 
  a 
  reasonable 
  rate 
  for 
  the 
  services 
  that 
  they 
  
use. 
  Likewise, 
  homeowners 
  must 
  get 
  a 
  fair 
  price 
  for 
  the 
  electric 
  services 
  they 
  sell 
  back 
  to 
  their 
  utilities. 
  
“The 
  electric 
  power 
  industry’s 
  mission 
  is 
  to 
  provide 
  safe, 
  reliable, 
  affordable, 
  and 
  increasingly 
  clean 
  
electricity. 
  Today 
  utilities 
  are 
  partnering 
  with 
  customers, 
  regulators 
  and 
  all 
  stakeholders 
  to 
  transform 
  
the 
  way 
  they 
  generate 
  and 
  deliver 
  electricity. 
  This 
  agreement 
  helps 
  chart 
  a 
  path 
  to 
  success,” 
  says 
  David 
  
Owens, 
  executive 
  vice 
  president 
  for 
  the 
  institute 
  that 
  represents 
  investor-­‐owned 
  utilities. 
  
With 
  the 
  demand 
  for 
  energy 
  expected 
  to 
  rise 
  in 
  the 
  coming 
  years, 
  the 
  grid 
  would 
  have 
  to 
  grow 
  along 
  
with 
  it. 
  But 
  if 
  increasing 
  numbers 
  of 
  people 
  “unplug” 
  from 
  their 
  local 
  utilities, 
  then 
  the 
  cost 
  of 
  that 
  
expansion 
  would 
  fall 
  on 
  a 
  fewer 
  number 
  of 
  customers. 
  That 
  would 
  harm 
  electric 
  reliability 
  and 
  it 
  would 
  
certainly 
  hurt 
  those 
  wind 
  and 
  solar 
  developers 
  that 
  use 
  the 
  transmission 
  network. 
  
But 
  it’s 
  not 
  so 
  simple: 
  Distributed 
  solar 
  customers 
  still 
  use 
  the 
  wires 
  — 
  either 
  to 
  get 
  electricity 
  on 
  cloudy 
  
days 
  or 
  to 
  send 
  their 
  excess 
  power 
  to 
  utilities, 
  which 
  can 
  then 
  avoid 
  buying 
  it 
  on 
  expensive 
  spot 
  
markets. 
  
The 
  two 
  sides 
  have 
  been 
  battling 
  over 
  cost 
  allocation. 
  Rooftop 
  solar 
  customers 
  want 
  to 
  pay 
  as 
  little 
  as 
  
possible 
  to 
  remain 
  minimally 
  connected 
  to 
  the 
  grid 
  while 
  they 
  want 
  to 
  receive 
  the 
  full 
  retail 
  rate 
  for 
  the 
  
power 
  that 
  they 
  sell 
  back 
  to 
  utilities. 
  Utilities, 
  meanwhile, 
  want 
  more 
  money 
  from 
  homeowners 
  to 
  
maintain 
  the 
  networks 
  and 
  they 
  only 
  want 
  to 
  pay 
  homeowners 
  the 
  wholesale 
  cost 
  of 
  the 
  power 
  they 
  
send 
  back 
  to 
  them 
  through 
  those 
  same 
  wires. 
  

23 
  
 
  

 The 
  battle 
  is 
  ongoing 
  in 
  California 
  and 
  Arizona 
  while 
  it 
  is 
  peaking 
  now 
  in 
  Colorado. 
  It 
  then 
  heads 
  to 
  such 
  
states 
  as 
  Texas, 
  Louisiana 
  and 
  Vermont. 
  
“Installations 
  are 
  up 
  34 
  percent 
  in 
  Colorado 
  in 
  2013,” 
  says 
  Mark 
  Stutz, 
  spokesman 
  for 
  Xcel 
  Energy 
  in 
  
Colorado. 
  “If 
  you 
  look 
  at 
  the 
  rooftop 
  benefits, 
  it 
  does 
  offset 
  some 
  of 
  our 
  generation. 
  But 
  it 
  does 
  not 
  
cover 
  the 
  full 
  distribution 
  and 
  transmission 
  costs, 
  which 
  our 
  customers 
  pay 
  for.” 
  
State 
  utility 
  commissions 
  understand 
  implicitly 
  the 
  issue 
  and 
  what 
  is 
  at 
  stake. 
  That’s 
  why 
  the 
  Edison 
  
Electric 
  Institute’s 
  and 
  the 
  Natural 
  Resources 
  Defense 
  Council’s 
  proposal 
  is 
  crucial 
  here. 
  Much 
  of 
  the 
  
substance 
  of 
  their 
  joint 
  statement 
  concerns 
  the 
  “decoupling” 
  of 
  retail 
  sales 
  from 
  a 
  utility’s 
  financial 
  
performance. 
  Instead, 
  the 
  relationship 
  should 
  focus 
  on 
  meeting 
  customers’ 
  energy 
  service 
  needs. 
  
The 
  idea 
  is 
  to 
  separate 
  utility 
  rates 
  from 
  their 
  sales 
  volume. 
  That 
  allows 
  utilities 
  to 
  promote 
  energy 
  
efficiency 
  while 
  still 
  recouping 
  their 
  allowable 
  expenses. 
  Under 
  traditional 
  regulatory 
  structures, 
  utility 
  
earnings 
  are 
  tied 
  to 
  the 
  volume 
  of 
  electricity 
  and 
  natural 
  gas 
  that 
  customers 
  use. 
  So, 
  even 
  a 
  small 
  
reduction 
  in 
  consumption 
  can 
  make 
  a 
  large 
  cut 
  into 
  a 
  utility’s 
  profitability. 
  This 
  presents 
  a 
  strong 
  
financial 
  disincentive 
  for 
  those 
  companies 
  to 
  push 
  energy 
  efficiency. 
  
Several 
  electric 
  and 
  natural 
  gas 
  utilities 
  are 
  working 
  with 
  their 
  state 
  commissioners 
  to 
  reform 
  the 
  way 
  
their 
  rates 
  are 
  set 
  up. 
  The 
  key 
  to 
  success, 
  supporters 
  say, 
  is 
  for 
  regulators 
  to 
  authorize 
  the 
  recovery 
  of 
  
fixed 
  costs 
  regardless 
  of 
  sales. 
  
The 
  more 
  energy-­‐saving 
  projects 
  that 
  are 
  executed, 
  the 
  greater 
  impact 
  it 
  will 
  have 
  on 
  demand. 
  Reduced 
  
consumption, 
  in 
  turn, 
  should 
  lessen 
  the 
  need 
  to 
  construct 
  an 
  ever-­‐expanding 
  infrastructure. 
  The 
  savings 
  
could 
  be 
  passed 
  through 
  to 
  both 
  customers 
  and 
  shareholders. 
  
“This 
  path-­‐breaking 
  agreement 
  steers 
  us 
  toward 
  new 
  and 
  innovative 
  ways 
  to 
  increase 
  and 
  speed 
  the 
  
deployment 
  of 
  clean 
  energy 
  resources,” 
  says 
  Ralph 
  Cavanagh, 
  co-­‐director 
  of 
  NRDC’s 
  energy 
  program. 
  
“NRDC 
  has 
  long 
  advocated 
  for 
  the 
  increased 
  integration 
  of 
  energy 
  efficiency 
  and 
  renewable 
  energy 
  into 
  
the 
  nation’s 
  electric 
  grid.” 
  
Grid 
  expansion 
  and 
  onsite 
  generation 
  are 
  inherently 
  in 
  conflict. 
  But 
  the 
  reality 
  is 
  that 
  both 
  technologies 
  
are 
  vital 
  to 
  the 
  national 
  economic 
  and 
  environmental 
  aspirations. 
  The 
  Edison 
  Electric 
  Institute 
  and 
  the 
  
Natural 
  Resources 
  Defense 
  Council 
  understand 
  this. 
  Now 
  it 
  is 
  a 
  function 
  of 
  a 
  getting 
  others 
  to 
  recognize 
  
the 
  importance 
  of 
  both 
  ideas, 
  especially 
  rooftop 
  solar 
  users. 
  

Solar 
  Industry, 
  Utilities 
  Seek 
  Common 
  Ground 
    
  National 
  Journal 
    
  Clare 
  Foran 
    
  2/21/14 
  
http://www.nationaljournal.com/daily/solar-­‐industry-­‐utilities-­‐seek-­‐common-­‐ground-­‐20140220 
   
  
A 
  divide 
  within 
  the 
  solar 
  industry 
  over 
  whether 
  utilities 
  are 
  an 
  ally 
  or 
  an 
  adversary 
  could 
  be 
  a 
  stumbling 
  
block 
  in 
  emerging 
  efforts 
  to 
  overhaul 
  rate 
  structures 
  for 
  customers 
  who 
  provide 
  some 
  of 
  their 
  own 
  
electricity. 
  
With 
  rooftop 
  solar 
  panels 
  popping 
  up 
  across 
  the 
  country 
  at 
  a 
  record 
  pace, 
  rate 
  issues 
  have 
  taken 
  center 
  
stage 
  in 
  high-­‐profile 
  regulatory 
  cases 
  in 
  Arizona, 
  California, 
  and 
  other 
  states 
  over 
  the 
  past 
  year. 
  The 
  
issues 
  are 
  nowhere 
  near 
  settled, 
  but 
  certain 
  segments 
  of 
  the 
  solar 
  industry 
  and 
  some 
  of 
  its 
  backers 
  say 
  
there 
  should 
  be 
  less 
  squabbling 
  and 
  more 
  cooperating 
  between 
  clean-­‐energy 
  providers 
  and 
  big 
  utilities. 
  
There 
  is 
  even 
  a 
  new 
  effort 
  by 
  two 
  major 
  organizations 
  often 
  at 
  odds 
  with 
  each 
  other 
  to 
  open 
  a 
  dialogue 
  
on 
  the 
  issue. 
  

24 
  
 
  

 Last 
  week, 
  the 
  Edison 
  Electric 
  Institute, 
  a 
  trade 
  association 
  representing 
  investor-­‐owned 
  electric 
  
companies, 
  and 
  the 
  Natural 
  Resources 
  Defense 
  Council, 
  one 
  of 
  the 
  nation's 
  largest 
  environmental 
  
groups, 
  released 
  a 
  joint 
  statement 
  in 
  support 
  of 
  policy 
  changes 
  to 
  help 
  put 
  more 
  clean 
  energy 
  on 
  the 
  
grid. 
  
"What 
  we're 
  trying 
  to 
  do 
  now 
  is 
  start 
  a 
  conversation 
  between 
  utility 
  and 
  solar 
  providers 
  so 
  that 
  we 
  can 
  
equitably 
  solve 
  the 
  cost 
  of 
  using 
  the 
  grid," 
  said 
  Ralph 
  Cavanagh, 
  codirector 
  of 
  NRDC's 
  energy 
  program. 
  
When 
  it 
  comes 
  to 
  the 
  substance 
  of 
  that 
  conversation, 
  however, 
  the 
  solar 
  industry 
  is 
  split. 
  A 
  major 
  
reason 
  for 
  that 
  is 
  disagreement 
  within 
  the 
  industry 
  over 
  whether 
  utilities 
  are 
  friends 
  or 
  foes. 
  
"The 
  solar 
  industry 
  is 
  very 
  diverse, 
  and 
  when 
  you 
  look 
  at 
  the 
  various 
  interests 
  at 
  play, 
  they 
  don't 
  
necessarily 
  align," 
  said 
  Julia 
  Hamm, 
  president 
  and 
  CEO 
  of 
  the 
  Solar 
  Electric 
  Power 
  Association, 
  which 
  
counts 
  both 
  solar 
  companies 
  and 
  utilities 
  among 
  its 
  members. 
  "But 
  a 
  growing 
  number 
  of 
  voices 
  in 
  the 
  
industry 
  are 
  willing 
  to 
  sit 
  down 
  with 
  utilities 
  and 
  talk 
  about 
  finding 
  a 
  solution 
  that 
  benefits 
  everyone." 
  
One 
  segment 
  of 
  the 
  small 
  but 
  growing 
  solar 
  industry 
  has 
  little 
  trust 
  in 
  power-­‐company 
  giants. 
  
"Utilities 
  are 
  constantly 
  trying 
  to 
  change 
  the 
  rules 
  in 
  a 
  way 
  that 
  would 
  hurt 
  solar," 
  said 
  Bryan 
  Miller, 
  
president 
  of 
  the 
  Alliance 
  for 
  Solar 
  Choice, 
  an 
  advocacy 
  group 
  for 
  rooftop 
  solar 
  providers. 
  "We've 
  worked 
  
to 
  start 
  up 
  negotiations, 
  and 
  in 
  some 
  cases 
  utilities 
  have 
  been 
  open 
  to 
  discussion, 
  but 
  in 
  many 
  situations 
  
what 
  we're 
  seeing 
  is 
  that 
  they 
  insist 
  on 
  nothing 
  short 
  of 
  pushing 
  policies 
  that 
  would 
  kill 
  rooftop 
  solar." 
  
Other 
  members 
  of 
  the 
  solar 
  supply 
  chain 
  see 
  things 
  differently. 
  "A 
  large 
  segment 
  of 
  the 
  solar 
  industry 
  
has 
  an 
  outstanding 
  relationship 
  with 
  the 
  utilities," 
  said 
  Jim 
  Hughes, 
  CEO 
  of 
  First 
  Solar, 
  a 
  solar-­‐panel 
  
manufacturer 
  and 
  services 
  provider. 
  "We 
  work 
  very 
  closely 
  with 
  utility 
  providers—they're 
  some 
  of 
  our 
  
largest 
  customers." 
  
At 
  the 
  heart 
  of 
  the 
  disputes 
  are 
  rate 
  structures 
  for 
  customers 
  with 
  solar 
  panels. 
  
Solar 
  users 
  in 
  most 
  states 
  can 
  sell 
  excess 
  power 
  back 
  to 
  the 
  grid—a 
  policy 
  that 
  rooftop 
  solar 
  companies 
  
say 
  is 
  sound. 
  But 
  utilities 
  argue 
  that 
  the 
  flood 
  of 
  electricity 
  has 
  strained 
  the 
  system, 
  and 
  they 
  want 
  
residential 
  solar 
  customers 
  to 
  pay 
  extra 
  as 
  a 
  result. 
  
This 
  divide 
  could 
  become 
  a 
  stumbling 
  block 
  in 
  efforts 
  to 
  broker 
  consensus 
  over 
  rate 
  structures. 
  
"We're 
  not 
  all 
  on 
  the 
  same 
  page 
  right 
  now, 
  and 
  that's 
  only 
  natural 
  because 
  we're 
  a 
  young 
  industry," 
  said 
  
Tom 
  Werner, 
  CEO 
  of 
  SunPower, 
  a 
  solar-­‐panel 
  designer 
  and 
  manufacturer 
  and 
  provider 
  of 
  both 
  utility-­‐
scale 
  and 
  residential 
  solar. 
  "But 
  energy 
  is 
  a 
  policy-­‐driven 
  market, 
  so 
  a 
  fragmented 
  approach 
  won't 
  work 
  
in 
  the 
  big 
  picture." 
  
The 
  road 
  to 
  regulatory 
  change 
  will 
  undoubtedly 
  be 
  rocky. 
  Despite 
  the 
  challenge, 
  industry 
  backers 
  remain 
  
optimistic 
  that 
  solar 
  can 
  find 
  its 
  way. 
  
"There 
  is 
  common 
  ground 
  [between 
  utilities 
  and 
  the 
  solar 
  industry], 
  and 
  that's 
  to 
  provide 
  energy 
  and 
  
consumer 
  choice. 
  As 
  long 
  as 
  we 
  have 
  a 
  true 
  north, 
  we'll 
  get 
  there," 
  Werner 
  said. 
  

Give 
  solar 
  energy 
  a 
  fair 
  chance 
  in 
  Utah 
    
  Salt 
  Lake 
  Tribune 
    
  Op-­‐ed: 
  By 
  Barry 
  Goldwater 
  Jr. 
    
  
2/22/14 
  
http://m.sltrib.com/sltrib/mobile3/57579507-­‐219/solar-­‐energy-­‐choice-­‐utah.html.csp 
   
  
25 
  
 
  

 The 
  utility 
  monopoly 
  assault 
  on 
  solar 
  energy 
  is 
  spreading 
  from 
  state 
  to 
  state, 
  and 
  Utah 
  appears 
  to 
  be 
  
next. 
  On 
  Feb. 
  1, 
  The 
  Salt 
  Lake 
  Tribune 
  published 
  an 
  editorial, 
  "Rates 
  should 
  be 
  fair, 
  and 
  green." 
  
 
  
The 
  arguments 
  for 
  a 
  tax 
  on 
  solar 
  energy 
  sound 
  very 
  much 
  like 
  what 
  utility 
  monopoly 
  Arizona 
  Public 
  
Service 
  (APS) 
  is 
  saying 
  in 
  Arizona. 
  
My 
  name 
  is 
  Barry 
  Goldwater 
  Jr. 
  and 
  I 
  am 
  Co-­‐Chairman 
  of 
  TUSK, 
  which 
  stands 
  for 
  Tell 
  Utilities 
  Solar 
  won’t 
  
be 
  Killed. 
  Just 
  as 
  my 
  father 
  stood 
  for 
  conservative 
  values 
  such 
  as 
  choice 
  and 
  free 
  markets, 
  I 
  stand 
  for 
  
energy 
  choice 
  and 
  energy 
  independence. 
  We 
  fought 
  APS’ 
  attempts 
  to 
  kill 
  solar 
  when 
  the 
  utility 
  
proposed 
  a 
  $50-­‐$100 
  a 
  month 
  solar 
  tax. 
  Instead, 
  the 
  utility 
  got 
  a 
  $5 
  a 
  month 
  tax 
  imposed 
  on 
  new 
  
rooftop 
  solar 
  customers. 
  Despite 
  our 
  efforts, 
  the 
  tax 
  has 
  already 
  led 
  to 
  noticeable 
  reductions 
  in 
  rooftop 
  
solar 
  installations 
  in 
  my 
  state. 
  Indeed, 
  they 
  have 
  been 
  cut 
  in 
  half. 
  APS 
  used 
  government 
  intervention 
  to 
  
harm 
  a 
  competitor. 
  That’s 
  bad 
  for 
  the 
  economy 
  and 
  it’s 
  certainly 
  not 
  the 
  conservative 
  way. 
  
Conservatives 
  stand 
  for 
  choice, 
  whether 
  it’s 
  school 
  choice, 
  health 
  care 
  choice, 
  or 
  energy 
  choice. 
  
Conservatives 
  believe 
  in 
  energy 
  independence 
  and 
  solar 
  plays 
  an 
  important 
  part 
  in 
  achieving 
  that 
  goal. 
  
Make 
  no 
  mistake, 
  Rocky 
  Mountain 
  Power 
  is 
  taking 
  a 
  page 
  from 
  APS’ 
  playbook 
  in 
  seeking 
  a 
  $4.25 
  tax 
  on 
  
rooftop 
  solar 
  users. 
  The 
  utility 
  knows 
  that 
  such 
  a 
  tax 
  would 
  slow 
  and 
  damage 
  the 
  emerging 
  rooftop 
  solar 
  
industry 
  in 
  Utah. 
  What’s 
  more, 
  from 
  the 
  editorial, 
  it 
  sounds 
  like 
  Rocky 
  Mountain 
  Power 
  is 
  also 
  working 
  
on 
  a 
  change 
  to 
  Utah 
  policy 
  that 
  would 
  guarantee 
  that 
  their 
  tax 
  request 
  is 
  granted, 
  without 
  sound 
  
analysis 
  and 
  in 
  spite 
  of 
  what 
  the 
  evidence 
  may 
  show. 
  
Conservatives 
  support 
  solar 
  power 
  because 
  it 
  encourages 
  the 
  free 
  market 
  over 
  monopolies, 
  because 
  it 
  
creates 
  jobs, 
  and 
  because 
  an 
  America 
  less 
  dependent 
  on 
  fossil 
  fuels 
  is 
  a 
  stronger 
  America. 
  Those 
  
arguments 
  are 
  not 
  lost 
  on 
  GOP 
  voters 
  in 
  Arizona. 
  In 
  an 
  August 
  2013 
  poll, 
  84 
  percent 
  of 
  Republican 
  
voters 
  in 
  the 
  Phoenix 
  area 
  said 
  they 
  would 
  be 
  less 
  likely 
  to 
  vote 
  for 
  a 
  candidate 
  who 
  voted 
  to 
  end 
  the 
  
program. 
  Another 
  2013 
  poll 
  conducted 
  in 
  all 
  Western 
  States 
  found 
  that 
  solar 
  and 
  other 
  renewables 
  
ranked 
  first 
  in 
  most 
  states 
  when 
  voters 
  were 
  asked 
  what 
  two 
  energy 
  sources 
  they 
  wanted 
  to 
  see 
  more 
  
money 
  spent 
  on. 
  
The 
  potential 
  for 
  solar 
  energy 
  in 
  Utah 
  is 
  enormous. 
  Despite 
  an 
  abundance 
  of 
  sunshine, 
  Utah 
  only 
  
generates 
  .075 
  percent 
  of 
  its 
  energy 
  with 
  solar 
  power. 
  Allowing 
  private 
  enterprise 
  and 
  the 
  rooftop 
  solar 
  
industry 
  to 
  thrive 
  could 
  drastically 
  change 
  that 
  number. 
  It 
  would 
  also 
  give 
  energy 
  customers 
  in 
  Utah 
  a 
  
choice 
  as 
  to 
  how 
  they 
  get 
  their 
  electricity. 
  Rocky 
  Mountain 
  Power 
  knows 
  this. 
  That’s 
  why 
  they 
  are 
  acting 
  
pro-­‐actively 
  to 
  kill 
  off 
  a 
  competitor. 
  Let’s 
  hope 
  regulators 
  and 
  policy 
  makers 
  in 
  Utah 
  know 
  better. 
  
Barry 
  Goldwater 
  Jr. 
  is 
  a 
  former 
  congressman 
  and 
  chairman 
  of 
  TUSK 
  (Tell 
  Utilities 
  Solar 
  won’t 
  be 
  Killed). 
  
 
  
 
  

Yergin: 
  Germany 
  Must 
  Focus 
  on 
  Cost-­‐Effective 
  Renewable 
  Energy 
    
  The 
  Wall 
  Street 
  Journal 
    
  
Jan 
  Hromadko 
    
  2/26/14 
  
http://online.wsj.com/news/articles/SB10001424052702304071004579407082647574004 
   
  
FRANKFURT—Germany 
  needs 
  to 
  focus 
  on 
  cost-­‐effective 
  renewable 
  energy 
  sources 
  and 
  start 
  drilling 
  for 
  
shale 
  gas 
  to 
  avoid 
  sapping 
  its 
  wealth 
  while 
  cutting 
  carbon 
  emissions, 
  said 
  energy 
  expert 
  Daniel 
  Yergin. 
   
  

26 
  
 
  

 Europe's 
  largest 
  economy 
  is 
  pursuing 
  one 
  of 
  the 
  world's 
  most 
  ambitious 
  climate-­‐protection 
  strategies, 
  
aiming 
  by 
  midcentury 
  to 
  nearly 
  eliminate 
  greenhouse 
  gas 
  emissions. 
  To 
  achieve 
  this 
  it 
  plans 
  to 
  drop 
  all 
  
nuclear 
  and 
  most 
  fossil-­‐fueled 
  power 
  generation 
  in 
  favor 
  of 
  alternatives 
  like 
  wind 
  and 
  solar 
  power. 
  
But 
  the 
  shift, 
  financed 
  through 
  surcharges 
  on 
  power 
  bills, 
  has 
  sent 
  electricity 
  prices 
  soaring. 
  Companies 
  
say 
  they 
  face 
  a 
  competitive 
  disadvantage 
  in 
  Germany 
  compared 
  with 
  the 
  U.S. 
  and 
  other 
  locations. 
  
Mr. 
  Yergin, 
  an 
  author 
  on 
  energy 
  issues 
  and 
  vice 
  chairman 
  at 
  consulting 
  firm 
  IHS, 
  said 
  in 
  an 
  interview 
  that 
  
Germany 
  should 
  scale 
  back 
  its 
  plans 
  for 
  expensive 
  renewables 
  and 
  complement 
  the 
  drive 
  with 
  more 
  
domestic 
  natural 
  gas 
  production. 
  
IHS 
  on 
  Thursday 
  published 
  an 
  analysis 
  of 
  Germany's 
  plans, 
  which 
  the 
  government 
  of 
  Chancellor 
  Angela 
  
Merkel 
  is 
  now 
  revising. 
  IHS 
  prepared 
  the 
  report 
  for 
  clients 
  including 
  Germany's 
  chemical 
  industry 
  
association 
  and 
  companies 
  including 
  Exxon 
  Mobil 
  Corp. 
  and 
  BASF 
  SE. 
  IHS 
  provided 
  an 
  advance 
  copy 
  to 
  
The 
  Wall 
  Street 
  Journal. 
  
 
  
A 
  spokesman 
  for 
  Germany's 
  energy 
  ministry 
  declined 
  to 
  comment 
  on 
  the 
  analysis 
  Wednesday 
  because 
  it 
  
had 
  not 
  yet 
  been 
  published. 
  
Profoundly 
  revamping 
  the 
  German 
  energy 
  transition 
  and 
  developing 
  shale 
  gas 
  could 
  boost 
  Germany's 
  
gross 
  domestic 
  product 
  by 
  nearly 
  €140 
  billion 
  through 
  2040, 
  or 
  3.4%, 
  and 
  create 
  around 
  1 
  million 
  new 
  
jobs, 
  Mr. 
  Yergin 
  said. 
  
Germany's 
  current 
  plans 
  will 
  cost 
  it 
  €185 
  billion 
  over 
  the 
  next 
  two 
  decades, 
  IHS 
  concluded. 
  
Without 
  revisions, 
  "Germany 
  will 
  lose 
  industrial 
  capacity 
  because 
  investment 
  moves 
  offshore, 
  which 
  
would 
  have 
  a 
  significant 
  impact 
  on 
  economic 
  growth, 
  employment 
  and 
  government 
  revenues," 
  Mr. 
  
Yergin 
  said. 
  
Germany's 
  shift 
  comes 
  as 
  the 
  rapid 
  development 
  of 
  shale 
  gas 
  in 
  North 
  America 
  has 
  made 
  the 
  U.S. 
  much 
  
more 
  attractive 
  for 
  manufacturing 
  and 
  exporting. 
  Average 
  industrial 
  electricity 
  prices 
  in 
  Germany 
  have 
  
risen 
  approximately 
  60% 
  since 
  2007, 
  while 
  price 
  in 
  the 
  U.S. 
  and 
  China 
  have 
  increased 
  less 
  than 
  10%, 
  IHS 
  
calculated. 
  
Ms. 
  Merkel's 
  new 
  government 
  has 
  already 
  pledged 
  to 
  slow 
  the 
  expansion 
  of 
  renewable 
  energies 
  to 
  
contain 
  costs 
  and 
  protect 
  German 
  business 
  interests 
  and 
  jobs. 
  Energy 
  Minister 
  Sigmar 
  Gabriel 
  said 
  last 
  
month 
  the 
  German 
  economy 
  cannot 
  handle 
  more 
  energy-­‐price 
  increases. 
  
Mr. 
  Yergin 
  said 
  the 
  statements 
  shows 
  the 
  government 
  appreciates 
  new 
  realities 
  in 
  global 
  energy 
  
markets. 
  "But 
  so 
  far, 
  it 
  has 
  been 
  a 
  shift 
  in 
  attitude 
  and 
  only 
  a 
  limited 
  change 
  of 
  policies," 
  he 
  said. 
  
One 
  shortcoming 
  he 
  cited 
  in 
  Germany's 
  reform 
  proposals 
  is 
  what 
  he 
  called 
  excessive 
  focus 
  on 
  offshore 
  
wind 
  energy. 
  Placing 
  wind 
  turbines 
  far 
  at 
  sea 
  is 
  appealing 
  because 
  it 
  provides 
  more 
  constant 
  power 
  than 
  
most 
  other 
  green 
  energy 
  sources. 
  But 
  wind 
  farms 
  in 
  deep, 
  remote 
  waters 
  are 
  much 
  more 
  expensive 
  to 
  
build, 
  connect 
  and 
  maintain 
  than 
  ones 
  in 
  shallower 
  coastal 
  waters, 
  as 
  the 
  U.K. 
  and 
  other 
  countries 
  have 
  
built. 
  
Germany 
  has 
  cut 
  its 
  target 
  for 
  offshore 
  wind 
  capacity 
  in 
  2030 
  to 
  15 
  gigawatts 
  from 
  25 
  gigawatts 
  but 
  IHS 
  
estimates 
  the 
  economy 
  can 
  afford 
  to 
  develop 
  only 
  6.5 
  gigawatts. 
  
Mr. 
  Yergin 
  also 
  criticized 
  Germany's 
  lack 
  of 
  support 
  for 
  natural 
  gas 
  exploration. 
  The 
  IHS 
  study 
  said 
  
developing 
  natural 
  gas 
  supplies 
  in 
  Germany 
  and 
  around 
  the 
  EU 
  could 
  cut 
  European 
  gas 
  prices 
  by 
  up 
  to 
  
20%. 
  IHS 
  estimated 
  German 
  production 
  could 
  cover 
  more 
  than 
  35% 
  of 
  its 
  domestic 
  gas 
  consumption. 
  
27 
  
 
  

 Domestic 
  shale 
  gas 
  production 
  could 
  also 
  help 
  Germany 
  reduce 
  greenhouse 
  gas 
  emissions, 
  IHS 
  
predicted. 
  An 
  unexpected 
  side 
  effect 
  of 
  energy-­‐market 
  upheaval 
  from 
  Germany's 
  renewables 
  push 
  has 
  
been 
  an 
  increased 
  use 
  of 
  coal. 
  Coal 
  is 
  inexpensive 
  but 
  among 
  the 
  most 
  polluting 
  fuels 
  available. 
  
"Lower 
  priced 
  gas 
  would 
  make 
  lower-­‐carbon, 
  gas-­‐fired 
  power 
  generation 
  more 
  economic 
  than 
  coal, 
  
which 
  is 
  presently 
  more 
  economic," 
  IHS 
  said. 
  
Shale 
  gas 
  production 
  is 
  controversial 
  across 
  Europe, 
  however. 
  The 
  hydraulic 
  fracturing 
  process, 
  known 
  
as 
  fracking, 
  is 
  opposed 
  by 
  many 
  environmentalists 
  and 
  residents 
  near 
  gas 
  fields, 
  who 
  fear 
  fracking 
  may 
  
contaminate 
  groundwater. 
  Germany 
  has 
  effectively 
  banned 
  fracking. 
  
While 
  Mr. 
  Yergin 
  criticized 
  most 
  of 
  Germany's 
  energy 
  policies, 
  he 
  supported 
  its 
  position 
  in 
  a 
  dispute 
  with 
  
European 
  Union 
  regulators 
  over 
  exemptions 
  from 
  paying 
  energies 
  subsidies 
  that 
  Germany 
  grants 
  large, 
  
energy-­‐intensive 
  manufacturers. 
  The 
  European 
  Commission, 
  the 
  EU's 
  executive 
  arm, 
  has 
  said 
  the 
  
exemptions 
  may 
  violate 
  European 
  subsidy 
  limits. 
  
Ending 
  the 
  rebates 
  could 
  cost 
  Germany 
  nearly 
  5% 
  of 
  its 
  gross 
  domestic 
  product 
  by 
  2020, 
  IHS 
  estimated. 
  
"Abolishing 
  the 
  rebates 
  at 
  time 
  of 
  economic 
  weakness 
  in 
  Europe 
  would 
  be 
  penny-­‐wise 
  and 
  pound-­‐
foolish," 
  Mr. 
  Yergin 
  said. 
  

What’s 
  the 
  ‘true’ 
  value 
  of 
  solar 
  power? 
  Stay 
  tuned 
    
  Denver 
  Business 
  Journal 
    
  Cathy 
  Proctor 
  
  
  2/26/14 
  
http://www.bizjournals.com/denver/blog/earth_to_power/2014/02/the-­‐true-­‐value-­‐of-­‐solar-­‐power-­‐
stay.html 
   
  

Supporters 
  of 
  solar 
  power 
  and 
  representatives 
  of 
  Xcel 
  Energy 
  Inc. 
  say 
  they 
  are 
  looking 
  forward 
  to 
  state 
  
regulators 
  taking 
  a 
  hard 
  look 
  at 
  the 
  "true" 
  value 
  of 
  rooftop 
  solar 
  power 
  systems, 
  the 
  kind 
  that 
  typically 
  
perch 
  on 
  residential 
  rooftops. 
  
 
  
The 
  question 
  is 
  one 
  that 
  state 
  regulators, 
  solar 
  power 
  companies 
  and 
  utilities 
  in 
  several 
  states 
  across 
  the 
  
country 
  are 
  looking 
  at. 
  
 
  
“No 
  one 
  knows 
  the 
  answer,” 
  said 
  John 
  Stanton, 
  the 
  vice 
  president 
  of 
  policy 
  and 
  electricity 
  markets 
  for 
  
SolarCity 
  Corp., 
  a 
  large 
  solar 
  power 
  company 
  based 
  in 
  San 
  Mateo, 
  Calif. 
  “But 
  it 
  looks 
  like 
  we’re 
  getting 
  
close 
  to 
  a 
  full 
  and 
  fair 
  accounting 
  in 
  Colorado." 
  
 
  
Stanton 
  spoke 
  Wednesday 
  during 
  a 
  packed 
  session 
  on 
  the 
  net 
  metering 
  issue 
  at 
  2014 
  Solar 
  Power 
  
Colorado, 
  an 
  annual 
  conference 
  for 
  the 
  industry 
  organized 
  by 
  the 
  Colorado 
  Solar 
  Energy 
  Industries 
  
Association, 
  an 
  industry 
  trade 
  group. 
  The 
  conference 
  was 
  held 
  at 
  the 
  Omni 
  Interlocken 
  Resort 
  and 
  
Conference 
  Center 
  in 
  Broomfield 
  on 
  Tuesday 
  and 
  Wednesday. 
  
 
  
Solar 
  power 
  supporters 
  and 
  Xcel 
  have 
  been 
  gearing 
  up 
  for 
  a 
  fight 
  at 
  the 
  Colorado 
  Public 
  Utilities 
  
Commission 
  (PUC) 
  for 
  months, 
  since 
  Xcel 
  (NYSE: 
  XEL) 
  in 
  July 
  2013 
  asked 
  to 
  take 
  a 
  look 
  at 
  the 
  issue 
  of 
  
“net 
  metering.” 
  
 
  
The 
  PUC 
  in 
  January 
  said 
  it 
  would 
  open 
  a 
  separate 
  docket 
  on 
  the 
  issue 
  to 
  try 
  to 
  come 
  up 
  with 
  a 
  number. 
  
 
  
28 
  
 
  

 Net 
  metering 
  is 
  the 
  program 
  in 
  which 
  owners 
  of 
  solar 
  power 
  systems 
  receive 
  a 
  credit 
  on 
  their 
  monthly 
  
electricity 
  bill 
  for 
  the 
  excess 
  solar 
  power 
  produced 
  by 
  their 
  rooftop 
  systems 
  and 
  sent 
  onto 
  the 
  electricity 
  
grid. 
  
 
  
Xcel 
  currently 
  credits 
  customers 
  at 
  a 
  rate 
  of 
  10.5 
  cents 
  per 
  kilowatt 
  hour 
  of 
  excess 
  power 
  produced, 
  but 
  
the 
  utility 
  says 
  it 
  believes 
  the 
  “true 
  value” 
  is 
  about 
  halt 
  that 
  — 
  just 
  4.6 
  cents 
  per 
  kilowatt 
  hour. 
  
 
  
Xcel 
  says 
  it 
  figures 
  the 
  solar 
  power 
  helps 
  the 
  utility, 
  and 
  its 
  customers, 
  avoid 
  the 
  cost 
  of 
  buying 
  or 
  
generating 
  power, 
  and 
  the 
  associated 
  fuel 
  requirements, 
  due 
  to 
  the 
  solar 
  power 
  that’s 
  produced 
  by 
  the 
  
rooftop 
  systems. 
  
 
  
But 
  supporters 
  of 
  solar 
  power 
  say 
  the 
  value 
  of 
  the 
  renewable 
  electricity 
  is 
  higher 
  than 
  Xcel’s 
  figure. 
  
 
  
Solar 
  power 
  supporters 
  say 
  the 
  net 
  metering 
  credits 
  are 
  big 
  driver 
  for 
  customers 
  interested 
  in 
  adding 
  
solar 
  power 
  to 
  their 
  homes. 
  The 
  credits 
  have 
  become 
  more 
  important 
  in 
  the 
  last 
  few 
  years 
  as 
  rebates 
  
and 
  other 
  incentives 
  have 
  dropped 
  to 
  near 
  zero 
  and 
  changes 
  to 
  the 
  net 
  metering 
  value 
  could 
  reduce 
  
customers’ 
  interest 
  in 
  solar 
  power 
  systems, 
  they 
  say. 
  
 
  
But 
  as 
  more 
  solar 
  power 
  systems 
  have 
  been 
  added 
  in 
  the 
  last 
  few 
  years, 
  utilities 
  have 
  grown 
  concerned 
  
that 
  customers 
  who 
  don’t 
  have 
  solar 
  power 
  systems 
  on 
  their 
  homes 
  may 
  unfairly 
  bear 
  the 
  burden 
  of 
  
paying 
  to 
  support 
  the 
  electricity 
  grid 
  that 
  delivers 
  power. 
  
 
  
“We 
  don’t 
  pretend 
  do 
  know 
  the 
  answer 
  [to 
  the 
  value 
  question],” 
  Stanton 
  told 
  the 
  group. 
  “And 
  if 
  the 
  
benefits 
  are 
  less 
  than 
  the 
  costs, 
  then 
  fine, 
  but 
  let’s 
  find 
  the 
  answer.” 
  
 
  
Frank 
  Prager, 
  Xcel’s 
  vice 
  president 
  of 
  policy 
  and 
  strategy, 
  said 
  the 
  utility 
  supports 
  the 
  PUC’s 
  new 
  docket 
  
on 
  net 
  metering. 
  
 
  
“We’d 
  love 
  to 
  find 
  a 
  way 
  to 
  have 
  a 
  future 
  for 
  rooftop 
  solar 
  and 
  also 
  to 
  have 
  it 
  be 
  fair 
  for 
  other 
  
customers, 
  so 
  that 
  they 
  aren’t 
  subsidizing 
  their 
  neighbor’s 
  rooftop 
  solar,” 
  Prager 
  said. 
  “We 
  are 
  trying 
  to 
  
have 
  an 
  open 
  discussion 
  on 
  the 
  true 
  value 
  that 
  [solar] 
  customers 
  of 
  utilities 
  receive, 
  and 
  there 
  is 
  a 
  
value." 
  
 
  
Once 
  the 
  value 
  of 
  the 
  hard 
  costs, 
  such 
  as 
  the 
  poles 
  and 
  wires, 
  has 
  been 
  established, 
  then, 
  Prager 
  said, 
  
policy 
  makers 
  can 
  decide 
  on 
  solar 
  power's 
  value 
  for 
  other 
  things, 
  such 
  as 
  the 
  environmental 
  attributes 
  
of 
  its 
  renewable 
  energy, 
  or 
  the 
  jobs 
  involved 
  in 
  the 
  solar 
  power 
  sector. 
  
 
  
"Then 
  policy 
  makers 
  can 
  change 
  the 
  incentive 
  [part 
  of 
  the 
  net 
  metering 
  credit] 
  to 
  better 
  reflect 
  the 
  
values 
  of 
  the 
  society," 
  Prager 
  said. 
  

 
  
Customers 
  tell 
  horror 
  stories 
  of 
  solar 
  company 
  that 
  gets 
  $422M 
  in 
  tax 
  dollars 
    
  Watchdog.org 
  
  
  Tori 
  Richards 
    
  2/26/14 
  
http://watchdog.org/130098/solarcity-­‐horror-­‐stories/ 
   
  
 
  

We 
  all 
  get 
  them 
  — 
  telemarketing 
  callers 
  pushing 
  home 
  solar-­‐energy 
  systems 
  that 
  will 
  save 
  us 
  from 
  rising 
  
electric 
  bills. 
  

29 
  
 
  

 Most 
  of 
  us 
  generally 
  hang 
  up. 
  But 
  in 
  2012, 
  Jeff 
  Leeds, 
  who 
  lives 
  in 
  the 
  Northern 
  California 
  town 
  of 
  Half 
  
Moon 
  Bay, 
  listened. 
  His 
  3,100-­‐square-­‐foot 
  home 
  features 
  91 
  incandescent 
  bucket 
  lights, 
  a 
  180-­‐gallon 
  
fish 
  tank, 
  three 
  large 
  refrigerator-­‐freezers 
  and 
  a 
  huge 
  entertainment 
  system. 
  His 
  electric 
  bill 
  was 
  
averaging 
  $350 
  per 
  month. 
  
The 
  sales 
  pitch 
  Leeds 
  was 
  hearing 
  on 
  the 
  phone 
  sounded 
  ideal: 
  Lease 
  a 
  system 
  from 
  SolarCity, 
  the 
  
nation’s 
  second-­‐largest 
  solar 
  electrical 
  contractor, 
  for 
  a 
  low 
  monthly 
  fee 
  and 
  reap 
  the 
  rewards 
  of 
  cheap 
  
electricity. 
  
“For 
  a 
  $600 
  fee 
  up 
  front, 
  I 
  would 
  pay 
  $182 
  a 
  month 
  for 
  the 
  next 
  20 
  years,” 
  Leeds 
  said. 
  “They 
  have 
  a 
  
performance 
  guarantee. 
  If 
  I 
  don’t 
  make 
  enough 
  electricity, 
  they 
  said, 
  ‘No 
  problem, 
  don’t 
  worry, 
  we 
  will 
  
write 
  you 
  a 
  check.’ 
  I 
  thought, 
  ‘I’m 
  covered.’” 
  
Tacked 
  on 
  to 
  that 
  would 
  be 
  what 
  the 
  company 
  called 
  a 
  small 
  bill 
  from 
  the 
  local 
  utility 
  company 
  allowing 
  
the 
  customer 
  to 
  use 
  the 
  grid 
  and 
  to 
  cover 
  the 
  use 
  of 
  any 
  electricity 
  Leeds 
  drew 
  from 
  the 
  utility 
  rather 
  
than 
  from 
  his 
  SolarCity 
  solar 
  panels. 
  
Now, 
  15 
  months 
  later, 
  the 
  local 
  utility 
  company 
  has 
  raised 
  its 
  rates 
  and 
  instead 
  of 
  a 
  lower 
  bill, 
  Leeds 
  is 
  
pushing 
  $500 
  a 
  month 
  with 
  no 
  way 
  out 
  for 
  the 
  next 
  two 
  decades. 
  And 
  he 
  has 
  the 
  eyesore 
  of 
  solar 
  panels 
  
that 
  cover 
  most 
  of 
  his 
  roof. 
  
“As 
  a 
  customer, 
  you 
  have 
  no 
  say,” 
  Leeds 
  said. 
  “With 
  a 
  solar 
  lease, 
  you 
  are 
  putting 
  the 
  stuff 
  on 
  your 
  roof. 
  
You 
  have 
  a 
  signed 
  contract 
  with 
  the 
  devil 
  and 
  you 
  are 
  stuck 
  with 
  the 
  stuff.” 
  
SolarCity 
  looked 
  into 
  Leeds’ 
  case 
  after 
  receiving 
  a 
  call 
  from 
  Watchdog.org 
  and 
  offered 
  this 
  comment: 
  
“Mr. 
  Leeds’ 
  system 
  did 
  produce 
  less 
  than 
  we 
  guaranteed 
  last 
  year 
  so 
  he 
  will 
  be 
  compensated 
  for 
  that 
  
under 
  his 
  performance 
  guarantee.” 
  
Was 
  Leeds’ 
  case 
  an 
  aberration? 
  
SolarCity 
  has 
  generated 
  a 
  high 
  number 
  of 
  cases 
  of 
  shoddy 
  installation, 
  said 
  Gerald 
  Chapman, 
  building 
  
inspector 
  manager 
  for 
  San 
  Mateo 
  County, 
  which 
  includes 
  Half 
  Moon 
  Bay. 
  
“SolarCity 
  seems 
  to 
  be 
  the 
  biggest 
  offender,” 
  Chapman 
  told 
  Watchdog.org. 
  
By 
  contrast, 
  he 
  said, 
  SolarCity’s 
  small 
  business 
  competitors 
  — 
  he 
  called 
  them 
  “the 
  little 
  guy” 
  — 
  “wants 
  
to 
  do 
  it 
  right.” 
  
“We 
  pride 
  ourselves 
  on 
  installation 
  quality, 
  but 
  if 
  we 
  do 
  make 
  a 
  mistake, 
  we 
  make 
  it 
  right,” 
  countered 
  
Jonathan 
  Bass, 
  SolarCity’s 
  vice 
  president 
  of 
  communications. 
  “We 
  are 
  rated 
  A-­‐plus 
  by 
  the 
  Better 
  
Business 
  Bureau, 
  the 
  highest 
  rating 
  they 
  provide. 
  Our 
  work 
  has 
  been 
  inspected 
  and 
  approved 
  by 
  more 
  
U.S. 
  building 
  departments 
  than 
  any 
  other 
  solar 
  provider.” 
  
Who 
  is 
  SolarCity? 
  
The 
  Obama 
  administration’s 
  2009 
  stimulus 
  package 
  created 
  an 
  open 
  trough 
  of 
  cash 
  subsidies, 
  leading 
  to 
  
an 
  explosion 
  of 
  solar-­‐energy 
  companies. 
  Some 
  of 
  those 
  — 
  Solyndra 
  is 
  the 
  most 
  prominent 
  example 
  —
 
  went 
  bust 
  spectacularly. 
  But 
  such 
  high-­‐profile 
  failures 
  and 
  reports 
  of 
  widespread 
  abuse 
  have 
  done 
  little 
  
to 
  dampen 
  entrepreneurial 
  enthusiasm. 
  
With 
  rebates, 
  tax 
  breaks 
  and 
  the 
  steady 
  climb 
  of 
  electric 
  rates, 
  more 
  and 
  more 
  Americans 
  have 
  been 
  
signing 
  on 
  for 
  solar. 
  But 
  retail 
  solar 
  technology 
  remains 
  expensive 
  — 
  upward 
  of 
  $20,000 
  per 
  home. 
  
That’s 
  where 
  SolarCity 
  comes 
  in. 
  
30 
  
 
  

 Founded 
  in 
  California 
  in 
  2006 
  by 
  Elon 
  Musk 
  — 
  PayPal 
  and 
  SpaceX 
  founder 
  and 
  CEO 
  of 
  Tesla 
  Motors, 
  
creators 
  of 
  the 
  luxury 
  electric 
  car 
  — 
  SolarCity 
  leverages 
  a 
  unique 
  business 
  model 
  to 
  make 
  solar 
  more 
  
affordable. 
  It 
  leases 
  systems 
  to 
  homeowners, 
  typically 
  for 
  a 
  20-­‐year 
  period. 
  
SolarCity 
  has 
  accepted 
  more 
  than 
  $11 
  million 
  in 
  federal 
  stimulus 
  funds 
  to 
  make 
  its 
  business 
  run. 
  But 
  the 
  
real 
  public 
  support 
  appears 
  elsewhere. 
  Because 
  SolarCity 
  technically 
  owns 
  the 
  energy 
  systems 
  it 
  installs, 
  
SolarCity 
  — 
  not 
  the 
  homeowner 
  — 
  earns 
  the 
  federal 
  tax 
  break 
  intended 
  as 
  an 
  incentive 
  to 
  go 
  solar. 
  So 
  
far 
  the 
  company 
  has 
  earned 
  $411 
  million 
  in 
  such 
  tax 
  breaks. 
  The 
  company 
  also 
  may 
  earn 
  additional 
  
income 
  on 
  state 
  subsidies. 
  
If 
  that 
  lease 
  is 
  a 
  financial 
  boon 
  to 
  SolarCity, 
  it 
  may 
  prove 
  problematic 
  for 
  SolarCity 
  consumers. 
  No 
  matter 
  
how 
  rapidly 
  solar 
  technology 
  evolves, 
  the 
  SolarCity 
  lease 
  ties 
  each 
  homeowner 
  to 
  technology 
  that 
  is 
  
cutting 
  edge 
  only 
  at 
  the 
  signing 
  of 
  the 
  20-­‐year 
  contract. 
  
“Our 
  approach 
  is 
  to 
  install 
  systems 
  to 
  the 
  highest 
  engineering 
  standards,” 
  SolarCity 
  says 
  on 
  its 
  web 
  site. 
  
“SolarCity 
  has 
  assembled 
  one 
  of 
  the 
  most 
  experienced 
  clean-­‐energy 
  project 
  design 
  and 
  installation 
  
teams 
  in 
  the 
  world.” 
  
The 
  marketing 
  has 
  paid 
  off. 
  SolarCity 
  claims 
  some 
  90,000 
  customers 
  in 
  14 
  states, 
  and 
  says 
  it 
  signs 
  a 
  new 
  
customer 
  every 
  five 
  minutes. 
  The 
  company 
  says 
  its 
  customers 
  include 
  Home 
  Depot, 
  Walmart 
  and 
  the 
  
U.S. 
  government. 
  
SolarCity 
  vs. 
  inspectors 
  
Yet 
  consumer-­‐oriented 
  sites 
  like 
  Yelp 
  and 
  the 
  Better 
  Business 
  Bureau 
  , 
  the 
  organization 
  that 
  rates 
  
SolarCity 
  an 
  A+, 
  feature 
  criticism 
  from 
  unhappy 
  customers 
  whose 
  complaints 
  follow 
  a 
  similar 
  theme 
  —
 
  shoddy 
  installation, 
  poor 
  customer 
  service 
  and 
  hidden 
  fees. 
  Many 
  of 
  the 
  postings 
  have 
  an 
  almost 
  panic-­‐
stricken 
  tone 
  as 
  the 
  consumers 
  plead 
  for 
  some 
  sort 
  of 
  resolution 
  to 
  their 
  nightmarish 
  scenario. 
  
More 
  often 
  than 
  not, 
  the 
  negative 
  comments 
  attract 
  the 
  attention 
  of 
  SolarCity 
  officials, 
  who 
  post 
  
resolutions 
  to 
  the 
  various 
  problems. 
  Many 
  of 
  the 
  consumers 
  complain 
  that 
  they 
  have 
  spent 
  months 
  
trying 
  to 
  remedy 
  faulty 
  installation, 
  only 
  to 
  receive 
  either 
  continuous 
  boilerplate 
  responses 
  from 
  
customer 
  service 
  or 
  no 
  response 
  at 
  all. 
  
One 
  California 
  man 
  got 
  a 
  front-­‐row 
  seat 
  at 
  the 
  conflict 
  between 
  SolarCity 
  installers 
  and 
  municipal 
  
building 
  inspectors 
  who 
  are 
  sent 
  to 
  sign 
  off 
  on 
  the 
  system 
  before 
  it 
  is 
  allowed 
  to 
  operate. 
  
“The 
  city 
  came 
  out 
  during 
  installation 
  and 
  an 
  inspector 
  gave 
  them 
  the 
  codes 
  and 
  requirements,” 
  said 
  the 
  
consumer, 
  who 
  asked 
  not 
  to 
  be 
  identified. 
  “The 
  city 
  guy 
  told 
  them 
  exactly 
  what 
  he 
  wanted 
  and 
  what 
  
was 
  necessary, 
  and 
  they 
  still 
  put 
  in 
  the 
  wrong 
  breakers 
  and 
  the 
  wrong 
  wiring. 
  The 
  inspector 
  came 
  back 
  
out 
  and 
  looked 
  at 
  it 
  and 
  said, 
  ‘You 
  guys 
  put 
  the 
  wrong 
  breakers 
  on 
  — 
  I 
  told 
  you 
  guys 
  what 
  I 
  needed 
  for 
  
the 
  code.’” 
  
The 
  consumer 
  said 
  nearly 
  three 
  weeks 
  went 
  by 
  with 
  no 
  word 
  from 
  SolarCity. 
  He 
  finally 
  called 
  and 
  talked 
  
to 
  a 
  manager 
  who 
  said 
  the 
  system 
  had 
  a 
  design 
  problem. 
  
“I 
  said, 
  ‘What 
  do 
  the 
  designs 
  have 
  to 
  do 
  with 
  the 
  breakers? 
  Why 
  not 
  have 
  the 
  right 
  design 
  from 
  the 
  get-­‐
go?’” 
  he 
  said. 
   
  
In 
  all, 
  he 
  claimed, 
  it 
  took 
  four 
  months 
  to 
  finish. 
  
Four 
  months 
  was 
  blazing 
  fast 
  compared 
  to 
  the 
  experience 
  of 
  San 
  Diego 
  lawyer 
  Andrew 
  Athanassious. 
  He 
  
first 
  talked 
  to 
  SolarCity 
  in 
  June 
  2013, 
  eager 
  to 
  get 
  a 
  system 
  installed 
  on 
  his 
  massive 
  home 
  before 
  a 
  large 
  
31 
  
 
  

 September 
  2013 
  utility 
  rate 
  hike. 
  Despite 
  a 
  contract, 
  Athanassious 
  said 
  SolarCity 
  later 
  told 
  him 
  his 
  roof 
  
was 
  “not 
  the 
  right 
  material” 
  and 
  he’d 
  have 
  to 
  pay 
  an 
  additional 
  $7,500. 
  
Athanassious 
  is 
  no 
  building 
  contractor, 
  but 
  he 
  said 
  SolarCity’s 
  installers 
  should 
  have 
  known 
  what 
  they 
  
were 
  getting 
  into. 
   
  
“It’s 
  obvious 
  what 
  kind 
  of 
  roof 
  I 
  have. 
  It’s 
  clay 
  tile. 
  It’s 
  not 
  like 
  you 
  could 
  think 
  it’s 
  anything 
  else,” 
  he 
  said. 
  
That 
  was 
  on 
  Aug. 
  1. 
  Athanssious 
  said 
  SolarCity 
  virtually 
  ignored 
  him 
  for 
  the 
  next 
  two 
  months. 
  He 
  finally 
  
agreed 
  to 
  split 
  the 
  cost 
  of 
  the 
  system 
  with 
  SolarCity 
  because 
  they 
  were 
  still 
  the 
  lowest-­‐priced 
  contractor 
  
and 
  because 
  finding 
  another 
  solar 
  company 
  would 
  take 
  too 
  much 
  time. 
  SolarCity 
  finally 
  installed 
  the 
  
system 
  in 
  October. 
  Unlike 
  Leeds, 
  subsequent 
  electricity 
  costs 
  haven’t 
  been 
  a 
  problem. 
  Athanassious’ 
  
utility 
  bill 
  was 
  $410 
  per 
  month 
  and 
  now 
  it’s 
  zero. 
  He 
  pays 
  SolarCity 
  $357 
  per 
  month 
  for 
  a 
  lease, 
  saving 
  
about 
  $50 
  a 
  month. 
  
SolarCity 
  responded: 
  “Mr. 
  Athanassious’ 
  system 
  did 
  require 
  a 
  roof 
  upgrade, 
  and 
  we 
  sourced 
  it 
  for 
  him 
  at 
  
the 
  lowest 
  cost.” 
  
But 
  Athanssious 
  has 
  problems 
  that 
  remain. 
  During 
  installation, 
  contractors 
  rewired 
  his 
  swimming 
  pool 
  
heater 
  incorrectly 
  when 
  they 
  were 
  working 
  on 
  the 
  home’s 
  electric 
  panel. 
  They 
  still 
  haven’t 
  fixed 
  that, 
  he 
  
said. 
  And 
  SolarCity 
  has 
  started 
  tacking 
  on 
  $15 
  per 
  month 
  to 
  Athanassious’ 
  bill 
  because 
  he 
  refuses 
  to 
  pay 
  
via 
  direct 
  deposit, 
  a 
  surcharge 
  hidden 
  in 
  the 
  contract. 
  
Other 
  consumers 
  have 
  been 
  hit 
  with 
  the 
  $15 
  fee 
  as 
  well, 
  and 
  they’ve 
  complained 
  on 
  Yelp 
  and 
  to 
  the 
  
Better 
  Business 
  Bureau. 
  
“When 
  I 
  signed 
  up, 
  I 
  was 
  led 
  to 
  believe 
  that 
  they 
  had 
  online 
  bill 
  paying,” 
  Athanassious 
  said. 
  “When 
  I 
  
called 
  them, 
  they 
  said 
  they 
  don’t 
  have 
  online 
  payment 
  capability.” 
  
More 
  problems 
  
Stefano 
  Chioetto 
  of 
  Denver 
  has 
  his 
  system 
  installed 
  last 
  February. 
  A 
  building 
  inspector 
  discovered 
  that 
  
the 
  installed 
  inverter 
  was 
  incompatible 
  with 
  the 
  utility 
  grid 
  and 
  the 
  system 
  would 
  not 
  operate. 
  For 
  the 
  
next 
  50 
  days, 
  Chioetto 
  checked 
  with 
  SolarCity 
  on 
  the 
  progress 
  of 
  a 
  replacement 
  part. 
  He 
  said 
  he 
  was 
  
given 
  only 
  vague 
  answers 
  like, 
  
 
  “We 
  are 
  doing 
  our 
  best 
  and 
  are 
  committed 
  to 
  fixing 
  your 
  system 
  ASAP,” 
  according 
  to 
  his 
  Better 
  Business 
  
Bureau 
  complaint. 
  
“They 
  found 
  out 
  that 
  the 
  inverter 
  they 
  actually 
  needed 
  was 
  very 
  expensive 
  and 
  they 
  had 
  to 
  shop 
  around 
  
and 
  had 
  no 
  idea 
  where 
  to 
  find 
  it 
  to 
  fit 
  in 
  their 
  budget,” 
  Chioetto 
  told 
  Watchdog.org, 
  saying 
  he 
  
discovered 
  this 
  from 
  an 
  outside 
  solar 
  energy 
  expert 
  that 
  he 
  contacted. 
  
Meanwhile, 
  the 
  summer 
  months 
  had 
  arrived 
  and 
  Chioetto 
  was 
  annoyed 
  that 
  he 
  couldn’t 
  use 
  his 
  panels. 
  
After 
  he 
  complained 
  to 
  the 
  BBB, 
  the 
  problem 
  was 
  fixed 
  almost 
  immediately 
  — 
  two 
  months 
  after 
  the 
  
building 
  inspector’s 
  discovery. 
  
But 
  now 
  he 
  has 
  a 
  new 
  problem. 
  Chioetto 
  lives 
  in 
  a 
  townhome 
  and 
  shares 
  a 
  roof 
  with 
  his 
  neighbor, 
  who 
  
has 
  decided 
  to 
  get 
  solar 
  panels 
  of 
  his 
  own. 
  He 
  discovered 
  that 
  SolarCity 
  installed 
  the 
  panels 
  about 
  18 
  
inches 
  onto 
  the 
  neighbor’s 
  side 
  of 
  the 
  roof 
  even 
  though 
  the 
  dividing 
  wall 
  is 
  clearly 
  visible 
  even 
  from 
  the 
  
ground, 
  both 
  men 
  said. 
  
“It’s 
  very 
  obvious 
  that 
  it’s 
  going 
  over 
  a 
  foot 
  and 
  a 
  half,” 
  said 
  the 
  neighbor, 
  who 
  did 
  not 
  want 
  to 
  be 
  
named. 
  “You 
  can 
  absolutely 
  see 
  the 
  property 
  line 
  without 
  going 
  on 
  the 
  roof.” 
  
32 
  
 
  

 SolarCity 
  admitted 
  that 
  was 
  a 
  problem. 
  
“Mr. 
  Chioetto 
  had 
  a 
  grid 
  parameter 
  that 
  is 
  unusual 
  in 
  a 
  residential 
  site, 
  and 
  we 
  ultimately 
  found 
  a 
  
compatible 
  inverter 
  that 
  could 
  support 
  it, 
  and 
  we 
  are 
  redesigning 
  his 
  system 
  to 
  appease 
  his 
  neighbor 
  
and 
  still 
  offer 
  him 
  the 
  same 
  performance,” 
  SolarCity 
  said 
  in 
  its 
  emailed 
  statement. 
  
The 
  neighbor 
  decided 
  against 
  using 
  SolarCity 
  because 
  it 
  kept 
  changing 
  terms 
  of 
  the 
  contract 
  by 
  
continuing 
  to 
  reduce 
  the 
  amount 
  of 
  electricity 
  that 
  would 
  be 
  produced. 
  Meanwhile, 
  he 
  says, 
  SolarCity 
  
hasn’t 
  fixed 
  the 
  encroachment. 
  
“They 
  said 
  they 
  are 
  researching 
  modules 
  that 
  are 
  smaller, 
  and 
  it’s 
  back-­‐ordered 
  until 
  May,” 
  the 
  neighbor 
  
said. 
  “I 
  don’t 
  know 
  if 
  I 
  believe 
  that.” 
  

Industry 
  Fights 
  Bill 
  that 
  Would 
  Tax 
  Solar 
  Panels 
    
  AZ 
  Central 
    
  Ryan 
  Randazzo 
    
  2/26/14 
  

http://www.azcentral.com/business/consumer/articles/20140226industry-­‐fights-­‐bill-­‐would-­‐tax-­‐solar-­‐
panels.html 
   
  

 
  

The 
  solar 
  industry 
  is 
  fighting 
  a 
  bill 
  introduced 
  by 
  Rep. 
  John 
  Allen, 
  R-­‐Scottsdale, 
  that 
  would 
  tax 
  solar 
  
panels 
  that 
  are 
  leased 
  by 
  homeowners. 
  
Current 
  Arizona 
  property 
  tax 
  law 
  states 
  that 
  rooftop 
  solar 
  panels 
  used 
  to 
  generate 
  electricity 
  on 
  site 
  for 
  
a 
  home 
  or 
  business 
  are 
  not 
  assessed 
  property 
  tax. 
  But 
  the 
  Department 
  of 
  Revenue 
  last 
  year 
  issued 
  a 
  
determination 
  that 
  leased 
  solar 
  panels, 
  the 
  fastest 
  growing 
  segment 
  of 
  the 
  industry 
  by 
  far, 
  should 
  be 
  
assessed 
  property 
  tax. 
  
The 
  Department 
  of 
  Revenue 
  found 
  the 
  actual 
  owners 
  of 
  those 
  systems 
  are 
  the 
  companies 
  such 
  as 
  
SolarCity 
  that 
  offer 
  the 
  leases, 
  or 
  their 
  investors, 
  and 
  they 
  are 
  not 
  using 
  the 
  power 
  “on-­‐site” 
  the 
  same 
  as 
  
a 
  customer 
  who 
  buys 
  solar 
  panels 
  for 
  a 
  home 
  or 
  business. 
  The 
  state 
  has 
  not 
  begun 
  billing 
  those 
  solar-­‐
panel 
  owners 
  for 
  the 
  taxes 
  owed 
  on 
  panels, 
  but 
  could 
  without 
  a 
  clarification. 
  Two 
  bills 
  were 
  introduced 
  
at 
  the 
  Legislature 
  this 
  session 
  to 
  clarify 
  the 
  law. 
  
Allen’s 
  proposal, 
  House 
  Bill 
  2595, 
  aligns 
  with 
  the 
  Department 
  of 
  Revenue 
  and 
  clarifies 
  that 
  the 
  owners 
  of 
  
the 
  solar 
  panels 
  would 
  be 
  assessed 
  taxes, 
  regardless 
  if 
  the 
  electricity 
  is 
  being 
  used 
  on 
  site. 
  
Solar 
  industry 
  officials 
  said 
  that 
  Arizona 
  Public 
  Service 
  Co., 
  which 
  tried 
  to 
  increase 
  the 
  bills 
  of 
  solar 
  
customers 
  last 
  year, 
  proposed 
  the 
  bill, 
  which 
  the 
  utility 
  denies. 
  
Allen 
  declined 
  to 
  comment 
  Wednesday 
  regarding 
  why 
  he 
  introduced 
  the 
  bill. 
  
APS 
  officials 
  said 
  they 
  were 
  not 
  pushing 
  the 
  bill. 
  
“Our 
  focus 
  is 
  on 
  continuing 
  to 
  develop 
  solar 
  power 
  in 
  Arizona,” 
  APS 
  spokesman 
  Jim 
  McDonald 
  said. 
  “Not 
  
only 
  is 
  HB 
  2995 
  not 
  a 
  priority 
  for 
  us, 
  we 
  have 
  not 
  taken 
  a 
  position 
  on 
  it. 
  It 
  is 
  a 
  department 
  of 
  revenue 
  
issue.” 
  
The 
  solar 
  industry 
  is 
  pushing 
  its 
  own 
  clarification 
  of 
  the 
  taxation 
  rules 
  in 
  Senate 
  Bill 
  1467, 
  sponsored 
  by 
  
Sen. 
  John 
  McComish, 
  R-­‐Phoenix. 
  His 
  bill 
  would 
  clarify 
  that 
  solar 
  panels 
  are 
  not 
  subject 
  to 
  property 
  tax, 
  
regardless 
  of 
  who 
  owns 
  them, 
  when 
  they 
  produce 
  power 
  used 
  on 
  site 
  by 
  a 
  home 
  or 
  business. 
  
McDonald 
  declined 
  to 
  say 
  whether 
  APS 
  has 
  a 
  position 
  on 
  that 
  bill. 
  
Officials 
  from 
  companies 
  that 
  finance 
  solar 
  leases, 
  and 
  would 
  be 
  subjected 
  to 
  taxes 
  for 
  the 
  panels 
  they 
  
own 
  and 
  lease 
  to 
  homeowners, 
  said 
  they 
  suspect 
  APS’ 
  involvement 
  on 
  the 
  matter. 
  
33 
  
 
  

 These 
  companies 
  spent 
  most 
  of 
  last 
  year 
  fighting 
  with 
  APS 
  over 
  a 
  fee 
  the 
  utility 
  proposed 
  for 
  solar 
  
customers. 
  APS 
  proposed 
  a 
  fee 
  of 
  $50 
  to 
  $100 
  a 
  month 
  on 
  customers 
  who 
  use 
  solar 
  and 
  pay 
  little 
  in 
  the 
  
way 
  of 
  an 
  energy 
  bill, 
  even 
  if 
  they 
  pay 
  a 
  monthly 
  lease 
  for 
  their 
  panels. 
  
Regulators 
  settled 
  on 
  a 
  fee 
  that 
  averages 
  about 
  $5 
  a 
  month 
  for 
  solar 
  customers, 
  and 
  only 
  affects 
  those 
  
who 
  installed 
  solar 
  after 
  Jan. 
  1. 
  
“This 
  won’t 
  even 
  make 
  them 
  any 
  money,” 
  said 
  Bryan 
  Miller, 
  vice 
  president 
  for 
  public 
  policy 
  and 
  power 
  
markets 
  for 
  Sunrun 
  Inc. 
  “It’s 
  just 
  going 
  to 
  hurt 
  the 
  solar 
  industry.” 
  

Report: 
  Solar 
  Paired 
  With 
  Storage 
  Is 
  a 
  ‘Real, 
  Near 
  and 
  Present’ 
  Threat 
  to 
  Utilities 
    
  Greentech 
  
Media 
    
  Stephen 
  Lacey 
    
  2/26/14 
  

http://www.greentechmedia.com/articles/read/where-­‐and-­‐when-­‐customers-­‐may-­‐start-­‐leaving-­‐the-­‐grid 
   
  

In 
  October 
  2012, 
  as 
  Superstorm 
  Sandy 
  rocked 
  the 
  East 
  Coast, 
  75 
  residents 
  gathered 
  in 
  the 
  Midtown 
  
Community 
  School 
  in 
  Bayonne, 
  New 
  Jersey. 
   
  
The 
  elementary 
  school 
  was 
  operating 
  as 
  an 
  emergency 
  shelter, 
  giving 
  people 
  who 
  were 
  stuck 
  in 
  the 
  
severely 
  flooded 
  town 
  a 
  place 
  to 
  stay 
  dry. 
  But 
  the 
  school 
  was 
  much 
  more 
  than 
  a 
  shelter 
  -­‐-­‐ 
  it 
  was 
  an 
  
experiment 
  in 
  hybrid 
  solar 
  photovoltaics 
  that 
  may 
  herald 
  a 
  coming 
  structural 
  change 
  in 
  the 
  power 
  
sector. 
  
Four 
  years 
  earlier, 
  the 
  local 
  school 
  district 
  approached 
  the 
  New 
  Jersey-­‐based 
  installer 
  Advanced 
  Solar 
  
Products, 
  which 
  had 
  already 
  developed 
  a 
  272-­‐kilowatt 
  system 
  for 
  the 
  Midtown 
  school. 
  The 
  school 
  
district 
  wanted 
  to 
  figure 
  out 
  how 
  to 
  allow 
  the 
  solar 
  PV 
  to 
  operate 
  during 
  power 
  outages 
  when 
  other 
  
systems 
  were 
  required 
  to 
  shut 
  off. 
  The 
  company 
  worked 
  with 
  SMA 
  to 
  modify 
  a 
  commercial 
  inverter 
  and 
  
tie 
  it 
  into 
  the 
  emergency 
  diesel 
  generator, 
  allowing 
  the 
  generator 
  to 
  idle 
  at 
  low 
  levels 
  when 
  the 
  sun 
  was 
  
shining. 
  
The 
  result 
  was 
  a 
  steep 
  drop 
  in 
  fuel 
  consumption 
  at 
  a 
  time 
  when 
  it 
  was 
  nearly 
  impossible 
  to 
  make 
  diesel 
  
deliveries 
  to 
  flood-­‐stricken 
  areas. 
  
"The 
  solar 
  did 
  what 
  it 
  was 
  supposed 
  to 
  do. 
  It 
  worked 
  exactly 
  as 
  planned," 
  said 
  Lyle 
  Rawlings, 
  president 
  
of 
  Advanced 
  Solar 
  Products, 
  in 
  an 
  interview. 
  
Although 
  the 
  system 
  was 
  a 
  custom 
  job, 
  making 
  it 
  fairly 
  expensive, 
  Rawlings 
  says 
  his 
  company 
  took 
  the 
  
experience 
  to 
  heart. 
  Advanced 
  Solar 
  Products 
  is 
  now 
  working 
  with 
  other 
  commercial 
  facilities 
  to 
  
integrate 
  lithium-­‐ion 
  batteries 
  with 
  solar, 
  and 
  plans 
  to 
  make 
  solar-­‐storage 
  systems 
  a 
  bigger 
  part 
  of 
  the 
  
business 
  going 
  forward. 
  
"We 
  see 
  this 
  as 
  a 
  thing 
  that's 
  going 
  to 
  develop 
  more 
  and 
  more, 
  and 
  we 
  want 
  to 
  take 
  the 
  lead 
  in 
  
development," 
  said 
  Rawlings. 
   
  
And 
  it's 
  not 
  just 
  emergency 
  backup 
  that 
  makes 
  storage 
  attractive. 
  Now 
  that 
  fast-­‐responding 
  systems 
  like 
  
flywheels 
  and 
  lithium-­‐ion 
  batteries 
  can 
  get 
  paid 
  for 
  frequency 
  regulation 
  services 
  in 
  PJM 
  or 
  help 
  reduce 
  
onsite 
  demand 
  charges 
  for 
  commercial 
  facilities, 
  storage 
  is 
  emerging 
  as 
  a 
  viable 
  economic 
  alternative. 
  
In 
  one 
  case, 
  Advanced 
  Solar 
  Products 
  was 
  able 
  to 
  pay 
  for 
  a 
  commercial 
  storage 
  system 
  and 
  inverter 
  
through 
  frequency 
  regulation 
  payments 
  -­‐-­‐ 
  actually 
  making 
  the 
  cost 
  of 
  a 
  hybrid 
  solar-­‐storage 
  system 
  
lower 
  than 
  solar 
  alone. 
  
"That, 
  to 
  us, 
  seemed 
  magical, 
  and 
  it 
  told 
  us 
  we 
  could 
  provide 
  this 
  service 
  for 
  a 
  low 
  cost," 
  said 
  Rawlings. 
  

34 
  
 
  

 Now 
  that 
  storage 
  is 
  moving 
  beyond 
  simple 
  emergency 
  applications, 
  that 
  "magical" 
  alternative 
  -­‐-­‐ 
  while 
  
still 
  very 
  site-­‐ 
  and 
  market-­‐specific 
  -­‐-­‐ 
  is 
  emerging 
  as 
  a 
  potential 
  threat 
  to 
  utilities. 
   
  
Driven 
  by 
  market 
  changes 
  that 
  reward 
  storage, 
  improving 
  system 
  economics 
  and 
  third-­‐party 
  financing 
  
tools, 
  the 
  nascent 
  distributed 
  storage 
  market 
  is 
  on 
  the 
  upswing 
  in 
  the 
  U.S. 
  Witnessing 
  these 
  changes, 
  
the 
  country's 
  leading 
  solar 
  installer, 
  SolarCity, 
  has 
  started 
  offering 
  solar 
  paired 
  with 
  storage 
  to 
  
commercial 
  customers. 
  And 
  distributed 
  storage 
  providers 
  such 
  as 
  Solar 
  Grid 
  Storage, 
  Stem, 
  Intelligent 
  
Generation 
  and 
  Green 
  Charge 
  Networks 
  are 
  reaching 
  out 
  to 
  solar 
  developers 
  to 
  form 
  partnerships. 
  
A 
  recent 
  GTM 
  Research 
  report 
  projected 
  that 
  the 
  U.S. 
  commercial 
  storage 
  market 
  could 
  grow 
  to 
  more 
  
than 
  720 
  megawatts 
  by 
  the 
  end 
  of 
  the 
  decade. 
  Some 
  of 
  that 
  growth 
  will 
  come 
  directly 
  from 
  a 
  closer 
  
relationship 
  with 
  the 
  solar 
  industry. 
  
So 
  what 
  does 
  this 
  mean 
  for 
  the 
  power 
  sector's 
  future? 
  
The 
  Rocky 
  Mountain 
  Institute 
  and 
  CohnReznick 
  attempted 
  to 
  answer 
  that 
  question 
  in 
  a 
  new 
  report 
  
released 
  yesterday. 
  The 
  analysis 
  looks 
  at 
  the 
  economics 
  of 
  storage-­‐solar 
  systems 
  in 
  the 
  commercial 
  and 
  
residential 
  sectors, 
  and 
  projects 
  when 
  mass 
  adoption 
  may 
  start 
  to 
  occur 
  in 
  key 
  markets. 
   
  
The 
  conclusion: 
  the 
  combination 
  of 
  solar 
  and 
  storage 
  is 
  a 
  "real, 
  near, 
  and 
  present" 
  threat 
  to 
  the 
  way 
  
utilities 
  do 
  business. 
  
"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," 
  wrote 
  the 
  authors. 
  
Using 
  modeling 
  software 
  from 
  Homer 
  Energy 
  and 
  electricity 
  data 
  from 
  the 
  Energy 
  Information 
  
Administration, 
  the 
  analysts 
  looked 
  at 
  a 
  range 
  of 
  technology 
  scenarios 
  in 
  the 
  commercial 
  sector 
  for 
  
solar, 
  lithium-­‐ion 
  batteries, 
  and 
  generators 
  working 
  together. 
  In 
  the 
  residential 
  sector, 
  the 
  analysts 
  
looked 
  just 
  at 
  solar 
  and 
  batteries. 
  
On 
  their 
  own, 
  the 
  economics 
  of 
  the 
  two 
  technologies 
  are 
  improving 
  steadily. 
  According 
  to 
  the 
  
Department 
  of 
  Energy, 
  lithium-­‐ion 
  battery 
  costs 
  have 
  dropped 
  by 
  50 
  percent 
  since 
  2008. 
  And 
  prices 
  
could 
  drop 
  as 
  low 
  as 
  $125 
  per 
  kilowatt-­‐hour 
  in 
  the 
  coming 
  decades. 
  Tesla 
  founder 
  Elon 
  Musk 
  thinks 
  they 
  
could 
  drop 
  to 
  as 
  low 
  as 
  $200 
  per 
  kilowatt-­‐hour 
  in 
  the 
  next 
  few 
  years. 
  
There's 
  been 
  an 
  equivalent 
  drop 
  in 
  residential 
  and 
  commercial 
  solar. 
  According 
  to 
  GTM 
  Research, 
  the 
  
average 
  price 
  of 
  an 
  installed 
  solar 
  system 
  (weighted 
  across 
  all 
  sectors) 
  has 
  fallen 
  by 
  61 
  percent 
  since 
  the 
  
first 
  quarter 
  of 
  2010. 
  
The 
  RMI/CohnReznick 
  analysis 
  shows 
  a 
  range 
  of 
  other 
  projections 
  for 
  cost 
  forecasts, 
  which 
  illustrate 
  an 
  
equally 
  steady 
  decline 
  in 
  the 
  coming 
  decades. 
  Those 
  cost 
  reductions, 
  driven 
  by 
  better 
  hardware, 
  lower 
  
module 
  prices, 
  efficient 
  installation 
  techniques 
  and 
  scale, 
  are 
  helping 
  to 
  further 
  drive 
  down 
  system 
  
prices. 
  
But 
  what 
  about 
  the 
  combination 
  of 
  the 
  two 
  technologies? 
  Adding 
  storage 
  will 
  increase 
  the 
  cost 
  of 
  a 
  
solar 
  system. 
  Although 
  those 
  costs 
  can 
  be 
  addressed 
  by 
  leveraging 
  storage 
  to 
  reduce 
  on-­‐site 
  demand 
  
charges 
  or 
  participate 
  in 
  frequency 
  regulation 
  where 
  allowed, 
  the 
  economics 
  vary 
  widely 
  based 
  upon 
  
the 
  region. 
  
The 
  analysis 
  looked 
  at 
  five 
  cities: 
  Honolulu, 
  Hawaii; 
  Los 
  Angeles, 
  California; 
  Louisville, 
  Kentucky; 
  San 
  
Antonio, 
  Texas; 
  and 
  Westchester, 
  New 
  York. 
   
  

35 
  
 
  

 Under 
  a 
  base-­‐case 
  scenario, 
  which 
  simply 
  factors 
  in 
  existing 
  technologies 
  and 
  market 
  constructs, 
  the 
  
authors 
  argue 
  that 
  the 
  combination 
  is 
  only 
  truly 
  competitive 
  in 
  Hawaii, 
  where 
  oil-­‐based 
  generation 
  is 
  
extremely 
  expensive. 
  (However, 
  as 
  the 
  previously 
  mentioned 
  case 
  from 
  New 
  Jersey 
  shows, 
  the 
  
technology 
  can 
  be 
  competitive 
  at 
  specific 
  sites 
  in 
  other 
  markets.) 
  
Under 
  a 
  more 
  aggressive 
  scenario, 
  which 
  factors 
  in 
  strong 
  technology 
  improvements 
  and 
  deeper 
  use 
  of 
  
intelligent 
  efficiency, 
  solar 
  and 
  storage 
  together 
  become 
  competitive 
  much 
  sooner 
  in 
  a 
  broader 
  range 
  of 
  
markets 
  -­‐-­‐ 
  even 
  becoming 
  a 
  strong 
  alternative 
  in 
  a 
  coal-­‐based 
  state 
  like 
  Kentucky, 
  where 
  electricity 
  
prices 
  are 
  relatively 
  low. 
  
Competitiveness 
  in 
  the 
  residential 
  sector 
  will 
  occur 
  later, 
  but 
  there 
  are 
  still 
  opportunities 
  for 
  grid 
  parity 
  
by 
  the 
  end 
  of 
  the 
  decade 
  -­‐-­‐ 
  or 
  even 
  today 
  -­‐-­‐ 
  in 
  several 
  markets. 
  
The 
  timing 
  outlined 
  in 
  the 
  report 
  varies 
  widely 
  depending 
  on 
  a 
  number 
  of 
  technological 
  and 
  market-­‐
based 
  factors. 
  But 
  even 
  under 
  the 
  most 
  conservative 
  scenario, 
  the 
  authors 
  conclude 
  that 
  solar 
  and 
  
storage 
  together 
  have 
  the 
  potential 
  to 
  massively 
  erode 
  utility 
  revenue. 
  
In 
  the 
  Southeast 
  and 
  Mid-­‐Atlantic 
  markets, 
  these 
  technologies 
  could 
  be 
  less 
  expensive 
  than 
  one-­‐fifth 
  of 
  
load 
  by 
  2024 
  with 
  no 
  dramatic 
  improvements. 
  That 
  means 
  more 
  than 
  1.2 
  million 
  customers 
  in 
  those 
  
regions 
  may 
  have 
  the 
  opportunity 
  to 
  virtually 
  disconnect 
  from 
  the 
  power 
  company. 
  Under 
  a 
  more 
  
advanced 
  scenario, 
  utilities 
  in 
  those 
  regions 
  could 
  be 
  at 
  risk 
  of 
  losing 
  their 
  traditional 
  relationship 
  with 
  
millions 
  more 
  customers. 
  
"In 
  the 
  Southwest, 
  as 
  many 
  as 
  20 
  million 
  residential 
  customers 
  could 
  find 
  economic 
  advantage 
  by 
  2024 
  
with 
  solar-­‐plus-­‐battery 
  systems 
  under 
  our 
  combined 
  improvement 
  scenario. 
  In 
  the 
  Mid-­‐Atlantic, 
  roughly 
  
8 
  million 
  customers 
  will 
  find 
  favorable 
  economics 
  for 
  solar-­‐plus-­‐battery 
  hybrid 
  systems 
  by 
  2024 
  given 
  
the 
  same 
  combined 
  improvements. 
  Between 
  the 
  two 
  geographies, 
  this 
  represents 
  over 
  $34 
  billion 
  in 
  
annual 
  utility 
  revenues," 
  wrote 
  the 
  authors. 
  
Earlier 
  this 
  month, 
  former 
  Duke 
  Energy 
  CEO 
  called 
  the 
  power 
  grid 
  a 
  "blank 
  sheet 
  of 
  paper" 
  and 
  
predicted 
  that 
  most 
  power 
  plants 
  will 
  need 
  to 
  be 
  replaced 
  by 
  the 
  middle 
  of 
  the 
  century. 
   
  
"One 
  of 
  the 
  big 
  challenges 
  as 
  we 
  redesign 
  the 
  generation 
  fleet 
  in 
  this 
  country 
  is 
  [figuring 
  out] 
  what 
  this 
  
mix 
  will 
  be," 
  Rogers 
  said. 
  
Even 
  with 
  no 
  dramatic 
  changes, 
  the 
  RMI/CohnReznick 
  analysis 
  shows 
  that 
  solar 
  and 
  storage 
  together 
  
will 
  be 
  competitive 
  in 
  most 
  regions 
  of 
  the 
  U.S. 
  by 
  2050. 
  Assuming 
  most 
  of 
  the 
  country's 
  centralized 
  
power 
  plants 
  need 
  to 
  be 
  replaced 
  by 
  that 
  time, 
  the 
  relationship 
  between 
  utilities 
  and 
  their 
  customers 
  
will 
  be 
  irreversibly 
  changed 
  as 
  more 
  people 
  invest 
  in 
  hybrid 
  systems. 
  
"Utilities 
  operate 
  on 
  a 
  long 
  time 
  horizon, 
  and 
  concerns 
  about 
  grid 
  defection 
  should 
  be 
  creeping 
  toward 
  
the 
  forefront 
  of 
  utilities' 
  minds 
  now," 
  said 
  Shayle 
  Kann, 
  senior 
  VP 
  of 
  GTM 
  Research. 
  "In 
  addition, 
  this 
  
should 
  be 
  a 
  prime 
  factor 
  in 
  utility 
  considerations 
  regarding 
  changes 
  to 
  net 
  energy 
  metering 
  programs. 
  
The 
  more 
  utilities 
  move 
  toward 
  rate 
  structures 
  that 
  impose 
  fixed 
  charges 
  which 
  cannot 
  be 
  reduced 
  
through 
  net 
  metering, 
  the 
  greater 
  the 
  incentive 
  for 
  customers 
  to 
  defect." 
  
Utilities 
  are 
  currently 
  worried 
  about 
  what 
  solar 
  may 
  do 
  to 
  revenues, 
  and 
  are 
  working 
  to 
  change 
  net 
  
metering 
  policies 
  in 
  order 
  to 
  account 
  for 
  grid 
  costs. 
  But 
  that 
  may 
  only 
  be 
  a 
  short-­‐term 
  fix. 
  If 
  storage 
  
continues 
  to 
  gain 
  traction 
  as 
  a 
  viable 
  partner 
  to 
  solar, 
  customers 
  may 
  still 
  have 
  the 
  opportunity 
  to 
  
loosen 
  or 
  break 
  ties 
  with 
  their 
  power 
  company. 
  
"Millions 
  of 
  customers...representing 
  billions 
  of 
  dollars 
  in 
  utility 
  revenues 
  will 
  find 
  themselves 
  in 
  a 
  
position 
  to 
  cost-­‐effectively 
  defect 
  from 
  the 
  grid 
  if 
  they 
  so 
  choose," 
  concluded 
  the 
  report 
  authors. 
  
36 
  
 
  

 Solar 
  Advocates 
  Oppose 
  Duke 
  Energy 
  Plan 
  to 
  Cut 
  Solar 
  Prices 
    
  Charlotte 
  Business 
  Journal 
    
  
John 
  Downey 
    
  2/26/14 
  

http://www.bizjournals.com/charlotte/blog/power_city/2014/02/solar-­‐advocates-­‐oppose-­‐duke-­‐energy-­‐
plan-­‐to-­‐cut.html 
   
  
The 
  N.C. 
  Sustainable 
  Energy 
  Association 
  says 
  Duke 
  Energy’s 
  plan 
  to 
  seek 
  a 
  cut 
  in 
  how 
  much 
  it 
  pays 
  
customers 
  for 
  solar 
  power 
  from 
  small 
  projects 
  is 
  unfair 
  and 
  has 
  hurt 
  the 
  state’s 
  solar 
  industry. 
  
It 
  says 
  state 
  regulators 
  should 
  protect 
  customers 
  by 
  at 
  least 
  guaranteeing 
  the 
  price 
  a 
  utility 
  pays 
  for 
  such 
  
power 
  will 
  be 
  good 
  for 
  10 
  years 
  after 
  the 
  project 
  is 
  installed. 
  And 
  it 
  wants 
  regulators 
  to 
  force 
  Duke 
  to 
  
disclose 
  how 
  it 
  contends 
  the 
  price 
  paid 
  now 
  for 
  such 
  power 
  is 
  unfairly 
  high 
  and 
  harms 
  customers 
  who 
  do 
  
not 
  install 
  solar 
  on 
  the 
  homes 
  or 
  businesses. 
  
At 
  issue 
  is 
  the 
  price 
  the 
  state 
  requires 
  utilities 
  to 
  pay 
  under 
  its 
  “net 
  metering” 
  provisions. 
  Solar 
  projects 
  
during 
  parts 
  of 
  a 
  day 
  often 
  produce 
  more 
  power 
  than 
  the 
  customer 
  who 
  owns 
  it 
  can 
  use. 
  During 
  those 
  
times, 
  utilities 
  are 
  required 
  to 
  credit 
  the 
  customer 
  for 
  that 
  power 
  at 
  the 
  same 
  retail 
  rate 
  the 
  customer 
  
would 
  pay 
  the 
  utility 
  for 
  power. 
  
Full 
  retail 
  rate 
  
Duke 
  contends 
  that 
  this 
  requires 
  it 
  to 
  overpay 
  for 
  the 
  power. 
  And 
  it 
  has 
  been 
  clear 
  it 
  intends 
  to 
  ask 
  
regulators 
  to 
  review 
  net 
  metering 
  and 
  reduce 
  the 
  price 
  utilities 
  are 
  required 
  to 
  pay. 
  
“We 
  want 
  to 
  pay 
  what 
  this 
  power 
  is 
  worth,” 
  says 
  spokesman 
  Randy 
  Wheeless. 
  “We 
  are 
  conducting 
  
operational 
  studies 
  to 
  help 
  us 
  determine 
  what 
  that 
  should 
  be.” 
  
Duke 
  says 
  crediting 
  customers 
  at 
  the 
  full 
  retail 
  rate 
  allows 
  them 
  to 
  avoid 
  some 
  of 
  the 
  costs 
  they 
  should 
  
bear 
  for 
  infrastructure 
  that 
  delivers 
  power 
  to 
  their 
  home 
  or 
  business 
  when 
  the 
  solar 
  panels 
  are 
  not 
  
producing 
  power. 
  It 
  would 
  prefer 
  to 
  pay 
  a 
  rate 
  closer 
  to 
  the 
  avoided-­‐cost 
  rate 
  it 
  pays 
  for 
  power 
  from 
  
larger 
  solar 
  projects. 
  
Those 
  costs 
  then 
  have 
  to 
  be 
  paid 
  by 
  customers 
  who 
  do 
  not 
  have 
  solar 
  installed, 
  Duke 
  says. 
  That 
  often 
  
works 
  to 
  the 
  detriment 
  of 
  lower-­‐income 
  and 
  fixed-­‐income 
  customers 
  who 
  do 
  not 
  feel 
  they 
  can 
  afford 
  to 
  
install 
  solar 
  projects. 
  
Recent 
  study 
  
In 
  a 
  motion 
  filed 
  this 
  week 
  with 
  the 
  N.C. 
  Utilities 
  Commission, 
  the 
  association 
  contends 
  there 
  is 
  no 
  
evidence 
  the 
  price 
  set 
  for 
  credits 
  under 
  the 
  state’s 
  net 
  metering 
  requirements 
  are 
  unfair. 
  And 
  the 
  
association 
  contends 
  current 
  evidence 
  indicates 
  otherwise. 
  
It 
  cites 
  a 
  2013 
  study 
  by 
  Crossborder 
  Energy. 
  That 
  report 
  finds 
  that 
  when 
  costs 
  and 
  benefits 
  are 
  taken 
  
into 
  account, 
  the 
  costs 
  to 
  non-­‐solar 
  customers 
  tend 
  to 
  be 
  less 
  than 
  the 
  benefits 
  even 
  for 
  customers 
  
without 
  solar. 
  
The 
  association 
  wants 
  the 
  commission 
  to 
  require 
  Duke 
  to 
  disclose 
  what 
  analysis 
  it 
  has 
  that 
  supports 
  the 
  
claim 
  that 
  net 
  metering 
  is 
  unfair. 
  
It 
  contends 
  Duke’s 
  public 
  announcement 
  that 
  it 
  will 
  seek 
  to 
  reduce 
  the 
  compensation 
  from 
  net 
  metering 
  
has 
  created 
  uncertainty 
  in 
  the 
  N.C. 
  market 
  for 
  small 
  solar 
  projects. 
  It 
  quotes 
  locally 
  owned 
  solar 
  business 
  
as 
  saying 
  this 
  has 
  had 
  a 
  “chilling 
  effect” 
  on 
  the 
  market 
  as 
  customers 
  hold 
  off 
  on 
  installing 
  solar 
  projects 
  
for 
  fear 
  the 
  credit 
  they 
  receive 
  for 
  net 
  metering 
  will 
  be 
  cut 
  in 
  coming 
  months. 
  

37 
  
 
  

 Guaranteed 
  price 
  
As 
  a 
  partial 
  solution 
  to 
  that, 
  the 
  association 
  calls 
  for 
  a 
  10-­‐year 
  guaranteed 
  price 
  for 
  a 
  customer 
  who 
  
installs 
  solar. 
  The 
  proposal 
  would 
  not 
  necessarily 
  lock 
  in 
  net 
  metering 
  credits 
  at 
  their 
  current 
  level. 
  But 
  it 
  
would 
  guarantee 
  customers 
  that 
  once 
  they 
  installed 
  a 
  project, 
  they 
  would 
  receive 
  whatever 
  net 
  
metering 
  credit 
  is 
  available 
  when 
  the 
  project 
  is 
  completed 
  for 
  ten 
  years. 
  That 
  would 
  protect 
  them 
  from 
  
changes 
  in 
  the 
  credit 
  after 
  they 
  purchase 
  a 
  project. 
  
It 
  also 
  will 
  make 
  it 
  easier 
  for 
  solar 
  installers 
  to 
  sell 
  small 
  home 
  and 
  commercial 
  projects. 
  The 
  association, 
  
which 
  represents 
  such 
  installers, 
  says 
  this 
  is 
  consistent 
  with 
  20 
  years 
  of 
  state 
  public 
  policy, 
  which 
  has 
  
supported 
  development 
  of 
  solar 
  as 
  a 
  hedge 
  against 
  the 
  monopolistic 
  power 
  of 
  utilities. 
  
“It 
  is 
  perhaps 
  solely 
  the 
  existence 
  of 
  this 
  competitive 
  threat 
  that 
  prevents 
  Duke 
  Energy 
  ... 
  from 
  rising 
  to 
  
the 
  level 
  of 
  monopolies 
  that 
  are 
  forbidden 
  by 
  the 
  state’s 
  constitution,” 
  the 
  motion 
  says. 
  
Duke 
  says 
  it 
  has 
  1,300 
  customers 
  who 
  take 
  advantage 
  of 
  net 
  metering 
  credits 
  in 
  North 
  Carolina. 
  They 
  
account 
  for 
  less 
  than 
  14 
  megawatts 
  of 
  Duke’s 
  more 
  than 
  30,000 
  megawatts 
  of 
  capacity 
  in 
  the 
  Carolinas. 
  

GDF 
  Suez 
  Earnings: 
  Utility 
  Takes 
  $20.4 
  Billion 
  Write-­‐Down 
    
  The 
  Wall 
  Street 
  Journal 
    
  Inti 
  
Landauro 
    
  2/27/14 
  
http://online.wsj.com/news/articles/SB10001424052702304255604579408362026916346 
   
  
PARIS— 
  GDF 
  Suez 
  SA 
  wrote 
  down 
  €14.9 
  billion 
  ($20.4 
  billion) 
  in 
  assets, 
  a 
  glaring 
  example 
  of 
  how 
  
Europe's 
  large-­‐scale 
  power-­‐generation 
  industry 
  has 
  been 
  crippled 
  by 
  wind 
  and 
  solar 
  electricity. 
  
"We 
  consider 
  that 
  the 
  deterioration 
  of 
  gas 
  storage 
  and 
  thermal-­‐energy 
  production 
  in 
  Europe 
  is 
  
deep 
  and 
  long-­‐lasting," 
  Chief 
  Executive 
  Gérard 
  Mestrallet 
  said 
  Thursday 
  as 
  the 
  company 
  reported 
  a 
  
loss 
  for 
  last 
  year. 
  
Even 
  for 
  a 
  large 
  company 
  with 
  global 
  reach 
  and 
  annual 
  revenue 
  of 
  almost 
  €90 
  billion, 
  the 
  
impairment 
  charge 
  was 
  huge, 
  erasing 
  12% 
  from 
  the 
  value 
  of 
  GDF's 
  total 
  assets. 
  
GDF, 
  German 
  rivals 
  RWE 
  AG 
  and 
  E. 
  ON 
  SE 
  and 
  other 
  big 
  utilities 
  dominated 
  Europe's 
  power 
  market 
  
for 
  decades, 
  until 
  the 
  growth 
  of 
  subsidized 
  renewable 
  energy 
  undermined 
  their 
  traditional 
  business 
  
models. 
  
 
  
Mr. 
  Mestrallet 
  repeatedly 
  has 
  said 
  that 
  subsidies 
  for 
  renewable 
  energy 
  are 
  turning 
  traditional 
  
power 
  production 
  into 
  a 
  losing 
  proposition. 
  
He 
  heads 
  a 
  group 
  of 
  utility 
  CEOs 
  who 
  are 
  lobbying 
  to 
  phase 
  out 
  subsidies 
  to 
  solar 
  and 
  wind 
  power 
  in 
  
Europe. 
  GDF 
  invests 
  in 
  renewable 
  sources, 
  but 
  aging, 
  traditional 
  plants 
  make 
  up 
  the 
  vast 
  majority 
  of 
  
its 
  capacity. 
  
European 
  wind-­‐ 
  and 
  solar-­‐power 
  producers 
  benefit 
  from 
  priority 
  access 
  to 
  the 
  electricity 
  grid 
  and 
  
guaranteed 
  prices 
  well 
  above 
  the 
  market 
  price, 
  regardless 
  of 
  demand. 
   
  
The 
  difference 
  is 
  paid 
  for 
  through 
  taxes 
  and 
  higher 
  retail 
  prices 
  for 
  electricity 
  from 
  traditional 
  
sources. 
  
Gas-­‐fired 
  power 
  plants 
  are 
  the 
  most 
  vulnerable. 
  Coal-­‐fired 
  plants 
  have 
  fared 
  better—an 
  unexpected 
  
result 
  of 
  the 
  U.S. 
  shale-­‐gas 
  boom 
  as 
  power 
  producers 
  in 
  the 
  country 
  have 
  switched 
  from 
  coal. 
   
  
That 
  has 
  spurred 
  U.S. 
  exports 
  of 
  coal, 
  sending 
  its 
  price 
  lower 
  world-­‐wide. 
  

38 
  
 
  

 By 
  the 
  end 
  of 
  last 
  year, 
  GDF 
  had 
  mothballed 
  around 
  10 
  gigawatts 
  of 
  capacity. 
  Another 
  five 
  
gigawatts 
  are 
  under 
  review 
  for 
  closure. 
  
The 
  situation 
  began 
  to 
  sour 
  for 
  utilities 
  with 
  the 
  2008 
  financial 
  crisis, 
  when 
  electricity 
  demand 
  
slowed 
  across 
  Europe 
  and 
  more 
  solar 
  panels 
  and 
  wind 
  farms 
  sprang 
  up, 
  further 
  weakening 
  
wholesale 
  power 
  prices. 
  
The 
  bloodletting 
  has 
  been 
  heavy 
  across 
  Europe. 
  RWE 
  in 
  January 
  said 
  it 
  would 
  write 
  down$4.5 
  billion 
  
on 
  power-­‐generation 
  assets 
  across 
  the 
  Continent. 
  The 
  utility 
  said 
  it 
  would 
  report 
  its 
  first 
  annual 
  loss 
  
Tuesday 
  because 
  of 
  the 
  charge. 
  
E. 
  ON, 
  Germany's 
  largest 
  utility 
  by 
  market 
  value, 
  has 
  written 
  down 
  the 
  value 
  of 
  its 
  power 
  plants 
  by 
  
several 
  billions 
  of 
  euros 
  over 
  the 
  past 
  two 
  years. 
  
GDF 
  on 
  Thursday 
  reported 
  a 
  net 
  loss 
  of 
  €9.3 
  billion 
  for 
  2013, 
  compared 
  with 
  a 
  €1.54 
  billion 
  net 
  
profit 
  a 
  year 
  earlier. 
  Excluding 
  the 
  effects 
  of 
  the 
  write-­‐down 
  and 
  asset 
  sales, 
  the 
  company 
  posted 
  
earnings 
  of 
  €3.4 
  billion 
  for 
  last 
  year. 
  
GDF's 
  shares 
  rose 
  6% 
  in 
  Paris 
  trading 
  as 
  analysts 
  welcomed 
  the 
  move 
  to 
  clean 
  the 
  slate. 
  GDF 
  had 
  
already 
  warned 
  it 
  would 
  take 
  the 
  impairment 
  charge. 
   
  
The 
  company 
  on 
  Thursday 
  also 
  raised 
  its 
  forecast 
  for 
  2014 
  net 
  recurring 
  income 
  to 
  between 
  €3.3 
  
billion 
  and 
  €3.7 
  billion. 
  GDF 
  earlier 
  had 
  forecast 
  between 
  €3.1 
  billion 
  and 
  €3.5 
  billion. 
   
  
The 
  write-­‐off 
  shows 
  "our 
  determination 
  to 
  transform 
  the 
  group 
  quickly 
  and 
  decisively," 
  Mr. 
  
Mestrallet 
  said. 
  Mr. 
  Mestrallet 
  has 
  said 
  that 
  the 
  company's 
  future 
  lies 
  in 
  emerging 
  markets. 
  "We 
  
want 
  to 
  become 
  the 
  leading 
  power 
  company 
  in 
  countries 
  with 
  strong 
  growth," 
  he 
  said. 
  
—Géraldine 
  Amiel 
  in 
  Paris 
  and 
  Jan 
  Hromadko 
  in 
  Frankfurt 
  contributed 
  to 
  this 
  article. 
  

SolarCity 
  CEO, 
  joined 
  by 
  Tesla’s 
  Musk, 
  says 
  regulators 
  must 
  address 
  ‘market 
  failure’ 
    
  SNL 
  
Energy 
    
  Christine 
  Cordner 
    
  2/28/14 
  
http://www.snl.com/InteractiveX/Article.aspx?cdid=A-­‐27064257-­‐13354 
   
  

Predicting 
  an 
  eventual 
  phase-­‐out 
  of 
  the 
  current 
  U.S. 
  grid 
  system, 
  Tesla 
  Motors 
  CEO 
  Elon 
  Musk 
  and 
  
SolarCity 
  Corp. 
  CEO 
  Lyndon 
  Rive 
  are 
  hoping 
  regulators 
  will 
  help 
  them 
  get 
  around 
  utilities 
  concerned 
  
about 
  cost-­‐shifting 
  as 
  they 
  seek 
  to 
  expand 
  distributed 
  generation 
  and 
  energy 
  storage 
  use 
  among 
  
ratepayers.
"There 
  will 
  be 
  some 
  amount 
  of 
  strife 
  for 
  existing 
  utilities, 
  particularly 
  ones 
  heavy 
  into 
  fossil 
  fuels. 
  There 
  
will 
  be 
  a 
  bit 
  of 
  hardship 
  for 
  them. 
  But 
  we 
  have 
  no 
  choice. 
  We 
  have 
  to 
  decide 
  if 
  we're 
  going 
  to 
  have 
  
clean, 
  sustainable 
  energy 
  or 
  not, 
  and 
  if 
  we 
  decide 
  we 
  want 
  a 
  good 
  future 
  … 
  then 
  we 
  need 
  to 
  make 
  hard 
  
decisions 
  to 
  achieve 
  that 
  objective," 
  Musk 
  said, 
  speaking 
  Feb. 
  27 
  at 
  a 
  California 
  Public 
  Utilities 
  
Commission's 
  Thought 
  Leaders 
  series 
  event 
  in 
  San 
  Francisco. 
  
The 
  PUC 
  event 
  came 
  a 
  day 
  after 
  Tesla 
  announced 
  plans 
  to 
  build 
  a 
  factory 
  aimed 
  at 
  slashing 
  costs 
  of 
  
lithium 
  ion 
  batteries 
  by 
  30% 
  per 
  kWh. 
  When 
  the 
  so-­‐called 
  Gigafactory 
  opens 
  in 
  2020 
  at 
  a 
  projected 
  cost 
  
of 
  between 
  $4 
  billion 
  and 
  $5 
  billion, 
  it 
  is 
  expected 
  to 
  have 
  a 
  cell 
  output 
  of 
  35 
  GWh 
  a 
  year. 
  The 
  batteries 
  
will 
  be 
  used 
  in 
  Tesla 
  vehicles, 
  but 
  also 
  in 
  stationary 
  applications, 
  namely 
  products 
  for 
  use 
  in 
  homes, 
  
commercial 
  sites, 
  and 
  by 
  utilities, 
  the 
  company 
  said. 
  

39 
  
 
  

 Coming 
  from 
  the 
  Silicon 
  Valley 
  tech 
  world 
  where 
  disrupting 
  traditional 
  industries 
  through 
  innovation 
  is 
  a 
  
mantra, 
  Musk, 
  who 
  is 
  also 
  chairman 
  of 
  solar 
  panel 
  installer 
  SolarCity 
  and 
  Rive's 
  cousin, 
  described 
  the 
  
utility 
  industry's 
  concern 
  over 
  cost 
  shifting 
  from 
  net 
  metering 
  "like 
  a 
  giant 
  with 
  someone 
  tapping 
  at 
  their 
  
toe" 
  given 
  how 
  much 
  of 
  a 
  threat 
  it 
  is 
  currently 
  to 
  the 
  U.S. 
  utility 
  sector. 
  "It's 
  really 
  silly," 
  he 
  said. 
  Rive 
  
said 
  that 
  the 
  situation 
  is 
  more 
  like 
  "touching 
  the 
  hair 
  of 
  the 
  toe" 
  of 
  the 
  giant 
  given 
  net 
  metering 
  impacts 
  
only 
  0.3% 
  of 
  utility 
  revenues. 
  
Despite 
  this 
  downplaying, 
  Musk 
  and 
  Rive 
  understood 
  well 
  why 
  investor-­‐owned 
  utilities 
  now 
  and 
  in 
  the 
  
future 
  see 
  accelerated 
  expansion 
  of 
  distributed 
  generation 
  and 
  energy 
  storage 
  as 
  a 
  serious 
  threat 
  to 
  
their 
  business 
  model, 
  which 
  has 
  been 
  historically 
  based 
  on 
  energy 
  sales 
  and 
  returns 
  from 
  investment 
  in 
  
infrastructure 
  such 
  as 
  wires 
  and 
  centralized 
  power 
  plants. 
  As 
  ratepayers 
  rely 
  less 
  on 
  their 
  local 
  utility 
  for 
  
power 
  supply, 
  this 
  throws 
  into 
  question 
  how 
  utilities 
  will 
  recoup 
  investments 
  from 
  fewer 
  customers 
  
making 
  up 
  their 
  rate 
  bases, 
  all 
  while 
  having 
  a 
  fiduciary 
  responsibility 
  to 
  their 
  shareholders. 
  Those 
  
customers 
  left, 
  they 
  fear, 
  will 
  see 
  utility 
  costs 
  shift 
  to 
  those 
  who 
  opt 
  not 
  to 
  or 
  cannot 
  buy 
  solar 
  panels 
  
and 
  energy 
  storage 
  technology, 
  which 
  covers 
  electric 
  vehicles 
  as 
  well 
  as 
  stationary 
  battery 
  installations. 
  
"Whenever 
  I 
  hear 
  'cost 
  shift,' 
  it's 
  the 
  wrong 
  word 
  to 
  use. 
  Revenue 
  loss 
  — 
  that's 
  the 
  issue 
  [for 
  utilities]," 
  
Rive 
  said, 
  adding 
  the 
  better 
  term 
  would 
  be 
  "revenue 
  shift" 
  given 
  the 
  real 
  issue 
  is 
  that 
  utilities 
  want 
  to 
  
keep 
  their 
  revenues. 
  
Facing 
  pressure 
  from 
  reluctant 
  utilities, 
  the 
  clean 
  energy 
  business 
  entrepreneurs 
  looked 
  to 
  regulators 
  to 
  
smooth 
  their 
  path. 
  Musk 
  said 
  pursing 
  customer 
  generation 
  options 
  such 
  as 
  battery 
  packs 
  in 
  garages 
  fed 
  
by 
  solar 
  panel 
  roof 
  installations 
  is 
  about 
  creating 
  a 
  world 
  of 
  clean 
  sustainable 
  energy 
  with 
  regulators 
  
"essential 
  to 
  make 
  sure 
  the 
  right 
  thing 
  happens."
Rive 
  contended 
  that 
  "climate 
  change 
  is 
  a 
  market 
  failure 
  that 
  is 
  occurring" 
  and 
  regulators 
  need 
  to 
  step 
  up 
  
to 
  address 
  that 
  as 
  they 
  have 
  other 
  market 
  failures. 
  Believing 
  decarbonizing 
  the 
  energy 
  sector 
  should 
  be 
  
a 
  goal 
  shared 
  by 
  everyone, 
  he 
  concluded: 
  "We 
  don't 
  want 
  two 
  energy 
  infrastructures. 
  At 
  some 
  point 
  
someone 
  has 
  to 
  shut 
  down, 
  and 
  if 
  you 
  fast 
  forward 
  10 
  or 
  20 
  years, 
  I 
  don't 
  think 
  we'll 
  be 
  shutting 
  down 
  
cleaner 
  energy." 
  
More 
  foreplay 
  with 
  cash 
  cows? 
  
Also 
  on 
  the 
  panel, 
  PUC 
  President 
  and 
  former 
  Southern 
  California 
  Edison 
  Co. 
  executive 
  Michael 
  Peevey 
  
supported 
  Musk 
  and 
  Rive's 
  drive 
  to 
  innovate 
  clean 
  energy 
  technology 
  and 
  usage 
  by 
  customers. 
  He 
  
acknowledged 
  that 
  regulation 
  can 
  "put 
  a 
  damper" 
  on 
  innovation 
  and 
  that 
  the 
  energy 
  sector 
  is 
  not 
  
known 
  for 
  innovative 
  policy. 
  But 
  he 
  did 
  highlight, 
  at 
  least 
  in 
  California, 
  that 
  innovative 
  policies 
  have 
  
been 
  pursued, 
  including 
  the 
  California 
  Solar 
  Initiative 
  for 
  rooftop 
  solar 
  and 
  the 
  state's 
  loading 
  order 
  that 
  
puts 
  energy 
  efficiency 
  and 
  renewable 
  energy 
  above 
  traditional 
  generation 
  resources. 
  
Peevey 
  also 
  highlighted 
  that 
  the 
  PUC 
  in 
  October 
  2013 
  ordered 
  PG&E 
  Corp. 
  subsidiary 
  Pacific 
  Gas 
  and 
  
Electric 
  Co., 
  Edison 
  International 
  subsidiary 
  SoCalEd, 
  and 
  Sempra 
  Energy 
  subsidiary 
  San 
  Diego 
  Gas 
  & 
  
Electric 
  Co. 
  to 
  issue 
  solicitations 
  starting 
  this 
  year 
  to 
  procure 
  a 
  total 
  of 
  1,325 
  MW 
  of 
  energy 
  storage 
  
capacity 
  by 
  2020. 
  

40 
  
 
  

 Peevey 
  said 
  he 
  shared 
  the 
  "frustration 
  and 
  lack 
  of 
  tolerance 
  of 
  the 
  status 
  quo" 
  felt 
  by 
  Musk 
  and 
  
particularly 
  Rive, 
  who 
  relayed 
  his 
  company's 
  problems 
  with 
  California 
  utilities 
  slowly 
  connecting 
  
customer 
  solar 
  systems 
  to 
  the 
  grid 
  or 
  "roadblocks" 
  as 
  he 
  called 
  them. 
  
"You 
  will 
  always 
  have 
  resistance 
  from 
  incumbents," 
  Peevey 
  said, 
  noting 
  that 
  the 
  economics 
  of 
  losing 
  
customers 
  will 
  continue 
  to 
  motivate 
  them. 
  He 
  relayed 
  a 
  similar 
  experience 
  he 
  had 
  with 
  New 
  Energy 
  
Ventures, 
  his 
  former 
  clean 
  energy 
  solutions 
  company 
  that 
  was 
  sold 
  to 
  AES 
  Corp. 
  for 
  $90 
  million 
  in 
  1999. 
  
It 
  involved 
  a 
  utility 
  delaying 
  the 
  installation 
  of 
  a 
  new 
  meter 
  at 
  a 
  San 
  Francisco 
  department 
  store. 
  He 
  
jokingly 
  did 
  not 
  want 
  to 
  mention 
  the 
  utility, 
  but 
  it 
  would 
  be 
  PG&E. 
  
Could 
  he 
  go 
  back 
  in 
  time 
  with 
  a 
  new 
  strategy, 
  Peevey 
  said 
  it 
  would 
  be 
  working 
  more 
  cooperatively 
  with 
  
legislators 
  and 
  utilities. 
  "I 
  wish 
  I 
  spent 
  more 
  time 
  trying 
  to 
  be 
  inclusive. 
  … 
  More 
  foreplay 
  or 
  romance, 
  if 
  
you 
  will," 
  he 
  said. 
  
With 
  his 
  final 
  PUC 
  term 
  done 
  by 
  year-­‐end, 
  Peevey 
  hoped 
  utilities 
  in 
  the 
  future 
  would 
  adapt 
  their 
  
business 
  models 
  to 
  change, 
  especially 
  since 
  he 
  expected 
  them 
  to 
  continue 
  to 
  be 
  profitable 
  and 
  remain 
  
"great 
  cash 
  cows." 
  They 
  will 
  become 
  "wires 
  companies 
  until 
  they 
  are 
  ultimately 
  finished 
  by 
  storage," 
  he 
  
predicted, 
  but 
  they 
  will 
  be 
  left 
  with 
  "a 
  lot 
  of 
  money 
  to 
  invest 
  in 
  other 
  things." 
  
Ultimately, 
  "the 
  race 
  goes 
  to 
  the 
  swift 
  and 
  the 
  clever," 
  Peevey 
  said, 
  with 
  utilities 
  entering 
  that 
  race 
  with 
  
enough 
  money 
  "to 
  exploit 
  and 
  invest." 
  Stranded 
  assets 
  are 
  not 
  the 
  challenge 
  but 
  rather 
  fostering 
  
innovation 
  is, 
  he 
  said: 
  "I'm 
  not 
  worrying 
  about 
  long-­‐lived 
  assets 
  of 
  the 
  past 
  that 
  are 
  largely 
  depreciated." 
  
 
  

Massive 
  losses 
  hit 
  Energy 
  Australia 
  as 
  demand 
  falls, 
  solar 
  soars 
    
  RenewEconomy 
    
  Giles 
  
Parkinson 
    
  2/28/2014 
  
http://reneweconomy.com.au/2014/massive-­‐losses-­‐hit-­‐energyaustralia-­‐as-­‐demand-­‐falls-­‐solar-­‐soars-­‐
67443 
  
EnergyAustralia, 
  one 
  of 
  the 
  big 
  three 
  utilities 
  in 
  the 
  country, 
  has 
  slumped 
  to 
  a 
  loss 
  of 
  $350 
  million 
  for 
  
calendar 
  2013 
  after 
  slashing 
  the 
  value 
  of 
  its 
  Yallourn 
  brown 
  coal 
  generator, 
  as 
  well 
  as 
  some 
  of 
  its 
  gas-­‐
fired 
  generation 
  assets. 
  
The 
  write-­‐down 
  came 
  as 
  the 
  company, 
  owned 
  by 
  Hong 
  Kong 
  based 
  CLP 
  Holdings, 
  returned 
  a 
  profit 
  of 
  
just 
  $18 
  million 
  (down 
  from 
  $236 
  million 
  in 
  2012) 
  for 
  the 
  year 
  from 
  its 
  portfolio 
  of 
  coal 
  and 
  gas 
  
generation 
  and 
  its 
  large 
  retail 
  customer 
  base 
  – 
  a 
  result 
  it 
  blamed 
  mostly 
  on 
  an 
  “unprecedented” 
  fall 
  in 
  
demand, 
  and 
  the 
  popularity 
  of 
  solar 
  PV. 
  
EnergyAustralia 
  also 
  chose 
  to 
  write 
  off 
  about 
  $300 
  million 
  from 
  the 
  value 
  of 
  its 
  ageing 
  Yallourn 
  brown 
  
coal 
  generator 
  in 
  Victoria. 
  This 
  was 
  part 
  of 
  a 
  total 
  write-­‐down 
  of 
  $445 
  million, 
  which 
  even 
  included 
  an 
  
$85 
  million 
  gain 
  from 
  what 
  it 
  called 
  the 
  “bargain 
  basement” 
  purchase 
  of 
  the 
  Mt 
  Piper 
  and 
  Wallerawang 
  
coal 
  fired 
  power 
  stations 
  from 
  the 
  NSW 
  Government. 
  
The 
  results 
  put 
  in 
  context 
  the 
  implacable 
  opposition 
  that 
  EnergyAustralia 
  has 
  to 
  the 
  renewable 
  energy 
  
target, 
  which 
  it 
  wants 
  halted 
  in 
  its 
  tracks 
  in 
  the 
  current 
  review 
  commissioned 
  by 
  the 
  Abbott 
  
government. 
  

41 
  
 
  

 And 
  it 
  also 
  highlights 
  the 
  dilemma 
  that 
  the 
  industry, 
  and 
  for 
  that 
  matter 
  the 
  government, 
  finds 
  itself 
  in 
  
over 
  soaring 
  gas 
  prices, 
  which 
  are 
  making 
  the 
  gas-­‐fired 
  generators 
  of 
  EnergyAustralia, 
  Origin 
  Energy, 
  
AGL 
  Energy 
  and 
  others, 
  such 
  as 
  Stanwell 
  Corp, 
  uneconomic 
  to 
  run 
  because 
  they 
  are 
  priced 
  out 
  of 
  the 
  
market. 
  Their 
  ability 
  to 
  compete 
  is 
  made 
  worse 
  by 
  the 
  Abbott 
  government’s 
  decision 
  to 
  try 
  and 
  dump 
  
the 
  carbon 
  price. 
  
It 
  also 
  explains 
  why 
  CLP 
  chose 
  to 
  defer, 
  indefinitely, 
  its 
  intended 
  stock 
  market 
  float 
  of 
  EnergyAustralia. 
  
EnergyAustralia 
  says 
  the 
  fall 
  in 
  wholesale 
  electricity 
  prices 
  has 
  been 
  caused, 
  perversely, 
  by 
  higher 
  
electricity 
  prices 
  for 
  customers, 
  mostly 
  due 
  to 
  network 
  costs, 
  which 
  is 
  encouraging 
  those 
  consumers 
  to 
  
put 
  on 
  more 
  solar 
  panels, 
  and 
  embrace 
  energy 
  efficiency. 
  Those 
  high 
  prices 
  are 
  also 
  contributing 
  to 
  the 
  
decisions 
  of 
  some 
  energy-­‐intensive 
  industries 
  to 
  leave 
  Australia. 
  While 
  network 
  costs 
  are 
  moderating, 
  
more 
  price 
  rises 
  can 
  be 
  expected 
  because 
  of 
  the 
  gas 
  boom. 
  Gas 
  still 
  supplies 
  around 
  10 
  per 
  cent 
  of 
  local 
  
generation, 
  and 
  often 
  sets 
  the 
  marginal 
  cost 
  of 
  generation. 
  
The 
  issue 
  of 
  over-­‐supply 
  and 
  falling 
  demand 
  is 
  one 
  of 
  the 
  principal 
  arguments 
  that 
  EnergyAustralia 
  and 
  
others 
  are 
  using 
  to 
  argue 
  for 
  either 
  scrapping 
  or 
  diluting 
  the 
  RET. 
  Even 
  AGL 
  Energy, 
  previously 
  the 
  
strongest 
  supporter 
  of 
  renewables 
  among 
  the 
  big 
  utilities, 
  is 
  backing 
  away 
  from 
  supporting 
  the 
  current 
  
fixed 
  target 
  following 
  its 
  own 
  proposed 
  bargain 
  basement 
  purchase 
  of 
  two 
  NSW 
  coal-­‐fired 
  generators 
  
(Bayswater 
  and 
  Liddell). 
  
Mostly, 
  though, 
  these 
  positions 
  are 
  about 
  protecting 
  the 
  short 
  term 
  interests 
  of 
  ageing 
  generators 
  that 
  
these 
  companies 
  have 
  been 
  able 
  to 
  buy 
  on 
  the 
  cheap 
  and 
  want 
  to 
  extract 
  maximum 
  value 
  from. 
  They 
  do 
  
not 
  reflect 
  some 
  of 
  the 
  fundamental 
  changes 
  that 
  are 
  occurring 
  in 
  the 
  industry, 
  particularly 
  the 
  changes 
  
in 
  consumer 
  behaviour 
  that 
  the 
  utilities 
  now 
  recognise 
  themselves. 
  
EnergyAustralia 
  did 
  note 
  some 
  of 
  the 
  major 
  pressures 
  on 
  the 
  Australian 
  electricity 
  market: 
  
-­‐ 
  Consumer 
  behaviour 
  and 
  expectations 
  had 
  changed 
  as 
  a 
  result 
  of 
  the 
  sharp 
  spike 
  in 
  retail 
  prices, 
  and 
  
the 
  growing 
  uptake 
  of 
  rooftop 
  solar 
  PV 
  and 
  energy 
  efficiency 
  products. 
  
-­‐ 
  The 
  uncertainty 
  around 
  carbon 
  pricing 
  and 
  other 
  policies 
  had 
  meant 
  it 
  was 
  impossible 
  to 
  enter 
  long-­‐
term 
  hedging 
  contracts, 
  which 
  reduced 
  the 
  ability 
  to 
  manage 
  risk. 
  
-­‐ 
  The 
  RET 
  had 
  forced 
  “subsidised” 
  renewable 
  capacity 
  into 
  an 
  over-­‐supplied 
  wholesale 
  market, 
  further 
  
dampening 
  wholesale 
  prices. 
  
-­‐ 
  Domestic 
  gas 
  prices 
  were 
  pushing 
  gas-­‐fired 
  generators 
  out 
  of 
  the 
  market, 
  and 
  the 
  pursuit 
  of 
  more 
  
“unconventional” 
  gas 
  to 
  meet 
  LNG 
  export 
  demand 
  was 
  also 
  adding 
  pressure 
  to 
  gas 
  prices. 
  
-­‐ 
  Coal 
  supply 
  has 
  become 
  more 
  challenging 
  as 
  costs 
  increase 
  and 
  legacy 
  contracts 
  roll-­‐off, 
  particularly 
  in 
  
NSW. 
   
  This 
  would 
  add 
  costs 
  and 
  prices 
  to 
  coal-­‐fired 
  generators. 
  
CEO 
  Richard 
  Lancaster 
  said 
  older 
  and 
  less 
  competitive 
  generators 
  would 
  soon 
  be 
  forced 
  out 
  of 
  the 
  
market. 
  It 
  has 
  already 
  closed 
  one 
  of 
  two 
  units 
  at 
  Wallerawang 
  and 
  the 
  second 
  unit 
  will 
  be 
  closed 
  next 
  
month. 
  Yallourn 
  this 
  year 
  was 
  hit 
  by 
  damage 
  and 
  outages 
  caused 
  by 
  the 
  flooding 
  of 
  the 
  adjacent 
  mine 
  by 
  
the 
  Morwell 
  River. 
  
The 
  write-­‐down 
  of 
  the 
  gas-­‐fired 
  generators 
  was 
  taken 
  after 
  the 
  company 
  noted 
  that 
  even 
  in 
  the 
  extreme 
  
heatwaves 
  in 
  Victoria 
  and 
  South 
  Australia 
  in 
  January, 
  wholesale 
  prices 
  remained 
  relatively 
  low 
  despite 
  
42 
  
 
  

 very 
  high 
  demand. 
  Because 
  the 
  cost 
  of 
  gas 
  generation 
  is 
  soaring 
  as 
  gas 
  prices 
  approach 
  export 
  parity, 
  
thanks 
  to 
  the 
  LNG 
  export 
  boom, 
  it 
  had 
  no 
  choice 
  but 
  to 
  declare 
  the 
  value 
  of 
  its 
  gas-­‐fired 
  generators 
  to 
  
be 
  impaired. 
  
EnergyAustralia 
  said 
  the 
  overcapacity 
  had 
  been 
  created 
  because 
  demand 
  had 
  fallen 
  by 
  6% 
  since 
  2007 
  
(against 
  all 
  expectations 
  of 
  an 
  increase), 
  while 
  generation 
  capacity 
  had 
  jumped 
  by 
  a 
  net 
  13%, 
  or 
  
5,5000MW 
  – 
  courtesy 
  of 
  new 
  thermal 
  generation 
  and 
  the 
  RET. 
  This 
  situation 
  had 
  been 
  exacerbated 
  by 
  a 
  
near 
  doubling 
  in 
  output 
  from 
  hydro 
  electric 
  generators. 
  
“The 
  over-­‐supply 
  of 
  electricity 
  generation, 
  aggravated 
  by 
  a 
  rush 
  to 
  build 
  renewable 
  energy 
  projects 
  to 
  
meet 
  Australia’s 
  Renewable 
  Energy 
  Target, 
  is 
  an 
  industry-­‐wide 
  issue.” 
  Lancaster 
  said 
  in 
  a 
  statement. 
  “It 
  
may 
  take 
  some 
  years 
  for 
  the 
  supply 
  and 
  demand 
  situation 
  to 
  return 
  to 
  balance 
  and 
  this 
  will 
  require 
  the 
  
closure 
  of 
  older, 
  less 
  competitive 
  generation 
  facilities.” 
  
Still, 
  despite 
  the 
  write-­‐downs, 
  plunging 
  operating 
  profits 
  and 
  bottom 
  line 
  losses, 
  there 
  was 
  none 
  of 
  the 
  
recent 
  talk 
  about 
  the 
  risk 
  of 
  blackouts 
  that 
  EnergyAustralia 
  has 
  deployed 
  in 
  the 
  Murdoch 
  press. 
  
“Our 
  generating 
  assets 
  are 
  supported 
  by 
  brown 
  coal 
  reserves, 
  black 
  coal 
  supply 
  contracts 
  and 
  
development 
  options, 
  long-­‐ 
  term 
  gas 
  contracts 
  and 
  gas 
  storage 
  operations,” 
  the 
  company 
  said. 
  “There 
  is 
  
considerable 
  strength 
  in 
  our 
  underlying 
  portfolio, 
  which 
  is 
  well 
  diversified 
  by 
  geography, 
  fuel 
  type 
  and 
  
operational 
  mode. 
  This 
  allows 
  us 
  to 
  effectively 
  manage 
  opportunities 
  and 
  risks 
  across 
  our 
  portfolio 
  in 
  
response 
  to 
  market 
  conditions.” 
  
Interestingly, 
  EnergyAustralia 
  said 
  the 
  purchase 
  of 
  Mount 
  Piper 
  and 
  Wallerawang 
  power 
  stations 
  in 
  
Australia 
  had 
  moved 
  the 
  company 
  “further 
  away” 
  from 
  its 
  ambitious 
  targets 
  to 
  reduce 
  its 
  carbon 
  
intensity 
  by 
  2020. 
  

Defending 
  Solar 
    
  Talk 
  107.3 
    
  3/11/2014 
  
http://www.talk1073.com/home/news/185190-­‐Defending-­‐solar.html 
  
(BATON 
  ROUGE) 
  Wednesday, 
  Louisiana's 
  Public 
  Service 
  Commission 
  will 
  once 
  again 
  take 
  a 
  vote 
  on 
  net 
  
metering, 
  a 
  policy 
  that 
  is 
  used 
  in 
  43 
  different 
  states 
  and 
  ensures 
  that 
  solar 
  customers 
  that 
  return 
  excess 
  
power 
  to 
  the 
  grid. 
  In 
  the 
  summer 
  of 
  2013, 
  the 
  PSC 
  halted 
  an 
  effort 
  to 
  end 
  net 
  metering 
  in 
  Louisiana. 
  At 
  
Wednesday's 
  meeting, 
  they'll 
  face 
  a 
  similar 
  decision. 
  
A 
  group 
  called 
  Tell 
  Utilities 
  Solar 
  won’t 
  be 
  Killed(TUSK) 
  is 
  fighting 
  Entergy's 
  efforts, 
  said 
  the 
  latest 
  poll 
  
numbers 
  show 
  that 
  roughly 
  84% 
  of 
  Louisianans 
  approve 
  of 
  net 
  metering 
  and 
  believe 
  the 
  successful 
  
policy 
  should 
  continue. 
  Brian 
  Miller 
  of 
  TUSK 
  told 
  Talk 
  107.3's 
  Kevin 
  and 
  Brian 
  that 
  Entergy 
  is 
  a 
  
monopoly, 
  and 
  would 
  cripple 
  the 
  solar 
  industry 
  if 
  they 
  are 
  able 
  to 
  eliminate 
  net 
  metering 
  in 
  the 
  state. 
  
Miller 
  explained 
  that 
  Hundreds 
  of 
  Louisianans 
  spoke 
  out 
  against 
  the 
  motion 
  last 
  year, 
  he 
  said 
  he 
  expects 
  
the 
  push 
  back 
  this 
  year 
  is 
  shaping 
  up 
  to 
  be 
  even 
  stronger. 
  
 
  
 
  
 
  

43 
  
 
  

 CMP 
  wants 
  Mainers 
  who 
  generate 
  their 
  own 
  power 
  to 
  pay 
  more 
    
  Portland 
  Press 
  Herald 
    
  Tux 
  

Turkel 
    
  3/11/2014 
  
http://www.pressherald.com/news/CMP_wants_Maine_self-­‐
generators_who_feed_grid_using_solar__wind_to_pay_more_.html 
  
Central 
  Maine 
  Power 
  Co. 
  wants 
  customers 
  that 
  generate 
  some 
  of 
  their 
  own 
  electricity 
  from 
  renewable 
  
sources 
  to 
  pay 
  higher 
  monthly 
  service 
  charges, 
  but 
  the 
  idea 
  is 
  being 
  challenged 
  as 
  an 
  attack 
  on 
  Maine’s 
  
renewable-­‐energy 
  industry. 
  
CMP 
  says 
  its 
  plan 
  would 
  help 
  cover 
  the 
  overall 
  cost 
  of 
  service 
  while 
  keeping 
  such 
  customers 
  on 
  the 
  grid 
  
even 
  if 
  they 
  don’t 
  need 
  power 
  all 
  the 
  time. 
  Advocates 
  of 
  solar 
  and 
  wind 
  power 
  say 
  the 
  so-­‐called 
  standby 
  
charge 
  would 
  kill 
  the 
  economics 
  of 
  investing 
  in 
  renewable 
  generation 
  and 
  run 
  counter 
  to 
  the 
  state’s 
  
policy 
  of 
  encouraging 
  renewable 
  energy 
  development. 
  
The 
  charges 
  would 
  have 
  “a 
  devastating 
  impact” 
  on 
  colleges 
  that 
  are 
  committed 
  to 
  promoting 
  
sustainability, 
  said 
  Laurie 
  Lachance, 
  president 
  of 
  Thomas 
  College 
  in 
  Waterville. 
  
In 
  2012, 
  the 
  college 
  had 
  a 
  12,600-­‐square-­‐foot 
  solar-­‐electric 
  array 
  installed 
  on 
  its 
  athletic 
  center. 
  The 
  
system 
  is 
  designed 
  to 
  supply 
  11 
  percent 
  of 
  the 
  school’s 
  electricity. 
  CMP’s 
  proposal 
  would 
  add 
  $38,000 
  to 
  
the 
  college’s 
  bill 
  over 
  five 
  years, 
  a 
  56 
  percent 
  increase, 
  Lachance 
  said. 
  
The 
  debate 
  is 
  part 
  of 
  a 
  rate 
  case 
  before 
  the 
  Maine 
  Public 
  Utilities 
  Commission. 
  The 
  case 
  centers 
  on 
  how 
  
much 
  CMP 
  can 
  collect 
  in 
  a 
  five-­‐year 
  rate 
  plan 
  through 
  2019 
  to 
  cover 
  the 
  cost 
  of 
  distributing 
  electricity, 
  
and 
  how 
  that 
  cost 
  will 
  be 
  divided 
  among 
  various 
  types 
  of 
  customers. 
  
The 
  PUC 
  will 
  hold 
  public 
  hearings 
  in 
  the 
  case 
  at 
  7 
  p.m. 
  April 
  2 
  at 
  the 
  commission’s 
  headquarters 
  in 
  
Hallowell 
  and 
  at 
  7 
  p.m. 
  April 
  3 
  at 
  the 
  University 
  of 
  Southern 
  Maine 
  in 
  Portland. 
  CMP 
  and 
  parties 
  to 
  the 
  
case 
  have 
  filed 
  thousands 
  of 
  pages 
  of 
  testimony. 
  
The 
  testimony 
  is 
  now 
  the 
  focus 
  of 
  closed-­‐door 
  meetings 
  in 
  which 
  the 
  parties 
  will 
  try 
  to 
  settle 
  key 
  points 
  
and 
  reach 
  an 
  agreement 
  on 
  a 
  rate 
  plan. 
  Since 
  1995, 
  every 
  five-­‐year 
  rate 
  plan 
  approved 
  by 
  the 
  three-­‐
member 
  PUC 
  has 
  been 
  based 
  on 
  agreements 
  reached 
  in 
  such 
  settlement 
  talks. 
  
PAYING 
  FOR 
  DISTRIBUTION 
  SERVICE 
  
For 
  many 
  years, 
  CMP 
  customers 
  have 
  paid 
  for 
  service 
  based 
  on 
  the 
  amount 
  of 
  electricity 
  they 
  use. 
  But 
  
overall 
  consumption 
  is 
  falling, 
  as 
  homes 
  and 
  businesses 
  become 
  more 
  efficient 
  and 
  growing 
  numbers 
  of 
  
users 
  generate 
  some 
  of 
  their 
  own 
  power 
  with 
  solar 
  panels 
  and 
  small 
  wind 
  turbines. 
  
About 
  1,000 
  of 
  CMP’s 
  customers 
  have 
  installed 
  renewable 
  power 
  units, 
  such 
  as 
  solar 
  arrays 
  or 
  wind 
  
turbines. 
  The 
  customers 
  range 
  from 
  homeowners 
  to 
  large 
  institutions, 
  including 
  several 
  of 
  Maine’s 
  
private 
  colleges. 
  
When 
  those 
  customers 
  are 
  generating 
  power 
  from 
  their 
  own 
  energy 
  sources, 
  they’re 
  not 
  buying 
  it 
  from 
  
another 
  supplier, 
  thereby 
  reducing 
  CMP’s 
  revenue. 
  CMP 
  wants 
  to 
  charge 
  those 
  customers 
  a 
  special 
  rate 
  
to 
  reflect 
  the 
  fact 
  that 
  even 
  though 
  they 
  aren’t 
  buying 
  power 
  all 
  the 
  time, 
  they 
  expect 
  CMP 
  to 
  provide 
  
them 
  with 
  reliable 
  distribution 
  service. 
  
It’s 
  an 
  issue 
  in 
  other 
  states, 
  too, 
  as 
  power 
  companies 
  adapt 
  to 
  increasing 
  power 
  generation 
  “behind 
  the 
  
meter,” 
  on-­‐site 
  by 
  small-­‐scale 
  producers. 
  
44 
  
 
  

 “They 
  aren’t 
  reducing 
  their 
  dependence 
  on 
  us,” 
  said 
  CMP 
  spokesman 
  John 
  Carroll. 
  “They’re 
  just 
  
reducing 
  their 
  dependence 
  on 
  grid-­‐supplied 
  electricity.” 
  
That 
  position 
  has 
  struck 
  a 
  nerve 
  with 
  a 
  wide 
  range 
  of 
  customers, 
  including 
  companies 
  that 
  sell 
  and 
  
install 
  wind 
  and 
  solar 
  equipment, 
  colleges 
  that 
  have 
  invested 
  in 
  solar, 
  wind 
  and 
  biomass 
  power 
  on 
  their 
  
campuses, 
  and 
  ski 
  areas 
  that 
  buy 
  renewable 
  power. 
  
CMP’s 
  proposal 
  is 
  discriminatory 
  and 
  would 
  stunt 
  the 
  growth 
  of 
  renewable 
  power 
  by 
  increasing 
  the 
  time 
  
it 
  takes 
  to 
  repay 
  the 
  investment 
  in 
  solar-­‐electric 
  panels, 
  said 
  Fortunat 
  Mueller, 
  co-­‐founder 
  of 
  ReVision 
  
Energy 
  in 
  Portland, 
  which 
  installed 
  Thomas 
  College’s 
  solar-­‐electric 
  array. 
  Every 
  customer 
  in 
  each 
  rate 
  
class 
  should 
  pay 
  the 
  same 
  basic 
  charge 
  for 
  service, 
  he 
  said. 
  
CMP’s 
  plan 
  is 
  especially 
  galling, 
  Mueller 
  said, 
  because 
  solar 
  customers, 
  on 
  average, 
  use 
  less 
  energy 
  
during 
  periods 
  when 
  the 
  power 
  grid 
  is 
  under 
  the 
  most 
  stress 
  and 
  wholesale 
  prices 
  are 
  high. 
  The 
  classic 
  
example 
  is 
  a 
  sunny 
  summer 
  day, 
  when 
  air 
  conditioners 
  are 
  running. 
  That’s 
  when 
  solar 
  panels 
  feed 
  
excess 
  electricity 
  to 
  the 
  grid, 
  reducing 
  the 
  need 
  for 
  new, 
  expensive 
  transmission 
  lines. 
  
Lachance, 
  who 
  filed 
  written 
  testimony 
  with 
  the 
  PUC 
  on 
  behalf 
  of 
  the 
  Maine 
  Independent 
  Colleges 
  
Association, 
  said 
  Thomas 
  College 
  uses 
  the 
  most 
  electricity 
  on 
  a 
  cold 
  winter 
  afternoon, 
  not 
  in 
  the 
  
summer. 
  
“CMP’s 
  proposal 
  to 
  impose 
  a 
  standby 
  charge 
  based 
  upon 
  a 
  customer’s 
  individual 
  peak 
  bears 
  no 
  
significant 
  relationship 
  to 
  the 
  likelihood 
  of 
  contribution 
  to 
  the 
  summer 
  peak,” 
  she 
  wrote. 
  “Although, 
  
perhaps 
  obviously, 
  many 
  customers 
  have 
  significant 
  usage 
  at 
  the 
  time 
  of 
  system 
  peak, 
  many 
  do 
  not. 
  The 
  
winter 
  peaking 
  nature 
  of 
  our 
  usage 
  is 
  a 
  clear 
  example 
  of 
  a 
  customer 
  situation 
  that 
  rebuts 
  CMP’s 
  basic 
  
assumption.” 
  
SLOWLY 
  RISING 
  CHARGES 
  PROPOSED 
  
Since 
  1995, 
  CMP 
  has 
  operated 
  under 
  five-­‐year 
  alternative 
  rate 
  plans. 
  The 
  PUC 
  sets 
  annual 
  performance 
  
targets 
  such 
  as 
  service 
  quality, 
  responsiveness 
  and 
  the 
  duration 
  of 
  power 
  outages. 
  CMP 
  is 
  rewarded 
  
with 
  a 
  certain 
  level 
  of 
  revenue 
  when 
  it 
  performs 
  well, 
  and 
  can 
  be 
  penalized 
  for 
  falling 
  short. 
  In 
  recent 
  
years, 
  CMP 
  has 
  met 
  or 
  exceeded 
  its 
  targets. 
  
CMP 
  also 
  has 
  kept 
  distribution 
  charges 
  relatively 
  flat 
  over 
  the 
  past 
  decade. 
  But 
  when 
  the 
  current 
  rate 
  
plan 
  was 
  being 
  developed 
  in 
  2007, 
  officials 
  assumed 
  electricity 
  sales 
  and 
  demand 
  would 
  grow 
  over 
  the 
  
next 
  five 
  years. 
  The 
  deep 
  recession, 
  warmer 
  winters 
  and 
  other 
  factors 
  ruined 
  those 
  projections. 
  Instead, 
  
sales 
  were 
  below 
  expectations 
  and 
  the 
  number 
  of 
  customers 
  hardly 
  grew. 
  
To 
  make 
  a 
  profit 
  in 
  line 
  with 
  investor-­‐owned 
  utilities, 
  CMP 
  wants 
  to 
  add 
  $1.03 
  a 
  month 
  in 
  the 
  first 
  year 
  
of 
  the 
  plan 
  to 
  the 
  distribution 
  share 
  of 
  an 
  average 
  home 
  customer’s 
  bill 
  of 
  $74.51. 
  The 
  numbers 
  would 
  
rise 
  each 
  year, 
  adding 
  a 
  total 
  of 
  $7 
  a 
  month 
  in 
  2018. 
  That 
  proposal 
  is 
  unrelated 
  to 
  the 
  standby 
  charge 
  for 
  
customers 
  that 
  generate 
  electricity. 
  
The 
  increase 
  would 
  be 
  for 
  only 
  the 
  distribution 
  portion 
  of 
  the 
  bill. 
  Energy 
  costs, 
  which 
  are 
  tied 
  to 
  the 
  
wholesale 
  price 
  of 
  natural 
  gas, 
  and 
  transmission 
  costs 
  make 
  up 
  roughly 
  two-­‐thirds 
  of 
  a 
  typical 
  residential 
  
bill. 
  

45 
  
 
  

 The 
  increase 
  would 
  fund 
  CMP’s 
  cost 
  of 
  complying 
  with 
  performance 
  targets, 
  such 
  as 
  limiting 
  the 
  
duration 
  and 
  frequency 
  of 
  power 
  outages, 
  and 
  cover 
  capital 
  spending 
  such 
  as 
  replacing 
  poles, 
  and 
  
maintenance 
  such 
  as 
  trimming 
  trees. 
  Those 
  are 
  typical 
  points 
  of 
  contention 
  in 
  a 
  rate 
  case. 
  
It’s 
  unknown 
  whether 
  the 
  parties 
  in 
  the 
  settlement 
  talks 
  will 
  compromise 
  on 
  the 
  standby 
  charge, 
  which 
  
would 
  roughly 
  double 
  the 
  basic 
  monthly 
  charge 
  for 
  self-­‐generators 
  by 
  2019. 
  
Eric 
  Bryant, 
  who 
  is 
  involved 
  with 
  the 
  case 
  as 
  a 
  senior 
  counsel 
  in 
  the 
  Maine 
  Public 
  Advocate’s 
  Office, 
  said 
  
the 
  parties 
  can’t 
  publicly 
  speculate 
  on 
  the 
  confidential 
  talks, 
  but 
  his 
  agency 
  opposes 
  the 
  charge. 
  
“At 
  this 
  point, 
  we 
  don’t 
  like 
  the 
  standby 
  charge,” 
  he 
  said. 
  “But 
  at 
  some 
  time 
  in 
  the 
  future, 
  there 
  may 
  be 
  
so 
  many 
  customers 
  that 
  own 
  generators 
  that 
  it 
  will 
  make 
  a 
  difference.” 
  

Net 
  metering, 
  a 
  contentious 
  issue 
  for 
  solar 
  industry 
  across 
  US, 
  center 
  of 
  debate 
  in 
  Colorado 
    
  
Associated 
  Press 
    
  Donna 
  Bryson 
    
  3/12/2014 
  
http://www.therepublic.com/w/CO-­‐Net-­‐Metering 
  
DENVER 
  — 
  When 
  Xcel 
  Energy 
  raised 
  questions 
  about 
  a 
  system 
  known 
  as 
  net 
  metering 
  that 
  helps 
  
determine 
  the 
  credit 
  homeowners 
  get 
  from 
  utility 
  companies 
  for 
  putting 
  solar 
  panels 
  on 
  their 
  roofs, 
  
regulators 
  found 
  the 
  issue 
  so 
  contentious 
  they 
  separated 
  it 
  from 
  a 
  review 
  of 
  the 
  renewable-­‐energy 
  
policies 
  of 
  Colorado's 
  largest 
  utility. 
  
On 
  Wednesday, 
  Colorado's 
  Public 
  Utilities 
  Commission 
  set 
  a 
  hearing 
  in 
  April 
  to 
  start 
  what 
  is 
  likely 
  to 
  be 
  a 
  
protracted 
  process 
  of 
  addressing 
  questions 
  solar 
  proponents 
  fear 
  could 
  lead 
  to 
  changes 
  that 
  could 
  hurt 
  
their 
  industry. 
  
Although 
  most 
  states 
  have 
  net-­‐metering 
  policies, 
  the 
  practice 
  has 
  touched 
  off 
  debates 
  from 
  Vermont 
  to 
  
Hawaii 
  that 
  could 
  have 
  a 
  profound 
  effect 
  on 
  renewable-­‐energy 
  policies 
  across 
  the 
  nation. 
  
In 
  Golden, 
  near 
  Denver, 
  the 
  city 
  council 
  responded 
  to 
  possible 
  changes 
  in 
  Colorado's 
  net-­‐metering 
  
policies 
  with 
  a 
  resolution 
  urging 
  regulators 
  "to 
  reject 
  efforts 
  by 
  Xcel 
  Energy 
  to 
  limit 
  net 
  metering." 
  
In 
  a 
  joint 
  letter 
  to 
  state 
  officials, 
  Dow, 
  the 
  giant 
  chemical 
  company 
  that 
  also 
  sells 
  rooftop 
  solar 
  systems, 
  
and 
  Florida-­‐based 
  home 
  developer 
  Lennar 
  said 
  potential 
  buyers 
  of 
  solar-­‐equipped 
  houses 
  in 
  Colorado 
  
are 
  showing 
  hesitancy 
  because 
  of 
  concern 
  that 
  regulators 
  might 
  tinker 
  with 
  net 
  metering. 
  
"The 
  reality 
  is 
  that 
  we'd 
  like 
  an 
  answer 
  as 
  soon 
  as 
  possible," 
  David 
  Kaiserman, 
  whose 
  SunStreet 
  Energy 
  
installs 
  solar 
  systems 
  in 
  Lennar 
  homes, 
  said 
  in 
  an 
  interview. 
  "But 
  we 
  don't 
  want 
  to 
  rush 
  and 
  get 
  the 
  
wrong 
  answer." 
  
Net-­‐metering 
  policies 
  across 
  the 
  U.S. 
  vary, 
  but 
  they 
  generally 
  allow 
  homeowners 
  with 
  solar 
  panels 
  on 
  
their 
  roofs, 
  once 
  they 
  have 
  met 
  their 
  own 
  needs, 
  to 
  get 
  credit 
  from 
  utility 
  companies 
  for 
  energy 
  they 
  put 
  
into 
  the 
  grid 
  to 
  be 
  sold 
  to 
  other 
  customers. 
  Many 
  homeowners 
  with 
  rooftop 
  solar 
  still 
  must 
  buy 
  energy 
  
from 
  their 
  utility 
  companies, 
  and 
  they 
  also 
  pay 
  service 
  and 
  other 
  charges. 
  When 
  homeowners 
  have 
  
surpluses, 
  the 
  credit 
  they 
  get 
  usually 
  goes 
  toward 
  their 
  overall 
  energy 
  bill. 
  
Minneapolis-­‐based 
  Xcel, 
  which 
  has 
  1.3 
  million 
  residential 
  and 
  commercial 
  electric 
  and 
  gas 
  customers 
  in 
  
Colorado, 
  says 
  net-­‐metering 
  customers 
  receive 
  a 
  10.5-­‐cent 
  credit 
  for 
  each 
  kilowatt 
  hour 
  they 
  put 
  on 
  the 
  
grid, 
  but 
  the 
  company 
  values 
  the 
  benefit 
  to 
  the 
  grid 
  at 
  only 
  5 
  cents 
  a 
  kilowatt 
  hour. 
  The 
  solar 
  industry 
  
has 
  challenged 
  Xcel's 
  figures. 
  
46 
  
 
  

 Xcel 
  is 
  not 
  calling 
  for 
  changes 
  immediately, 
  saying 
  it 
  first 
  wants 
  to 
  make 
  clear 
  to 
  consumers 
  what 
  part 
  of 
  
the 
  net-­‐metering 
  credit 
  reflects 
  the 
  value 
  of 
  the 
  energy 
  produced 
  and 
  what 
  part 
  should 
  be 
  seen 
  as 
  a 
  
subsidy. 
  When 
  it 
  first 
  raised 
  the 
  issue 
  earlier 
  this 
  year, 
  Xcel 
  said 
  that 
  if 
  regulators 
  do 
  not 
  agree 
  to 
  that 
  
accounting, 
  it 
  would 
  ask 
  to 
  drastically 
  reduce 
  the 
  amount 
  of 
  solar 
  energy 
  it 
  took 
  on 
  from 
  rooftop 
  
producers 
  this 
  year. 
  
Xcel 
  spokesman 
  Mark 
  Stutz 
  said 
  Wednesday 
  the 
  company 
  was 
  no 
  longer 
  proposing 
  a 
  reduction, 
  and 
  that 
  
the 
  company 
  was 
  pleased 
  to 
  be 
  having 
  a 
  public 
  "discussion 
  about 
  what 
  we 
  consider 
  to 
  be 
  a 
  net-­‐
metering 
  incentive." 
  
Jason 
  Keyes, 
  a 
  lawyer 
  who 
  represents 
  the 
  Interstate 
  Renewable 
  Energy 
  Council, 
  said 
  net-­‐metering 
  
calculations 
  by 
  utility 
  companies 
  often 
  leave 
  out 
  factors 
  such 
  as 
  the 
  possibility 
  money 
  could 
  be 
  saved 
  by 
  
relying 
  on 
  renewable 
  sources 
  instead 
  of 
  building 
  new 
  infrastructure. 
  The 
  council 
  he 
  represents 
  
promotes 
  renewable 
  energy. 
  
David 
  Owens, 
  executive 
  vice 
  president 
  of 
  the 
  Edison 
  Electric 
  Institute, 
  a 
  utility 
  industry 
  think 
  tank 
  and 
  
lobbying 
  body, 
  acknowledges 
  that 
  utilities 
  benefit 
  by, 
  for 
  example, 
  avoiding 
  transmission 
  costs 
  to 
  
homeowners 
  who 
  are 
  supplying 
  their 
  own 
  needs. 
  
But 
  Owens 
  said 
  that 
  from 
  a 
  utility's 
  perspective, 
  it's 
  not 
  clear 
  that 
  rooftop 
  solar 
  producers 
  are 
  paying 
  
their 
  fair 
  share 
  of 
  the 
  costs 
  of 
  maintaining 
  the 
  grid. 
  If 
  they 
  aren't, 
  he 
  said, 
  the 
  financial 
  burden 
  falls 
  on 
  
customers 
  who 
  don't 
  have 
  solar 
  systems. 
  His 
  institute's 
  polling 
  has 
  shown 
  that 
  that 
  argument 
  resonates 
  
with 
  rate-­‐payers, 
  he 
  said. 
  
Solar 
  companies 
  accuse 
  traditional 
  utility 
  companies, 
  some 
  of 
  which 
  are 
  establishing 
  large 
  solar 
  projects 
  
of 
  their 
  own, 
  of 
  wanting 
  to 
  squash 
  an 
  innovative, 
  agile 
  competitor. 
  Rooftop 
  solar 
  is 
  a 
  small 
  player 
  now, 
  
but 
  it 
  is 
  growing 
  rapidly. 
  
Colorado 
  voters 
  were 
  the 
  first 
  in 
  the 
  nation 
  to 
  adopt 
  their 
  own 
  renewable-­‐energy 
  standards 
  after 
  
passing 
  a 
  citizens 
  initiative 
  in 
  2004. 
  
Denver 
  homeowner 
  Barbara 
  Donachy, 
  testifying 
  at 
  a 
  utilities 
  commission 
  hearing 
  earlier 
  this 
  year 
  that 
  
focused 
  on 
  net 
  metering, 
  said 
  shade 
  and 
  other 
  factors 
  make 
  her 
  own 
  home 
  unsuitable 
  for 
  solar. 
  But 
  she 
  
supports 
  efforts 
  to 
  promote 
  solar 
  on 
  her 
  neighbors' 
  roofs. 
  
"I 
  never 
  thought 
  I 
  would 
  be 
  on 
  the 
  same 
  side 
  as 
  Dow," 
  she 
  said 
  later 
  in 
  an 
  interview. 
  Decades 
  ago, 
  
Donachy 
  protested 
  against 
  Dow 
  because 
  the 
  company 
  managed 
  a 
  bomb 
  factory 
  near 
  Boulder 
  that 
  
became 
  a 
  notorious 
  hazardous 
  waste 
  site. 
  
On 
  solar, 
  Dow's 
  letter 
  to 
  the 
  governor 
  shows 
  "people 
  do 
  have 
  vested 
  economic 
  interests," 
  she 
  said. 
  But 
  
"if 
  I 
  paid 
  more 
  on 
  my 
  utility 
  bill 
  and 
  I 
  knew 
  that 
  was 
  going 
  to 
  lower 
  the 
  carbon 
  footprint, 
  I 
  would 
  do 
  it." 
  

Minn. 
  regulators 
  approve 
  solar 
  tariff 
  formula 
    
  Jeffrey 
  Tomich  
  E&E 
  News 
    
  3/13/2014 
  
http://www.eenews.net/energywire/stories/1059996066/search?keyword=Minnesota 
  
Regulators 
  in 
  Minnesota 
  yesterday 
  put 
  the 
  state 
  on 
  a 
  path 
  to 
  become 
  the 
  first 
  in 
  the 
  nation 
  to 
  design 
  a 
  
specific 
  utility 
  rate 
  for 
  solar 
  energy 
  generated 
  by 
  homeowners 
  and 
  businesses. 
  

47 
  
 
  

 The 
  Minnesota 
  Public 
  Utilities 
  Commission 
  voted 
  3-­‐2 
  to 
  approve 
  the 
  "value 
  of 
  solar 
  tariff" 
  formula 
  after 
  
more 
  than 
  four 
  hours 
  of 
  debate 
  that 
  covered 
  a 
  wide 
  variety 
  of 
  complex 
  issues, 
  from 
  compliance 
  with 
  
federal 
  utility 
  law 
  to 
  tax 
  consequences 
  to 
  calculating 
  the 
  value 
  of 
  avoided 
  carbon 
  dioxide 
  emissions. 
  
The 
  formula 
  approved 
  by 
  the 
  PUC 
  represents 
  a 
  method 
  for 
  computing 
  a 
  per 
  kilowatt-­‐hour 
  rate 
  meant 
  to 
  
accurately 
  assign 
  a 
  value 
  of 
  customer-­‐generated 
  solar 
  energy 
  to 
  utilities, 
  their 
  customers 
  and 
  society. 
  
The 
  case 
  has 
  piqued 
  interest 
  among 
  utilities 
  and 
  regulators 
  across 
  the 
  country 
  because 
  it 
  represents 
  an 
  
alternative 
  to 
  controversial 
  state 
  net 
  metering 
  policies, 
  which 
  credit 
  customers 
  for 
  excess 
  energy 
  put 
  
onto 
  the 
  grid, 
  usually 
  at 
  retail 
  electric 
  rates. 
  
Net 
  metering, 
  which 
  exists 
  in 
  43 
  states 
  and 
  the 
  District 
  of 
  Columbia, 
  has 
  become 
  a 
  hot 
  topic 
  in 
  many 
  
other 
  states 
  and 
  a 
  focus 
  of 
  utilities, 
  which 
  argue 
  that 
  such 
  policies 
  don't 
  adequately 
  compensate 
  them 
  
for 
  fixed 
  costs. 
  
The 
  methodology 
  approved 
  yesterday 
  may 
  represent 
  a 
  solution. 
  But 
  it's 
  just 
  one 
  step 
  in 
  a 
  longer 
  process 
  
before 
  a 
  solar 
  tariff 
  can 
  be 
  applied. 
  
Importantly, 
  the 
  value 
  of 
  a 
  solar 
  tariff 
  is 
  voluntary, 
  and 
  it 
  is 
  too 
  soon 
  to 
  tell 
  whether 
  Minnesota 
  utilities 
  
will 
  embrace 
  solar 
  rates, 
  which 
  would 
  likely 
  be 
  a 
  higher 
  rate 
  than 
  current 
  net 
  metering 
  rates. 
  
The 
  Minnesota 
  Legislature 
  passed 
  a 
  law 
  last 
  spring 
  that 
  required 
  the 
  Department 
  of 
  Commerce 
  to 
  
propose 
  a 
  value 
  of 
  solar 
  methodology. 
  By 
  law, 
  the 
  PUC 
  could 
  adopt 
  it, 
  reject 
  it 
  or 
  propose 
  modifications 
  
that 
  would 
  require 
  the 
  department's 
  consent. 
  
A 
  value-­‐of-­‐solar 
  rate 
  is 
  intended 
  to 
  as 
  accurately 
  as 
  possible 
  peg 
  the 
  net 
  benefit 
  of 
  distributed 
  solar 
  
energy 
  to 
  utilities, 
  customers 
  and 
  society, 
  not 
  encourage 
  solar 
  investment 
  over 
  the 
  25-­‐year 
  assumed 
  life 
  
span 
  of 
  a 
  customer's 
  solar 
  energy 
  system 
  (EnergyWire, 
  March 
  11). 
  
But 
  it 
  is 
  not 
  meant 
  by 
  itself 
  to 
  encourage 
  solar 
  development, 
  Bill 
  Grant, 
  deputy 
  commissioner 
  for 
  energy 
  
at 
  the 
  Commerce 
  Department, 
  told 
  the 
  PUC. 
  
"There 
  are 
  things 
  value 
  of 
  solar 
  is, 
  and 
  things 
  that 
  value 
  of 
  solar 
  isn't," 
  he 
  said. 
  "What 
  it 
  isn't 
  is 
  an 
  
incentive 
  for 
  solar 
  PV." 
  
Social 
  cost 
  of 
  carbon 
  
The 
  proposed 
  solar 
  tariff 
  methodology 
  was 
  the 
  product 
  of 
  months 
  of 
  dialogue 
  among 
  the 
  state, 
  utilities 
  
and 
  solar 
  energy 
  advocates. 
  The 
  formula 
  was 
  designed 
  to 
  be 
  a 
  sum 
  of 
  all 
  the 
  attributes 
  of 
  distributed 
  
solar 
  energy, 
  including 
  cost 
  of 
  power 
  plant 
  fuel 
  not 
  burned, 
  unused 
  transmission 
  and 
  distribution 
  
capacity 
  and 
  avoided 
  emissions 
  of 
  carbon 
  dioxide 
  and 
  other 
  pollutants. 
  
Much 
  of 
  the 
  discussion 
  yesterday 
  focused 
  on 
  the 
  value 
  assigned 
  to 
  carbon 
  emissions, 
  which 
  is 
  taken 
  
from 
  the 
  social-­‐cost-­‐of-­‐carbon 
  calculation 
  developed 
  by 
  a 
  federal 
  interagency 
  working 
  group. 
  The 
  cost-­‐
of-­‐carbon 
  figure, 
  which 
  has 
  already 
  been 
  used 
  by 
  U.S. 
  EPA 
  and 
  the 
  Department 
  of 
  Energy 
  in 
  federal 
  
rulemakings, 
  estimates 
  the 
  incremental 
  cost 
  of 
  a 
  ton 
  of 
  carbon 
  dioxide 
  in 
  property 
  damage, 
  health 
  care 
  
costs 
  and 
  lost 
  agricultural 
  output. 
  

48 
  
 
  

 In 
  comments 
  filed 
  with 
  the 
  PUC, 
  three 
  Minnesota 
  utilities 
  disagreed 
  with 
  the 
  proposal 
  to 
  plug 
  in 
  the 
  
federal 
  social 
  cost 
  of 
  carbon 
  figure 
  of 
  $37 
  per 
  ton 
  of 
  CO2. 
  They 
  reiterated 
  their 
  disagreement 
  yesterday. 
  
So 
  did 
  Commissioner 
  David 
  Boyd, 
  who 
  cast 
  one 
  of 
  two 
  dissenting 
  votes. 
  
"For 
  me 
  this 
  is 
  a 
  deal-­‐breaker," 
  Boyd 
  said 
  early 
  on 
  during 
  the 
  hearing. 
  "I 
  don't 
  think 
  that 
  this 
  is 
  the 
  right 
  
procedural 
  path 
  to 
  follow." 
  
'Perfect 
  indifference' 
  sought 
  
Discussions 
  also 
  focused 
  on 
  the 
  appropriate 
  method 
  for 
  calculating 
  utilities' 
  avoided 
  fuel 
  costs. 
  
The 
  methodology 
  approved 
  by 
  the 
  PUC 
  assumes 
  the 
  marginal 
  unit 
  of 
  energy 
  displaced 
  by 
  customer-­‐
generated 
  solar 
  energy 
  will 
  be 
  gas-­‐fired 
  generation 
  with 
  avoided 
  fuel 
  costs 
  based 
  on 
  natural 
  gas 
  futures 
  
traded 
  on 
  the 
  New 
  York 
  Mercantile 
  Exchange. 
  Because 
  NYMEX 
  gas 
  futures 
  extend 
  out 
  only 
  12 
  years, 
  the 
  
solar 
  tariff 
  would 
  use 
  the 
  consumer 
  price 
  index 
  to 
  determine 
  appropriate 
  avoided 
  fuel 
  costs 
  for 
  years 
  13 
  
through 
  25. 
  
Commissioner 
  Betsy 
  Wergin, 
  the 
  other 
  commission 
  member 
  who 
  voted 
  against 
  the 
  proposed 
  
methodology, 
  also 
  raised 
  the 
  issue 
  of 
  cross-­‐subsidization 
  -­‐-­‐ 
  a 
  current 
  criticism 
  by 
  the 
  utility 
  industry 
  of 
  
net 
  metering 
  policies. 
  
Wergin 
  said 
  she's 
  concerned 
  that 
  a 
  value-­‐of-­‐solar 
  rate 
  would 
  benefit 
  wealthier 
  customers 
  who 
  could 
  
better 
  afford 
  solar 
  energy 
  systems, 
  at 
  the 
  expense 
  of 
  low-­‐income 
  consumers. 
  
"I 
  see 
  a 
  cross-­‐subsidy 
  happening 
  within 
  a 
  rate 
  class," 
  Wergin 
  said. 
  
But 
  if 
  done 
  right, 
  the 
  value-­‐of-­‐solar 
  tariff 
  would 
  void 
  that 
  problem 
  by 
  finding 
  the 
  exact 
  point 
  where 
  
utilities 
  and 
  consumers 
  are 
  indifferent 
  to 
  whether 
  a 
  utility 
  customer 
  puts 
  a 
  solar 
  array 
  on 
  his 
  or 
  her 
  roof, 
  
Grant 
  said. 
  
"The 
  goal 
  of 
  the 
  tariff," 
  he 
  said, 
  "is 
  to 
  find 
  that 
  point 
  of 
  perfect 
  indifference." 
  

Utility 
  regulator 
  fields 
  solar 
  complaints 
    
  Arizona 
  Republic 
    
  Ryan 
  Randazzo 
    
  3/13/2014 
  
http://www.azcentral.com/story/money/business/2014/03/13/utility-­‐regulator-­‐fields-­‐solar-­‐
complaints/6372529/ 
  
The 
  state's 
  top 
  utility 
  regulator 
  is 
  getting 
  complaints 
  from 
  Tucson 
  customers 
  of 
  SolarCity 
  Corp. 
  that 
  the 
  
solar 
  leasing 
  company 
  is 
  misleading 
  them 
  regarding 
  the 
  state 
  rules 
  for 
  hooking 
  up 
  a 
  solar 
  array, 
  he 
  said 
  
Wednesday. 
  
Arizona 
  Corporation 
  Commission 
  Chairman 
  Bob 
  Stump 
  wrote 
  a 
  letter 
  to 
  SolarCity 
  CEO 
  Lyndon 
  Rive 
  on 
  
Wednesday 
  asking 
  him 
  to 
  address 
  the 
  concerns. 
  
"This 
  is 
  an 
  issue 
  of 
  consumer 
  protection 
  and 
  solar 
  installer 
  transparency," 
  Stump 
  said 
  Wednesday. 
  
Stump 
  specifically 
  asked 
  Rive 
  to 
  describe 
  the 
  types 
  of 
  statements 
  SolarCity's 
  sales 
  representatives 
  make, 
  
the 
  type 
  of 
  training 
  they 
  get, 
  and 
  what 
  kind 
  of 
  monitoring 
  the 
  company 
  undertakes 
  to 
  ensure 
  they 
  
provide 
  "accurate 
  and 
  balanced 
  information." 
  
49 
  
 
  

 He 
  said 
  he 
  is 
  concerned 
  about 
  statements 
  regarding 
  net 
  metering, 
  the 
  arrangement 
  whereby 
  utilities 
  
give 
  customers 
  credit 
  for 
  the 
  electricity 
  they 
  send 
  to 
  the 
  power 
  grid 
  when 
  their 
  homes 
  are 
  not 
  using 
  it. 
  
The 
  credit 
  they 
  get 
  for 
  excess 
  generation 
  helps 
  offset 
  the 
  power 
  they 
  draw 
  from 
  the 
  utility 
  at 
  night. 
  
SolarCity 
  spent 
  most 
  of 
  2013 
  debating 
  Arizona 
  Public 
  Service 
  Co. 
  over 
  net 
  metering. 
  The 
  utility 
  
suggested 
  solar 
  net-­‐metered 
  customers 
  pay 
  $50 
  to 
  $100 
  a 
  month 
  for 
  their 
  use 
  of 
  the 
  utility 
  grid. 
  The 
  five 
  
regulators 
  settled 
  on 
  a 
  fee 
  of 
  about 
  $5 
  a 
  month 
  in 
  November 
  for 
  customers 
  who 
  install 
  solar 
  after 
  the 
  
first 
  of 
  this 
  year. 
  
The 
  decision 
  "grandfathered" 
  in 
  the 
  nearly 
  20,000 
  APS 
  customers 
  that 
  already 
  installed 
  solar, 
  and 
  
Stump's 
  letter 
  said 
  he 
  is 
  concerned 
  that 
  SolarCity 
  is 
  incorrectly 
  telling 
  customers 
  that 
  the 
  rules 
  can't 
  
change. 
  
Stump 
  said 
  several 
  Tucson 
  Electric 
  Power 
  customers 
  have 
  complained 
  that 
  they 
  were 
  told 
  by 
  SolarCity 
  
that 
  if 
  they 
  install 
  solar, 
  they 
  will 
  be 
  grandfathered 
  in. 
  But 
  then 
  those 
  customers 
  must 
  sign 
  an 
  
interconnection 
  agreement 
  with 
  TEP, 
  which 
  states 
  that 
  the 
  utility's 
  rates 
  and 
  tariffs 
  are 
  subject 
  to 
  
change. 
  
TEP 
  began 
  adding 
  the 
  language 
  to 
  its 
  interconnection 
  agreements 
  after 
  the 
  commission 
  required 
  such 
  
statements 
  in 
  the 
  APS 
  agreements. 
  
"They 
  are 
  confused 
  and 
  they 
  are 
  angry, 
  believing 
  that 
  TEP 
  is 
  at 
  fault," 
  Stump 
  said. 
  "We 
  need 
  to 
  ensure, 
  
in 
  my 
  view, 
  that 
  the 
  representations 
  and 
  statements 
  are 
  indeed 
  accurate 
  on 
  the 
  part 
  of 
  the 
  sale 
  
representatives." 
  
Stump 
  said 
  any 
  decision 
  by 
  the 
  commission 
  is 
  subject 
  to 
  review, 
  especially 
  for 
  TEP 
  customers, 
  which 
  will 
  
face 
  a 
  separate 
  decision 
  on 
  regarding 
  net 
  metering. 
  
"In 
  TEP's 
  next 
  rate 
  case, 
  or 
  in 
  some 
  other 
  subsequent 
  TEP 
  proceeding 
  concerning 
  net 
  metering 
  or 
  rate 
  
design, 
  grandfathering 
  is 
  one 
  possible 
  outcome," 
  Stump 
  said 
  in 
  the 
  letter. 
  "However, 
  it 
  is 
  presumptuous 
  
to 
  tell 
  customers 
  that 
  such 
  an 
  outcome 
  is 
  certain." 
  
Stump 
  said 
  he 
  will 
  place 
  the 
  item 
  on 
  the 
  agenda 
  of 
  an 
  upcoming 
  commission 
  meeting 
  to 
  discuss 
  his 
  
concerns 
  with 
  fellow 
  commissioners. 
  He 
  asked 
  Rive 
  to 
  respond 
  to 
  his 
  questions 
  by 
  March 
  31. 
  
Rive 
  is 
  the 
  cousin 
  of 
  Tesla 
  Motors 
  CEO 
  Elon 
  Musk, 
  who 
  is 
  currently 
  deciding 
  whether 
  to 
  locate 
  a 
  $4 
  
billion 
  to 
  $5 
  billion 
  battery 
  factory 
  in 
  Arizona, 
  Nevada, 
  New 
  Mexico 
  or 
  Texas. 
  

SolarCity 
  says 
  accusations 
  political 
    
  Arizona 
  Republic 
    
  Ryan 
  Randazzo 
    
  3/14/2014 
  
http://www.azcentral.com/story/money/business/2014/03/14/solarcity-­‐says-­‐accusations-­‐
political/6420853/ 
  
SolarCity 
  Corp. 
  responded 
  to 
  accusations 
  from 
  Arizona's 
  top 
  utility 
  regulator 
  saying 
  the 
  company 
  is 
  
truthful 
  in 
  its 
  advertising 
  and 
  battling 
  utilities 
  that 
  see 
  solar 
  as 
  a 
  competitive 
  threat. 
  
Arizona 
  Corporation 
  Commission 
  Chairman 
  Bob 
  Stump 
  wrote 
  a 
  letter 
  to 
  SolarCity 
  CEO 
  Lyndon 
  Rive 
  on 
  
Wednesday 
  asking 
  about 
  statements 
  SolarCity's 
  sales 
  representatives 
  make 
  and 
  what 
  kind 
  of 
  monitoring 
  
the 
  company 
  undertakes 
  to 
  ensure 
  they 
  provide 
  accurate 
  information. 
  

50 
  
 
  

 Stump 
  said 
  Tucson 
  Electric 
  Power 
  customers 
  were 
  complaining 
  about 
  conflicting 
  information 
  from 
  
SolarCity 
  and 
  the 
  utility. 
  
"We 
  believe 
  that 
  this 
  allegation 
  is 
  politically 
  motivated," 
  said 
  Will 
  Craven, 
  senior 
  communications 
  
manager 
  for 
  SolarCity. 
  "Utilities 
  are 
  trying 
  to 
  disrupt 
  straightforward 
  private 
  business 
  transactions 
  
between 
  solar 
  companies 
  and 
  Arizona 
  residents 
  by 
  planting 
  seeds 
  of 
  doubt 
  in 
  the 
  minds 
  of 
  ratepayers 
  
wherever 
  they 
  can, 
  simply 
  in 
  order 
  to 
  harm 
  the 
  rooftop 
  solar 
  industry." 
  
Stump 
  said 
  he 
  is 
  concerned 
  about 
  statements 
  regarding 
  net 
  metering, 
  the 
  arrangement 
  whereby 
  
utilities 
  give 
  customers 
  credit 
  for 
  the 
  electricity 
  they 
  send 
  to 
  the 
  power 
  grid 
  when 
  their 
  homes 
  are 
  not 
  
using 
  it. 
  The 
  credit 
  they 
  get 
  for 
  excess 
  generation 
  helps 
  offset 
  the 
  power 
  they 
  draw 
  from 
  the 
  utility 
  at 
  
night, 
  lowering 
  their 
  bills. 
  
SolarCity 
  spent 
  most 
  of 
  2013 
  debating 
  Arizona 
  Public 
  Service 
  Co. 
  over 
  net 
  metering. 
  Regulators 
  in 
  
November 
  decided 
  to 
  add 
  a 
  fee 
  that 
  averages 
  $5 
  a 
  month 
  to 
  new 
  solar 
  customers. 
  The 
  commissioners 
  
decided 
  to 
  "grandfather" 
  the 
  nearly 
  20,000 
  APS 
  customers 
  that 
  already 
  installed 
  solar, 
  sparing 
  them 
  the 
  
fee. 
  
Stump's 
  letter 
  said 
  he 
  is 
  concerned 
  that 
  SolarCity 
  is 
  incorrectly 
  telling 
  customers 
  that 
  the 
  rules 
  can't 
  
change. 
  Stump 
  said 
  several 
  TEP 
  customers 
  have 
  complained 
  that 
  they 
  were 
  told 
  by 
  SolarCity 
  that 
  if 
  they 
  
install 
  solar, 
  they 
  will 
  be 
  grandfathered 
  in. 
  But 
  then 
  those 
  customers 
  must 
  sign 
  an 
  interconnection 
  
agreement 
  with 
  TEP, 
  which 
  states 
  that 
  the 
  utility's 
  rates 
  and 
  tariffs 
  are 
  subject 
  to 
  change. 
  
Stump 
  said 
  any 
  decision 
  by 
  the 
  commission 
  is 
  subject 
  to 
  review, 
  especially 
  for 
  TEP 
  customers, 
  who 
  will 
  
face 
  a 
  separate 
  decision 
  on 
  net 
  metering. 
  
"It 
  is 
  presumptuous 
  to 
  tell 
  customers 
  that 
  such 
  an 
  outcome 
  is 
  certain," 
  he 
  said. 
  
Craven 
  said 
  the 
  only 
  reason 
  the 
  rules 
  will 
  change 
  is 
  if 
  TEP, 
  APS 
  or 
  other 
  utilities 
  seek 
  such 
  changes, 
  and 
  
that 
  what 
  SolarCity 
  tells 
  customers 
  is 
  correct. 
  
"We 
  are 
  confident 
  that 
  the 
  information 
  we 
  provide 
  to 
  customers 
  is 
  accurate," 
  Craven 
  said. 
  "In 
  sales 
  
conversations 
  we 
  note 
  that 
  utility 
  regulations 
  and 
  prices 
  are 
  subject 
  to 
  change, 
  but 
  to 
  date 
  no 
  rooftop 
  
solar 
  customer 
  in 
  the 
  nation 
  has 
  failed 
  to 
  be 
  grandfathered 
  following 
  changes 
  to 
  net 
  metering 
  — 
  in 
  
every 
  case 
  the 
  discussion 
  is 
  not 
  whether 
  to 
  grandfather, 
  but 
  how 
  much 
  to 
  grandfather 
  ... 
  To 
  the 
  extent 
  
that 
  solar 
  customers 
  are 
  at 
  risk 
  of 
  changes, 
  it 
  is 
  due 
  entirely 
  to 
  the 
  desire 
  and 
  willingness 
  of 
  utilities 
  to 
  
put 
  them 
  at 
  risk." 
  
The 
  dustup 
  with 
  SolarCity's 
  Rive 
  comes 
  as 
  Rive's 
  cousin, 
  Elon 
  Musk, 
  is 
  considering 
  where 
  to 
  locate 
  a 
  $4 
  
billion 
  to 
  $5 
  billion 
  battery 
  factory 
  for 
  his 
  company, 
  Tesla 
  Motors. 
  Arizona 
  is 
  one 
  of 
  four 
  states 
  in 
  the 
  
running 
  for 
  the 
  factory. 
  

Solar 
  PV 
  to 
  replace 
  coal 
  as 
  “incumbent” 
  technology 
    
  RenewEconomy 
    
  Giles 
  Parkinson 
    
  
3/17/2014 
   
  
http://reneweconomy.com.au/2014/solar-­‐pv-­‐replace-­‐coal-­‐incumbent-­‐technology-­‐38095 
  
Australia 
  is 
  embarking 
  on 
  a 
  radical 
  transformation 
  of 
  its 
  electricity 
  system 
  that 
  will 
  see 
  solar 
  PV 
  
transition 
  from 
  being 
  “disruptive” 
  technology 
  to 
  the 
  “incumbent” 
  technology, 
  displacing 
  coal 
  and 
  
sparking 
  a 
  radical 
  change 
  in 
  the 
  way 
  that 
  electricity 
  is 
  provided. 
  
51 
  
 
  

 This 
  is 
  the 
  assessment 
  from 
  Clean 
  Energy 
  Council 
  CEO 
  David 
  Green 
  (pictured), 
  who 
  in 
  a 
  presentation 
  last 
  
week 
  said 
  generation 
  will 
  move 
  from 
  its 
  traditional 
  place 
  at 
  the 
  point 
  of 
  supply 
  to 
  at 
  or 
  near 
  the 
  point 
  of 
  
use; 
  the 
  primary 
  role 
  of 
  the 
  grid 
  will 
  be 
  converted 
  to 
  that 
  of 
  a 
  back-­‐up 
  “battery”; 
  and 
  consumers 
  will 
  
play 
  a 
  key 
  role 
  in 
  a 
  more 
  competitive 
  market. 
  
Green 
  told 
  a 
  Davos 
  Connection 
  conference 
  on 
  infrastructure 
  last 
  week 
  that 
  the 
  core 
  logic 
  behind 
  having 
  
large 
  scale 
  generation 
  plants 
  close 
  to 
  their 
  fuel 
  source 
  (coal 
  or 
  hydro) 
  was 
  being 
  challenged 
  by 
  shifts 
  in 
  
the 
  basic 
  cost 
  parameters 
  of 
  many 
  sources 
  of 
  energy 
  allow 
  generation 
  (mostly 
  solar) 
  to 
  be 
  built 
  closer 
  to 
  
where 
  it 
  is 
  used. 
  
It 
  was 
  clear, 
  he 
  said, 
  that 
  solar 
  PV 
  has 
  been 
  taken 
  up 
  more 
  rapidly 
  in 
  lower-­‐income 
  suburbs 
  than 
  higher 
  
income 
  – 
  because 
  of 
  the 
  attraction 
  for 
  lower-­‐income 
  households 
  to 
  get 
  a 
  lower, 
  fixed 
  rate 
  of 
  electricity. 
  
Now, 
  new 
  financing 
  models 
  – 
  such 
  as 
  leasing 
  and 
  community 
  ownership, 
  as 
  well 
  as 
  models 
  for 
  renters 
  – 
  
was 
  likely 
  to 
  spark 
  a 
  third 
  wave 
  of 
  investment 
  in 
  solar 
  PV. 
  
“Further 
  innovation 
  in 
  the 
  business 
  models 
  will 
  potentially 
  unleash 
  still 
  more 
  waves 
  of 
  investment 
  until 
  
solar 
  PV 
  has 
  fully 
  transitioned 
  from 
  disruptive 
  technology 
  to 
  the 
  new 
  incumbent 
  technology,” 
  Green 
  
says. 
  (You 
  can 
  read 
  the 
  whole 
  presentation 
  here) 
  
“In 
  a 
  similar 
  way 
  we 
  are 
  witnessing 
  the 
  battery 
  energy 
  storage 
  market 
  emerge. 
  Like 
  the 
  solar 
  PV 
  market, 
  
it 
  is 
  initially 
  focused 
  on 
  early 
  adopters, 
  but 
  spreading 
  quickly 
  as 
  the 
  economic 
  case 
  for 
  investment 
  
becomes 
  favorable.” 
  
Green 
  says 
  it 
  is 
  not 
  yet 
  clear 
  whether 
  the 
  spread 
  of 
  low-­‐cost 
  energy 
  storage 
  will 
  result 
  in 
  households 
  
disconnecting 
  from 
  the 
  distribution 
  grid 
  entirely 
  – 
  seen 
  as 
  the 
  most 
  radical 
  vision 
  for 
  a 
  decentralized 
  
energy 
  sector, 
  and 
  one 
  that 
  CSIRO 
  entertained 
  in 
  its 
  Future 
  Grids 
  analysis, 
  and 
  which 
  has 
  been 
  raised 
  by 
  
utilities 
  in 
  the 
  US 
  and 
  elsewhere 
  as 
  either 
  a 
  great 
  opportunity, 
  or 
  a 
  horrendous 
  threat. 
  
“For 
  the 
  moment 
  it 
  would 
  seem 
  more 
  likely 
  that 
  households 
  will 
  stay 
  on 
  the 
  grid,” 
  Green 
  says. 
  “But 
  that 
  
the 
  role 
  of 
  grid-­‐supplied 
  power 
  will 
  be 
  inverted, 
  from 
  the 
  primary 
  source 
  of 
  power 
  (supplemented 
  by 
  
embedded 
  generation 
  like 
  solar 
  PV) 
  to 
  a 
  safety 
  net 
  supplier 
  of 
  last 
  resort, 
  with 
  embedded 
  generation 
  
being 
  the 
  primary 
  source 
  of 
  power.” 
  
“Even 
  this 
  more 
  moderate 
  vision 
  would 
  require 
  a 
  fundamental 
  rethink 
  in 
  the 
  financial 
  model 
  for 
  
distribution 
  network 
  services 
  businesses.” 
  
Those 
  comments 
  fit 
  in 
  with 
  the 
  scenarios 
  painted 
  by 
  the 
  CSIRO, 
  which 
  suggested 
  that 
  customers 
  were 
  
more 
  likely 
  to 
  remain 
  on 
  the 
  grid 
  if 
  the 
  utilities 
  adapted 
  their 
  business 
  models. 
  But 
  it 
  also 
  made 
  clear 
  
that 
  a 
  third 
  or 
  more 
  customers 
  could 
  simply 
  leave 
  the 
  grid 
  if 
  the 
  utilities 
  failed 
  to 
  act. 
  
Green 
  said 
  it 
  was 
  clear 
  that 
  the 
  pace 
  of 
  innovation 
  in 
  distributed 
  generation 
  technology, 
  the 
  demand 
  by 
  
consumers 
  for 
  greater 
  involvement 
  in, 
  and 
  control 
  of, 
  the 
  ownership 
  and 
  usage 
  of 
  electricity, 
  and 
  the 
  
international 
  drive 
  to 
  address 
  climate 
  change 
  are 
  all 
  promoting 
  real 
  and 
  fundamental 
  change. 
  
“A 
  ‘new 
  normal’ 
  has 
  not 
  yet 
  been 
  established 
  but 
  all 
  the 
  indications 
  are 
  that 
  the 
  emerging 
  model 
  will 
  
lower 
  the 
  cost 
  of 
  new 
  infrastructure, 
  improve 
  competition 
  and 
  greatly 
  improve 
  the 
  degree 
  to 
  which 
  
existing 
  infrastructure 
  is 
  used 
  efficiently.” 
  
He 
  noted 
  that 
  while 
  many 
  incumbents 
  saw 
  distributed 
  generation 
  as 
  a 
  niche, 
  it 
  was 
  moving 
  at 
  such 
  a 
  
speed 
  that 
  it 
  was 
  simply 
  a 
  matter 
  of 
  innovation 
  and 
  to 
  what 
  extent 
  the 
  “new 
  entrants 
  of 
  today”are 
  
allowed 
  to 
  become 
  the 
  incumbents 
  of 
  tomorrow. 
  

52 
  
 
  

 Green 
  says 
  that 
  Australia 
  has 
  managed 
  to 
  shift 
  around 
  13 
  per 
  cent 
  of 
  its 
  electricity 
  generation 
  to 
  more 
  
decentralised 
  renewable 
  sources 
  so 
  far, 
  with 
  much 
  of 
  this 
  also 
  coming 
  in 
  the 
  form 
  of 
  what 
  he 
  calls 
  
“modular” 
  wind 
  farms 
  (they 
  can 
  be 
  built 
  with 
  just 
  a 
  few 
  turbines 
  or 
  more 
  than 
  a 
  hundred). 
  
But 
  because 
  this 
  and 
  solar 
  are 
  disruptive, 
  it 
  will 
  be 
  fiercely 
  contested 
  by 
  those 
  who 
  benefit 
  from 
  the 
  
traditional 
  system 
  – 
  the 
  network 
  operators 
  and 
  the 
  fossil 
  fuel 
  producers. 
  
“They 
  will 
  have 
  an 
  obvious 
  tendency 
  to 
  resist 
  change,” 
  he 
  says. 
  “Others 
  will 
  embrace 
  it. 
  It 
  is 
  potentially 
  
an 
  exciting 
  and 
  dynamic 
  time 
  for 
  the 
  energy 
  sector 
  to 
  drive 
  innovation 
  and 
  reach 
  for 
  the 
  future.” 
  
RenewEconomy’s 
  Take: 
  Green 
  is 
  right, 
  and 
  this 
  speech 
  is 
  welcome. 
  It 
  is 
  about 
  time 
  that 
  the 
  clean 
  
energy 
  industry 
  articulates 
  such 
  a 
  vision 
  for 
  the 
  future 
  in 
  a 
  co-­‐ordinated 
  and 
  vigorous 
  manner. 
  There 
  is 
  
much 
  at 
  stake. 
  
As 
  in 
  the 
  US, 
  there 
  is 
  a 
  mixture 
  between 
  those 
  who 
  see 
  opportunity, 
  and 
  those 
  who 
  see 
  only 
  threat. 
  
Right 
  now, 
  it 
  appears, 
  it 
  is 
  the 
  latter 
  dominating 
  policy 
  settings. 
  The 
  utilities 
  are 
  resisting 
  change, 
  and 
  so 
  
are 
  the 
  government 
  owners. 
  
The 
  carbon 
  price 
  is 
  being 
  wound 
  back, 
  the 
  renewable 
  energy 
  target 
  is 
  under 
  threat, 
  and 
  energy 
  
efficiency 
  schemes 
  are 
  also 
  being 
  wound 
  back. 
  In 
  the 
  meantime, 
  tariffs 
  and 
  regulations 
  appear 
  ready 
  to 
  
be 
  deployed 
  to 
  slow 
  down 
  the 
  uptake 
  of 
  the 
  solar 
  and 
  solar 
  storage 
  and 
  other 
  technologies. 
  It 
  should 
  be 
  
a 
  quite 
  battle. 
  

Tentative 
  deal 
  reached 
  on 
  solar 
  power 
  in 
  SC 
    
  The 
  State 
    
  Sammy 
  Fretwell 
    
  3/19/2014 
  
http://www.thestate.com/2014/03/19/3336444/tentative-­‐deal-­‐reached-­‐on-­‐solar.html 
  
COLUMBIA, 
  SC 
  — 
  Solar 
  energy 
  boosters 
  and 
  utility 
  representatives 
  say 
  they 
  have 
  broken 
  a 
  stalemate 
  
over 
  expanding 
  the 
  use 
  of 
  sun 
  power 
  in 
  South 
  Carolina 
  after 
  years 
  of 
  disagreement. 
  
The 
  tentative 
  deal, 
  which 
  needs 
  approval 
  from 
  the 
  Legislature, 
  would 
  make 
  it 
  easier 
  for 
  homeowners 
  
and 
  businesses 
  to 
  acquire 
  the 
  use 
  of 
  solar 
  panels 
  that 
  could 
  save 
  money 
  on 
  monthly 
  power 
  bills. 
  
Caps 
  on 
  solar 
  power 
  also 
  would 
  be 
  loosened 
  so 
  that 
  businesses 
  and 
  other 
  non-­‐residential 
  entities 
  could 
  
widen 
  their 
  use 
  of 
  energy 
  from 
  the 
  sun, 
  according 
  to 
  a 
  bill 
  discussed 
  Wednesday 
  with 
  state 
  senators 
  in 
  
Columbia. 
  
Furman 
  University 
  would 
  be 
  among 
  the 
  winners. 
  The 
  Greenville 
  college, 
  known 
  for 
  its 
  earth-­‐friendly 
  
initiatives, 
  has 
  been 
  blocked 
  from 
  expanding 
  its 
  solar 
  energy 
  use 
  because 
  of 
  a 
  restrictive 
  state 
  cap. 
  A 
  
looser 
  cap 
  would 
  change 
  that. 
  
The 
  deal 
  doesn’t 
  resolve 
  all 
  issues 
  – 
  including 
  how 
  the 
  state 
  specifically 
  could 
  help 
  non-­‐profit 
  groups, 
  
schools 
  and 
  churches 
  afford 
  the 
  upfront 
  costs 
  of 
  acquiring 
  solar 
  panels. 
  The 
  proposal 
  also 
  needs 
  to 
  be 
  
fully 
  vetted 
  by 
  others, 
  including 
  the 
  state 
  Office 
  of 
  Regulatory 
  Staff. 
  
But 
  environmentalists 
  and 
  power 
  company 
  representatives 
  said 
  the 
  agreement 
  is 
  a 
  substantial 
  leap 
  
ahead. 
  
During 
  a 
  Senate 
  subcommittee 
  meeting 
  packed 
  with 
  business 
  interests 
  and 
  environmentalists, 
  no 
  one 
  
spoke 
  against 
  the 
  agreement 
  when 
  asked 
  by 
  Sen. 
  Luke 
  Rankin, 
  R-­‐Horry. 
  
53 
  
 
  

 “An 
  enormous 
  amount 
  of 
  work 
  went 
  into 
  getting 
  to 
  a 
  place 
  of 
  compromise,” 
  said 
  Hamilton 
  Davis, 
  who 
  
heads 
  the 
  energy 
  division 
  for 
  the 
  S.C. 
  Coastal 
  Conservation 
  League. 
  “It’s 
  not 
  ideal, 
  but 
  I 
  think 
  it’s 
  a 
  good 
  
product 
  and 
  something 
  that 
  is 
  worthy 
  of 
  the 
  Senate’s 
  consideration.” 
  
Chuck 
  Claunch, 
  a 
  lobbyist 
  for 
  Duke 
  Energy, 
  said 
  after 
  the 
  meeting 
  that 
  utilities 
  like 
  the 
  compromise 
  
discussed 
  Wednesday. 
  So 
  do 
  the 
  state’s 
  electric 
  cooperatives, 
  co-­‐op 
  representative 
  John 
  Frick 
  said. 
  
“From 
  where 
  we 
  were 
  last 
  (year) 
  to 
  where 
  we 
  are 
  now, 
  is 
  a 
  pretty 
  big 
  accomplishment,” 
  said 
  Sen. 
  Greg 
  
Gregory, 
  a 
  Lancaster 
  Republican 
  who 
  has 
  pushed 
  to 
  make 
  solar 
  easier 
  for 
  people 
  to 
  use 
  and 
  afford. 
  
In 
  South 
  Carolina, 
  a 
  groundswell 
  of 
  support 
  for 
  solar 
  has 
  helped 
  make 
  the 
  use 
  of 
  sun 
  power 
  more 
  
attractive, 
  observers 
  said 
  Wednesday. 
  Utilities, 
  such 
  as 
  SCE&G 
  and 
  Santee 
  Cooper, 
  have 
  even 
  begun 
  to 
  
develop 
  solar 
  farms. 
  
If 
  the 
  bill 
  goes 
  through, 
  Davis 
  predicted 
  it 
  could 
  increase 
  South 
  Carolina’s 
  use 
  of 
  solar 
  sharply. 
  The 
  state 
  
now 
  has 
  about 
  7 
  megawatts 
  of 
  installed 
  solar 
  capacity, 
  one 
  of 
  the 
  lowest 
  amounts 
  in 
  the 
  country. 
  
A 
  key 
  part 
  of 
  the 
  compromise 
  focuses 
  on 
  how 
  solar 
  companies 
  would 
  provide 
  the 
  panels 
  to 
  
homeowners 
  at 
  affordable 
  rates. 
  
Instead 
  of 
  allowing 
  the 
  sale 
  of 
  power 
  directly 
  to 
  customers 
  from 
  rooftop 
  solar 
  panels, 
  as 
  proposed 
  in 
  a 
  
bill 
  last 
  year, 
  companies 
  could 
  lease 
  the 
  panels 
  to 
  homeowners 
  or 
  businesses. 
  Utilities 
  opposed 
  direct 
  
sales, 
  worrying 
  that 
  it 
  could 
  set 
  a 
  precedent 
  that 
  would 
  allow 
  unregulated 
  companies 
  to 
  compete 
  
directly 
  with 
  them, 
  observers 
  said. 
  
Davis 
  said 
  the 
  leasing 
  arrangement 
  provides 
  the 
  same 
  benefit 
  to 
  private 
  homeowners 
  and 
  businesses 
  
because 
  leases 
  would 
  make 
  the 
  upfront 
  panel 
  costs 
  more 
  reasonable. 
  But 
  for 
  tax 
  reasons, 
  leasing 
  
essentially 
  shuts 
  out 
  non-­‐profit 
  groups, 
  schools 
  and 
  churches, 
  he 
  and 
  others 
  said. 
  
Part 
  of 
  the 
  compromise 
  is 
  to 
  have 
  utilities 
  develop 
  programs 
  to 
  help 
  non-­‐profits, 
  churches 
  and 
  schools 
  
afford 
  the 
  panels. 
  
“There 
  wasn’t 
  an 
  entity 
  at 
  the 
  table 
  that 
  doesn’t 
  want 
  to 
  help 
  fix 
  this 
  issue,” 
  Frick 
  said. 
  
The 
  legislation, 
  which 
  would 
  amend 
  an 
  existing 
  solar 
  bill 
  that 
  allows 
  third-­‐party 
  sales, 
  is 
  expected 
  to 
  be 
  
voted 
  on 
  as 
  early 
  as 
  next 
  week 
  by 
  the 
  subcommittee. 
  
According 
  to 
  the 
  deal 
  discussed 
  Wednesday, 
  the 
  state 
  would: 
  
• 
  Raise 
  a 
  state 
  limit 
  on 
  the 
  use 
  of 
  solar 
  power, 
  which 
  is 
  now 
  capped 
  at 
  100 
  kilowatts, 
  to 
  1 
  megawatt 
  for 
  
non-­‐residential 
  use. 
  
• 
  Set 
  a 
  statewide 
  limit 
  of 
  2 
  percent 
  for 
  the 
  use 
  of 
  solar 
  power 
  for 
  those 
  involved 
  in 
  net-­‐metering 
  
programs. 
  
• 
  Encourage 
  utilities 
  to 
  increase 
  the 
  use 
  of 
  solar 
  power 
  they 
  use 
  in 
  their 
  mix 
  of 
  energy 
  sources. 
  
54 
  
 
  

 German 
  Energy 
  Push 
  Runs 
  into 
  Problems 
    
  New 
  York 
  Times 
    
  Melissa 
  Eddy 
    
  3/20/2014 
  
http://www.nytimes.com/2014/03/20/business/energy-­‐environment/german-­‐energy-­‐push-­‐runs-­‐into-­‐
problems.html?ref=energy-­‐
environment&_r=1&version=meter+at+6&region=FixedCenter&pgtype=article&priority=true&module=
RegiWall-­‐Regi&action=click 
  
BERLIN 
  — 
  It 
  is 
  Germany’s 
  national 
  goal: 
  to 
  have 
  the 
  bulk 
  of 
  its 
  energy 
  supplied 
  by 
  renewable 
  power 
  
sources 
  by 
  2050, 
  without 
  endangering 
  the 
  country’s 
  powerful 
  industrial 
  sector 
  or 
  an 
  export-­‐based 
  
economy 
  that 
  is 
  the 
  envy 
  of 
  other 
  Europeans. 
  
This 
  energy 
  push, 
  known 
  as 
  the 
  Energiewende, 
  or 
  energy 
  transformation, 
  took 
  on 
  new 
  urgency 
  with 
  the 
  
decision 
  to 
  speed 
  up 
  the 
  phasing 
  out 
  of 
  nuclear 
  power 
  after 
  the 
  2011 
  Fukushima 
  disaster. 
  
But 
  the 
  question 
  of 
  whether 
  Germany 
  can 
  meet 
  its 
  2050 
  goal 
  has 
  been 
  hotly 
  debated. 
  And 
  the 
  issue 
  has 
  
taken 
  on 
  added 
  importance 
  with 
  the 
  Russia-­‐Ukraine 
  crisis 
  threatening 
  Germany’s 
  largest 
  single 
  source 
  of 
  
natural 
  gas. 
  
Chancellor 
  Angela 
  Merkel’s 
  government 
  plans 
  to 
  revamp 
  the 
  energy 
  law 
  to 
  focus 
  on 
  wind 
  turbine 
  parks 
  
and 
  solar 
  energy 
  as 
  the 
  most 
  cost-­‐effective 
  renewable 
  sources, 
  in 
  the 
  hope 
  of 
  reining 
  in 
  runaway 
  
electricity 
  prices. 
  
But 
  international 
  energy 
  experts, 
  who 
  recently 
  completed 
  a 
  study 
  of 
  the 
  German 
  energy 
  sector, 
  say 
  the 
  
country 
  cannot 
  meet 
  its 
  future 
  needs 
  solely 
  through 
  renewable 
  sources. 
  They 
  say 
  the 
  plan 
  must 
  also 
  
include 
  a 
  climate-­‐friendly 
  — 
  even 
  if 
  not 
  renewable 
  — 
  option, 
  like 
  domestic 
  natural 
  gas. 
  
Energy 
  will 
  be 
  on 
  the 
  agenda 
  when 
  European 
  Union 
  leaders 
  convene 
  in 
  Brussels 
  on 
  Thursday, 
  with 
  
member 
  countries’ 
  heavy 
  dependence 
  on 
  Russian 
  gas 
  almost 
  certain 
  to 
  galvanize 
  the 
  discussion. 
  
Leaders 
  are 
  also 
  to 
  discuss 
  recent 
  changes 
  to 
  the 
  bloc’s 
  climate 
  agenda. 
  Germany 
  hopes 
  that 
  a 
  deal 
  can 
  
be 
  reached 
  to 
  end 
  a 
  dispute 
  with 
  the 
  union 
  over 
  Berlin’s 
  exemption 
  of 
  some 
  energy-­‐intensive 
  industries 
  
from 
  the 
  country’s 
  environmental 
  surcharges. 
  
The 
  German 
  daily 
  Frankfurter 
  Allgemeine 
  Zeitung 
  reported 
  this 
  week 
  that 
  a 
  proposal 
  had 
  been 
  floated 
  
that 
  would 
  allow 
  Berlin 
  to 
  grant 
  surcharge 
  reductions 
  for 
  companies 
  in 
  approximately 
  65 
  sectors. 
  
During 
  a 
  visit 
  to 
  Berlin 
  last 
  month, 
  Joaquín 
  Almunia, 
  the 
  European 
  Union’s 
  competition 
  commissioner, 
  
said 
  that 
  aluminum 
  and 
  steel 
  industries 
  would 
  be 
  among 
  those 
  exempted. 
  Experts 
  say 
  they 
  expect 
  the 
  
industrial 
  gas, 
  cement 
  and 
  electronic 
  components 
  sectors 
  also 
  to 
  be 
  included. 
  
About 
  11 
  percent 
  of 
  Germany’s 
  energy 
  is 
  provided 
  by 
  natural 
  gas, 
  of 
  which 
  35 
  percent 
  comes 
  from 
  
Russia. 
  Despite 
  the 
  German 
  government’s 
  assurances 
  that 
  reserves 
  of 
  natural 
  gas 
  held 
  in 
  storage 
  tanks 
  
are 
  sufficient 
  to 
  ensure 
  continued 
  supply, 
  there 
  are 
  fears 
  of 
  shortages 
  should 
  Moscow 
  decide 
  to 
  
retaliate 
  to 
  Western 
  sanctions 
  by 
  reducing 
  the 
  flow 
  of 
  natural 
  gas 
  to 
  the 
  West. 
  
Germany 
  has 
  almost 
  no 
  natural 
  gas 
  of 
  its 
  own 
  — 
  at 
  least 
  not 
  gas 
  that 
  can 
  be 
  extracted 
  through 
  
conventional 
  drilling 
  techniques. 
  

55 
  
 
  

 It 
  does 
  have 
  potentially 
  promising 
  reserves 
  of 
  gas 
  in 
  shale 
  rock. 
  But 
  extraction 
  of 
  that 
  shale 
  gas 
  through 
  
the 
  technique 
  known 
  as 
  hydraulic 
  fracturing, 
  or 
  fracking, 
  does 
  not 
  feature 
  in 
  Germany’s 
  current 
  plans. 
  
Germany, 
  by 
  2030, 
  would 
  be 
  able 
  to 
  produce 
  the 
  equivalent 
  of 
  25 
  percent 
  of 
  the 
  natural 
  gas 
  that 
  it 
  
currently 
  consumes, 
  if 
  it 
  were 
  to 
  tap 
  shale 
  resources 
  within 
  the 
  country, 
  according 
  to 
  the 
  international 
  
study 
  conducted 
  by 
  IHS 
  Energy, 
  a 
  research 
  and 
  consulting 
  firm. 
  That 
  could 
  rise 
  to 
  35 
  percent, 
  equivalent 
  
to 
  what 
  Germany 
  currently 
  imports 
  from 
  Russia, 
  in 
  subsequent 
  years, 
  IHS 
  predicted. 
  
But 
  Berlin’s 
  firm 
  belief 
  remains 
  that 
  only 
  by 
  uncoupling 
  from 
  a 
  dependence 
  on 
  gas 
  and 
  other 
  fossil 
  fuels 
  
through 
  the 
  expansion 
  of 
  power 
  generated 
  by 
  renewable 
  sources 
  can 
  Germany 
  secure 
  its 
  energy 
  future. 
  
“The 
  energy 
  transformation 
  in 
  Germany 
  will 
  be 
  carried 
  out 
  by 
  two 
  main 
  sources 
  — 
  those 
  are 
  wind 
  and 
  
solar,” 
  Rainer 
  Baake, 
  a 
  deputy 
  energy 
  minister, 
  said 
  this 
  week. 
  
The 
  unexpected 
  drop 
  in 
  global 
  energy 
  prices 
  through 
  the 
  emergence 
  of 
  abundant, 
  low-­‐cost 
  natural 
  gas 
  
in 
  the 
  United 
  States 
  has 
  posed 
  a 
  threat 
  to 
  the 
  energy 
  transformation, 
  according 
  to 
  a 
  study 
  by 
  the 
  IHS 
  
research 
  group 
  presented 
  in 
  Berlin 
  this 
  week. 
  
“There 
  has 
  been 
  a 
  kind 
  of 
  waking 
  up 
  to 
  the 
  fact 
  that 
  the 
  premises 
  of 
  the 
  Energiewende, 
  however 
  well-­‐
intentioned 
  they 
  are, 
  no 
  longer 
  hold 
  because 
  the 
  world 
  has 
  changed,” 
  said 
  Daniel 
  Yergin, 
  an 
  energy 
  
industry 
  analyst 
  and 
  historian 
  who 
  helped 
  carry 
  out 
  the 
  study. 
  
The 
  Renewable 
  Energy 
  Act 
  in 
  Germany 
  has 
  been 
  amended 
  several 
  times 
  over 
  the 
  last 
  13 
  years. 
  The 
  
latest 
  changes 
  are 
  to 
  be 
  voted 
  on 
  by 
  Parliament 
  before 
  its 
  summer 
  recess, 
  and 
  crucial 
  points 
  have 
  
already 
  been 
  approved 
  by 
  Ms. 
  Merkel’s 
  government. 
  Revisions 
  to 
  the 
  law 
  concentrate 
  on 
  managing 
  the 
  
expansion 
  of 
  renewable 
  sources 
  by 
  focusing 
  on 
  technologies 
  that 
  have 
  proved 
  to 
  be 
  the 
  most 
  cost-­‐
effective 
  over 
  the 
  last 
  decade. 
  
These 
  changes 
  reflect 
  lessons 
  learned 
  since 
  Germany 
  first 
  decided 
  to 
  phase 
  out 
  its 
  nuclear 
  reactors 
  in 
  
favor 
  of 
  energy 
  generated 
  by 
  renewable 
  resources, 
  which 
  until 
  now 
  have 
  all 
  been 
  promoted 
  equally 
  
through 
  government 
  subsidies. 
  
Berlin’s 
  nearer-­‐term 
  goals 
  have 
  not 
  changed, 
  aiming 
  for 
  40 
  to 
  45 
  percent 
  of 
  all 
  energy 
  to 
  come 
  from 
  
renewable 
  sources 
  by 
  2025, 
  rising 
  to 
  55 
  to 
  60 
  percent 
  by 
  2035. 
  But 
  the 
  mix 
  of 
  technologies 
  has 
  been 
  
revised, 
  with 
  the 
  focus 
  now 
  on 
  large 
  onshore 
  wind 
  parks 
  and 
  solar 
  energy 
  farms. 
  
“With 
  the 
  Renewable 
  Energies 
  Act 
  that 
  we 
  created 
  in 
  2000, 
  we 
  financed 
  a 
  learning 
  curve 
  that 
  was 
  
expensive,” 
  said 
  Mr. 
  Baake, 
  the 
  deputy 
  energy 
  minister, 
  who 
  is 
  considered 
  by 
  some 
  to 
  be 
  the 
  
grandfather 
  of 
  Germany’s 
  energy 
  transition. 
  “But 
  the 
  good 
  news 
  is 
  that 
  we 
  have 
  learned 
  in 
  only 
  13 
  years 
  
to 
  produce 
  electricity 
  with 
  wind 
  power 
  and 
  large 
  solar 
  facilities 
  at 
  the 
  same 
  price 
  as 
  if 
  we 
  were 
  to 
  build 
  
new 
  coal 
  or 
  gas 
  power 
  stations,” 
  he 
  added. 
  
In 
  Britain, 
  the 
  government 
  is 
  also 
  responding 
  to 
  complaints 
  from 
  its 
  businesses 
  and 
  consumers 
  about 
  
the 
  cost 
  of 
  green 
  taxes 
  and 
  other 
  environmental 
  measures. 
  In 
  a 
  parliamentary 
  speech 
  on 
  Wednesday 
  
outlining 
  his 
  budget 
  for 
  2014 
  to 
  2015, 
  the 
  chancellor 
  of 
  the 
  Exchequer, 
  George 
  Osborne, 
  noted 
  that 
  
industrial 
  energy 
  prices 
  in 
  the 
  United 
  States 
  were 
  half 
  those 
  of 
  Britain. 
  “We 
  need 
  to 
  cut 
  our 
  energy 
  
costs,” 
  he 
  said. 
  

56 
  
 
  

 Mr. 
  Osborne 
  said 
  he 
  would 
  take 
  measures 
  to 
  reduce 
  energy 
  bills, 
  which 
  would 
  include 
  capping 
  Britain’s 
  
tax 
  on 
  carbon 
  dioxide 
  at 
  18 
  pounds, 
  or 
  about 
  $30, 
  a 
  ton 
  — 
  although 
  not 
  until 
  after 
  next 
  year’s 
  national 
  
elections. 
  The 
  tax, 
  which 
  is 
  now 
  about 
  £5 
  a 
  ton, 
  would 
  otherwise 
  have 
  increased 
  to 
  about 
  £36 
  a 
  ton 
  by 
  
the 
  end 
  of 
  the 
  decade, 
  analysts 
  say. 
  The 
  freeze 
  would 
  cut 
  a 
  midsize 
  manufacturer’s 
  electric 
  bill 
  by 
  
£50,000 
  a 
  year 
  and 
  a 
  household’s 
  by 
  £15 
  annually, 
  Mr. 
  Osborne 
  said. 
  
Electricity 
  prices 
  in 
  Germany 
  are 
  already 
  among 
  the 
  highest 
  in 
  the 
  world. 
  The 
  price 
  of 
  industrial 
  
electricity 
  has 
  risen 
  about 
  37 
  percent 
  since 
  2005, 
  according 
  to 
  the 
  Federation 
  of 
  German 
  Industries. 
  The 
  
price 
  in 
  the 
  United 
  States 
  has 
  fallen 
  by 
  4 
  percent 
  over 
  about 
  the 
  same 
  time. 
  
The 
  rise 
  in 
  energy 
  prices 
  has 
  already 
  cost 
  Germany 
  $52 
  billion 
  in 
  net 
  exports 
  and 
  could 
  prove 
  even 
  more 
  
damaging 
  if 
  steps 
  are 
  not 
  taken 
  to 
  keep 
  prices 
  in 
  check, 
  according 
  to 
  the 
  IHS 
  study. 
  IHS 
  asserts 
  that 
  
adding 
  domestic 
  shale 
  gas 
  into 
  the 
  mix 
  would 
  keep 
  prices 
  down. 
  
A 
  decision 
  by 
  the 
  European 
  Commission 
  this 
  year 
  made 
  it 
  possible 
  for 
  member 
  countries 
  like 
  Britain 
  and 
  
Poland 
  which 
  are 
  interested 
  in 
  pursuing 
  their 
  shale 
  gas 
  reserves 
  to 
  do 
  so. 
  
The 
  Federal 
  Environmental 
  Agency 
  in 
  Germany 
  is 
  conducting 
  its 
  own 
  study 
  into 
  the 
  impact 
  that 
  tapping 
  
those 
  gas 
  reserves 
  through 
  fracking 
  would 
  have 
  on 
  the 
  environment. 
  The 
  study 
  is 
  to 
  be 
  completed 
  in 
  
May. 
  But 
  political 
  support 
  for 
  the 
  practice 
  all 
  but 
  died 
  last 
  June, 
  when 
  the 
  chancellor’s 
  center-­‐right 
  
government 
  withdrew 
  a 
  bill 
  that 
  would 
  have 
  furthered 
  progress 
  on 
  the 
  use 
  of 
  fracking. 
  Thus 
  far, 
  there 
  
has 
  been 
  no 
  talk 
  in 
  Berlin 
  of 
  seeking 
  to 
  revive 
  that 
  proposal. 
  
Stanley 
  Reed 
  contributed 
  reporting 
  from 
  London. 
  
Correction: 
  March 
  20, 
  2014 
   
  
 
  
An 
  earlier 
  version 
  of 
  this 
  article 
  misspelled 
  the 
  name 
  of 
  the 
  nuclear 
  power 
  plant 
  disaster 
  in 
  2011. 
  It 
  was 
  
Fukushima, 
  not 
  Fukishima. 
  

 
  
 
   
   
   
   
   
   
   
  

57 
  
 
  

 Policy Resolutions

 

 

Resolution 14-02
Sponsors: Southern Minnesota Municipal Power Agency; Sacramento Municipal Utility District;
Minnesota Municipal Utilities Association; Salt River Project
In Support of Distributed Generation Policies that Allow for Local Decision-making and Equitable
Rates Among Customers
1 
  

 
  
The amount of distributed generation (DG), in particular solar, has increased significantly in the last five

2 
  

years. As of 2011, 4 gigawatts (GW) of distributed capacity has been installed in the U.S., and is

3 
  

expected to increase to approximately 9 GW by 2016, and as much as 20 GW by 2020. There are a

4 
  

number of factors driving this exponential growth, including: the significant decrease in the price of solar

5 
  

panels, which has led to a 70 percent drop in solar installation costs since 2008; the concomitant increased

6 
  

consumer demand; the leased financing model reducing upfront costs for consumers; and state, federal,

7 
  

and utility incentives for solar panel installations, as well as state renewable portfolio standards (RPS).

8 
  
9 
  

Distributed solar provides both opportunities and challenges for utilities and their customers. As with all

10 
  

distributed technologies, those benefits and costs are site specific and dependent upon the unique resource

11 
  

needs of each utility. Increased levels of DG may be able to reduce the need for new utility generation

12 
  

assets, providing a source of clean, emissions-free electricity (maturation of battery storage technology

13 
  

could further reduce the need for new generation). It may also be able to reduce peak demand or lessen

14 
  

demand on heavily loaded distribution system feeders. In addition, future solar with advanced inverters

15 
  

may help balance load on distribution systems.

16 
  
17 
  

While DG can provide benefits to electric utilities, it can also pose operational challenges. Distributed

18 
  

solar can increase congestion on distribution system feeder lines. It can also, at higher penetration levels,

19 
  

cause electric grid system imbalance. DG can present safety risks for lineworkers, particularly if a DG

20 
  

unit continues to energize a feeder despite a utility service disruption. In addition, enhanced DG

21 
  

penetration can also place an increased strain on the distribution system due to voltage fluctuations caused

22 
  

by the intermittency of solar systems. Utilities will have to make additional investments in technology,

23 
  

training, and staff time to accommodate these operational challenges.

24 
  
25 
  

There are several methods for compensating distributed generators for the power they provide to utilities.

26 
  

Under a net-metering program, a utility will credit customers with on-site generation for their kilowatt-

27 
  

hour (kWh) sales to the grid, and charge them for periods when electricity consumption from the grid

28 
  

exceeds their generation. Essentially, the utility charges the net difference between consumption and

29 
  

generation. Under most net-metering programs, the customer is both charged and credited at the utility’s

30 
  

full retail rate of electricity, potentially over-compensating distributed generators by crediting them with a

31 
  

value of generation that is higher than the utility’s avoided cost.
1

 32 
  
33 
  

Under a feed-in tariff (FIT) program, the utility and distributed generator enter into a long-term contract

34 
  

under which the utility agrees to purchase excess generation at a per-kWh price, whereby the customer is

35 
  

paid like a non-utility wholesale power producer. Under FITs, rates vary from utility to utility and can be

36 
  

higher or lower than the retail rate. FITs are more common in Europe than the U.S. and have been used

37 
  

there to incent more DG.

38 
  
39 
  

Recently, a new “dual transaction” model has developed for solar DG where the utility continues to

40 
  

supply all the customer energy needs and the customer sells all the output of the solar installation to the

41 
  

utility. The compensation received is determined by a value-of-solar (VOS) payment which is designed

42 
  

to reflect the value to utility supply, as well as the environmental value.

43 
  
44 
  

DG compensation methodologies may include a component intended to capture the societal benefits to be

45 
  

derived from wider implementation of DG. These components should be carefully developed to avoid

46 
  

overestimating the benefits and passing unjustified costs on to consumers.

47 
  
48 
  

DG can pose additional revenue and customer equity challenges for electric utilities. DG customers are

49 
  

typically compensated at times when they produce excess power to the grid and charged when they

50 
  

consume power from the utility. Their electric bills can net to zero, and in some cases, their net balance

51 
  

can go negative, meaning the utility must pay the customer. Since residential electric bills are based

52 
  

primarily on electric consumption, and the associated customer charges rarely reflect the full amount of

53 
  

fixed costs utilities incur to provide retail electric service, utilities could face a revenue shortfall. As a

54 
  

result, other retail customers (not owning DG) may subsidize customers with distributed generation.

55 
  
56 
  

NOW, THEREFORE, BE IT RESOLVED: That the American Public Power Association (APPA)

57 
  

believes DG can play an important role in public power’s renewable energy portfolio; and

58 
  
59 
  

BE IT FURTHER RESOLVED: That APPA believes it is important that all DG customers pay their

60 
  

fair share of the costs of keeping the grid operating safely and reliably, recognizing the benefits provided

61 
  

by those customers; and

62 
  
63 
  

BE IT FURTHER RESOLVED: That APPA believes DG customer compensation policies must to be

64 
  

designed to reflect utility costs and benefits, and to assure that all those who benefit from the grid or

65 
  

provide benefits to the grid are sharing fairly in the cost of building and maintaining it.

2

 Resolution Encouraging State Commissions Policymakers to Continue to Engage in
Collaborative Dialogue Regarding Distributed Generation Policies Regulations

WHEREAS, Distributed generation (DG) may be de?ned as non-centralized sources of
electricity generation generally interconnected to the distribution system and located at or near
customers? homes or businesses. Examples of DG include solar panels, energy storage devices,
fuel cells, microturbines, reciprocating engines, small wind turbines, backup generation, and
combined heat and power (CI-1P) systems; and

WHEREAS, DG can offer economic, reliability, and environmental bene?ts to consumers and
utilities; and

WHEREAS, Many States, recognizing the value of DG in their States, have implemented
policies, taken regulatory actions, and offered tax and other incentives to encourage the
deployment of such DG technologies; and

WHEREAS, One such DG policy, adopted in 43 States, the District of Columbia, and four
United States Territories, is net metering that credits DG customers for the excess electricity
generated and exported to the electric grid; and

WHEREAS, Federal and State policymakers and regulators, consumer advocates, trade
associations, utility representatives, and other stakeholder groups are examining DG deployment
and its related issues; and

WHEREAS, There have been many collaborative efforts involving regulators and various
stakeholders addressing the multitude of regulatory and other issues relating to the potential and
challenges of DO in providing safe, reliable, affordable, cost-effective, and environmentally
sound energy supply; and

WHEREAS, The issues related to DG merit continued discussion among stakeholders to
develop options for further consideration by policymakers and regulators; now, therefore, be it

RESOLVED, That the National Association of Regulatory Utility Commissioners, convened at
its 125th Annual Meeting in Orlando, Florida, encourages State commissions and policymakers
to continue to participate in collaborative discussions regarding DG so that State commissions
(and States) have the bene?t of key stakeholder input and are better prepared to:

0 Evaluate the system-wide bene?ts and costs of DG (including costs and bene?ts relating
to the investment in and operation of generation and the transmission and distribution
grid) so that those costs and bene?ts relating to DO can be appropriately allocated and
made transparent to regulators and consumers;

- Ensure that all necessary consumer protections are maintained and assist consumers as
they consider or invest in DG technologies and services;

- Facilitate the continued provision of safe, reliable, resilient, secure, cost-effective, and
environmentally sound energy services at fair and affordable electric rates as new and
innovative technologies are added to the energy mix; and

- Engage fully and effectively at both the State and federal levels on DG-related policy
considerations.

Sponsored by the Committee on Consumer Affairs, the Committee on Electricity, and the
Committee on Energy Resources the Environment

Recommended by the NAR UC Board of Directors November 19, 2013

Adopted by the NAR UC Committee of the Whole November 20, 2013

ENERGY, TRANSPORTATION, AND ENVIRONMENT

Resolution 

 

URGING EOUITABLE DISTRIBUTION OF ELECTRICITY GRID SYSTEM COSTS
WHEREAS, the US. electric grid delivers a product essential to all Americans;

WHEREAS, electricity runs our economy, and it powers our homes, businesses, industries, and the
smart technologies, and innovations that enhance our quality of life;

WHEREAS, the United States needs a diverse supply of safe and reliable electricity;

WHEREAS, the domestic development of alternative energy sources should be concurrently
beneficial to our country?s environment and to our country?s economy;

WHEREAS, the electric power industry is leading the transformation to make the grid more flexible
and more resilient to meet the growing demands of our digital society;

WHEREAS, the electric power industry directly employs more than 500,000 American workers and
is the nation?s most capital-intensive industry, investing more than $85 billion per year, on average,
in capital expenditures, including investments in transmission and distribution infrastructure;

WHEREAS, more than 40 states, the District of Columbia, and four US. territories now have
established policies to regulate the use of rooftop solar panels and other small-scale, on-site
distributed generation (00) systems;

WHEREAS, it is recognized that when these rooftop solar and other DG systems first came to market
years ago, many states approved a billing plan called net metering to encourage their introduction;

WHEREAS, net?metered customers pull energy from the grid in the absence of sunshine, and must
use the grid to feed energy back into the grid when the solar unit is generating more power than
the house or business needs;

WHEREAS, some states now have net metering policies that credit rooftop solar or other DG
customers for any excess electricity they generate and sell using the grid, and require utilities to buy
this power typically at the full retail rate?despite the availability of lower retail rates through self-
production or through wholesale market providers;

WHEREAS, the full retail rate of electricity often includes the fixed costs of poles, wires, meters,
advanced technologies, and other infrastructure that make the electric grid safe, reliable, and able
to accommodate solar panels and other 06 systems;

WHEREAS, when net-metered customers are credited for the full retail cost of electricity, they
effectively avoid paying the grid costs, and utilities may shift these costs for maintaining the grid to
those customers without rooftop solar or other DG systems through higher utility bills;

WHEREAS, all residential and business consumers who use the electric grid should pay to support
its maintenance and to ensure its reliability;

 

30 RESOLUTION ENVIRONMENT

ENERGY, TRANSPORTATION, AND ENVIRONMENT

Resolution 

 

WHEREAS, shifting costs from those who can afford DG systems to less affluent customers and
others unable to afford or qualify for rooftop solar leases is an unfair financial burden; and

WHEREAS, the use of rooftop solar and other DG systems now has become more widespread, and
many states are reviewing their net metering polices.

THEREFORE BE IT RESOLVED, that the National Black Caucus of State Legislators 
encourages state policymakers to recognize the value that the electric grid delivers to all and to
examine the following:

updating net metering policies in their states so that solar customers and other distributed
generation customers that use the electric grid pay a fair and equitable fee to maintain the grid
and to keep it operating reliably at all times;

whether such a fee should be charged solely to solar customers and other distributed
generation customers and assessed based on their electricity use;

policies for solar rooftop customers that distribute system costs equitany by creating
mechanisms that recover grid costs from DG systems, enhance cost transparency, and
determine if non-solar customers do, in fact, benefit sufficiently from the policy change; and

ensuring electric rates are fair and affordable for all customers and that all customers have safe
and reliable electricity;

BE IT FURTHER RESOLVED, that supports subsidizing the cost of alternative energy build
out throughout the country and encourages legislators on the state and federal level to continue to
encourage the implementation of alternative sources;

BE IT FURTHER RESOLVED, that urges state and federal lawmakers to support programs
that provide funding or utilize alternative financing models to aid low-income households and
communities to become more energy efficient and to use solar panels or other forms of alternative
energy; and

BE IT FINALLY RESOLVED, that a copy of this resolution be transmitted to the President of the
United States, the Vice President of the United States, members of the United States House of
Representatives and the United States Senate, and other federal and state government officials as

appropriate.

 

SPONSOR: Representative Joseph Gibbons (FL)

Committee of Jurisdiction: Energy, Transportation, and Environment Policy Committee
Certified by Committee Chair: Representative Joe Gibbons (FL)

Ratified in Plenary Session: Ratification Date is December 13, 2013

Ratification is certified by: Representative Joe (TN), President

 

ENVIRONMENT I RESOLUTIUNETE-M-SZ 3i

UPDATING NET METERING POLICIES RESOLUTION

WHEREAS, the US. electric grid delivers a product essential to all Americans; and

WHEREAS, electricity runs our powers our homes, businesses, industries, and the
smart technologies and innovations that enhance our quality of life; and

WHEREAS, the United States needs a diverse supply of safe and reliable electricity; and

WHEREAS, the electric power industry is leading the transformation to make the grid more
?exible and more resilient to meet the growing demands of our digital society; and

WHEREAS, the domestic development of alternative energy sources should be concurrently
bene?cial to our country?s environment and to our country?s economy; and

WHEREAS, the electric power industry directly employs more than 500,000 American workers
and is the nation?s most capital-intensive industry, investing more than $85 billion per year, on
average, in capital expenditures, including investments in transmission and distribution
infrastructure; and

WHEREAS, there is growing interest in rooftop solar panels and other small-scale, on?site
distributed generation (DG) systems; and

WHEREAS, it is recognized that when these rooftop solar and other DG systems ?rst came to
market years ago, many states approved a billing plan called net metering to encourage their
introduction; and

WHEREAS, some states now have net metering policies that credit rooftop solar or other DG
customers for any excess electricity that they generate and sell using the grid and require utilities
to buy this power; and

WHEREAS, the utilities are typically required to buy the excess electricity at the full retail rate
despite the availability of lower rates through self-production or through wholesale market
providers; and

WHEREAS, the full retail rate of electricity often includes the ?xed 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; and

WHEREAS, when net-metered customers are credited for the full retail cost of electricity, they
effectively avoid paying the grid costs, and these ?xed costs for maintaining the grid then are
shifted to those customers without rooftop solar or other DG systems through higher utility bills;
and

WHEREAS, net-metered customers pull energy from the grid in the absence of sunshine, and
must use the grid to feed energy back into the grid when the solar unit is generating more power
than the customer needs; and

WHEREAS, all consumers who use the electric grid should pay to support its maintenance and
to ensure its reliability; and

WHEREAS, net metering policies allow customers with rooftop solar or other DG systems to
unfairly pro?t from exporting excess energy back to the grid while penalizing customers with
basic energy needs who cannot afford rooftop solar or other DG systems; and

WHEREAS, African American households experience disproportionate levels of poverty,
exceeding the national average, and have lower household income than their non-African
American counterparts; and

WHEREAS, a lack of electric power affordability diSproportionally impacts economically
disadvantaged sectors and threatens the long term ?nancial stability of our country; and

WHEREAS, shifting costs from those who can afford DG systems to low-income customers and
others unable to afford or qualify for rooftop solar leases is an unfair ?nancial burden; and

WHEREAS, energy regulation, including net metering policies, should protect vulnerable
populations from drastic price increases or cost-shifting caused by energy production conversion
from conventional to renewable sources; and

WHEREAS, the use of rooftop solar and other DG systems now has become more widespread,
and many states are reviewing their net metering polices; and

THEREFORE BE IT RESOLVED, that the National Policy Alliance, which includes the
leadership of Blacks in Government, National Association of Black County Of?cials, The
National Bar, National Black Caucus of Local Elected Of?cials, National Black Caucus of
School Board Members, National Black Caucus of State Legislators, National Conference of
Black Mayors and the World Conference of Mayors encourages state policymakers and
regulators to recognize the value the electric grid delivers to all and to:

1. Update net metering policies to require that everyone who uses the grid helps pay to
maintain it and to keep it operating reliably at all times; and

2. Create a ?xed grid charge or other rate mechanisms that recover grid costs from DG
systems to ensure that costs are transparent to the customer; and

3. Ensure electric rates are fair and affordable for all customers and that all customers have
safe and reliable electricity.

BE IT FINALLY RESOLVED, that a copy of this resolution be transmitted to the President of
the United States, the Vice President of the United States, members of the United States House
of Representatives and the United States Senate, other federal of?cials, and Governors and other
state government of?cials as appropriate.

OUTHERN Sign?
- 6?


norm? Adopted on October 14, 2013
Sponsored by: Senator John Watkins of Virginia
Senator Cam Ward of Alabama

6.2013 Updating Net Metering Policies Resolution
WHEREAS, the US. electric grid delivers a product essential to all Americans; and

WHEREAS, electricity runs our economy?it powers our homes, businesses, industries, and the
smart technologies and innovations that enhance our quality of life; and

WHEREAS, the United States needs a diverse supply of safe and reliable electricity; and

WHEREAS, the electric power industry is leading the transformation to make the grid more
?exible and more resilient to meet the growing demands of our digital society; and

WHEREAS, the electric power industry directly employs more than 500,000 American workers
and is the nation?s most capital-intensive industry, investing more than $85 billion per year, on
average, in capital expenditures, including investments in transmission and distribution
infrastructure; and

WHEREAS, there is growing interest in rooftop solar panels and other small-scale, on-site
distributed generation (DG) systems; and

WHEREAS, it is recognized that when these rooftop solar and other DG systems ?rst came to
market years ago, many states approved a billing plan called net metering to encourage their
introduction; and

WHEREAS, some states now have net metering policies that credit rooftop solar or other DG
customers for any excess electricity that they generate and sell using the grid and require utilities
to buy this power at the full retail rate; and

WHEREAS, the full retail rate of electricity often includes 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; and

WHEREAS, when net-metered customers are credited for the full retail cost of electricity, they
effectively avoid paying the grid costs, and these costs for maintaining the grid then are shifted
to those customers without rooftop solar or other DG systems through higher utility bills; and

WHEREAS, the use of rooftop solar and other DG systems now has become more widespread,
and many states are reviewing their net metering polices; and

THEREFORE, BE IT RESOLVED that the Southern States Energy Board encourages state
policymakers to recognize the value the electric grid delivers to all and to:

1. Update net metering policies to require that everyone who uses the grid helps pay to
maintain it and to keep it operating reliably at all times;

 

*euenm 30m? Adopted on October 14, 2013

Sponsored by: Senator John Watkins of Virginia
Senator Cam Ward of Alabama

2. Create a ?xed grid charge or other rate mechanisms that recover grid costs from DG
systems to ensure that costs are tranSparent to the customer; and

3. Ensure electric rates are fair and affordable for all customers and that all customers have
safe and reliable electricity.

Resources

 

 

EEI 
  Member 
  Company 
  
Distributed 
  Generation 
  and 
  Net 
  Metering 
  
Resources 
  

 
  
Online 
  Toolkit 
  

Be 
  sure 
  to 
  access 
  the 
  EEI 
  online 
  toolkit 
  that 
  includes 
  links 
  to 
  studies 
  and 
  analysis, 
  EEI 
  
messaging 
  and 
  outreach 
  materials, 
  and 
  background 
  on 
  the 
  experts 
  available 
  to 
  help 
  
advocate 
  and 
  engage 
  on 
  issues 
  within 
  your 
  states. 
  
 
  
http://www.eei.org/issuesandpolicy/generation/DGResources/Pages/default.aspx 
  
 
  (EEI 
  member 
  log-­‐in 
  and 
  password 
  required.) 
  
 
  
 
  

Internet 
  Workroom 
  

To 
  join 
  EEI’s 
  Distributed 
  Generation 
  Internet 
  Workroom, 
  send 
  an 
  e-­‐mail 
  to 
  
jvignoe@eei.org 
  with 
  your 
  name 
  and 
  the 
  name 
  of 
  your 
  company. 
  
 
  
 
  

Animations 
  

View 
  EEI-­‐produced 
  animations 
  on 
  net 
  metering. 
  
 
  
Net 
  Metering 
  Animation 
  -­‐ 
  Whiteboard 
  (3 
  minutes) 
  
Net 
  Metering 
  Animation 
  -­‐ 
  Whiteboard 
  (30 
  seconds) 
  
Net 
  Metering 
  Animation 
  

 To:

Federal, State and Local Policymakers

Re:

Updating Net Metering Policies

The U.S. electric grid delivers a product essential to all Americans. Indeed, electricity runs our
economy—it powers our homes, businesses, industries, and enables the smart technologies and
innovations that enhance our quality of life.
Today, the electric power industry is leading the transformation to make the grid more flexible
and more resilient to meet the growing demands of customers in this digital society. In fact, the
electric power industry is the nation’s most capital-intensive industry, investing more than $90
billion per year, on average, in capital expenditures, including investments in transmission and
distribution infrastructure. The industry also directly employs more than 500,000 workers.
As a broad group of organizations that represent American businesses, consumers, organized
labor, energy producers, and our nation’s industrial base, we recognize the critical importance of
these investments and of maintaining and enhancing the electric power grid. We also believe it is
vital for our nation to have a diverse supply of safe and reliable electricity and that electric rates
should be fair and affordable for all customers.
There is growing interest in the use of distributed generation (DG), such as customer-owned
wind, solar photovoltaic (PV) panels, and combined heat and power systems, to meet our
nation’s electric power needs. If developed properly, DG has the potential to provide consumers
and society with substantial benefits. Hence, electric utilities are pursuing carefully considered,
cost-effective DG technologies to meet the needs of their retail consumers and support their
systems. 
   
   
  
Many states and localities also are reviewing the need for and impact of their net metering policies,
which were approved to encourage the introduction of these systems and technologies when they
first came to market years ago. (Net metering is a billing mechanism that credits DG customers
for the excess electricity they generate and sell to an electric company using the grid.)
As you are probably aware, because of the way that some net metering policies are structured,
customers who use solar PV panels, for example, are credited for the power they sell to electric
utilities, usually at the full retail electricity rate. This rate is far higher than the value of the electric
energy sold to the utility, because it also includes payments for all of 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 PV panels and other distributed generation systems. Through
the retail credit they receive, net-metered customers effectively are avoiding paying these costs for
the grid.
Unlike customers who use the grid only to buy power, customers with DG use the grid both to buy
power during times when their systems are not producing enough to meet their needs and to sell
power when their systems are producing more electricity than is needed. As a result, customers

 without DG—primarily America’s working families and businesses—unfairly absorb the costs of
the grid through higher utility bills.
As you consider net metering in your states and localities, we, the undersigned, urge you to
recognize the value that the electric grid delivers to all of us and to support policy updates that
require everyone who uses the grid to share equitably in the costs of maintaining it and keeping it
operating reliably at all times.
Sincerely,
America’s Natural Gas Alliance
American Association of Blacks in Energy
American Public Power Association
Edison Electric Institute
Energy Equipment and Infrastructure Alliance
Hispanics in Energy
International Brotherhood of Electrical Workers
National Association of Neighborhoods
National Black Chamber of Commerce
National Policy Alliance
National Rural Electric Cooperative Association
Nuclear Energy Institute
U.S. Chamber of Commerce
Utility Workers Union of America

Updated: March 4, 2014

 FOR IMMEDIATE RELEASE

NRDC Contacts: Elizabeth Heyd, 202-289-2424, eheyd@nrdc.org, or Pat Remick, 202-289-2411, premick@nrdc.org
EEI Contacts: Jeff Ostermayer, 202-508-5683, jostermayer@eei.org, or Jon Corley, 202-508-5609, jcorley@eei.org

EEI/NRDC Agreement Supports Policies To Benefit Electricity Consumers
and the Environment
WASHINGTON, DC (February 12, 2014) – The Edison Electric Institute (EEI) and the Natural Resources
Defense Council (NRDC) today announced a joint agreement to advance support for utility policies that
enhance the electric power grid for the benefit of all electricity customers and the environment.
EEI, which represents the nation’s investor-owned electric utilities, and the major environmental
organization will work together to encourage state utility regulators to implement policies that balance the
desire to promote innovation, while at the same time supporting fair and adequate cost recovery for
maintaining the evolving grid.
The agreement urges state utility regulators to adopt a number of policies that range from employing new
rate designs to ensure utilities remain financially whole when they help customers adopt distributed
generation technologies and use energy more efficiently to assuring customers that costs will not be
shifted unreasonably to them from other customers.
“The electric power industry’s mission is to provide safe, reliable, affordable, and increasingly clean
electricity. Today utilities are partnering with customers, regulators and all stakeholders to transform the
way they generate and deliver electricity. This agreement helps chart a path to success,” said EEI
Executive Vice President David Owens.
Ralph Cavanagh, co-director of NRDC’s energy program, added, “This path-breaking agreement steers us
toward new and innovative ways to increase and speed the deployment of clean energy resources. NRDC
has long advocated for the increased integration of energy efficiency and renewable energy into the
nation’s electric grid.”
Owens and Cavanagh announced the agreement during a joint presentation to the National Association of
Regulatory Utility Commissioners, which is meeting this week in Washington. NARUC’s chief objective
is to serve the consumer interest by seeking to improve the quality and effectiveness of public regulation
in America.
The joint statement is posted at: http://docs.nrdc.org/energy/files/ene_14021101a.pdf
The Edison Electric Institute (EEI) is the association that represents all U.S. investor-owned electric companies. Our members provide electricity for 220
million Americans, operate in all 50 states and the District of Columbia, and directly employ more than 500,000 workers. Visit us at www.eei.org and follow
us on Twitter @edison_electric.
The Natural Resources Defense Council (NRDC) is an international nonprofit environmental organization with more than 1.4 million members and online
activists. Since 1970, our lawyers, scientists, and other environmental specialists have worked to protect the world's natural resources, public health, and the
environment. NRDC has offices in New York City, Washington, D.C., Los Angeles, San Francisco, Chicago, Bozeman, MT, and Beijing. Visit us at
www.nrdc.org and follow us on Twitter @NRDC.

 


Edison Electric

Institute 

PQWBI tyAssmafmn Dunn's 3651 Dunn

 

EEIINRDC JOINT STATEMENT TO STATE UTILITY REGULATORS

February 12. 2014

Introduction

The future of America?s vital electricity sector will continue to be a promising one as long as
regulatory policies are fair and forward looking. As we move into a new age of innovation, the
use of the grid is evolving, facilitating power ?ows in two directions, so that customers can
engage in both purchases and sales of energy, and provide other services such as balancing,
voltage support, and voluntary load management. Innovation is providing new incentives for
customers to use the grid more effectively and ef?ciently, optimizing the use of existing
infrastructure.

Anticipating as much, we launched a joint campaign in 2008 to accelerate energy ef?ciency
gains and encourage utilities to undertake a host of other cost-effective and clean energy
resources and grid enhancements. Together, these changes have done much to promote clean
energy and ef?cient electricity usage, but they also have highlighted the vital need for regulatory
policies that will support fair and adequate cost recovery for maintaining the evolving grid.

Recovering the ?xed costs of the grid is becoming more challenging. While customers are
discovering new opportunities that enhance the value that the grid brings to them, policy makers
should rethink how utility costs are recovered, with consideration needed for new rate designs
and new approaches that balance the desire to promote innovation while still enabling recovery
of the capital investment that recognizes the value of the grid to all customers and their new uses
of the grid. Traditional rate regulation can at times incentivize utility retail sales growth; in turn,
utilities sometimes leverage that growth between rate cases to meet system-wide needs for cost
recovery and capital investment.

Utility customers value electricity for the comforts, conveniences, and productivity it enables
such as lighting, cooling, and mechanical drive provided reliably and just-in-time. In 2008, we
outlined measures that would keep utilities whole for recovery of authorized non-fuel costs as
electricity sales volumes ?uctuated. We reaf?rm that goal.

If properly done, utilities can adapt to the changing needs of customers, modern electricity
systems, and technologies, while continuing to deliver safe and reliable service, maintain
?nancial integrity by allocating costs of service fairly among customers, and continuously
improve environmental performance. But utility regulatory and business model changes are
necessary to accelerate progress and ensure transparent and equitable attainment of these
objectives.

 JOINT STATEMENT TO STATE UTILITY REGULATORS

The recommendations listed below re?ect our strong belief in the promise of new technologies
for enhancing grid performance while lowering emissions communications infrastructure,
smart grid technologies, distributed generation, demand response, and upgraded controls). This
innovation surge is viewed as having potential for grid improvement (including reliability and
cost?effectiveness), and increased value of connectivity. Innovation does not threaten the grid;
collectively, technology advances are making the nation?s transmission and distribution systems
more important than ever as drivers of economic and environmental progress.

Kev recommendations:

1.

The retail electricity distribution business should not be viewed or regulated as if it were a
commodity business dependent on. growth in electricity use to keep its owners ?nancially
whole. Instead, utility businesses should focus on meeting customers? energy service needs.
Therefore, recovery of utilities? non?fuel costs should reflect their costs of maintaining and
improving the electricity grid, and should not be tied to levels of retail commodity sales.

Traditional rate regulation allows non-fuel revenues to grow between rate cases in proportion
to growth in commodity sales, which averaged more than twice the rate of population growth
between 1973 and 2000 before slowing signi?cantly. If regulators break the linkage between
cost recovery and commodity sales, they should provide for reasonable and predictable
annual adjustments in utilities? authorized non-fuel revenue requirements.

?Net metering? programs in wide use across the United States have helped valuable
?distributed? technologies such as rooftop solar power gain traction and improve
performance, but additional approaches are needed now. Although such generation can
reduce a grid?s needs for central station generation and other infrastructure, it typically does
not eliminate its owners? needs for grid services. For example, solar generation at a residence
typically does not align perfectly with the occupants? energy use, requiring some use of the
grid as the equivalent of a battery.

When they use distribution and transmission systems to import and export electricity, owners
and operators of on-site distributed generation must provide reasonable cost-based
compensation for the utility services they use, while also being compensated fairly for the
services they provide. Customers deserve the opportunity to interconnect distributed
generation to the grid quickly and easily.

Utilities deserve assurances that recovery of their authorized non-fuel costs will not vary with
?uctuations in electricity use. Customers deserve assurances that costs will not be shifted
unreasonably to them from other customers. Rate designs will continue to develop that
reward customers for using electricity more ef?ciently. Examples include, but are not limited
to, real-time pricing and variable demand charges that take advantage of digital meter
capabilities where available.

It is appropriate to consider expanding investor?owned utilities? earnings opportunities to
include performance based incentives tied to bene?ts delivered to their customers by cost?
effective initiatives to improve energy ef?ciency, integrate clean energy generation, and
improve grids. In general, business models should include pro?t opportunities linked to
utilities? performance in delivering safe, reliable, affordable, and clean energy services.

EEIINRDC JOINT STATEMENT TO STATE REGULATORS

6. We will work together to ensure that energy ef?ciency services reach undersewed
populations, including the increased deployment of utility programs focused on affordable
multi?family housing.

7. We reaf?rm our goal of ?helping electricity users take advantage of all cost-effective energy
ef?ciency opportunities through an integrated combination of ?nancial incentives to
customers and minimum standards governing the performance of buildings and equipment,?
and we rededicate ourselves to the five key elements of that campaign.

8. We also reaf?rm our call to state regulators, when presented with a reasonable business case
by utilities, to ?support signi?cantly enhanced utility investment in ?smart meters? and a
?smart grid? that focuses on delivering new energy management tools to customers, enabling
increased energy efficiency, supporting ef?cient new technology such as plug?in electric
vehicles, and rcducin the cost of integrating renewable energy generation with variable
output into resource portfolios.?



Out of

B alance

The law of unintended consequences is already affecting
power markets in Europe and offers valuable lessons for
power markets in the rest of the world.
BY JEFFREY ALTMAN

O

VER THE LAST DECADE, VARIOUS WELL-MEANING GOVERNMENTS AND
REGULATORS ACROSS EUROPE HAVE CREATED SHORT-SIGHTED RENEWABLE
ENERGY POLICIES WITHOUT FULLY ASSESSING THE IMPLICATIONS OF THEIR
ACTIONS. These policies, in turn, came as a response to previous policies

that slowly revealed themselves to be unsustainable. As a result, the effects of
these policies are exerting pressure on consumers, the environment, and power
companies alike.
Germany has been one of the most aggressive supporters of renewable
power in the world and accordingly provides an appropriate case study of the law
of unintended consequences.

JANUARY   FEBRUARY 2014  29

 Peter Schaffrath/E.ON

Rising Electricity Bills
By 2050, Germany is gearing up to
reduce carbon dioxide (co2) emissions
by 90 percent from 1990 levels and to
provide 80 percent of its electricity
generation with renewables. In addition, the government wants to phase
out nuclear power by 2022.
A recent front cover of Der Spiegel
magazine, entitled: “Luxury electricity: Why energy is becoming more expensive and what politicians must do
about it,” showed gold-plated and diamond-encrusted power cables that
succinctly summarized the mood of
the German public toward high energy prices. Since the feed-in tariff
(fit) program supporting renewables
started in the early 2000s, electricity
prices have more than doubled, going
from 18 cents per kilowatt-hour in
2000 to more than 37 cents in 2013. By
comparison, the average electricity
price in the United States is 10 cents
per kilowatt-hour. The cold reality is
that unless the current system is corrected, electricity prices are expected
Jeffrey Altman is a senior advisor at Finadvice GmbH in
Frankfurt, Germany.

Der Spiegel

30 

ELECTRIC PERSPECTIVES    

Magazine

www.eei.org/EP

to increase in Germany by 35 percent
for consumers and
some 30 percent for
industrials by 2020.
The consequences to
Germany as a competitive exporter, as
well as to its overall
economy, could be
significant. Germany’s national strategic
energy plan (known
as “Energiewende”
or energy change),
which is currently
in development and
calls for the buildout of and additional
subsidies for renewables, is now being
challenged by power
companies, industry,
consumers, and even
some governmental
officials.
Part of the explanation for the
increase in electricity prices lies in
the generous government support
for renewable energy technologies.
For the most part, renewables still
are not at grid parity based on ultimate true costs and their adoption
requires subsidies and other financial and non-financial incentives. The
fit subsidy program already has cost
more than $468 billion and some estimate that program costs could exceed

$1.3 trillion by the time it expires.
German consumers and companies
finance clean-energy subsidies by
paying a surcharge on their monthly
power bills. The levy jumped 18 percent on January 1, 2014, and has
surged more than fivefold since 2009,
according to a recent Bloomberg
report. In October 2012, according to
www.stromvergleich.de, this surcharge amounted to 14.6 percent of
the electricity price paid by consumers.

Since the feed-in tariff program supporting
renewables started in the early 2000s,
electricity prices have more than doubled,
going from 18 cents per kilowatt-hour in
2000 to more than 37 cents in 2013. By
comparison, the average electricity price in the
United States is 10 cents per kilowatt-hour.

 Decreasing Wholesale Prices and
Thermal Generators
Due to massively subsidized renewable energy through fits in Germany
and other European countries, producers of other sources of electricity have seen the prices paid to them
fall as renewables, with much lower
short-term marginal production costs
than traditional thermal plants, get
dispatched first.
Depending on the region, the
growth in renewables is creating
load and margin destruction to conventional power plants. As more
renewable energy is used to meet
electricity demand, there is less need
for the electricity produced by conventional sources. In addition to this
loss of revenue due to reduced production, there also is a reduction of
the wholesale price per unit paid to
conventional generators since least-

cost, subsidized renewable resources
displace more costly sources of generation. In Germany, last year’s estimated market price for power was
48 euros per megawatt (mw). In midNovember 2013, the market price for
power stood at 37 euros per mw—a
reduction of 23 percent.
A close examination of daily solar and wind production in Germany
shows the unsurprising seasonality of
both wind and solar. Moreover, it illustrates that the wind blows only for
a couple of minutes on many occasions and that solar has a tremendous
amount of variability, including that
it is not available during nighttime
hours. Therefore, thermal generators
are still producing a majority of the
load in Germany. (See Figure 1.) In
essence, these thermal plants have
now moved from baseload plants
to back-up plants. Having thermal

plants as spinning reserves is nothing
unusual to the power industry. What
is unusual, however, is having up to
40–55 gigawatts of thermal plants as
back-up generation, and just as important, the amount of times these
plants must intervene in power
markets by producing electricity to
quickly make up for the lack of output generated by variable renewable
resources.
Unfortunately, the magnitude of
these interventions is growing and
most thermal plants were not built
to produce such intermittent power.
(See Figure 2.) Moreover, these

FIGURE 1

MONTHLY
PRODUCTION OF SOLAR, WIND, AND CONVENTIONAL ENERGY (2012)
50
(Terawatt-hours (TWh))

Conventional>100 MW

Wind

Solar

40

30

20

10

0

Jan.

Feb.

March

April

May

June

July

Aug.

Sept.

Oct.

Nov.

Dec.

Source: Fraunhofer ISE, EEX Transparency Platform

JANUARY   FEBRUARY 2014  31

 FIGURE 2

INTERVENTIONS TO STABILIZE THE GRID IN GERMANY BY GRID OPERATOR TENNET, 2003-2012

1,400

1213

1,200
1,000
800
600
400
200
0

2
2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Source: Tennet

FIGURE 3

DEVELOPMENT OF RATINGS OF MAJOR EUROPEAN UTILITIES SINCE 2010

Clear downward trend in
ratings for utilities across
Europe.

Positive
AA- / Aa3
Negative

l

Profitability and investability
at stake.

Positive
A+ / A1

l

Negative

l

Positive
A / A2

l

Negative

l

l

l

Positive
A- / A3

l

l

l

Negative

l

l

Positive
BBB+ / Baa1

l

l

Negative

l

l

Positive
BBB / Baa2

l

Negative

l
EDF

STANDARD &
POOR’S

ELECTRIC PERSPECTIVES    

E.ON

EnBW

rating as per Jan. 1, 2010
l rating as per May 2013
MOODY’S
l standalone rating as per June 4, 2013
(If applicable and different from corporate rating)

Source: E.ON

32 

GSZ

www.eei.org/EP

RWE

Enel

rating as per Jan. 1, 2010
l rating as per May 2013
l standalone rating as per June 4, 2013
(If applicable and different from corporate rating)

Iberdrola

 Depending on the
region, the growth
in renewables is
creating load and
margin destruction to
conventional power
plants. As more
renewable energy
is used to meet
electricity demand,
there is less need
for the electricity
produced by
conventional sources.

interventions are not sufficient to
keep many of these thermal plants
economically viable under the current market regime and, as a result,
many thermal plants are now being
closed. In Germany’s case, these often include the more costly gas-fired
plants.

Growing Carbon Emissions
In fact, perhaps the most unintended
consequence of over-subsidizing renewable energy in Europe has been
an increase in co2 emissions. In Germany, natural gas prices hovered
around $10.00 per million British
thermal units last summer, and coal
delivered to power plants fell to a record low last fall. In these conditions,
many of the highly efficient gas-fired
power plants are being put off-line in
favor of coal since the price of gas in
Europe is so high.
In 2013, Bloomberg determined
that German power plants burning
coal can earn 12 cents per megawatt-hour while German power
plants burning natural gas lose 25
cents per megawatt-hour. This discrepancy clearly explains why coal is
replacing natural gas. In November,
for example, Germany opened its first

coal-fired power plant in eight years
and more will be coming online in the
future, which will grow the coal fleet
by 33 percent. As a result, co2 emissions are going up. In 2013, German
energy-related co 2 emissions were
estimated to increase for the second
straight year, by about 20 million tons.

Increased Distribution Investments
and Capital Costs
It is not only the power plants that
are being stressed but also the

electric grids of the European continent. With the ever-increasing need
to call on system resources to balance the system, investment in smart
grid technology will become a further
necessity in order to balance the system from the variability of renewable
power.
Moreover, grids will need to be
refurbished to handle additional
loads as well as built out to go
to those locations where renewable resources are more prevalent.

JANUARY   FEBRUARY 2014  33

 Siemens

Germany, for example, is
going through a massive
build-out of its grids to facilitate new onshore and offshore
wind farms as well as solar
farms. It is estimated that this
investment will range from 21–
27 billion euros over the next
decade.

Balancing the Market and the Grid
Replacing costly resources with
less costly ones is exactly what
competitive and well-functioning markets are supposed to do.
However, as Germany’s situation proves, government
policies of large renewable
subsidies without giving
consideration to the
balancing of the whole
system have created
disequilibrium in
the power markets
and higher power
prices.
Current renewable
and storage technologies are not economically or technically
capable of replacing all
load from conventional
power producers. Since re-

34 

ELECTRIC PERSPECTIVES    

www.eei.org/EP

newable energy is variable in nature,
conventional power plants need to be
able to remain in the market so they
can be called upon when the wind is
not blowing or the sun is not shining.
A large reduction in wholesale electricity prices, brought about by unsustainably high subsidies, runs the
risk of driving these needed generators out of the market. Without this
backup load from thermal generators, issues of reliability of supply occur, including the potential for major
power outages.
In Germany, there are already calls
to modify the existing market rules
and provide capacity payments to existing conventional generators to ensure that many of these plants avoid
closure. From a regulatory perspective, this is essentially a call for the reregulation of thermal plants that were
deregulated back in the late 1990s.

Economic Impact to Utilities
The impact to European utilities is
materially significant. The European
Stoxx Utilities Index is down some
31 percent since 2010, and e.on, one
of Germany’s largest utilities, has
seen its stock plunge some 45 percent since 2010 (although it was also
impacted by the nuclear decommis-

sioning). The impact to credit ratings
of these institutions has also been
significant, which helps explain why
the cost of capital is going up for the
major utilities. (See Figure 3.)

The Coming Wave of Regulation
All of the factors mentioned previously, as exemplified by what has
occurred in Germany, have made
various European governments review their policies toward renewables
over the last couple of years. Some
governments have instituted retroactive taxes or changes in existing
regulatory policies where they had
inappropriately structured various
tariff regimes that had been gamed
by various market players or made
obsolete by unforeseen technical or
market conditions. Spain, for example, went through five regulatory interventions over the last several years
that impacted more than 6 billion euros of investors’ equity and debt.
A new wave of regulation that will
be driven by the incumbent utilities,
as well as the governmental authorities, is likely to be coming shortly.
Utilities would ask for a fair and level
playing field, whereby renewable energy producers would share in the
costs of the whole system, including

 Distributed Generation in
the United States
BY LOLA INFANTE

A

grid enhancements. (See the sidebar,
“Distributed Generation in the United
States.”) Currently, there are ongoing policy discussions with respect
to major changes to various national
power markets, including reregulating deregulated gas-fired power
plants through new subsidy schemes
via capacity payments. These actions
and current discussions have significantly increased uncertainty not only
for utilities but for all power market
players. Accordingly, Fitch Ratings
has recently announced that it places
European renewable energy project
finance transactions as having the
highest risk of ratings downgrades
within the energy sector over the next
12 months.
In conclusion, given recent developments in Europe, it can be reasonably expected that within the next
decade, renewable capacity will be

added based only on its cost competitiveness and ability to maintain
equilibrium to the entire system. European governments have finally realized that they can no longer afford
to massively subsidize uneconomic
renewable power and introduce further instability to the entire electric
system. These governments are just
now developing the appropriate regulatory frameworks that will allow
these new technologies to generate
clean and inexpensive electricity—
but also provide funding for their fair
share of the required grid enhancements and back-up generation costs.
As the advancement of capabilities
and economies of scale increase in
renewable and storage technologies,
we will likely see more of these systems coming online and becoming a
greater part of the total power portfolio. EP

cross the United States, there is
growing interest in using rooftop
solar panels and other small-scale,
on-site power sources known as distributed generation (dg). To encourage the
introduction of these systems when they
first came to market years ago, many
states approved a billing system called net
metering.
While net metering policies vary by
state, generally customers with rooftop
solar or other dg systems are credited
for any electricity they sell via the electric power  grid. Electric companies are
required to buy this power typically at the
full retail rate,  which includes all of  the
fixed costs of the poles, wires, meters,
advanced technologies, and other infrastructure that make the grid safe, reliable,
and able to accommodate solar panels
or other dg systems.  Through the credit
they receive, net metered customers
effectively are avoiding paying these costs
for the grid. As a result, these costs are
shifted to those customers without rooftop
solar or other dg systems through higher
utility bills.
Net metering policies and rate structures in many states should be updated
so that everyone who uses the electric
grid helps pay to maintain it and to keep
it operating reliably at all times. This will
ensure that all customers have safe and
reliable electricity and that electric rates
are fair and affordable for all customers.
Please visit the Edison Electric
Institute’s website at www.eei.org/
DistributedGeneration for additional information. The resources outline the industry’s support for solar power, as well as
our concerns with current net metering
policies. EP
Lola Infante is director of generation fuels and market analysis
for the Edison Electric Institute.

JANUARY   FEBRUARY 2014  35

  

 

 

Ashley Brown is Executive Director of
the Harvard Electricity Policy Group
(HEPG), a program of the Mossavar~

Rahmani Center for Business and
Government at Harvard University's Iohn
P. Kennedy School of Government. HEPG

provides a forum for the discussion and
analysis of electricity issues in the United
States.

Mr. Brown is of counsel to the law firm of
Greenberg Traurig. He has also served as
an advisor on infrastructure regulatory
issues to governments such as Brazil,

Tanzania, India, Ukraine, Russia,
Philippines, Zambia, Namibia, Argentina,

Costa Rica and Hungary.
From 1983?1993, he served as
Commissioner of the Public Utilities

Commission of Ohio, appointed twice by

Governor Richard P. Celeste. Prior to his

appointment, he was the coordinator and

counsel for the Montgomery County [Ohio]

Pair HouSing Center, managing attorney

for the Legal Aid Society of Dayton, Inc,
and legal advisor to the Miami Valley

Regional Planning Commission, also in

Dayton.

Mr. Brown has specialized in litigation in
federal and state courts and before
administrative bodies. He has taught in
public schools. and universities, frequently
lectures at universities and conferences
throughout the world, and publishes
articles on subjects of interest to American
and foreign electricity sectors.

Louisa Land is Program Director for the
Consortium for Energy Policy Research at
the Mossavar-Rahmani Center for
Business and Government at Harvard
University?s John P. Kennedy School of
Government. Previously, she held positions
with the Los Angeles city government

as an analyst for the City Council and as
deputy to the City Controller. She received
her doctorate in political science from
Harvard in 1999.

 

 

Distributed Generation: How
Green? How Ef?cient? How
Well-Priced?

A close look at the details of state and local programs in
support of distributed generation raises some questions
about the whether the promotion of green DG actually
advances environmental objectives, especially when it
takes place in a context of ?net metering? and flat
residential electricity rates. It is time to reassess where we
are going and to calibrate our pricing and policies to make
certain that our efforts are carrying us in the right

direction.

Ashley Brown and Louisa Lund

 

A backwards-spinning
electricity meter driven by a
rooftop solar panel is a power-
fully appealing image for a public
increasingly attuned to
environmental, reliability, energy
ef?ciency, and self-suf?ciency 
considerations. Thus, the promo-
tion of ?distributed generation"
(DC) has substantial public
appeal. Not surprisingly, there-
fore, throughout the country,
various mechanisms such as

 

mandated access, subsidies, net
metering programs, solar and
other renewable energy credits,
feed-in tariffs, and distributed
generation requirements
embedded within renewable
portfolio standards are all being
deployed to promote and support
DC. DC is generally de?ned as
smaller-scale generation intended
primarily for self-consumption at 
the premises of end users,

who are connected directly to the

 

 

23 front matter 2013 Elsevier Inc. All rights reserved, The Electricity journal
Used with permission. Further redistribution prohibited.

 

 

 

 

 

distribution system for the sale of
any excess energy that is pro~
duced. In practice, solar power,
particularly rooftOp installations,
is the predominant form of energy
being promoted through DG
programs, although the
policies are not necessarily
limited to it. Utilities in many
areas are struggling to keep
up with the demand for new
interconnections stimulated by
these programs.
I theory, distributed genera-
tion has the potential for mul-

tiple bene?ts, including reduced
congestion on transmission lines,
increased reliability, and possible
reductions in energy losses
through the transmission and
distribution system. Above all, it is
often assumed (sometimes expli-
citly and sometimes implicitly)
that ?distributed generation"
means renewable, low~carbon
energy. For many programs
nationwide, the wish to promote
green energy is the driving force
behind support for distributed
generation.

hose theoretical green ben-

e?ts, however, are neither
inherent nor certain. There is
some evidence that the antici-
pated bene?ts are offset by pro?
gram costs; potential perverse
incentives created with respect to
energy conservation, energy ef?-
ciency, and technology optimizar
tion; and socially regressive
cost allocations. Given the
importance that green
considerations have in driving
support for distributed genera-
tion, it is to examine
carefully the environmental

 

implications of distributed gen-
eration programs as they are
typically implemented.1 A close
look at the details of state and
local programs in support of dis-
tributed generation raises some
questions about whether the
promotion of green DG actually
advances environmental objec-
tives, especially when it takes
place in a context of ?net
metering? and ?at residential
electricity rates.

 

When the

context for

a distributed
generation program
is an overall
statewide RPS,

the result is a

zero sum game.

I. Is Support for
Distributed Generation
Cost-effective as a Way to
Promote the Use of
Renewable Energy?

To the extent that support for
distributed generation is moti-
vated by environmental concerns,
there is no clear policy basis for
providing more support for green
distributed generation than for
central renewable generation. But
that is exactly what seems to be
happening in many cases. Dis-
tributed generation programs are
often an add-on or carve-out in a
larger framework of a statewide
RPS or other system of support for

 

renewable energy. The very fact
that distributed generation pro?
grams need additional support
within an RPS framework sug-
gests that central generation of
renewables is likely cheaper than 
renewable DG*and further evi-

dence for this can be found in the
fact that many of the programs
intended to support distributed
generation come with pre~set
limits on the amount of genera-
tion to be supported. When a
governmeiit establishes a pro-
gram but sets a limit on how
much it can be used, that consti~
tutes a de facto admission that
policymakers are very uncertain
as to the bene?ts that are to be
gained, so they are ?cutting their
losses? up front. When the con-
text for a distributed generation
program is an overall statewide
RPS, the result is a zero sum game
in which the distributed genera?
tion requirement itself does not
increase the overall share of
renewables in the electricity sys-
temwit merely offsets renewable
requirements that would other?
wise be fulfilled by central
renewables.

II. What Effect do
Incentives for
Distributed Generation
Have on Energy
Conservation and Energy
Ef?ciency? 

This is a complex question, but
one that could yield surprising,
and, from an environmental
perspective, counterproductive

results. Certainly, the same

 

April 2013, Vol. 26, Issue 3 front matter 2013 Elsevier Inc. All rights reserved, 29

 

 

 

 

environmental concerns that
motivate support for promoting
renewable DG would favor con-
servation and end use ef?ciency.
There is, however, a possible
con?ict between pricing incen-

tives intended to promote DC and
rate designs likely to stimulate
more ef?cient use of energy. The

con?ict can be resolved, as we
discuss in the concluding section
of this essay, but only by diluting
some of the incentives for
renewable energy.

The con?ict between  and
energy conservation ef?ciency is
rooted in the fact that any use of
distributed generation will cause
a decline in the revenues being
collected by local distribution
companies. That occurs, of course,
because when self-produced
energy is being consumed, the
customer is paying nothing for
distribution services, other than
?xed charges. In addition, for
excess energy2 derived from DC,
when payment for that energy is
made by net metering, or ?run-
ning the meter backward,? the
outcome for the distributor is
even more severe, since the
practical reality of net metering is
that the DG owner is effectively
being paid the retail price, which
includes not only the energy, but
also the costs of transmission and
distribution as well. While energy
payments are economically justi?
?able, as is economic recognition
of transmission savings,3 it is very
dif?cult to ?nd any reasonable
basis for including distribution
costs in the compensation paid
DG providers, when, in fact, they
provide no such services and,

 

naturally, incur no costs for the
services they don?t provide.
Indeed, DG providers continue to
rely on the distributor for distri?
bution services. Thus, in any
given month, a distributed gen-
eration customer might pay only
the ??xed? portion of their bill?
the part not proportional to
energy use?and be paid them?-
selves for the full retail value of
any electricity they produce in
excess of their usage?including

 

There is, however,

a possible con?ict
between pricing
incentives intended to
promote DC and rate
designs likely to
stimulate more efficient
use of energy.

 

charges associated with trans-
mission and distribution, along
with the wholesale cost of energy.
his ?net energy? approach
creates problems for utili-
ties, because it asks them to
reimburse the customer an
amount greater than the utility's
cost savings. When a house with a
solar panel on it, for example, sells
excess electricity back to the uti-
lity, it is at best allowing the utility
to save money on wholesale
energy costs and perhaps trans~

mission costsmit does nothing to -

reduce the utility? 3 distribution
costs. So if the utility pays the
customer at the full electricity
rate, the utility is guaranteed to

 

lose money on distributed gen-
eration. Not surprisingly, distri?
bution companies will seek to
protect themselves from revenue
erosion and will pass the
responsibility for making up the
delta revenue to the balance of 
their customers. The utilities fear 
that if they raise the charges tied I
to electricity usage, they will cre-
ate a vicious cycle in which more
and more users opt out, and the
whole cost of the distribution
system will need to be borne by an
ever-shrinking customer base.
Given these concerns about
demand elasticity and further
revenue erosion, distributors are
likely to pass those costs through
as ?xed, rather than variable,
costs, in order to best assure their
full recovery. That is precisely
where the potential for serious
con?ict between environmental
objectives and the use of DC to
accomplish them arises. I

he problem here from a

green point of view is not the
inherent subsidy (subject to the
questions about cost~effectiveness
raised above), but the more subtle
question of how this is likely to
play out in terms of its impact on
electricity pricing. As we dis-
cussed above, utilities are likely to
try to solve the ?nancial problems
created by net metering by trying
to put more costs into the ??xed?
portion of the bill that customers
pay even if they use no electricity.
Regulators, perhaps sharing con?
cerns about revenue erosion, but
certainly constrained by the fact
that the losses were caused by
implementing public regulatory
policy regarding the promotion of

 

so front matter 2013 Elsevier Inc. A12 rights reserved, http:/ The Electricity journal

 

 

DC, are highly likely to go along.
The ironic result would be that
less and less of the electricity bill
is tied to actual usage, with the
anti-green result that the rewards
for energy ef?ciency, energy
conservation, and distributed
generation itself become smaller
and smaller as more and more
costs are shifted to the one part of
the bill that everybody has to pay
without regard to the level

of consumption. In short, the
fundamental environmental
principle, ?polluter pays,?
which in electric pricing means
greater emphasis on the part

of the bill that rises with
consumption, will be violated in
the name of promoting

?green energy.? Irony seems

an inadequate word

to describe that fundamental
contradiction.?1

Do Current Rate
Structures Discourage
Customers From
Adopting the Most
Bene?cial Technologies?

Compounding the distortion-
ary impact of net metering is the
use of ?at retail rates for electri?
city. In many localities, rates for
compensating distributed gen-
eration are based on old?fash?
ioned ?dumb? meters that don?t
provide information about when
energy was produced. There is a
big difference, from the utility? 8
point of view, between the value
of energy ?fed in? to the system at
a time of peak demand, when
wholesale energy prices are high,

 

 

and the value of energy provided
when demand and prices are low.
this case, it"s not clear
whether providers of distrib-
uted generation are more likely to
be overcompensated or under
compensated?ma good solar
installation churning out energy
at peak hours might well be
under~compensated based on
average rates that don?t re?ect the
real-time value of the energy
being provided to the grid. The

 

In short, the
fundamental
environmental
principle,

?polluter pays,?

will be violated in the
name of promoting
?green energy.?

rates also fail to re?ect transmis?
sion savings that DG might
enable. What is clear is that
incentives are not being provided
to support customers in choosing
the most valuable forms of dis-
tributed generation. Pricing that
re?ected the real-time value of
wholesale energy might well
result in distributed generation
deve10ping in new and exciting
directions, including creative uses
of energy storage that might
help to ensure that distributed
generation electricity is provided
to the grid at the time when it
would do the most good.

From a technological point of
view, therefore, the use of ?at

 

rates for electricity has a perverse 
effect on the development and
deployment of two very impor-
tant technologies: smart meters
and energy storage. There are
three fundamental values asso-
ciated with smart meters. The
?rst, of course, is to enable much
more ef?cient utility operations.
The second is to enable more
ef?cient use of energy by end
users, and the third is to deal
effectively with distributed
energy, frdin both economic and
safety points of view.5 The use of -
net metering (insensitive to when
energy is produced), of course,
largely negates the potential
advantages of smart meters in
encouraging more ef?cient
energy consumption and distrib-
uted generation production, since
the incentive to provide energy to
the grid at high-value times of day
is removed. The other technology
adversely affected by net meter-
ing is energy storage. If DG were
compensated on a real-time basis,
its investors would be incenti-
vized to deploy storage technol~
ogy in order to maximize the
value of what they produce.
Given the critical stage of devel-
opment in which energy storage
technology currently finds itself,
that would provide a boost to a
technology with great promise for
ef?ciency improvements. Indeed,
it is almost perverse to promote
an intermittent generation tech-
nology, such as distributed solar,
while discouraging the develop-
ment and use of the very tech-
nology that will enable solar to be
highly reliable. Realwtime pricing
of DC would ?x that gap and is

 

April 2013, Vol. 26, Issue 3 front matter 2013 Eisevier Inc. All rights reserved, 31

 

 

 

arguably in the best long

 term interest of intermittent

resources.

IV. Which Customers are
Most Likely to Bear the
Cost of Distributed
Generation Programs?

To the extent that the above
concerns are not addressed, it is
worth asking ourselves who will
bear the brunt of any inef?cient
choices we make with respect to
DG. There is a socially regressive
aspect to passing on additional
costs and delta revenue losses
attributed to DC to the balance of
customers who do not have DG
facilities. While certainly not all
DG providers are af?uent, nor
will all af?uent customers invest
in DC, there is a likelihood that
DG investors will on average be
higher~income than other custo-
mers. It is unlikely that many low-
to moderate?income households
will have the ?nancial resources
and desire to invest in DG. Thus,

 any additional cost or delta rev-
 enue loss attributable to DG that is
 passed on to the balance of cus~
- tomers has a high probability of

being a wealth transfer from the
less af?uent to the more af?uent.
This socially regressive result is
compounded by the fact that ?xed
costs are incurred equally by all
customers, whereas variable costs
are passed on based on levels

of consumption. Hence poor
customers who use small
amounts of electricity for lighting,
refrigeration, and perhaps
entertainment, will pay the same

 

 

costs as wealthy customers with a
plethora of appliances consuming
electricity.

course, the concerns

above are not necessarily
reasons to abandon support for
distributed generation. They do,
however, suggest two areas worth
further thought for those con~
cerned with a green agenda. First,
if we believe that a transition to
greener energy is both vital and
likely to be expensive, it is

 

There is a socially
regressive aspect?to
passing on additional
costs and delta revenue
losses attributed to DG
to the balance of
customers who do not
have DG facilities.

 

important to be ef?cient in our
green energy choices. To this end,
it would be to more
clearly understand the relative
costs of distributed generation
compared to alternative sources
of green energy?whow much of a
premium are we paying for dis-
tributed generation under current
practices? How much should we
pay, and what are we trying to
accomplish with this money? Are
we fostering an infant industry? If
so, how do we decide when to
stop? Do we need DG in order to
reach renewables goals in the face
of NIMBY opposition to larger
projects?6 Are the other bene?ts
of DC in terms of reliability

 

signi?cant, and how can we
quantify them?

econd, we should think

carefully about how distrib-
uted generation is incorporated
into overall electricity rates,
particularly how it interacts with
?net metering? and ?at rate
electricity charges. Does it magnify
or reduce the problems of current
rate systems in terms of incentives
for ef?ciency and demand
response? Structuring DG
compensation well could alleviate
a number of the potential negative
outcomes of DC programs??the
?anti-green? and socially regres-
sive results of DC pressures on
electricity pricing, as well as the
disincentives current pricing
schemes create to the adoption of
ef?cient technologies. All of these
can be avoided, or at least miti~
gated, by compensating DG pro-
ducers at the market clearing
wholesale price at the time they
deliver energy, plus any trans?
mission savings they enable. That,
of course, would re?ect the true
economic value of what they pro-
vide. It would also eliminate the
other related problem of compen~
sating DG providers based on 
average costs over the billing cycle 
regardless of whether they are 
producing on or off peak.7 The
solution to this problem, of course,
lies in the deployment of smart
meters, which are capable of
measuring energy inputs and
outputs on a real-time basis.

Proponents of DG have, for the

most part, opposed such pricing
schemes.- They argue that such
arrangements will make DG
less attractive ?nancially and

 

 

32

front matter 2013 Elsevier Inc. All rights reserved, http:/ 

The Electricity journal

 

therefore reduce the scope of its
deployment. They are, of course,
probably correct in that assertion.
The more money thrown at any
technology, the more likely it is to
be deployed. Thoughtful deploy-
ment of DG, however, is a far
more complex matter than simply
adopting ?nancial incentives for
DC investment. Public policy

 

 

demands that resource deploy?-
ment be consistent with overall
system optimization and not just
with the promotion of a favored
technology. While notions of
system optimization may well
include both the internal eco-
nomics of the network, as well
as externalities such as the
environment, the practice of

 

simply pricing a particular
resource in order to promote it, as
opposed to pricing it to reason?-
ably re?ect its overall value,
constitutes a leap of faith that is
virtually incapable of justifica-
tion.8 It is, therefore, important to
facilitate the entry of DG into the
marketplace, but to do so in
economically justi?ed ways. For

 

Legislators in states such as Massachusetts and California recognized that there were potentially perverse consequences.

 

April 2013, Vol. 26, Issue 3 front matter 2013 Elsevier Inc. All rights reserved, 

 

 

example, it might be possible to
address these problems by chan-
ging the compensation of distrib?
uted generation to include only the
avoided costs of energy and
transmission services and to re?ect
real~time energy prices. This might
mean that it would be harder for
homeowners to earn a good return
from their distributed generation
investments. But this may be a
necessary risk. If we are promoting
renewable distributed generation
for purposes of environmental
bene?t, then we need to link that to
pricing. What we are doing now is
exactly the opposite. We are pro-
ducing anti?green pricing to com?
pensate for promoting green
technology.

things currently stand,

the desire to have a robust
program of support for green
distributed generation may be
pushing many utilities and reguw
lators into supporting programs
that, at best, are not cost-effective
and at worst create perverse
incentives that work against the
green goals that motivate them.
When it comes to distributed
generation, we need additional
clarity on what we are trying to
achieve and whether distributed
generation is the best way to get
there. Legislators in states such as
Massachusetts and California,
despite their aggressiveness in
promoting DG, recognized that
there were potentially perverse
consequences, because they
capped the amount of energy
required to be purchased. With
the experience that we have now
had, it is time to reassess where
we are going and to calibrate

 

our pricing and policies to make
certain that our efforts are carry-
ing us in the right direction.-

Endnotes:

1. As noted earlier, not all distributed
generation is solar, nor renewable,
for that matter, but since carbon
neutrality is a major, although not
necessarily the only, driver of
policies promoting DG, much of the

 

focus of DG policy revolves around
renewable energy.

2. Excess energy, for purposes of this
article, is defined as DG~produced
energy in excess of that being consumed
at the premises wherein the DG facility
is located, energy which is customarily
sold into the distribution system.

3. Since DG feeds directly into the
distribution system, the purchase of
DG reduces the need for transmission
services and, therefore, reduces the
costs that a distributor would
otherwise pass on to their customers.
This bene?t is even greater when the
distributor is incurring congestion
costs on the tranSmission grid, as DG
can actually serVe to relieve
congestion and thereby reduce system
costs.

4. One could make the same
argument about de?coupling to
remove the utility disincentive to
provide demand-side management or
energy ef?ciency programs. Energy

 

 

ef?ciency and DG are not, however,
the same. Ef?ciency programs obviate
the need for generation, increase end
use ef?ciency, and constitute the most
environmentally benign source of
energy, megawatts. In short, society,
over the long run, saves both energy
and money. DC, on the other hand,
constitutes simply another supply'
side resource requiring a revenue
stream. While DG may or may not be
preferable to other sources of
generation for economic or
environmental reasons, it does not
save energy. It may cause the utility
the same kind of revenue erosion as
demand side management, but that is
not inherently true, as it is with
conservation and energy efficiency.
The revenue effects of DG are largely,
although not entirely, the result of
how DG is priced. Thus, comparisons
of the rate effect of DG with energy
ef?ciency programs are misplaced.

5. Dumb meters do not reveal the
presence of stray voltage on the grid
when work is being done, while smart
meters do. Thus, distribution workers
are better protected by smart rather
than dumb meters.

6. NIMBY may, in fact, not be unique
to large projects. Many communities
have contemplated or are likely to 
contemplate the promulgation of land
use, noise, and aesthetics regulations
to govern distributed generation.

7. The problem of compensating DC
by reversing the meter based billing cycle is not a
trivial one. The effect is to pay the
producer the same price on? or off"
peak, a result devoid of any basis in
costs, system bene?ts, externality
bene?ts, or any other economic logic,
other than simply subsidizing DG.

8. The authors are not arguing that no
subsidies are ever justi?ed. Certainly,
they may be required to incentivize
research and development, and
perhaps other limited purposes. That
is a subject beyond the scope of this
article. What is not a good idea,
however, is merely subsidizing a
resource to favor a particular
technology without fully analyzing
the overall effect of doing so, both
economically and socially.

 

34

front matter 2013 Elsevier inc. All rights reserved, 

Used with permission. Further redistribution prohibited.

 

The Electricity journal

Sponsored Content

A Principled Approach to DER
Katrina McMurrian
Executive Director
Critical Consumer Issues Forum (CCIF)

Today the nation’s electric
power grid is undergoing a major
transformation—it is changing from a
system in which electricity flows one
way, from an electric company to the
consumer, to a grid where power as
well as information can flow to and
from the consumer. More than $85
billion in annual capital expenditures
are enabling an electric superhighway
for the 21 st century and creating more
options for consumers to generate
some of their own electricity through
distributed energy resources (DER).
DER
include
generation
technologies such as rooftop solar
panels, microturbines that provide
auxiliary or backup power for a
building, energy storage devices, small
wind turbines, and fuel cells. They are
non-centralized sources of electricity
generation generally interconnected
to the distribution system and located
at or near customers’ homes or
businesses. Most customers with DER
produce their own electricity at some
times of the day, sell surplus electricity
over the grid at others times, and rely
upon the grid to provide electricity to
them when their generators are not
operating or not providing them all
the power they need.
When paired with appropriate
public policies, DER have the potential
to provide benefits to consumers, both

individually and collectively. There are
also challenges associated with DER
that should be considered.

self-generator at the full retail rate
for delivered power, which includes
both the cost of the power itself and

Potential Benefits & Challenges of DER
When paired with appropriate public
policies, DER have the potential to
provide direct and indirect benefits
to consumers, both individually and
collectively. Depending on the type of DER,
benefits that may be realized include:
1.  Cost and risk reduction benefits;
2.  Security and reliability;
3.  Environmental benefits;
4.  Innovation, expanded research and
development, and other economic
benefits; and
5.  Expanded customer choice and
control.

The growing use of DER, for
example, is raising questions about
how states should encourage, as well
as regulate, their use. Some DER
incentives—such as net metering,
which has been adopted in some
form in 43 states and the District
of Columbia—have the potential to
shift costs from those consumers who
generate a portion or all of their own
electricity to those consumers who do
not. While net metering policies vary
by state, an electric company generally
must purchase excess power from the

40 State & Local Energy Report // SUMMER 2013

Likewise, the challenges associated with
DER should be considered. Depending
on the type of DER, such challenges
may include:
1.  Financial impacts on utilities and
customers, including increased costs,
revenue losses, and cost-shifting;
2.  Safety, security, operational control,
reliability, and planning;
3.  Siting, permitting, and other
environmental issues;
4.  Maintaining consumer protection
standards; and
5.  Jurisdictional and regulatory issues.

the fixed costs of maintaining the grid
network that supports both consumers
with and without DER. Consumers
without DER might then have to pick
up those fixed costs, thereby subsidizing
those consumers with DER.
By the same token, if those homes
or businesses that generate their
power no longer contribute their share
of fixed costs to the grid or pay for the
costs they impose on the system, then
remaining consumers could be exposed
to higher rates. Moreover, rates that
fail to recover the appropriate share

of integration or backup service costs
from DER consumers may encourage
DER applications that are not
economically efficient, which raises the
total cost for all electricity consumers.
As DER programs expand, it
is becoming more important that
integrating
increasing
amounts
of DER be done in a way that is
fair to consumers with—as well as
without—DER. Because the electric
grid is a service that everyone uses,
everyone should contribute to its
upkeep. As such, DER may require
new approaches for providing and
regulating electricity services.
To offer a framework for
policymakers and other stakeholders to
encourage the development of DER in
a way that is both economically sound
and equitable for all utility customers,
a unique organization, the Critical
Consumer Issues Forum (CCIF), has
advanced a set of broad principles.
In developing this framework, CCIF
recognized the differing regulatory
and market structures of the states
(e.g., vertically integrated utilities,

wires-only utilities, etc.), as well as the
potential significance of regional and
federal requirements.
CCIF was formed in 2010
and engages state commissioners,
consumer advocates, and electric
utility representatives to develop
mutually agreeable solutions to
energy challenges. Leader from the
National Association of Regulatory
Utility Commissioners (NARUC), the
National Association of State Utility
Consumer Advocates (NASUCA), and
the Edison Electric Institute (EEI)
established the group to provide an
opportunity for state commissioners,
consumer advocates, and electric
industry representatives to collectively
tackle tough consumer issues through
unique, highly interactive discourse
and debate, to find consensus when
possible, and at a minimum, to achieve
a clearer understanding of–and
appreciation for–each group’s specific
concerns and positions.
Through
its
distinctive,
collaborative process, CCIF recently
developed 21 principles to assist

policymakers and other stakeholders
in evaluating issues related to the
opportunities and challenges of DER
in providing safe, reliable, affordable,
and environmentally sound service to
electric consumers. While DER can
include energy efficiency and demand
response, CCIF focused on distributed
generation.
Approximately 100 leader from
the state commissioner, consumer
advocate,
and
electric
utility
communities participated in a series
of interactive dialogues and formed
consensus in the following four areas:
• 
• 
• 
• 

Financial and Regulatory Issues
Market Development and Deployment Issues
Consumer Issues
Safety, Reliability and System
Planning Issues

Philip Jones, NARUC President
and
Washington
Utilities
and
Transportation Commissioner, said,
“DER is a timely topic that is
extremely important for the electric

State & Local Energy Report // SUMMER 2013 41

 Sponsored Content

A Principled Approach to DER
Katrina McMurrian
Executive Director
Critical Consumer Issues Forum (CCIF)

Today the nation’s electric
power grid is undergoing a major
transformation—it is changing from a
system in which electricity flows one
way, from an electric company to the
consumer, to a grid where power as
well as information can flow to and
from the consumer. More than $85
billion in annual capital expenditures
are enabling an electric superhighway
for the 21 st century and creating more
options for consumers to generate
some of their own electricity through
distributed energy resources (DER).
DER
include
generation
technologies such as rooftop solar
panels, microturbines that provide
auxiliary or backup power for a
building, energy storage devices, small
wind turbines, and fuel cells. They are
non-centralized sources of electricity
generation generally interconnected
to the distribution system and located
at or near customers’ homes or
businesses. Most customers with DER
produce their own electricity at some
times of the day, sell surplus electricity
over the grid at others times, and rely
upon the grid to provide electricity to
them when their generators are not
operating or not providing them all
the power they need.
When paired with appropriate
public policies, DER have the potential
to provide benefits to consumers, both

individually and collectively. There are
also challenges associated with DER
that should be considered.

self-generator at the full retail rate
for delivered power, which includes
both the cost of the power itself and

Potential Benefits & Challenges of DER
When paired with appropriate public
policies, DER have the potential to
provide direct and indirect benefits
to consumers, both individually and
collectively. Depending on the type of DER,
benefits that may be realized include:
1.  Cost and risk reduction benefits;
2.  Security and reliability;
3.  Environmental benefits;
4.  Innovation, expanded research and
development, and other economic
benefits; and
5.  Expanded customer choice and
control.

The growing use of DER, for
example, is raising questions about
how states should encourage, as well
as regulate, their use. Some DER
incentives—such as net metering,
which has been adopted in some
form in 43 states and the District
of Columbia—have the potential to
shift costs from those consumers who
generate a portion or all of their own
electricity to those consumers who do
not. While net metering policies vary
by state, an electric company generally
must purchase excess power from the

40 State & Local Energy Report // SUMMER 2013

Likewise, the challenges associated with
DER should be considered. Depending
on the type of DER, such challenges
may include:
1.  Financial impacts on utilities and
customers, including increased costs,
revenue losses, and cost-shifting;
2.  Safety, security, operational control,
reliability, and planning;
3.  Siting, permitting, and other
environmental issues;
4.  Maintaining consumer protection
standards; and
5.  Jurisdictional and regulatory issues.

the fixed costs of maintaining the grid
network that supports both consumers
with and without DER. Consumers
without DER might then have to pick
up those fixed costs, thereby subsidizing
those consumers with DER.
By the same token, if those homes
or businesses that generate their
power no longer contribute their share
of fixed costs to the grid or pay for the
costs they impose on the system, then
remaining consumers could be exposed
to higher rates. Moreover, rates that
fail to recover the appropriate share

of integration or backup service costs
from DER consumers may encourage
DER applications that are not
economically efficient, which raises the
total cost for all electricity consumers.
As DER programs expand, it
is becoming more important that
integrating
increasing
amounts
of DER be done in a way that is
fair to consumers with—as well as
without—DER. Because the electric
grid is a service that everyone uses,
everyone should contribute to its
upkeep. As such, DER may require
new approaches for providing and
regulating electricity services.
To offer a framework for
policymakers and other stakeholders to
encourage the development of DER in
a way that is both economically sound
and equitable for all utility customers,
a unique organization, the Critical
Consumer Issues Forum (CCIF), has
advanced a set of broad principles.
In developing this framework, CCIF
recognized the differing regulatory
and market structures of the states
(e.g., vertically integrated utilities,

wires-only utilities, etc.), as well as the
potential significance of regional and
federal requirements.
CCIF was formed in 2010
and engages state commissioners,
consumer advocates, and electric
utility representatives to develop
mutually agreeable solutions to
energy challenges. Leader from the
National Association of Regulatory
Utility Commissioners (NARUC), the
National Association of State Utility
Consumer Advocates (NASUCA), and
the Edison Electric Institute (EEI)
established the group to provide an
opportunity for state commissioners,
consumer advocates, and electric
industry representatives to collectively
tackle tough consumer issues through
unique, highly interactive discourse
and debate, to find consensus when
possible, and at a minimum, to achieve
a clearer understanding of–and
appreciation for–each group’s specific
concerns and positions.
Through
its
distinctive,
collaborative process, CCIF recently
developed 21 principles to assist

policymakers and other stakeholders
in evaluating issues related to the
opportunities and challenges of DER
in providing safe, reliable, affordable,
and environmentally sound service to
electric consumers. While DER can
include energy efficiency and demand
response, CCIF focused on distributed
generation.
Approximately 100 leader from
the state commissioner, consumer
advocate,
and
electric
utility
communities participated in a series
of interactive dialogues and formed
consensus in the following four areas:
• 
• 
• 
• 

Financial and Regulatory Issues
Market Development and Deployment Issues
Consumer Issues
Safety, Reliability and System
Planning Issues

Philip Jones, NARUC President
and
Washington
Utilities
and
Transportation Commissioner, said,
“DER is a timely topic that is
extremely important for the electric

State & Local Energy Report // SUMMER 2013 41

 Sponsored Content

DER) should be based on clear
policy objectives and periodically
reevaluated based on market
conditions. Once the underlying
policy objectives are met or as
the technologies become costcompetitive or cost-prohibitive,
such incentives should be modified
or discontinued.
incentives,
through
4.  Any
ratemaking
practices,
taxes,
or otherwise, should be fair,
transparent, and appropriate.
5.  Utility investments required to
accomplish DER deployment
should be consistent with state
policies and recovered in a manner
consistent with state laws and
regulatory policies.
6.  To the extent that state
commissions
evaluate
new
regulatory policies and procedures
in light of increased emphasis
on DER, they should take
into account the interests and
concerns of all stakeholders.

Market Development &
Deployment Issues
power industry and all consumers
– whether they invest in these
technologies directly or not. CCIF
has afforded the opportunity for state
regulators to explore these issues and
their potential implications with our
colleagues representing both consumer
and utility interests. As a result, I
expect the principles developed to be a
valuable resource not only to those of
us who participated in the dialogue, but
also to stakeholders across the board.”
Paula
Carmody,
NASUCA
President and Maryland People’s
Counsel, added that, “Consumer
advocates welcome our involvement
in a dialogue with state regulators
and utility representatives on issues
that have real-world implications for
consumers. CCIF recognizes that
consumer issues are at the forefront
in energy policy debates, and in the
discussions on DER in particular. Our
input as consumer representatives is
valued in this process, and the results
of this dialogue can be useful as we

work through DER-related issues at
the state and national levels. Once
again, the CCIF process has shown
that state regulators, consumer
advocates, and electric utilities can
find some common ground as we all
try to develop a framework to address
complex energy issues that may affect
every household and business in our
respective states.”
EEI Executive Vice President of
Business Operations David Owens
praised CCIF’s collaborative process
saying, “The value of collaboration is
evident in this quality product. While
our three communities face a number
of challenges related to the growth
of DER, the principles provide an
objective framework for addressing
them. Certainly, the dialogue on
these issues will continue and will
afford opportunities for broader
participation, but CCIF has guided
public policy in a positive direction,
potentially benefitting electric consumers
for years to come.”

42 State & Local Energy Report // SUMMER 2013

The CCIF framework on DER
includes the following 21 consensus
principles within the following four
respective categories:

Financial & Regulatory Issues
1.  Generally, DER costs imposed
on utilities should be borne by
those who cause the costs. For
example, backup or standby utility
costs
(particularly
regarding
intermittent DER technologies)
should be borne by the operator of
the DER.
2.  Any required allocation of costs
to others should be rational,
transparent, based on benefits
received,
and
not
unduly
burdensome.
3.  DER incentives (such as tax
subsidies, rebates, subsidized
financing, or any net metering
arrangement that provides benefits
exceeding the underlying value
of the energy received from that

7.  Utility and regulatory processes
and requirements should allow
for customer deployment of DER
technologies subject to reasonable
rules and regulations.
8.  Utility participation in DER
markets should be fair, reasonable,
non-discriminatory, and overseen
and approved by the appropriate
regulatory authority.
9.  Policies
related
to
DER
interconnection or deployment
should be fair, reasonable, not

unduly
discriminatory,
and
overseen and approved by the
appropriate regulatory authorities.
10.  DER should be permitted on either
the customer side or the utility
side of the meter in accordance
with interconnection rules and
other applicable regulations.
11.  While
policies
and
their
application may vary by state,
DER programs, grants, or
subsidies should be periodically
evaluated for cost-effectiveness
and adjusted by the appropriate
regulatory authority as market
conditions and policy objectives
or requirements change.
12.  Utilities and DER provider
should work toward appropriate
and reasonable data sharing that
facilitates capturing system benefits
and identifying costs of DER.

Consumer Issues
13.  As DER technologies are deployed,
consumer protection policies
should be periodically reviewed
and revised as appropriate. In any
event, consumers should be given a
clear avenue to resolve complaints.
14.  Utilities and DER provider,
with the participation of state
regulatory bodies and consumer
advocates,
should
develop
standards for data protection,
access, and disclosure consistent
with state requirements.
15.  States,
consumer
advocates,
and utilities should coordinate
education
and
customer
engagement programs and make
available objective information

Formed in 2010, the Critical Consumer
Issues Forum (CCIF) brings together
state commissioners, consumer advocates,
and electric utility representatives to
tackle consumer-focused energy issues
through interactive discourse and debate,
to find consensus when possible, and,
at a minimum, to achieve a clearer
understanding of—and appreciation for—
each other’s perspectives and positions.
Learn more at www.CCIForum.com.

associated with DER technologies.
16.  In developing DER policies,
particular attention should be
given to the cost impacts on all
utility customers, including those
not participating and those least
able to afford such costs.

Safety, Reliability & System
Planning Issues
17.  Utilities should be aware that
changes to utility system planning
and operations may be required
because of greater integration of
DER technologies.
18.  DER interconnection standards,
procedures, and practices must
ensure the safety of the public,
first responder, and electric
utility workers. These standards,
procedures, and practices must also
protect utility and customer assets.
19.  DER deployment must be
accomplished in a manner that
does not compromise the continued
reliability of utility infrastructure
and operating systems.
20.  DER deployment should not
diminish infrastructure security or
cybersecurity.
21.  Transmission and distribution
planning entities should consider
and incorporate as appropriate
state DER requirements into their
planning processes.
For more information about the
Critical Consumer Issues Forum, as
well as a copy of the new CCIF report,
“Policy Considerations Related to
Distributed Energy Resources,” please
visit www.CCIForum.com.

A former Florida Public
Service Commissioner
(2006-2009), Katrina
McMurrian draws upon
extensive regulatory
experience to organize
and facilitate relevant
policy forums and to
advise an array of entities
on key regulatory and
public policy matters.

State & Local Energy Report // SUMMER 2013 43

 Sponsored Content

DER) should be based on clear
policy objectives and periodically
reevaluated based on market
conditions. Once the underlying
policy objectives are met or as
the technologies become costcompetitive or cost-prohibitive,
such incentives should be modified
or discontinued.
incentives,
through
4.  Any
ratemaking
practices,
taxes,
or otherwise, should be fair,
transparent, and appropriate.
5.  Utility investments required to
accomplish DER deployment
should be consistent with state
policies and recovered in a manner
consistent with state laws and
regulatory policies.
6.  To the extent that state
commissions
evaluate
new
regulatory policies and procedures
in light of increased emphasis
on DER, they should take
into account the interests and
concerns of all stakeholders.

Market Development &
Deployment Issues
power industry and all consumers
– whether they invest in these
technologies directly or not. CCIF
has afforded the opportunity for state
regulators to explore these issues and
their potential implications with our
colleagues representing both consumer
and utility interests. As a result, I
expect the principles developed to be a
valuable resource not only to those of
us who participated in the dialogue, but
also to stakeholders across the board.”
Paula
Carmody,
NASUCA
President and Maryland People’s
Counsel, added that, “Consumer
advocates welcome our involvement
in a dialogue with state regulators
and utility representatives on issues
that have real-world implications for
consumers. CCIF recognizes that
consumer issues are at the forefront
in energy policy debates, and in the
discussions on DER in particular. Our
input as consumer representatives is
valued in this process, and the results
of this dialogue can be useful as we

work through DER-related issues at
the state and national levels. Once
again, the CCIF process has shown
that state regulators, consumer
advocates, and electric utilities can
find some common ground as we all
try to develop a framework to address
complex energy issues that may affect
every household and business in our
respective states.”
EEI Executive Vice President of
Business Operations David Owens
praised CCIF’s collaborative process
saying, “The value of collaboration is
evident in this quality product. While
our three communities face a number
of challenges related to the growth
of DER, the principles provide an
objective framework for addressing
them. Certainly, the dialogue on
these issues will continue and will
afford opportunities for broader
participation, but CCIF has guided
public policy in a positive direction,
potentially benefitting electric consumers
for years to come.”

42 State & Local Energy Report // SUMMER 2013

The CCIF framework on DER
includes the following 21 consensus
principles within the following four
respective categories:

Financial & Regulatory Issues
1.  Generally, DER costs imposed
on utilities should be borne by
those who cause the costs. For
example, backup or standby utility
costs
(particularly
regarding
intermittent DER technologies)
should be borne by the operator of
the DER.
2.  Any required allocation of costs
to others should be rational,
transparent, based on benefits
received,
and
not
unduly
burdensome.
3.  DER incentives (such as tax
subsidies, rebates, subsidized
financing, or any net metering
arrangement that provides benefits
exceeding the underlying value
of the energy received from that

7.  Utility and regulatory processes
and requirements should allow
for customer deployment of DER
technologies subject to reasonable
rules and regulations.
8.  Utility participation in DER
markets should be fair, reasonable,
non-discriminatory, and overseen
and approved by the appropriate
regulatory authority.
9.  Policies
related
to
DER
interconnection or deployment
should be fair, reasonable, not

unduly
discriminatory,
and
overseen and approved by the
appropriate regulatory authorities.
10.  DER should be permitted on either
the customer side or the utility
side of the meter in accordance
with interconnection rules and
other applicable regulations.
11.  While
policies
and
their
application may vary by state,
DER programs, grants, or
subsidies should be periodically
evaluated for cost-effectiveness
and adjusted by the appropriate
regulatory authority as market
conditions and policy objectives
or requirements change.
12.  Utilities and DER provider
should work toward appropriate
and reasonable data sharing that
facilitates capturing system benefits
and identifying costs of DER.

Consumer Issues
13.  As DER technologies are deployed,
consumer protection policies
should be periodically reviewed
and revised as appropriate. In any
event, consumers should be given a
clear avenue to resolve complaints.
14.  Utilities and DER provider,
with the participation of state
regulatory bodies and consumer
advocates,
should
develop
standards for data protection,
access, and disclosure consistent
with state requirements.
15.  States,
consumer
advocates,
and utilities should coordinate
education
and
customer
engagement programs and make
available objective information

Formed in 2010, the Critical Consumer
Issues Forum (CCIF) brings together
state commissioners, consumer advocates,
and electric utility representatives to
tackle consumer-focused energy issues
through interactive discourse and debate,
to find consensus when possible, and,
at a minimum, to achieve a clearer
understanding of—and appreciation for—
each other’s perspectives and positions.
Learn more at www.CCIForum.com.

associated with DER technologies.
16.  In developing DER policies,
particular attention should be
given to the cost impacts on all
utility customers, including those
not participating and those least
able to afford such costs.

Safety, Reliability & System
Planning Issues
17.  Utilities should be aware that
changes to utility system planning
and operations may be required
because of greater integration of
DER technologies.
18.  DER interconnection standards,
procedures, and practices must
ensure the safety of the public,
first responder, and electric
utility workers. These standards,
procedures, and practices must also
protect utility and customer assets.
19.  DER deployment must be
accomplished in a manner that
does not compromise the continued
reliability of utility infrastructure
and operating systems.
20.  DER deployment should not
diminish infrastructure security or
cybersecurity.
21.  Transmission and distribution
planning entities should consider
and incorporate as appropriate
state DER requirements into their
planning processes.
For more information about the
Critical Consumer Issues Forum, as
well as a copy of the new CCIF report,
“Policy Considerations Related to
Distributed Energy Resources,” please
visit www.CCIForum.com.

A former Florida Public
Service Commissioner
(2006-2009), Katrina
McMurrian draws upon
extensive regulatory
experience to organize
and facilitate relevant
policy forums and to
advise an array of entities
on key regulatory and
public policy matters.

State & Local Energy Report // SUMMER 2013 43

 THE REGULATORY CHALLENGE OF DISTRIBUTED GENERATION
David B. Raskin∗

I.

Introduction

Recent published reports point toward a growing conviction that the demand for
utility service from the U.S. electric grid may soon decline, perhaps substantially, due to
the expanding use of distributed generation.1 One report prepared by a division of
Citigroup describes the improving economics of distributed solar power, which the
authors expect will continue.2 A second Citigroup report projects reductions in the
demand for utility service in developed markets of up to fifty percent by 2050.3 Favorable
projections for distributed generation, however, depend on assumptions about
technological change that may turn out to be overstated, and even if distributed
generation grows substantially, millions of homes and businesses will continue to rely on
the electric grid for many decades.4
*

David Raskin is a partner in the Washington, DC office of Steptoe & Johnson LLP. He has
represented stakeholders in the electric power industry for more than thirty years. During this time, he has
been involved in most of the significant federal regulatory initiatives designed to increase competition in
the electric industry and has assisted clients in managing the unprecedented changes that have occurred in
recent decades.
1
E.g., Diane Cardwell, On Rooftops, a Rival for Utilities, N.Y. TIMES, July 26, 2013,
http://www.nytimes.com/2013/07/27/business/energy-environment/utilities-confront-fresh-threat-do-ityourself-power.html; Peter Kind, Disruptive Challenges: Financial Implications and Strategic Responses
to a Changing Retail Electric Business, EDISON ELECTRIC INSTITUTE (Jan. 2013),
www.eei.org/ourissues/finance/Documents/disruptivechallenges.pdf‎.
2
Citi Research, Rising Sun: Implications for US Utilities (Aug. 8, 2013),
http://www.wecc.biz/committees/BOD/TEPPC/SPSG/Lists/Events/Attachments/706/CITIRising%20Sun%20Implications%20for%20US%20Utilities.pdf.
3
Jason Channell et al., Energy Darwinism: The Evolution of the Energy Industry, CITI GLOBAL
PERSPECTIVES
&
SOLUTIONS
73-75
(Oct.
2013),
https://ir.citi.com/Jb89SJMmf%2BsAVK2AKa3QE5EJwb4fvI5UUplD0ICiGOOk0NV2CqNI%2FPDLJq
xidz2VAXXAXFB6fOY%3D.
4
Even if Citi’s aggressive prediction of fifty percent demand reduction by 2015 turns out to be
38

 THE REGULATORY CHALLENGE OF DISTRIBUTED GENERATION

VOLUME 4

Germany has gone further to promote distributed generation5 than any other
industrialized nation, and its experience provides a cautionary tale. More than a decade
after Germany initiated its Energiewende,6 the average residential price for electricity is
almost 36 cents per kWh,7 and rates are projected to rise another thirty to fifty percent in
the next ten years.8 Without a change in policy, German residential electric rates may
therefore approach 50 cents per kWh by the end of this decade. In contrast, the average
residential rate in the U.S. is approximately 12.5 cents per kWh.9 Because the average
U.S. residence uses approximately 1,000 kWh of electricity per month,10 the current
German rate would be equivalent to an average household tax of $3,000 per year. Rates
anywhere near the levels being experienced in Germany would be unacceptable in the
U.S.11

accurate, that prediction leaves fifty percent of electric load dependent on grid service.
5
In this Article, references to “distributed generation” refer to energy sources located behind the
retail meter or connected to a micro grid, where the intent is to remove some load or demand from the
system of integrated electric generation, transmission, and distributed facilities that comprise what is
referred to in this Article as the “grid.”
6
Energiewende, or energy transformation, is the product of the German Renewable Energy Act of
2000 (Erneuerbare-Energien-Gesetz) that put in place substantial subsidies for distributed generation and
grid-connected renewables. See General Information: Transformation of Our Energy System, GER. FED.
MINISTRY FOR THE ENV’T, NATURE CONSERVATION AND NUCLEAR SAFETY, www.bmu.de/P118-1/ (last
visited Nov. 24, 2013).
7
Jesse Morris, How Germany’s Solar Evolution Impacts America, EARTH TECHLING (Oct. 12, 2013),
http://www.earthtechling.com/2013/10/how-germanys-solar-evolution-impacts-america. Ironically, this
article laments the fact that the German feed-in tariff rate for distributed solar is only 20 cents per kWh,
well below the full retail rate.
8
Institute for Energy Research, Germany’s Energy Policy: Man-Made Crisis Now Costing Billions
(Oct. 30, 2012), http://www.instituteforenergyenergy research.org/10/20/2012. Many Germans claim they
can no longer afford to buy electricity. Germany’s Energy Poverty: How Electricity Became a Luxury
Good, SPIEGEL ONLINE INT’L (Sept. 4, 2013), http://www.spiegel.de/international/germany/high-costsand-errors-of-german-transition-to-renewable-energy-a-920288.html.
9
Energy Info. Admin., Table 5.6.A. Average Retail Price of Electricity to Ultimate Customers by
End-Use
Sector,
(Nov.
20,
2013),
http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_5_6_a.
10
Energy Info. Admin., How Much Electricity Does an American Home Use?,
http://www.eia.gov/tools/faqs/faq.cfm?id=97&t=3 (last updated Mar. 19, 2013).
11
Germany’s Environment Minister, Peter Altmaier, has acknowledged that Germany has overdone
the subsidies and needs to cut them back. Diarmaid Williams, Altmaier says German energy transition
ENERGY
INTERNATIONAL
(Feb.
21,
2013),
could
cost
$1.34trn,
POWER
http://www.powerengineeringint.com/articles/2013/02/Altmaier-says-German-energy-transition-couldcost-134trn.html; Minister Altmaier: EEG Cuts Needed—or Energiewende Costs Will Reach Trillion
ENERGY
BLOG
(Feb.
20,
2013),
Euro
Mark
by
2040,
GERMAN
http://www.germanenergyblog.de/?p=12278.
39

 HARVARD BUSINESS LAW REVIEW ONLINE

2013

Even with extraordinarily high and increasing electric rates, aggregate carbon
dioxide emissions by the German electric sector are rising.12 In contrast, U.S. emissions
are falling even though renewables constitute a much smaller percentage of the electric
energy mix in the U.S.13 The stability of the German grid is also being put at risk: it has
relied more heavily on variable, renewable generation at the same time that grid resources
capable of rapidly balancing supply and demand have been shutting down due to
anomalous market price signals.14 Energiewende has also taken a toll on the utility
companies that may have to make the grid investments to fix these operating problems.
Equity values for Germany’s biggest utilities have fallen by fifty percent or more over the
past three years.15
While Germany struggles with Energiewende, the growth of distributed generation
in the U.S. is being fueled by a controversial regulatory practice known as net metering.
If distributed generation comes to play a significant role, the loss of demand for service
from the grid may eventually make it difficult for the owners of grid assets to recover
their costs, creating what the utility industry calls “stranded costs.” This Article explores
the debate over net metering and then turns to the longer-term prospect of having to
address potential stranded costs produced by the expanded use of distributed generation.
II.

Net Metering: The Current Battlefield

Most renewable generation in the U.S. is subsidized through investment or
production tax credits.16 This Article focuses on an additional subsidy to distributed
renewable generation alone that exists as a result of “net metering” as applied in about
forty states. Under net metering, retail customers (including commercial and industrial
customers) can offset their electricity purchases from the grid with energy generated
12

Spiegel Online Int’l, supra note 8; Max Luke, Jessica Lovering & Alex Trembath, Trash, Trees and
Taxes: The Cost of Germany’s Energiewende, ENERGY COLLECTIVE (Sept. 16, 2013),
http://theenergycollective.com/maxluke/274041/trash-trees-and-taxes.
13
An environmental critique of Energiewende can be found in Will Boisvert, Green Energy Bust in
Germany, DISSENT (2013), http://www.dissentmagazine.org/article/green-energy-bust-in-germany.
14
Tilting
at
Windmills,
ECONOMIST,
June
15,
2013,
available
at
http://www.economist.com/news/special-report/21579149-germanys-energiewende-bodes-ill-countryseuropean-leadership-tilting-windmills.
15
How to Lose Half a Trillion Euros, ECONOMIST, October 12, 2013,ERROR! BOOKMARK NOT
DEFINED. available at http://www.economist.com/news/briefing/21587782-europes-electricity-providersface-existential-threat-how-lose-half-trillion-euro.
16
German subsidies primarily take the form of “feed in tariffs” that guarantee minimum per kWh
payments to those employing favored technologies, which are paid out of a pool funded by consumers.
See Stefan Nicola, German Industry Wants End of Feed-in Tariff on Rising Power Cost, BLOOMBERG
(Sep 19, 2013, 5:53 AM), http://www.bloomberg.com/news/2013-09-19/german-industry-wants-end-offeed-in-tariff-on-rising-power-cost.html.
40

 THE REGULATORY CHALLENGE OF DISTRIBUTED GENERATION

VOLUME 4

behind the retail meter, such as from rooftop solar panels. In most of the states that allow
net metering, the credit equals the bundled retail rate. The credit applies not only to
foregone consumption but also—with limited exceptions—to the energy generated from
behind the meter in excess of the customer’s own use and delivered to the utility.17
Net metering therefore values the energy produced by distributed generators at the
bundled retail rate for electricity. The bundled retail rate includes, in addition to the cost
of producing electric energy, the costs associated with investment in and operation of
transmission and distribution facilities and other costs incurred to ensure reliability and
fund public policy initiatives endorsed by utility regulators. As noted above, the average
residential price of electricity (the average bundled rate) is currently around 12.5 cents
per kWh.18 According to published data as of November 2013, the market price of energy
from grid-connected19 generators is averaging, in most locations, between 2 and 3 cents
per kWh during off-peak periods and between 4 and 5 cents per kWh during on-peak
periods.20 Recent sales of grid-connected renewable energy have been priced near or
below 3 cents per kWh.21 Therefore, net metering allows the owners of distributed
generation to effectively sell their energy at prices between two and six times the market
price for energy.
Grid-connected renewable generators are paid the much lower market price for
their energy, so the issue is not, as advocates of distributed generation allege, merely
about promoting “clean” energy. A grid-connected solar generator at the same location as
a distributed solar generator receives a fraction of the compensation for providing energy
using similar—and equally clean—technology.22 Grid-scale solar generation is actually
more efficient, so net metering provides a huge subsidy to a less efficient form of
17

As discussed below, the Federal Energy Regulatory Commission (FERC) has disclaimed
jurisdiction over energy supplied from behind-the-meter distributed generation so long as the customer
does not supply more excess energy than it acquires from the grid over the course of a monthly retail
billing period.
18
Energy Info. Admin., Table 5.6.A, supra note 9.
19
This Article refers to generators that are connected on the utility side of the customer meter as
“grid-connected generation” for ease of reference. This is a misnomer, however, because all generation,
including generation located on a retail customer’s property on the customer side of the meter, is
connected to and part of the electric grid. Electricity does not recognize the difference in location; at all
times sufficient energy must be supplied to meet the aggregate demand of all users, and the system must
be kept in precise balance (supply equaling demand) in order to prevent outages and serious damage to
facilities.
20
See Platts, MEGAWATT DAILY, at 2-10 (November 27, 2013).
21
American Wind Energy Association, The Cost of Wind Energy in the U.S.,
http://www.awea.org/Resources/Content.aspx?ItemNumber=5547 (last visited Nov. 24, 2013).
22
The analysts at Citi put it succinctly: “While residential solar has the advantage of competing
against higher residential electricity prices, merchant utility scale solar must compete against wholesale
power prices.” Citi Research, supra note 2 at 21.
41

 HARVARD BUSINESS LAW REVIEW ONLINE

2013

renewable energy.
Utilities point out that the differential is paid by other retail customers. Because
virtually all retail service is billed based on energy usage, net metering causes a reallocation of transmission, distribution, and reliability costs to those customers who do
not own distributed generation. Yet, the owners of distributed generation continue to rely
on utility service from the grid for back-up and supplemental energy (for example, at
night and when it is cloudy). Presently, the use of distributed generation in the U.S. is
sufficiently limited that the cost-shifting effects are minor. However, subsidies this large
can induce rapid changes. A report recently issued by the California Public Utilities
Commission forecasts that net metering will cost the State $1.1 billion per year in 2020.23
It also finds that the average net metering customer in California has an income almost
twice the state’s average, 24 confirming claims that net metering entails a wealth transfer
from low- to high-income consumers.
Net metering raises a number of legal issues that are just beginning to be explored.
The definition of “net metering service” in the Energy Policy Act of 2005 indicates that
Congress did not endorse the subsidy described above.25 Section 111(d)(11) of the Public
Utility Regulatory Policies Act (PURPA)26 was added in 2005 to a list of retail
ratemaking practices that state utility commissions are required to evaluate for use in
their jurisdictions. This provision defines “net metering service” as follows:
Net Metering – Each electric utility shall make available upon request net
metering service to any electric consumer that the electric utility serves. For
purposes of this paragraph, the term “net metering service” means service
to an electric consumer under which electric energy generated by that
electric consumer from an eligible on-site generating facility and delivered
to the local distribution facilities may be used to offset energy provided by
the electric utility to the electric consumer during the applicable billing
period.27

23

See Cal. Pub. Utils. Comm’n, CALIFORNIA NET ENERGY METERING (NEM) DRAFT COSTEFFECTIVENESS EVALUATION (2013), available at http://www.cpuc.ca.gov/NR/rdonlyres/BD9EAD367648-430B-A692-8760FA186861/0/CPUCNEMDraftReport92613.pdf.
24
Id. at 110.
25
Energy Policy Act of 2005, Pub. L. No.109-58, sec. 1251, § 111(d), 119 Stat. 962 (codified as
amended at 16 U.S.C. 2621(d)(11)).
26
See id.; Pub. Util. Reg. Policies Act of 1978, Pub. L. No. 95-617, § 111(d), 92 Stat. 3117, 3142-43
(codified as amended at 16 U.S.C. § 2621(d)(10)(E)(11) (2006)).
27
Energy Policy Act § 111(d); 16 U.S.C. § 2621(d)(10)(E)(11).
42

 THE REGULATORY CHALLENGE OF DISTRIBUTED GENERATION

VOLUME 4

Under this definition, “electric energy” generated by a retail customer’s on-site
facility may be used to offset “energy” provided by the utility. The language strongly
implies that Congress meant only to ensure that consumers would receive an appropriate
credit for the energy supplied from on-site generation and not a credit based on the
bundled retail rate that includes costs associated with transmission, distribution, and
reliability. If this is correct, net metering as applied in most states is inconsistent with this
part of PURPA.28
In 2002, the Supreme Court of Ohio addressed this very issue in connection with
interpreting Ohio legislation that required public utilities to offer net metering.29 In that
case, FirstEnergy proposed a net metering regime under which net metered customers
would receive a credit for energy supplied from on-site generation based on the
unbundled generation component of the retail rate.30 This proposal was rejected by the
Ohio Public Utilities Commission, which directed that FirstEnergy offer a credit based on
the full bundled retail rate.31 The Ohio Supreme Court held that FirstEnergy had correctly
applied statutory language requiring utilities to provide a credit for the “electricity”
produced by on-site generators by offering to credit only the generation component of the
retail rate.32 The Court found that FirstEnergy was correct in contending that a net meter
customer “does not provide transmission, distribution or ancillary services,” and therefore
the term “electricity” in the statute did not require a credit for the costs associated with
these other unbundled services.33
Net metering also appears to be inconsistent with provisions of PURPA that were
designed to protect electric consumers from cross-subsidization. Under PURPA, utilities
are required to purchase energy from qualifying “small power production” facilities that
meet eligibility standards established in the law.34 Under FERC regulations, retail
customers that own on-site generators with a maximum net generating capacity of less
than 1 MW are permitted to self-implement PURPA’s mandatory purchase requirement

28

Congress also did not define what it meant by “delivered to the local distribution facilities” in this
provision. It may have intended the energy credit to apply only to energy in excess of the customer’s onsite use, or it may have intended that all energy produced on-site be treated as energy provided to the grid
because all such energy substitutes energy that would otherwise be supplied from the grid. Either way, the
definition provides only for an energy credit, which is not what occurs in most jurisdictions.
29
FirstEnergy Corp. v. Pub. Utils. Comm’n of Ohio, 768 N.E.2d 648 (Ohio 2002).
30
Id. at 650.
31
Id.
32
Id. at 652.
33
Id.
34
Pub. Util. Reg. Policies Act § 210 (codified at 16 U.S.C. § 824a-3(a) (2006)). FERC regulations
refer to these as “qualifying facilities.” 18 C.F.R. § 292.101(b)(1).
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without any notification to or approval from FERC.35 Most retail customers using net
metering rely on the mandatory purchase requirement to require their host utilities to
purchase their energy.36 Absent the PURPA requirement, utilities would generally have
no obligation to buy energy from distributed generators because the Federal Power Act37
(the law that applies in the absence of PURPA) does not obligate utilities to purchase
energy at wholesale.38
PURPA, however, while requiring utilities to buy, also caps the price paid to
qualifying facilities at the purchasing utility’s “avoided cost,” which is defined as the cost
of energy that would have been supplied from the utility’s own system if the energy had
not been supplied by the qualifying facility.39 Because net metering compensates owners
for the energy supplied from distributed generation at the utility’s bundled retail rate, this
practice would appear to violate the avoided cost rate cap that is based on the cost of
energy alone.
The FERC, however, permits net meter customers to avoid this price cap. The
FERC holds that unless a retail customer with on-site generation is a net supplier of
energy to the grid over the state retail billing period (almost always one month), no sale
takes place under PURPA or the Federal Power Act, even if there are substantial
deliveries of energy to the grid during the month.40 In the absence of a “sale” to the
utility, FERC deems that no mandatory purchase of energy is taking place under PURPA
and the avoided cost price cap does not apply.41
The FERC’s theory, that the existence of a “sale” can be determined by netting
metered inflows and outflows over the course of a month, was recently rejected in two
appellate cases involving FERC’s use of this same theory to determine whether a retail
sale has occurred when generators acquire energy for station service purposes, the mirror

35

18 C.F.R. § 292.203(d) (2010).
See Stephanie Watson, How Net Metering Works, HOW STUFF WORKS,
http://science.howstuffworks.com/environmental/green-science/net-metering2.htm (last visited Nov. 24,
2013).
37
16 U.S.C §§ 791a-825r.
38
From the earliest days of Federal Power Act jurisprudence, courts have emphasized that wholesale
power transactions under the Federal Power Act are voluntary. Fed. Power Comm’n v. Sierra Pac. Power
Co., 350 U.S. 348 (1956). In organized Regional Transmission Organization (RTO) markets, any
generator that signs a service agreement with RTO is permitted to bid its energy into the market and, if
dispatched, gets paid the locational marginal cost of energy, even if the generator does not have a contract
with a specific buyer.
39
Am. Paper Inst. v. Am. Elec. Power Serv. Corp., 461 U.S. 402, 404 (1983).
40
See MidAmerican Energy Co., 94 F.E.R.C. P 61,340 (2001); Sun Edison LLC, 129 F.E.R.C. P
6,1146 (2009).
41
Id.
36

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image of the net metering situation.42 In these two cases, the D.C. Court of Appeals held
that netting could not be used to determine whether a sale has taken place and that there
is a sale whenever energy is delivered from the generator to the utility and vice versa.43
The FERC’s disclaimers of jurisdiction in MidAmerican and SunEdison may therefore be
subject to a renewed challenge, which, if successful, would require net metering rules to
be changed at the state level.
This same “netting” theory allows FERC to avoid facing the fact that the prices
inherent in net metering are discriminatory. The Federal Power Act prohibits charges for
wholesale energy that are “unduly discriminatory,”44 but this prohibition only applies if
there is a FERC-jurisdictional wholesale transaction. MidAmerican Energy and
SunEdison therefore provide a rationale for FERC to avoid addressing the huge
differential between the prices paid to distributed and grid-connected generators for the
energy they supply.
From both economic and environmental perspectives, energy from distributed
generation is no more beneficial than other forms of renewable generation. Energy
available to meet electric load, whether generated behind the retail meter or from gridconnected generation, provides equivalent value to the electric system. Therefore, the
price discrimination inherent in net metering cannot be justified based on differences in
the value of the services offered. If anything, distributed solar is less valuable than most
energy from grid-connected generators because the energy output of solar facilities varies
uncontrollably. Consequently, utilities must have sufficient grid-connected capacity on
hand to supply the entire load when solar generation is non-productive. For the same
reason, retail customers with distributed generation require access to grid-supplied energy
up to their full load at unpredictable times.45 Indeed, solar generation has a pernicious
effect on energy markets because energy from solar generators tends to suppress energy
market prices during peak-load periods, providing less revenue for grid-connected
42

See S. Cal. Edison Co. v. FERC, 603 F.3d 996 (D.C. Cir. 2010); Calpine Corp. v. FERC, 702 F.3d
41 (D.C. Cir. 2012).
43
See S. Cal Edison Co. 603 F.3d at 1000-01; Calpine Corp. 702 F.3d at 45.
44
16 U.S.C. § 824e(a).
45
California is attempting to overcome this issue by requiring utilities to purchase storage
capacity using new technologies to help balance supply and demand. Order Instituting
Rulemaking Pursuant to Assembly Bill 2514 to Consider the Adoption of Procurement
Targets for Viable and Cost-Effective Energy (published October 17, 2013), Cal. Pub. Utils.
Comm’n, 2013 Cal. PUC LEXIS 569, available at
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M078/K912/78912194.PDF.
Whether these alternative technologies will become available in sufficient quantities and at
a reasonable cost to replace balancing generation from the grid, and how long this may take,
is unknown.
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generation and falsely signaling to the market that grid-connected generation that is
needed for reliability is no longer economic.46
In conclusion, net metering as currently practiced in most states provides a huge
subsidy to distributed generators over and above the tax subsidy provided to all
renewable generation, discriminates against all forms of grid-connected generation
(including renewables), forces an inappropriate re-allocation of the costs of the grid to
remaining (and disproportionately lower income) customers, and sends a faulty price
signal that can cause under-investment in (or early shut down of) grid-connected
generation that is needed for real-time balancing purposes and to meet peak demands.
These same problems—in larger scale—are among the primary causes of Germany’s
growing dysfunction.
III.

The Return of Stranded Costs

Broadly speaking, the current dispute over net metering is about managing the
growth of distributed generation during the period when growth is being fueled by
subsidies. If projections such as those made by Citigroup are correct, the cost of energy
from distributed generation will decline, eventually making it competitive with energy
from the grid without subsidies, and the pace of growth will accelerate. At some point,
distributed generation could be married to behind-the-meter storage capability, permitting
customers to disconnect from the grid or significantly limit their use of utility service.
Investments in distributed generation combined with storage should expand rapidly when
and if the combined cost of distributed energy and storage reaches parity with the cost of
bundled service from the grid.
In this scenario, as the demand for service from the grid declines and utilities need
to recover the cost of the grid from a smaller customer base, utilities will have to respond
by filing to raise rates. While this is occurring, a large body of customers will remain
dependent on electricity from the grid for a considerable period of time since many
customers may not have the resources to install distributed generators and others may
choose to take their electric service from the grid.
Even as this possible transition approaches, billions of dollars of grid investments
46

The Economist notes: “Renewables can depress wholesale prices, e.g. when the sun creates a
midday jolt. This discourages investors in the flexible, gas-powered generation needed to provide backup
for windless, cloudy days.” Energiewinde, ECONOMIST, July 28, 2012, at 3. Citi Research, noting that
solar production causes lower utilization rates for conventional generation plants, concludes: “This would
in a perfect economic world lead to the closure of some higher heat rate gas plants, but the problem of
course is that much of this generation capacity needs to remain to cover lost generation on less sunny days
and at night, and through the winter . . . .” Citi Research, supra note 2, at 17.
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are being made, mostly in response to regulatory mandates.47 As the use of distributed
generation grows, investors in grid assets will demand that regulators provide assurance
that their investments will be recoverable over time with a reasonable return. Otherwise,
the cost of capital will rise, exacerbating the problem of rising rates during the transition,
and in a worst case making it impossible for utilities to raise the capital needed to serve
remaining customers and compensate investors for their prior investments in the grid.
Around the turn of the century, the utility industry faced the prospect that
investments in generation might be unrecoverable. In those jurisdictions that permitted
“retail choice” of electricity suppliers, utility generation was unbundled and re-priced to
market. This competitive transformation produced debates over whether utilities were
entitled to recover the costs associated with prior generation investments from departing
customers when sunk costs exceeded the revenues recoverable at market prices. The
differential was known as “stranded costs.”
Utilities argued that they were entitled by law to recover their stranded costs
pursuant to an implicit bargain with the government under which utilities had assumed an
obligation to serve the public in return for assurance that they would be compensated for
their prudent investments made to meet that obligation. Along with many scholars,
utilities argued that the law recognized this “regulatory compact” and that failure to
permit the recovery of stranded costs represented an unconstitutional taking of utility
property.48 Others argued that no such legal right exists and that allowing utilities to
recover their stranded costs would be inconsistent with the transition to competition.49
In the states that endorsed retail choice, legislative or regulatory compromises
were reached in which utilities recovered most of their stranded costs. The underlying
legal question was never resolved decisively in the courts. The stranded cost issue will be
different in the context of utility loss of demand to distributed generation. In this context,
stranded cost issues will not appear at one point in time (such as a legislative
47

For example, the electric industry is investing significant sums in response to state laws imposing
renewable portfolio standards. Large additional investments are being made to modernize the
transmission and distribution systems and incorporate so-called “smart grid” technologies. One utility
executive recently noted that half the existing transmission grid is more than fifty years old, so sizable
investments to sustain it are inevitable. Lisa Barton, IHS The Energy Daily, September 26, 2013, at 14.
Several northeastern states are requiring utilities to invest in “hardening” their systems in response to
recent storm-related outages. See Diana Cardwell et al., Hurricane Sandy Alters Utilities’ Calculus on
Upgrades, N.Y. TIMES, Dec. 28, 2012, at B1. Since 2005, the utility industry has also been subject to
mandatory reliability standards approved by the FERC that require significant ongoing investments in the
grid. 16 U.S.C. § 824o (2005).
48
See, e.g., J. Gregory Sidak & Daniel F. Spulber, Deregulatory Takings and Breach of the
Regulatory Contract, 71 N.Y.U. L. REV. 851 (1996).
49
See, e.g., Susan Rose-Ackerman & Jim Rossi, Disentangling Deregulatory Takings, 86 VA. L. REV.
1436 (2000).
47

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determination to permit retail customer choice) but will emerge gradually as utilities and
regulators respond to reductions in aggregate demand for utility service. The stranded
cost issue may also include stranded investment in transmission and distribution assets as
well as generation. Further, stranded cost recovery will have to be addressed in the
context of a declining utility customer base that may ultimately become too small to
support recovery. In the last round of stranded costs, customers changing power suppliers
remained as transmission and distribution customers of the utility and stranded costs
could be recovered in the rates for these unbundled services.
A. Cost Recovery for Regulated Assets
Assuming distributed generation becomes economical without subsidies, retail
customers will be making independent decisions about whether to reduce or jettison
utility service, and these decisions will occur over time as the relative economics of gridproduced and distributed electricity change. The stranded cost issue is therefore likely to
arise in individual rate proceedings as utilities file to increase their rates to offset the
effects of declining demand and regulators respond by requiring offsetting cost
reductions to cabin these rate increases to remaining captive customers. As this process
unfolds, history teaches that there will be disputes over the prudence of past utility
expenditures and over whether particular assets remain “used and useful” and thus
eligible for cost recovery.
The Supreme Court’s decision in Duquesne Light Co. v. Barasch holds that a
utility’s Constitutional right to recover its costs to serve the public is not infringed by
regulatory decisions disallowing individual items of cost.50 An unlawful “taking” occurs
only when the overall level of rates produces insufficient revenue to satisfy the “endresult” test established in FPC v. Hope Natural Gas Co.51 Hope held that overall rate
levels “which enable a company to operate successfully, to maintain its financial
integrity, to attract capital, and to compensate its investors for the risk assumed . . . ” are
sufficient to pass Constitutional muster.52 The Hope test is fairly subjective and may not
produce rates that are attractive to investors. Duquesne suggests that stranded cost issues
will have to be addressed through rate litigation, which means the availability of relief to
distressed utilities may be delayed.53 Without legislation, moreover, the remaining
50

488 U.S. 299, 314-15 (1989) [hereinafter Duquesne].
320 U.S. 591, 602-03 (1944) [hereinafter Hope].
52
Id. at 605.
53
The takings issue will recur if demand declines further over time. If demand declines after rates
have been set, utilities will once again under-recover their costs, forcing them to file for another round of
rate increases to offset the effect of the loss of load since the prior rate case. Utilities will be playing
“catch-up” to get the revenues needed to recover their costs and attract investment.
51

48

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VOLUME 4

customer base will eventually become too small, forcing utilities to try and convince
regulators to permit them to charge exit fees to departing customers. For these reasons,
substantial pressure will arise to resolve stranded cost recovery issues through legislation.
Legislative fixes will be a hard sell politically, but legislators may be convinced to act in
order to prevent important energy policy issues from being decided in the courts.54
In determining which facilities remain used and useful, regulators will have to
balance reliability and environmental effects as well as economics. They will also have to
address complex competing interests. For example, utilities supply power using a
combination of owned generation and purchases in the form of FERC-jurisdictional
power purchase agreements (PPAs), most of which are the product of regulatory
mandates. Federal law protects FERC-jurisdictional PPAs by requiring state regulators to
pass through the costs incurred by utility buyers in their retail rates.55 But this “trapped
cost” protection will be a two-edged sword for utilities that face premature retirement of
their own generation while continuing to pay third parties for purchased power. FERC
may therefore face a host of contract termination disputes. The transition will be made
more difficult by the fact that most utility-owned generation is subject to state regulation,
PPAs are regulated by FERC, and substantial generation is publicly owned and not
subject to traditional rate regulation.
Generation cost recovery is likely to be under pressure before transmission and
distribution. For the most part, the electric delivery system operates as an integrated
network, and it will be difficult to identify specific assets that are no longer required as
demand declines. Nonetheless, a substantial portion of the cost of electricity consists of
investments in transmission and distribution, and a regulator under pressure to reduce
rates would eventually have to pay attention to the cost of these facilities. Stranded
transmission and distribution cost issues will play out simultaneously at FERC (which
regulates most unbundled transmission) and in state proceedings (for bundled
transmission and local distribution) unless Congress changes jurisdictional
responsibilities.56

54

Assuming much of the utility industry will have moved into other business lines, including
distributed generation, legislators could be less inclined to provide full stranded cost relief in these
circumstances.
55
See Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 970 (1986); Entergy La., Inc. v. La.
Pub. Serv. Comm’n, 539 U.S. 39, 48 (2003).
56
In Texas, the Public Utility Commission of Texas (PUCT) regulates all of these functions. In other
states where retail rates remain bundled, states will have most of the control over this process for both
transmission and distribution assets, unless the FERC chooses (or is forced) to assume jurisdiction over
interstate transmission costs that are bundled into retail rates pursuant to the Supreme Court’s opinion in
New York v. FERC, 535 U.S. 1 (2002).
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Disputes will likely arise over which assets should be targeted for early retirement.
The interstate transmission grid, for example, is an integrated network of facilities owned
by a large number of entities.57 One can imagine a form of competition among
transmission asset owners to protect their assets and avoid stranded costs. Most publiclyowned transmission is not subject to FERC or state jurisdiction, which will further
complicate the process.
As this process unfolds, utility investors will be watching. As cost recovery
uncertainty rises, debt and equity investors will demand higher returns, making it more
expensive to maintain a reliable grid and putting further upward pressure on utility rates.
At some point, the risks could be large enough that investors will not provide capital on
acceptable commercial and regulatory terms, and investment in the grid will become
problematic, even as many consumers continue to rely on it.
B. Unregulated Generation
In regions where utilities have already divested their generation to merchant power
producers, capacity and energy is transacted in wholesale markets under the control of
RTOs, subject to overarching FERC regulation. Market forces will therefore play a
significant role in determining which generators survive as demand declines. The owners
of unregulated generation have assumed the market risk and are much less likely to have
valid stranded cost claims.
But electricity markets will only provide a partial solution. With recent reductions
in natural gas costs and flat demand, grid-connected generation is already under
considerable economic pressure, and regulators are being asked to approve additional
revenue streams to support reliability and new investment. In response to disputes over
market rules, regulators are making critical decisions on the economic margin. Therefore,
even where generation is subject to market forces, the future portends complex regulatory
disputes over how wholesale markets should be organized to respond to reductions in the
demand for energy from the grid. At the core of these disputes, an enduring tension will
exist between economics, reliability, and fairness.

57

FERC has recently decided that more entities should be eligible to build and own transmission
facilities. Transmission Planning and Cost Allocation by Transmission Owning and Operating Public
Utilities, Order No. 1000, FERC Stats. & Regs. ¶ 31,323 (2011), order on reh’g, Order No. 1000-A, 139
FERC ¶ 61,132, order on reh’g, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), appeal docketed, S.C.
Pub. Serv. Auth. v. FERC, No. 12-1232 (D.C. Cir. 2012).

50

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IV.

VOLUME 4

Conclusion

Once a sizable number of customers have invested in distributed generation in
response to the subsidies afforded under net metering, changing the economic rules will
be difficult, both because some customers will have relied on subsidies to make their
investments and others will want the same opportunities as their neighbors. Policymakers
therefore should not long defer addressing the consequences of providing these subsidies
in order to promote distributed generation over other alternatives. What may appear
politically attractive in its early stages can quickly become a regulatory and political
quagmire, as the Germans are learning. The U.S. will not countenance electric rates
anywhere close to German levels, nor an electric system that is not reliable. Over the long
term, any required unwinding of the utility-owned grid due to distributed generation will
be extraordinarily complex and will raise many novel and intractable legal and policy
issues.

51

 A Policy Framework for Designing
Distributed Generation Tariffs

Prepared by:
Edison Electric Institute

December 2013

 © 2013 by the Edison Electric Institute (EEI).
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 Edison Electric Institute - A Policy Framework for Designing Distributed Generation Tariffs

EXECUTIVE SUMMARY
It is a fundamental rule of electric utility regulation that customers should pay for the costs of the
services they receive from their utility and the electric power grid and should not pay for the costs of
services provided to other customers. This principle applies to the services electric utilities provide
to all customers, including customers with distributed generation (DG) systems. DG systems are
small-scale, on-site power sources located at or near customers’ homes or businesses. Some common
examples include solar panels, energy storage devices, fuel cells, microturbines, small wind turbines,
and combined heat and power systems.
The way utilities currently charge customers runs counter to this principle when customers are able
to dramatically curtail their electricity usage, as customers with DG systems (DG customers) can do.
Most of the costs of providing electric service to customers are recovered on a fixed-cost basis. The
costs of metering, billing, and call center support, plus the costs to support the grid infrastructure
(poles, wires, meters, other technologies, etc.) are largely the same regardless of how much
electricity a customer uses.1
However, utility rates are mostly volumetric – they are proportional to use. Consequently, utilities
must recover what are essentially fixed costs through rates that vary by usage. When customers
dramatically curtail usage, the fixed costs are not recovered from those customers and must be
recovered from other customers. Further, when DG customers are able to generate enough electricity
to offset all of their needs with some electricity left over, they can use the grid to sell any excess
electricity that they generate to electric utilities and are, in most cases, credited at the full retail price
for this electricity (i.e., retail price net metering). In these cases, the utility must pay the DG
customer for the fixed costs that the utility, not the customer, is incurring. Again, these costs get
shifted to other customers.
State rate policies for DG should be updated to ensure that everyone who uses the electric grid helps
pay to maintain it and to keep it operating reliably at all times. Any cost-shifting to non-DG
participating customers created by current rate design policy should be resolved. Otherwise, these
policies will result in increasing numbers of customers avoiding payment of the full cost of service,
with a decreasing number of customers assuming such costs. This is unfair and unsustainable over
the long-term.
Some DG stakeholders advocate that the utility costs shifted to other consumers represent
compensation for benefits, such as avoided emissions and jobs that DG customers provide to other
utility customers and/or society at large. Benefits specific to the utility should be determined using a
directly quantifiable approach that measures the net cost impact of DG to the utility. However, all
sources of electric generation provide jobs and economic benefits and many produce no emissions.
The value of such externalities should not be used in setting prices for power from DG unless these
costs reduce costs the utility incurs to serve customers.
1

E

While capacity-related costs are not strictly fixed, for most customers demand varies little and, for many practical
reasons, is treated as a fixed cost. For the purposes of this paper, these costs will be described as fixed.
1

 Edison Electric Institute - A Policy Framework for Designing Distributed Generation Tariffs

This paper is designed 1) to explain how certain policies enable utility DG customers to avoid paying
for the costs of critical delivery and support services that they use and 2) to provide alternative
approaches that fairly compensate such providers for their generation services, while also ensuring
that they continue to pay for the delivery and other services upon which they rely.
Section 1 more clearly defines the issue, explains cost causation and the cost-shifting problem, and
provides three examples to illustrate the problems that may arise under retail net metering as
customers install DG.
Section 2 identifies numerous alternative ratemaking approaches that would assure that DG
customers pay their share of the costs of the grid and would treat all customers in a fair, sustainable
manner. These include, for example, establishing a fixed charge for DG customers to ensure utility
recovery of the full cost of the use of the distribution system without cost shifting, and net metering
with bidirectional meters as well as various buy/sell arrangements.
Section 3 explains why payments for surplus power from distributed generators should reflect the
―
avoided cost‖ from the utility’s perspective. Section 3 also explains recent decisions by the Federal
Energy Regulatory Commission (FERC) that allow avoided cost to be determined separately for
renewable generation when states require the purchase of such renewable sources of power.
Distributed generation is an important part of the future of the electric utility industry. Through
economic ratemaking, we can help ensure the success of DG and the electric grid that makes it
possible and effective.

E

2

 Edison Electric Institute - A Policy Framework for Designing Distributed Generation Tariffs

SECTION 1
Defining the Issue
The National Academy of Engineering called the North American power grid the ―
supreme
engineering achievement of the 20th century.‖ Grid electricity has placed its stamp on the world,
changing the standard of living by introducing electricity to almost every facet of daily life. It has
fundamentally changed the way all customers experience the world. It powers everything from
homes, to businesses and industries, to the nation’s critical infrastructure. Grid electricity provides
value that far exceeds the actual cost of providing the service. 2 But unlike almost every other
business, it has been a longstanding policy in the electric utility industry to charge customers based
on the cost to provide a service, not on the value their customers receive.
While DG may be changing the way some utility customers interact with the grid, the same costbased approach used for all utility rates should apply to all customers who choose to install DG. As
such, rate design should reflect the utility’s cost-of-service and should be guided by the principle of
cost causation. Retail utility tariffs should be designed such that all customers, whether they are DG
customers or not, pay their share of the costs the utility incurs to serve them.

Cost Causation and the Cost-Shifting Problem
It is a fundamental rule of utility regulation that customers should pay for the costs of the services
they receive from a utility and not pay for the costs of services provided to other customers. Proper
cost allocation is essential to fair ratemaking and the avoidance of hidden cross-subsidies. Deviations
from this policy lead to distorted incentives and diseconomies that are not sustainable over time, as
demonstrated by recent experiences in Europe.
As the use of DG increases, many states are reviewing current policies to ensure that they do not
negatively impact electricity customers and the power grid upon which we all depend. Unlike
customers who use the grid only to buy power, customers with rooftop solar or other DG use the grid
both to buy and to sell electricity. Because of the way that some net metering policies were originally
designed, net-metered customers are credited for the power they generate usually at the full retail
electricity rate, which includes all of the fixed costs of the technologies and infrastructure that make
the electric grid safe, reliable, and able to accommodate solar panels and other DG. This paper refers
to that practice as ―
retail price net metering.‖
Through the credit they receive, DG customers effectively avoid paying the costs for using the grid.
As a result, these costs are shifted to those customers without rooftop solar or other DG systems
through higher utility bills, unfairly impacting many working families and businesses.

2

See ―
Lines Down‖ by Steve Mitnick (2013) for a more complete discussion of the value of grid electricity.
3

 Edison Electric Institute - A Policy Framework for Designing Distributed Generation Tariffs

Three examples below illustrate the problems that may arise as customers install DG. 3 Example 1
represents a utility customer who does not self-generate and uses 1,000 kilowatt-hours (kWh) of
electricity per month. Example 2 shows a utility customer with a DG system who net meters and
generates 1,000 kWh/month and also uses 1,000 kWh/month. (While this customer may take energy
from the utility at different times during the month, depending on the relationship between his load
and generation output, under net metering the customer’s meter would record zero at the end of the
month.) Example 3 shows the utility-customer transaction under a simultaneous buy-sell agreement,
in which a customer purchases 1,000 kWh/month from the utility and the utility purchases all of the
customer’s output (500 kWh in this example) from the customer’s DG system. The common element
in each example is that the customer purchases 1,000kWh/month from the utility.
In the first example, the costs to the utility and the amount billed to the customer are the same
($128.50).
In the second example, the costs to the utility are $93.50 4 (see second column), but the amount the
net-metered customer pays for those costs is only $11.50 (see fourth column). The difference
between the two ($82) represents costs the utility incurs to serve the customer that are not recovered
under net metering when the customer’s output is valued at the retail rate. Note, both customers still
purchase 1,000 kWh of electricity, but the net-metered customer pays much less, despite the fact that
he uses the grid both to buy and to sell power. Also note that the customer credit is much higher than
the value of the generation it is displacing.
This disparity occurs largely because many of the utility’s fixed costs of transmission, distribution,
and other charges are recovered through charges based on energy usage. As long as the net-metered
customer produces enough electricity at some time during the month to offset all of the electricity
used at other times during the month (i.e., net zero usage), the customer avoids paying for any of the
fixed costs of being connected to and supported by the utility grid. The customer may even avoid
paying for various social programs (e.g., low-income support). As a result, these costs are shifted to
other, non-net-metered customers. This dramatic imbalance between costs incurred and revenues
contributed is not in the public interest in terms of maintaining the long-term health and viability of
the grid.
The third example illustrates how these disparities can be avoided. There, the net-metered customer
pays his bill for 1,000 kWh, as would normally be the case, and simultaneously receives a payment
for 500 kWh of production from the DG unit, which is calculated on the wholesale value of the
power. Under this approach, the customer continues to pay for transmission, distribution, and public
benefit programs just like every other customer of the utility and is paid for the power that he
produces at the wholesale price.
This example illustrates how customers with DG can enjoy the benefits they associate with DG and
be compensated for the power that they produce.

3

4

Not included is an example of a customer with a DG system who chooses to become completely self-sufficient,
totally islanded from the grid. In this case, the customer is not connected to the grid, and the utility has no
obligation to serve and incurs no costs.
Note that there may be additional costs to serve DG customers (e.g., interconnection costs) that are not included in
this example.

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Example 1
Utility/Customer Cost Comparison
Residential Service
1,000 kWh Monthly Usage

Service

Cost to
utility/month to
provide
electricity service

Representative
rate

Generation Capacity

$40

$0.04/kWh*

Fixed costs/mortgage cost for having
generation capacity available to serve
customers.

Generation Fuel and
Purchased Power

$35

$0.035/kWh

Fuel and purchased power to serve customer
requirements.

Transmission

$5

$0.005/kWh*

Fixed costs/mortgage cost for having
transmission capacity available to serve
customers and support the grid, including
generation reserves.

Distribution

$30

$0.03/kWh*

Fixed costs/mortgage cost for having local
grid and customer-specific facilities available
to serve customers.

Metering

$3.50

$3.50

Cost to meter customer consumption.

Billing/Customer
Accounting

$7

$7

Costs associated with billing and customer
information systems.

Meter Reading

$1

$1

Cost to read meters, including communication
costs for Automated Metering Infrastructure.

System
Benefits/Public
Programs/EE/RPS**

$7

$0.007/kWh*

Cost of customer programs, such as lowincome support, and regulator-mandated
programs, such as energy efficiency programs
and renewable energy programs.

Total

$128.50

Description

*Fixed costs that are typically collected through volumetric charges in residential customer rates.
**EE refers to energy efficiency. RPS refers to renewable portfolio standard.

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 Edison Electric Institute - A Policy Framework for Designing Distributed Generation Tariffs

Example 2
Utility/Customer Cost Comparison
Residential Service for DG Customer
1,000 kWh Monthly Usage – 1,000 kWh Generated From DG System

Service

Cost to
utility/month to
provide electricity
service

Representative rate

Amount paid by
customer/month for
service

Service costs
shifted to nonDG
customers**

Generation Capacity

$40

$0.04/kWh*

$0

$40

Generation Fuel and
Purchased Power

$0

$0.035/kWh

$0

Transmission

$5

$0.005/kWh*

$0

$5

Distribution

$30

$0.03/kWh*

$0

$30

Metering

$3.50

$3.50

$3.50

$0

Billing/Customer
Accounting

$7

$7

$7

$0

Meter Reading

$1

$1

$1

$0

System
Benefits/Public
Programs/EE/RPS

$7

$0.007/kWh*

$0

$7

Total

$93.50

$11.50

$82

*Fixed costs that are typically collected through volumetric charges in residential customer rates.
**DG customers avoid paying these costs so customers without DG will ultimately pay the costs.

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 Edison Electric Institute - A Policy Framework for Designing Distributed Generation Tariffs

Example 3
Utility/Customer Cost Comparison
Residential Service for DG Customer Under Simultaneous Buy-Sell Agreement
1,000 kWh Monthly Usage – 500 Generated From DG System

Service

Cost to
utility/month to
provide electricity
service

Generation Capacity

Representative rate

Amount paid by
customer/month
for service

Service costs
shifted to non-DG
customers***

$40

$0.04/kWh*

$40

$0

Generation Fuel and
Purchased Power

$35

$0.035/kWh

$35

$0

Transmission

$5

$0.005/kWh*

$5

$0

Distribution

$30

$0.03/kWh*

$30

$0

Metering

$3.50

$3.50

$0

Billing/Customer
Accounting

$7.00

$7.00

$0

Meter Reading

$1

$1

$0

System
Benefits/Public
Programs/EE/RPS

$7

$0.007/kWh

$7

$0

$0.035/kWh

($17.50)

Generation Credit
Total

$128.50

$111.00**

$0

*Fixed costs that are typically collected through volumetric charges in residential customer rates.
**Assumes an avoided cost credit of 3.5 cents/kWh, the short-run generation fuel and purchased
power rate. Depending upon the utility, the credit could be higher or lower based on the avoided cost
of the fuel source assumed. Generation credit to customer is $17.50.
***Customers with DG avoid paying these costs so customers without DG ultimately will pay the
costs.

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Charging customers with DG according to a retail price net metering arrangement runs counter to
cost causation principles that are the foundation of ratemaking. Such a plan credits the net-metered
customer at the full retail rate of electricity when that customer generates electricity. This overcompensates the customer by crediting the customer for all of the delivery and grid services provided
by the electric utility, when the customer generation provided to the utility accounts for only a small
part of those services—wholesale generation. As described below, not only does net metering shift a
portion of the DG customer’s allocated share of fixed costs of grid service to other customers, it also
increases the variable energy costs the utility incurs to serve those other customers.5
Further, a DG customer is leaning on the utility system to reverse power flows and is imposing more
expenses for the system than generally appear on a customer’s bill. The determination of whether the
customer with a DG system is generating more than he uses is generally made over a period of time,
such as a month. However, when dissected further, it becomes clear that, on a minute-by-minute
basis, the customer with a DG system is generating more than he uses for a much greater percentage
of the time than might show up on a monthly total. Much of this loss of detail in tracking generation
flows is avoided if the customer with a DG system has a two-meter or two-way system and operates
under a rate scheme that accounts for both sales and purchases, such as the buy-sell agreement
described in Example 3.
Example 2 highlights the resulting mismatch. Under retail price net metering, the utility would pay
the customer with a DG system, on average, 12.05 cents/kWh for every kWh the customer generated
in excess of the customer’s use at any one time, when the utility could purchase that same amount of
power from other sources within a typical price range of 3.0 cents/kWh to 6.5 cents/kWh. The other
customers on the system pay the difference. However, this does not capture the full impact of the
difference, because the samples above use average prices for the sake of simplicity. For many
utilities, costs to serve and costs recovered from customers vary by time blocks. For example, solar is
strongest during on-peak time blocks in which both the system price and the retail rate are above
average.
Some analysts might argue that it is appropriate to pay DG solar customers these high amounts
because solar offers benefits to the utility system. For example, solar helps trim peak demand and, as
observed in the example, many of the utility costs are driven by peak demand. However, while solar
generally produces electricity during periods with above-average demand, its efficacy decreases
dramatically during peak periods. Moreover, the warmer the climate, the later electricity usage peaks
in general, thus moving the system peak further away from the early afternoon peak for solar. As an
illustration of this, utility planners would likely plan for about 2 kilowatts (kW) of contribution to
system demand for 5 kW solar systems due to the variable nature of the resource and the lack of
coincidence with utility system peak.
5

The examples assume the customer generates an amount of electricity equal to or less than the customer’s monthly
use. What if the customer was to generate more electricity than he used? Currently customers with DG are almost
exclusively compensated according to a net metering paradigm that, in essence, runs the meter backward when the
customer is generating more electricity than is being used and forward when the customer is using more electricity
than is being generated. Consequently, if the DG customer was to generate more than he uses, the utility might pay
the customer a credit or some other form of compensation. Terms and conditions for this overall net metering
scheme vary from utility to utility, but this is the basic plan currently followed for compensating customers with
DG that are net sellers.

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Most of the other claims of the benefits of solar to utilities prove similarly weak on closer
examination. This is evidenced by utilities’ ability to buy solar power, with most of its claimed
benefits, on the open market for small multiples of the prices claimed by some analysts.
The buy-sell arrangement illustrated in Example 3 shows one approach to solve the problems of
retail price net metering. In this example, the customer is credited with the wholesale value of his
generation, but continues to pay for the transmission, distribution, and other services he receives
from the utility. Here, the utility continues to receive payments for generation because it continues to
provide power to the customer. Moreover, the utility has an obligation, as directed by its state public
utility commission (PUC), to provide those services should the customer’s DG system not perform
because of intermittency or fail for other reasons.6
Other Complications
The analysis above reveals how retail price net metering can fail to recover the costs of providing
grid services to DG customers. Yet, providing service to DG customers is more complex and costly
for utilities than providing service to customers lacking self-generation.
DG customers require services beyond those of non-DG customers. For example, DG customers
often require advanced metering capabilities and enhanced billing services. These services are more
expensive than standard services. The utility will likely also need to offer interconnection services
that allow DG customers to access the grid and market, including engineering and design studies to
properly design interconnection for these customers. Because utility rates currently recover many of
these fixed distribution costs in variable kWh charges, if retail price net metering is applied, utilities
will not recover these additional costs from DG customers, thus shifting these costs to other
customers.
DG customers also have the potential to provide some benefits to the grid. Some DG stakeholders
advocate that the utility costs shifted to other consumers represent compensation for benefits, such as
avoided emissions and jobs that DG customers provide to other utility customers and/or society at
large. Benefits specific to the utility should be determined using a directly quantifiable approach that
measures the net cost impact of DG to the utility. However, all sources of electric generation provide
jobs and economic benefits and many produce no emissions. The value of such externalities should
not be used in setting prices for power from DG unless these costs are measureable and reduce the
costs the utility incurs to serve customers. It would be just as unfair—to the extent that those benefits
have a direct effect on reducing the utility’s revenue requirement—to shift those benefits to non-DG

6

The value of that capacity is dependent on a number of factors. If a utility has excess capacity, the value of the
incremental capacity any individual customer with DG offsets is effectively zero. In aggregate, there are some
reductions in system requirements, and, in jurisdictions with capacity markets, there is a fairly transparent value,
which is probably not zero. But the aggregate value is very circumstantial. Further, the utility’s purchase of DG
generation is no different than the utility’s purchase of generation on the wholesale market. The contractual
wholesale market price takes into account all of the costs incurred and saved by the utility in the transaction. These
contractual wholesale transactions usually include performance clauses that specify conditions that customers with
DG currently do not need to meet. Absent those performance clauses, the price of that generation would be heavily
discounted.

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customers as it is unfair to shift those costs of DG that have the effect of increasing the utility’s
revenue requirement to non-DG customers.
Verified costs and benefits that directly affect the utility’s revenue requirement—or the total cost of
providing grid electricity to all customers, both DG and non-DG—should be accounted for and fairly
allocated as part of the regulatory process. These may include, for example, the avoided costs of
upgrading transmission or distribution facilities.
DG advocates believe that crediting DG customers the full retail rate compensates those customers
for the additional benefits that DG conveys to the system. However, given that 43 states and the
District of Columbia have some form of net metering and, further, given that not all DG is alike in
terms of environmental benefits and other qualities, it is unlikely that the full retail rate in each of
these jurisdictions matches the verifiable cost savings that DG provides to the utility and its non-DG
customers. Consequently, this ―
rough justice‖ perspective is often called into question.
Importantly, many of the benefits often associated with DG do not directly affect utility revenue
requirements. The benefits most often mentioned are externalities that accrue to society more
generally. Externality values are the most difficult to model and are currently not reflected directly in
the utility pricing model. They should not be accounted for in utility rates.
Distributed generation is an important part of the future of the electric utility industry. Through
economic ratemaking, we can help ensure the success of DG and the electric grid that makes it
possible and effective.

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SECTION 2
Alternative Rate Structures for Distributed Generation Customers
For decades, electricity customers have had the ability to own and to operate generating facilities on
their premises, including combined heat and power plants in factories, backup turbine generators in
commercial buildings, and solar panels on the roofs of commercial facilities. Electric utilities always
have had rate designs for purchasing power from these energy resources. In recent years, there has
been growing interest in using small versions of these resources, known as distributed generation,
which connect directly to the distribution network rather than the higher-voltage transmission grid,
and more widespread adoption by residential and small general service customers. The rates for
service to these customers are primarily regulated by state commissions.
Traditionally, rates that had been designed for residential and commercial customers, when their use
of these resources was relatively uncommon, were designed for simplicity, rather than in strict
accord with principles of cost causation. If customers on these rates who installed DG systems were
over-compensated for the electricity that they sold back to the local utility, the impact on other
customers was negligible, because the amount of electricity purchased was insignificant.
With more widespread adoption of DG by more customers, the incorrect pricing of net-metered DG
power has resulted in a tangible increase in electricity costs to other customers. To address this,
many utilities have adopted new approaches to designing rates for DG. This section describes some
of the new approaches that have been implemented, along with the particular issues or design
questions that might guide a utility’s or state commission’s choice to adopt one approach rather than
another.

General Rate Design Approaches for Purchases of Customer-Provided Electricity
Retail Price Net Metering

A common rate design used to compensate residential customers (and small general service
customers) for power provided from onsite electricity generation facilities is retail price net
metering, as discussed in Section 1. In its most common form, this type of rate enables customers to
retain their regular meter. When power is being provided from onsite generation, the electric meter
slows or—in cases where onsite electricity generation is exceeding what a customer is actually
using—actually runs backwards. With customer usage being recorded by the traditional, single
standard interval meter, the utility is incapable of knowing how much electricity the customer
actually produced. Hence, a customer on this rate is simply billed for net electricity consumed. In
those cases when net electricity usage is negative (because the customer produced more power
during a billing period than was consumed), it is standard practice to carry this forward to future bills
as an energy or financial credit, rather than to actually send a payment to the customer. Even in those
billing periods where there is a net electricity surplus, the customer may still receive a fixed charge
for service, which is generally equivalent to the fixed customer and/or demand charges that are part
of the standard rate design.

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Initially, the simplicity of the rate design, and the fact that no additional metering equipment was
required to support it, made net metering attractive. The fundamental flaw in this approach stems
from the fact that, by paying the customer for the full retail rate of electricity, the customer is
invariably being paid for more than merely the electricity he generates and delivers to the utility. To
the extent that a utility is recovering its fixed costs of service in the volumetric (i.e., per kilowatthour) portion of the retail rate, then the utility is actually paying, rather than charging, the customer
with DG for its delivery and grid services whenever the customer is supplying electricity. Moreover,
the advent of smart meters has made the process of tracking customer use and sales much simpler
and more cost-effective.
Responses to Retail Price Net Metering

Many utilities, in addressing this issue, have elected to view this as more of a problem stemming
from rate design, rather than net metering itself. If a utility can collect all or most of its fixed charges
of service in a fixed customer charge and/or monthly demand charge, much of the cost
misallocations stemming from retail price net metering disappear. With a rate design more closely
aligned with cost causation, in cases where a customer generates a net surplus of electricity in any
billing period, that customer still would be billed for the fixed costs of service and only would be
compensated for the electricity ―
commodity.‖ Therefore, many electric distribution companies have
moved toward fixed/variable rate designs that include larger fixed monthly customer charges that are
more proportional to fixed costs. In lieu of a general redesign of rates, if DG tariffs at least have a
larger fixed monthly charge, then cost recovery and subsidization problems stemming from net
metering can be mitigated.
There is still a potential problem, however, when fixed costs are passed on to customers in the form
of a demand charge, because demand charges are usually set based upon a customer’s peak
electricity usage and/or demand only during peak periods. If a customer has reduced peak demand
(measured as peak net energy consumption) because of onsite generation facilities, then the
computed demand charge may understate the system capacity that the customer is still actually using
during other hours. On the other hand, customers with onsite generation might contend that this
―
phantom capacity‖ should not be provided at the conventional full retail rate, since it is now rarely
used, if ever, and has really become only a standby service. This issue has been less predominant
with residential net metering rates, since standard residential rate designs generally consist of a
customer charge only to recover fixed costs of service and no demand charge. The issue is also less
predominant with variable energy resources, such as solar or wind, since these resources tend to have
a limited impact on reducing a customer’s peak demand and consequent demand charges, although
this could change when more efficient and affordable electricity storage systems begin to accompany
onsite variable resources.
Net Metering with Separate Compensation for Electricity Exports

One approach to mitigating the cost mismatch inherent in net metering is to establish a fair value rate
for net electricity provided to the utility and to apply this rate to the purchase of that electricity. If a
standard meter is being used, this could only be done in billing months where total electricity
produced by the customer exceeded total electricity consumed, and the special rate would be applied
to the excess. However, if a meter is required that is capable of separately measuring total energy
exported, then this rate could be applied for all energy supplied to the utility by the customer during
the billing period. In either case, the customer still would be billed under the standard applicable

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retail rate for net energy consumed. While this approach provides the utility with the flexibility to set
a price on the surplus electricity that it receives from the customer, it does not completely remedy the
cost mismatch problem. When a customer’s self-generation is merely reducing net consumption,
then the amount being reduced still is being credited essentially at the full retail rate.
Net Metering with Bidirectional Meters

Another approach to rectifying the cost mismatch described above is to require the use of a meter
capable of measuring both total energy consumption and total energy production. With the use of
such meters, the most common approach to net metering is to bill the customer under the standard
applicable retail rate for all energy consumed, and then to deduct from this bill a credit for energy
supplied by the customer at a price that is established by the utility and that is intended to represent
the fair value of the electricity that is purchased. The advantage to this approach is that it ensures that
the customer will pay all fixed costs of service, including demand charges, which will continue to be
calculated based upon the customer’s total energy consumption. This approach provides the utility
with the flexibility to set a price on the electricity that it buys back from the customer. Another
benefit to this approach is that it obviates the need to fundamentally redesign the standard retail rates
in order to better align fixed costs of service with fixed customer charges.
Buy/Sell Tariffs

Another approach, which is a variant of the previous one, is to put customers with DG systems on
special rates for both electricity purchases and electricity sales, rather than to continue to bill the
customer for total consumption under a standard retail rate. Base service is provided under a
―
parallel generation‖ tariff that includes a fixed monthly customer charge, a demand charge, a
―
standby‖ charge, and energy charges for electricity delivered. Electricity is sold back to the utility
under a ―
purchased power‖ tariff, which consists of an administrative charge, an interconnection
facilities charge, and credits for both capacity and energy delivered. Customers may be provided
with the option to supply electricity under a fixed contract rate, a variable rate, or a combination of
both.
Contract Energy Purchases

The most sophisticated approach is to mimic the tariff designs that have been in place for years to
purchase power from qualifying facilities (QFs) as defined by the Public Utility Regulatory Policies
Act (PURPA). Under this arrangement, the customer is treated as a wholesale electricity provider
and is put under a sales contract for the purchase of electricity, and often capacity as well. Any
electricity that the customer receives from the utility is treated as firm or interruptible backup power,
and the customer must contract for it accordingly. Typical options include firm or interruptible
maintenance power for planned outages and firm or interruptible standby power for unscheduled
outages. These arrangements are often limited to larger general service customers and/or customers
who are providing all or nearly all of their electricity needs.
Common Design Parameters

Each of the following design parameters occurs in one or more of the alternative approaches
described below:


Tariff structure: Net metering or energy sales arrangements may be made available as (1) a
rider within the standard residential or general service tariff, (2) an auxiliary tariff that is
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linked to the standard one, or (3) a separate standalone tariff with all rates, charges, and
conditions for both purchases and sales of electricity fully specified.


Treatment of metering costs: If a bidirectional meter is required, cost recovery for the
meter must be specified. Some utilities require that customers pay for meter upgrades
upfront. Others opt for cost recovery through a fixed monthly charge, and others simply
absorb the cost of the meter, with no explicit cost responsibility assigned to the customer. In
all cases, however, costs for any system upgrades that are determined to be over and above
what is usually required to support the installation and interconnection of DG facilities are
borne by the customer, either as a direct, upfront expense, or as a contribution or revenue
guarantee in aid of construction.



Purchase rate(s) for customer-provided generation: A critical component of any DG tariff
is the assignment of a purchase rate for electricity provided by the customer. A fundamental
design parameter is whether these purchase rates will be identical to the corresponding rates
for electricity provided by the utility, or whether they will be different. Following are some
of the standard purchase rate assignments:
o The energy (per kilowatt-hour) rate that is part of the standard tariff. This is the
compensation rate associated with most traditional net metering designs. As
described above, unless a utility has designed its standard tariff to recover all of its
fixed costs of service in fixed monthly customer and/or demand charges, this energy
rate will result in insufficient recovery of fixed costs, which then must be subsidized
by other customers.
o Variable energy charges, specified by the company. These rates generally are
designed to correspond to the projected, forward-looking electricity production
and/or purchase costs faced by the utility. As such, each rate represents an ―
avoided
energy‖ cost, though a projected one, rather than an actual one. Multiple rates may be
specified to correspond to peak and off-peak periods, weekdays vs. weekends, and
different seasons. The schedule of rates is periodically updated to reflect changing
cost projections.
o Fixed energy charges. Some tariff designs allow customers to lock into a long-term
fixed rate, usually as part of a contract for service. While these energy charges might
be intended to correspond to long-term projected wholesale electricity prices, some
utilities offer a premium, above-market rate as an incentive to support renewable DG,
which is essentially a feed-in tariff.
o True avoided-cost energy charges. These tariff designs attempt to compensate
customers for the actual avoided energy costs that corresponded to the energy that
they provided during each billing period. Simpler designs merely calculate an
average wholesale cost of electricity for the billing period just ended, and apply this
rate to the energy provided; more sophisticated designs attempt to assign an avoided
cost based on the actual time periods (e.g., on-peak vs. off-peak) that the energy was
provided within, and the most advanced designs estimate avoided costs based on the
real-time cost of electricity. This last design most closely resembles the method used
by many utilities to compensate QFs under PURPA in electricity purchase
arrangements. A common index used to establish the real-time cost of wholesale

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electricity within organized markets under these arrangements is the day-ahead or
real-time hourly locational marginal price.


Compensation for non-energy services: Some rate designs compensate customers for more
than merely the energy provided. These are usually payments for capacity, and occur in
jurisdictions where markets for electricity capacity exist. Hence, a real value to the capacity
can be assigned. Customers often are paid for renewable energy credits as well.



Interconnection standards, codes, and guidelines: The rules, regulations, and procedures
under which a customer installs a DG source and integrates it within the electrical system
must be clearly outlined and specified, including any special equipment requirements for
which the customer is responsible. Interconnection rules generally appear as a section in the
rules and regulations section of a utility’s tariff, although sometimes they are included in a
contract for service that the customer signs as a condition for entering into a net metering or
electricity repurchase arrangement. The breadth and specificity of interconnection rules vary
widely among utilities, ranging from a few paragraphs to more than a hundred pages in
length.



Service options based upon customer and/or DG facility size: Features of the electricity
tariff, including the general rate design offered, the energy buy-back rate, the magnitude of
fixed and demand charges, metering requirements, and the imposition of metering or other
installation costs, often vary based upon one or more of the following parameters:
o Customer class (residential, small general service, large general service);
o Size of the DG facilities;
o Size of customer (e.g., contract demand in kW); and
o Service delivery point (distribution or transmission).

For example, many utilities do not charge residential customers for bidirectional or other advanced
metering requirements, but do charge general service customers for these meters. In general,
residential DG tariffs tend to be less complex than those offered for classes of larger customers.
Also, many DG options are only made available to customers with facilities below a certain size.

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SECTION 3
Alternative Approaches to Determining Payments to DG Customers
When a utility obtains surplus power from a distributed generator for resale to another customer, it is
essentially engaging in a wholesale transaction. Thus, the value of the power is what power of
comparable quality and certainty would be in the wholesale market. In practice, since many DG
providers are QFs under PURPA, it is appropriate to understand how PURPA’s concept of ―
avoided
cost‖ applies.
PURPA requires utilities to interconnect with, buy power from, and sell power to QFs. Utilities must
purchase power from the QFs at rates that are just and reasonable to electricity consumers, are in the
public interest, do not discriminate against owners and operators of QFs, and do not exceed the costs
the purchasing utility actually avoids. QFs are defined to include only cogeneration facilities and
certain small power production facilities (namely, ones up to 80 megawatts that rely on biomass,
waste, renewable resources, or geothermal resources).
To qualify, the facilities must meet fuel use, fuel efficiency, reliability, and other requirements set by
FERC, and must be owned by persons not primarily engaged in the generation or sale of electric
power other than from such facilities. Avoided cost is defined as the cost to the utility of energy that
―
but for the purchase of electricity from such cogenerator or small power producer such utility would
generate or purchase from another source.‖7
Often avoided costs are determined administratively by state PUCs, with oversight by FERC. In such
cases, regulators need to exercise caution not to overestimate the costs in order to avoid
inappropriately increasing the rates utilities and their customers must pay for power from QFs. When
PURPA was passed, and for many decades thereafter, avoided cost was understood to mean that if a
utility had more generating capacity than it needed to meet its peak demand, its avoided cost was the
short-run marginal cost of additional fuel needed to generate an additional kWh of power. If the
utility was short on generating capacity, avoided cost meant the long-run marginal cost of the most
economic source of new supply.
Yet in recent years, some state regulators have included in avoided costs both the long-run marginal
costs of adding new generating capacity and the short-run fuel cost of operating existing capacity.
State regulators also have based avoided cost estimates on technology with high capital costs (e.g.,
nuclear and baseload coal) instead of on technology with low capital costs (e.g., natural gas-fired
peakers).
In a 2010 order clarifying its PURPA regulations, FERC determined that in estimating avoided costs,
states can recognize constraints on utility purchases of energy and capacity created by state
requirements to purchase certain amounts of renewable energy. 8 This amounts to an

7
8

16 U.S.C. 824a-3.
California Public Utilities Commission, 133 FERC ¶ 61,059 (2010), reh’g denied 134 FERC ¶ 61,044 (2011).
16

 Edison Electric Institute - A Policy Framework for Designing Distributed Generation Tariffs

acknowledgement that renewable resources are frequently more expensive than other supply options
(e.g., natural gas-fired generation). If state renewable mandates raise utility costs, FERC says it is
acceptable to reflect this in QF purchase rates.
In the same ―
clarifying‖ order, FERC also determined that states could administer ―
tiered‖ avoided
costs.9 This means that rather than estimate the true marginal cost of new supply on the utility’s
system,10 states can impose multiple avoided costs, one each for a set of discrete technologies. If a
state has legislated mandates for discrete renewable energy source technologies (e.g., wind,
distributed photovoltaic, central station photovoltaic, fuel cells, biomass-derived synthetic fuels), the
state can administer an avoided cost for each. Where the cost of most of these technologies is above
market (i.e., above the clearing prices that come out of organized wholesale markets in which all
generation types are allowed to bid), the effect of this kind of avoided cost unbundling is to raise the
prices utilities pay for renewable power.
FERC also determined that states could factor in any ―
real costs‖ that utilities face in purchasing
11
energy and capacity. What FERC may have had in mind in elaborating this factor was the cost of
new transmission lines needed to bring wind power from the places where the wind blows to the
places where people live. These are huge additional costs, which in many cases would not be
incurred but for the state renewable resource mandates. Again, FERC enlarged the concept of
avoided cost to pass these costs on to consumers.
All three of these determinations represent a potentially costly (for utilities and consumers) evolution
in regulatory policy away from the original understanding of avoided cost, which was simply the
incremental cost of the most economic source of additional supply to the utility. FERC’s 2010
determinations mean that avoided cost can now be used as a tool to promote renewable resources,
regardless of the cost, when combined with renewable portfolio requirements in a low-growth
environment.
To compound matters, FERC recently determined that utilities might not unilaterally curtail QF
purchases governed by power purchase agreements during periods when electricity usage is low and
the utilities do not need QF power, presumably absent explicit contractual rights to curtail the
purchases in such circumstances. Impliedly according to FERC in such cases, PURPA requires
utilities to buy QF power—and customers to pay for it—whether the utility needs the power or not.12

Social Pricing Is Incompatible with the Regulatory Compact
Many DG advocates argue that the benefits DG installations provide to utility systems and to society
are very large and that such benefits should be used to offset a substantial portion of the costs
utilities incur to serve DG customers. In effect, this is an argument that the benefits of DG should be
priced on the basis of its value, while the benefits of electricity service should be priced based on its
cost.

9

Ibid.
A utility has only one marginal cost of supply.
11
Same as footnote 2, supra.
12
Idaho Wind Partners 1, LLC, 140 FERC ¶ 61,219 (2012).
10

17

 Edison Electric Institute - A Policy Framework for Designing Distributed Generation Tariffs

This is mixing apples and oranges. Rate-regulated utilities are able to recover only those actual costs
that the utilities experience during ―
test years.‖ These costs make their way into required revenues
and are recovered in rates controlled by state regulatory commissions. This is the construct that
investors rely on when they provide capital to investor-owned electric utilities. This also is the
construct assumed in U.S. Supreme Court decisions establishing standards for just and reasonable
rates. Utilities use a variety of fuels that produce no air or climate emissions and produce many jobs,
but the value of such benefits should not be included in rates for DG power unless these types of
costs are already included in utility rates for power produced from renewable, hydro, nuclear, or
other non-emitting generation.

Payments to Customers with DG Should Be Based on Directly Measurable Avoided Costs
from the Utility’s Perspective
It follows that to the extent to which distributed generators provide benefits to the utility such
benefits should be measured and compensated in terms of reductions in the utility’s cost of service.
This can include reductions in fixed costs (e.g., generating, transmission, and distribution capacity)
that the utility may avoid or defer because of the presence of a distributed generator on its system. It
also can include reductions in variable costs (e.g., fuel) that the utility may avoid. However, it should
not include the value of other benefits (e.g., job creation) that do not reduce the utility’s revenue
requirements. Such benefits relate to costs that are presently outside (external to) the cost-of-service
system. Indeed, they are external to the entire market economy.

18

 February 
  20, 
  2014 
  
 
  
Katrina 
  Pielli, 
  US 
  Department 
  of 
  Energy 
  
Senior 
  Policy 
  Advisor 
  to 
  the 
  Deputy 
  Assistant 
  Secretary 
  for 
  Energy 
  Efficiency, 
   
  
Advanced 
  Manufacturing 
  Office 
  Deployment 
  Acting 
  Supervisor 
  
 
  
RE: 
  Comments 
  on 
  Barriers 
  to 
  Industrial 
  Energy 
  Efficiency 
  
 
  
Dear 
  Katrina: 
  
Thank 
  you 
  for 
  the 
  opportunity 
  to 
  comment 
  on 
  the 
  Department 
  of 
  Energy 
  (DOE) 
  report 
  entitled 
  Barriers 
  
to 
  Industrial 
  Energy 
  Efficiency. 
   
  Be 
  assured 
  that 
  National 
  Association 
  of 
  Regulatory 
  Utility 
  Commissioners 
  
(NARUC), 
  National 
  Rural 
  Electric 
  Cooperative 
  Association 
  (NRECA), 
  and 
  the 
  Edison 
  Electric 
  Institute 
  (EEI) 
  
support 
  increased 
  industrial 
  energy 
  efficiency 
  (IEE), 
  cost 
  effective 
  combined 
  heat 
  and 
  power 
  systems 
  
(CHP) 
  and 
  increased 
  industrial 
  competiveness. 
   
  In 
  fact, 
  the 
  vast 
  majority 
  of 
  NRECA 
  and 
  EEI 
  members 
  
have 
  very 
  active 
  energy 
  efficiency 
  programs 
  which 
  are 
  overseen 
  by 
  NARUC 
  members. 
   
  Moreover, 
  both 
  
NRECA 
  and 
  EEI 
  support 
  NARUC 
  resolutions 
  calling 
  for 
  CHP 
  development 
  that 
  is 
  safe, 
  cost-­‐effective, 
  
nondiscriminatory, 
  and 
  reasonably 
  priced. 
  (Resolution 
  to 
  Encourage 
  the 
  Use 
  of 
  Combined 
  Heat 
  and 
  
Power, 
  including 
  the 
  Recycling 
  of 
  Waste 
  Energy, 
  February 
  20, 
  2008; 
  Resolution 
  in 
  Support 
  of 
  the 
  
Deployment 
  of 
  Combined 
  Heat 
  and 
  Power, 
  November 
  14, 
  2012) 
   
   
  
 
  
State 
  commissions 
  have 
  jurisdiction 
  over 
  generation 
  and 
  have 
  jurisdiction 
  over 
  utility 
  programs 
  for 
  the 
  
deployment 
  of 
  energy 
  efficiency, 
  demand 
  side 
  management, 
  and 
  distributed 
  generation. 
   
  State 
  
commissions 
  ensure 
  safe, 
  reliable 
  and 
  affordable 
  electric 
  service 
  and 
  face 
  differing 
  demographics, 
  
geographies, 
  and 
  market 
  structures, 
  and 
  what 
  is 
  appropriate 
  in 
  one 
  jurisdiction 
  is 
  not 
  appropriate 
  in 
  
others. 
   
  While 
  the 
  role 
  of 
  State 
  commissions 
  is 
  somewhat 
  acknowledged 
  in 
  the 
  report, 
  none 
  of 
  the 
  
recommendations 
  included 
  in 
  the 
  report 
  should 
  direct 
  State 
  commissions 
  to 
  do 
  any 
  more 
  than 
  “consider 
  
the 
  adoption 
  of” 
  regulatory 
  policies 
  and 
  all 
  should 
  be 
  qualified 
  with 
  “protecting 
  consumers.” 
   
  Generally, 
  
the 
  recommendation 
  section 
  as 
  directed 
  to 
  State 
  commissions 
  is 
  too 
  prescriptive. 
  
 
  
With 
  regard 
  to 
  CHP 
  in 
  particular, 
   
  NARUC’s 
   
  resolutions 
  (attached) 
  stress 
  the 
  need 
  for 
  cost-­‐effectiveness 
  
in 
  promoting 
  CHP 
  , 
  as 
  well 
  as 
  the 
  need 
  to 
  protect 
  consumers 
  when 
  addressing 
  CHP 
  barriers 
  to 
  increased 
  

 use 
  of 
  CHP 
  related 
  to 
  standby 
  rate 
  design, 
  interconnection 
  and 
  traditional 
  utility 
  revenue 
  recovery 
  
mechanisms. 
   
  Less 
  prescriptive 
  language 
  in 
  the 
  recommendation 
  section 
  would 
  better 
  reflect 
  these 
  
needs. 
   
   
  
 
  
After 
  reviewing 
  the 
  report, 
  we 
  believe 
  the 
  draft 
  includes 
  a 
  number 
  of 
  recommendations 
  that 
  can 
  further 
  
these 
  important 
  goals 
  and 
  objectives. 
   
  Having 
  said 
  that, 
  we 
  are 
  substantially 
  concerned 
  with 
  several 
  
aspects 
  of 
  the 
  current 
  draft 
  that 
  we 
  believe 
  would 
  undermine 
  those 
  goals 
  and 
  reduce 
  industrial 
  
competiveness 
  and 
  energy 
  productivity. 
   
   
  To 
  wit: 
   
   
  
•

The 
  study, 
  incorrectly, 
  we 
  believe, 
  presumes 
  that 
  all 
  industrial 
  IEE 
  and 
  CHP 
  is 
  per 
  se 
  beneficial, 
  
and 
  all 
  obstacles 
  to 
  increase 
  deployment 
  are 
  by 
  definition, 
  arbitrary, 
  meritless 
  and 
  should 
  be 
  
eliminated 
  -­‐-­‐-­‐ 
  such 
  is 
  clearly 
  not 
  the 
  case 
  

•

The 
  study 
  repeatedly 
  calls 
  the 
  absence 
  of 
  incentives 
  and 
  the 
  absence 
  of 
  mandates 
  “barriers” 
  
that 
  DOE 
  should 
  address-­‐-­‐-­‐yet 
  cost-­‐effective 
  IEE 
  and 
  CHP 
  may 
  not 
  need 
  such 
  incentives 
  or 
  
mandates 
  

•

It 
  calls 
  upon 
  States 
  to 
  establish 
  policies 
  that 
  provide 
   
  incentives 
  and 
  support 
  to 
  IEE 
  without 
  the 
  
need 
  to 
  have 
  the 
  States 
  review 
  whether 
  or 
  not 
  the 
  IEE 
  is 
  cost 
  effective, 
  reliable, 
  and 
  supports 
  
the 
  individual 
  goals 
  and 
  objectives 
  of 
  the 
  state, 
   
  including 
  fairness 
  to 
  all 
  consumers 
  

•

The 
  study 
  fails 
  to 
  make 
  clear 
  that 
  to 
  maximize 
  efficiency, 
  CHP 
  must 
  be 
  sized 
  to 
  support 
  process 
  
thermal 
  load 
  and 
  as 
  a 
  result 
  most 
  often 
  does 
  not 
  generate 
  enough 
  excess 
  power 
  to 
  sell 
  to 
  the 
  
grid 
  – 
  and, 
  conversely, 
  if 
  CHP 
  is 
  sized 
  to 
  generate 
  excess 
  power 
  for 
  sale, 
  or 
  provide 
  ancillary 
  
services, 
  overall 
  CHP 
  efficiency 
  can 
  be 
  significantly 
  reduced. 
  (EPA 
  CHP 
  Project 
  Development 
  
Handbook, 
  page 
  14 
  http://www.epa.gov/chp/documents/chp_handbook.pdf) 
  

•

The 
  study, 
  by 
  comparing 
  the 
  efficiency 
  of 
  existing 
  generation 
  with 
  state 
  of 
  the 
  art 
  CHP, 
  fails 
  to 
  
make 
  clear 
  that 
  the 
  difference 
  in 
  efficiency 
  between 
  state 
  of 
  the 
  art 
  electric 
  generation 
  and 
  CHP 
  
has 
  been 
  significantly 
  narrowed-­‐-­‐e.g. 
  new 
  natural 
  gas 
  combined 
  cycle 
  plants 
  with 
  a 
  60% 
  overall 
  
efficiency 
  

 
  
We 
  believe 
  cost 
  effective 
  IEE 
  and 
  CHP 
  can 
  bring 
  potential 
  benefits 
  to 
  consumers, 
  industrial 
  
competiveness, 
  and 
  utilities, 
  and 
  we 
  support 
  efforts 
  to 
  increase 
  IEE 
  and 
  CHP. 
   
  However 
  these 
  
benefits 
  will 
  only 
  be 
  realized 
  through 
  policies 
  that 
  encourage 
  cost-­‐effective 
  development, 
  do 
  not 
  
unfairly 
  shift 
  costs 
  among 
  customers, 
  and 
  do 
  not 
  risk 
  degrading 
  electric 
  reliability 
  or 
  safety. 
   
  As 
  
indicated 
  above, 
  we 
  do 
  not 
  believe 
  the 
  current 
  draft 
  of 
  the 
  report 
  has 
  met 
  this 
  requirement. 
  

  
  
In 
  addition 
  to 
  the 
  above, 
  we 
  would 
  like 
  to 
  attach 
  by 
  reference 
  our 
  earlier 
  comments 
  this 
  past 
  
summer. 
   
  
 
  
Again 
  we 
  agree 
  with 
  and 
  support 
  the 
  goals 
  of 
  increasing 
  industrial 
  energy 
  efficiency; 
  increasing 
  
system 
  reliability 
  and 
  resilience; 
  helping 
  industrial 
  customers 
  reduce 
  energy 
  cost 
  to 
  assist 
  in 
  
increasing 
  U.S. 
  competiveness; 
  and 
  doing 
  so 
  without 
  the 
  need 
  to 
  have 
  subsidies 
  and 
  mandates 
  that 
  
will 
  only 
  increase 
  cost 
  to 
  other 
  consumers 
  and 
  promote 
  sub 
  optimal 
  solutions. 
   
   
  
 
  
 
  

 
  
 
  
/s/James 
  Bradford 
  Ramsay 
  
James 
  Bradford 
  Ramsay 
  
General 
  Counsel 
  
 
  
/s/Holly 
  Rachel 
  Smith, 
  Esq. 
  
Holly 
  Rachel 
  Smith, 
  Esq. 
  
Assistant 
  General 
  Counsel 
  
 
  
National 
  Association 
  of 
  Regulatory 
  Utility 
  
Commissioners 
  
1101 
  Vermont 
  Ave, 
  NW 
  Suite 
  200 
  
Washington, 
  DC 
  20005 
  
jramsay@naruc.org 
   
  
hsmith@naruc.org 
   
  
(202) 
  898-­‐1350 
  
 
  
/s/David 
  L. 
  Mohre 
  
David 
  L. 
  Mohre 
  
Executive 
  Director, 
  Energy 
  & 
  Power 
  Division 
  
 
  
National 
  Rural 
  Electric 
  Cooperative 
  Association 
  
4301 
  Wilson 
  Blvd. 
  
Arlington, 
  VA 
  22203 
  
dave.mohre@nreca.gov 
   
  
(703) 
  907-­‐5812 
  
 
  

Respectfully 
  submitted, 
  
 
  
/s/ 
  Eric 
  Ackerman 
  
Eric 
  Ackerman 
  
Director, 
  Alternative 
  Regulation 
  
 
  
Edison 
  Electric 
  Institute 
   
  
701 
  Pennsylvania 
  Avenue, 
  NW 
   
  
Washington, 
  DC 
  20004-­‐2696 
  
eackerman@eei.org 
   
  
(202) 
  508-­‐5000 
   
  
 
  

 State Activities

 

 

States 
  with 
  Key 
  Activities 
  on 
  Net 
  Energy 
  Metering/Value 
  of 
  
Distributed 
  Generation 
  

Identified “Net Metering/Value of DG Hot Spots”: 39 States including D.C.

 
  

Summary 
  of 
  Key 
  State 
  Activities 
  on 
  NEM 
  and/or 
  Value 
  of 
  DG: 
  39 
  States 
  Including 
  D.C. 
  

 
  

AZ 
  
CA 
  

Regulatory 
  workshops 
  on 
  value 
  of 
  DG/grid 
  & 
  rate 
  design 
  as 
  part 
  of 
  NEM 
  cost 
  shift 
  solution 
  

 
  

Implementation 
  of 
  laws 
  on 
  rate 
  design, 
  NEM, 
  shared 
  solar 
  ▪ 
  Interconnection 
  rules 
  ▪ 
  Storage 
  mandate 
  
interplay 
  w/NEM 
  & 
  value 
  of 
  grid 
  

 
  

CO 
  
CT 
  

Regulatory 
  proceedings 
  on 
  RES 
  compliance, 
  NEM/value 
  of 
  DG 
   
  

 
  

Implementation 
  of 
  energy 
  strategy 
  law 
  including 
   
  expanded 
  virtual 
  NEM 
  ▪ 
  Continued 
  debate 
  over 
  RES 
  
resource 
  eligibility 
  ▪ 
  Policy 
  scrutiny 
  of 
  feed-­‐in 
  tariffs 
  ▪ 
  Shared 
  solar 
  legislation 
  

 
  

DC 
  
IA 
  
FL 
   
  

Implementation 
  of 
  shared 
  renewables 
  law 
   
  

 
  

Utilities 
  Board 
  notice 
  of 
  inquiry 
  on 
  DG 
  ▪ 
  2014 
  state 
  Supreme 
  Court 
  ruling 
  on 
  3rd 
  party 
  financing 
  

 
  

High-­‐profile 
  gubernatorial 
  race 
  could 
  put 
  renewables/NEM 
  issues 
  center 
  stage 
  ▪ 
  Growing 
  pressures 
  to 
  
increase 
  solar 
  penetration, 
  reduce 
  coal 
  reliance 
  in 
  Sunshine 
  State 
  

 
  

GA 
  
HI 
  

Solar 
  mandate 
  implementation 
  ▪ 
  Debate 
  on 
  3rd 
  party 
  financing, 
  shared 
  renewables 
  

 
  

Dramatic 
  increase 
  in 
  solar 
  penetration 
  raises 
  operational 
  issues 
  ▪ 
  PUC 
  poised 
  to 
  review 
  DG 
  issues 
  
including 
  NEM 
  ▪ 
  Legislation 
  on 
  RES, 
  NEM, 
  interconnection, 
  storage, 
  3rd 
  parties 
  

 
  

IL 
  

Rulemaking 
  on 
  NEM 
  changes 
  ▪ 
  Continued 
  debate 
  on 
  RES 
  changes 
   
   
  

 
  

1 
  
 
  

 IN 
  
KS 
  
KY 
  
LA 
  

Regulatory 
  proceeding 
  to 
  extend/modify 
  expiring 
  NIPSCO 
  feed-­‐in 
  tariff; 
  NEM 
  is 
  a 
  factor 
  

 
  

Legislation 
  on 
  NEM 
  (cost/benefit 
  study, 
  lower 
  NEM 
  credits), 
  RES 
  (expand/reduce) 
  

 
  

Legislation 
  on 
  NEM, 
  RES 
  

 
  

Regulatory 
  proceeding 
  on 
  co-­‐ops 
  hitting 
  NEM 
  caps 
  ▪ 
  Legislation 
  on 
  3rd 
  party 
  financing, 
  tax, 
  consumer 
  
protection 
  issues 
  ▪ 
  PSC 
  study 
  of 
  NEM 
  costs/benefits 
  

 
  

ME 
  
MD 
  
MA 
  

Legislation 
  on 
  DG 
  incentives, 
  FITs, 
  RES 
  changes, 
  shared 
  solar, 
  VOS 
  

 
  

Recurring 
  legislative 
  efforts 
  to 
  expand 
  NEM 
  ▪ 
  Legislation 
  on 
  community 
  renewables, 
  RES 
  expansion 
   
  

 
  

Regulatory 
  expansion 
  of 
  RES 
  solar 
  carve-­‐out 
  ▪ 
  Interconnection 
  rule 
  changes 
  ▪ 
  Legislation 
  on 
  NEM 
  caps 
  
▪ 
  Study 
  of 
  NEM 
  costs/benefits 
  

 
  

MI 
  
MN 
  

Governor 
  proposals 
  on 
  RES 
  ▪ 
  Interplay 
  of 
  DG, 
  retail 
  choice 
  

 
  

Implementation 
  of 
  solar 
  carve-­‐out 
  law, 
  including 
  distribution 
  VOS 
  methodology 
  & 
  solar 
  garden 
  
requirement 
  ▪ 
  PUC 
  rule 
  changes 
  to 
  further 
  expand 
  NEM 
   
  

 
  

MO 
  
NV 
  
NH 
  
NJ 
  
NM 
  
NY 
  

Legislation 
  on 
  VOS, 
  solar 
  rebates, 
  RES 
  changes 
  ▪ 
  Implementation 
  of 
  law 
  on 
  solar 
  rebate 
  phase-­‐out 
  

 
  

PUC 
  proceeding 
  on 
  NEM 
  costs/benefits; 
  study 
  to 
  be 
  completed 
  mid-­‐2014 
   
  

 
  

Implementation 
  of 
  shared 
  renewables 
  ▪ 
  Energy 
  Office 
  developing 
  state 
  energy 
  policy 
  w/DG 
  section 
  

 
  

Implementation 
  of 
  Solar 
  Act 
  including 
  NEM 
  provisions 
  ▪ 
  Value 
  of 
  DG 
  in 
  context 
  of 
  resiliency 
  

 
  

Continued 
  debate 
  on 
  supply 
  diversity, 
  RES 
  compliance 
  ▪ 
  Community 
  renewables 
  development 
  

 
  

Extension 
  of 
  Governor’s 
  NY-­‐Sun 
  initiative 
  ▪ 
  Legislation 
  on 
  NEM 
  expansion, 
  shared 
  renewables, 
  other 
  
DG 
  grid 
  issues 
  ▪ 
  PSC 
  to 
  consider 
  “Utility 
  2.0,” 
  including 
  NEM/DG/resiliency/business 
  model 
  issues 
   
  

 
  

NC 
  

Value 
  of 
  DG 
  in 
  context 
  of 
  PURPA 
  avoided 
  cost 
  ▪ 
  Continuing 
  debate 
  on 
  RES 
  changes 
  ▪ 
  Legislation 
  on 
  3rd 
  
party 
  financing 
  ▪ 
  Anticipated 
  regulatory 
  proceeding 
  on 
  NEM 
  changes 
  

 
  

OH 
  
OK 
  
OR 
  
PA 
  
RI 
  
SC 
  
TN 
  
TX 
  
UT 
  
VT 
  
VA 
  
WA 
  
WI 
  

PUC 
  seeks 
  utility 
  proposals 
  on 
  SFV 
  rate 
  design 
  to 
  align 
  w/state 
  DG 
  & 
  other 
  policies 
  ▪ 
  RES 
  legislation 
  

 
  

Legislation 
  addressing 
  NEM 
  cost 
  shift, 
  RES 
  

 
  

Implementation 
  of 
  law 
  requiring 
  PUC 
  to 
  study 
  VOS 
  ▪ 
  Governor 
  seeks 
  more 
  rooftop 
  solar 
  investment 
   
  

 
  

PUC 
  NOPR 
  on 
  NEM 
  rule 
  changes 
  in 
  context 
  of 
  retail 
  choice 
  

 
  

Legislation 
  on 
  DG 
  procurement/financing 
  

 
  

PSC 
  renewables 
  policy 
  review 
  including 
  NEM 
  ▪ 
  Legislation 
  on 
  3rd 
  party 
  financing, 
  NEM, 
  rate 
  design 
  

 
  

Advocacy 
  for 
  expanded 
  TVA 
  green 
  power 
  program 
  (eliminate 
  NEM 
  caps, 
  new 
  value 
  of 
  DG 
  approach) 
  

 
  

No 
  statewide 
  NEM 
  but 
  recurring 
  efforts 
  to 
  institute 
  ▪ 
  Austin 
  has 
  VOS 
  tariff 
  but 
  so 
  far 
  not 
  transferable 
   
  
PacifiCorp 
  rate 
  case 
  addressing 
  NEM 
  cost 
  shift, 
  fixed 
  cost 
  recovery 
  ▪ 
  Legislation 
  on 
  NEM 
  costs/benefits 
  

 
  
 
  

Legislation 
  to 
  raise 
  NEM 
  caps 
  ▪ 
  Regulatory 
  NEM 
  proceedings 
  as 
  co-­‐ops 
  hit 
  existing 
  caps 
  

 
  

rd

Implementation 
  of 
  laws 
  on 
  3  
  party 
  PPA 
  pilot 
  for 
  solar/wind 
  and 
  agricultural 
  NEM 
   
  

 
  

UTC 
  investigation 
  under 
  way 
  of 
  costs/benefits 
  of 
  DG, 
  effect 
  of 
  DG 
  on 
  utility 
  provision 
  of 
  service 
  

 
  

Muni 
  3rd 
  party 
  financing 
  deal; 
  possible 
  legislation 
  on 
  statewide 
  application 
  ▪ 
  Legislation 
  on 
  RES 
   
  

 
  

March 
  2014 
  

2 
  
 
  

  
  

Timeline 
  of 
  Key 
  State 
  Activities 
  on 
  Net 
  Energy 
  Metering 
  
March 
  10, 
  2014 
  
 
  
Note: 
  This 
  timeline 
  reflects 
  a 
  cross-­‐section 
  of 
  state 
  activity 
  and 
  is 
  not 
  comprehensive. 
  The 
  material 
  and 
  research 
  is 
  based 
  on 
  media 
  reports, 
  
state 
  regulatory 
  and 
  legislative 
  documents, 
  Stateside 
  Associates 
  services, 
  and 
  company 
  input. 
   
  We 
  welcome 
  any 
  information 
  you 
  have 
  
that 
  is 
  relative 
  to 
  the 
  activity 
  in 
  your 
  state 
  so 
  that 
  this 
  document 
  remains 
  current. 
  Please 
  send 
  updates 
  to 
  Martha 
  Rowley 
  at 
  
mrowley@eei.org 
  . 
  Thank 
  you. 
  
 
  

ARIZONA 
  
Rates 
  and 
  Regulation 
  
•

•

•

Utility 
  compliance 
  with 
  DG 
  requirements 
  of 
  the 
  state 
  RES, 
  Docket 
  No. 
  E-­‐01345A-­‐10-­‐0394, 
  et 
  al. 
   
   
  
o February 
  6, 
  2014: 
   
  The 
  Arizona 
  Corporation 
  Commission 
  (ACC) 
  voted 
  unanimously 
  to 
  reopen 
  
renewable 
  energy 
  standard 
  (RES) 
  rules 
  to 
  develop 
  a 
  new 
  methodology 
  for 
  utility 
  compliance 
  with 
  
the 
  DG 
  carve-­‐out 
  that 
  does 
  not 
  rely 
  solely 
  on 
  renewable 
  energy 
  certificates 
  (RECs). 
  The 
  action 
  
reflects 
  the 
  changing 
  DG 
  market 
  and 
  the 
  fact 
  that 
  the 
  commission 
  previously 
  eliminated 
  the 
  
mechanism 
  by 
  which 
  utilities 
  can 
  acquire 
  RECs 
  from 
  third 
  parties. 
  The 
  ACC 
  also 
  agreed 
  to 
  allow 
  
utilities 
  to 
  seek 
  one-­‐year 
  waivers 
  of 
  compliance 
  with 
  the 
  DG 
  carve-­‐out 
  while 
  it 
  develops 
  a 
  longer 
  
term 
  compliance 
  solution. 
  A 
  new 
  rulemaking 
  docket 
  will 
  be 
  opened. 
  The 
  state 
  RES 
  target 
  is 
  15% 
  by 
  
2025, 
  with 
  30% 
  of 
  that 
  from 
  distributed 
  energy 
  technologies.
o February 
  26, 
  2014: 
  Written 
  order 
  issued.
o April 
  15, 
  2014: 
  Staff 
  to 
  file 
  proposed 
  new 
  rules.
o May 
  2014: 
  Commission 
  to 
  address 
  notice 
  of 
  proposed 
  rulemaking 
  at 
  its 
  May 
  open 
  meeting 
  or 
  as 
  
soon 
  as 
  practical 
  thereafter.
 
  
Investigation 
  of 
  Value 
  and 
  Cost 
  of 
  DG, 
  including 
  NEM, 
  Docket 
  No. 
  E-­‐00000J-­‐14-­‐0023 
  
o January 
  24, 
  2014: 
  The 
  ACC 
  opened 
  a 
  generic 
  docket 
  to 
  gather 
  stakeholder 
  input 
  to 
  inform 
  
commission 
  policy 
  on 
  the 
  value 
  and 
  costs 
  that 
  DG 
  brings 
  to 
  the 
  grid. 
  
o January 
  27, 
  2014: 
  ACC 
  staff 
  posted 
  a 
  letter 
  to 
  stakeholders 
  with 
  a 
  list 
  of 
  potential 
  DG 
  values 
  and 
  
costs. 
  The 
  letter 
  seeks 
  comments 
  on 
  each 
  listed 
  value/cost 
  and 
  on 
  any 
  other 
  DG-­‐related 
  issues 
  that 
  
should 
  be 
  considered 
  in 
  the 
  docket. 
  
o February 
  14, 
  2014: 
  Comments 
  due. 
  
 
  
Innovations 
  and 
  Technological 
  Developments, 
  Docket 
  No. 
  E-­‐00000J-­‐13-­‐0375. 
   
  
o September 
  11, 
  2013: 
  The 
  ACC 
  voted 
  to 
  close 
  its 
  inquiry 
  on 
  electric 
  retail 
  competition, 
  at 
  which 
  time 
  
Commissioner 
  Bob 
  Burns 
  successfully 
  moved 
  to 
  open 
  a 
  new 
  docket 
  to 
  examine 
  the 
  impact 
  of 
  
innovation 
  and 
  technological 
  development 
  on 
  the 
  utility 
  business 
  model. 
  
o November 
  4, 
  2013: 
  Commissioner 
  Burns 
  issued 
  a 
  memorandum 
  opening 
  the 
  docket. 
  The 
  memo 
  
cites 
  concerns 
  about 
  the 
  effect 
  of 
  falling 
  technology 
  prices 
  such 
  that 
  more 
  entities 
  will 
  be 
  enabled 
  to 
  
use 
  technologies 
  to 
  go 
  off 
  the 
  grid, 
  leaving 
  remaining 
  ratepayers 
  to 
  pick 
  up 
  the 
  cost 
  of 
  the 
  grid. 
   
  

 Timeline of Key State Activities on Net Energy Metering

2

 
  
o

•

December 
  5, 
  2013: 
  Burns 
  memo 
  to 
  commissioners 
  and 
  stakeholders 
  proposing 
  scoping. 
  Among 
  
suggested 
  areas 
  of 
  review 
  are: 
  1) 
  Distributed 
  supply 
  and 
  storage 
  resources 
  enabling 
  customer 
  self-­‐
supply, 
  including 
  customer 
  shared 
  generation 
  (virtual 
  net 
  metering), 
  and 
  2) 
  microgrids. 
   
  
! January 
  17, 
  2014: 
  Comments 
  due. 
  

 
  
Arizona 
  Public 
  Service 
  net 
  metering 
  proposals, 
  Docket 
  No. 
  E-­‐01345A-­‐13-­‐0248 
  
o July 
  12, 
  2013: 
  APS 
  filed 
  a 
  proposal 
  with 
  the 
  ACC 
  outlining 
  two 
  options 
  for 
  reducing 
  cost 
  shift 
  
resulting 
  from 
  net 
  metering: 
  1) 
  Replace 
  current 
  net 
  metering 
  by 
  requiring 
  new 
  solar 
  DG 
  customers 
  
to 
  take 
  service 
  under 
  existing 
  residential 
  time 
  of 
  use 
  rate 
  (ECT-­‐2) 
  that 
  would 
  impose 
  a 
  higher 
  charge 
  
for 
  basic 
  service 
  and 
  for 
  demand 
  (and 
  recover 
  about 
  70 
  percent 
  of 
  utility’s 
  costs), 
  or 
  2) 
  create 
  a 
  
feed-­‐in 
  tariff 
  (FIT)-­‐like 
  mechanism 
  under 
  which 
  a 
  customer 
  is 
  charged 
  the 
  utility 
  rate 
  for 
  all 
  power 
  it 
  
uses, 
  reduced 
  by 
  the 
  wholesale 
  value 
  of 
  all 
  solar 
  power 
  it 
  generates; 
  requires 
  value 
  of 
  solar 
  (VOS) 
  
analysis. 
   
  In 
  preparation 
  for 
  the 
  filing, 
  APS 
  hosted 
  a 
  multi-­‐session 
  technical 
  workshop. 
  
o July-­‐September 
  2013: 
  The 
  Alliance 
  for 
  Solar 
  Choice 
  (TASC), 
  Solar 
  Energy 
  Industries 
  Association 
  
(SEIA), 
  and 
  Interstate 
  Renewable 
  Energy 
  Council 
  (IREC) 
  filed 
  protests. 
  SEIA 
  moved 
  to 
  dismiss. 
  IREC 
  
urged 
  that 
  consideration 
  be 
  deferred 
  until 
  a 
  future 
  general 
  rate 
  case. 
  APS 
  filed 
  responses 
  in 
  
opposition. 
  Numerous 
  customer 
  and 
  other 
  comments 
  were 
  filed 
  in 
  support 
  of 
  and 
  opposition 
  to 
  the 
  
APS 
  proposals. 
  
o September 
  30, 
  2013: 
  Staff 
  filed 
  a 
  proposed 
  order 
  recommending 
  that 
  the 
  APS 
  proposals 
  not 
  be 
  
approved 
  and 
  that 
  consideration 
  of 
  the 
  NEM 
  cost 
  shift 
  issue 
  be 
  deferred 
  until 
  a 
  future 
  general 
  rate 
  
case. 
  Any 
  cost 
  shift 
  issue 
  created 
  by 
  NEM 
  is 
  fundamentally 
  a 
  rate 
  design 
  issue, 
  staff 
  said, 
  
recommending 
  that 
  the 
  ACC 
  hold 
  stakeholder 
  workshops 
  to 
  help 
  inform 
  future 
  policy 
  on 
  the 
  value 
  
of 
  DG. 
  Staff 
  also 
  offered 
  two 
  bridge 
  solutions 
  in 
  the 
  event 
  the 
  commission 
  wants 
  to 
  act 
  sooner. 
  Both 
  
staff 
  alternatives 
  would 
  make 
  adjustments 
  to 
  the 
  existing 
  lost 
  fixed 
  cost 
  recovery 
  mechanism. 
  The 
  
next 
  APS 
  general 
  rate 
  case 
  is 
  expected 
  to 
  be 
  filed 
  in 
  June 
  2015. 
   
  
o October 
  17, 
  2013: 
  Commissioner 
  Pierce 
  issued 
  a 
  letter 
  seeking 
  more 
  information 
  on 
  the 
  staff 
  
alternatives. 
  He 
  said 
  he 
  has 
  no 
  position 
  yet 
  on 
  the 
  issues 
  presented 
  by 
  the 
  case. 
   
  
o October 
  30, 
  2013: 
  Commissioner 
  Burns 
  issued 
  a 
  letter 
  seeking 
  more 
  information 
  from 
  utilities 
  and 
  
solar 
  providers/related 
  organizations 
  on 
  how 
  much 
  money 
  they 
  have 
  spent 
  on 
  NEM 
  public 
  relations 
  
campaigns. 
  The 
  Residential 
  Utility 
  Consumer 
  Office 
  (RUCO) 
  filed 
  comments 
  and 
  a 
  proposed 
  order 
  
providing 
  for 
  phasing 
  in 
  a 
  market-­‐based 
  fixed 
  charge 
  on 
  new 
  solar 
  customer 
  bills 
  to 
  address 
  the 
  cost 
  
shift 
  issue. 
  RUCO 
  also 
  recommended 
  that 
  the 
  commission 
  open 
  a 
  docket 
  to 
  address 
  broader 
  issues 
  
related 
  to 
  the 
  cost 
  shift. 
  
o November 
  4, 
  2013: 
  Staff-­‐suggested 
  deadline 
  for 
  comments 
  on 
  proposed 
  order. 
  
o November 
  6, 
  2013: 
  Comments 
  due 
  in 
  response 
  to 
  Pierce 
  letter 
  and 
  to 
  Burns 
  letter. 
  
o November 
  13-­‐14, 
  2013: 
  The 
  AZ 
  CC 
  voted 
  3-­‐2 
  to 
  adopt 
  a 
  rate 
  charge 
  of 
  $0.70 
  per 
  kW, 
  estimated 
  to 
  
be 
  $4.90 
  per 
  month 
  for 
  typical 
  installations, 
  for 
  new 
  rooftop 
  solar 
  customers 
  as 
  of 
  January 
  1, 
  2014. 
  
Revenue 
  will 
  be 
  credited 
  back 
  to 
  non-­‐DG 
  customers. 
  Existing 
  customers 
  are 
  grandfathered 
  until 
  the 
  
next 
  rate 
  case. 
  New 
  customers 
  must 
  sign 
  an 
  affidavit 
  stating 
  that 
  they 
  recognize 
  that 
  the 
  surcharge 
  
could 
  change 
  in 
  the 
  future. 
  The 
  surcharge 
  will 
  be 
  reconsidered 
  in 
  the 
  next 
  APS 
  general 
  rate 
  case, 
  
which 
  the 
  AZ 
  CC 
  directed 
  the 
  company 
  to 
  file 
  in 
  2015. 
  The 
  commission 
  acknowledged 
  the 
  cost 
  shift 
  
and 
  value 
  of 
  the 
  grid 
  and 
  called 
  for 
  workshops 
  to 
  look 
  at 
  broader 
  rate 
  design 
  issues. 
   
  
o December 
  3, 
  2013: 
  Final 
  decision 
  issued. 
   
  
o January 
  1, 
  2014: 
  Rate 
  change 
  effective. 
  

 Timeline of Key State Activities on Net Energy Metering

3

 
  
o
o

January 
  27, 
  2014: 
  The 
  commission 
  directed 
  stakeholders 
  to 
  a 
  new 
  docket 
  on 
  value 
  and 
  costs 
  of 
  DG 
  
to 
  the 
  grid. 
  (See 
  item 
  above 
  for 
  Docket 
  No. 
  E-­‐00000J-­‐13-­‐0375.) 
  
January 
  2014: 
  Numerous 
  comments 
  from 
  the 
  public 
  continue 
  to 
  be 
  filed 
  in 
  the 
  docket, 
  many 
  of 
  
them 
  using 
  the 
  same 
  language 
  urging 
  protection 
  of 
  ratepayers 
  not 
  participating 
  in 
  DG. 
  

Legislation 
  
•

H.C.R. 
  2032: 
  Proposes 
  a 
  constitutional 
  amendment 
  under 
  which 
  utilities 
  would 
  be 
  required 
  to 
  
interconnect 
  with 
  any 
  net 
  metered 
  retail 
  customer 
  regardless 
  of 
  size 
  of 
  the 
  NEM 
  facility, 
  prohibited 
  
from 
  charging 
  any 
  additional 
  fees 
  or 
  charges 
  not 
  imposed 
  on 
  non-­‐net 
  metered 
  customers, 
  and 
  required 
  
to 
  compensate 
  net 
  metered 
  customers 
  at 
  the 
  retail 
  rate 
  for 
  excess 
  generation. 
  New 
  meters 
  would 
  be 
  
required 
  to 
  have 
  two-­‐way 
  capability. 
  
o February 
  10, 
  2014: 
  Introduced. 
  

ARKANSAS 
  
Rates 
  and 
  Regulation 
  
•

Generic 
  rulemaking 
  on 
  changes 
  to 
  net 
  metering 
  rules, 
  Docket 
  No. 
  12-­‐060-­‐R 
  
o August 
  8, 
  2012: 
  The 
  AR 
  Public 
  Service 
  Commission 
  (PSC) 
  issued 
  an 
  order 
  opening 
  a 
  proceeding 
  to 
  
consider 
  changes 
  to 
  net 
  metering 
  rules 
  addressing 
  aggregation 
  and 
  other 
  issues. 
  
o May 
  15, 
  2013: 
  The 
  PSC 
  issued 
  an 
  order 
  proposing 
  amendments 
  to 
  rules. 
  
o June 
  21, 
  2013: 
  Hearing 
  held. 
  
o September 
  3, 
  2013: 
  The 
  PSC 
  issued 
  an 
  order 
  approving 
  proposed 
  rule 
  amendments 
  that 
  expand 
  the 
  
existing 
  net 
  metering 
  program 
  by 
  allowing 
  meter 
  aggregation. 
  
o Excerpt 
  from 
  order: 
  “Given 
  the 
   
  nascent 
  state 
  of 
  distributed 
  renewable 
  generation 
  in 
  
Arkansas 
  at 
  this 
  time, 
  the 
  common 
  agreement 
  that 
  its 
  current 
  cost 
  impacts 
  are 
  negligible, 
  
the 
  paucity 
  of 
  the 
  record 
  regarding 
  the 
  precise 
  potential 
  future 
  economic 
  impacts 
  of 
  net 
  
metering, 
  and 
  the 
  statutory 
  directive 
  to 
  promote 
  the 
  growth 
  of 
  net 
  metering 
  and 
  the 
  public 
  
policy 
  benefits 
  thereof, 
  the 
  Commission 
  remains 
  convinced 
  that 
  it 
  is 
  unnecessary 
  and 
  
premature 
  at 
  this 
  time 
  to 
  further 
  delay 
  the 
  promotion 
  of 
  net 
  metering 
  in 
  an 
  attempt 
  to 
  
translate 
  the 
  exact 
  economic 
  impact 
  of 
  potential 
  expanded 
  net 
  metering 
  into 
  new 
  
ratemaking 
  mechanisms. 
  Further, 
  any 
  party 
  is 
  at 
  liberty 
  to 
  raise 
  the 
  issue 
  of 
  subsidies 
  within 
  
a 
  rate 
  case 
  or 
  in 
  other 
  proceedings, 
  and 
  the 
  statute 
  provides 
  sufficient 
  guidance 
  for 
  the 
  
consideration 
  of 
  that 
  issue.” 
   
  

Legislation 
  
•

H.B. 
  2019 
  (2013): 
  Allows 
  customers 
  to 
  be 
  credited 
  during 
  their 
  next 
  billing 
  cycle 
  for 
  net 
  excess 
  
generation 
  equal 
  to 
  four 
  months 
  of 
  average 
  usage. 
  The 
  PSC 
  is 
  authorized 
  to 
  allow 
  utilities 
  to 
  assess 
  net-­‐
metered 
  customers 
  a 
  greater 
  fee 
  or 
  charge 
  of 
  any 
  type, 
  if 
  the 
  electric 
  utility's 
  direct 
  costs 
  of 
  
interconnection 
  and 
  administration 
  of 
  net 
  metering 
  outweigh 
  the 
  distribution 
  system, 
  environmental, 
  
and 
  public 
  policy 
  benefits 
  of 
  allocating 
  the 
  costs 
  among 
  the 
  electric 
  utility's 
  entire 
  customer 
  base. 
  
o April 
  12, 
  2013: 
  Enacted. 
  

 Timeline of Key State Activities on Net Energy Metering

4

 
  

CALIFORNIA 
  
Rates 
  and 
  Regulation 
  
•

•

•

Implementation 
  of 
  portions 
  of 
  S.B. 
  43 
  (below) 
  addressing 
  shared 
  renewables, 
  currently 
  being 
  
addressed 
  in 
  the 
  context 
  of 
  individual 
  utility 
  filings 
  in 
  consolidated 
  Docket 
  No. 
  A12-­‐01-­‐008. 
  The 
  CA 
  
Public 
  Utilities 
  Commission 
  (CPUC) 
  may 
  open 
  a 
  separate 
  docket. 
  Schedule 
  for 
  A12-­‐01-­‐008: 
  
o Second 
  quarter 
  2014: 
  Proposed 
  decision. 
  
o June 
  30, 
  2014: 
  CPUC 
  decision. 
  
 
  
PG&E 
  general 
  rate 
  case, 
  Docket 
  No. 
  A12-­‐11-­‐009. 
   
  
o November 
  15, 
  2012: 
  Filed 
  with 
  the 
  CPUC. 
  PG&E 
  has 
  requested 
  a 
  change 
  in 
  its 
  A6 
  rate, 
  which 
  applies 
  
time 
  of 
  use 
  (TOU) 
  pricing 
  without 
  a 
  demand 
  charge 
  to 
  nonresidential 
  customers 
  up 
  to 
  500 
  kW. 
  
PG&E 
  is 
  seeking 
  to 
  limit 
  customer 
  capacity 
  to 
  75 
  kW. 
  The 
  CPUC’s 
  Office 
  of 
  Ratepayer 
  Advocate 
  has 
  
recommended 
  a 
  20 
  kW 
  limit. 
  Solar 
  advocates 
  argue 
  that 
  setting 
  a 
  lower 
  capacity 
  limit 
  as 
  proposed 
  
would 
  disrupt 
  the 
  solar 
  market 
  in 
  the 
  state 
  and 
  particularly 
  harm 
  schools 
  and 
  local 
  government 
  
entities. 
   
  
o March 
  15, 
  2014: 
  Commission 
  decision 
  expected. 
  
 
  
PG&E 
  2013 
  rate 
  design 
  window 
  proceeding, 
  Docket 
  No. 
  A12-­‐12-­‐002 
  
o December 
  3, 
  2012: 
  PG&E 
  filed 
  in 
  compliance 
  with 
  a 
  2011 
  CPUC 
  decision, 
  which 
  required 
  PG&E 
  to 
  file 
  
a 
  demand 
  charge 
  cost 
  study 
  and 
  evaluation 
  of 
  “Option 
  R” 
  for 
  commercial 
  and 
  industrial 
  with 
  solar 
  
generation 
  that 
  exceeds 
  10% 
  of 
  their 
  demand. 
  Option 
  R 
  would 
  change 
  rates 
  to 
  collect 
  a 
  smaller 
  
portion 
  of 
  generation 
  and 
  distribution 
  capacity 
  through 
  the 
  demand 
  charge 
  and 
  more 
  from 
  the 
  
energy 
  charge. 
  
o May 
  10 
  and 
  June 
  14, 
  2013: 
  Intervenor 
  testimony 
  and 
  rebuttal 
  testimony, 
  respectively. 
  
o July 
  8-­‐12, 
  2013: 
  Evidentiary 
  hearing. 
  
o August 
  2 
  and 
  August 
  23, 
  2013: 
  Opening 
  briefs 
  and 
  reply 
  briefs, 
  respectively. 
  SEIA 
  proposed 
  an 
  
optional 
  Option 
  R 
  that 
  would 
  eliminate 
  about 
  half 
  the 
  revenue 
  currently 
  collected 
  in 
  demand 
  
charges 
  under 
  Schedules 
  E-­‐19 
  and 
  E-­‐20 
  and 
  increase 
  energy 
  charges 
  that 
  are 
  more 
  readily 
  avoided 
  
by 
  solar 
  customers. 
  The 
  proposed 
  changes 
  also 
  would 
  allow 
  those 
  NEM 
  customers 
  with 
  significant 
  
power 
  exports 
  to 
  the 
  grid 
  to 
  receive 
  much 
  larger 
  payments 
  for 
  exports 
  during 
  the 
  entire 
  summer 
  
on-­‐peak 
  TOU 
  period. 
  PG&E 
  urged 
  the 
  CPUC 
  to 
  reject 
  the 
  proposal, 
  saying 
  it 
  violates 
  longtime 
  CPUC 
  
policy 
  in 
  support 
  of 
  demand 
  charges 
  for 
  large 
  customers, 
  is 
  not 
  cost-­‐justified, 
  and 
  would 
  create 
  
unneeded 
  new 
  cost 
  shifts 
  at 
  a 
  time 
  when 
  solar 
  customers 
  are 
  already 
  being 
  subsidized 
  by 
  other 
  
customers. 
   
  
o November 
  8, 
  2013: 
  PG&E 
  filed 
  a 
  motion 
  to 
  take 
  official 
  notice 
  of 
  the 
  CPUC’s 
  October 
  28, 
  2013, 
  NEM 
  
study 
  prepared 
  by 
  E3. 
  The 
  report 
  found 
  that 
  benefits 
  to 
  non-­‐solar 
  ratepayers 
  were 
  less 
  than 
  the 
  
costs 
  of 
  the 
  solar 
  installations 
  to 
  other 
  customers. 
  PG&E 
  said 
  a 
  key 
  issue 
  in 
  the 
  case 
  is 
  the 
  cost 
  and 
  
rate 
  impact 
  that 
  result 
  when 
  large 
  C&I 
  customers 
  install 
  solar. 
  
o November 
  20, 
  2013: 
  SEIA 
  filed 
  a 
  response 
  in 
  opposition 
  to 
  PG&E’s 
  motion, 
  saying 
  it 
  is 
  procedurally 
  
invalid 
  and 
  that 
  further 
  hearings 
  would 
  be 
  required 
  to 
  interpret 
  and 
  test 
  the 
  validity 
  of 
  study 
  results. 
  
o December 
  2, 
  2013: 
  PG&E 
  filed 
  a 
  reply, 
  saying 
  SEIA’s 
  arguments 
  are 
  frivolous 
  and 
  should 
  be 
  rejected, 
  
and 
  further 
  hearings 
  are 
  not 
  needed. 
  
o August 
  2014: 
  Expected 
  PUC 
  decision. 
  

 Timeline of Key State Activities on Net Energy Metering

5

 
  
•

•

 
  
SDG&E 
  2011 
  rate 
  case 
  (Phase 
  2 
  – 
  cost 
  allocation/rate 
  design), 
  Docket 
  No. 
  A11-­‐10-­‐002 
  
o January 
  16, 
  2014: 
  The 
  CPUC 
  issued 
  a 
  decision 
  that, 
  among 
  other 
  things, 
  denied 
  without 
  prejudice 
  
SDG&E’s 
  proposed 
  basic 
  service 
  fee 
  (BSF) 
  of 
  $3/mo. 
  to 
  recover 
  a 
  portion 
  of 
  fixed 
  distribution 
  costs. 
  
The 
  fee 
  would 
  replace 
  the 
  current 
  minimum 
  bill, 
  which 
  is 
  applied 
  at 
  a 
  rate 
  of 
  $0.17/day 
  (approx. 
  
$5.10/mo.) 
  The 
  BSF 
  was 
  opposed 
  by 
  the 
  CPUC’s 
  Office 
  of 
  Ratepayer 
  Advocate, 
  TURN, 
  Vote 
  Solar 
  and 
  
other 
  parties. 
  The 
  CPUC 
  said 
  that 
  since 
  the 
  passage 
  of 
  AB 
  327, 
  it 
  is 
  uncertain 
  whether 
  the 
  legal 
  
arguments 
  against 
  the 
  BSF 
  still 
  apply. 
  Among 
  the 
  legal 
  arguments 
  was 
  that 
  the 
  proposal 
  would 
  raise 
  
rates 
  too 
  much 
  for 
  lower 
  income 
  customers. 
  The 
  CPUC 
  said 
  it 
  is 
  more 
  appropriate 
  to 
  consider 
  the 
  
proposed 
  BSF 
  in 
  the 
  ongoing 
  rulemaking 
  proceeding 
  addressing 
  rate 
  design 
  (Docket 
  No. 
  R12-­‐06-­‐013, 
  
below). 
  This 
  would 
  allow 
  evaluation 
  of 
  whether 
  this 
  type 
  of 
  fee 
  should 
  be 
  adopted 
  for 
  all 
  electric 
  
utilities 
  in 
  a 
  more 
  comprehensive 
  manner 
  rather 
  than 
  on 
  a 
  utility-­‐by-­‐utility 
  basis, 
  the 
  CPUC 
  said. 
   
  
 
  
Generic 
  rulemaking 
  on 
  rate 
  design/implementation 
  of 
  AB 
  327, 
  Docket 
  No. 
  R12-­‐06-­‐013 
  
o June 
  28, 
  2012: 
  The 
  CPUC 
  instituted 
  a 
  rulemaking 
  to 
  conduct 
  a 
  comprehensive 
  study 
  of 
  investor-­‐
owned 
  utility 
  rate 
  design 
  structures, 
  including 
  residential 
  tier 
  structure, 
  and 
  meet 
  other 
  statutory 
  
obligations. 
  The 
  CPUC 
  is 
  looking 
  at 
  whether 
  the 
  current 
  rate 
  structure 
  is 
  meeting 
  state 
  policy 
  
objectives, 
  including 
  “increased 
  usage 
  of 
  distributed 
  solar 
  by 
  end-­‐use 
  customers” 
  through 
  the 
  
California 
  Solar 
  Initiative 
  and 
  NEM 
  policies. 
  Each 
  major 
  utility 
  submitted 
  a 
  rate 
  design 
  proposal 
  prior 
  
to 
  enactment 
  of 
  A.B. 
  327. 
  The 
  CPUC 
  has 
  not 
  yet 
  indicated 
  whether 
  it 
  will 
  open 
  a 
  new 
  docket 
  to 
  
address 
  other 
  A.B. 
  327 
  issues 
  or 
  whether 
  the 
  issues 
  will 
  be 
  addressed 
  in 
  this 
  docket. 
  
Phase 
  1 
  
o

o
o
o

o
o
o
o
o
o
o

January 
  6, 
  2014: 
  Amended 
  scope 
  memo 
  and 
  ruling: 
  1) 
  Issues 
  the 
  Energy 
  Division 
  (ED) 
  “Staff 
  Proposal 
  
for 
  Residential 
  Rate 
  Reform 
  in 
  Compliance 
  with 
  Rulemaking 
  12-­‐06-­‐013 
  and 
  Assembly 
  Bill 
  327,” 
  2) 
  
amends 
  the 
  scope 
  of 
  Phase 
  1 
  and 
  re-­‐categorizes 
  it 
  as 
  ratesetting, 
  and 
  3) 
  sets 
  the 
  category 
  for 
  Phase 
  
2 
  of 
  this 
  proceeding 
  as 
  ratesetting. 
  The 
  ED 
  proposal 
  aligns 
  to 
  a 
  large 
  extent 
  with 
  utility 
  positions 
  but 
  
key 
  differences 
  include 
  the 
  ED’s 
  support 
  for 
  mandatory 
  TOU 
  rates 
  and 
  its 
  apparent 
  equating 
  of 
  
customer 
  charges 
  with 
  minimum 
  bills. 
  The 
  ED 
  said 
  choosing 
  an 
  approach 
  of 
  applying 
  a 
  customer 
  
charge 
  (as 
  allowed 
  by 
  AB 
  327 
  of 
  up 
  to 
  $10/mo. 
  for 
  non-­‐low 
  income 
  customers) 
  or 
  minimum 
  bill 
  is 
  a 
  
policy 
  choice 
  for 
  the 
  CPUC 
  to 
  decide. 
  
January 
  8, 
  2014: 
  Prehearing 
  conference. 
  
January 
  31, 
  2014: 
  General 
  corrections 
  (extended 
  schedule). 
  
February 
  13, 
  2014: 
  Assigned 
  commissioner 
  ruling 
  issued 
  directing 
  PG&E, 
  SDG&E 
  and 
  SCE 
  to 
  file 
  
residential 
  rate 
  change 
  proposals 
  for 
  the 
  period 
  January 
  1, 
  2015, 
  through 
  December 
  31, 
  2018. 
  
Utilities 
  must 
  provide 
  an 
  update 
  inventory 
  of 
  residential 
  tariffs/issues 
  to 
  be 
  resolved 
  in 
  this 
  
proceeding 
  and 
  answer 
  a 
  set 
  of 
  rate 
  design 
  questions. 
  
February 
  14, 
  2014: 
  Rate 
  issue 
  inventory. 
  
February 
  28, 
  2014: 
  Utility 
  rate 
  change 
  proposals 
  and 
  related 
  testimony. 
  
March 
  10, 
  2014: 
  Prehearing 
  statements 
  to 
  identify 
  and 
  refine 
  factual 
  and 
  legal 
  issues 
  to 
  be 
  resolved. 
  
March 
  14, 
  2014: 
  Prehearing 
  conference. 
  
March 
  21, 
  2014: 
  Supplemental 
  filings 
  answering 
  remaining 
  rate 
  design 
  questions. 
  
March 
  31, 
  2014: 
  Phase 
  1 
  scoping 
  memo. 
  
April 
  11, 
  2014: 
  Supplemental 
  utility 
  testimony, 
  if 
  necessary. 
  

 Timeline of Key State Activities on Net Energy Metering

6

 
  
o
o
o
o
o
o
o

May 
  16, 
  2014: 
  Intervenor 
  testimony. 
  
May 
  30, 
  2014: 
  Rebuttal 
  testimony. 
  
June/July 
  2014: 
  Evidentiary 
  hearings. 
  
August 
  15, 
  2014: 
  Opening 
  briefs. 
  
August 
  29, 
  2014: 
  Reply 
  briefs. 
  
October 
  21, 
  2014: 
  Proposed 
  decision. 
  
By 
  end 
  of 
  2014: 
  Final 
  decision 
  expected. 
  

Phase 
  2 
   
  
o

o
o
o
o

o
o
o
o
o
o
o
o
o
o
o
o
o
o
 
  

October 
  25, 
  2013: 
  Assigned 
  commissioner 
  ruling 
  invites 
  utilities 
  to 
  file 
  applications 
  for 
  interim 
  
residential 
  rate 
  changes 
  under 
  AB 
  327 
  and 
  opens 
  a 
  new 
  Phase 
  2 
  of 
  the 
  proceeding. 
  Phase 
  1 
  will 
  
continue 
  to 
  examine 
  residential 
  rate 
  designs 
  that 
  will 
  result 
  in 
  a 
  long-­‐term 
  policy 
  decision. 
  Phase 
  2 
  
will 
  proceed 
  concurrently 
  with 
  Phase 
  1 
  to 
  address 
  interim 
  rate 
  designs 
  that 
  better 
  align 
  residential 
  
prices 
  with 
  cost 
  to 
  serve 
  and 
  other 
  policy 
  objectives. 
  Rate 
  design 
  changes 
  should 
  be 
  “modest, 
  easy 
  
to 
  evaluate, 
  and 
  consistent 
  with 
  AB 
  327,” 
  the 
  ruling 
  said. 
  
November 
  8, 
  2013: 
  Comments 
  due 
  on 
  procedural 
  schedule 
  and 
  need 
  for 
  evidentiary 
  hearings. 
  The 
  
Alliance 
  for 
  Solar 
  Choice 
  (TASC) 
  filed 
  comments. 
  
November 
  22, 
  2013: 
  Utilities 
  filed 
  interim 
  rate 
  applications. 
  
December 
  5, 
  2013: 
  Pre-­‐hearing 
  conference. 
  
December 
  23, 
  2013: 
  Protests 
  due. 
  TASC 
  and 
  the 
  Interstate 
  Renewable 
  Energy 
  Council 
  (IREC) 
  filed 
  
protests 
  against 
  utility 
  interim 
  rate 
  design 
  proposals. 
  TASC 
  and 
  IREC 
  said 
  the 
  proposals 
  would 
  
substantially 
  reduce 
  or 
  eliminate 
  the 
  savings 
  by 
  solar 
  customers. 
  TASC 
  said 
  the 
  proposals 
  could 
  have 
  
a 
  “devastating 
  impact” 
  on 
  the 
  solar 
  industry. 
  IREC 
  said 
  its 
  initial 
  analysis 
  shows 
  that 
  increases 
  in 
  
lower 
  tier 
  rates 
  and 
  corresponding 
  decreases 
  in 
  upper 
  tier 
  rates, 
  as 
  proposed, 
  would 
  result 
  in 
  20-­‐
30% 
  bill 
  increases 
  for 
  NEM 
  customers. 
  IREC 
  spoke 
  to 
  the 
  general 
  significance 
  of 
  the 
  proposals, 
  
saying 
  “they 
  begin 
  to 
  shift 
  to 
  the 
  new 
  rate 
  paradigm 
  and 
  essentially 
  create 
  the 
  new 
  ‘baseline’ 
  or 
  
status 
  quo 
  from 
  which 
  future 
  [general 
  rate 
  cases] 
  will 
  start.” 
   
  
January 
  3, 
  2014: 
  Replies 
  filed. 
  
January 
  8, 
  2014: 
  Prehearing 
  conference. 
  
January 
  10, 
  2014: 
  Motions 
  for 
  evidentiary 
  hearing 
  due. 
  
January 
  24, 
  2014: 
  Phase 
  2 
  scoping 
  memo 
  issued 
  with 
  new 
  schedule. 
   
  
January 
  28, 
  2014: 
  Simplified 
  utility 
  rate 
  design 
  proposals 
  and 
  supplemental 
  utility 
  testimony. 
  
February 
  5, 
  2014: 
  Vote 
  Solar 
  presented 
  a 
  petition 
  to 
  the 
  CPUC 
  with 
  approx. 
  50,000 
  signatures. 
  The 
  
petition 
  supports 
  30-­‐year 
  NEM 
  grandfathering. 
  
February 
  25, 
  2014: 
  ALJ 
  issued 
  ruling 
  amending 
  procedural 
  schedule. 
   
  
March 
  4, 
  2014: 
  Anticipated 
  SCE 
  motion 
  to 
  adopt 
  settlement. 
  
March 
  5, 
  2014: 
  Intervenor 
  testimony. 
  Anticipated 
  PG&E 
  motion 
  to 
  adopt 
  settlement. 
  
March 
  12, 
  2014: 
  Rebuttal 
  testimony. 
  
March 
  24-­‐26, 
  2014: 
  Evidentiary 
  hearing. 
  
April 
  7, 
  2014: 
  Opening 
  briefs. 
  
April 
  16, 
  2014: 
  Reply 
  briefs. 
  
May 
  9, 
  2014: 
  Proposed 
  decision. 
   
  
 
  

 Timeline of Key State Activities on Net Energy Metering

7

 
  
•

•

 
  
Generic 
  rulemaking 
  docket 
  on 
  NEM, 
  storage, 
  grandfathering, 
  other 
  DG 
  issues, 
  Docket 
  No. 
  R12-­‐11-­‐005 
  
o November 
  15, 
  2012: 
  The 
  CPUC 
  opened 
  a 
  new 
  rulemaking 
  to 
  continue 
  DG 
  work, 
  including 
  NEM 
  
issues, 
  from 
  previous 
  dockets 
  (including 
  R10-­‐05-­‐004 
  below). 
   
  
o October 
  17, 
  2013: 
  Assigned 
  commissioner 
  ruling 
  seeks 
  comment 
  on 
  a 
  proposal 
  to 
  give 
  storage 
  
devices 
  paired 
  with 
  renewable 
  generation 
  facilities 
  the 
  same 
  benefits 
  the 
  renewable 
  facilities 
  
receive 
  under 
  NEM 
  tariffs 
  until 
  at 
  least 
  the 
  end 
  of 
  2015. 
  Utilities 
  must 
  submit 
  reports 
  by 
  July 
  1, 
  
2015, 
  on 
  lost 
  revenues 
  resulting 
  from 
  this 
  treatment. 
  Based 
  on 
  information 
  in 
  the 
  reports, 
  the 
  CPUC 
  
could 
  choose 
  to 
  amend 
  or 
  extend 
  the 
  program. 
  A 
  concern 
  has 
  been 
  raised 
  by 
  utilities 
  that 
  energy 
  
from 
  batteries 
  sold 
  back 
  to 
  the 
  grid 
  cannot 
  be 
  verified 
  as 
  renewable-­‐sourced. 
  
! November 
  1, 
  2013: 
  Comments 
  due 
  under 
  extended 
  schedule. 
  
! November 
  8, 
  2013: 
  Reply 
  comments 
  due. 
  
! January 
  6, 
  2014: 
  Assigned 
  commissioner 
  ruling 
  seeks 
  additional 
  comment 
  on 
  safety 
  
considerations 
  specific 
  to 
  storage 
  devices. 
  
! January 
  8, 
  2014: 
  Comments 
  due. 
  Reply 
  comments 
  not 
  requested. 
  
o November 
  27, 
  2013: 
  Assigned 
  commissioner 
  ruling 
  seeks 
  comments 
  on 
  implementation 
  of 
  NEM 
  
transition 
  period 
  under 
  AB 
  327. 
  The 
  law 
  provides 
  that 
  customers 
  who 
  were 
  net 
  metered 
  prior 
  to 
  
reaching 
  the 
  statutory 
  NEM 
  cap 
  by 
  July 
  1, 
  2017, 
  are 
  protected 
  for 
  a 
  transition 
  period 
  to 
  be 
  
determined 
  by 
  the 
  CPUC. 
  The 
  governor 
  in 
  his 
  signing 
  message 
  for 
  AB 
  327 
  called 
  for 
  the 
  CPUC 
  to 
  
consider 
  the 
  entire 
  lifespan 
  of 
  customer 
  solar 
  systems 
  whereas 
  the 
  law 
  specifies 
  that 
  the 
  
commission 
  consider 
  a 
  reasonable 
  expected 
  payback 
  period. 
  
! December 
  3, 
  2013: 
  Intervention 
  filed 
  by 
  TASC. 
  Other 
  solar 
  advocates 
  such 
  as 
  CASEIA 
  already 
  are 
  
parties. 
  
! December 
  13, 
  2103: 
  Comments 
  due 
  (extended 
  schedule). 
  Solar 
  advocates 
  supported 
  the 
  
governor’s 
  signing 
  message 
  (above). 
  Consumer 
  representatives 
  recommended 
  relatively 
  low 
  
payback 
  periods 
  (e.g., 
  7 
  years) 
  while 
  the 
  utilities 
  generally 
  came 
  in 
  around 
  10 
  years. 
  
! December 
  23, 
  2013: 
  Reply 
  comments 
  due 
  (extended 
  schedule). 
  
! February 
  20, 
  2014: 
  Proposed 
  decision 
  issued 
  that 
  would 
  set 
  20-­‐year 
  transition 
  period. 
   
  
! March 
  12, 
  2014: 
  Comments 
  due 
  on 
  proposed 
  decision. 
  
! March 
  17, 
  2014: 
  Reply 
  comments 
  due. 
  
! March 
  27, 
  2014: 
  CPUC 
  open 
  meeting. 
  The 
  proposed 
  decision 
  may 
  be 
  discussed. 
  
! March 
  31, 
  2014: 
  Statutory 
  deadline 
  for 
  final 
  decision. 
   
  
 
  
Generic 
  rulemaking 
  on 
  DG 
  interconnection, 
  Docket 
  No. 
  R11-­‐09-­‐011 
  
o September 
  22, 
  2011: 
  The 
  CPUC 
  proposed 
  amendments 
  to 
  Rule 
  21 
  to 
  ensure 
  interconnections 
  of 
  DG 
  
and 
  storage 
  facilities 
  are 
  timely, 
  nondiscriminatory, 
  cost-­‐effective 
  and 
  transparent. 
  
o As 
  of 
  October 
  21, 
  2013: 
  Parties 
  filing 
  comments. 
  No 
  events 
  scheduled 
  for 
  fall 
  2013. 
  
o February 
  5, 
  2014: 
  ALJ 
  proposed 
  decision 
  issued 
  that 
  would 
  establish 
  new 
  utility 
  Distribution 
  Group 
  
Study 
  Process 
  and 
  new 
  forms 
  for 
  handling 
  interconnection 
  applications 
  and 
  related 
  cost 
  allocation. 
  
o February 
  19, 
  2014: 
  Prehearing 
  conference 
  held 
  to 
  discuss 
  report, 
  “Smart 
  Inverter 
  Working 
  Group 
  
Recommendations,” 
  issued 
  January 
  14. 
  Report 
  is 
  Attachment 
  1 
  at 
  this 
  location: 
  
http://docs.cpuc.ca.gov/SearchRes.aspx?DocFormat=ALL&DocID=87262222 
   
  
o February 
  25, 
  2014: 
  Comments 
  due 
  on 
  proposed 
  decision. 
  
o March 
  13, 
  2014: 
  Open 
  commission 
  meeting. 
  Proposed 
  decision 
  expected 
  to 
  be 
  discussed. 
  

 Timeline of Key State Activities on Net Energy Metering

8

 
  
•

 
  
Generic 
  rulemaking 
  on 
  NEM/other 
  DG 
  issues, 
  Docket 
  No. 
  R10-­‐05-­‐004 
  CLOSED 
  
o May 
  24, 
  2012: 
  The 
  CPUC 
  effectively 
  doubled 
  the 
  NEM 
  cap 
  and 
  required 
  study 
  of 
  the 
  costs/benefits 
  
of 
  NEM. 
   
  
o September 
  26, 
  2013: 
  The 
  CPUC 
  issued 
  its 
  much-­‐anticipated 
  report, 
  California 
  Net 
  Energy 
  Metering 
  
Ratepayer 
  Impacts 
  Evaluation. 
  Required 
  by 
  A.B. 
  2514 
  (2012), 
  the 
  319-­‐page 
  report 
  by 
  consultant 
  E3 
  
concludes 
  that 
  state’s 
  NEM 
  program 
  could 
  end 
  up 
  costing 
  other 
  California 
  ratepayers 
  $1.1 
  billion 
  a 
  
year 
  by 
  2020 
  (in 
  2012$). 
  The 
  report 
  identifies 
  California's 
  flawed 
  inclining 
  block 
  residential 
  rate 
  
design 
  as 
  the 
  primary 
  source 
  of 
  this 
  rate 
  inequity 
  where 
  the 
  levelized 
  net 
  cost 
  reaches 
  $0.20 
  per 
  
kWh 
  generated. 
  The 
  report's 
  conclusions 
  support 
  the 
  position 
  taken 
  by 
  SCE 
  and 
  others 
  that 
  the 
  
CPUC 
  needs 
  to 
  re-­‐design 
  both 
  residential 
  rates 
  and 
  the 
  NEM 
  program, 
  both 
  of 
  which 
  are 
  authorized 
  
by 
  A.B. 
  327. 
  The 
  report 
  is 
  located 
  at: 
  http://www.cpuc.ca.gov/NR/rdonlyres/BD9EAD36-­‐7648-­‐430B-­‐
A692-­‐8760FA186861/0/CPUCNEMDraftReport92613.pdf 
   
  
o September 
  27, 
  2013: 
  The 
  CPUC 
  held 
  a 
  workshop 
  to 
  discuss 
  the 
  report. 
   
  
o October 
  10, 
  2013: 
  Comments 
  due. 
  
o November 
  13, 
  2013: 
  The 
  CPUC 
  issued 
  an 
  order 
  vacating 
  its 
  May 
  2012 
  order, 
  dismissing 
  applications 
  
for 
  rehearing 
  as 
  moot, 
  and 
  closing 
  the 
  proceeding 
  in 
  light 
  of 
  the 
  recent 
  enactment 
  of 
  A.B. 
  327. 
  The 
  
PUC 
  said 
  A.B. 
  327 
  addresses 
  issues 
  resolved 
  in 
  its 
  earlier 
  decision 
  and 
  that 
  it 
  will 
  administer 
  the 
  NEM 
  
program 
  in 
  accord 
  with 
  the 
  new 
  law. 
  

Legislation 
  
•

A.B. 
  2649: 
  Would 
  allow 
  a 
  U.S. 
  military 
  installation 
  to 
  exceed 
  1 
  MW 
  limitation 
  on 
  customer-­‐generators 
  if 
  
the 
  total 
  capacity 
  of 
  all 
  renewable 
  generation 
  facilities 
  on 
  the 
  installation 
  does 
  not 
  exceed 
  50% 
  of 
  the 
  
highest 
  daily 
  peak 
  demand 
  at 
  that 
  installation 
  for 
  the 
  preceding 
  calendar 
  year. 
  Each 
  physically 
  separate 
  
and 
  distinct 
  building 
  within 
  privatized 
  residential 
  housing 
  communities 
  on 
  contiguous 
  military 
  properties 
  
would 
  be 
  deemed 
  a 
  separate 
  premise 
  for 
  purposes 
  of 
  the 
  1 
  MW 
  capacity 
  limitation.
o February 
  21, 
  2014: 
  Introduced.

•

A.B. 
  327 
  (2013): 
  Authorizes 
  the 
  CPUC 
  to 
  restructure 
  rate 
  design 
  for 
  residential 
  electric 
  customers, 
  create 
  
a 
  new 
  NEM 
  program, 
  and 
  require 
  the 
  procurement 
  of 
  eligible 
  renewable 
  energy 
  resources 
  in 
  amounts 
  
greater 
  than 
  what 
  is 
  required 
  in 
  the 
  state 
  renewable 
  electricity 
  standard 
  (RES) 
  statute. 
  The 
  bill: 
  
! Repeals 
  limitations 
  on 
  residential 
  rate 
  increases 
  including 
  low-­‐income 
  rates 
  and 
  authorizes 
  
the 
  CPUC 
  to 
  approve 
  new 
  or 
  expanded 
  fixed 
  charges 
  up 
  to 
  $10/mo. 
  ($5/mo. 
  for 
  low-­‐
income), 
  with 
  increases 
  tied 
  to 
  CPI. 
  The 
  CPUC 
  is 
  allowed 
  to 
  consider 
  minimum 
  bill 
  as 
  an 
  
alternative 
  to 
  fixed 
  charges.
! Authorizes 
  the 
  CPUC 
  to 
  approve 
  for 
  each 
  utility 
  default 
  residential 
  rates 
  based 
  on 
  time-­‐of-­‐
use 
  rates. 
  Residential 
  customers 
  could 
  opt 
  to 
  decline 
  such 
  pricing 
  and 
  continue 
  to 
  pay 
  fixed 
  
rates. 
  Other 
  provisions 
  are 
  aimed 
  at 
  protecting 
  vulnerable 
  customers 
  in 
  hot 
  climate 
  zones 
  
from 
  unreasonable 
  hardship.
! Requires 
  utilities 
  to 
  provide 
  NEM 
  to 
  additional 
  customer 
  generators 
  through 
  December 
  31, 
  
2016, 
  or 
  until 
  the 
  utility 
  has 
  made 
  a 
  specified 
  amount 
  of 
  generating 
  capacity 
  available 
  to 
  
customer 
  generators, 
  whichever 
  occurs 
  first. 
  The 
  CPUC 
  must 
  develop 
  by 
  July 
  1, 
  2015, 
  a 
  
standard 
  contract 
  or 
  tariff 
  for 
  NEM 
  with 
  no 
  participation 
  limit. 
  The 
  standard 
  contract 
  or 
  
tariff 
  must 
  be 
  based 
  on 
  costs/benefits 
  received 
  by 
  non-­‐participating 
  customers 
  and 
  ensure 
  

 Timeline of Key State Activities on Net Energy Metering

9

 
  

o
o
o

nonparticipant 
  ratepayer 
  indifference. 
  Those 
  receiving 
  service 
  under 
  current 
  tariffs 
  would 
  
be 
  grandfathered 
  through 
  December 
  31, 
  2020. 
  
! Requires 
  that 
  utilities 
  file 
  by 
  July 
  1, 
  2015, 
  a 
  distribution 
  resources 
  plan 
  proposal 
  to 
  identify 
  
optimal 
  locations 
  for 
  the 
  deployment 
  of 
  distributed 
  resources. 
  
! Requires 
  the 
  CPUC 
  to 
  establish 
  an 
  RES 
  requiring 
  all 
  retail 
  sellers 
  to 
  procure 
  eligible 
  
renewable 
  energy 
  resources 
  at 
  specified 
  percentages 
  of 
  the 
  total 
  kWh 
  sold 
  to 
  their 
  retail 
  
end-­‐customers 
  during 
  specified 
  compliance 
  periods. 
  Requires 
  each 
  local 
  publicly 
  owned 
  
electric 
  utility 
  to 
  procure 
  eligible 
  renewable 
  energy 
  resources 
  to 
  achieve 
  targets. 
  Authorizes 
  
the 
  CPUC 
  to 
  require 
  a 
  retail 
  seller 
  to 
  procure 
  eligible 
  renewable 
  energy 
  resources 
  in 
  excess 
  
of 
  the 
  statutory 
  requirement. 
  Allows 
  the 
  CPUC 
  to 
  suspend 
  the 
  requirement 
  for 
  the 
  inclusive 
  
periods 
  of 
  January 
  1, 
  2014 
  to 
  December 
  31, 
  2016 
  and 
  January 
  1, 
  2017 
  to 
  December 
  31, 
  
2020, 
  until 
  the 
  state's 
  unemployment 
  rate 
  is 
  at 
  or 
  below 
  5.5% 
  for 
  4 
  consecutive 
  quarters.
May 
  23, 
  2013: 
  Passed 
  Assembly 
  on 
  66-­‐4 
  vote.
September 
  9, 
  2013: 
  Passed 
  Senate 
  on 
  33-­‐5 
  vote.
October 
  7, 
  2013: 
  Signed 
  by 
  Governor. 
  In 
  his 
  signing 
  message, 
  the 
  Governor 
  encouraged 
  the 
  CPUC 
  to 
  
decide 
  to 
  grandfather 
  existing 
  customers 
  for 
  the 
  expected 
  life 
  span 
  of 
  their 
  solar 
  systems, 
  which 
  
goes 
  beyond 
  A.B. 
  327 
  grandfathering 
  provisions. 
  
http://gov.ca.gov/docs/AB_327_2013_Signing_Message.pdf 
  

 
  
•

S.B. 
  43 
  (2013): 
  Provides 
  for 
  creation 
  of 
  the 
  Green 
  Tariff 
  Shared 
  Renewables 
  Program. 
  Electrical 
  
corporations 
  with 
  100,000 
  or 
  more 
  customers 
  must 
  file 
  with 
  the 
  CPUC 
  an 
  application 
  requesting 
  
approval 
  of 
  a 
  program 
  that 
  would 
  enable 
  ratepayers 
  such 
  as 
  renters 
  who 
  cannot 
  install 
  their 
  own 
  DG 
  to 
  
participate 
  directly 
  in 
  offsite 
  electrical 
  generation 
  facilities 
  that 
  use 
  eligible 
  renewable 
  energy 
  resources. 
   
  
o May 
  30, 
  2013: 
  Passed 
  Senate 
  on 
  27-­‐9 
  vote. 
  
o September 
  11, 
  2013: 
  Passed 
  Assembly 
  on 
  53-­‐22 
  vote. 
  
o September 
  28, 
  2013: 
  Signed 
  by 
  the 
  Governor. 
  

 
  
Other 
  Policy 
  Initiatives 
  
•

CEC 
  proceeding 
  on 
  DG 
  integration 
  analysis, 
  Docket 
  No. 
   
  13-­‐IEP-­‐1H 
  
o The 
  California 
  Energy 
  Commission 
  (CEC) 
  contracted 
  with 
  Navigant 
  Consulting 
  to 
  examine 
  costs 
  and 
  
impacts 
  of 
  increased 
  DG 
  penetration 
  levels 
  on 
  a 
  utility 
  electricity 
  system. 
  CEC 
  partnered 
  with 
  
Southern 
  California 
  Edison 
  to 
  use 
  its 
  system 
  for 
  the 
  study. 
  The 
  initiative 
  grew 
  out 
  of 
  an 
  SCE 
  study, 
  
The 
  Impact 
  of 
  Localized 
  Energy 
  Resources 
  on 
  Southern 
  California 
  Edison’s 
  Transmission 
  and 
  
Distribution 
  System, 
  May 
  2012, 
  and 
  Gov. 
  Brown’s 
  Clean 
  Energy 
  Jobs 
  Plan 
  setting 
  a 
  goal 
  of 
  12,000 
  
MW 
  of 
  localized 
  energy 
  development 
  in 
  California 
  by 
  2020. 
  
o August 
   22, 
   2013: 
   Preliminary 
   results 
   presented 
   at 
   CEC 
   staff 
   workshop. 
   Presentations 
   located 
   at: 
  
http://www.energy.ca.gov/2013_energypolicy/documents/2013-­‐08-­‐22_workshop/presentations/ 
   
  
o As 
  of 
  November 
  1, 
  2013: 
  The 
  report 
  is 
  in 
  draft 
  final 
  stage 
  and 
  expected 
  to 
  be 
  released 
  soon. 
  
o December 
  3, 
  2013: 
  Final 
  consultant 
  report 
  released. 
  Excerpt 
  from 
  abstract: 
  “This 
  study 
  validated 
  
Southern 
  California 
  Edison’s 
  approach 
  and 
  concluded 
  that 
  the 
  cost 
  to 
  integrate 
  localized 
  renewable 
  
energy 
  resources 
  depends 
  highly 
  upon 
  locational 
  factors 
  for 
  both 
  the 
  distribution 
  and 
  transmission 
  
systems. 
  Additionally, 
  it 
  concludes 
  that 
  policies 
  to 
  guide 
  projects 
  to 
  areas 
  better 
  equipped 
  to 
  
accommodate 
  renewable 
  distributed 
  generation 
  can 
  significantly 
  reduce 
  integration 
  costs. 
  The 
  

 Timeline of Key State Activities on Net Energy Metering

10

 
  
Energy 
  Commission 
  considers 
  this 
  study 
  a 
  first 
  step 
  toward 
  the 
  2012 
  Integrated 
  Energy 
  Policy 
  Report 
  
Update 
  goals 
  of 
  identifying 
  preferred 
  areas 
  for 
  renewable 
  distributed 
  generation 
  and 
  minimizing 
  
interconnection 
  and 
  integration 
  costs 
  and 
  requirements.” 
  
 
  
• CEC 
  proceeding 
  on 
  petition 
  for 
  societal 
  cost-­‐benefit 
  evaluation 
  of 
  California’s 
  NEM 
  program, 
  Docket 
  
No. 
  13-­‐IEP-­‐1. 
  The 
  petition 
  is 
  part 
  of 
  the 
  docket 
  on 
  the 
  2013 
  Integrated 
  Energy 
  Policy 
  Report 
  (IEPR). 
  The 
  
CEC 
  adopts 
  and 
  IEPR 
  every 
  two 
  years 
  and 
  an 
  update 
  every 
  other 
  year. 
   
  
o Petition 
  by 
  joint 
  coalition, 
  comments, 
  and 
  other 
  docket 
  materials 
  are 
  available 
  at: 
  
http://www.energy.ca.gov/2013_energypolicy/documents/ 
   
  
• June 
  7, 
  2013: 
  CEC 
  issued 
  notice 
  requesting 
  comments 
  on 
  joint 
  petition. 
  
• June 
  28, 
  2013: 
  Comments 
  due. 
  
o July 
  15, 
  2013: 
  Reply 
  comments 
  due. 
   
   
  
o January 
  15, 
  2013: 
  2013 
  IEPR 
  adopted. 
  Final 
  report 
  is 
  available 
  at: 
  
http://www.energy.ca.gov/2013_energypolicy/ 
   
  

COLORADO 
  
Rates 
  and 
  Regulation 
  
•

Xcel 
  Energy 
  2014 
  RES 
  Compliance 
  Plan, 
  Docket 
  No. 
  13A-­‐0836E 
  
o July 
  24, 
  2013: 
  Xcel 
  Energy 
  filed 
  with 
  the 
  CO 
  Public 
  Utilities 
  Commission 
  (PUC) 
  its 
  2014 
  RES 
  
http://infocastinc.com/events/ca-­‐energy13 
  compliance 
  plan. 
  In 
  its 
  plan, 
  the 
  company 
  proposes: 
  1) 
  
Achieving 
  transparency 
  by 
  including 
  the 
  cost 
  for 
  net 
  metering 
  of 
  new 
  installations 
  in 
  the 
  existing 
  RES 
  
adjustment 
  mechanism 
  while 
  at 
  same 
  time 
  crediting 
  an 
  equal 
  amount 
  to 
  the 
  electric 
  commodity 
  
adjustment, 
  resulting 
  in 
  continued 
  socialization 
  and 
  recovery 
  of 
  costs 
  from 
  all 
  customers; 
  2) 
  If 
  the 
  
transparency 
  proposal 
  is 
  approved, 
  acquire 
  42.5 
  MW 
  to 
  comply 
  with 
  the 
  state 
  RES; 
  3) 
  If 
  the 
  
transparency 
  proposal 
  is 
  rejected, 
  acquire 
  12.5 
  MW 
  for 
  achieving 
  “minimum” 
  RES 
  compliance. 
  A 
  
study 
  by 
  Xcel 
  Energy 
  of 
  the 
  costs 
  and 
  benefits 
  of 
  net 
  metering 
  is 
  at 
  issue 
  in 
  this 
  proceeding. 
  The 
  
study 
  was 
  filed 
  in 
  Docket 
  No. 
  11M-­‐426E, 
  a 
  proceeding 
  opened 
  in 
  2011 
  to 
  gather 
  research 
  on 
  the 
  
costs 
  and 
  benefits 
  of 
  net 
  metering. 
  
o September 
  18, 
  2013: 
  Vote 
  Solar 
  Initiative 
  moved 
  to 
  sever 
  net 
  metering 
  from 
  consideration 
  of 
  2014 
  
RES 
  compliance 
  plan 
  and 
  to 
  order 
  a 
  full 
  evaluation 
  of 
  costs 
  and 
  benefits 
  of 
  net 
  metering 
  in 
  the 
  
previously 
  mentioned 
  Docket 
  No. 
  11M-­‐426E. 
  
o September 
  20, 
  2013: 
  Xcel 
  Energy 
  filed 
  response 
  opposing 
  Vote 
  Solar 
  Initiative 
  motion. 
  
o October 
  2, 
  2013: 
  The 
  PUC 
  denied 
  Vote 
  Solar 
  Initiative 
  motion. 
  
o October 
  22, 
  2013: 
  The 
  Colorado 
  Energy 
  Office 
  (CEO) 
  moved 
  for 
  late 
  intervention 
  because 
  the 
  
proceeding 
  concerns 
  issues 
  around 
  the 
  costs 
  and 
  benefits 
  of 
  DG 
  and 
  because 
  the 
  PUC 
  closed 
  the 
  
cost-­‐benefit 
  proceeding. 
  (Docket 
  No. 
  11M-­‐426E, 
  below) 
  The 
  CEO 
  hired 
  independent 
  facilitator 
  
George 
  Burmeister 
  to 
  conduct 
  discussions 
  among 
  stakeholders 
  in 
  an 
  effort 
  to 
  reach 
  a 
  consensus. 
  
(See 
  item 
  below-­‐Other 
  Policy 
  Initiatives.) 
  
o October 
  31, 
  2013: 
  The 
  Alliance 
  for 
  Solar 
  Choice 
  (TASC) 
  filed 
  a 
  motion 
  to 
  strike 
  portions 
  of 
  Xcel 
  
Energy’s 
  plan 
  relating 
  to 
  inclusion 
  of 
  net 
  metering 
  costs 
  in 
  the 
  2014 
  RES 
  adjustment. 
  Any 
  such 
  
determination 
  must 
  be 
  made 
  via 
  rulemaking, 
  TASC 
  said. 
  

 Timeline of Key State Activities on Net Energy Metering

11

 
  
November 
  14, 
  2013: 
  Xcel 
  Energy 
  filed 
  a 
  response 
  to 
  TASC 
  motion, 
  saying 
  the 
  motion 
  has 
  no 
  legal 
  
basis 
  and 
  the 
  proceeding 
  is 
  utility-­‐specific 
  and 
  does 
  not 
  seek 
  to 
  change 
  RES 
  rules. 
  
o November 
  26, 
  2013: 
  The 
  ALJ 
  issued 
  an 
  interim 
  ruling 
  denying 
  the 
  TASC 
  motion 
  to 
  strike 
  and 
  saying 
  a 
  
separate 
  “motion 
  to 
  certify” 
  on 
  a 
  legal 
  determination 
  – 
  that 
  interim 
  denial 
  of 
  the 
  motion 
  to 
  strike 
  is 
  
immediately 
  appealable 
  – 
  will 
  be 
  decided 
  separately. 
  
o December 
  2, 
  2013: 
  Testimony 
  due. 
   
  
o December 
  6, 
  2013: 
  Xcel 
  Energy 
  filed 
  response 
  in 
  opposition 
  to 
  TASC 
  motion 
  to 
  certify. 
  
o December 
  11, 
  2013: 
  Protest 
  rally 
  in 
  Denver 
  planned 
  by 
  HostVote 
  Solar, 
  TASC, 
  COSEIA, 
  Environment 
  
Colorado, 
  and 
  others. 
  The 
  groups 
  delivered 
  a 
  petition 
  to 
  Xcel 
  Energy 
  to 
  withdraw 
  its 
  filing. 
  The 
  
petition 
  was 
  written 
  by 
  SEIA 
  and 
  had 
  about 
  27,000 
  signatures. 
  
o December 
  26, 
  2013: 
  The 
  ALJ 
  issued 
  an 
  interim 
  order 
  denying 
  the 
  TASC 
  motion 
  to 
  certify, 
  saying 
  TASC 
  
failed 
  to 
  show 
  extraordinary 
  relief 
  is 
  warranted. 
   
  
o January 
  17, 
  2013: 
  Rebuttal 
  testimony 
  due. 
  
o January 
  21, 
  2014: 
  CO 
  Energy 
  Office 
  filed 
  motion 
  to 
  separate 
  NEM 
  issues 
  from 
  this 
  proceeding 
  and 
  to 
  
consider 
  them 
  in 
  a 
  new 
  docket. 
  TASC 
  issued 
  press 
  release 
  in 
  support 
  of 
  motion. 
  Xcel 
  also 
  filed 
  in 
  
support 
  of 
  the 
  motion 
  but 
  objected 
  to 
  CEO 
  procedural 
  recommendations. 
  The 
  Office 
  of 
  Consumer 
  
Counsel 
  also 
  raised 
  procedural 
  concerns. 
  
o January 
  29, 
  2014: 
  PUC 
  issued 
  interim 
  decision 
  saying 
  it 
  needs 
  more 
  time 
  to 
  deliberate 
  on 
  CO 
  Energy 
  
Office 
  motion 
  and 
  will 
  make 
  a 
  decision 
  on 
  the 
  merits 
  in 
  the 
  next 
  several 
  weeks. 
  The 
  order 
  also 
  
vacated 
  certain 
  procedural 
  steps. 
  
o February 
  3, 
  2014: 
  Public 
  hearing 
  held 
  with 
  large 
  turnout 
  by 
  solar 
  advocates. 
  
o February 
  18, 
  2014: 
  Xcel 
  moved 
  for 
  temporary 
  suspension 
  of 
  PUC 
  deliberations; 
  TASC 
  filed 
  response 
  
in 
  opposition. 
  
o February 
  27, 
  2014: 
  The 
  PUC 
  issued 
  an 
  interim 
  decision 
  that 
  grants 
  the 
  CO 
  Energy 
  Office 
  request 
  to 
  
sever 
  NEM 
  issues. 
  A 
  new 
  NEM 
  proceeding 
  will 
  be 
  opened 
  by 
  a 
  separate, 
  future 
  order. 
  
o March 
  12, 
  2014: 
  Supplemental 
  testimony 
  due 
  addressing 
  party 
  positions 
  in 
  light 
  of 
  NEM 
  severance. 
   
  
o March 
  17, 
  2014: 
  Prehearing 
  conference. 
  
 
  
Solar 
  PV 
  Financial 
  Incentives, 
  Docket 
  No. 
  11M-­‐426E. 
  CLOSED 
   
  
o May 
  18, 
  2013: 
  The 
  CO 
  PUC 
  opened 
  docket 
  to 
  gather 
  research 
  on 
  current 
  and 
  historic 
  solar 
  PV 
  
incentive 
  practices. 
   
   
  
o May 
  23, 
  2013: 
  Xcel 
  Energy 
  filed 
  a 
  report 
  on 
  the 
  costs/benefits 
  of 
  DG. 
  
o September 
  9, 
  2013: 
  Comments 
  due 
  on 
  Xcel 
  Energy 
  report. 
   
  
o October 
  2, 
  2013: 
  Proceeding 
  closed. 
  The 
  PUC 
  said 
  the 
  docket 
  fulfilled 
  its 
  purpose 
  in 
  gathering 
  
research 
  and 
  the 
  Xcel 
  Energy 
  study 
  is 
  at 
  issue 
  in 
  Docket 
  No. 
  13A-­‐0836E 
  (above). 
  The 
  Xcel 
  Energy 
  
report 
  and 
  comments 
  are 
  posted 
  at: 
  https://www.dora.state.co.us/pls/efi/EFI_Search_UI.search 
   
  
o

•

Legislation 
   
  
•

 
  

H.B. 
  1113: 
  Would 
  reduce 
  the 
  RPS 
  target 
  for 
  investor-­‐owned 
  utilities 
  from 
  20% 
  to 
  15% 
  for 
  the 
  years 
  2015 
  
through 
  2019, 
  and 
  from 
  30%-­‐15% 
  for 
  the 
  years 
  2020 
  and 
  thereafter. 
  Cooperative 
  targets 
  would 
  be 
  
reduced 
  as 
  well. 
  
o January 
  15, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  Transportation 
  and 
  Energy 
  Committee. 
  
o January 
  30, 
  2014: 
  Hearing 
  held. 
  The 
  bill 
  is 
  not 
  likely 
  to 
  receive 
  further 
  consideration 
  during 
  this 
  
session. 
  

 Timeline of Key State Activities on Net Energy Metering

12

 
  
•

•

•

 
  
H.B. 
  1118: 
  Would 
  include 
  hydro 
  and 
  pumped 
  storage 
  as 
  RPS-­‐eligible 
  resources. 
   
  
o January 
  16, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  the 
  House 
  Transportation 
  and 
  Energy 
  Committee. 
   
   
  
 
  
S.B. 
  35: 
  Would 
  reverse 
  the 
  RPS 
  from 
  20% 
  back 
  to 
  10% 
  for 
  electric 
  associations 
  serving 
  100,000 
  or 
  more 
  
meters. 
  Eliminates 
  coal 
  mine 
  methane 
  and 
  synthetic 
  gas 
  produced 
  by 
  pyrolysis 
  of 
  municipal 
  waste 
  from 
  
unapproved 
  energy 
  resources. 
  Reduces 
  the 
  retail 
  rate 
  impact 
  of 
  compliance 
  back 
  to 
  1%. 
  Eliminates 
  
distributed 
  generation 
  subsidies. 
  Eliminates 
  reporting 
  requirements 
  and 
  portfolio 
  standards 
  for 
  
cooperative 
  electric 
  associations. 
  
o January 
  8, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  State, 
  Veterans 
  and 
  Military 
  Affairs. 
   
  
o January 
  15, 
  2014. 
  Hearing 
  held. 
  The 
  bill 
  failed 
  in 
  committee; 
  will 
  no 
  longer 
  be 
  considered 
  in 
  2014. 
   
  
 
  
S.B. 
  252 
  (2013): 
  For 
  rural 
  electric 
  cooperatives 
  serving 
  100,000 
  or 
  more 
  meters, 
  establishes 
  1% 
  DG 
  
carve-­‐out 
  and 
  increases 
  RES 
  from 
  10% 
  to 
  20% 
  by 
  2020, 
  with 
  cost 
  increases 
  capped 
  at 
  2%. 
  (Investor-­‐
owned 
  utilities 
  are 
  already 
  subject 
  to 
  a 
  30% 
  by 
  2020 
  standard 
  and 
  3% 
  DG 
  carve-­‐out.) 
  Adds 
  coal 
  mine 
  
methane 
  and 
  municipal 
  waste 
  synthetic 
  gas 
  to 
  eligible 
  RES 
  resources. 
  Eliminates 
  in-­‐state 
  preference. 
  
o June 
  5, 
  2013: 
  Enacted. 
  

Other 
  Policy 
  Initiatives 
  
•

•

January 
  8, 
  2014: 
  Glenn 
  Vaad 
  was 
  sworn 
  in 
  as 
  one 
  of 
  three 
  Colorado 
  PUC 
  members 
  despite 
  criticism 
  of 
  
his 
  past 
  membership 
  in 
  the 
  American 
  Legislative 
  Exchange 
  Council. 
  Vaad 
  is 
  a 
  former 
  state 
  representative 
  
from 
  Mead. 
  He 
  still 
  requires 
  approval 
  by 
  the 
  legislature. 
  
 
  
October 
  29, 
  2013: 
  The 
  Colorado 
  Energy 
  Office 
  began 
  facilitating 
  discussions 
  on 
  the 
  value 
  of 
  solar 
  to 
  seek 
  
consensus 
  where 
  possible. 
  
• News 
  article: 
  Solar 
  advocates 
  and 
  Xcel 
  spar 
  over 
  the 
  future 
  of 
  rooftop 
  solar 
  power, 
  October 
  
29, 
  2013, 
  by 
  Mark 
  Jaffe, 
  The 
  Denver 
  Post 
   
  
o November 
  18, 
  2013: 
  Next 
  CEO 
  facilitated 
  meeting 
  held. 
  Consensus 
  language 
  has 
  not 
  emerged 
  and 
  
no 
  further 
  meetings 
  are 
  planned 
  at 
  this 
  time. 
  

CONNECTICUT 
  
Rates 
  and 
  Regulation 
  
•

 
  

Development 
  of 
  administrative 
  processes 
  and 
  program 
  specifications 
  for 
  virtual 
  net 
  metering, 
  per 
  H.B. 
  
6360 
  (Public 
  Act 
  13-­‐298), 
  Docket 
  No. 
  13-­‐08-­‐14 
  
o September 
  23, 
  2013: 
  Technical 
  meeting 
  held. 
  Minutes: 
  
http://www.dpuc.state.ct.us/dockcurr.nsf/8e6fc37a54110e3e852576190052b64d/2c8d905fdb80b6
9785257bef006b46b6?OpenDocument 
   
  
o October 
  24, 
  2013: 
  Working 
  group 
  meeting. 
  
o February 
  12, 
  2014: 
  Working 
  group 
  report 
  released. 
  
 
  

 Timeline of Key State Activities on Net Energy Metering

13

 
  
Legislation 
  
•

•

H.B. 
  6360 
  (2013): 
  An 
  act 
  concerning 
  implementation 
  of 
  Connecticut’s 
  comprehensive 
  energy 
  strategy 
  
and 
  various 
  revisions 
  to 
  the 
  energy 
  statutes. 
  Broadens 
  eligibility 
  for 
  virtual 
  net 
  metering 
  in 
  several 
  ways, 
  
including 
  opening 
  the 
  option 
  to 
  state 
  agencies 
  and 
  agricultural 
  customers 
  and 
  increasing 
  the 
  maximum 
  
size 
  of 
  the 
  eligible 
  renewable 
  resource 
  from 
  2 
  to 
  3 
  MW. 
  Applies 
  virtual 
  net 
  metering 
  credit 
  against 
  
customer’s 
  generation 
  service 
  charge 
  (GSC) 
  and 
  a 
  declining 
  percentage 
  of 
  distribution 
  and 
  transmission 
  
charges, 
  thereby 
  increasing 
  its 
  value 
  compared 
  to 
  prior 
  law, 
  which 
  provided 
  that 
  the 
  credit 
  be 
  applied 
  
against 
  the 
  GSC. 
  Allows 
  any 
  virtual 
  net 
  metered 
  customer 
  to 
  aggregate 
  meters 
  that 
  are 
  billed 
  to 
  the 
  
customer 
  host 
  of 
  the 
  generation 
  facility. 
  
o July 
  8, 
  2013: 
  Enacted. 
  
 
  
S.B. 
  1138 
  (2013): 
  Amends 
  the 
  state 
  RES 
  to 
  allow 
  large 
  hydro 
  to 
  count 
  as 
  eligible 
  resource 
  under 
  certain 
  
conditions 
  and 
  reduces 
  value 
  of 
  renewable 
  energy 
  credits 
  for 
  certain 
  biomass 
  facilities. 
  Alternative 
  
compliance 
  payments 
  must 
  be 
  used 
  to 
  reduce 
  rates. 
  
o June 
  5, 
  2013: 
  Enacted. 
  

DISTRICT 
  OF 
  COLUMBIA 
  
Legislation 
  
•

D.C. 
  B20 
  57 
  (2013): 
  Community 
  Renewable 
  Energy 
  Amendment 
  Act 
  of 
  2013 
  allows 
  virtual 
  net 
  metering. 
   
  
o October 
  7, 
  2013: 
  Passed 
  City 
  Council. 
  
o October 
  17, 
  2013: 
  Signed 
  by 
  mayor. 
  
o October 
  24, 
  2013: 
  Transmitted 
  to 
  Congress 
  for 
  review. 
   
  
o December 
  31, 
  2013: 
  Projected 
  DC 
  law 
  date. 
  

GEORGIA 
  
Rates 
  and 
  Regulation 
  
•

•

Georgia 
  Power 
  2013 
  integrated 
  resource 
  plan, 
  Docket 
  No. 
  36498 
  
o July 
  11, 
  2013: 
  The 
  GA 
  Public 
  Service 
  Commission 
  (PSC) 
  voted 
  to 
  require 
  Georgia 
  Power 
  to 
  include 
  in 
  
its 
  2013 
  integrated 
  resource 
  plan 
  an 
  additional 
  525 
  MW 
  of 
  solar 
  generation, 
  including 
  100 
  MW 
  of 
  
distributed 
  solar 
  generation, 
  to 
  be 
  procured 
  via 
  competitive 
  bidding. 
  
 
  
Georgia 
  Power 
  general 
  rate 
  case, 
  Docket 
  No. 
  36989 
  
o June 
  28, 
  2013: 
  Rate 
  case 
  filed. 
  Includes 
  proposal 
  to 
  eliminate 
  unused 
  backup 
  power 
  tariff 
  and 
  
institute 
  new 
  supplemental 
  power 
  service 
  (SPS) 
  tariff, 
  which 
  would 
  apply 
  to 
  residential 
  customers 
  
who 
  do 
  not 
  participate 
  in 
  the 
  company’s 
  Advanced 
  Solar 
  Initiative. 
  The 
  tariff 
  would 
  apply 
  to 
  
customers 
  of 
  any 
  size 
  who 
  self-­‐generate 
  behind 
  the 
  meter, 
  who 
  require 
  supplementary 
  power, 
  and 
  
who 
  install 
  their 
  generation 
  after 
  January 
  1, 
  2014. 
  The 
  company’s 
  existing 
  real-­‐time 
  pricing 
  (RTP) 
  
tariff 
  currently 
  makes 
  available 
  such 
  service 
  to 
  large 
  cogenerating 
  and 
  QF 
  customers 
  at 
  
approximately 
  avoided 
  cost. 
   
  Under 
  the 
  proposed 
  new 
  tariff, 
  small 
  and 
  medium 
  customers 
  would 
  be 
  
able 
  to 
  purchase 
  supplemental 
  power 
  as 
  well 
  as 
  receive 
  credit 
  for 
  generation 
  that 
  offsets 
  usage. 
  

 Timeline of Key State Activities on Net Energy Metering

14

 
  

o
o
o
o
o

They 
  would 
  be 
  required 
  to 
  subscribe 
  to 
  a 
  demand 
  billing 
  rate 
  or 
  pay 
  an 
  additional 
  charge 
  per 
  kW 
  of 
  
installed 
  capacity. 
   
  
October 
  1-­‐3, 
  2013: 
  PSC 
  hearing 
  held. 
  
October 
  18, 
  2013: 
  Staff/intervenor 
  testimony 
  due. 
  Staff 
  recommended 
  disallowing 
  the 
  proposed 
  
new 
  solar 
  tariff. 
   
  
November 
  5-­‐7, 
  2013: 
  Second 
  round 
  of 
  hearings. 
  
November 
  18, 
  2013: 
  On 
  rebuttal, 
  GP 
  filed 
  a 
  settlement 
  providing 
  for, 
  among 
  other 
  things, 
  
withdrawal 
  of 
  the 
  proposed 
  SPS 
  tariff. 
  The 
  settlement 
  must 
  be 
  approved 
  by 
  the 
  PSC. 
  
December 
  17, 
  2013: 
  The 
  PSC 
  unanimously 
  approved 
  the 
  settlement. 
  

Legislation 
  
•

•

 
  

H.B. 
  657: 
  Would 
  authorize 
  the 
  PSC 
  to 
  establish 
  rural 
  voluntary 
  community 
  solar 
  initiative 
  and 
  oversee 
  
and 
  manage 
  “responsible” 
  expansion 
  of 
  solar 
  energy, 
  including 
  prevention 
  of 
  involuntary 
  ratepayer 
  
subsidies. 
  
o March 
  26, 
  2013: 
  Date 
  filed. 
  Although 
  too 
  late 
  to 
  pass 
  in 
  2013 
  legislative 
  term, 
  filing 
  aimed 
  at 
  
facilitating 
  stakeholder 
  input. 
  Will 
  carry 
  over 
  to 
  next 
  session. 
  
o October 
  30, 
  2013: 
  House 
  Energy, 
  Utilities 
  and 
  Telecommunications 
  Committee 
  met 
  to 
  discuss 
  bill. 
  
The 
  committee 
  will 
  not 
  meet 
  again 
  before 
  the 
  next 
  session 
  begins 
  on 
  January 
  13, 
  2014. 
  Summary 
  
from 
  Stateside 
  Associates: 
  “…The 
  proponent 
  of 
  the 
  bill, 
  Representative 
  Culver 
  (R) 
  outlined 
  the 
  need 
  
for 
  this 
  bill. 
  Robert 
  Green, 
  President 
  Georgia 
  Solar 
  Utilities, 
  testified 
  in 
  support 
  of 
  this 
  measure 
  as 
  
well. 
  Mr. 
  Green 
  testified 
  that 
  solar 
  power 
  is 
  less 
  expensive 
  per 
  kilowatt 
  per 
  hour 
  than 
  any 
  form 
  of 
  
energy 
  provided 
  by 
  electric 
  utilities 
  and 
  that 
  the 
  more 
  solar 
  power 
  a 
  property 
  possess 
  the 
  more 
  
competitive 
  it 
  is 
  than 
  property 
  without 
  its 
  own 
  energy 
  generation. 
  Mr. 
  Green 
  was 
  questioned 
  
repeatedly 
  by 
  the 
  committee, 
  as 
  some 
  members 
  disagreed 
  vehemently 
  with 
  his 
  testimony. 
   
  
Several 
  opponents 
  testified 
  against 
  the 
  bill 
  including 
  Bill 
  Verner, 
  External 
  Affairs, 
  Georgia 
  EMC, 
  
representing 
  Georgia’s 
  electric 
  cooperatives. 
  He 
  testified 
  that 
  the 
  industry 
  is 
  doing 
  quite 
  well 
  
already 
  and 
  that 
  this 
  measure 
  is 
  not 
  necessary 
  and 
  will 
  require 
  cooperatives 
  to 
  fight 
  for 
  needed 
  
exemptions. 
  Due 
  to 
  time 
  constraints 
  and 
  the 
  amount 
  of 
  public 
  testimony, 
  the 
  topic 
  of 
  climate 
  
change 
  issues 
  was 
  tabled 
  for 
  a 
  hearing 
  yet 
  to 
  be 
  scheduled. 
  A 
  vote 
  did 
  not 
  take 
  place. 
  The 
  meeting 
  
was 
  open 
  to 
  the 
  public 
  and 
  public 
  testimony 
  was 
  accepted.” 
  
• News 
  article: 
  Outlook 
  for 
  solar 
  bill 
  isn’t 
  bright 
  in 
  Georgia, 
  October 
  30, 
  2013, 
  by 
  Walter 
  C. 
  
Jones, 
  The 
  Florida 
  Times-­‐Union 
   
  
 
  
H.B. 
  874: 
  Would 
  allow 
  third-­‐party 
  solar 
  financing. 
   
  
o January 
  28, 
  2014: 
  Introduced. 
  
o January 
  31, 
  2014: 
  Referred 
  to 
  Committee 
  on 
  Energy, 
  Utilities 
  and 
  Telecommunications. 
  
o February 
  20, 
  2014: 
  Hearing 
  held. 
  While 
  it 
  initially 
  appeared 
  that 
  the 
  bill 
  would 
  be 
  subject 
  to 
  further 
  
review 
  for 
  the 
  remainder 
  of 
  the 
  year, 
  House 
  leadership 
  is 
  reported 
  to 
  have 
  agreed 
  to 
  move 
  the 
  bill. 
  
o March 
  3, 
  2014: 
  Committee 
  amendments 
  possible, 
  after 
  which 
  the 
  bill 
  could 
  move 
  to 
  the 
  House 
  floor 
  
for 
  a 
  vote. 
  
o March 
  4, 
  2014: 
  Failed 
  crossover 
  deadline. 
  The 
  bill 
  is 
  unlikely 
  to 
  receive 
  further 
  consideration. 
  
 
  

 Timeline of Key State Activities on Net Energy Metering

15

 
  

HAWAII 
  
Rates 
  and 
  Regulation 
  
•

Generic 
  proceeding 
  on 
  DG 
  
o 2014: 
  The 
  HI 
  PUC 
  is 
  expected 
  to 
  open 
  a 
  docket 
  to 
  take 
  a 
  comprehensive 
  look 
  at 
  DG 
  in 
  the 
  state 
  
including 
  net 
  metering. 
  
o January 
  2014: 
  The 
  PUC 
  issued 
  a 
  study 
  on 
  NEM 
  costs/benefits 
  prepared 
  by 
  consultant 
  E3. 
   
  

Legislation 
  
 
  
• H.B. 
  1541: 
  States 
  that 
  nothing 
  shall 
  prevent 
  an 
  eligible 
  customer-­‐generator 
  from 
  contracting 
  with 
  a 
  
licensed 
  electrician 
  to 
  install 
  an 
  approved 
  meter 
  at 
  the 
  customer-­‐generator's 
  own 
  expense. 
  Requires 
  a 
  
utility 
  to 
  install 
  and 
  purchase 
  a 
  new 
  meter 
  for 
  a 
  customer-­‐generator, 
  should 
  a 
  customer-­‐generator's 
  
current 
  meter 
  fail 
  to 
  measure 
  electricity 
  flow 
  in 
  two 
  directions. 
  States 
  that 
  customers 
  who 
  generate 
  
solar, 
  wind 
  turbine, 
  biomass, 
  or 
  hydroelectric 
  energy 
  are 
  eligible 
  to 
  receive 
  net 
  metering 
  service. 
   
  
Amends 
  the 
  definition 
  of 
  "net 
  energy 
  metering" 
  to 
  measuring 
  the 
  difference 
  between 
  the 
  electricity 
  
supplied 
  through 
  the 
  electric 
  grid 
  and 
  the 
  electricity 
  generated 
  by 
  an 
  eligible 
  customer-­‐generator 
  and 
  
fed 
  back 
  to 
  the 
  electric 
  grid 
  over 
  a 
  monthly 
  billing 
  period. 
  
o January 
  9, 
  2014: 
  Prefiled. 
  
o January 
  15, 
  2014: 
  Referred 
  to 
  House 
  committees 
  on 
  Commerce 
  and 
  Consumer 
  Affairs, 
  and 
  Energy 
  
and 
  Environmental 
  Protection. 
  
 
  
• H.B. 
  1543: 
  States 
  that 
  an 
  electric 
  utility 
  shall 
  make 
  available 
  to 
  the 
  eligible 
  customer-­‐generator 
  the 
  
option 
  of 
  receiving 
  compensation 
  in 
  lieu 
  of 
  a 
  credit 
  for 
  excess 
  kilowatt-­‐hours. 
  States 
  that 
  the 
  rate 
  at 
  
which 
  compensation 
  will 
  be 
  added 
  will 
  be 
  determined 
  by 
  the 
  HI 
  PUC. 
  Requires 
  that 
  credits 
  for 
  excess 
  
electricity 
  from 
  the 
  eligible 
  customer-­‐generator 
  that 
  remain 
  unused 
  after 
  each 
  12-­‐month 
  reconciliation 
  
period 
  shall 
  be 
  carried 
  over 
  to 
  the 
  next 
  12-­‐month 
  period. 
  
o January 
  9, 
  2014: 
  Prefiled. 
  
o January 
  15, 
  2014: 
  Referred 
  to 
  House 
  committees 
  on 
  Commerce 
  and 
  Consumer 
  Affairs, 
  and 
  Energy 
  
and 
  Environmental 
  Protection. 
  
o February 
  11, 
  2014: 
  Hearing 
  held, 
  amended 
  and 
  passed 
  8-­‐1 
  by 
  Energy 
  committee. 
  
 
  
• H.B. 
  1878: 
  Would 
  require 
  the 
  PUC 
  to 
  create 
  an 
  interconnection 
  fee 
  schedule 
  that 
  may 
  be 
  charged 
  by 
  a 
  
utility 
  to 
  an 
  eligible 
  customer-­‐generator 
  for 
  connecting 
  a 
  solar 
  facility 
  to 
  the 
  electrical 
  grid. 
  
o January 
  17, 
  2014: 
  Introduced. 
  
o February 
  10, 
  2014: 
  Hearing 
  held. 
  
o February 
  12, 
  2014: 
  Decision 
  meeting 
  held. 
  Action 
  deferred; 
  measure 
  is 
  awaiting 
  further 
  committee 
  
action. 
  
 
  
• H.B.1939: 
  Would 
  extend 
  Clean 
  Energy 
  Initiative 
  goals 
  to 
  2050 
  and 
  RPS 
  to 
  100% 
  clean 
  energy 
  by 
  2050. 
   
   
  
o January 
  17 
  & 
  24, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  committees 
  on 
  Energy 
  and 
  Environmental 
  
Protection; 
  and 
  Consumer 
  Protection 
  and 
  Commerce. 
  
o February 
  11, 
  2014: 
  Energy 
  Committee 
  held 
  hearing, 
  passed 
  measure 
  9-­‐0. 
  

 Timeline of Key State Activities on Net Energy Metering

16

 
  
February 
  24 
  & 
  26, 
  2014: 
  Consumer 
  Protection 
  hearing 
  held. 
   
  
 
  
H.B. 
  1943: 
  Requires 
  the 
  PUC 
  to 
  adopt 
  rules 
  for 
  improved 
  accessibility 
  to 
  connect 
  to 
  grid 
  and 
  to 
  initiate 
  a 
  
proceeding 
  by 
  July 
  1, 
  2014, 
  to 
  discuss 
  system 
  upgrades 
  to 
  accommodate 
  anticipated 
  growth 
  of 
  customer 
  
generation. 
  
o January 
  17 
  & 
  24, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  committees 
  on 
  Energy 
  and 
  Environmental 
  
Protection; 
  Consumer 
  Protection 
  and 
  Commerce; 
  and 
  Finance. 
  
o January 
  30, 
  2014: 
  Hearing 
  held 
  by 
  Energy. 
  Bill 
  was 
  amended 
  and 
  passed 
  7-­‐3. 
  Current 
  version 
   
  
o February 
  10, 
  2014: 
  Hearing 
  held. 
   
  
o February 
  12, 
  2014: 
  Decision 
  meeting 
  held 
  by 
  Consumer 
  protection. 
  Amended 
  and 
  passed 
  13-­‐0. 
   
  
o February 
  20, 
  2014: 
  Hearing 
  held 
  by 
  Finance. 
   
  
o February 
  26, 
  2014: 
  Decision 
  meeting 
  held; 
  passed 
  Finance 
  17-­‐0. 
  
o March 
  4, 
  2014: 
  Passed 
  House 
  without 
  opposition. 
  
 
  
H.B. 
  2141: 
  Would 
  establish 
  community-­‐based 
  renewable 
  energy 
  program. 
  
o January 
  21 
  & 
  24, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  committees 
  on 
  Energy 
  and 
  Environmental 
  
Protection; 
  Consumer 
  Protection 
  and 
  Commerce; 
  and 
  Economic 
  Development 
  and 
  Business. 
  
o January 
  30, 
  2014: 
  Hearing 
  held 
  by 
  Energy 
  panel. 
  Amended 
  and 
  passed 
  unanimously. 
  
o February 
  11, 
  2014: 
  Hearing 
  held 
  by 
  Economic 
  Development 
  panel. 
  Bill 
  was 
  deferred 
  and 
  awaits 
  
further 
  committee 
  action. 
  
 
  
H.B. 
  2166: 
  States 
  that 
  utilities 
  shall 
  be 
  responsible 
  for 
  and 
  not 
  pass 
  on 
  any 
  costs 
  for 
  interconnection 
  
studies 
  for 
  any 
  consumer 
  seeking 
  to 
  make 
  an 
  interconnection 
  on 
  the 
  Hawaii 
  electric 
  system 
  to 
  install 
  a 
  
solar 
  PV 
  on 
  a 
  single-­‐family 
  residential 
  dwelling 
  or 
  townhouse 
  that 
  the 
  consumer 
  owns. 
  
o January 
  21 
  & 
  24, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  committees 
  on 
  Consumer 
  Protection 
  and 
  
Commerce; 
  and 
  Finance. 
  
o

•

•

•

 
  
•

H.B. 
  2619: 
  Would 
  require 
  the 
  PUC 
  to 
  establish 
  energy 
  storage 
  portfolio 
  standards. 
  
o January 
  23, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  committees 
  on 
  Energy 
  and 
  Environmental 
  Protection, 
  
and 
  Consumer 
  Protection 
  and 
  Commerce. 
  
o February 
  11, 
  2014: 
  Hearing 
  held 
  by 
  Energy 
  panel. 
  Amended 
  and 
  passed 
  9-­‐0. 
  
o February 
  24 
  & 
  26, 
  2014: 
  Hearings 
  held 
  by 
  Consumer 
  Protection. 
  
o February 
  28, 
  2014: 
  Failed 
  committee 
  deadline 
  and 
  is 
  unlikely 
  to 
  receive 
  further 
  consideration. 
  

 
   
  
•

•

October 
  14, 
  2013: 
  The 
  House 
  Energy 
  and 
  Environmental 
  Protection 
  Committee 
  held 
  an 
  informational 
  
hearing 
  to 
  receive 
  an 
  update 
  from 
  Hawaiian 
  Electric 
  on 
  recent 
  changes 
  to 
  its 
  solar 
  PV 
  and 
  
interconnection 
  policies. 
  Agenda 
   
  
 
  
S.B. 
  2181: 
  Would 
  increase 
  RPS 
  to 
  70% 
  by 
  2040 
  and 
  100% 
  by 
  2050. 
  
o January 
  15, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  committees 
  on 
  Commerce 
  and 
  Consumer 
  Protection, 
  
and 
  Energy 
  and 
  Environment. 
  
o February 
  4, 
  2014: 
  Joint 
  hearing. 
  Passed 
  unanimously. 
  The 
  Division 
  of 
  Consumer 
  Advocacy 
  testified 
  in 
  
support 
  of 
  the 
  intent 
  of 
  the 
  measure 
  but 
  said, 
  however, 
  "that 
  it 
  is 
  more 
  reasonable 
  to 
  establish 
  
goals 
  with 
  a 
  time 
  frame 
  that 
  can 
  be 
  better 
  supported 
  with 
  relevant 
  analysis. 
  Creating 
  meaningful 
  

 Timeline of Key State Activities on Net Energy Metering

17

 
  

•

•

plans 
  to 
  meet 
  goals 
  that 
  are 
  almost 
  40 
  years 
  out 
  is 
  difficult, 
  if 
  not 
  impossible 
  and 
  may 
  result 
  in 
  
imprudent 
  resource 
  allocations 
  that 
  ratepayers 
  may 
  be 
  required 
  to 
  bear." 
  The 
  PUC 
  testified 
  that 
  
"Again, 
  while 
  the 
  Commission 
  continues 
  to 
  support 
  the 
  State's 
  clean 
  energy 
  mandates, 
  any 
  
determinations 
  regarding 
  an 
  increase 
  and/or 
  extension 
  of 
  RPS 
  going 
  forward 
  should 
  take 
  into 
  
account 
  the 
  challenges 
  associated 
  with 
  such 
  amendments 
  and 
  should 
  only 
  be 
  done 
  with 
  proper 
  
information 
  and 
  analysis." 
  The 
  Sierra 
  Club 
  testified 
  in 
  support 
  of 
  the 
  measure. 
  
 
  
S.B. 
  2656: 
  Would 
  require 
  the 
  PUC 
  to 
  adopt 
  rules 
  for 
  improved 
  accessibility 
  to 
  connect 
  to 
  the 
  Hawaii 
  
electric 
  system 
  for 
  any 
  person, 
  business 
  or 
  entity 
  on 
  the 
  system 
  and 
  to 
  initiate 
  a 
  proceeding 
  no 
  later 
  
than 
  July 
  1, 
  2014, 
  to 
  discuss 
  system 
  upgrades 
  for 
  anticipated 
  growth 
  of 
  customer 
  generation. 
  Similar 
  
House 
  bill 
  is 
  H.B. 
  1943. 
  
o January 
  17, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  committees 
  on 
  Energy 
  and 
  Environment; 
  
Commerce; 
  Ways 
  and 
  Means. 
   
  
o February 
  4, 
  2014: 
  Joint 
  hearing 
  by 
  Energy 
  and 
  Commerce 
  panels. 
  PUC 
  Chair 
  Morita 
  testified 
  in 
  
opposition, 
  stating 
  that 
  while 
  the 
  title 
  is 
  intended 
  to 
  address 
  grid 
  modernization, 
  the 
  commission 
  is 
  
concerned 
  that 
  the 
  legislation 
  as 
  written 
  is 
  solely 
  focused 
  on 
  interconnection 
  issues 
  related 
  to 
  DG 
  by 
  
creating 
  a 
  statutory 
  right 
  to 
  interconnect 
  DG 
  facilities, 
  which 
  may 
  be 
  to 
  the 
  detriment 
  of 
  the 
  rest 
  of 
  
the 
  electric 
  system 
  and 
  at 
  the 
  expense 
  of 
  ratepayers 
  who 
  may 
  not 
  have 
  the 
  ability 
  to 
  site 
  DG 
  
systems 
  at 
  their 
  homes 
  or 
  businesses. 
  The 
  Division 
  of 
  Consumer 
  Advocacy 
  testified 
  in 
  support 
  of 
  the 
  
intent 
  of 
  the 
  measure, 
  but 
  raised 
  concerns 
  about 
  the 
  proposed 
  mandate 
  that 
  each 
  electric 
  grid 
  be 
  
modified 
  to 
  ensure 
  that 
  any 
  person, 
  business 
  or 
  entity 
  can 
  operate 
  customer 
  generation 
  regardless 
  
of 
  where 
  that 
  person, 
  business 
  or 
  entity 
  is 
  located. 
  The 
  CA 
  also 
  said 
  issues 
  need 
  to 
  be 
  regarding 
  the 
  
costs 
  that 
  non-­‐participants 
  must 
  bear. 
  Testifying 
  in 
  support 
  were 
  the 
  League 
  of 
  Women 
  Voters 
  of 
  HI, 
  
HI 
  Solar 
  Energy 
  Association 
  (HSEA), 
  other 
  solar 
  industry 
  representatives, 
  and 
  many 
  members 
  of 
  the 
  
public. 
  
o February 
  11, 
  2014: 
  Hearing 
  held 
  by 
  Energy 
  and 
  Commerce 
  panels. 
  Energy 
  passed 
  4-­‐0; 
  Commerce 
  
passed 
  3-­‐0. 
  
o February 
  20, 
  2014: 
  Hearing 
  held 
  by 
  Ways 
  and 
  Means. 
  
o February 
  25, 
  2014: 
  Hearing 
  held 
  by 
  Ways 
  and 
  Means. 
  Amended 
  and 
  passed 
  11-­‐0. 
  
o March 
  3, 
  2014: 
  Passed 
  Senate 
  23-­‐0. 
  
 
  
S.B. 
  2932: 
  Would 
  establish 
  energy 
  storage 
  portfolio 
  standard 
  that 
  that 
  would, 
  among 
  other 
  things, 
  
facilitate 
  increased 
  use 
  of 
  renewable 
  energy. 
  
o January 
  22 
  & 
  24, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  committees 
  on 
  Energy 
  and 
  the 
  
Environment; 
  Commerce 
  and 
  Consumer 
  Protection; 
  and 
  Ways 
  and 
  Means. 
  
o February 
  4, 
  2014: 
  Hearing 
  held 
  by 
  the 
  Energy 
  and 
  Commerce 
  panels. 
  Deferred 
  for 
  future 
  
consideration. 
  PUC 
  Chair 
  Morita 
  testified: 
  "The 
  Commission 
  is 
  concerned 
  that 
  the 
  establishment 
  of 
  a 
  
portfolio 
  standard 
  would 
  focus 
  the 
  State's 
  attention 
  on 
  satisfying 
  a 
  pre-­‐established 
  quota 
  for 
  a 
  
specific 
  technology 
  and 
  may 
  hinder 
  utilization 
  of 
  alternative 
  technologies 
  and 
  programs 
  that 
  could 
  
achieve 
  the 
  stated 
  goals 
  of 
  this 
  bill 
  more 
  cost-­‐effectively." 
  Erik 
  Kvam, 
  President 
  of 
  Renewable 
  Energy 
  
Action 
  Coalition 
  of 
  HI, 
  testified 
  in 
  support 
  of 
  the 
  measure. 
  He 
  stated 
  that 
  without 
  large 
  amounts 
  of 
  
energy 
  storage, 
  the 
  large 
  amounts 
  of 
  intermittent 
  solar 
  and 
  wind 
  generation 
  that 
  have 
  been 
  and 
  will 
  
be 
  added 
  to 
  the 
  Hawaiian 
  island 
  grids 
  will 
  be 
  undispatchable 
  and 
  unusable 
  when 
  imported 
  fuels 
  
stop 
  flowing 
  to 
  Hawaii. 
  Warren 
  Bollmeier, 
  testifying 
  on 
  behalf 
  of 
  the 
  Hi 
  Renewable 
  Energy 
  Alliance, 
  

 Timeline of Key State Activities on Net Energy Metering

18

 
  
said, 
  "We 
  believe 
  the 
  goal 
  of 
  600 
  MWHs 
  of 
  storage 
  is 
  too 
  pedestrian. 
  In 
  addition 
  to 
  distributed 
  
energy 
  storage, 
  we 
  will 
  need 
  a 
  significant 
  amount 
  of 
  utility-­‐scale 
  storage, 
  such 
  as 
  pumped 
  hydro, 
  if 
  
we 
  are 
  to 
  reach 
  our 
  clean 
  energy 
  goals. 
  We 
  support 
  the 
  role 
  of 
  the 
  Public 
  Utility 
  Commission 
  to 
  
open 
  a 
  docket 
  on 
  this 
  portfolio, 
  at 
  which 
  time, 
  we 
  can 
  sharpen 
  our 
  pencils." 
  The 
  Sierra 
  Club 
  of 
  
Hawaii 
  testified 
  in 
  support 
  of 
  the 
  measure. 
  
 
  
•

S.B. 
  2934: 
  Would 
  establish 
  community-­‐based 
  renewable 
  energy 
  program. 
  Similar 
  House 
  bill 
  is 
  H.B. 
  2141. 
  
o January 
  22 
  & 
  24, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  committees 
  on 
  Energy 
  and 
  the 
  
Environment; 
  Commerce 
  and 
  Consumer 
  Protection; 
  and 
  Ways 
  and 
  Means. 
  
o February 
  4, 
  2014: 
  Hearing 
  before 
  Energy 
  Committee. 
  Amended 
  and 
  passed 
  3-­‐0. 
  PUC 
  Chair 
  Morita 
  
testified 
  "the 
  Commission 
  supports 
  the 
  intent 
  of 
  creating 
  a 
  community-­‐based 
  renewable 
  energy 
  
tariff 
  structure 
  that 
  will 
  increase 
  access 
  to 
  renewable 
  generation, 
  but 
  it 
  believes 
  the 
  measure 
  is 
  
overly 
  prescriptive 
  and 
  may 
  have 
  unintended 
  program 
  design 
  consequences 
  that 
  would 
  require 
  
future 
  and 
  untimely 
  statutory 
  amendments 
  resulting 
  in 
  implementation 
  barriers. 
  The 
  Commission 
  
believes 
  that 
  this 
  measure 
  is 
  not 
  necessary." 
  The 
  Sierra 
  Club 
  of 
  Hawaii 
  testified 
  in 
  support 
  of 
  the 
  
measure. 
  
o February 
  5, 
  2014: 
  Hearing 
  held 
  by 
  Commerce 
  Committee. 
  Amended 
  and 
  passed 
  4-­‐0. 
   
  
o February 
  19, 
  2014: 
  Hearing 
  held 
  by 
  Ways 
  and 
  Means. 
  Amended 
  and 
  passed 
  11-­‐0. 
  
o March 
  3, 
  2014: 
  Passed 
  Senate 
  23-­‐0. 
  
o March 
  7, 
  2014: 
  Referred 
  to 
  three 
  House 
  committees: 
  Energy 
  and 
  Environment, 
  Commerce 
  and 
  
Consumer 
  Protection, 
  and 
  Finance. 
  

•

S.B. 
  3020: 
  Would 
  increase 
  the 
  NEM 
  customer 
  capacity 
  limit 
  to 
  1 
  MW; 
  repeal 
  total 
  capacity 
  limit 
  but 
  
impose 
  a 
  total 
  capacity 
  limit 
  determined 
  by 
  the 
  PUC; 
  prohibit 
  an 
  electric 
  utility 
  from 
  unreasonably 
  
denying, 
  burdening 
  or 
  delaying 
  NEM 
  service 
  upon 
  a 
  request 
  by 
  a 
  retail 
  customer 
  of 
  the 
  utility. 
  
o January 
  23, 
  2014: 
  Introduced. 
  
 
  
S.R. 
  27: 
  Requests 
  that 
  the 
  Hawaii 
  State 
  Energy 
  Office 
  study 
  the 
  feasibility 
  of 
  creating 
  a 
  publicly 
  funded 
  
integrated 
  resource 
  plan 
  to 
  meet 
  the 
  electric 
  energy 
  needs 
  of 
  the 
  state. 
  Requires 
  cooperation 
  from 
  
investor-­‐owned 
  utilities 
  and 
  report 
  to 
  legislature, 
  including 
  any 
  proposed 
  legislation. 
   
  
o March 
  3, 
  2014: 
  Introduced. 
  

 
  

•

IDAHO 
  
Rates 
  and 
  Regulation 
  
•

Idaho 
  Power 
  net 
  metering 
  program, 
  Docket 
  No. 
  IPC-­‐E-­‐12-­‐27 
  
o July 
  3, 
  2013: 
  The 
  ID 
  Public 
  Utilities 
  Commission 
  (PUC) 
  rejected 
  most 
  of 
  Idaho 
  Power’s 
  application 
  to 
  
make 
  changes 
  in 
  its 
  net 
  metering 
  program, 
  including 
  increasing 
  the 
  monthly 
  service 
  charge 
  to 
  better 
  
reflect 
  cost 
  of 
  service 
  to 
  net 
  metered 
  customers. 
  The 
  PUC 
  said, 
  however, 
  that 
  IP 
  raised 
  valid 
  issues 
  
that 
  are 
  better 
  addressed 
  in 
  a 
  general 
  rate 
  case. 
  IP 
  on 
  its 
  website 
  said 
  it 
  will 
  not 
  file 
  a 
  general 
  rate 
  
case 
  in 
  2013: 
  http://www.idahopower.com/AboutUs/RatesRegulatory/Rates/PCA_FAQs.cfm#6 
  

 Timeline of Key State Activities on Net Energy Metering

19

 
  

ILLINOIS 
  
Rates 
  and 
  Regulation 
  
•

•

Generic 
  proceeding, 
  revisions 
  to 
  net 
  metering 
  rule; 
  documents 
  posted 
  at: 
  
http://www.icc.illinois.gov/electricity/NetMetering.aspx 
   
  
o June 
  28, 
  2013: 
  The 
  IL 
  Commerce 
  Commission 
  (CC) 
  staff 
  issued 
  a 
  notice 
  of 
  request 
  for 
  comments 
  on 
  
draft 
  net 
  metering 
  rule. 
   
  
o July 
  19, 
  2013: 
  Comments 
  due. 
  Comments 
  are 
  posted 
  at 
  above 
  link. 
  
 
  
Commonwealth 
  Edison 
  general 
  rate 
  case, 
  including 
  straight 
  fixed 
  variable 
  rate 
  design 
  issue, 
  Docket 
  
No. 
  13-­‐0387 
  
o As 
  part 
  of 
  general 
  rate 
  case, 
  consumer 
  advocate 
  and 
  state 
  attorney 
  general 
  have 
  requested 
  
elimination 
  of 
  ComEd’s 
  commission-­‐approved 
  modified 
  straight 
  fixed 
  variable 
  rate 
  (SFV) 
  design 
  for 
  
residential 
  customers. 
  The 
  company 
  is 
  arguing, 
  among 
  other 
  things, 
  that 
  “to 
  the 
  extent 
  that 
  future 
  
state 
  policy 
  is 
  designed 
  to 
  encourage 
  the 
  adoption 
  of 
  clean 
  sources 
  of 
  behind-­‐the-­‐meter 
  distributed 
  
generation 
  like 
  rooftop 
  solar, 
  SFV 
  pricing 
  addresses 
  concerns 
  about 
  the 
  utility’s 
  ability 
  to 
  recover 
  the 
  
costs 
  of 
  its 
  investments 
  in 
  the 
  distribution 
  grid 
  by 
  making 
  it 
  financially 
  indifferent 
  to 
  such 
  
proposals.” 
  (See 
  Rebuttal 
  Testimony 
  of 
  Philip 
  Q. 
  Hanser, 
  filed 
  August 
  19, 
  2013, 
  p. 
  9.) 
  
o September 
  24-­‐25: 
  Evidentiary 
  hearing. 
  
o October 
  23, 
  2013: 
  Statements 
  of 
  position 
  due. 
  Staff 
  filed 
  a 
  position 
  statement 
  in 
  support 
  of 
  
retention 
  of 
  SFV 
  rate 
  design 
  percentages 
  previously 
  approved 
  by 
  the 
  commission 
  in 
  Docket 
  10-­‐0467. 
  
o November 
  8, 
  2013: 
  Proposed 
  order 
  issued 
  by 
  ALJ. 
  The 
  ALJ 
  would 
  adopt 
  the 
  rate 
  design 
  proposed 
  by 
  
the 
  AG, 
  who 
  argued 
  that 
  the 
  move 
  toward 
  SFV 
  should 
  be 
  reversed 
  in 
  favor 
  of 
  rates 
  that 
  reflect 
  cost 
  
of 
  service. 
  The 
  AG 
  argued 
  that 
  the 
  SFV 
  rate 
  design 
  previously 
  approved 
  by 
  the 
  commission 
  resulted 
  
in 
  an 
  undue 
  and 
  disproportionate 
  burden 
  on 
  low 
  usage 
  customers. 
  The 
  AG 
  rate 
  design 
  reduces 
  
customer 
  charges 
  for 
  two 
  residential 
  subclasses 
  and 
  upwardly 
  adjusts 
  the 
  per-­‐kWh 
  usage 
  charge 
  to 
  
better 
  reflect 
  what 
  the 
  AG 
  asserts 
  are 
  more 
  accurate 
  calculations 
  of 
  fixed 
  and 
  variable 
  costs. 
  
o November 
  18, 
  2013: 
  Briefs 
  on 
  exceptions 
  due. 
  
o November 
  25, 
  2013: 
  Reply 
  briefs 
  on 
  exceptions 
  due. 
  
o December 
  18, 
  2013: 
  The 
  commission 
  issued 
  an 
  order 
  that, 
  among 
  other 
  things, 
  adopted 
  the 
  AG 
  rate 
  
design 
  under 
  which 
  fixed 
  charges 
  decrease 
  and 
  variable 
  charges 
  increase 
  for 
  low-­‐use 
  residential 
  
customers 
  (single 
  family 
  homes). 
   
  

INDIANA 
  
Legislation 
  
•

September 
  18, 
  2013: 
  The 
  Regulatory 
  Flexibility 
  Committee 
  held 
  a 
  meeting 
  that 
  included 
  presentations 
  
on 
  feed-­‐in 
  tariffs 
  (FITs) 
  for 
  electricity. 
  Presentations 
  were 
  made 
  by 
  NIPSCO 
  jointly 
  with 
  IPL, 
  and 
  the 
  
Indiana 
  Distributed 
  Energy 
  Alliance 
  (IDEA). 
  Among 
  other 
  things, 
  IDEA 
  advocated 
  expansion 
  of 
  existing 
  
net 
  metering 
  rules 
  to 
  give 
  FIT 
  customers 
  the 
  option 
  to 
  net 
  meter. 
  

Rates 
  and 
  Regulation 
  
•

Extension/modification 
  of 
  NIPSCO 
  voluntary 
  FIT 
  for 
  renewable 
  energy, 
  Docket 
  No. 
  44393 
  

 Timeline of Key State Activities on Net Energy Metering

20

 
  
September 
  11, 
  2013: 
  Northern 
  Indiana 
  Public 
  Service 
  petitioned 
  the 
  IN 
  Utility 
  Regulatory 
  
Commission 
  (URC) 
  to 
  extend 
  and 
  make 
  certain 
  changes 
  to 
  its 
  existing 
  pilot 
  FIT. 
   
  IDEA 
  is 
  an 
  
intervenor. 
   
  
o October 
  15, 
  2013: 
  Public 
  prehearing 
  conference 
  and 
  preliminary 
  hearing. 
  
o October 
  23, 
  2013: 
  The 
  URC 
  issued 
  a 
  procedural/interim 
  order 
  authorizing 
  NIPSCO 
  to 
  continue 
  
offering 
  the 
  existing 
  FIT 
  beyond 
  its 
  scheduled 
  expiration 
  date 
  pending 
  a 
  final 
  order 
  in 
  this 
  case. 
   
  
o December 
  31, 
  2013: 
  Existing 
  NIPSCO 
  pilot 
  FIT 
  set 
  to 
  expire. 
  
o January 
  10, 
  2014: 
  NIPSCO 
  case 
  in 
  chief 
  due 
  (per 
  October 
  23 
  procedural 
  order). 
  Parties 
  filed 
  agreed 
  
motion 
  for 
  9-­‐week 
  extension 
  of 
  this 
  procedural 
  schedule, 
  saying 
  they 
  have 
  been 
  engaged 
  in 
  
settlement 
  discussions 
  – 
  the 
  most 
  recent 
  of 
  which 
  was 
  January 
  6 
  – 
  and 
  need 
  more 
  time 
  to 
  
collaborate. 
  
o March 
  7, 
  2014: 
  Intervenor 
  testimony 
  due 
  (per 
  October 
  23 
  procedural 
  order). 
  
o March 
  28, 
  2014: 
  NIPSCO 
  rebuttal 
  due 
  (per 
  October 
  23 
  procedural 
  order). 
  
o May 
  8, 
  2014: 
  Evidentiary 
  hearing 
  (per 
  October 
  23 
  procedural 
  order). 
  
 
  
At 
  present 
  there 
  are 
  no 
  initiatives 
  to 
  change 
  the 
  existing 
  NEM 
  rule, 
  which 
  first 
  was 
  adopted 
  in 
  2004 
  and 
  
re-­‐adopted 
  in 
  2010. 
  In 
  2011, 
  the 
  URC 
  updated 
  the 
  rules, 
  including 
  provisions 
  that: 
  1) 
  expanded 
  eligibility 
  
to 
  all 
  customer 
  classes 
  (from 
  residential 
  and 
  K-­‐12 
  schools), 
  2) 
  expanded 
  eligible 
  renewable 
  energy 
  
resources, 
  3) 
  increased 
  eligible 
  customer 
  generation 
  from 
  10 
  kW 
  to 
  1 
  MW 
  (or 
  more 
  at 
  utility’s 
  
discretion), 
  and 
  4) 
  increased 
  the 
  aggregate 
  limit 
  on 
  net 
  metering 
  capacity 
  from 
  0.1% 
  to 
  1% 
  of 
  utility’s 
  
most 
  recent 
  summer 
  peak 
  load 
  – 
  with 
  at 
  least 
  40% 
  reserved 
  for 
  residential. 
  Aggregate 
  limit 
  may 
  be 
  
increased 
  at 
  utility’s 
  discretion. 
   
  
o

•

Other 
  Policy 
  Initiatives 
  
•

Development 
  of 
  new 
  state 
  energy 
  plan 
  
o December 
  2, 
  2013: 
  The 
  IN 
  Office 
  of 
  Energy 
  Development 
  announced 
  it 
  has 
  begun 
  developing 
  a 
  new 
  
state 
  energy 
  plan 
  per 
  the 
  Governor’s 
  Roadmap 
  for 
  Indiana 
  initiative. 
  The 
  plan 
  will 
  be 
  based 
  on 
  three 
  
main 
  principles: 
  utilize 
  all 
  energy 
  resources 
  in 
  the 
  state, 
  improve 
  availability 
  of 
  options 
  to 
  customers, 
  
and 
  commercialize 
  new 
  energy 
  technologies. 
  
o June 
  2014: 
  OED 
  to 
  complete 
  plan 
  and 
  submit 
  energy 
  recommendations 
  to 
  Governor. 
  

IOWA 
  
Rates 
  and 
  Regulation 
  
•

•

 
  

Notice 
  of 
  inquiry 
  on 
  DG, 
  Docket 
  No. 
  NOI-­‐2014-­‐0001 
  
o January 
  7, 
  2014: 
  The 
  IA 
  Utilities 
  Board 
  (UB) 
  issued 
  the 
  NOI 
  to 
  gather 
  information 
  related 
  to 
  DG 
  
policy 
  and 
  technical 
  issues. 
  The 
  UB 
  said 
  the 
  information 
  will 
  assist 
  it 
  in 
  addressing 
  the 
  potential 
  
widespread 
  use 
  of 
  DG, 
  related 
  consumer 
  protections, 
  and 
  interconnection 
  and 
  safety 
  
considerations. 
  
o February 
  26, 
  2014: 
  Comments 
  due. 
  
 
  
March 
  29, 
  2013: 
  A 
  district 
  court 
  issued 
  a 
  ruling 
  allowing 
  third-­‐party 
  sale 
  of 
  electricity 
  by 
  SZ 
  Enterprises 
  
to 
  Dubuque 
  City 
  Council. 
  The 
  ruling 
  was 
  viewed 
  by 
  analysts 
  as 
  clearing 
  the 
  way 
  for 
  similar 
  arrangements 
  

 Timeline of Key State Activities on Net Energy Metering

21

 
  
in 
  Iowa 
  and 
  influencing 
  debates 
  in 
  other 
  states 
  such 
  as 
  Georgia 
  and 
  South 
  Carolina 
  on 
  third-­‐party 
  solar 
  
financing. 
   
  (See 
  related 
  items 
  for 
  those 
  states.) 
  The 
  court 
  reversed 
  an 
  April 
  12, 
  2012, 
  ruling 
  by 
  the 
  IA 
  UB, 
  
which 
  held 
  that 
  SZ 
  (dba 
  Eagle 
  Point 
  Solar) 
  would 
  be 
  a 
  public 
  utility 
  under 
  state 
  law 
  and 
  therefore 
  
prohibited 
  from 
  offering 
  service 
  to 
  the 
  city. 
  (IA 
  UB 
  Docket 
  No 
  DRU-­‐2012-­‐0001). 
  The 
  UB 
  proceeding 
  
involved 
  many 
  parties, 
  including 
  SEIA 
  as 
  a 
  member 
  of 
  a 
  large 
  Solar 
  Coalition. 
  (Iowa 
  District 
  Court 
  for 
  Polk 
  
County, 
  SZ 
  Enterprises 
  v. 
  Iowa 
  Utilities 
  Board, 
  March 
  29, 
  2013, 
  Case 
  No. 
  CVCV009166) 
  
o April 
  10, 
  2013: 
  Appealed 
  to 
  Iowa 
  Supreme 
  Court. 
  (S.Ct. 
  No. 
  13-­‐0642) 
  
o January 
  22, 
  2014: 
  IA 
  Supreme 
  Court 
  heard 
  oral 
  arguments. 
  The 
  court 
  usually 
  issues 
  a 
  decision 
  6 
  to 
  8 
  
months 
  after 
  argument. 
  
Legislation 
  
•

•

•

H.R. 
  2336: 
  Would 
  establish 
  NEM 
  program 
  applicable 
  to 
  rate-­‐regulated 
  electric 
  utilities. 
  The 
  IA 
  Utilities 
  
Board 
  (UB) 
  would 
  utilize 
  existing 
  standard 
  offer 
  contract 
  forms 
  to 
  facilitate 
  interconnection 
  between 
  a 
  
utility 
  and 
  a 
  DG 
  facility, 
  and 
  that 
  the 
  standard 
  offer 
  contracts 
  would 
  be 
  in 
  effect 
  for 
  a 
  20-­‐year 
  period. 
  
Utilities 
  must 
  purchase 
  a 
  minimum 
  of 
  5% 
  of 
  its 
  required 
  electrical 
  output 
  from 
  DG 
  facilities 
  pursuant 
  to 
  
NEM 
  agreements 
  by 
  July 
  1, 
  2019. 
  Prohibits 
  the 
  UB 
  from 
  placing 
  limits 
  on 
  the 
  aggregate 
  capacity 
  of 
  net-­‐
metered 
  systems 
  as 
  a 
  percentage 
  of 
  the 
  utility’s 
  peak 
  demand. 
  Permits 
  the 
  board 
  to 
  allow 
  indefinite 
  net 
  
excess 
  generation 
  carryover. 
  Prohibits 
  the 
  board 
  from 
  imposing 
  special 
  fees 
  applicable 
  specifically 
  to 
  net 
  
metering. 
  Sets 
  reporting 
  requirements. 
  
o February 
  19, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Commerce 
  Committee. 
   
  
 
   
  
S.F. 
  2107: 
  Would 
  change 
  existing 
  105 
  MW 
  RPS 
  to 
  apply 
  only 
  to 
  solar, 
  with 
  the 
  share 
  to 
  be 
  
purchased/owned 
  by 
  each 
  major 
  investor-­‐owned 
  utility 
  by 
  2020. 
  A 
  minimum 
  of 
  10% 
  of 
  that 
  power 
  must 
  
come 
  from 
  solar 
  facilities 
  of 
  20 
  kW 
  or 
  less. 
  Utilities 
  would 
  be 
  required 
  to 
  establish 
  and 
  maintain 
  one 
  or 
  
more 
  community 
  solar 
  gardens 
  that 
  generate 
  1 
  MW 
  or 
  less 
  for 
  subscribers. 
  NEM 
  requirements 
  would 
  be 
  
set 
  for 
  solar 
  installations. 
  
o February 
  5, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  Commerce 
  Committee. 
  
o February 
  17, 
  2014: 
  Hearing 
  held 
  with 
  large 
  turnout 
  on 
  both 
  sides 
  of 
  the 
  measure. 
  Utilities 
  voiced 
  a 
  
number 
  of 
  concerns 
  including 
  the 
  timing 
  of 
  the 
  bill, 
  which 
  is 
  being 
  considered 
  as 
  the 
  IA 
  UB 
  conducts 
  
a 
  notice 
  of 
  inquiry 
  on 
  DG 
  and 
  as 
  a 
  state 
  Supreme 
  Court 
  decision 
  is 
  awaited 
  on 
  solar 
  leasing 
  (items 
  
below), 
  and 
  confusing 
  language 
  around 
  the 
  NEM 
  requirements. 
  
o February 
  20, 
  2014: 
  Hearing 
  held. 
  Measure 
  deferred. 
  
 
  
H.F. 
  2166: 
  Would 
  require 
  that 
  25% 
  of 
  the 
  existing 
  105 
  MW 
  RPS 
  come 
  from 
  solar. 
  
o February 
  6, 
  2014: 
  Introduced. 
  

KANSAS 
  
Legislation 
  
 
  
• H.B. 
  2458: 
  Similar 
  to 
  S.B. 
  280 
  (below). 
  Would 
  reduce 
  compensation 
  to 
  net 
  metered 
  customers 
  for 
  excess 
  
generation 
  from 
  current 
  retail 
  rate 
  and 
  allow 
  commission 
  to 
  authorize 
  unique 
  tariffs 
  such 
  as 
  standby 
  
charges 
  and 
  fixed 
  charges. 
  

 Timeline of Key State Activities on Net Energy Metering

22

 
  
January 
  17 
  & 
  21, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  Committee 
  on 
  Energy 
  and 
  Environment, 
  
respectively. 
  
o January 
  30, 
  2014: 
  Hearing 
  held. 
  KCP&L, 
  Westar 
  and 
  Empire 
  Electric 
  testified 
  in 
  support 
  of 
  the 
  
measure. 
  The 
  Kansas 
  Corporation 
  Commission 
  offered 
  testimony 
  but 
  did 
  not 
  take 
  a 
  position. 
  
Representatives 
  from 
  Kansans 
  for 
  Clean 
  Energy, 
  The 
  Alliance 
  for 
  Solar 
  Choice, 
  Mid 
  America 
  Bank, 
  
Brightergy 
  and 
  the 
  Vote 
  Solar 
  Initiative 
  all 
  testified 
  in 
  opposition, 
  according 
  to 
  Stateside 
  Associates. 
  
o January 
  31, 
  2014: 
  Possible 
  continuation 
  of 
  hearing 
  and 
  vote 
  was 
  canceled. 
  
o February 
  11, 
  2014: 
  Committee 
  voted 
  9-­‐7 
  to 
  table 
  the 
  bill. 
   
  
o February 
  20, 
  2014: 
  Committee 
  took 
  bill 
  off 
  table, 
  held 
  hearing, 
  amended 
  and 
  passed. 
  Amended 
  
version 
  removes 
  proposed 
  authority 
  for 
  commission 
  to 
  approve 
  unique 
  tariffs. 
  Measure 
  is 
  likely 
  to 
  
be 
  referred 
  to 
  another 
  committee 
  before 
  House 
  floor 
  consideration. 
  Current 
  version 
   
  
o February 
  28, 
  2014: 
  Stricken 
  from 
  House 
  calendar. 
  The 
  measure 
  will 
  no 
  longer 
  be 
  considered 
  in 
  this 
  
session. 
  
 
  
H.B. 
  2460: 
  Would 
  exempt 
  any 
  renewable 
  energy 
  supplier 
  from 
  the 
  definition 
  of 
  a 
  public 
  utility, 
  and 
  from 
  
the 
  definition 
  of 
  a 
  retail 
  electric 
  supplier. 
  
o January 
  16, 
  2014: 
  Introduced. 
  This 
  measure 
  is 
  a 
  committee 
  bill, 
  sponsored 
  by 
  the 
  House 
  Committee 
  
on 
  Energy 
  and 
  Environment. 
  
o January 
  21, 
  2014: 
  Referred 
  to 
  House 
  Committee 
  on 
  Utilities 
  and 
  Telecommunications. 
  
o February 
  12, 
  2014: 
  Hearing 
  held; 
  vote 
  not 
  taken. 
  
 
  
H.B. 
  2465: 
  Would 
  allow 
  tax 
  exempt 
  entities 
  (TXE) 
  to 
  self-­‐generate 
  from 
  renewables 
  facilities; 
  facilities 
  
could 
  not 
  exceed 
  200% 
  of 
  TXE 
  baseline 
  usage 
  for 
  previous 
  3 
  years. 
  Utilities 
  could 
  apply 
  customer 
  charge 
  
as 
  provisional 
  charge 
  for 
  being 
  available 
  to 
  supply 
  TXE 
  load. 
  Utility 
  compensation 
  to 
  TXE 
  for 
  any 
  
generation 
  would 
  be 
  150% 
  of 
  utility 
  monthly 
  system 
  average 
  cost 
  of 
  energy/kWh; 
  compensation 
  could 
  
be 
  provided 
  via 
  credits 
  or, 
  under 
  specified 
  circumstances, 
  payments. 
  
o January 
  21, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Energy 
  and 
  Environment 
  Committee. 
  
o January 
  22, 
  2014: 
  Withdrawn 
  from 
  Energy; 
  referred 
  to 
  Utilities 
  and 
  Telecommunications 
  
Committee. 
  
o February 
  12 
  & 
  19, 
  2014: 
  Hearings 
  held. 
  Kansas 
  Interfaith 
  Power 
  and 
  Light 
  and 
  Cromwell 
  Solar 
  
testified 
  in 
  support. 
  Kansas 
  Electric 
  Cooperatives 
  and 
  Kansas 
  City 
  Power 
  and 
  Light 
  testified 
  in 
  
opposition. 
  A 
  vote 
  was 
  not 
  taken. 
  
o

•

•

 
  
•

S.B. 
  280: 
  States 
  that 
  on 
  and 
  after 
  January 
  1, 
  2030, 
  compensation 
  for 
  all 
  net 
  excess 
  energy 
  (NEG) 
  shall 
  be 
  
credited 
  to 
  the 
  customer 
  at 
  a 
  rate 
  of 
  150% 
  of 
  the 
  utility's 
  monthly 
  system 
  average 
  cost 
  of 
  energy/kWh. 
  
Provides 
  that 
  NEG 
  shall 
  be 
  credited 
  to 
  the 
  customer 
  at 
  a 
  rate 
  of 
  150% 
  of 
  the 
  utility's 
  monthly 
  system 
  
average 
  cost 
  of 
  energy/kWh 
  if 
  a 
  customer-­‐generator 
  begins 
  operating 
  its 
  renewable 
  energy 
  resource 
  
under 
  an 
  interconnect 
  agreement 
  with 
  the 
  utility 
  on 
  and 
  after 
  July 
  1, 
  2014. 
  Allows 
  the 
  KS 
  Corporation 
  
Commission 
  to 
  authorize 
  unique 
  tariffs 
  and 
  fixed 
  charges. 
  (Under 
  existing 
  net 
  metering 
  framework, 
  NEG 
  
is 
  carried 
  forward 
  to 
  the 
  next 
  month 
  at 
  the 
  full 
  retail 
  rate.) 
  
o January 
  16 
  and 
  17, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  Utilities 
  Committee, 
  respectively. 
  This 
  
measure 
  is 
  sponsored 
  by 
  the 
  Senate 
  Utilities 
  Committee. 
  Republicans 
  control 
  both 
  chambers 
  as 
  well 
  
as 
  the 
  Governor's 
  Office. 
  This 
  measure 
  is 
  similar 
  to 
  H.B. 
  2458 
  (above), 
  filed 
  by 
  the 
  House 
  Committee 
  
on 
  Energy 
  and 
  Environment. 
  

 Timeline of Key State Activities on Net Energy Metering

23

 
  
o
o
o

January 
  30, 
  2014: 
  Hearing 
  held. 
   
  
Week 
  of 
  February 
  17, 
  2014: 
  Committee 
  vote 
  possible. 
  
May/June 
  2014: 
  Session 
  adjourns. 
  

 
  
•

H.B. 
  2241: 
  Would 
  ease 
  requirements 
  of 
  state 
  RES. 
  
o March 
  19, 
  2013: 
  Tabled 
  by 
  House 
  Energy 
  and 
  Environment 
  Committee. 
   
  
o 2014: 
  Another 
  legislative 
  effort 
  is 
  expected 
  to 
  delay 
  the 
  remaining 
  steps 
  in 
  the 
  RES. 
  Separate 
  
legislation 
  also 
  is 
  expected 
  to 
  expand 
  the 
  RES. 
  

•

S.B. 
  154: 
  Would 
  amend 
  the 
  expiration 
  date 
  of 
  net 
  excess 
  generation 
  credit 
  from 
  the 
  end 
  of 
  the 
  calendar 
  
year 
  to 
  no 
  more 
  than 
  12 
  months 
  after 
  one 
  of 
  three 
  dates 
  of 
  the 
  customer’s 
  choosing. 
  
o February 
  7, 
  2013: 
  Introduced 
  by 
  the 
  Committee 
  on 
  Utilities. 
  Will 
  carry 
  over 
  to 
  next 
  session. 
  
o January 
  21, 
  2014: 
  Hearing 
  held. 
  A 
  vote 
  was 
  not 
  taken. 
  
 
  
November 
  14, 
  2013: 
  Rep. 
  Tom 
  Sloan 
  convened 
  an 
  informal 
  private 
  discussion 
  with 
  interested 
  parties 
  
from 
  the 
  regulatory 
  and 
  customer 
  communities 
  to 
  address 
  the 
  Future 
  of 
  Electric 
  Rates, 
  including 
  topics 
  
related 
  to 
  DG 
  and 
  value 
  of 
  solar. 
   
  

 
  

•

KENTUCKY 
  
Legislation 
  
•

•

H.B. 
  195: 
  Would 
  establish 
  mandatory 
  RPS 
  with 
  target 
  of 
  12.5% 
  of 
  average 
  2022-­‐23 
  retail 
  sales 
  in 
  2024, 
  
with 
  1% 
  of 
  that 
  from 
  solar. 
   
  
o January 
  13-­‐14, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  Tourism, 
  Development 
  and 
  Energy 
  
Committee. 
  
o March 
  6, 
  2014: 
  Hearing 
  scheduled. 
  
 
  
H.B. 
  535: 
  Would 
  raise 
  the 
  NEM 
  system 
  capacity 
  limit 
  from 
  30 
  kW 
  to 
  500 
  kW. 
  
o March 
  4, 
  2014: 
  Introduced. 
  

LOUISIANA 
  
Rates 
  and 
  Regulation 
  
•

Re-­‐examination 
  of 
  net 
  metering 
  rules, 
  Docket 
  No. 
  R-­‐31417 
  
o July 
  26, 
  2013: 
   
  The 
  LA 
  Public 
  Service 
  Commission 
  (PSC) 
  rejected 
  two 
  motions 
  to: 
  1) 
  replace 
  retail 
  rate 
  
compensation 
  to 
  net 
  metered 
  customers 
  with 
  an 
  avoided 
  cost 
  credit, 
  and 
  2) 
  require 
  utilities 
  to 
  
conduct 
  more 
  thorough 
  analysis 
  of 
  the 
  cost 
  of 
  net 
  metering. 
  LA 
  PSC 
  capped 
  residential 
  net 
  metering 
  
at 
  0.5% 
  of 
  system 
  peak. 
  

•

August 
  21, 
  2013: 
  Open 
  session 
  of 
  LA 
  PSC. 
  Chairman 
  Skrmetta 
  issued 
  directive 
  to 
  utilities 
  to 
  accept 
  NEM 
  
applications 
  from 
  otherwise 
  eligible 
  customers 
  that 
  have 
  executed 
  contracts 
  as 
  of 
  this 
  date 
  for 
  
purchase, 
  lease 
  or 
  installation 
  of 
  solar 
  panels. 
  The 
  directive 
  also 
  requires 
  utilities 
  to 
  notify 
  customers 
  

 
  

 Timeline of Key State Activities on Net Energy Metering

24

 
  
and 
  solar 
  providers 
  when 
  they 
  are 
  nearing 
  their 
  NEM 
  caps. 
  The 
  directive 
  came 
  as 
  some 
  co-­‐ops 
  neared 
  or 
  
reached 
  0.5% 
  NEM 
  caps. 
   
  

MAINE 
  
Legislation 
  
•

•

L.D. 
  1085: 
  Would 
  establish 
  a 
  feed-­‐in 
  tariff 
  (FIT) 
  for 
  renewables. 
  
o March 
  18, 
  2013: 
  Introduced 
  and 
  referred 
  to 
  Energy, 
  Utilities 
  and 
  Technology 
  Committee. 
  
o April 
  24, 
  2013: 
  Hearing 
  held. 
  Maine 
  Central 
  Power 
  testified 
  in 
  opposition. 
  The 
  Governor’s 
  Energy 
  
Office 
  expressed 
  concerns. 
  The 
  ME 
  Public 
  Utilities 
  Commission 
  (PUC) 
  provided 
  information. 
  The 
  
Sierra 
  Club 
  testified 
  in 
  support. 
  
o May 
  7 
  and 
  May 
  13, 
  2013: 
  Work 
  sessions 
  held. 
   
  
o July 
  9, 
  2013: 
  Carried 
  over. 
  
o December 
  11, 
  2013: 
  Work 
  session 
  held. 
  No 
  action 
  was 
  taken. 
  The 
  committee 
  may 
  be 
  working 
  on 
  a 
  
more 
  encompassing 
  piece 
  of 
  legislation 
  relating 
  to 
  renewable 
  energy. 
  
o January 
  15 
  & 
  22, 
  2014: 
  Work 
  sessions 
  held. 
  Votes 
  were 
  not 
  taken. 
   
  
o January 
  28 
  & 
  February 
  4, 
  2014: 
  Work 
  sessions 
  held. 
   
  
o February 
  6, 
  2014: 
  Work 
  session 
  held. 
  The 
  committee 
  could 
  not 
  come 
  to 
  a 
  unanimous 
  decision, 
  
resulting 
  in 
  a 
  divided 
  report. 
  The 
  measure 
  was 
  not 
  reported 
  out 
  of 
  committee. 
  Once 
  reported, 
  the 
  
measure 
  will 
  go 
  to 
  the 
  House 
  floor 
  for 
  consideration. 
  
o February 
  27, 
  2014: 
  Majority 
  report 
  accepted 
  by 
  Senate. 
  House 
  must 
  concur. 
  
 
  
L.D. 
  1252: 
  Would 
  reinstate 
  solar 
  and 
  wind 
  energy 
  rebate 
  program 
  until 
  June 
  30, 
  2018; 
  increase 
  the 
  limit 
  
on 
  total 
  renewable 
  capacity 
  allowed 
  under 
  the 
  community 
  renewable 
  energy 
  pilot 
  program 
  from 
  50 
  
MW 
  to 
  60 
  MW 
  and 
  require 
  the 
  ME 
  PUC 
  to 
  reserve 
  10 
  MW 
  in 
  that 
  program 
  for 
  solar; 
  increase 
  the 
  limit 
  
on 
  the 
  PUC-­‐authorized 
  contract 
  price 
  for 
  eligible 
  solar 
  generation 
  and 
  index 
  the 
  price 
  limit 
  to 
  the 
  CPI; 
  
extend 
  the 
  repeal 
  date 
  for 
  the 
  Community-­‐based 
  Renewable 
  Energy 
  Act 
  from 
  December 
  31, 
  2015, 
  to 
  
December 
  31, 
  2017; 
  and 
  require 
  the 
  PUC 
  to 
  submit 
  to 
  the 
  Legislature 
  by 
  January 
  15, 
  2014, 
  a 
  report 
  on 
  
options 
  for 
  establishing 
  a 
  solar 
  carve-­‐out 
  within 
  the 
  RPS. 
   
   
  
o March 
  27, 
  2013: 
  Introduced 
  and 
  referred 
  to 
  Energy, 
  Utilities 
  and 
  Technology 
  Committee. 
  
o April 
  24, 
  2013: 
  Hearing 
  held. 
  Maine 
  Central 
  Power 
  and 
  the 
  Governor’s 
  Energy 
  Office 
  testified 
  in 
  
opposition. 
  The 
  Sierra 
  Club 
  and 
  other 
  groups 
  testified 
  in 
  support. 
  
o May 
  7 
  and 
  May 
  13, 
  2013: 
  Work 
  sessions 
  held. 
  
o July 
  9, 
  2013: 
  Carried 
  over. 
  
o December 
  11, 
  2013: 
  Work 
  session 
  held. 
  The 
  committee 
  may 
  be 
  working 
  on 
  a 
  more 
  encompassing 
  
piece 
  of 
  legislation 
  relating 
  to 
  renewable 
  energy. 
  
o January 
  15 
  & 
  22, 
  2014: 
  Work 
  sessions 
  held. 
  Votes 
  were 
  not 
  taken. 
  
o January 
  28 
  & 
  February 
  4, 
  2014: 
  Work 
  sessions 
  held. 
   
  
o February 
  6, 
  2014: 
  Work 
  session 
  held. 
  The 
  committee 
  could 
  not 
  come 
  to 
  a 
  unanimous 
  decision, 
  
resulting 
  in 
  a 
  divided 
  report. 
  The 
  measure 
  was 
  not 
  reported 
  out 
  of 
  committee. 
  Once 
  reported, 
  the 
  
measure 
  will 
  go 
  to 
  the 
  House 
  floor 
  for 
  consideration. 
  
 
  

 Timeline of Key State Activities on Net Energy Metering

25

 
  
•

•

•

L.D. 
  1652: 
  Would 
  create 
  Maine 
  Solar 
  Energy 
  Act; 
  require 
  the 
  PUC 
  to 
  determine 
  the 
  value 
  of 
  distributed 
  
solar, 
  develop 
  a 
  method 
  for 
  doing 
  so, 
  and 
  monitor 
  solar 
  development 
  and 
  market 
  trends. 
  The 
  PUC 
  must 
  
report 
  to 
  the 
  legislature. 
  Would 
  set 
  state 
  solar 
  goals: 
  40 
  MW 
  of 
  installed 
  capacity 
  by 
  2016, 
  200 
  MW 
  by 
  
2020 
  and 
  500 
  MW 
  by 
  2030. 
  
o 2013: 
  Filed 
  October 
  1. 
  Approved 
  by 
  Legislative 
  Council 
  October 
  30. 
  Changed 
  into 
  legislative 
  
document 
  and 
  referred 
  to 
  Joint 
  Committee 
  on 
  Energy, 
  Utilities 
  and 
  Technology 
  December 
  23. 
  
o January 
  21, 
  2014: 
  Hearing 
  scheduled. 
  A 
  vote 
  is 
  not 
  anticipated. 
  The 
  sponsor, 
  Sen. 
  Millett 
  (D), 
  Rep. 
  
Dorney 
  (D), 
  and 
  representatives 
  of 
  the 
  Maine 
  Audubon 
  Society, 
  the 
  International 
  Brotherhood 
  of 
  
Electrical 
  Workers 
  and 
  Central 
  Maine 
  Power 
  offered 
  testimony 
  in 
  support. 
  Gov. 
  LePage 
  (R) 
  and 
  
representatives 
  from 
  the 
  Governor's 
  Energy 
  Office 
  testified 
  in 
  opposition. 
  
o January 
  22, 
  2014: 
  Work 
  session 
  held. 
   
  
o February 
  12, 
  19 
  & 
  27 
  and 
  March 
  6 
  & 
  7, 
  2014: 
  Work 
  sessions 
  held. 
   
  
o March 
  11, 
  2014: 
  Work 
  session 
  scheduled. 
  
 
  
October 
  1, 
  2013: 
  L.R. 
  3650, 
  an 
  act 
  to 
  encourage 
  DG 
  in 
  the 
  state, 
  filed 
  by 
  president 
  of 
  the 
  Senate. 
  This 
  is 
  
a 
  Legislator 
  Request 
  (LR); 
  bill 
  text 
  will 
  not 
  be 
  available 
  until 
  it 
  is 
  formally 
  introduced. 
   
  This 
  measure 
  will 
  
only 
  be 
  introduced 
  if 
  a 
  member 
  of 
  the 
  Legislature 
  takes 
  it 
  up 
  and 
  elects 
  to 
  sponsor 
  it. 
  When 
  the 
  request 
  
is 
  formally 
  introduced, 
  it 
  will 
  then 
  be 
  referred 
  to 
  a 
  committee. 
  The 
  Maine 
  Legislature 
  will 
  convene 
  
January 
  8, 
  2014. 
  
 
  
October 
  21, 
  2013: 
  Joint 
  Standing 
  Committee 
  on 
  Energy, 
  Utilities 
  and 
  Technology 
  will 
  hold 
  a 
  public 
  
meeting 
  featuring 
  policy 
  discussions 
  that 
  include 
  community-­‐based 
  renewable 
  energy, 
  net 
  energy 
  
billing, 
  feed-­‐in 
  tariffs, 
  and 
  renewable 
  portfolio 
  standards. 
  Agenda 
   
  

MARYLAND 
  
Legislation 
  
•

•

H.B. 
  1149: 
  Would 
  increase 
  RPS 
  to 
  40% 
  (Tier 
  1 
  renewable 
  resources) 
  by 
  2025, 
  including 
  4% 
  solar 
  carve-­‐
out 
  and 
  max. 
  2.5% 
  offshore 
  wind. 
  Current 
  RPS 
  targets 
  are 
  20% 
  (Tier 
  1) 
  by 
  2022 
  including 
  2% 
  solar 
  carve-­‐
out, 
  and 
  max. 
  2.5% 
  offshore 
  wind 
  carve-­‐out 
  beginning 
  in 
  2017. 
  
o February 
  6, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  Economic 
  Matters 
  Committee. 
  
o February 
  27, 
  2014: 
  Hearing 
  held. 
  Representatives 
  from 
  the 
  Chesapeake 
  Climate 
  Network, 
  MD 
  
League 
  of 
  Conservation 
  Voters, 
  Sierra 
  Club 
  and 
  the 
  MD-­‐DE-­‐VA 
  Solar 
  Industries 
  Association 
  testified 
  
in 
  support. 
  Exelon, 
  BGE, 
  W.R. 
  Grace, 
  First 
  Energy, 
  MD 
  Industrial 
  Technology 
  Alliance, 
  MD 
  Wild 
  lands 
  
Committee, 
  Southern 
  MD 
  Electric 
  Cooperative, 
  Future 
  of 
  Energy 
  Initiative, 
  MD 
  Conservation 
  Council, 
  
and 
  MD 
  Retailers 
  Association 
  and 
  Energy 
  Justice 
  Network 
  testified 
  in 
  opposition. 
  
 
  
H.B. 
  1192: 
  Would 
  create 
  a 
  community 
  renewable 
  energy 
  system 
  pilot 
  program, 
  administered 
  by 
  the 
  MD 
  
Public 
  Service 
  Commission 
  (PSC). 
  Subscribers, 
  through 
  net 
  metering, 
  could 
  receive 
  credit 
  for 
  net 
  excess 
  
generation 
  up 
  to 
  120% 
  of 
  baseline 
  annual 
  usage. 
  Utility 
  ownership 
  allowed. 
  Would 
  ensure 
  that 
  an 
  lectric 
  
company 
  continue 
  to 
  facilitate 
  operation 
  of 
  a 
  community 
  renewable 
  system 
  even 
  after 
  the 
  pilot 
  has 
  
been 
  terminated. 
  
o February 
  7, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  Economic 
  Matters 
  Committee. 
  

 Timeline of Key State Activities on Net Energy Metering

26

 
  
March 
  6, 
  2014: 
  Hearing 
  held. 
  The 
  MD 
  Energy 
  Administration, 
  Baltimore 
  Sustainability 
  Commission, 
  
Capital 
  Sun 
  Group, 
  Interfaith 
  Power 
  and 
  Light, 
  MD-­‐DC-­‐VA 
  Solar 
  Energy 
  Industries 
  Association, 
  
Baltimore 
  Community 
  Foundation, 
  City 
  of 
  Rockville, 
  Green 
  Building 
  Initiative, 
  Chesapeake 
  Climate 
  
Action 
  Network, 
  Greenbelt 
  Community 
  Solar 
  and 
  Office 
  of 
  People's 
  Counsel 
  testified 
  in 
  support. 
  The 
  
Sierra 
  Club 
  and 
  Community 
  Research 
  testified 
  in 
  support 
  but 
  with 
  an 
  amendment 
  to 
  not 
  include 
  
gasification 
  in 
  the 
  definition. 
  GE, 
  Exelon 
  and 
  FirstEnergy/Potomac 
  Edison 
  testified 
  in 
  opposition. 
  No 
  
action 
  was 
  taken. 
  
 
  
S.B. 
  786: 
  Would 
  establish 
  pilot 
  community 
  renewables 
  program 
  to 
  be 
  administered 
  by 
  the 
  MD 
  PSC. 
  
o January 
  31, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  Finance 
  Committee. 
  
o March 
  4, 
  2014: 
  Hearing 
  held. 
  The 
  MD 
  Energy 
  Administration, 
  Energy 
  Justice 
  Network, 
  Chesapeake 
  
Climate 
  Action 
  Network, 
  MD 
  Solar 
  United 
  Neighborhoods, 
  Greenbelt 
  Community 
  Solar, 
  MD 
  Clean 
  
Energy 
  Center, 
  Office 
  of 
  People's 
  Counsel 
  and 
  George 
  Washington 
  Solar 
  Institute 
  testified 
  in 
  
support. 
  BGE, 
  Exelon 
  and 
  FirstEnergy/Potomac 
  Edison 
  testified 
  in 
  opposition. 
  The 
  Sierra 
  Club 
  and 
  
Rockville 
  Environment 
  commission 
  testified 
  in 
  support 
  with 
  amendments. 
  No 
  action 
  was 
  taken. 
  
o

•

MASSACHUSETTS 
  
Legislation 
  
•

H.B. 
  3802: 
  Would 
  add 
  clean, 
  non-­‐combustion 
  DG 
  facilities 
  to 
  solicitation 
  requirements 
  for 
  DG 
  contracts 
  
by 
  distribution 
  companies 
  as 
  stated 
  in 
  existing 
  law. 
  States 
  that 
  10% 
  of 
  long-­‐term 
  contracts 
  shall 
  be 
  
reserved 
  for 
  clean, 
  non-­‐combustion 
  DG 
  facilities. 
  
o November 
  22, 
  2013: 
  Filed. 
  Referred 
  to 
  Joint 
  Committee 
  on 
  Telecommunications, 
  Utilities 
  and 
  Energy 
  
on 
  November 
  27, 
  2013. 
   
  
o January 
  8, 
  2014: 
  Hearing 
  scheduled. 
  

•

S.B. 
  1970: 
  Would 
  establish 
  an 
  alternative 
  energy 
  portfolio 
  standard 
  for 
  all 
  retail 
  electricity 
  providers. 
  
Eligible 
  resources 
  include 
  combined 
  heat 
  and 
  power 
  and 
  flywheel 
  energy 
  storage. 
  
o January 
  9, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  Committee 
  on 
  Ways 
  and 
  Means. 
  
 
  
S.B. 
  2019: 
  Specifies 
  that 
  any 
  on-­‐site 
  renewable 
  energy 
  source 
  determined 
  by 
  the 
  administrator 
  of 
  the 
  
net 
  metering 
  system 
  of 
  assurance 
  to 
  otherwise 
  meet 
  the 
  qualifications 
  for 
  NEM 
  cap 
  allocation 
  will 
  
qualify 
  for 
  NEM, 
  provided 
  the 
  determination 
  is 
  obtained 
  on 
  or 
  before 
  December 
  31, 
  2016. 
  Would 
  
establish 
  a 
  study 
  commission 
  to 
  research 
  and 
  review 
  the 
  long-­‐term 
  viability 
  of 
  net 
  metering. 
  
(Companion 
  bill 
  – 
  H.B. 
  3901) 
  
o January 
  10, 
  2014: 
  Introduced. 
  
o January 
  13 
  & 
  February 
  26, 
  2014: 
  Referred 
  respectively 
  to 
  Joint 
  Committee 
  on 
  Rules 
  and 
  Joint 
  
Committee 
  on 
  Telecommunications, 
  Utilities 
  and 
  Energy. 
  
o March 
  11, 
  2014: 
  Hearing. 
  A 
  vote 
  is 
  not 
  expected 
  but 
  may 
  occur 
  at 
  the 
  discretion 
  of 
  the 
  chair. 
  
 
  
S.B. 
  2030: 
  Requires 
  the 
  Department 
  of 
  Energy 
  Resources 
  (DOER) 
  to 
  authorize 
  utilities 
  to 
  individually 
  and 
  
jointly 
  propose 
  and 
  implement 
  competitive 
  programs 
  for 
  procurement 
  of 
  solar 
  DG 
  projects 
  500 
  kW 
  and 
  
larger, 
  including 
  any 
  subsets, 
  that 
  begin 
  operation 
  on 
  or 
  after 
  January 
  1, 
  2016. 
  Procurements 
  may 
  

 
  

•

•

 Timeline of Key State Activities on Net Energy Metering

27

 
  

•

include 
  solar 
  renewable 
  energy 
  certificates. 
  Would 
  increase 
  aggregate 
  NEM 
  capacity 
  from 
  3% 
  of 
  a 
  
distribution 
  company's 
  peak 
  load 
  to 
  4%. 
  Requires 
  the 
  DPU 
  to 
  open 
  by 
  July 
  1, 
  2015, 
  a 
  generic 
  docket 
  to 
  
establish 
  minimum 
  distribution 
  bill 
  charges 
  for 
  net 
  metered 
  customers. 
  
o February 
  24, 
  2014: 
  Introduced. 
  
o March 
  4, 
  2014: 
  Referred 
  to 
  Joint 
  Committee 
  on 
  Telecommunications, 
  Utilities 
  and 
  Energy. 
  
o March 
  11, 
  2014: 
  Hearing 
  scheduled. 
  
 
  
S.B. 
  2395 
  (2012): 
  “An 
  Act 
  relative 
  to 
  competitively 
  priced 
  electricity 
  in 
  the 
  Commonwealth.” 
  Doubles 
  net 
  
metering 
  cap 
  to 
  6 
  percent; 
  of 
  that, 
  3 
  percent 
  applies 
  to 
  public 
  projects 
  and 
  3% 
  to 
  private 
  projects. 
  
Certain 
  small 
  facilities 
  are 
  exempt 
  from 
  cap, 
  e.g., 
  those 
  less 
  than 
  10 
  kW 
  (single 
  phase). 
  Allows 
  electric 
  
utilities 
  to 
  own 
  up 
  to 
  25 
  MW 
  of 
  solar; 
  utilities 
  must 
  obtain 
  DPU 
  approval 
  for 
  such 
  facilities 
  by 
  June 
  30, 
  
2014. 
  Adds 
  anaerobic 
  digestion 
  to 
  allowable 
  net 
  metered 
  facilities. 
  Directs 
  DPU 
  to 
  develop 
  enforceable 
  
standard 
  interconnection 
  timeline. 
  Appoints 
  9-­‐member 
  commission 
  to 
  study 
  economic/environmental 
  
benefits 
  and 
  economic/electricity 
  cost 
  implications 
  of 
  the 
  commonwealth’s 
  energy 
  policies. 
  Requires 
  
DPU 
  to 
  design 
  base 
  rates 
  using 
  cost 
  allocation 
  method 
  based 
  on 
  equalized 
  rates 
  of 
  return 
  for 
  each 
  
customer 
  class. 
  Has 
  numerous 
  other 
  provisions, 
  including 
  those 
  affecting 
  RES 
  and 
  long-­‐term 
  contracting 
  
requirements. 
  
o August 
  3, 
  2012: 
  Enacted. 
  
o As 
  of 
  December 
  2013: 
  Utilities 
  have 
  hit 
  or 
  are 
  near 
  hitting 
  the 
  NEM 
  caps, 
  giving 
  rise 
  to 
  discussion 
  of 
  
legislation 
  to 
  raise 
  the 
  cap 
  again. 
  
o June 
  30, 
  2014: 
  Utilities 
  must 
  obtain 
  DPU 
  approval 
  for 
  utility-­‐owned 
  solar 
  facilities 
  up 
  to 
  25 
  MW. 
  

Rates 
  and 
  Regulation 
  
•

•

•

National 
  Grid 
  proposal 
  to 
  own 
  20 
  MW 
  of 
  solar, 
  Docket 
  No. 
  DPU 
  14-­‐01 
  
o January 
  2, 
  2014: 
  National 
  Grid 
  filed 
  petition 
  with 
  MA 
  Department 
  of 
  Public 
  Utilities 
  (DPU), 
  as 
  part 
  of 
  
broader 
  solar 
  program, 
  to 
  own 
  and 
  operate 
  up 
  to 
  20 
  MW 
  of 
  solar 
  on 
  company-­‐owned 
  or 
  customer-­‐
owned 
  property. 
  
o January 
  28, 
  2014: 
  Interventions 
  due. 
  The 
  AG 
  intervened. 
  
o January 
  31, 
  2014: 
  Public 
  hearing 
  and 
  procedural 
  conference; 
  discovery 
  begins. 
  
o April 
  15, 
  2014: 
  Final 
  discovery 
  responses 
  due. 
  
o April 
  24-­‐25, 
  2014: 
  Evidentiary 
  hearings, 
  if 
  necessary. 
  
o May 
  12, 
  2014: 
  Simultaneous 
  briefs. 
  
o May 
  19, 
  2014: 
  Simultaneous 
  reply 
  briefs. 
  
 
  
Investigation 
  into 
  time-­‐varying 
  rates, 
  Docket 
  No. 
  1404. 
  
o January 
  23, 
  2014: 
  The 
  MA 
  DPU 
  opened 
  an 
  investigation 
  to 
  explore, 
  among 
  other 
  things, 
  whether 
  
time-­‐varying 
  rates 
  provide 
  appropriate 
  incentives 
  for 
  distributed 
  resources 
  such 
  as 
  solar 
  PV 
  and 
  
storage. 
  The 
  investigation 
  is 
  in 
  the 
  context 
  of 
  grid 
  modernization. 
  
o March 
  10, 
  2014: 
  Comments 
  due. 
  
 
  
DPU 
  net 
  metering 
  webpage: 
  Provides 
  docket 
  information 
  on 
  proceedings 
  related 
  to 
  individual 
  utility 
  net 
  
metering 
  tariffs 
  and 
  net 
  metering 
  recovery 
  surcharges 
  (NMRS), 
  interconnection, 
  and 
  other 
  information. 
  
 
   
  

 Timeline of Key State Activities on Net Energy Metering

28

 
  
•

•

Renewable 
  Portfolio 
  Standard 
  (RPS) 
  Solar 
  Carve-­‐out 
   
  (SREC 
  program) 
  
o August 
  12, 
  2013: 
  The 
  MA 
  Department 
  of 
  Energy 
  Resources 
  (DOER) 
  presented 
  at 
  a 
  stakeholder 
  
meeting 
  its 
  proposed 
  update 
  of 
  the 
  RPS 
  solar 
  carve-­‐out, 
  which 
  currently 
  is 
  400 
  MW 
  by 
  2017. 
  The 
  
proposal 
  was 
  made 
  under 
  emergency 
  regulations 
  issued 
  by 
  DOER 
  on 
  June 
  28, 
  2013, 
  to 
  expand 
  the 
  
400 
  MW 
  cap, 
  which 
  is 
  oversubscribed. 
  The 
  proposed 
  new 
  program 
  would 
  be 
  capped 
  at 
  1,200 
  MW, 
  
create 
  a 
  new 
  separate 
  solar 
  renewable 
  energy 
  credit 
  market 
  (SREC 
  II) 
  and 
  provide 
  for 
  declining 
  
incentives 
  over 
  time, 
  differentiated 
  by 
  market 
  sector. 
  The 
  Governor 
  has 
  set 
  a 
  goal 
  of 
  1600 
  MW 
  by 
  
2020. 
  Presentation 
  is 
  located 
  at: 
  http://www.mass.gov/eea/docs/doer/renewables/solar/srec-­‐ii-­‐
final-­‐proposed-­‐design-­‐stakeholder-­‐review-­‐mtg-­‐081213.pdf 
   
  
Consultant 
  reports 
  and 
  other 
  materials 
  in 
  regulatory 
  proceeding 
  are 
  posted 
  at: 
  
www.mass.gov/eea/energy-­‐utilities-­‐clean-­‐tech/renewable-­‐energy/solar/rps-­‐solar-­‐carve-­‐out/post-­‐
400-­‐mw-­‐solar-­‐policy-­‐development.html 
   
  
o August 
  26, 
  2013: 
  Comments 
  due 
  on 
  proposed 
  updated 
  solar 
  carve-­‐out 
  design. 
  
o October 
  7, 
  2013: 
  DOER 
  technical 
  conference 
  for 
  stakeholders 
  to 
  review 
  consultant 
  reports 
  with 
  
consultants 
  contracted 
  by 
  DOER 
  to 
  inform 
  decisions. 
  Five 
  reports 
  are 
  posted 
  at 
  above 
  link: 
  1) 
  
Evaluation 
  of 
  Current 
  Solar 
  Costs 
  and 
  Needed 
  Incentive 
  Levels 
  Across 
  Market 
  Segments, 
  and 
  2) 
  
Comparative 
  Evaluation 
  of 
  Carve-­‐out 
  Policy 
  with 
  Other 
  Policy 
  Alternatives, 
  3) 
  Evaluation 
  of 
  400 
  MW 
  
(SREC-­‐I) 
  Program 
  in 
  Meeting 
  its 
  Objectives, 
  4) 
  Analysis 
  of 
  Economic 
  Costs 
  and 
  Benefits 
  of 
  Solar 
  
Program 
  (SREC-­‐II), 
  and 
  5) 
  Comparative 
  Regional 
  Economic 
  Impacts 
  of 
  Solar 
  Ownership/Financing 
  
Alternatives. 
  
o November 
  14, 
  2013: 
  DOER 
  released 
  the 
  RPS 
  Solar 
  Carve-­‐Out 
  Construction 
  Timeline 
  Extensions 
  final 
  
guideline, 
  Detailed 
  Construction 
  Cost 
  Form, 
  and 
  Construction 
  Timeline 
  Affidavit. 
  The 
  guideline 
  
applies 
  to 
  all 
  solar 
  carve-­‐out 
  generation 
  units 
  larger 
  than 
  100 
  kW 
  that 
  have 
  received 
  a 
  Statement 
  of 
  
Qualification 
  and 
  have 
  not 
  received 
  the 
  authorization 
  to 
  interconnect 
  or 
  permission 
  to 
  operate 
  by 
  
December 
  31, 
  2013. 
  In 
  addition, 
  DOER 
  is 
  still 
  developing 
  the 
  program 
  design 
  for 
  the 
  next 
  phase 
  of 
  
the 
  solar 
  carve-­‐out 
  program 
  (SREC-­‐II). 
  
o December 
  12, 
  2013: 
  At 
  the 
  New 
  England 
  Electricity 
  Restructuring 
  Roundtable, 
  Commissioner 
  Sylvia 
  
provided 
  a 
  presentation 
  on 
  the 
  final 
  SREC 
  II 
  policy 
  design 
  (located 
  at 
  materials 
  link 
  above). 
  
o January 
  3, 
  2014: 
  DOER 
  issued 
  a 
  proposed 
  regulation 
  that 
  plans 
  for 
  consistent 
  annual 
  growth 
  through 
  
2020 
  for 
  meeting 
  the 
  program 
  goal 
  (cap) 
  of 
  1600 
  MW. 
  
o January 
  24, 
  2014: 
  Public 
  hearing. 
  
o January 
  29, 
  2014: 
  Comments 
  due. 
   
  
o February 
  11, 
  2014: 
  DOER 
  submitted 
  an 
  updated 
  draft 
  regulation 
  to 
  the 
  Joint 
  Committee 
  on 
  
Telecommunications, 
  Utilities, 
  and 
  Energy, 
  which 
  will 
  review 
  it 
  for 
  30 
  days 
  and 
  submit 
  comments. 
  
DOER 
  will 
  review 
  the 
  comments 
  for 
  30 
  days 
  and 
  promulgate 
  the 
  regulation 
  as 
  soon 
  as 
  possible. 
  
 
  
DOER 
  study 
  on 
  net 
  metering 
  
o December 
  12, 
  2013: 
  In 
  a 
  presentation 
  at 
  the 
  New 
  England 
  Electricity 
  Restructuring 
  Roundtable, 
  
Commissioner 
  Sylvia 
  said 
  the 
  DOER 
  is 
  cognizant 
  that 
  utilities 
  are 
  hitting 
  NEM 
  caps 
  but 
  does 
  not 
  have 
  
a 
  position 
  on 
  whether 
  caps 
  should 
  be 
  raised. 
  DOER 
  has 
  commissioned 
  a 
  study 
  on 
  NEM 
  policy 
  and 
  is 
  
evaluating 
  costs/benefits 
  and 
  policy 
  options 
  to 
  assist 
  with 
  policymaking. 
   
  The 
  study 
  is 
  due 
  soon, 
  
Sylvia 
  said. 
  Sen. 
  Marc 
  Pacheco, 
  D-­‐Taunton, 
  who 
  sits 
  on 
  the 
  Telecommunications, 
  Utilities 
  and 
  Energy 
  
Committee, 
  has 
  been 
  quoted 
  as 
  saying 
  the 
  legislature 
  is 
  waiting 
  for 
  review 
  of 
  the 
  program 
  by 
  DOER 
  
before 
  it 
  considers 
  raising 
  the 
  cap. 
  

 Timeline of Key State Activities on Net Energy Metering

29

 
  
•

 
  
Generic 
  investigation 
  into 
  DG 
  interconnection, 
  Docket 
  Nos. 
  DPU 
  11-­‐75 
  and 
  11-­‐11 
  
o March 
  13, 
  2013: 
  The 
  MA 
  DPU 
  issued 
  an 
  order 
  (Docket 
  No. 
  11-­‐75-­‐E) 
  that, 
  among 
  other 
  things, 
  
accepted 
  tariff 
  and 
  non-­‐tariff 
  recommendations 
  of 
  DG 
  working 
  group 
  in 
  the 
  group’s 
  September 
  14, 
  
2012, 
  report, 
  and 
  created 
  new 
  designation 
  of 
  interconnection 
  service 
  agreement 
  (ISA) 
  called 
  Early 
  
ISA 
  (Docket 
  No. 
  11-­‐11). 
  The 
  DPU 
  also 
  directed 
  the 
  DG 
  Transition 
  working 
  group 
  (WG) 
  to 
  collaborate 
  
to 
  develop 
  a 
  timeline 
  enforcement 
  mechanism 
  to 
  encourage 
  utility 
  adherence 
  to 
  interconnection 
  
timelines 
  and 
  to 
  report 
  results 
  to 
  DPU. 
  
o August 
  9, 
  2013: 
  Comments 
  due 
  on 
  Early 
  ISA. 
  
o August 
  16, 
  2013: 
  Reply 
  comments 
  due 
  on 
  Early 
  ISA. 
  
o October 
  1, 
  2013: 
  Working 
  Group 
  proposal(s) 
  for 
  timeline 
  enforcement 
  mechanism 
  submitted: 
  
http://www.env.state.ma.us/dpu/docs/electric/11-­‐75/11-­‐75-­‐Filing-­‐4789.pdf 
   
  
o October 
  30, 
  2013: 
  The 
  DPU 
  issued 
  an 
  order 
  finding 
  that 
  an 
  Early 
  ISA 
  satisfies 
  its 
  “executed 
  ISA” 
  
requirement 
  for 
  filing 
  an 
  application 
  with 
  the 
  net 
  metering 
  System 
  of 
  Assurance. 
  
o November 
  21, 
  2013: 
  The 
  DPU 
  released 
  a 
  memorandum 
  regarding 
  the 
  interconnection 
  timeline 
  
enforcement 
  mechanism. 
  The 
  DPU 
  is 
  reviewing 
  the 
  proposed 
  interconnection 
  timeframe 
  
enforcement 
  metric, 
  and 
  it 
  may 
  take 
  more 
  than 
  two 
  months 
  to 
  release 
  the 
  final 
  mechanism. 
  To 
  
avoid 
  delaying 
  the 
  first 
  reporting 
  year, 
  the 
  DPU 
  directed 
  distribution 
  companies 
  to 
  begin 
  collecting 
  
this 
  data 
  January 
  1, 
  2014. 
  

Other 
  Initiatives 
  
•

October 
  18, 
  2013: 
  The 
  Energy 
  Policy 
  Review 
  Commission 
  (EPRC) 
  released 
  for 
  comment 
  its 
  mandated 
  
draft 
  report 
  to 
  the 
  legislature. 
  The 
  commission 
  was 
  created 
  per 
  S. 
  2395 
  (August 
  2012) 
  to 
  research 
  and 
  
review 
  the 
  economic/environmental 
  benefit 
  and 
  economic/electricity 
  cost 
  implications 
  of 
  energy 
  and 
  
electricity 
  policies 
  in 
  the 
  commonwealth, 
  including 
  net 
  metering. 
  (See 
  item 
  under 
  Legislation 
  above.) 
  
o October 
  28, 
  2013: 
  Comments 
  due 
  on 
  draft 
  report. 
  
o October 
  30, 
  2013: 
  Next 
  commission 
  meeting. 
  
o October 
  31, 
  2013: 
  Final 
  report 
  submitted 
  to 
  legislature 
  under 
  extended 
  schedule. 
  The 
  commission 
  
recommended 
  metrics, 
  including: 
  Rate 
  impact 
  of 
  NEM, 
  DG, 
  and 
  other 
  similar 
  behind 
  the 
  meter 
  
measures 
  on 
  different 
  rate 
  classes, 
  both 
  in 
  the 
  short 
  term 
  and 
  over 
  time 
  as 
  part 
  of 
  a 
  cost 
  benefit 
  
analysis. 
  One 
  example 
  is 
  the 
  potential 
  for 
  innovative 
  technologies 
  to 
  proliferate 
  in 
  some 
  rate 
  classes 
  
but 
  not 
  others 
  given 
  current 
  energy 
  economics 
  and 
  policy 
  environment. 
  

MICHIGAN 
  
•

Report 
  on 
  renewable 
  energy, 
  including 
  discussion 
  of 
  DG 
  and 
  net 
  metering 
  
o September 
  20, 
  2013: 
  The 
  MI 
  Public 
  Service 
  Commission 
  (PSC) 
  and 
  MI 
  Energy 
  Office 
  issued 
  a 
  draft 
  
report 
  that 
  was 
  requested 
  in 
  November 
  2012 
  by 
  Gov. 
  Rick 
  Snyder 
  after 
  the 
  defeat 
  of 
  Proposal 
  12-­‐3. 
  
The 
  proposal 
  would 
  have 
  amended 
  the 
  state 
  Constitution 
  to 
  require 
  that 
  25% 
  of 
  the 
  state’s 
  energy 
  
come 
  from 
  renewable 
  sources 
  (versus 
  the 
  existing 
  standard 
  of 
  10% 
  by 
  2015). 
  Snyder 
  had 
  said 
  he 
  
wanted 
  to 
  study 
  the 
  issue 
  for 
  a 
  year 
  to 
  enable 
  him 
  to 
  make 
  policy 
  recommendations 
  to 
  the 
  
legislature 
  in 
  2014. 
  Recommendations 
  could 
  include 
  an 
  increase 
  in 
  the 
  RES 
  target. 
  
o October 
  16, 
  2013: 
  Comments 
  due. 
  
o November 
  4, 
  2013: 
  Final 
  report 
  released. 
  

 Timeline of Key State Activities on Net Energy Metering

30

 
  
o

December 
  19, 
  2013: 
  The 
  Governor 
  announced 
  goals 
  for 
  an 
  energy 
  policy 
  that 
  moves 
  the 
  state 
  
toward 
  a 
  clean 
  energy 
  policy 
  standard. 
  The 
  Governor 
  is 
  expected 
  to 
  issue 
  legislative 
  policy 
  
recommendations 
  with 
  the 
  annual 
  energy 
  report 
  to 
  the 
  legislature. 
  

MINNESOTA 
  
Rates 
  and 
  Regulation 
  
 
  
• Establishment 
  of 
  distributed 
  value 
  of 
  solar 
  (VOS) 
  methodology 
  per 
  H.F. 
  729, 
  MN 
  Public 
  Utilities 
  
Commission 
  (PUC) 
  Docket 
  No. 
  E999/M-­‐14-­‐65 
  
o January 
  31, 
  2014: 
  Filing 
  of 
  proposed 
  tariff 
  methodology 
  by 
  MN 
  Department 
  of 
  Commerce 
  (DOC), 
  
Division 
  of 
  Energy 
  Resources. 
  (See 
  item 
  below 
  for 
  MN 
  DOC 
  implementation 
  of 
  H.F. 
  729.) 
  The 
  PUC 
  
must 
  approve, 
  modify 
  with 
  DOC’s 
  consent, 
  or 
  disapprove 
  the 
  methodology 
  within 
  60 
  days. The 
  PUC 
  
is 
  seeking 
  comments 
  on 
  two 
  questions: 
  1) 
  Whether 
  the 
  proposed 
  methodology 
  complies 
  with 
  the 
  
statute, 
  and 
  2) 
  the 
  reasonableness 
  of 
  the 
  proposed 
  methodology. 
  
o February 
  13, 
  2014: 
  Initial 
  comments 
  due. 
  
o February 
  20, 
  2014: 
  Reply 
  comments 
  due. 
  
o March 
  4, 
  2014: 
  Informational 
  meeting 
  to 
  help 
  PUC 
  understand 
  DOC 
  proposal. 
  
o March 
  12, 
  2014: 
  PUC 
  deliberation. 
  Oral 
  comments 
  to 
  be 
  heard. 
  
 
  
• Implementation 
  of 
  H.F. 
  729: 
  MN 
  DOC 
  development 
  of 
  proposed 
  VOS 
  tariff 
  methodology 
  for 
  approval 
  
by 
  the 
  MN 
  PUC. 
  The 
  DOC 
  is 
  holding 
  a 
  series 
  of 
  workshops 
  for 
  stakeholders 
  on 
  VOS 
  tariff 
  methodology. 
  
Utilities 
  that 
  adopt 
  a 
  VOS 
  tariff 
  as 
  an 
  alternative 
  to 
  net 
  metering 
  or 
  as 
  a 
  rate 
  for 
  community 
  solar 
  
gardens 
  will 
  be 
  required 
  to 
  follow 
  the 
  approved 
  methodology. 
  Clean 
  Power 
  Research 
  and 
  Rocky 
  
Mountain 
  Institute 
  are 
  assisting 
  DOC. 
  Information 
  on 
  the 
  proceeding, 
  including 
  meeting 
  agendas, 
  
presentations 
  and 
  comments, 
  is 
  located 
  at: 
  http://mn.gov/commerce/energy/topics/resources/energy-­‐
legislation-­‐initiatives/value-­‐of-­‐solar-­‐tariff-­‐methodology%20.jsp 
   
  
o September 
  17, 
  2013: 
  Workshop 
  1 
  – 
  overview 
  of 
  national 
  efforts 
  including 
  solar 
  PV 
  cost/benefit 
  
studies 
  and 
  stakeholder 
  Q&A 
  
o September 
  20, 
  2013: 
  Initial 
  comments 
  due. 
  (For 
  listing 
  of 
  comments 
  filed, 
  see 
  below.) 
  
o October 
  1, 
  2013: 
  Workshop 
  2 
  – 
  will 
  provide 
  review 
  of 
  a 
  proposed 
  approach 
  to 
  methodology, 
  
stakeholder 
  perspectives, 
  and 
  identification 
  of 
  key 
  issues 
  with 
  a 
  facilitated 
  discussion. 
  
o October 
  15, 
  2013: 
  Workshop 
  3 
  – 
  discussion 
  and 
  resolution 
  of 
  key 
  issues. 
  
o November 
  19, 
  2013: 
  Workshop 
  4 
  – 
  presentation 
  of 
  initial 
  draft 
  methodology 
  and 
  stakeholder 
  Q&A. 
  
Draft 
  VOS 
  methodology 
   
  
o December 
  10, 
  2013: 
  Comments 
  due 
  on 
  draft 
  methodology. 
  The 
  Department 
  is 
  currently 
  reviewing 
  
all 
  comments, 
  which 
  will 
  be 
  used 
  to 
  inform 
  the 
  final 
  draft 
  VOS 
  tariff 
  methodology. 
  
o January 
  31, 
  2014: 
  DOC 
  submitted 
  final 
  draft 
  methodology 
  to 
  PUC. 
  (See 
  entry 
  for 
  MN 
  PUC 
  Docket 
  No. 
  
E999/M-­‐14-­‐65.) 
  
•

Xcel 
  Energy 
  community 
  solar 
  gardens 
  program, 
  Docket 
  No. 
  E002/M-­‐13-­‐867 
  
o September 
  30, 
  2013: 
  As 
  required 
  by 
  H.F. 
  729, 
  Xcel 
  Energy 
  filed 
  a 
  petition 
  with 
  the 
  MN 
  PUC 
  
requesting 
  approval 
  of 
  a 
  proposed 
  community 
  solar 
  gardens 
  program. 
  Compensation 
  would 
  be 
  
provided 
  at 
  the 
  applicable 
  retail 
  rate 
  in 
  the 
  absence 
  of 
  a 
  VOS 
  tariff. 
   
  Xcel 
  Energy 
  proposed 
  to 
  accept 
  

 Timeline of Key State Activities on Net Energy Metering

31

 
  

•

applications 
  from 
  solar 
  developers 
  to 
  develop 
  the 
  gardens. 
  Xcel 
  Energy 
  would 
  seek 
  2.5 
  MW 
  per 
  
quarter 
  for 
  a 
  total 
  of 
  up 
  to 
  20 
  MW. 
  (The 
  H.F. 
  729 
  requirement 
  is 
  voluntary 
  for 
  other 
  utilities. 
  The 
  
utility 
  that 
  offers 
  the 
  program 
  may 
  own 
  the 
  PV 
  system.) 
  
o November 
  6, 
  2013: 
  Initial 
  comments 
  due. 
   
  
o December 
  3, 
  2013: 
  Supplemental 
  initial 
  comments 
  due. 
  
o December 
  17, 
  2013: 
  Reply 
  comments 
  due 
  on 
  extended 
  schedule. 
  The 
  PUC 
  is 
  currently 
  reviewing 
  all 
  
comments 
  and 
  will 
  proceed 
  accordingly. 
  
o February 
  18, 
  2014: 
  Oral 
  argument. 
  
o February 
  20, 
  2014: 
  PUC 
  deliberation. 
  PUC 
  gave 
  preliminary 
  approval, 
  including 
  purchase 
  at 
  the 
  retail 
  
rate 
  and 
  consumer 
  protections. 
  
o February 
  27, 
  2014: 
  PUC 
  deliberation. 
  The 
  PUC 
  came 
  to 
  a 
  final 
  decision 
  requiring 
  Xcel 
  Energy 
  to 
  refile 
  
its 
  plan/tariff 
  with 
  several 
  modifications 
  within 
  30 
  days 
  of 
  issuance 
  of 
  a 
  written 
  order. 
  
 
  
Possible 
  amendments 
  to 
  rules 
  governing 
  cogeneration 
  and 
  small 
  power 
  production, 
  including 
  NEM, 
  
Docket 
  No. 
  E-­‐999/R-­‐13-­‐729. 
  Possible 
  amendments 
  under 
  consideration 
  by 
  the 
  MN 
  Public 
  Utilities 
  
Commission 
  (PUC) 
  include: 
  1) 
  increasing 
  the 
  net-­‐metering 
  threshold 
  capacity; 
   
  2) 
  establishing 
  a 
  new 
  
annual 
  billing/crediting 
  method; 
  3) 
  prohibiting 
  certain 
  standby 
  charges; 
  4) 
  requiring 
  public 
  utilities 
  to 
  
aggregate 
  meters 
  for 
  net 
  metering 
  at 
  the 
  request 
  of 
  customers; 
  5) 
  authorizing 
  the 
  commission 
  to 
  limit 
  
cumulative 
  generation 
  from 
  net-­‐metered 
  customers 
  and 
  permitting 
  a 
  public 
  utility 
  to 
  request 
  that 
  the 
  
commission 
  set 
  these 
  limits; 
  6) 
  authorizing 
  public 
  utilities 
  to 
  limit 
  capacity 
  to 
  120% 
  of 
  demand 
  for 
  wind 
  
customers 
  and 
  to 
  120% 
  of 
  energy 
  consumption 
  for 
  solar 
  PV 
  customers; 
  and 
  7) 
  changing 
  requirements 
  
governing 
  the 
  uniform 
  statewide 
  contract 
  to 
  incorporate 
  the 
  new 
  net-­‐metering 
  threshold 
  for 
  facilities 
  
interconnecting 
  to 
  a 
  public 
  utility. 
   
  The 
  amendments 
  would 
  likely 
  affect 
  public 
  utilities, 
  cogenerators, 
  
small 
  power 
  producers, 
  municipal 
  electric 
  utilities, 
  net 
  -­‐metered 
  customers, 
  and 
  those 
  wanting 
  to 
  
interconnect 
  with 
  a 
  public 
  utility. 
   
  
o August 
  26, 
  2013: 
  Notice 
  of 
  request 
  for 
  comments 
  (pdf 
  pg. 
  278). 
  
o September 
  30, 
  2013: 
  Comments 
  due. 
  Staff 
  has 
  not 
  released 
  a 
  draft 
  proposal. 
  
o December 
  12, 
  2013: 
  The 
  PUC 
  authorized 
  the 
  appointment 
  of 
  an 
  advisory 
  committee, 
  with 
  size 
  and 
  
composition 
  to 
  be 
  determined 
  by 
  the 
  Executive 
  Secretary. 
  Staff 
  will 
  prepare 
  draft 
  rules 
  for 
  review 
  
and 
  approval 
  by 
  the 
  committee 
  as 
  soon 
  as 
  practicable. 
  

 
  
Legislation 
  
o

H.F. 
  729 
  (2013): 
  Sets 
  1.5% 
  solar 
  DG 
  target 
  by 
  2020 
  in 
  addition 
  to 
  existing 
  RES 
  of 
  25% 
  by 
  2025. 
  (Xcel 
  
Energy’s 
  RES 
  is 
  30% 
  by 
  2025.) 
  10% 
  of 
  1.5% 
  carve-­‐out 
  must 
  be 
  met 
  with 
  projects 
  20 
  kW 
  or 
  smaller. 
  
Certain 
  large 
  industrial 
  retail 
  customers, 
  co-­‐ops 
  and 
  municipals 
  are 
  not 
  included 
  in 
  solar 
  carve-­‐out 
  
calculation. 
  (Defeated 
  were 
  provisions 
  to 
  impose 
  a 
  4% 
  solar 
  carve-­‐out 
  and 
  1.33% 
  tax 
  on 
  electric 
  bills 
  to 
  
fund 
  small 
  solar 
  incentives.) 
  Also 
  provides: 
  
! Compensation 
  for 
  net 
  metered 
  customers 
  at 
  retail 
  rate 
  to 
  40 
  kW 
  and 
  at 
  avoided 
  cost 
  for 
  40 
  
kW 
  to 
  1 
  MW 
  
! Above 
  40 
  kW, 
  DG 
  must 
  be 
  sized 
  to 
  load, 
  i.e., 
  no 
  larger 
  than 
  120% 
  of 
  customer 
  need. 
  
! Multiple 
  account 
  tie-­‐in 
  (aggregation) 
  allowed 
  under 
  net 
  metering 
  
! PV 
  and 
  solar 
  thermal 
  incentive 
  funding 
  from 
  conservation/renewable 
  development 
  fund 
  
programs 
  

 Timeline of Key State Activities on Net Energy Metering

32

 
  
MN 
  Department 
  of 
  Commerce 
  (DOC) 
  to 
  develop 
  a 
  value 
  of 
  solar 
  (VOS) 
  tariff 
  methodology 
  
for 
  approval 
  by 
  the 
  MN 
  PUC. 
  
! VOS 
  tariff 
  may 
  be 
  developed 
  and 
  offered 
  by 
  utilities 
  in 
  lieu 
  of 
  retail 
  rate 
  under 
  net 
  metering; 
  
if 
  less 
  than 
  retail 
  price, 
  must 
  wait 
  three 
  years 
  to 
  offer 
  
! “Solar 
  garden” 
  DG 
  subscription 
  program 
  must 
  be 
  offered 
  by 
  Xcel 
  and 
  may 
  be 
  offered 
  by 
  
other 
  utilities 
  to 
  allow 
  multi-­‐party 
  shared 
  ownership 
  of 
  DG 
  units 
  
! Investor-­‐owned 
  utilities 
  may 
  petition 
  to 
  limit 
  further 
  DG 
  once 
  their 
  system 
  saturation 
  equals 
  
4% 
  of 
  annual 
  sales 
  
! Co-­‐ops 
  have 
  less 
  aggressive 
  DG 
  requirements 
   
  
o May 
  23, 
  2013: 
  Enacted. 
   
  
 
  
Note: 
  A 
  report 
  by 
  Mid-­‐Atlantic 
  SEIA 
  is 
  cited 
  by 
  MN 
  SEIA 
  in 
  its 
  initial 
  comments: 
  The 
  Value 
  of 
  Distributed 
  Solar 
  
Electric 
  Generation 
  to 
  New 
  Jersey 
  and 
  Pennsylvania, 
  http://mseia.net/site/wp-­‐
content/uploads/2012/05/MSEIA-­‐Final-­‐Benefits-­‐of-­‐Solar-­‐Report-­‐2012-­‐11-­‐01.pdf 
  
!

MISSOURI 
  
Rates 
  and 
  Regulation 
  
 
  
• KCP&L 
  Greater 
  Missouri 
  Operations 
  2013 
  RES 
  compliance 
  plan, 
  Docket 
  No. 
  ET-­‐2014-­‐0026 
  CLOSED 
  
o July 
  5, 
  2013: 
  KCP&L-­‐GMO 
  filed 
  motion 
  and 
  tariff 
  with 
  the 
  MO 
  Public 
  Service 
  Commission 
  (PSC) 
  in 
  
proceeding 
  on 
  2013 
  RES 
  compliance 
  plan 
  (filed 
  May 
  28, 
  2013, 
  Docket 
  No. 
  EO-­‐2013-­‐0505) 
  to 
  suspend 
  
payment 
  of 
  certain 
  solar 
  rebates 
  from 
  September 
  3, 
  2013, 
  through 
  December 
  31, 
  2013. 
  KCP&L-­‐GMO 
  
said 
  it 
  otherwise 
  will 
  be 
  out 
  of 
  compliance 
  with 
  the 
  state 
  RES, 
  which 
  imposes 
  a 
  1% 
  rate 
  increase 
  cap 
  
on 
  compliance 
  activities. 
  KCP&L-­‐GMO 
  said 
  it 
  is 
  trying 
  to 
  protect 
  customers 
  who 
  do 
  not 
  receive 
  
rebate 
  payments 
  “from 
  paying 
  a 
  subsidy 
  that 
  is 
  no 
  longer 
  rationally 
  related 
  to 
  the 
  solar 
  market.” 
   
  
o August 
  1, 
  2013: 
  The 
  PSC 
  issued 
  an 
  order 
  separating 
  the 
  motion 
  from 
  the 
  proceeding 
  on 
  the 
  RES 
  
plan. 
  Staff 
  filed 
  a 
  recommendation 
  to 
  reject 
  the 
  motion 
  and 
  require 
  more 
  evidence 
  from 
  KCP&L-­‐
GMO. 
  As 
  an 
  alternative, 
  staff 
  recommended 
  a 
  30-­‐day 
  suspension 
  of 
  the 
  proposed 
  tariff 
  to 
  October 
  
3, 
  2013. 
  
o September 
  4, 
  2013: 
  The 
  PSC 
  closed 
  the 
  docket 
  upon 
  withdrawal 
  by 
  KCP&L-­‐GMO 
  of 
  the 
  tariff. 
  The 
  
PSC 
  concurrently 
  opened 
  a 
  new 
  docket, 
  No. 
  ET-­‐2014-­‐0059, 
  to 
  consider 
  a 
  similar 
  tariff 
  filing 
  KCP&L-­‐
GMO 
  made 
  concurrently 
  on 
  September 
  4, 
  2013. 
  (See 
  item 
  below.) 
  
 
  
• KCP&L 
  Greater 
  Missouri 
  Operations 
  (GMO) 
  solar 
  rebates, 
  Docket 
  No. 
  ET-­‐2014-­‐0059 
  
o September 
  4, 
  2013: 
  GMO 
  filed 
  a 
  motion 
  and 
  tariff 
  with 
  the 
  MO 
  PSC 
  to 
  suspend 
  solar 
  rebates 
  in 
  
accord 
  with 
  a 
  new 
  law, 
  H.B. 
  142, 
  no 
  later 
  than 
  November 
  3, 
  2013. 
  GMO 
  said 
  it 
  reached 
  the 
  1% 
  cap 
  
in 
  July 
  2013. 
  Under 
  provisions 
  of 
  H.B. 
  142, 
  the 
  PSC 
  is 
  required 
  to 
  decide 
  the 
  case 
  within 
  60 
  days 
  of 
  
filing. 
  This 
  filing 
  differs 
  from 
  an 
  earlier 
  filing 
  (Docket 
  No. 
  ET-­‐2014-­‐0026, 
  above) 
  in 
  that 
  it 
  was 
  filed 
  
pursuant 
  to 
  the 
  provisions 
  of 
  H.B. 
  142. 
  (For 
  more 
  detail 
  on 
  H.B. 
  142, 
  see 
  item 
  below.) 
  
o September 
  10, 
  2013: 
  KCP&L-­‐Missouri 
  (KCP&L) 
  filed 
  a 
  similar 
  application 
  (Docket 
  No. 
  ET-­‐2014-­‐0071, 
  
consolidated 
  with 
  ET-­‐2014-­‐0059) 
  
o October 
  3-­‐4, 
  2013: 
  Evidentiary 
  hearing. 
   
  

 Timeline of Key State Activities on Net Energy Metering

33

 
  
October 
  10, 
  2013: 
  Non-­‐unanimous 
  settlement 
  filed 
  that 
  converts 
  the 
  remaining 
  years 
  of 
  the 
  rebate 
  
program, 
  which 
  extends 
  up 
  to 
  2010, 
  to 
  a 
  dollar 
  amount. 
  KCP&L 
  and 
  GMO 
  would 
  stop 
  making 
  
payments 
  once 
  the 
  amount 
  is 
  reached, 
  regardless 
  of 
  how 
  soon 
  it 
  happens. 
  Settlement 
  signed 
  by 
  
companies, 
  staff, 
  solar 
  interests, 
  consumer 
  advocate, 
  and 
  others. 
   
  
o October 
  23, 
  2013: 
  On-­‐the-­‐record 
  presentation 
  for 
  parties 
  to 
  answer 
  questions 
  from 
  the 
  bench 
  about 
  
the 
  settlement. 
  
o October 
  30, 
  2013: 
  The 
  PSC 
  issued 
  a 
  final 
  order, 
  effective 
  November 
  10, 
  2013, 
  approving 
  the 
  
specified 
  levels 
  that 
  KCP&L 
  ($36.5 
  million) 
  and 
  GMO 
  ($50 
  million) 
  must 
  reach 
  before 
  suspending 
  
payments. 
  The 
  order 
  also 
  states 
  that 
  the 
  1% 
  retail 
  rate 
  impact 
  cap 
  will 
  be 
  addressed 
  in 
  a 
  separate 
  
rulemaking 
  docket, 
  which 
  has 
  not 
  yet 
  been 
  opened. 
   
  Order 
  approving 
  stipulation 
  and 
  agreement 
   
  
 
  
• Ameren 
  Missouri 
  solar 
  rebates, 
  Docket 
  No. 
  ET-­‐2014-­‐0085 
  
o October 
  11, 
  2013: 
  Ameren 
  filed 
  a 
  petition 
  similar 
  to 
  that 
  of 
  KCP&L 
  in 
  Docket 
  No. 
  ET-­‐2014-­‐0059 
  and 
  
is 
  discussing 
  a 
  similar 
  settlement 
  (above). 
  By 
  law 
  the 
  PSC 
  must 
  act 
  within 
  60 
  days 
  of 
  the 
  application. 
   
  
o November 
  4, 
  2013: 
  Settlement 
  conference. 
  
o November 
  8, 
  2013: 
  Hearing. 
  
o November 
  13, 
  2013: 
  The 
  PSC 
  approved 
  a 
  settlement 
  reached 
  by 
  Ameren, 
  staff, 
  Office 
  of 
  Public 
  
Counsel, 
  and 
  solar 
  and 
  other 
  groups 
  similar 
  to 
  a 
  settlement 
  reached 
  in 
  the 
  KCP&L/GMO 
  cases 
  
(above). 
  The 
  settlement 
  provides 
  for 
  Ameren 
  to 
  continue 
  making 
  rebate 
  payments 
  until 
  a 
  dollar 
  cap 
  
is 
  reached: 
  $91.9 
  million 
  incurred 
  after 
  July 
  31, 
  2012. 
  Ameren 
  spent 
  $21.9 
  million 
  on 
  rebates 
  
between 
  August 
  1, 
  2012, 
  and 
  October 
  31, 
  2013, 
  according 
  to 
  the 
  agreement. 
  
Legislation 
  
 
  
• H.B. 
  1795: 
  Would 
  redefine 
  "customer 
  generator" 
  to 
  include 
  those 
  “supplied 
  electricity 
  by 
  an 
  electric 
  
utility 
  that 
  has 
  as 
  an 
  electric 
  generating 
  system 
  with 
  a 
  capacity 
  of 
  not 
  more 
  than 
  one 
  megawatt” 
  and 
  
that 
  may 
  not 
  be 
  sized 
  to 
  exceed 
  100% 
  of 
  its 
  own 
  requirements. 
  Would 
  require 
  the 
  MO 
  PSC 
  to 
  define 
  net 
  
metering 
  as 
  a 
  demand-­‐side 
  program 
  and 
  develop 
  cost 
  recovery 
  measures 
  that 
  allow 
  utilities 
  to 
  recover 
  
reasonable 
  costs 
  related 
  to 
  net 
  metering. 
  
o February 
  10 
  &18, 
  2014: 
  Introduced 
  and 
  referred 
  respectively 
  to 
  Utilities 
  Committee. 
  
o February 
  26, 
  2014: 
  Hearing 
  held. 
  
 
  
• H.B. 
  142 
  (2013): 
  Amends 
  solar 
  rebate 
  requirements 
  to 
  provide 
  for 
  the 
  step 
  down 
  of 
  the 
  solar 
  rebate 
  
over 
  7 
  years 
  beginning 
  in 
  2014 
  while 
  providing 
  certain 
  protections 
  to 
  solar 
  installers 
  and 
  utilities. 
  
Utilities 
  may 
  choose 
  to 
  offer 
  solar 
  rebates 
  after 
  the 
  phase-­‐out 
  period, 
  and 
  they 
  may 
  suspend 
  rebate 
  
payments 
  at 
  any 
  time 
  to 
  the 
  extent 
  such 
  payments 
  would 
  cause 
  the 
  utility 
  to 
  exceed 
  the 
  1% 
  retail 
  rate 
  
increase 
  cap 
  imposed 
  by 
  the 
  state 
  RES 
  on 
  compliance 
  activities. 
  Utilities 
  would 
  own 
  solar 
  renewable 
  
energy 
  credits 
  related 
  to 
  solar 
  projects 
  for 
  which 
  rebates 
  are 
  provided. 
   
  
o July 
  3, 
  2013: 
  Enacted. 
   
  
o August 
  28, 
  2013: 
  Became 
  effective. 
  
 
  
• H.B. 
  2064: 
  Would 
  require 
  utilities 
  to 
  make 
  solar 
  rebates 
  for 
  new 
  or 
  expanded 
  solar 
  electric 
  systems 
  of 
  
less 
  than 
  25 
  kW/system 
  available 
  to 
  public 
  schools, 
  public 
  and 
  private 
  institutions 
  of 
  higher 
  education, 
  
private 
  schools, 
  charter 
  schools 
  and 
  nonprofit 
  organizations. 
  Compliance 
  costs 
  would 
  be 
  limited 
  to 
  1% 
  of 
  
the 
  utility’s 
  base 
  revenue 
  level 
  and 
  retail 
  rate 
  increases 
  for 
  compliance 
  would 
  be 
  prohibited. 
  
o

 Timeline of Key State Activities on Net Energy Metering

34

 
  
o

March 
  4, 
  2014: 
  Introduced. 
  

 
  
•

•

•

S.B. 
  598: 
  Modifies 
  provisions 
  relating 
  to 
  the 
  renewable 
  energy 
  standard. 
  Text 
  not 
  yet 
  available. 
  
o December 
  3, 
  2013: 
  Filed. 
  
 
  
S.B. 
  871: 
  Would 
  requires 
  all 
  net 
  excess 
  energy 
  be 
  carried 
  forward 
  from 
  month-­‐to-­‐month 
  and 
  credited 
  
one-­‐to-­‐one 
  against 
  the 
  customer-­‐generator's 
  energy 
  consumption 
  in 
  subsequent 
  months; 
  net 
  excess 
  
energy 
  may 
  be 
  accumulated 
  over 
  multiple 
  billing 
  periods 
  except 
  any 
  accumulation 
  remaining 
  in 
  a 
  
customer-­‐generator's 
  account 
  shall 
  expire, 
  without 
  compensation, 
  as 
  the 
  end 
  of 
  March 
  billing 
  period 
  of 
  
a 
  12-­‐month 
  billing 
  period 
  or 
  when 
  the 
  customer-­‐generator 
  discontinues 
  service 
  or 
  terminates 
  NEM. 
  
o February 
  13, 
  2014: 
  Introduced. 
  
o March 
  6, 
  2014: 
  Referred 
  to 
  Commerce, 
  Consumer 
  Protection, 
  Energy 
  and 
  the 
  Environment 
  
Committee. 
  
 
  
S.C.R. 
  35: 
  Would 
  establish 
  Joint 
  Committee 
  on 
  Missouri's 
  Energy 
  Future 
  and 
  Fuel 
  Sources. 
  The 
  
committee 
  would 
  make 
  recommendations 
  in 
  several 
  areas, 
  including 
  solar 
  energy/calculation 
  of 
  VOS, 
  
and 
  battery 
  storage 
  technology 
  and 
  the 
  future 
  of 
  energy 
  capture, 
  renewable 
  energy 
  firming, 
  frequency 
  
leveling, 
  and 
  peak 
  load 
  shaving. 
   
   
  
o February 
  20, 
  2014: 
  Introduced. 
  

MONTANA 
  
•

S.B. 
  247: 
  Would 
  increase 
  the 
  net 
  metering 
  cap 
  on 
  a 
  customer’s 
  generating 
  capacity 
  from 
  50 
  kW 
  to 
  100 
  
kW. 
   
  
o February 
  26, 
  2013: 
  Failed 
  in 
  Senate 
  on 
  26-­‐24 
  vote. 
  

NEBRASKA 
  
Legislation 
  
•

•

 
  

L.B. 
  557: 
  Would 
  allow 
  a 
  community 
  solar 
  garden 
  (solar 
  electric 
  generation 
  facility) 
  to 
  be 
  owned 
  by 
  a 
  
subscriber 
  organization 
  and 
  provide 
  renewable 
  electricity 
  to 
  customers. 
  If 
  electricity 
  output 
  of 
  the 
  solar 
  
garden 
  is 
  not 
  fully 
  consumed, 
  the 
  local 
  distribution 
  utility 
  is 
  required 
  to 
  purchase 
  the 
  remaining 
  
renewable 
  energy. 
   
  
o March 
  5, 
  2013: 
  Hearing 
  held 
  by 
  Natural 
  Resources 
  Committee. 
  Will 
  carry 
  over 
  to 
  next 
  session. 
  
 
  
L.B. 
  818: 
  Changes 
  NEM 
  provisions 
  by 
  increasing 
  capacity 
  from 
  25 
  kWh 
  to 
  125 
  kWh 
  under 
  the 
  definition 
  
of 
  a 
  "qualified 
  facility." 
  States 
  that 
  nothing 
  prevents 
  a 
  local 
  distribution 
  utility 
  from 
  entering 
  into 
  other 
  
arrangements 
  with 
  customers 
  desiring 
  to 
  install 
  electric 
  generating 
  equipment 
  or 
  from 
  providing 
  NEM 
  to 
  
customer-­‐generators 
  having 
  renewable 
  generation 
  units 
  above 
  125 
  kWh. 
  
o January 
  10, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Natural 
  Resources 
  Committee. 
  
o February 
  13, 
  2014: 
  Hearing 
  held. 
  No 
  action 
  taken. 
  
 
  

 Timeline of Key State Activities on Net Energy Metering

35

 
  

NEVADA 
  
Legislation 
  
•

•

A.B. 
  428 
  (2013): 
  Makes 
  substantial 
  changes 
  to 
  solar, 
  waterpower 
  and 
  wind 
  programs 
  and 
  requires 
  the 
  
Public 
  Utilities 
  Commission 
  of 
  Nevada 
  (PUC) 
  to 
  open 
  an 
  investigatory 
  docket 
  on 
  the 
  costs 
  and 
  benefits 
  of 
  
net 
  metering. 
  (See 
  item 
  below.) 
  
o June 
  11, 
  2013: 
  Enacted. 
   
  
 
  
S.B. 
  252 
  (2013): 
  Revises 
  the 
  state 
  RES 
  by 
  gradually 
  eliminating 
  energy 
  efficiency 
  as 
  an 
  eligible 
  resource, 
  
eliminating 
  the 
  DG 
  credit 
  multiplier, 
  changing 
  requirements 
  for 
  RECs 
  including 
  carry-­‐forward 
  provisions, 
  
and 
  requiring 
  a 
  PUC 
  report 
  on 
  RECs. 
  
o June 
  6, 
  2013: 
  Enacted. 
  

Rates 
  and 
  Regulation 
  
•

•

Generic 
  investigation 
  on 
  net 
  metering, 
  Docket 
  No. 
  13-­‐07010. 
   
  
o July 
  8, 
  2013: 
  Per 
  A.B. 
  428, 
  the 
  NV 
  PUC 
  opened 
  an 
  investigation 
  to 
  examine 
  costs 
  and 
  benefits 
  of 
  net 
  
metering 
  in 
  Nevada. 
  
o August 
  23, 
  2013: 
  Comments 
  due. 
  
o September 
  6, 
  2013: 
  Reply 
  comments 
  due. 
  
o September 
  12, 
  2013: 
  Public 
  workshop 
  to 
  discuss 
  comments. 
  
o October 
  7, 
  2013: 
  Report 
  on 
  costs/benefits 
  of 
  DG 
  released 
  by 
  Interstate 
  Renewable 
  Energy 
  Council 
  
and 
  filed 
  in 
  docket 
  at 
  request 
  of 
  Commissioner 
  Noble. 
  The 
  report 
  looks 
  at 
  “lessons 
  learned” 
  from 
  16 
  
regional 
  and 
  utility-­‐specific 
  distributed 
  solar 
  generation 
  cost/benefit 
  studies 
  summarized 
  by 
  Rocky 
  
Mountain 
  Institute 
  and 
  proposes 
  standardized 
  valuation 
  methodology 
  for 
  PUCs 
  to 
  consider 
  
implementing 
  in 
  future 
  studies. 
  Report: 
  http://www.irecusa.org/wp-­‐
content/uploads/2013/10/IREC_Rabago_Regulators-­‐Guidebook-­‐to-­‐Assessing-­‐Benefits-­‐and-­‐Costs-­‐of-­‐
DSG.pdf 
   
  
o October 
  10, 
  2013: 
  The 
  PUC 
  issued 
  an 
  informal 
  solicitation 
  for 
  a 
  consultant 
  to 
  work 
  with 
  regulatory 
  
staff 
  to 
  produce 
  a 
  study 
  of 
  the 
  costs 
  and 
  benefits 
  of 
  net 
  metering 
  in 
  Nevada. 
  
http://puc.nv.gov/uploadedFiles/pucnvgov/Content/Home/Documents/InformalSolicitationNetMet
eringStudy.pdf 
   
  
o October 
  17, 
  2013: 
  The 
  PUC 
  formed 
  a 
  stakeholder 
  committee, 
  whose 
  members' 
  names 
  were 
  due 
  on 
  
this 
  date. 
  Members 
  are 
  NV 
  Energy, 
  IREC, 
  PUC 
  Regulatory 
  Operations 
  Staff 
  and 
  Bureau 
  of 
  Consumer 
  
Protection. 
  
o November 
  5, 
  2013: 
  Proposals 
  due, 
  per 
  solicitation 
  above. 
  
o November 
  7, 
  2013: 
  Stakeholder 
  committee 
  meeting 
  to 
  discuss 
  consultant 
  proposals. 
  
o February 
  and 
  May 
  2014: 
  Stakeholder 
  committee 
  meetings. 
  Additional 
  meetings 
  may 
  be 
  scheduled 
  
as 
  necessary. 
  
o May 
  1, 
  2014: 
  Expected 
  completion 
  of 
  draft 
  study 
  by 
  E3 
  Consulting. 
  
o July 
  1, 
  2014: 
  Final 
  study 
  completed. 
  
o October 
  1, 
  2014: 
  The 
  PUC 
  will 
  submit 
  a 
  final 
  report 
  to 
  the 
  state 
  Legislature 
  by 
  Oct. 
  1, 
  2014. 
   
  
 
  
Sierra 
  Pacific 
  Power 
  general 
  rate 
  case, 
  Docket 
  No. 
  13-­‐06002, 
  et 
  al. 
  

 Timeline of Key State Activities on Net Energy Metering

36

 
  
o

o
o

December 
  16, 
  2013: 
  The 
  PUC 
  voted 
  to 
  approve 
  an 
  increase 
  in 
  the 
  basic 
  service 
  charge 
  paid 
  by 
  single-­‐
family 
  residential 
  customers 
  from 
  $9.25 
  to 
  $17.50 
  per 
  month 
  starting 
  Jan. 
  1, 
  2014, 
  to 
  end 
  cost-­‐of-­‐
service 
  subsidies 
  in 
  volumetric 
  rates. 
   
  
December 
  18, 
  2013: 
  Order 
  issued. 
  
January 
  3, 
  2014: 
  The 
  Attorney 
  General’s 
  Bureau 
  of 
  Consumer 
  Protection 
  filed 
  a 
  petition 
  for 
  
reconsideration. 
  The 
  BCP 
  asked 
  the 
  commission 
  to 
  lower 
  the 
  service 
  charge 
  to 
  the 
  BCP-­‐supported 
  
level 
  (no 
  increase), 
  or 
  minimum 
  amounts 
  supported 
  by 
  staff 
  ($13) 
  or 
  the 
  company 
  ($15). 
  The 
  BCP 
  is 
  
concerned 
  that 
  a 
  higher 
  charge 
  sends 
  an 
  inappropriate 
  price 
  signal 
  that 
  would 
  discourage 
  energy 
  
efficiency 
  and 
  conservation. 
  
 
  

NEW 
  HAMPSHIRE 
  
Legislation 
   
   
  
•

S.B. 
  98 
  (2013): 
  Authorizes 
  group 
  net 
  metering 
  for 
  businesses 
  and 
  municipalities. 
  
o July 
  24, 
  2013: 
  Enacted. 
   
  

Rates 
  and 
  Regulation 
  

•

Implementation 
  of 
  S.B. 
  98, 
  group 
  net 
  metering 
  (above) 
  (Docket 
  No. 
  DRM 
  13-­‐311)
o November 
  1, 
  2013: 
  PUC 
  open 
  meeting 
  to 
  discuss 
  initial 
  proposal. 
  The 
  PUC 
  released 
  notice 
  of 
  a 
  
proposed 
  interim 
  rule 
  for 
  public 
  review. 
  There 
  is 
  no 
  associated 
  comment 
  period 
  at 
  this 
  time. 
  The 
  
proposed 
  amendments 
  would 
  implement 
  group 
  net 
  metering 
  by 
  establishing 
  a 
  registration 
  process 
  
for 
  hosts, 
  minimum 
  requirements 
  for 
  agreements 
  among 
  hosts 
  and 
  their 
  members, 
  duties 
  of 
  the 
  
distribution 
  utility, 
  required 
  annual 
  reports, 
  sanctions, 
  and 
  forms. 
  
o December 
  19, 
  2013: 
  The 
  Joint 
  Legislative 
  Committee 
  on 
  Administrative 
  Rules 
  will 
  consider 
  the 
  
interim 
  rule 
  for 
  adoption. 
  
o January 
  9, 
  2014: 
  Notice 
  of 
  interim 
  rule 
  published; 
  effective 
  date 
  is 
  January 
  3, 
  2014.
o July 
  2, 
  2014: Interim 
  rule 
  expires. 
  The 
  PUC 
  will 
  work 
  on 
  finalizing 
  a 
  rule 
  in 
  2014.

Other 
  Initiatives 
  
•

 
  

Development 
  of 
  state 
  energy 
  strategy. 
  
o October 
  10, 
  2013: 
  The 
  NH 
  Office 
  of 
  Energy 
  and 
  Planning 
  held 
  an 
  organizational 
  meeting 
  to 
  discuss 
  
the 
  development 
  of 
  a 
  state 
  energy 
  strategy, 
  per 
  S.B. 
  191, 
  which 
  requires 
  preparation 
  of 
  a 
  10-­‐year 
  
energy 
  strategy. 
  The 
  strategy 
  must 
  include 
  a 
  section 
  on 
  small-­‐scale 
  and 
  distributed 
  energy 
  resources 
  
and 
  energy 
  storage 
  technologies 
  and 
  their 
  potential 
  in 
  the 
  state. 
  The 
  Office 
  is 
  working 
  in 
  
consultation 
  with 
  the 
  State 
  Energy 
  Advisory 
  Council, 
  as 
  required 
  by 
  S.B. 
  191. 
  
o November 
  5 
  & 
  December 
  17, 
  2013: 
  Advisory 
  Committee 
  meetings 
  held. 
  
o January 
  24, 
  February 
  21, 
  2014: 
  Advisory 
  Committee 
  meetings 
  held. 
  
o March 
  7 
  & 
  21, 
  2014: 
  Advisory 
  Committee 
  meetings 
  scheduled. 
  Agenda 
  for 
  March 
  7. 
  
o March 
  14, 
  2014: 
  Webinar 
  to 
  discuss 
  preliminary 
  Resource 
  Potential 
  Study. 
  
 
  

 Timeline of Key State Activities on Net Energy Metering

37

 
  

NEW 
  JERSEY 
  
Rates 
  and 
  Regulation 
  
•

•

Updates 
  to 
  renewable 
  energy 
  and 
  energy 
  efficiency 
  rules 
  are 
  being 
  discussed 
  generally 
  by 
  the 
  NJ 
  Board 
  
of 
  Public 
  Utilities 
  (BPU). 
  Staff 
  established 
  a 
  net 
  metering 
  and 
  interconnection 
  technical 
  working 
  group 
  to 
  
engage 
  stakeholders 
  and 
  support 
  the 
  ongoing 
  discussions. 
  The 
  working 
  group 
  met 
  several 
  times 
  in 
  2012 
  
and 
  earlier 
  in 
  2013. 
  
o November 
  1, 
  2013: 
  Working 
  group 
  meeting. 
  
o March 
  25, 
  2014: 
  Working 
  group 
  meeting. 
  
 
  
Generic 
  proceeding, 
  aggregated 
  net 
  metering, 
  Docket 
  No. 
  EO12090832V, 
  et 
  al. 
  
o March 
  20, 
  2013: 
  The 
  NJ 
  BPU 
  adopted 
  new 
  rules 
  to 
  codify 
  new 
  statutory 
  requirements 
  enacted 
  
through 
  the 
  Solar 
  Act 
  of 
  2012. 
  The 
  rules 
  allow 
  governmental 
  customers 
  to 
  aggregate 
  eligible 
  
facilities 
  for 
  the 
  purpose 
  of 
  sizing 
  the 
  system. 
  

Legislation 
  
•

•

S. 
  1295 
  (2012): 
  Solar 
  Act 
  of 
  2012 
  restructures 
  state 
  energy 
  policies 
  including 
  solar 
  program. 
  Amends 
  
guidelines 
  for 
  net 
  metering 
  of 
  small 
  scale 
  solar 
  facilities. 
  Caps 
  total 
  amount 
  of 
  new 
  projects 
  (80 
  MW 
  for 
  
projects 
  that 
  are 
  not 
  net 
  metered, 
  not 
  an 
  on-­‐site 
  generating 
  facility, 
  not 
  eligible 
  for 
  net 
  metering 
  
aggregation, 
  or 
  not 
  certified 
  for 
  certain 
  locations 
  such 
  as 
  brownfields). 
  Provides 
  for 
  certain 
  government 
  
entities 
  to 
  engage 
  in 
  virtual 
  aggregated 
  net 
  metering 
  for 
  multiple 
  facilities. 
  Raises 
  minimum 
  annual 
  solar 
  
targets 
  through 
  2017 
  but 
  lowers 
  targets 
  from 
  current 
  mandates 
  for 
  years 
  thereafter. 
  Reduces 
  cost 
  of 
  
solar 
  alternative 
  compliance 
  payments. 
  Extends 
  from 
  three 
  to 
  five 
  years 
  the 
  period 
  in 
  which 
  solar 
  and 
  
wind 
  RECs 
  can 
  be 
  used. 
  Exempts 
  existing 
  long-­‐term 
  power 
  supply 
  contracts 
  from 
  inclusion 
  in 
  utility 
  
generation 
  profiles 
  for 
  purposes 
  of 
  calculating 
  annual 
  solar 
  targets. 
  Provides 
  incentives 
  for 
  grid 
  supply 
  
projects 
  on 
  brownfields, 
  historic 
  fill 
  and 
  landfills. 
   
  
o July 
  23, 
  2012: 
  Enacted. 
  
 
  
A.B. 
  1384 
  (November 
  18, 
  2013 
  version): 
  Would 
  establish 
  alternative 
  energy 
  portfolio 
  standard 
  and 
  
related 
  certificate 
  program. 
  Incentivizes 
  development 
  of 
  CHP 
  facilities 
  using 
  fuel 
  cell 
  technology, 
  which 
  
would 
  be 
  considered 
  a 
  Class 
  1 
  renewable 
  technology 
  under 
  NEM. 
  Directs 
  the 
  BPU 
  to 
  provide 
  that 
  the 
  
energy 
  portfolio 
  standard 
  and 
  certificate 
  program 
  assist 
  in 
  the 
  creation 
  of 
  1500 
  MW 
  of 
  new 
  CHP 
  projects 
  
targeted 
  to 
  critical 
  institutional 
  assets 
  and 
  commercial 
  projects 
  that 
  meet 
  the 
  specific 
  requirements 
  set 
  
forth 
  in 
  a 
  net 
  positive 
  benefits 
  test 
  required 
  pursuant 
  to 
  the 
  bill. 
   
  Authorizes 
  the 
  BPU 
  to 
  regulate 
  standby 
  
charges 
  charged 
  by 
  electric 
  power 
  suppliers 
  and 
  basic 
  generation 
  service 
  providers. 
  (Companion 
  bill 
  – 
  
S.B. 
  2651) 
  
o February 
  7, 
  2013: 
  Hearing 
  held; 
  amended 
  and 
  passed 
  5-­‐1 
  Assembly 
  Telecommunications 
  and 
  
Utilities 
  Committee. 
  East 
  Clean 
  Energy 
  Center 
  testified 
  in 
  support 
  of 
  this 
  proposal 
  as 
  did 
  Mid 
  Atlantic 
  
Solar. 
  Several 
  utilities 
  expressed 
  concerns 
  with 
  the 
  proposal. 
  
o November 
  18, 
  2013: 
  Hearing 
  held; 
  amended 
  and 
  passed 
  Assembly 
  Appropriations 
  Committee. 
  
o December 
  19, 
  2013: 
  Amended 
  on 
  Assembly 
  floor. 
  Amendment 
  language 
  not 
  yet 
  available. 
  
o January 
  14, 
  2014: 
  Failed 
  upon 
  adjournment. 
  

 Timeline of Key State Activities on Net Energy Metering

38

 
  

NEW 
  MEXICO 
  
•

Generic 
  rulemaking 
  on 
  reasonable 
  cost 
  threshold 
  and 
  diversity 
  requirements 
  of 
  renewables 
  portfolio 
  
standard 
  (RPS), 
  Docket 
  No. 
  13-­‐00152-­‐UT 
  
o May 
  1, 
  2013: 
  The 
  NM 
  Public 
  Regulation 
  Commission 
  (PRC) 
  voted 
  to 
  end 
  a 
  case 
  in 
  which 
  it 
  was 
  
rehearing 
  a 
  December 
  2012 
  order 
  that 
  made 
  significant 
  changes 
  to 
  existing 
  RPS 
  requirements. 
  The 
  
commission 
  instead 
  agreed 
  to 
  open 
  a 
  new 
  rulemaking 
  to 
  consider 
  eliminating 
  its 
  “diversity 
  
requirement” 
  and 
  making 
  other 
  changes, 
  including 
  the 
  calculation 
  of 
  avoided 
  cost 
  in 
  determining 
  
the 
  RPS 
  “reasonable 
  cost 
  threshold.” 
  The 
  reasonable 
  cost 
  threshold 
  rule 
  excuses 
  utilities 
  from 
  RPS 
  
compliance 
  if 
  adding 
  renewables 
  to 
  their 
  supply 
  portfolios 
  exceeds 
  3% 
  of 
  total 
  revenues. 
  The 
  related 
  
diversity 
  rule 
  provides 
  for 
  a 
  certain 
  percentage 
  of 
  solar, 
  geothermal 
  and 
  DG 
  in 
  each 
  utility’s 
  
renewable 
  supply 
  mix. 
  The 
  diversity 
  requirements 
  are 
  now 
  set 
  at: 
  minimum 
  30% 
  for 
  wind, 
  20% 
  
solar, 
  5% 
  other 
  technologies, 
  1.5% 
  DG 
  (2011-­‐2014) 
  and 
  3% 
  DG 
  by 
  2015. 
  Solar 
  advocates 
  have 
  said 
  
that 
  elimination 
  of 
  the 
  diversity 
  rule 
  would 
  decimate 
  small 
  solar 
  in 
  the 
  state. 
  New 
  Mexico 
  is 
  one 
  of 
  
the 
  few 
  states 
  whose 
  net 
  metering 
  program 
  provides 
  for 
  compensation 
  to 
  net 
  metered 
  customers 
  
at 
  avoided 
  cost, 
  rather 
  than 
  at 
  the 
  retail 
  rate. 
  
o July 
  26, 
  2013: 
  Comments 
  due. 
  
o August 
  26, 
  2013: 
  Reply 
  comments 
  due. 
   
  
o September 
  10, 
  2013: 
  Public 
  comment 
  hearing. 
  The 
  hearing 
  attracted 
  a 
  large 
  turnout 
  of 
  solar 
  
interests, 
  which 
  opposed 
  the 
  proposed 
  rule 
  changes. 
  
o October 
  10, 
  2013: 
  Record 
  closed. 
  
o November 
  20, 
  2013: 
  Open 
  meeting. 
  The 
  PRC 
  voted 
  to 
  keep 
  diversity 
  but 
  to 
  change 
  the 
  value 
  of 
  
RECs, 
  which 
  means 
  utilities 
  will 
  be 
  required 
  to 
  procure 
  less 
  renewable 
  energy 
  to 
  comply 
  with 
  the 
  
RPS. 
  For 
  example, 
  solar 
  RECs, 
  which 
  previously 
  had 
  a 
  value 
  of 
  1 
  REC 
  = 
  1 
  kWh, 
  now 
  have 
  a 
  value 
  of 
  2 
  
RECs 
  = 
  1 
  kWh. 
  The 
  commission 
  also 
  changed 
  the 
  calculation 
  for 
  the 
  reasonable 
  cost 
  threshold 
  to 
  
include 
  all 
  costs 
  and 
  benefits 
  versus 
  the 
  previous 
  requirement 
  to 
  count 
  only 
  avoided 
  fuel 
  and 
  
purchased 
  power 
  costs 
  and 
  other 
  costs 
  that 
  could 
  be 
  shown 
  to 
  impact 
  the 
  utility's 
  expenses 
  in 
  the 
  
current 
  year. 
  The 
  decision 
  is 
  expected 
  to 
  be 
  challenged 
  by 
  solar 
  and 
  other 
  renewables 
  advocates. 
  
o December 
  18, 
  2013: 
  The 
  PRC 
  reversed 
  its 
  November 
  20, 
  2013, 
  decision 
  to 
  instate 
  a 
  two-­‐to-­‐one 
  value 
  
for 
  solar 
  RECs 
  (2 
  RECs 
  = 
  1 
  kWh 
  solar) 
  and 
  reinstated 
  the 
  previous 
  one-­‐to-­‐one 
  status 
  of 
  REC 
  credits. 
  
Solar 
  and 
  environmental 
  interests 
  had 
  protested 
  and 
  threatened 
  court 
  action. 
  
o January 
  8, 
  2014: 
  The 
  PRC 
  agreed 
  to 
  rehear 
  the 
  decision 
  again. 
  
o February 
  4, 
  2014: 
  Additional 
  motions 
  for 
  rehearing 
  due. 
  

NEW 
  YORK 
  
Legislation 
  
•

A.B. 
  3143: 
  Would 
  raise 
  net 
  metering 
  cap 
  to 
  5% 
  of 
  a 
  utility’s 
  electric 
  demand 
  in 
  2005 
  for 
  solar 
  and 
  2% 
  of 
  a 
  
utility’s 
  2005 
  demand 
  for 
  wind. 
  (Companion 
  Bill 
  – 
  S.B. 
  2498) 
  
o January 
  23, 
  2013: 
  Introduced 
  and 
  referred 
  to 
  Assembly 
  Energy 
  Committee. 
  
o April 
  22, 
  2013: 
  Meeting 
  held, 
  passed 
  committee 
  and 
  referred 
  to 
  Ways 
  and 
  Means. 
  
o January 
  8, 
  2014: 
  Re-­‐referred 
  to 
  Assembly 
  Energy 
  Committee. 
  
o February 
  26, 
  2014: 
  Hearing 
  held; 
  passed 
  14-­‐2. 
  During 
  the 
  hearing 
  Ranking 
  Member 
  Palmesano 
  (R) 
  
stated 
  that 
  net 
  metering 
  causes 
  rates 
  to 
  go 
  up 
  for 
  communities 
  and 
  that 
  energy 
  in 
  the 
  state 
  already 
  

 Timeline of Key State Activities on Net Energy Metering

39

 
  

•

•

•

•

•

•

•

•

costs 
  more 
  than 
  in 
  most 
  states. 
  Chairwoman 
  Paulin 
  (D) 
  stated 
  that 
  net 
  metering 
  is 
  intended 
  to 
  drive 
  
renewables. 
  The 
  measure 
  will 
  next 
  be 
  considered 
  in 
  the 
  Assembly 
  Ways 
  and 
  Means 
  Committee, 
   
  
where 
  it 
  never 
  received 
  a 
  hearing 
  in 
  2013. 
  
 
  
A.B. 
  8238: 
  Would 
  establish 
  a 
  shared 
  renewable 
  energy 
  program 
  that 
  increases 
  access 
  to 
  and 
  accelerates 
  
development 
  of 
  renewable 
  energy, 
  by 
  enabling 
  electric 
  customers 
  to 
  subscribe 
  to 
  a 
  shared 
  renewable 
  
energy 
  facility 
  and 
  receive 
  associated 
  benefits 
  through 
  their 
  utility 
  bill. 
  (Companion 
  bill 
  – 
  S.B. 
  5280) 
  
o November 
  6, 
  2013: 
  Introduced 
  and 
  referred 
  to 
  Assembly 
  Energy 
  Committee. 
   
  The 
  Legislature 
  
recessed 
  June 
  22. 
  Either 
  chamber 
  may 
  return 
  at 
  the 
  call 
  of 
  the 
  leadership 
  or 
  the 
  governor 
  at 
  any 
  
time 
  prior 
  to 
  the 
  convening 
  of 
  the 
  2014 
  legislative 
  session 
  January 
  8. 
  All 
  legislation 
  carries 
  over 
  to 
  
the 
  2014 
  session. 
  
 
  
A.B. 
  8307: 
  Would 
  require 
  the 
  NY 
  PSC 
  to 
  establish 
  a 
  new 
  community 
  solar 
  pilot 
  program. 
  
o December 
  6, 
  2013: 
  Introduced 
  and 
  referred 
  to 
  Assembly 
  Committee 
  on 
  Energy. 
   
  
 
  
A.B. 
  8798: 
  Would 
  make 
  non-­‐residential 
  customers 
  owning 
  or 
  operating 
  farm 
  waste 
  electric 
  generating 
  
equipment 
  on 
  premises 
  eligible 
  to 
  receive 
  NEM 
  credits. 
  
o February 
  14, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Assembly 
  Committee 
  on 
  Energy. 
   
  
o February 
  26, 
  2014: 
  Hearing 
  scheduled. 
  
 
  
S.B. 
  1111 
  (2013): 
  Adds 
  installation 
  of 
  net 
  metering 
  generating 
  systems 
  to 
  the 
  measures 
  eligible 
  for 
  
financing 
  through 
  the 
  "Green 
  Jobs/Green 
  New 
  York" 
  Program. 
   
  (Companion 
  Bill 
  – 
  AB 
  1245) 
  
o October 
  22, 
  2013: 
  Enacted. 
  
 
  
S.B. 
  2383: 
  Would 
  include 
  micro-­‐combined 
  heat 
  and 
  power 
  and 
  fuel 
  cell 
  customer-­‐generators 
  in 
  total 
  
rate 
  reimbursement 
  from 
  electric 
  corporations. 
  (Companion 
  Bill 
  – 
  AB 
  6367) 
  
o February 
  4, 
  2013: 
  Meeting 
  held 
  and 
  passed 
  Senate 
  Energy 
  and 
  Telecommunications 
  committee. 
  
o June 
  21, 
  2013: 
  Referred 
  to 
  Rules 
  Committee. 
  Bill 
  will 
  carry 
  over 
  to 
  2014 
  session. 
  
 
   
  
S.B. 
  2498: 
  Would 
  raise 
  net 
  metering 
  cap 
  to 
  5% 
  of 
  a 
  utility’s 
  electric 
  demand 
  in 
  2005 
  for 
  solar 
  and 
  2% 
  of 
  a 
  
utility’s 
  2005 
  demand 
  for 
  wind. 
  (Companion 
  Bill 
  – 
  A.B. 
  3143) 
  
o February 
  4, 
  2013: 
  Meeting 
  held 
  and 
  passed 
  Senate 
  Energy 
  and 
  Telecommunications 
  Committee. 
  
o June 
  21, 
  2013: 
  Referred 
  to 
  Rules 
  Committee. 
  Bill 
  will 
  carry 
  over 
  to 
  2014 
  session. 
  
 
  
S.B. 
  5150: 
  Would 
  facilitate 
  development 
  of 
  large 
  scale 
  PV 
  installations 
  through 
  net 
  metering 
  in 
  cities 
  of 
  1 
  
million 
  or 
  more. 
  It 
  does 
  so 
  by 
  allowing 
  solar 
  PV 
  systems 
  with 
  a 
  generating 
  capacity 
  of 
  at 
  least 
  1,000 
  kW 
  
to 
  account 
  for 
  a 
  maximum 
  of 
  40 
  MW 
  of 
  net 
  metering. 
  (Companion 
  Bill 
  – 
  AB 
  7311B) 
  
o June 
  22, 
  2013: 
  Passed 
  Senate 
  on 
  63-­‐0 
  vote 
  and 
  transmitted 
  to 
  Assembly. 
   
  
o June 
  24, 
  2013: 
  Referred 
  to 
  Assembly 
  Energy 
  Committee. 
  Bill 
  will 
  carry 
  over 
  to 
  2014 
  session. 
  
 
  
S.B. 
  5988: 
  Would 
  legislatively 
  set 
  a 
  state 
  RPS 
  with 
  targets 
  of 
  30% 
  for 
  2015 
  through 
  2019, 
  and 
  40%, 
  with 
  
at 
  least 
  2% 
  derived 
  from 
  solar, 
  for 
  2020. 
  The 
  current 
  state 
  RPS 
  was 
  set 
  administratively 
  by 
  the 
  PSC 
  with 
  
a 
  target 
  of 
  30% 
  by 
  2015, 
  subject 
  to 
  certain 
  requirements. 
  The 
  bill 
  provides 
  that 
  net 
  metering-­‐eligible 
  
customer-­‐generators 
  own 
  environmental 
  attributes 
  as 
  of 
  April 
  1, 
  2020. 
  

 Timeline of Key State Activities on Net Energy Metering

40

 
  
o

November 
  20, 
  2013: 
  Filed 
  and 
  referred 
  to 
  Rules 
  Committee. 
  

Rates 
  and 
  Regulation 
  
•

•

•

Three 
  inter-­‐related 
  proposals 
  affecting 
  NY-­‐Sun 
  program, 
  Docket 
  No. 
  13-­‐M-­‐0412, 
  et 
  al. 
  Cost 
  shifting 
  
resulting 
  from 
  net 
  metering 
  has 
  been 
  raised 
  as 
  an 
  issue 
  in 
  the 
  proceeding. 
  
o September 
  13, 
  2013: 
  The 
  NY 
  Public 
  Service 
  Commission 
  (PSC) 
  issued 
  a 
  notice 
  seeking 
  comments 
  and 
  
setting 
  a 
  technical 
  conference 
  on 
  proposals 
  affecting 
  the 
  NY 
  Sun 
  initiative, 
  including 
  the 
  RPS 
  
program. 
  The 
  proposals 
  include 
  one 
  by 
  the 
  NY 
  State 
  Energy 
  Research 
  and 
  Development 
  Authority 
  
(NYSERDA) 
  that 
  seeks, 
  among 
  other 
  things, 
  the 
  ability 
  to 
  lower 
  the 
  existing 
  standard 
  offer 
  PV 
  
incentive 
  level 
  on 
  a 
  regional 
  basis 
  in 
  response 
  to 
  achieving 
  a 
  designated 
  threshold 
  of 
  MW 
  under 
  
contract 
  (MW 
  Block 
  Program), 
  and 
  the 
  ability 
  to 
  transition 
  the 
  Competitive 
  PV 
  program 
  to 
  a 
  MW 
  
Block 
  performance-­‐based 
  incentive 
  program. 
  
o October 
  15, 
  2013: 
  Technical 
  conference. 
  Agenda 
  includes 
  NY 
  Sun 
  petition 
  review, 
  RPS 
  review, 
  and 
  
opportunity 
  for 
  Q&A 
  on 
  both. 
  
o October 
  28, 
  2013: 
  Initial 
  comments 
  due. 
  
o November 
  12, 
  2013: 
  Reply 
  comments 
  due. 
  
o December 
  19, 
  2013: 
  The 
  PSC 
  issued 
  two 
  orders 
  in 
  dockets 
  in 
  this 
  consolidated 
  proceeding. 
  One 
  
order 
  (Docket 
  No. 
  03-­‐E-­‐0188 
  authorizes 
  NYSERDA 
  to 
  reallocate 
  certain 
  funds 
  to 
  the 
  solar 
  PV 
  
programs 
  in 
  the 
  customer-­‐sited 
  tier 
  of 
  the 
  RPS 
  and 
  to 
  make 
  program 
  revisions 
  in 
  response 
  to 
  
changing 
  markets, 
  with 
  the 
  goal 
  of 
  reducing 
  and 
  ultimately 
  eliminating 
  RPS 
  incentives 
  for 
  PV 
  
programs. 
  The 
  other 
  order 
  approves 
  establishment 
  of 
  a 
  Green 
  Bank 
  and 
  initial 
  capitalization 
  (Docket 
  
No. 
  13-­‐M-­‐0412). 
  The 
  orders 
  did 
  not 
  address 
  net 
  metering. 
  
December 
  26, 
  2013: 
  The 
  PSC 
  issued 
  an 
  order 
  approving 
  changes 
  to 
  the 
  state 
  energy 
  efficiency 
  portfolio 
  
standard 
  (Docket 
  No. 
  07-­‐M-­‐0548). 
  The 
  order 
  did 
  not 
  address 
  net 
  metering. 
  
 
  
Consolidated 
  Edison, 
  et 
  al., 
  Docket 
  No. 
  12-­‐E-­‐0485, 
  et 
  al. 
  
o June 
  13, 
  2013: 
  The 
  NY 
  PSC 
  approved 
  raising 
  net 
  metering 
  caps 
  in 
  accord 
  with 
  Gov. 
  Cuomo’s 
  NY-­‐Sun 
  
initiative, 
  announced 
  in 
  2012, 
  to 
  quadruple 
  installed 
  solar 
  capacity 
  in 
  2013 
  from 
  the 
  2011 
  level. 
  NY 
  
PSC 
  increased 
  each 
  utility’s 
  system-­‐wide 
  net 
  metering 
  cap 
  from 
  1% 
  to 
  3% 
  of 
  system 
  peak 
  load. 
  

Other 
  Initiatives 
  
•

New 
  York 
  State 
  Draft 
  Energy 
  Plan, 
  2014 
  Draft, 
  prepared 
  by 
  New 
  York 
  State 
  Energy 
  Planning 
  Board, 
  
released 
  February 
  2014. 
  Initiative 
  5 
  of 
  the 
  plan 
  seeks 
  to 
  coordinate 
  renewable 
  energy 
  policies 
  to 
  
strategically 
  harness 
  resources 
  in 
  the 
  state. 
  States 
  that 
  NY 
  DPS 
  and 
  NYSERDA 
  and 
  other 
  agencies 
  work 
  to 
  
create 
  a 
  portfolio 
  of 
  renewable 
  energy 
  programs 
  with 
  a 
  state 
  commitment 
  through 
  2025 
  to 
  help 
  achieve 
  
scale 
  and 
  drive 
  down 
  the 
  cost 
  of 
  implementation. 
  The 
  state’s 
  approach 
  to 
  renewable 
  energy 
  would 
  
operate 
  in 
  accordance 
  with 
  the 
  following 
  guiding 
  principles: 
  1) 
  provide 
  greater 
  incentive-­‐level 
  
predictability 
  and 
  increased 
  project 
  revenue 
  certainty 
  through 
  the 
  state’s 
  various 
  renewable 
  energy 
  
programs 
  and 
  policies, 
  2) 
  dedicate 
  state 
  resources 
  to 
  reducing 
  development 
  costs 
  such 
  as 
  permitting, 
  
licensing, 
  stand-­‐by 
  charges, 
  regulatory 
  compliance, 
  and 
  customer 
  acquisition 
  expenses, 
  3) 
  conduct 
  
predevelopment 
  work 
  to 
  accelerate 
  and 
  aggregate 
  economic 
  opportunities 
  for 
  emerging 
  technologies 
  
and 
  nascent 
  markets, 
  4) 
  coordinate 
  with 
  other 
  states 
  to 
  increase 
  the 
  scale 
  of 
  clean 
  energy 
  projects, 
  5) 
  
develop 
  renewable 
  resources 
  that 
  support 
  community-­‐based 
  energy 
  needs, 
  6) 
  establish 
  incentives 
  that 
  

 Timeline of Key State Activities on Net Energy Metering

41

 
  
reward 
  installation 
  of 
  new 
  renewable 
  power 
  sources 
  where 
  they 
  can 
  increase 
  system 
  efficiency, 
  
improve 
  portfolio 
  diversity 
  and 
  contribute 
  to 
  the 
  state’s 
  environmental 
  goals. 
  Materials 
  are 
  located: 
  
http://energyplan.ny.gov/Plans/2014.aspx 
   
  
o February 
  18, 
  19, 
  20 
  & 
  25, 
  2014: 
  Public 
  hearings 
  held. 
  
o March 
  31, 
  2014: 
  Comments 
  due. 
  
o March 
  3 
  & 
  6, 
  2014: 
  Upcoming 
  public 
  hearings. 
  

NORTH 
  CAROLINA 
   
  
Rates 
  and 
  Regulation 
  
•

•

•

Generic 
  NEM 
  changes; 
  potential 
  Duke 
  Energy 
  proceeding 
  on 
  NEM, 
  Docket 
  No. 
  E-­‐100, 
  Sub 
  83. 
  This 
  is 
  a 
  
longstanding 
  North 
  Carolina 
  Utilities 
  Commission 
  (UC) 
  open 
  docket 
  on 
  NEM 
  rules. 
  It 
  is 
  not 
  certain 
  
whether 
  a 
  Duke 
  proceeding 
  would 
  be 
  carried 
  on 
  in 
  this 
  docket. 
  However, 
  filings 
  are 
  being 
  made 
  here 
  in 
  
anticipation 
  of 
  a 
  Duke 
  request 
  to 
  address 
  NEM 
  cost 
  shifting. 
  
o February 
  24, 
  2014: 
  The 
  NC 
  Sustainable 
  Energy 
  Association 
  (NCSEA) 
  filed 
  a 
  motion 
  for 
  the 
  NC 
  Utilities 
  
Commission 
  (UC) 
  to 
  take 
  two 
  steps 
  in 
  anticipation 
  of 
  a 
  Duke 
  filing: 
  1) 
  direct 
  Duke 
  to 
  guarantee 
  the 
  
availability 
  of 
  NEM 
  terms 
  and 
  conditions 
  for 
  10 
  years 
  from 
  the 
  date 
  of 
  a 
  residential/commercial 
  
customer 
  installation 
  of 
  a 
  net 
  metered 
  facility 
  prior 
  to 
  a 
  commission 
  ruling 
  in 
  any 
  NEM 
  proceeding, 
  
and 
  2) 
  direct 
  Duke 
  to 
  release 
  the 
  analysis 
  underlying 
  recent 
  messaging 
  on 
  NEM 
  cost 
  shifting. 
  
o March 
  3, 
  2014: 
  The 
  NC 
  UC 
  issued 
  an 
  order 
  requesting 
  comments 
  on 
  the 
  NCSEA 
  motion. 
  
o March 
  17, 
  2014: 
  Duke 
  filed 
  response, 
  saying 
  motion 
  is 
  premature 
  because 
  there 
  is 
  no 
  pending 
  
proceeding 
  and 
  underlying 
  studies 
  are 
  not 
  yet 
  complete. 
  Duke 
  said 
  it 
  has 
  already 
  committed 
  to 
  
releasing 
  the 
  studies 
  once 
  complete. 
  
o March 
  21, 
  2014: 
  Comments 
  due. 
  
o April 
  4, 
  2014: 
  Reply 
  comments 
  due. 
  
 
  
Duke 
  Energy 
  Green 
  Source 
  Rider, 
  Docket 
  No. 
  E-­‐7, 
  Sub 
  1043 
  
o November 
  15, 
  2013: 
  Duke 
  filed 
  with 
  the 
  NC 
  Utilities 
  Commission 
  (UC) 
  for 
  approval 
  of 
  a 
  three-­‐year 
  
experimental 
  program 
  under 
  which 
  nonresidential, 
  energy-­‐intensive 
  customers 
  could 
  choose 
  to 
  
offset 
  some 
  or 
  all 
  of 
  their 
  new 
  load 
  with 
  renewable 
  energy, 
  either 
  owned 
  by 
  Duke 
  or 
  procured 
  via 
  
PPAs 
  from 
  third 
  parties. 
  The 
  costs 
  of 
  the 
  program 
  would 
  not 
  be 
  borne 
  by 
  nonparticipating 
  
customers. 
  Renewable 
  energy 
  supplied 
  through 
  the 
  program 
  would 
  be 
  in 
  addition 
  to 
  that 
  needed 
  to 
  
meet 
  existing 
  obligations 
  under 
  the 
  state 
  RPS. 
  
 
  
2012 
  biennial 
  proceeding 
  on 
  avoided 
  cost 
  under 
  PURPA, 
  Docket 
  No. 
  E-­‐100, 
  Sub 
  136. 
  Utilities 
  are 
  
seeking 
  to 
  lower 
  avoided 
  costs, 
  in 
  part 
  due 
  to 
  lower 
  natural 
  gas 
  prices. 
  The 
  value 
  of 
  solar 
  is 
  at 
  issue 
  in 
  
this 
  proceeding. 
   
  
o September 
  27, 
  2013: 
  NC 
  Sustainable 
  Energy 
  Association 
  (NCSEA) 
  submitted 
  testimony 
  by 
  Karl 
  R. 
  
Rabago 
  and 
  accompanying 
  report 
  prepared 
  for 
  NCSEA 
  by 
  Crossborder 
  Energy, 
  “The 
  Benefits 
  and 
  
Costs 
  of 
  Solar 
  Generation 
  for 
  Electric 
  Ratepayers 
  in 
  North 
  Carolina.” 
  The 
  study 
  concludes 
  that 
  the 
  
benefits 
  of 
  solar 
  outweigh 
  the 
  costs. 
  Rabago 
  said 
  that 
  traditional 
  avoided 
  cost 
  calculations 
  do 
  not 
  
adequately 
  capture 
  avoided 
  costs 
  associated 
  with 
  solar 
  generation. 
  He 
  asked 
  the 
  commission 
  to 
  

 Timeline of Key State Activities on Net Energy Metering

42

 
  

o
o

o

implement 
  short-­‐ 
  and 
  long-­‐term 
  approaches 
  to 
  ensure 
  that 
  “full” 
  avoided 
  cost 
  rates 
  are 
  offered 
  to 
  
qualifying 
  solar 
  generators. 
  
October 
  25, 
  2013: 
  Dominion 
  NC 
  and 
  Duke 
  Energy 
  Progress 
  jointly 
  moved 
  to 
  strike 
  NCSEA 
  
correspondence 
  and 
  the 
  report, 
  citing 
  noncompliance 
  with 
  commission 
  rules 
  and 
  procedures. 
  
October 
  29, 
  2013: 
  Evidentiary 
  hearing. 
  Staff 
  raised 
  various 
  concerns 
  with 
  methodology, 
  
assumptions, 
  and 
  other 
  aspects 
  of 
  the 
  utility 
  filings. 
  Dominion 
  and 
  Duke 
  each 
  filed 
  a 
  settlement 
  with 
  
staff. 
   
  
December 
  20, 
  2013: 
  Briefs 
  and 
  proposed 
  orders 
  due. 
  

Legislation 
  
•

•

H.B. 
  298: 
  Would 
  repeal 
  requirements 
  of 
  state 
  RES. 
   
  
o April 
  24, 
  2013: 
  Defeated 
  in 
  House 
  Committee 
  on 
  Public 
  Utilities 
  and 
  Energy 
  on 
  18-­‐13 
  vote. 
  
Stakeholders 
  are 
  expected 
  to 
  continue 
  discussions 
  in 
  2014 
  focusing 
  on 
  ways 
  to 
  resolve 
  issues 
  
related 
  to 
  updating 
  of 
  the 
  RES, 
  which 
  has 
  been 
  in 
  place 
  since 
  2007 
  and 
  requires 
  investor-­‐owned 
  
utilities 
  to 
  meet 
  a 
  target 
  of 
  12.5% 
  renewables 
  by 
  2021. 
  
 
  
Legislative 
  debate 
  is 
  expected 
  in 
  2014 
  on 
  third-­‐party 
  solar 
  financing. 
   
  

NORTH 
  DAKOTA 
  
•

S.B. 
  2291: 
  Would 
  provide 
  compensation 
  to 
  net 
  metered 
  customers 
  at 
  retail 
  rates 
  (vs. 
  existing 
  avoided 
  
cost 
  rate). 
   
  
• February 
  28, 
  2013: 
  On 
  second 
  reading 
  in 
  Senate, 
  failed 
  to 
  pass 
  44-­‐3. 
  

OHIO 
  
Rates 
  and 
  Regulation 
  
•

•

Generic 
  proceeding 
  on 
  aligning 
  distribution 
  rates 
  with 
  state 
  policies 
  on 
  competition, 
  energy 
  efficiency 
  
and 
  DG, 
  including 
  straight 
  fixed 
  variable 
  rate 
  (SFV), 
  Docket 
  No. 
  10-­‐3126-­‐EL-­‐UNC 
  
o August 
  21, 
  2013: 
  The 
  Public 
  Utilities 
  Commission 
  (PUC) 
  of 
  Ohio 
  issued 
  an 
  order 
  finding 
  that 
  the 
  rate 
  
structure 
  that 
  may 
  best 
  accomplish 
  Ohio’s 
  policy 
  goals 
  on 
  competition, 
  energy 
  efficiency 
  and 
  DG 
  is 
  
the 
  SFV 
  rate 
  design 
  and 
  encouraging 
  utilities 
  to 
  utilize 
  an 
  SFV 
  rate 
  design 
  in 
  their 
  next 
  rate 
  case 
  
filings. 
  If 
  utilities 
  do 
  not 
  propose 
  an 
  SFV 
  rate 
  design, 
  staff 
  is 
  directed 
  to 
  do 
  so. 
  There 
  are 
  no 
  electric 
  
general 
  rate 
  cases 
  pending 
  in 
  Ohio. 
   
  
o December 
  4, 
  2013: 
  PUC 
  denied 
  rehearing. 
  
 
  
Five-­‐year 
  review 
  of 
  electric 
  utility 
  rules 
  including 
  net 
  metering, 
  Docket 
  No. 
  12-­‐2050-­‐EL-­‐ORD 
  
o November 
  7, 
  2012: 
  The 
  PUC 
  recommended 
  changes 
  to 
  net 
  metering 
  rules, 
  including 
  consideration 
  
of 
  virtual 
  net 
  metering 
  and 
  aggregation, 
  and 
  sought 
  comment. 
   
  
o January 
  7, 
  2013: 
  Comments 
  due. 
  (Reply 
  comments 
  due 
  February 
  6, 
  2013.) 
  
o August 
  6, 
  2013: 
  Supplemental 
  comments 
  due. 
  
o August 
  16, 
  2013: 
  Reply 
  comments 
  due. 
  

 Timeline of Key State Activities on Net Energy Metering

43

 
  
o
o

January 
  15, 
  2014: 
  Open 
  meeting. 
  The 
  PUC 
  issued 
  a 
  Finding 
  and 
  Order 
  adopting 
  the 
  draft 
  
amendments 
  and 
  filed 
  with 
  the 
  Joint 
  Committee 
  on 
  Agency 
  Rule 
  Review 
  (JCARR) 
  for 
  review. 
   
  
February 
  14, 
  2014: 
  Requests 
  for 
  rehearing 
  due. 
   
  

Legislation 
  
•

•

S.B. 
  58: 
  Would 
  amend 
  the 
  law 
  setting 
  energy 
  efficiency 
  (EE) 
  and 
  renewable 
  standards. 
  Under 
  the 
  
existing 
  renewable 
  energy 
  standard 
  (RES), 
  at 
  least 
  12.5 
  percent 
  of 
  electricity 
  sold 
  by 
  each 
  electric 
  
provider 
  must 
  be 
  from 
  renewable 
  sources, 
  with 
  at 
  least 
  half 
  produced 
  in 
  state 
  and 
  at 
  least 
  0.5 
  percent 
  
from 
  solar. 
  The 
  bill 
  would 
  retain 
  the 
  overall 
  target 
  but 
  eliminate 
  the 
  in-­‐state 
  requirement 
  and 
  count 
  
Canadian 
  hydropower 
  as 
  eligible, 
  which 
  would 
  have 
  implications 
  for 
  the 
  amount 
  of 
  and 
  location 
  of 
  solar 
  
procured 
  for 
  compliance. 
  (Companion 
  Bill 
  – 
  H.B. 
  302, 
  below) 
  
o February 
  27, 
  2013: 
  Introduced. 
  
o March 
  5, 
  2013: 
  Referred 
  to 
  Senate 
  Committee 
  on 
  Public 
  Utilities. 
  
o September 
  9, 
  October 
  2, 
  October 
  9, 
  October 
  22, 
  2013: 
  Hearings 
  held. 
  
o November 
  6 
  & 
  13, 
  2013: 
  Hearing 
  held. 
   
  
o November 
  20, 
  2013: 
  Hearing 
  scheduled 
  but 
  canceled. 
  
o December 
  4, 
  2013: 
  Vote 
  scheduled 
  but 
  canceled. 
  This 
  ends 
  the 
  possibility 
  of 
  action 
  this 
  year, 
  but 
  the 
  
bill 
  sponsor 
  plans 
  to 
  continue 
  work 
  on 
  the 
  bill 
  in 
  2014. 
  
 
  
H.B. 
  302: 
  (Companion 
  bill 
  – 
  S.B. 
  58, 
  above). 
  
o October 
  16, 
  2013: 
  Introduced, 
  referred 
  to 
  House 
  Committee 
  on 
  Public 
  Utilities. 
  
o October 
  22 
  & 
  30, 
  November 
  13, 
  2013: 
  Hearings 
  held. 
  
o November 
  20 
  and 
  December 
  4 
  & 
  11, 
  2013: 
  Hearings 
  held. 
  
o The 
  committee 
  adjourned 
  without 
  a 
  vote 
  and 
  the 
  measure 
  will 
  be 
  carried 
  over 
  to 
  2014. 
  Committee 
  
Chairman 
  Rep. 
  Stautberg 
  (R) 
  said 
  he 
  believes 
  policymakers 
  still 
  "need 
  to 
  do 
  something 
  in 
  this 
  area” 
  
and 
  that 
  he 
  is 
  also 
  considering 
  other 
  options. 
  Sen. 
  Seitz 
  (R), 
  one 
  of 
  the 
  prime 
  supporters 
  of 
  the 
  
legislation, 
  believes 
  that 
  more 
  time 
  is 
  needed 
  for 
  members 
  to 
  review 
  the 
  issues. 
  He 
  also 
  laid 
  out 
  
plans 
  to 
  start 
  hearings 
  on 
  a 
  bill 
  that 
  would 
  eliminate 
  renewable 
  and 
  energy 
  efficiency 
  mandates 
  
outright 
  (S.B. 
  34). 
  Senator 
  Seitz 
  co-­‐sponsored 
  S.B. 
  216 
  (2012) 
  an 
  unsuccessful 
  attempt 
  to 
  completely 
  
repeal 
  the 
  requirement 
  that 
  electric 
  distribution 
  utilities 
  and 
  electric 
  services 
  companies 
  provide 
  
25% 
  of 
  their 
  retail 
  power 
  supplies 
  from 
  advanced 
  and 
  renewable 
  energy 
  resources 
  by 
  2025. 
   
  

OKLAHOMA 
  
Legislation 
  
•

•

H.B. 
  2268: 
  Would 
  change 
  the 
  current 
  renewable 
  energy 
  goal 
  from 
  15% 
  by 
  2015 
  to 
  20% 
  by 
  2020. 
  
o January 
  31, 
  2014: 
  Referred 
  to 
  House 
  Energy 
  and 
  Aerospace 
  Committee. 
  Carried 
  over 
  from 
  2013. 
  
 
  
H.B. 
  2605: 
  Directs 
  the 
  OK 
  Corporation 
  Commission 
  to 
  set 
  an 
  RPS. 
  
o January 
  17, 
  2014: 
  Prefiled. 
  
o January 
  31, 
  2014: 
  Referred 
  to 
  House 
  Energy 
  and 
  Aerospace 
  Committee. 
  
 
  

 Timeline of Key State Activities on Net Energy Metering

44

 
  
•

S.B. 
  1456 
  (February 
  20 
  version): 
   
  States 
  that 
  no 
  retail 
  electric 
  supplier 
  shall 
  increase 
  rates 
  charged 
  or 
  
enforce 
  a 
  surcharge 
  above 
  that 
  required 
  to 
  recover 
  the 
  full 
  costs 
  necessary 
  to 
  serve 
  a 
  customer 
  who 
  
installs 
  DG 
  on 
  the 
  customer's 
  side 
  of 
  the 
  meter 
  after 
  the 
  effective 
  date 
  of 
  this 
  act. 
  States 
  that 
  no 
  retail 
  
electric 
  supplier 
  shall 
  allow 
  a 
  customer 
  with 
  DG 
  to 
  be 
  subsidized 
  by 
  customers 
  in 
  the 
  same 
  class 
  of 
  
service 
  who 
  do 
  not 
  have 
  distributed 
  generation. 
  
o January 
  16, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  Energy 
  Committee. 
  
o February 
  20, 
  2014: 
  Hearing 
  held. 
  Amended 
  and 
  passed. 
  Amended 
  text 
  establishes 
  definition 
  for 
  DG 
  
and 
  states 
  utility 
  responsibilities 
  for 
  customers 
  with 
  DG. 
  

OREGON 
  
Legislation 
  
 
  
• January 
  17, 
  2014: 
  The 
  House 
  Interim 
  Committee 
  on 
  Energy 
  and 
  Environment 
  will 
  host 
  an 
  informational 
  
public 
  hearing 
  to 
  discuss 
  various 
  legislative 
  concepts 
  as 
  well 
  as 
  topics 
  relating 
  to 
  net 
  metering 
  and 
  
renewable 
  portfolio 
  standards. 
  In 
  Oregon 
  a 
  Legislative 
  Concept 
  (L.C.) 
  is 
  a 
  draft 
  of 
  an 
  idea 
  for 
  legislation 
  
that 
  is 
  prepared 
  by 
  Legislative 
  Counsel. 
  If 
  the 
  committee 
  decides 
  to 
  formally 
  introduce 
  this 
  L.C. 
  as 
  a 
  bill 
  it 
  
will 
  receive 
  a 
  new 
  bill 
  number. 
  The 
  Committee 
  will 
  hear 
  testimony 
  regarding 
  L.C. 
  54, 
  Relating 
  to 
  Net 
  
Metering 
  of 
  Energy 
  Produced 
  by 
  Marine 
  Resources, 
  from 
  Lt. 
  Col. 
  Ken 
  Safe 
  of 
  the 
  United 
  State 
  Army 
  
Corps 
  of 
  Engineers 
  as 
  well 
  as 
  Richard 
  Williams, 
  Director 
  of 
  Columbia 
  Region 
  Leidos 
  Maritime 
  Solutions. 
  
Lisa 
  Schwartz, 
  Director 
  of 
  the 
  Department 
  of 
  Energy, 
  will 
  present 
  testimony 
  and 
  legislative 
  
recommendations 
  on 
  renewable 
  portfolio 
  standards 
  in 
  Oregon 
  along 
  with 
  Ted 
  Case, 
  Executive 
  Director 
  
of 
  Oregon's 
  Rural 
  Electric 
  Cooperative 
  Association, 
  Varner 
  Seaman, 
  Policy 
  Director, 
  Renewable 
  
Northwest 
  Project 
  and 
  Scott 
  Bolton, 
  Vice 
  President, 
  Community 
  and 
  Government 
  Relations 
  for 
  Pacific 
  
Power. 
  The 
  committee 
  meeting 
  will 
  be 
  open 
  to 
  the 
  public, 
  however, 
  only 
  invited 
  testimony 
  will 
  be 
  
accepted. 
   
  
 
  
• H.B. 
  2435 
  (2013): 
  Expands 
  eligible 
  technologies 
  for 
  net 
  metering 
  to 
  include 
  geothermal. 
  
o July 
  25, 
  2013: 
  Enacted. 
  
 
   
  
• H.B. 
  2893 
  (2013): 
  Extends 
  and 
  slightly 
  expands 
  solar 
  feed-­‐in 
  tariff 
  (FIT) 
  pilot. 
  Requires 
  the 
  OR 
  Public 
  
Utility 
  Commission 
  (PUC) 
  to 
  study 
  the 
  effectiveness 
  of 
  existing 
  solar 
  PV 
  incentive 
  programs, 
  including 
  
investigation 
  of 
  solar 
  resource 
  value, 
  the 
  costs/benefits 
  of 
  the 
  programs 
  for 
  retail 
  electricity 
  customers 
  
and 
  how 
  those 
  costs/benefits 
  are 
  distributed. 
  The 
  PUC 
  must 
  make 
  recommendations 
  for 
  modifying 
  the 
  
programs 
  or 
  establishing 
  new 
  ones 
  to 
  provide 
  solar 
  incentives 
  that 
  are 
  cost-­‐effective 
  and 
  protective 
  of 
  
ratepayers, 
  including 
  non-­‐participating 
  ratepayers. 
  Increases 
  the 
  program 
  capacity 
  cap 
  for 
  existing 
  
volumetric 
  incentive 
  rate 
  pilot 
  for 
  solar 
  PV, 
  from 
  25 
  MW 
  to 
  27.5 
  MW, 
  and 
  extends 
  expiration 
  date 
  from 
  
March 
  2015 
  to 
  March 
  2016. 
  The 
  program 
  allocates 
  capacity 
  by 
  investor-­‐owned 
  utility, 
  geographic 
  
region, 
  and 
  for 
  small 
  and 
  large 
  systems 
  – 
  20 
  of 
  the 
  25 
  MW 
  was 
  reserved 
  for 
  net 
  metered 
  systems 
  < 
  100 
  
kW. 
  PUC 
  must 
  craft 
  new 
  rules 
  for 
  allocating 
  extra 
  2.5 
  MW; 
  no 
  deadline 
  specified. 
   
  
o May 
  28, 
  2013: 
  Enacted. 
   
  
 
  

 Timeline of Key State Activities on Net Energy Metering

45

 
  
•

H.B. 
  4042: 
  Would 
  add 
  renewable 
  marine 
  energy 
  to 
  types 
  of 
  energy 
  eligible 
  for 
  NEM. 
  If 
  located 
  on 
  
territorial 
  sea 
  or 
  outer 
  continental 
  shelf, 
  it 
  is 
  deemed 
  directly 
  interconnected 
  to 
  the 
  customer-­‐
generator’s 
  premises. 
  
o January 
  23, 
  2014: 
  Prefiled 
  and 
  referred 
  to 
  Committee 
  on 
  Energy 
  and 
  Environment. 
  
o February 
  4, 
  2014: 
  Hearing 
  held. 
  Amended 
  and 
  passed. 
  
o February 
  11, 
  2014: 
  Passed 
  House 
  58-­‐0. 
  
o February 
  17, 
  2014: 
  Referred 
  to 
  Senate 
  Rural 
  Communities 
  and 
  Economic 
  Development. 
  
o February 
  20, 
  2014: 
  Hearing 
  held 
  and 
  passed 
  4-­‐0. 
  
o March 
  6, 
  2014: 
  Signed 
  by 
  Gov. 
  Kitzhaber. 
  

 
  
Rates 
  and 
  Regulation 
  
 
  
• PUC 
  Legislative 
  Report 
  to 
  Comply 
  with 
  H.B. 
  2893 
  regarding 
  solar 
  incentives, 
  Docket 
  No. 
  UM 
  1673 
  
o October 
  8, 
  2013: 
  Workshop 
  held 
  for 
  this 
  docket 
  and 
  Docket 
  No. 
  UM 
  1452 
  (below), 
  per 
  H.B. 
  2893. 
  
Staff 
  and 
  other 
  parties 
  recognized 
  there 
  is 
  not 
  enough 
  time 
  for 
  a 
  full, 
  comprehensive 
  study. 
  Among 
  
the 
  possibilities 
  is 
  a 
  commission 
  interpretation 
  of 
  the 
  law 
  as 
  requiring 
  what 
  already 
  has 
  been 
  done 
  
in 
  proceedings 
  on 
  the 
  existing 
  solar 
  FIT 
  pilot 
  program, 
  under 
  which 
  utilities 
  have 
  filed 
  resource 
  value 
  
estimates 
  that 
  approximate 
  avoided 
  cost. 
  At 
  the 
  workshop, 
  staff 
  appeared 
  to 
  support 
  an 
  avoided 
  
cost 
  methodology 
  (avoided 
  cost 
  plus 
  line 
  losses). 
  
o November 
  2013: 
  Staff 
  issued 
  list 
  of 
  questions 
  addressing 
  goals 
  for 
  promoting 
  solar 
  and 
  the 
  role 
  of 
  
utilities, 
  evaluation 
  of 
  existing 
  incentive 
  programs, 
  resource 
  value, 
  costs 
  and 
  benefits 
  of 
  existing 
  
programs, 
  forecasting 
  solar 
  costs, 
  program 
  barriers, 
  future 
  development 
  of 
  solar 
  energy 
  (e.g, 
  at 
  
what 
  penetration 
  levels 
  would 
  distribution 
  reliability 
  be 
  affected; 
  what 
  business 
  models 
  best 
  meet 
  
overall 
  goals.) 
   
  
o December 
  18, 
  2013: 
  Responses 
  to 
  questions 
  due. 
  The 
  Alliance 
  for 
  Solar 
  Choice 
  filed 
  comments 
  one 
  
day 
  after 
  it 
  petitioned 
  to 
  intervene. 
  Numerous 
  other 
  solar 
  and 
  renewable 
  interests 
  have 
  intervened 
  
as 
  well. 
  
o January 
  16, 
  2014: 
  Public 
  workshop. 
  The 
  agenda 
  can 
  be 
  found 
  at 
  this 
  PUC 
  webpage. 
  Solar 
  advocates, 
  
including 
  SolarCity 
  representing 
  TASC, 
  pushed 
  for 
  more 
  fully 
  exploring 
  the 
  costs 
  and 
  benefits 
  of 
  solar 
  
programs 
  and 
  the 
  value 
  of 
  solar. 
  Commissioners 
  said 
  they 
  are 
  not 
  interested 
  in 
  more 
  studies 
  and 
  
that 
  there 
  is 
  enough 
  information 
  now 
  in 
  the 
  public 
  domain 
  that 
  can 
  be 
  synthesized 
  for 
  use, 
  
according 
  to 
  a 
  participant. 
  Commissioners 
  also 
  expressed 
  hesitation 
  about 
  addressing 
  many 
  issues 
  
at 
  once, 
  preferring 
  to 
  have 
  a 
  relatively 
  limited 
  scope 
  that 
  enables 
  them 
  to 
  move 
  forward 
  while 
  
avoiding 
  a 
  major 
  fight 
  among 
  competing 
  interests. 
  No 
  additional 
  workshops 
  are 
  scheduled. 
  
o March 
  2014: 
  Parties 
  to 
  the 
  docket 
  expect 
  a 
  draft 
  report 
  from 
  the 
  commission 
  around 
  March. 
  Parties 
  will 
  
have 
  an 
  opportunity 
  to 
  submit 
  comments 
  to 
  the 
  draft. 
  Parties 
  are 
  having 
  ongoing 
  informal 
  discussions 
  with 
  
Commission 
  Staff 
  during 
  this 
  process. 
  

o

July 
  1, 
  2014: 
  PUC 
  study 
  due 
  to 
  legislature. 
  

 
  
•

Volumetric 
  Incentive 
  Rates 
  and 
  FIT 
  capacity 
  allocation, 
  Docket 
  No. 
  UM 
  1452 
  
o October 
  8, 
  2013: 
  Workshop 
  held 
  for 
  this 
  docket 
  and 
  Docket 
  No. 
  UM 
  1673 
  (above), 
  per 
  H.B. 
  2893. 
  
2893. 
  Half 
  of 
  the 
  session 
  addressed 
  allocation 
  of 
  an 
  additional 
  2.5 
  MW 
  of 
  FIT 
  capacity. 
  Staff 
  favored 
  
a 
  60/40 
  split 
  between 
  small 
  and 
  medium 
  systems 
  (small 
  = 
  5-­‐10 
  kW) 
  and 
  offering 
  the 
  capacity 
  in 
  April 
  
2014.The 
  other 
  half 
  of 
  the 
  workshop 
  addressed 
  the 
  PUC 
  report 
  to 
  the 
  legislature 
  on 
  solar 
  incentives. 
  

 Timeline of Key State Activities on Net Energy Metering

46

 
  
November 
  5, 
  2013: 
  Settlement 
  conference 
  on 
  FIT 
  capacity 
  allocation. 
  
November 
  15, 
  2013: 
  Comments 
  due 
  on 
  FIT 
  capacity 
  allocation. 
  
January 
  3, 
  2014: 
  More 
  comments 
  due. 
  
January 
  22, 
  2014: 
  Order 
  issued 
  approving 
  incentive 
  rates 
  for 
  small 
  and 
  medium 
  scale 
  projects. 
  
The 
  PUC 
  issued 
  a 
  general 
  report 
  on 
  the 
  Solar 
  Incentive 
  Rate 
  Pilot 
  Program 
  for 
  the 
  April 
  1, 
  2014, 
  
enrollment 
  period, 
  which 
  will 
  include 
  the 
  new 
  2.5 
  MW 
  of 
  capacity 
  per 
  H.B. 
  2893. 
  Other 
  documents 
  
in 
  the 
  docket 
  are 
  located 
  at: 
  http://apps.puc.state.or.us/edockets/docket.asp?DocketID=15820 
   
   
  
 
  
Investigation 
  into 
  appropriate 
  calculation 
  of 
  solar 
  PV 
  resource 
  value, 
  Docket 
  No. 
  UM 
  1559 
  
o October 
  18, 
  2012: 
  The 
  OR 
  PUC 
  issued 
  an 
  order 
  broadening 
  the 
  scope 
  of 
  utility 
  reporting 
  
requirements 
  under 
  the 
  existing 
  statutory 
  solar 
  PV 
  pilot 
  program. 
  Utilities 
  must 
  use 
  a 
  variety 
  of 
  
methods 
  including 
  standard 
  avoided 
  cost 
  methodology 
  to 
  enable 
  comparison 
  of 
  the 
  results. 
  
o
o
o
o
o

•

PENNSYLVANIA 
  
Rates 
  and 
  Regulation 
  
•

•

Changes 
  to 
  NEM, 
  interconnection 
  and 
  compliance 
  rules 
  under 
  the 
  Alternative 
  Energy 
  Portfolio 
  
Standards 
  Act, 
  Docket 
  No. 
  L-­‐2014-­‐2404361 
   
  
o February 
  20, 
  2014: 
  The 
  PA 
  Public 
  Utilities 
  Commission 
  (PUC) 
  issued 
  a 
  Notice 
  of 
  Proposed 
  
Rulemaking 
  proposing 
  rule 
  changes 
  involving 
  law, 
  procedure 
  and 
  policy. 
  Various 
  issues 
  are 
  specific 
  
to 
  NEM 
  in 
  a 
  retail 
  choice 
  state. 
  The 
  PUC 
  will 
  accept 
  written 
  comments 
  until 
  30 
  days 
  after 
  the 
  
proposed 
  rules 
  are 
  officially 
  published 
  in 
  the 
  Pennsylvania 
  Bulletin. 
  The 
  rules 
  have 
  not 
  yet 
  been 
  
officially 
  published; 
  the 
  Pennsylvania 
  Bulletin 
  is 
  released 
  on 
  Fridays. 
  
 
  
Net 
  metering 
  default 
  service 
  in 
  context 
  of 
  investigation 
  into 
  the 
  retail 
  energy 
  market 
  in 
  PA, 
  Docket 
  No. 
  
I-­‐2011-­‐2237952. 
  
o February 
  15, 
  2013: 
  The 
  PA 
  Public 
  Utility 
  Commission 
  (PUC) 
  ordered 
  the 
  formation 
  of 
  a 
  working 
  
group 
  to 
  explore 
  recommendations 
  regarding 
  provision 
  by 
  alternative 
  retail 
  service 
  providers 
  of 
  
default 
  service, 
  the 
  potential 
  for 
  providing 
  net 
  metering 
  benefits, 
  and 
  cost 
  recovery. 
  
o November 
  15, 
  2013: 
  Working 
  group 
  was 
  required 
  to 
  file 
  a 
  report 
  with 
  the 
  PUC. 
  However, 
  the 
  
deadline 
  is 
  delayed 
  in 
  light 
  of 
  introduction 
  of 
  S.B. 
  1121 
  (below). 
  A 
  new 
  deadline 
  has 
  not 
  been 
  set. 
  

Legislation 
  
•

•

•

H.B. 
  1912: 
  Would 
  repeal 
  the 
  Alternative 
  Energy 
  Portfolio 
  Standards 
  Act. 
  
o December 
  12, 
  2013: 
  Introduced 
  and 
  referred 
  to 
  House 
  Committee 
  on 
  Consumer 
  Affairs. 
   
  
 
  
S.B. 
  1121: 
  Proposes 
  a 
  new 
  model 
  for 
  electric 
  default 
  service 
  beginning 
  June 
  1, 
  2015. 
   
  Electric 
  generation 
  
suppliers 
  would 
  be 
  responsible 
  for 
  providing 
  net 
  metering 
  to 
  customer 
  generators 
  pursuant 
  to 
  the 
  
Alternative 
  Energy 
  Portfolio 
  Standards 
  Act 
  of 
  2004. 
  
o October 
  10, 
  2013: 
  Referred 
  to 
  Consumer 
  Protection 
  and 
  Professional 
  Licensure 
  Committee. 
  
 
   
  
S.B. 
  1171: 
   
  Would 
  amend 
  alternative 
  energy 
  portfolio 
  standard 
  (AEPS), 
  which 
  has 
  two 
  tiers. 
  The 
  AEPS 
  
calls 
  for 
  8% 
  of 
  retail 
  electricity 
  sold 
  in 
  Pennsylvania 
  to 
  come 
  from 
  Tier 
  1 
  resources 
  such 
  as 
  wind 
  and 
  

 Timeline of Key State Activities on Net Energy Metering

47

 
  
hydroelectric 
  projects 
  by 
  2021. 
  The 
  AEPS 
  also 
  has 
  a 
  solar 
  carve-­‐out 
  of 
  0.5% 
  by 
  2021. 
  Under 
  the 
  AEPS, 
  
10% 
  must 
  come 
  from 
  Tier 
  2 
  resources 
  like 
  waste 
  coal 
  and 
  wood 
  pulping 
  by 
  2021. 
  S.B. 
  1171 
  would 
  
increase 
  the 
  Tier 
  1 
  requirement 
  to 
  15% 
  by 
  2023 
  in 
  1.5% 
  per 
  year 
  increments 
  starting 
  in 
  2018, 
  and 
  
increase 
  the 
  solar 
  carve-­‐out 
  to 
  1.5% 
  by 
  2023. 
  Similar 
  legislation, 
  H.B. 
  100, 
  was 
  introduced 
  in 
  the 
  House 
  
earlier 
  this 
  year. 
   
  
o November 
  15, 
  2013: 
  Introduced 
  and 
  referred 
  to 
  Environmental 
  Resources 
  and 
  Energy 
  Committee. 
  

RHODE 
  ISLAND 
  
•

S.B. 
  2990: 
   
  Would 
  create 
  a 
  tariff-­‐based 
  renewable 
  energy 
  DG 
  financing 
  program, 
  or 
  “Distributed 
  
Generation 
  Growth 
  Program.” 
  Under 
  the 
  program 
  utilities 
  would 
  file 
  each 
  year 
  for 
  at 
  least 
  give 
  years 
  
tariffs 
  providing 
  for 
  multiyear 
  streams 
  of 
  performance-­‐based 
  incentives 
  for 
  eligible 
  projects. 
  The 
  
incentives 
  would 
  be 
  designed 
  to 
  achieve 
  MW 
  targets 
  at 
  reasonable 
  cost 
  through 
  a 
  competitive 
  process. 
  
o March 
  5, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  Environment 
  and 
  Agriculture. 
   
   
  

SOUTH 
  CAROLINA 
  
Rates 
  and 
  Regulation 
  
•

•

Ex 
  parte 
  PSC 
  briefing 
  on 
  economic 
  development 
  issues 
  related 
  to 
  solar, 
  wind, 
  energy 
  efficiency, 
  Docket 
  
No. 
  ND-­‐2013-­‐19-­‐E 
  
o December 
  17, 
  2013: 
  The 
  SC 
  Public 
  Service 
  Commission 
  (PSC) 
  held 
  a 
  briefing 
  to 
  hear 
  presentations 
  on 
  
solar 
  issues 
  in 
  response 
  to 
  a 
  request 
  by 
  the 
  SC 
  Coastal 
  Conservation 
  League 
  and 
  Southern 
  Alliance 
  
for 
  Clean 
  Energy 
  via 
  the 
  Southern 
  Environmental 
  Law 
  Center. 
  Electric 
  utilities 
  did 
  not 
  make 
  
presentations. 
  No 
  action 
  was 
  taken. 
  The 
  transcript 
  and 
  other 
  related 
  documents 
  can 
  be 
  downloaded 
  
from 
  his 
  PSC 
  webpage. 
   
   
  
 
  
Generic 
  proceeding 
  on 
  implementation 
  of 
  net 
  metering 
  standards 
  per 
  Energy 
  Policy 
  Act 
  of 
  2005, 
  
Docket 
  No. 
  2005-­‐385E 
  
o July 
  2, 
  2013: 
  The 
  SC 
  Public 
  Service 
  Commission 
  (PSC) 
  issued 
  an 
  order 
  directing 
  that 
  a 
  workshop 
  be 
  
held 
  as 
  part 
  of 
  a 
  review 
  of 
  the 
  net 
  metering 
  program 
  since 
  changes 
  were 
  last 
  implemented 
  in 
  2009. 
  
o Sept. 
  12, 
  2013: 
  Public 
  workshop 
  on 
  net 
  metering. 
  Canceled 
  by 
  the 
  PSC 
  in 
  response 
  to 
  a 
  request 
  from 
  
Electric 
  Cooperatives 
  of 
  South 
  Carolina, 
  which 
  said 
  the 
  workshop 
  is 
  premature 
  pending 
  completion 
  
of 
  an 
  ongoing 
  legislative 
  study. 
  (See 
  item 
  below.) 
  
o September 
  30, 
  2013: 
  Deadline 
  for 
  written 
  comments. 
   
  

Legislation 
  
•

Public 
  Utility 
  Review 
  Committee 
  (PURC) 
  Energy 
  Advisory 
  Committee 
  (EAC): 
  The 
  committee 
  is 
  
conducting 
  a 
  study 
  of 
  solar 
  issues, 
  including 
  the 
  impact 
  of 
  H. 
  3425, 
  which 
  would 
  allow 
  third-­‐party 
  solar 
  
financing/power 
  purchase 
  agreements. 
  (Companion 
  S. 
  536) 
  The 
  bill 
  was 
  referred 
  to 
  the 
  Labor, 
  
Commerce 
  and 
  Industry 
  Committee, 
  which 
  delayed 
  action 
  until 
  the 
  EAC 
  study 
  is 
  completed. 
  The 
  study 
  
also 
  includes 
  rate 
  design 
  and 
  cost 
  shifting 
  issues. 
  The 
  EAC 
  is 
  co-­‐facilitated 
  by 
  Ashlie 
  Lancaster 
  of 
  the 
  
State 
  Energy 
  Office 
  and 
  C. 
  Dukes 
  Scott, 
  Executive 
  Director 
  of 
  the 
  Office 
  of 
  Regulatory 
  Staff. 
  The 
  EAC 
  is 
  a 
  

 Timeline of Key State Activities on Net Energy Metering

48

 
  
non-­‐legislative 
  advisory 
  board 
  created 
  in 
  2010 
  by 
  PURC. 
  PURC 
  is 
  a 
  joint 
  standing 
  committee 
  of 
  the 
  SC 
  
Legislature, 
  chaired 
  by 
  Senator 
  Thomas 
  Alexander 
  (R) 
  and 
  Representative 
  William 
  Sandifer 
  (R). 
  The 
  
committee 
  also 
  consists 
  of 
  non-­‐legislative 
  public 
  members. 
   
  
o October 
  29, 
  2013: 
  EAC 
  met 
  to 
  address 
  initial 
  working 
  draft 
  report 
  that 
  addresses 
  list 
  of 
  issues, 
  as 
  
described 
  in 
  “EAC 
  Research 
  Questions.” 
  In 
  addition 
  to 
  the 
  impact 
  of 
  H. 
  3425, 
  the 
  questions 
  address 
  
the 
  extent 
  to 
  which 
  the 
  basic 
  facilities 
  charge 
  reflects 
  actual 
  fixed 
  costs, 
  alternative 
  rate 
  schedules 
  
that 
  may 
  better 
  accommodate 
  DG 
  technologies, 
  characteristics 
  of 
  various 
  forms 
  of 
  generation 
  in 
  
comparison 
  to 
  DG, 
  third-­‐party 
  sales 
  of 
  DG, 
  and 
  other 
  issues. 
  Research 
  questions 
  
o December 
  11, 
  2013: 
  The 
  EAC 
  held 
  a 
  meeting 
  to 
  discuss 
  the 
  Distributed 
  Energy 
  Resources 
  Initial 
  Draft 
  
Report 
  and 
  accept 
  testimony. 
  Agenda 
   
   
  
o December 
  18, 
  2013: 
  Written 
  comments 
  due. 
   
  
o December 
  31, 
  2013: 
  EAC 
  report 
  to 
  PURC 
  due. 
  

SOUTH 
  DAKOTA 
  
Rates 
  and 
  Regulation 
  
 
  
• Rulemaking 
  on 
  PURPA 
  avoided 
  cost, 
  SD 
  Public 
  Utilities 
  Commission 
  (PUC) 
  Docket 
  No. 
  RM13-­‐002 
   
  
o December 
  3, 
  2013: 
  Comments 
  due. 
   
  
o January 
  27, 
  2014: 
  The 
  PUC 
  approved 
  a 
  motion 
  to 
  proceed 
  with 
  a 
  rulemaking 
  regarding 
  creation 
  of 
  a 
  
legal 
  enforceable 
  obligation. 
  
o March 
  1, 
  2014: 
  Comments 
  due. 
  The 
  comments 
  may 
  include 
  draft 
  rule 
  language, 
  concepts, 
  or 
  
positions. 
  
o February 
  4, 
  2014: 
  The 
  SD 
  PUC 
  issued 
  a 
  press 
  release. 
   
  
 
  
Legislation 
  
 
  
• H.B. 
  1254: 
  Would 
  create 
  a 
  net 
  metering 
  requirement 
  for 
  electric 
  utilities 
  and 
  rural 
  electric 
  cooperatives. 
  
Excess 
  generation 
  to 
  be 
  carried 
  forward 
  month 
  to 
  month 
  and 
  credited 
  at 
  70% 
  of 
  the 
  retail 
  rate. 
  
Customer-­‐generators 
  could 
  not 
  be 
  charged 
  fees 
  or 
  rates 
  that 
  do 
  not 
  apply 
  to 
  non-­‐DG 
  customers. 
  Eligible 
  
rated 
  capacity 
  of 
  the 
  renewable 
  generator 
  could 
  not 
  exceed 
  150 
  kW. 
  
o February 
  4, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  Agriculture 
  and 
  Natural 
  Resources 
  Committee. 
  
o February 
  13, 
  2014: 
  Hearing 
  held. 
  
o February 
  18, 
  2014: 
  Hearing 
  held; 
  measure 
  deferred 
  until 
  41st 
  day, 
  which 
  means 
  it 
  has 
  been 
  tabled 
  
and 
  is 
  unlikely 
  to 
  receive 
  further 
  consideration. 
  Dakota 
  Rural 
  Action 
  testified 
  in 
  support. 
  The 
  South 
  
Dakota 
  Rural 
  Electric 
  Association, 
  South 
  Dakota 
  Electric 
  Utility 
  Companies, 
  South 
  Dakota 
  Municipal 
  
Electric 
  Association 
  and 
  Heartland 
  Consumers 
  Power 
  District 
  testified 
  in 
  opposition.

TEXAS 
  
•

There 
  is 
  no 
  statewide 
  net 
  metering. 
  Solar 
  proponents 
  are 
  expected 
  to 
  continue 
  to 
  fight 
  for 
  legislation 
  to 
  
institute 
  statewide 
  net 
  metering 
  and 
  expand 
  the 
  state 
  RES, 
  despite 
  defeats 
  in 
  the 
  2013 
  legislative 
  
session. 
  Austin 
  Energy 
  has 
  a 
  value 
  of 
  solar 
  tariff. 
  CPS 
  Energy 
  (owned 
  by 
  San 
  Antonio) 
  in 
  spring 
  2013 
  

 Timeline of Key State Activities on Net Energy Metering

49

 
  
proposed 
  to 
  replace 
  its 
  net 
  metering 
  tariff 
  with 
  a 
  value 
  of 
  solar 
  tariff 
  modeled 
  after 
  Austin 
  Energy’s 
  
VOST. 
  However, 
  CPS’ 
  proposed 
  pricing 
  differed 
  significantly 
  from 
  Austin’s 
  VOST 
  and 
  the 
  muni 
  was 
  forced 
  
to 
  withdraw 
  its 
  proposal 
  in 
  the 
  face 
  of 
  opposition 
  from 
  solar 
  installers 
  and 
  customers. 
  

UTAH 
  
Rates 
  and 
  Regulation 
  
 
  
• PacifiCorp 
  general 
  rate 
  case, 
  Docket 
  No. 
  13-­‐035-­‐184 
  
o January 
  3, 
  2014: 
  Filed 
  with 
  UT 
  Public 
  Service 
  Commission 
  (PSC). 
  Request 
  includes: 
  increase 
  in 
  
residential 
  customer 
  charge 
  from 
  $5 
  to 
  $8; 
  increase 
  in 
  minimum 
  bill 
  applying 
  to 
  extremely 
  low-­‐use 
  
customers 
  from 
  $7 
  to 
  $15; 
  imposition 
  of 
  net 
  metering 
  surcharge 
  of 
  $4.25/month 
  for 
  residential. 
  
Testimony 
  cites 
  need 
  to 
  recover 
  more 
  fixed 
  distribution 
  and 
  customers 
  service 
  costs 
  through 
  fixed 
  
charges 
  as 
  company 
  role 
  changes 
  (e.g., 
  to 
  include 
  becoming 
  a 
  facilitator 
  of 
  energy 
  services 
  provided 
  
by 
  other 
  entities, 
  as 
  DG 
  and 
  net 
  metered 
  customers 
  increase, 
  and 
  other 
  factors. 
  
o January 
  16, 
  2014: 
  Scheduling 
  conference. 
  
o January 
  22, 
  2014: 
  Order 
  issued 
  dividing 
  case 
  into 
  Phase 
  1 
  (revenue 
  requirement) 
  and 
  Phase 
  2 
  (cost 
  
of 
  service) 
  and 
  setting 
  schedule. 
  
o May 
  15, 
  2014: 
  Interventions 
  for 
  Phase 
  1 
  & 
  2. 
  
o May 
  22, 
  2014: 
  Direct 
  testimony 
  (non-­‐company) 
  for 
  Phase 
  2. 
  
o June 
  26, 
  2014: 
  Rebuttal 
  (all 
  parties) 
  for 
  Phase 
  2. 
  
o July 
  17, 
  2014: 
  Surrebuttal 
  (all 
  parties) 
  for 
  Phase 
  2. 
  
o July 
  28-­‐August 
  1: 
  Hearing 
  for 
  Phase 
  2. 
  
o July 
  29, 
  2014: 
  Public 
  hearing 
  for 
  Phase 
  1 
  & 
  2. 
  
 
  
Legislation 
  
 
  
• October 
  16, 
  2013: 
  The 
  Public 
  Utilities 
  and 
  Technology 
  Interim 
  Committee 
  held 
  a 
  public 
  meeting 
  to 
  
discuss 
  several 
  topics, 
  including 
  development 
  of 
  energy 
  sources, 
  power 
  purchase 
  contracts 
  and 
  the 
  role 
  
of 
  net 
  metering 
  in 
  the 
  provision 
  of 
  electric 
  power. 
  After 
  hearing 
  presentations 
  from 
  the 
  state 
  energy 
  
office, 
  PacifiCorp 
  and 
  others, 
  the 
  committee 
  concluded 
  that 
  solar 
  penetration 
  in 
  the 
  state 
  is 
  at 
  too 
  small 
  
a 
  level 
  to 
  cause 
  significant 
  cost 
  shift 
  and 
  other 
  issues, 
  and 
  that 
  action 
  is 
  not 
  warranted 
  at 
  this 
  time. 
   
  
 
  
• H.B. 
  284 
  (2013): 
  Modifies 
  a 
  definition 
  applicable 
  to 
  the 
  net 
  metering 
  of 
  electricity 
  so 
  that 
  an 
  electrical 
  
corporation's 
  rate 
  schedule 
  may 
  define 
  a 
  billing 
  cycle 
  other 
  than 
  a 
  cycle 
  starting 
  on 
  April 
  1 
  of 
  one 
  year 
  
and 
  ending 
  on 
  March 
  31 
  of 
  the 
  following 
  year. 
  
o March 
  26, 
  2013: 
  Enacted. 
  Effective 
  date 
  of 
  implementation 
  is 
  May 
  14, 
  2013. 
  
 
  
• S.B. 
  208: 
  Current 
  version 
  (March 
  4, 
  2014) 
  provides 
  for 
  the 
  PSC 
  to 
  determine 
  whether 
  costs 
  that 
  a 
  utility 
  
or 
  non-­‐participating 
  customers 
  will 
  incur 
  from 
  a 
  net 
  metering 
  program 
  will 
  exceed 
  the 
  benefits 
  or 
  vice 
  
versa, 
  and 
  determine 
  a 
  charge, 
  credit 
  or 
  ratemaking 
  structure 
  – 
  including 
  new 
  or 
  existing 
  tariffs 
  – 
  in 
  light 
  
of 
  the 
  costs 
  and 
  benefits. 
  Would 
  require 
  that 
  at 
  the 
  end 
  of 
  an 
  annualized 
  billing 
  period 
  an 
  utility's 
  
avoided 
  cost 
  value 
  of 
  remaining 
  unused 
  NEM 
  credits 
  be 
  granted 
  to 
  the 
  utility's 
  low-­‐income 
  assistance 
  
programs 
  or 
  for 
  another 
  use 
  as 
  determined 
  by 
  PSC. 
  Requires 
  each 
  customer 
  participating 
  in 
  NEM 
  to 
  

 Timeline of Key State Activities on Net Energy Metering

50

 
  
provide 
  all 
  equipment 
  necessary 
  to 
  meet 
  applicable 
  utility 
  interconnection 
  requirements 
  at 
  the 
  
customer's 
  expense. 
  
o February 
  19 
  & 
  20, 
  2014: 
  Introduced 
  and 
  referred 
  respectively 
  to 
  Committee 
  on 
  Business 
  and 
  Labor. 
  
o February 
  24, 
  2014: 
  Hearing 
  held. 
  Passed 
  unanimously 
  with 
  no 
  amendment. 
  Senate 
  floor 
  
consideration 
  is 
  next.
o March 
  4, 
  2014: 
  Substituted.
o March 
  5, 
  2014: 
  Passed 
  Senate 
  unanimously; 
  referred 
  to 
  House 
  Public 
  Utilities 
  and 
  Technology 
  
Committee. 
  
o March 
  6, 
  2014: 
  Passed 
  committee 
  unanimously. 
  

VERMONT 
  
Rates 
  and 
  Regulation 
  
•

•

•

Washington 
  Electric 
  Cooperative 
  net 
  metering 
  tariff, 
  Docket 
  No. 
  8159 
  
o October 
  25, 
  2013: 
  WEC, 
  which 
  had 
  met 
  its 
  4% 
  NEM 
  cap, 
  filed 
  with 
  the 
  PSB 
  to 
  raise 
  the 
  cap 
  to 
  allow 
  
customers 
  with 
  up 
  to 
  5 
  kW 
  of 
  capacity 
  to 
  install 
  more 
  capacity. 
   
  
o November 
  22, 
  2013: 
  The 
  VT 
  Department 
  of 
  Public 
  Service 
  (DPS) 
  recommended 
  suspension 
  of 
  the 
  
tariff 
  and 
  an 
  investigation. 
  
o December 
  2, 
  2013: 
  The 
  VT 
  Public 
  Service 
  Board 
  (PSB) 
  issued 
  an 
  order 
  suspending 
  the 
  tariff 
  and 
  
opening 
  an 
  investigation. 
   
  The 
  PSB 
  said 
  the 
  proposed 
  tariff 
  differs 
  from 
  the 
  statutory 
  NEM 
  program, 
  
which 
  raises 
  legal 
  questions. 
  
o December 
  12, 
  2013: 
  Pre-­‐hearing 
  conference. 
  
 
  
Vermont 
  Electric 
  Cooperative 
  interim 
  net 
  metering 
  tariff 
  
o October 
  1, 
  2013: 
  Filed 
  with 
  VT 
  PSB. 
  Would 
  allow 
  VEC 
  members 
  to 
  continue 
  installing 
  net 
  metering 
  
systems 
  above 
  statutory 
  4 
  percent 
  system 
  cap, 
  which 
  VEC 
  has 
  reached. 
  Noting 
  there 
  are 
  many 
  legal 
  
opinions 
  regarding 
  what 
  can 
  happen 
  after 
  the 
  cap 
  is 
  reached, 
  VEC 
  said 
  it 
  would 
  not 
  object 
  if 
  the 
  PSB 
  
opened 
  an 
  investigation. 
  Filed 
  documents: 
  
http://www.vermontelectric.coop/content/Combined_Files_3.pdf 
   
  
Proposed 
  amendment 
  to 
  net 
  metering 
  rule, 
  Docket 
  No. 
  Rule 
  5100 
  
o July 
  19, 
  2013: 
  The 
  VT 
  Public 
  Service 
  Board 
  (PSB) 
  filed 
  with 
  the 
  Secretary 
  of 
  State 
  proposed 
  changes 
  
to 
  the 
  existing 
  net 
  metering 
  rule 
  including 
  a 
  proposed 
  increase 
  in 
  eligible 
  system 
  capacity, 
  changes 
  
to 
  billing 
  for 
  group 
  systems, 
  increases 
  in 
  the 
  utility 
  net 
  metered 
  capacity 
  limit, 
  and 
  establishment 
  of 
  
a 
  registration 
  process 
  for 
  smaller 
  systems. 
  Comments 
  and 
  other 
  information 
  are 
  posted 
  at: 
  
http://psb.vermont.gov/statutesrulesandguidelines/proposedrules/rule51002013 
   
  
o September 
  5, 
  2013: 
  Public 
  hearing 
  scheduled. 
  
o September 
  20, 
  2013: 
  Written 
  comments 
  due. 
  
o November 
  18, 
  2013: 
  The 
  PSB 
  issued 
  text 
  of 
  its 
  final 
  proposed 
  rule 
  and 
  response 
  to 
  comments, 
  
available 
  at 
  the 
  above 
  link. 
  
o December 
  19, 
  2013: 
  The 
  PSB 
  adopted 
  the 
  rule 
  as 
  proposed. 
  The 
  rule 
  is 
  final 
  and 
  effective 
  
1/27/2014. 
   
  In 
  Vermont, 
  notice 
  of 
  final 
  rulemakings 
  is 
  not 
  published 
  by 
  the 
  Secretary 
  of 
  State. 
  

 Timeline of Key State Activities on Net Energy Metering

51

 
  
Legislation 
  
•

•

•

H.B. 
  702: 
  Would 
  raise 
  aggregate 
  NEM 
  capacity 
  cap 
  from 
  4% 
  to 
  15% 
  and 
  make 
  other 
  changes 
  to 
  NEM 
  
program, 
  which 
  must: 
  1) 
  advance 
  renewable 
  goals; 
  2) 
  reduce 
  greenhouse 
  gas 
  emissions; 
  3) 
  ensure 
  that 
  
net 
  metering 
  does 
  not 
  shift 
  costs 
  included 
  in 
  each 
  retail 
  electricity 
  provider’s 
  revenue 
  requirement 
  
between 
  net 
  metering 
  customers 
  and 
  other 
  customers; 
  and 
  4) 
  allow 
  the 
  expansion 
  of 
  net 
  metering 
  to 
  
all 
  customers 
  who 
  want 
  to 
  participate. 
  Requires 
  the 
  VT 
  Public 
  Service 
  Board 
  to 
  create 
  rules 
  for 
  this 
  
program 
  by 
  2017. 
  This 
  measure 
  was 
  the 
  result 
  of 
  meetings 
  between 
  lawmakers, 
  utilities 
  and 
  
stakeholders 
  and 
  the 
  work 
  done 
  by 
  the 
  Committee 
  on 
  Natural 
  Resources 
  and 
  Energy. 
  Governor 
  Peter 
  
Shumlin 
  (D) 
  has 
  also 
  stated 
  his 
  support 
  of 
  the 
  expansion 
  of 
  net 
  metering. 
  It 
  has 
  been 
  described 
  as 
  a 
  
"three-­‐year 
  fix" 
  of 
  the 
  current 
  net 
  metering 
  program. 
  Democrats 
  control 
  both 
  chambers 
  of 
  the 
  
Legislature, 
  as 
  well 
  as 
  the 
  Governor's 
  Office. 
  
o January 
  24, 
  2014: 
  Introduced. 
  
o January 
  29, 
  2014: 
  Amended 
  by 
  House. 
  This 
  measure 
  was 
  never 
  referred 
  to 
  a 
  committee. 
  
o January 
  30, 
  2014: 
  Passed 
  House 
  on 
  voice 
  vote. 
  
o January 
  31, 
  2014: 
  Referred 
  to 
  Senate 
  Finance 
  Committee. 
  
o February 
  4, 
  2014: 
  Hearing 
  held. 
  Representatives 
  from 
  the 
  Department 
  of 
  Public 
  Service, 
  Green 
  
Mountain 
  Power, 
  Burlington 
  Electric 
  Department, 
  Washington 
  Electric 
  Co-­‐op 
  and 
  Vermont 
  Electric 
  
Cooperative 
  offered 
  testimony. 
  A 
  vote 
  was 
  not 
  taken. 
  The 
  committee 
  will 
  likely 
  hold 
  more 
  hearings. 
  
o February 
  19, 
  2014: 
  Hearing 
  held. 
  The 
  Department 
  of 
  Public 
  Service, 
  Washington 
  Electric 
  Co-­‐op, 
  
Renewable 
  Energy 
  Vermont, 
  Associated 
  Industries 
  of 
  Vermont, 
  and 
  Town 
  Manager 
  of 
  Johnson 
  
offered 
  testimony. 
  
o February 
  25, 
  2014: 
  Hearing 
  held. 
  The 
  Vermont 
  Legislature's 
  Office 
  of 
  Legislative 
  Council, 
  the 
  Public 
  
Service 
  Board, 
  Efficiency 
  Vermont 
  and 
  the 
  Vermont 
  Fuel 
  Dealers 
  association, 
  and 
  Department 
  of 
  
Public 
  Service 
  offered 
  testimony. 
  
o February 
  28, 
  2014: 
  Hearing 
  held. The 
  committee 
  considered 
  redrafts 
  of 
  the 
  measure. 
  
Representatives 
  from 
  the 
  Washington 
  Electric 
  Co-­‐op, 
  Department 
  of 
  Public 
  Service, 
  VT 
  Electric 
  
Cooperative, 
  Green 
  Mountain 
  Power, 
  Agency 
  of 
  Natural 
  Resources, 
  Renewable 
  Energy 
  Vermont, 
  VT 
  
Public 
  Interest 
  Research 
  Group, 
  Energize 
  VT, 
  Burlington 
  Electric 
  Department, 
  and 
  VT 
  Public 
  Power 
  
Supply 
  Authority 
  offered 
  testimony. 
  
 
  
Rural 
  electric 
  co-­‐ops 
  are 
  hitting 
  net 
  metering 
  caps 
  and 
  are 
  poised 
  to 
  work 
  with 
  legislators 
  in 
  2014 
  to 
  
address 
  cost-­‐shifting 
  issues. 
  Note: 
  Rural 
  utility 
  peaks 
  generally 
  fall 
  in 
  the 
  evening. 
  Green 
  Mountain 
  
Power, 
  whose 
  customers 
  are 
  about 
  one-­‐third 
  residential, 
  one 
  third 
  commercial 
  and 
  one-­‐third 
  
industrial, 
  experiences 
  its 
  peak 
  earlier 
  in 
  the 
  day 
  and 
  therefore 
  is 
  positioned 
  differently 
  with 
  regard 
  to 
  
solar. 
   
  
o Renewable 
  Energy 
  Vermont 
  wrote 
  to 
  Gov. 
  Peter 
  Shumlin 
  asking 
  him 
  to 
  work 
  to 
  preserve 
  and 
  
strengthen 
  net 
  metering 
  in 
  the 
  state. 
  A 
  copy 
  of 
  the 
  letter 
  is 
  found 
  in 
  this 
  news 
  article: 
  
http://vtdigger.org/2013/11/25/vermonts-­‐renewable-­‐businesses-­‐call-­‐governor-­‐support-­‐strong-­‐net-­‐
metering-­‐program/ 
   
  
 
  
January 
  8-­‐10, 
  2014: 
  The 
  House 
  Committee 
  on 
  Natural 
  Resources 
  and 
  Energy 
  held 
  meetings 
  on 
  net 
  
metering. 
  Among 
  those 
  scheduled 
  to 
  offer 
  testimony 
  were 
  Commissioner 
  Chris 
  Recchia 
  of 
  the 
  Public 
  
Service 
  Department, 
  Deputy 
  Commissioner 
  Darren 
  Springer 
  of 
  the 
  Public 
  Service 
  Department 
  (PSD), 
  

 Timeline of Key State Activities on Net Energy Metering

52

 
  

•

Public 
  Policy 
  Manager 
  Dan 
  Barlow 
  of 
  Vermont 
  Businesses 
  for 
  Social 
  Responsibility, 
  Director 
  Karen 
  Horn 
  
of 
  Vermont 
  League 
  of 
  Cities 
  and 
  Towns, 
  Outreach 
  Director 
  and 
  Energy 
  Program 
  Co-­‐Director 
  Johanna 
  
Miller 
  of 
  Vermont 
  Natural 
  Resources 
  Council, 
  Clean 
  Energy 
  Advocate 
  Ben 
  Walsh 
  of 
  Vermont 
  Public 
  
Interest 
  Research 
  Group, 
  and 
  Director 
  of 
  Government 
  Affairs 
  Robert 
  Dostis 
  of 
  Green 
  Mountain 
  Power. 
   
  
o Springer 
  of 
  DPS 
  presented 
  a 
  proposal 
  on 
  behalf 
  of 
  the 
  Shumlin 
  Administration 
  to 
  increase 
  the 
  4% 
  
cap 
  to 
  15% 
  during 
  the 
  next 
  three 
  years 
  as 
  an 
  interim 
  step 
  while 
  a 
  more 
  permanent 
  solution 
  is 
  
developed 
  before 
  solar 
  tax 
  credits 
  expire 
  at 
  the 
  end 
  of 
  2016.
 
  
H.B. 
  366: 
  Would 
  increase 
  the 
  net 
  metering 
  system 
  capacity 
  for 
  industrial 
  facilities 
  and 
  standardize 
  the 
  
definition 
  of 
  “plant 
  capacity” 
  as 
  it 
  applies 
  to 
  solar 
  electric 
  generation. 
  
o February 
  26, 
  2013: 
  Referred 
  to 
  Committee 
  on 
  Natural 
  Resources 
  and 
  Energy. 
  The 
  bill 
  will 
  carry 
  over 
  
to 
  the 
  next 
  session. 
  

 
  
•

•

H.B. 
  604: 
  States 
  that 
  net 
  metering 
  credits 
  do 
  not 
  apply 
  to 
  either 
  the 
  fixed 
  customer 
  charge 
  or 
  the 
  energy 
  
efficiency 
  charge 
  on 
  a 
  customer's 
  bill. 
  
o January 
  15, 
  2014: 
  Referred 
  to 
  the 
  House 
  Committee 
  on 
  Natural 
  Resources 
  and 
  Energy. 
  
 
  
S.B. 
  105: 
  Would 
  require 
  regional 
  planning 
  commissions 
  to 
  plan 
  for 
  siting 
  of 
  renewable 
  electric 
  energy 
  
plants. 
  
o February 
  14, 
  2013: 
  Referred 
  to 
  Committee 
  on 
  Natural 
  Resources 
  and 
  Energy. 
  The 
  bill 
  will 
  carry 
  over 
  
to 
  the 
  next 
  session. 
  

 
  
•

S.B. 
  196: 
   
  Would 
  eliminate 
  the 
  existing 
  NEM 
  4% 
  system 
  capacity 
  limit 
  and, 
  so 
  that 
  NEM 
  customers 
  
contribute 
  to 
  the 
  cost 
  of 
  maintaining 
  and 
  operating 
  the 
  grid, 
  would 
  require 
  these 
  customers 
  “to 
  pay 
  the 
  
monthly 
  customer 
  charge 
  billed 
  by 
  the 
  electric 
  company.” 
  
o December 
  17, 
  2013: 
  Two 
  similar 
  measures 
  in 
  2013 
  saw 
  no 
  significant 
  action. 
  The 
  sponsor 
  is 
  a 
  
member 
  of 
  the 
  majority 
  party. 
  Democrats 
  control 
  both 
  chambers 
  of 
  the 
  Legislature 
  and 
  the 
  
governor's 
  office.

S.B. 
  204: 
  Would 
  create 
  the 
  "10 
  Percent 
  for 
  Vermont 
  Program," 
  provide 
  financing 
  to 
  create 
  renewable 
  
energy, 
  and 
  set 
  a 
  goal 
  of 
  90% 
  of 
  energy 
  to 
  be 
  supplied 
  through 
  renewable 
  sources 
  by 
  2050. 
  
o December 
  17 
  & 
  January 
  7, 
  2013: 
  Filed 
  and 
  referred 
  to 
  Senate 
  Committee 
  on 
  Finance. 
  
o February 
  5, 
  2014: 
  Meeting 
  held. 
  No 
  action 
  taken. 
   
  
o February 
  25, 
  2014: 
  Hearing 
  held. 
  
 
  
Other 
  Initiatives 
  
 
  
• Total 
  Energy 
  Study, 
  VT 
  Public 
  Service 
  Department 
  (PSD) 
  (executive 
  branch 
  agency 
  that 
  represents 
  the 
  
public 
  interest 
  before 
  the 
  PSB 
  and 
  other 
  entities). 
  PSD 
  webpage 
  As 
  part 
  of 
  this 
  effort, 
  the 
  PSD 
  will 
  
produce 
  a 
  proposal 
  for 
  consideration 
  during 
  the 
  2014 
  legislative 
  session. 
   
   
  
o June 
  21, 
  2013: 
  PSD 
  issued 
  “Request 
  for 
  public 
  comment 
  and 
  stakeholder 
  engagement 
  on 
  ‘Total 
  
Energy 
  Study’ 
  Framing 
  Report.” 
  The 
  PSD 
  held 
  stakeholder 
  sessions 
  through 
  summer 
  2013. 
  The 
  
comment 
  period 
  is 
  now 
  closed. 
  
o November 
  14, 
  2013: 
  Public 
  meeting 
  and 
  webinar 
  presentation. 
   
  
•

 Timeline of Key State Activities on Net Energy Metering

53

 
  

VIRGINIA 
  

 
  

Rates 
  and 
  Regulation 
  
 
  
• Implementation 
  of 
  H.B. 
  1695 
  (below), 
  agricultural 
  NEM, 
  Docket 
  No. 
  PUE-­‐2014-­‐00003. 
   
  
o January 
  27, 
  2014: 
  The 
  VA 
  SCC 
  issued 
  an 
  order 
  to 
  open 
  a 
  docket 
  to 
  establish 
  an 
  NEM 
  program 
  for 
  
eligible 
  agricultural 
  customers. 
   
  
o February 
  24, 
  2014: 
  Proposed 
  regulation 
  published 
  in 
  State 
  Register. 
  
o March 
  27, 
  2014: 
  Comments 
  due. 
  
o July 
  1, 
  2014: 
  Statutory 
  deadline 
  for 
  program 
  implementation. 
  
 
  
• Implementation 
  of 
  S.B. 
  1023 
  (below), 
  Docket 
  No. 
  PUE-­‐2013-­‐00045. 
  CLOSED 
  
o November 
  14, 
  2013: 
  The 
  VA 
  State 
  Corporation 
  Commission 
  (SCC) 
  issued 
  a 
  final 
  order 
  establishing 
  
guidelines 
  on 
  aspects 
  of 
  a 
  third-­‐party 
  purchased 
  power 
  agreement 
  pilot 
  program 
  for 
  solar 
  and 
  wind 
  
power 
  in 
  Dominion 
  Virginia 
  Power’s 
  service 
  territory. 
   
  This 
  docket 
  is 
  now 
  closed. 
   
  The 
  SCC 
  will 
  review 
  
the 
  pilot 
  program 
  in 
  2015 
  and 
  every 
  two 
  years 
  after. 
  
 
  
Legislation 
  
 
  
• H.B. 
  879: 
  Authorizes 
  municipal 
  renewable 
  NEM 
  projects 
  for 
  which 
  load 
  from 
  governmental 
  buildings, 
  
facilities, 
  and 
  other 
  governmental 
  operations, 
  including 
  load 
  served 
  by 
  multiple 
  meters, 
  may 
  be 
  
aggregated. 
  Eligible 
  resources 
  are 
  solar, 
  wind, 
  and 
  aerobic 
  or 
  anaerobic 
  digester 
  gas 
  and 
  landfill 
  gas. 
  
Aggregate 
  capacity 
  would 
  be 
  capped 
  at 
  5 
  MW 
  unless 
  a 
  utility 
  elects 
  a 
  higher 
  capacity. 
  The 
  measure 
  also 
  
would 
  require 
  the 
  VA 
  SCC 
  to 
  establish, 
  by 
  July 
  1, 
  2015, 
  a 
  multifamily 
  NEM 
  program 
  for 
  customers 
  
operating 
  renewable 
  generation 
  in 
  a 
  condominium, 
  apartment 
  complex, 
  neighborhood 
  or 
  homeowners 
  
association. 
  
o January 
  7, 
  2014: 
  Introduced. 
  This 
  bill 
  is 
  sponsored 
  by 
  a 
  Republican 
  (controlling 
  House/Senate 
  party). 
  
Democrat-­‐sponsored 
  measures 
  with 
  similar 
  aims 
  also 
  were 
  introduced: 
  S.B. 
  350 
  (below) 
  and 
  H.B. 
  
906. 
  
o January 
  30, 
  2014: 
  Tabled 
  on 
  voice 
  vote 
  by 
  special 
  energy 
  subcommittee 
  of 
  House 
  Commerce 
  and 
  
Labor. 
  The 
  similar 
  H.B.906 
  also 
  was 
  tabled 
  on 
  voice 
  vote. 
  
 
  
• H.B. 
  818: 
  Would 
  establish 
  VA 
  Commission 
  on 
  Energy 
  and 
  Environment 
  in 
  legislative 
  branch. 
  Provides 
  
that 
  the 
  commission 
  must 
  review 
  and 
  make 
  recommendations 
  to 
  help 
  implement 
  the 
  VA 
  Energy 
  Plan. 
  
Duties 
  include 
  evaluating 
  renewable 
  energy 
  portfolios, 
  pursuing 
  DG 
  plans, 
  and 
  evaluating 
  grid 
  upgrades. 
  
Also 
  would 
  create 
  related 
  fund 
  to 
  help 
  commission 
  implement 
  requirements. 
  
o January 
  7, 
  2014: 
  Prefiled. 
  
 
  
• H.B. 
  1061: 
  Would 
  set 
  DG 
  minimum 
  goals 
  as 
  part 
  of 
  state 
  RPS 
  goals. 
  
o January 
  8, 
  2014: 
  Prefiled. 
  
 
  
• H.B. 
  1158: 
  Would 
  allow 
  a 
  subscriber 
  organization 
  to 
  own 
  a 
  community 
  solar 
  garden 
  to 
  receive 
  net 
  
metering 
  credits 
  from 
  a 
  utility. 
  Requires 
  the 
  utility 
  to 
  purchase 
  unsubscribed 
  renewable 
  energy 
  at 
  the 
  
same 
  rate 
  as 
  the 
  utility's 
  average 
  hourly 
  incremental 
  cost 
  of 
  electricity 
  supply 
  from 
  the 
  previous 
  year. 
  

 Timeline of Key State Activities on Net Energy Metering

54

 
  
o
o

January 
  16, 
  2014: 
  Assigned 
  to 
  House 
  Commerce 
  and 
  Labor 
  special 
  subcommittee 
  on 
  energy. 
  
January 
  30, 
  2014: 
  Tabled 
  by 
  subcommittee 
  on 
  voice 
  vote. 
  

•

H.B. 
  1695 
  (2013): 
  Requires 
  the 
  VA 
  State 
  Corporation 
  Commission 
  (SCC) 
  to 
  expand 
  the 
  existing 
  net 
  
metering 
  program 
  to 
  allow 
  eligible 
  agricultural 
  customer-­‐generators 
  the 
  opportunity 
  to 
  use 
  multiple 
  
meters 
  for 
  net 
  metering. 
  
o March 
  13, 
  2013: 
  Enacted. 
  

•

H.J. 
  76: 
  Would 
  create 
  mandatory 
  RPS. 
  
o January 
  8, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  House 
  Committee 
  on 
  Rules. 
  

•

S.B. 
  350: 
  Would 
  authorize 
  municipal 
  renewable 
  NEM 
  projects, 
  allow 
  aggregation 
  of 
  load 
  of 
  
governmental 
  buildings, 
  and 
  require 
  the 
  SCC 
  to 
  establish 
  by 
  July 
  1, 
  2015, 
  a 
  multifamily 
  NEM 
  program. 
   
  
o January 
  7, 
  2014: 
  Introduced; 
  referred 
  to 
  Senate 
  Commerce 
  and 
  Labor 
  Committee. 
  
o February 
  3, 
  2014: 
  Hearing 
  held. 
  Continued 
  to 
  2015 
  on 
  13-­‐3 
  vote. 
  No 
  further 
  consideration 
  is 
  
expected 
  in 
  2014. 
  
 
  
S.B. 
  1023 
  (2013): 
  Creates 
  a 
  third-­‐party 
  purchased 
  power 
  agreement 
  pilot 
  program 
  for 
  solar 
  and 
  wind 
  
power 
  in 
  Dominion 
  Virginia 
  Power’s 
  service 
  territory. 
  The 
  program 
  is 
  limited 
  to 
  50 
  MW 
  within 
  the 
  state’s 
  
overall 
  net 
  metering 
  cap 
  of 
  1% 
  of 
  utility 
  peak 
  load 
  (approximately 
  165 
  MW 
  for 
  Dominion). 
  Projects 
  are 
  
limited 
  to 
  non-­‐residential 
  customers 
  and 
  to 
  1 
  MW 
  in 
  size 
  (and 
  for-­‐profit 
  entities 
  are 
  also 
  subject 
  to 
  a 
  50 
  
kW 
  minimum, 
  thereby 
  ensuring 
  they 
  pay 
  a 
  standby 
  charge 
  under 
  Dominion’s 
  current 
  rate 
  structure). 
  
o March 
  14, 
  2013: 
  Enacted. 
   
   
  
 
  
S.R. 
  47: 
  Requests 
  the 
  departments 
  of 
  Environmental 
  Quality 
  and 
  Mines, 
  Minerals 
  and 
  Energy 
  to 
  jointly 
  
convene 
  a 
  stakeholder 
  group 
  to 
  study 
  the 
  costs 
  and 
  benefits 
  of 
  solar 
  DG 
  and 
  NEM. 
  Requires 
  the 
  
stakeholder 
  group 
  to 
  study 
  relevant 
  data, 
  make 
  recommendations 
  on 
  methods 
  for 
  evaluating 
  such 
  data 
  
and 
  consider 
  other 
  issues 
  as 
  appropriate. 
  
o March 
  3, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  Rules 
  Committee. 
  
o March 
  4, 
  2014: 
  Passed 
  Rules 
  9-­‐3. 
  
o March 
  6, 
  2014: 
  Referred 
  back 
  to 
  Rules. 
  Passed 
  by 
  indefinitely, 
  which 
  means 
  it 
  is 
  unlikely 
  to 
  receive 
  
further 
  consideration 
  in 
  this 
  session. 
  

•

•

WASHINGTON 
  
Rates 
  and 
  Regulation 
  
 
  
• Investigation 
  of 
  costs/benefits 
  of 
  DG 
  and 
  the 
  effect 
  of 
  DG 
  on 
  utility 
  provision 
  of 
  electric 
  service, 
  
Docket 
  No. 
  UE-­‐131883 
  
o October 
  15, 
  2013: 
  WA 
  Utilities 
  and 
  Transportation 
  (UTC) 
  issued 
  a 
  notice 
  that 
  it 
  is 
  seeking 
  to 
  
understand 
  net 
  metering/DG 
  issues 
  as 
  they 
  relate 
  to 
  utilities 
  in 
  the 
  state, 
  including 
  the 
  effect 
  of 
  net 
  
metering 
  on 
  the 
  relationship 
  between 
  revenues 
  from 
  rate 
  schedules 
  and 
  revenue 
  derived 
  from 
  
individual 
  customers 
  within 
  a 
  rate 
  schedule. 
  The 
  workshop 
  also 
  will 
  include 
  a 
  discussion 
  of 
  DG 
  value 
  
studies 
  from 
  Washington 
  and 
  other 
  states; 
  utility 
  analyses 
  of 
  the 
  technical 
  benefits 
  of 
  DG 
  on 
  feeder 
  

 Timeline of Key State Activities on Net Energy Metering

55

 
  
lines 
  and 
  public 
  disclosure 
  of 
  this 
  information; 
  whether 
  utilities 
  have 
  strategies 
  for 
  participating 
  in 
  
the 
  DG 
  market 
  on 
  a 
  regulated 
  or 
  non-­‐regulated 
  basis; 
  and 
  the 
  potential 
  legal 
  or 
  regulatory 
  
impediments 
  to 
  these 
  strategies. 
  
o November 
  6, 
  2013: 
  Written 
  comments 
  due. 
  
o November 
  13, 
  2013: 
  Public 
  workshop. 
  Video 
  of 
  the 
  workshop 
  is 
  available. 
  
o December 
  19, 
  2013: 
  The 
  UTC 
  published 
  a 
  notice 
  of 
  opportunity 
  to 
  file 
  comments. 
  The 
  comments 
  
should 
  address 
  which 
  issues 
  the 
  UTC 
  should 
  consider 
  in 
  the 
  DG 
  investigation, 
  proposals 
  for 
  how 
  to 
  
address 
  these 
  issues, 
  and 
  what 
  process 
  would 
  best 
  facilitate 
  the 
  investigation. 
   
   
  
o January 
  31, 
  2014: 
  Comments 
  due.
•

Generic 
  rulemaking 
  to 
  consider 
  changes 
  to 
  interconnection 
  rules, 
  Docket 
  No. 
  UE-­‐112133 
  
o July 
  19, 
  2013: 
  Washington 
  Utilities 
  and 
  Transportation 
  Commission 
  (WA 
  UTC) 
  issued 
  a 
  final 
  order 
  
promulgating 
  interconnection 
  rule 
  changes 
  that 
  allow 
  third-­‐party 
  net 
  metering. 
  

 
  
Legislation 
  
 
  
• H.B. 
  1106: 
  Would 
  exclude 
  a 
  third-­‐party 
  owner 
  of 
  a 
  customer-­‐sited 
  renewable 
  energy 
  facility 
  from 
  the 
  
definition 
  of 
  electrical 
  company. 
  Increases 
  the 
  cumulative 
  generating 
  capacity 
  available 
  to 
  net 
  metering 
  
systems 
  from 
  0.25% 
  of 
  peak 
  demand 
  in 
  1996 
  to 
  0.5% 
  of 
  peak 
  demand 
  in 
  1996. 
  Also 
  changes 
  meter 
  
aggregation 
  for 
  customers, 
  limiting 
  customers 
  to 
  aggregating 
  no 
  more 
  than 
  199 
  kW 
  of 
  electricity 
  per 
  
billing 
  period. 
  (Companion 
  bill 
  S.B. 
  5707) 
  
o March 
  13, 
  2013: 
  Sent 
  to 
  Rules 
  Committee 
  for 
  second 
  reading. 
  Will 
  carry 
  over 
  to 
  the 
  next 
  session, 
  
which 
  begins 
  January 
  13, 
  2014. 
   
  
 
  
• H.B. 
  1289: 
  Allows 
  utilities 
  to 
  count 
  toward 
  RES 
  requirements 
  energy 
  dispatched 
  from 
  a 
  storage 
  facility 
  at 
  
2.5 
  times 
  its 
  output, 
  if 
  certain 
  conditions 
  are 
  met. 
   
  
o June 
  30, 
  2013: 
  Carried 
  over 
  upon 
  adjournment. 
   
  
 
  
• H.B. 
  2176: 
  Provides 
  mechanisms 
  for 
  low-­‐cost 
  financing 
  of 
  energy 
  systems 
  on 
  the 
  distribution 
  side 
  of 
  the 
  
electricity 
  grid. 
  Provides 
  utility 
  companies 
  or 
  third-­‐party 
  vendors 
  with 
  the 
  ability 
  to 
  offer 
  low-­‐cost 
  loans 
  
or 
  lease 
  programs 
  to 
  customers. 
  States 
  the 
  loans 
  and 
  leases 
  will 
  be 
  used 
  by 
  customers 
  for 
  renewable 
  
energy 
  systems. 
  Allows 
  the 
  electric 
  utility 
  priority 
  when 
  offering 
  loans 
  or 
  leases. 
  Allows 
  for 
  the 
  customer 
  
to 
  purchase 
  the 
  renewable 
  energy 
  system 
  at 
  the 
  end 
  of 
  the 
  leasing 
  period. 
  
o January 
  8, 
  2014: 
  Prefiled 
  for 
  introduction. 
  
o January 
  14, 
  2014: 
  Public 
  hearing 
  – 
  House 
  Technology, 
  Energy 
  and 
  Economic 
  Development 
  
Committee. 
  The 
  sponsor 
  is 
  the 
  Chairman 
  of 
  the 
  committee 
  of 
  reference. 
  The 
  sponsor, 
  Rep. 
  Jeff 
  
Morris 
  (D), 
  chairs 
  the 
  committee 
  and 
  has 
  a 
  track 
  record 
  for 
  legislation 
  that 
  has 
  encouraged 
  
renewable 
  energy 
  resources. 
  
o January 
  31, 
  2014: 
  Executive 
  session. 
  A 
  substitute 
  measure 
  was 
  adopted 
  and 
  passed 
  by 
  the 
  
committee 
  that 
  changed 
  some 
  of 
  the 
  types 
  of 
  energy 
  that 
  will 
  qualify 
  under 
  renewable 
  energy, 
  
minor 
  adjustments 
  to 
  net 
  metering 
  requirements, 
  and 
  erased 
  the 
  provision 
  that 
  would 
  have 
  allowed 
  
Renewable 
  Energy 
  Investment 
  Cost 
  Recovery 
  Program 
  to 
  extend 
  past 
  2021 
  and 
  gave 
  the 
  
Department 
  of 
  Ecology 
  the 
  responsibility 
  of 
  measuring 
  the 
  environmental 
  impact 
  of 
  leased 
  energy 
  
systems 
  and 
  energy 
  storage 
  systems. 
  

 Timeline of Key State Activities on Net Energy Metering

56

 
  
•

•

 
  
H.B. 
  2183: 
  States 
  the 
  Joint 
  Committee 
  on 
  Energy 
  Supply 
  and 
  Energy 
  Conservation 
  shall 
  make 
  
recommendations 
  to 
  the 
  energy 
  committees 
  of 
  the 
  legislature 
  that 
  would 
  establish 
  new 
  renewable 
  
energy 
  and 
  energy 
  efficiency 
  goals 
  for 
  utilities. 
  Recommendations 
  must: 
  encourage 
  renewable 
  energy 
  
resources, 
  promote 
  the 
  greatest 
  efficiency 
  in 
  using 
  existing 
  resources, 
  increase 
  efficiency 
  of 
  existing 
  
technology, 
  reduce 
  pollution 
  from 
  energy, 
  and 
  energy 
  consumption. 
   
  
o January 
  14, 
  2014: 
  Hearing 
  held 
  by 
  House 
  Committee 
  on 
  Technology 
  and 
  Economic 
  Development. 
  
Climate 
  Solutions, 
  New 
  Energy 
  Coalition, 
  WA 
  Utilities 
  and 
  Transportation 
  Commission, 
  and 
  WA 
  
Environmental 
  Council 
  testified 
  in 
  support. 
  The 
  only 
  group 
  to 
  oppose 
  the 
  measure 
  was 
  the 
  
Washington 
  Rural 
  Electric 
  Cooperative 
  Association. 
  
o January 
  24, 
  2014: 
  Work 
  sessions 
  held; 
  passed 
  with 
  favorable 
  recommendation. 
  
o February 
  12, 
  2014: 
  Passed 
  House 
  82-­‐16. 
  
o February 
  19, 
  2014: 
  Hearing 
  held 
  by 
  Senate 
  Committee 
  on 
  Energy, 
  Environment 
  and 
  
Telecommunications. 
  Puget 
  Sound 
  Energy 
  and 
  Northwest 
  Energy 
  Coalition 
  testified 
  in 
  support. 
  
There 
  was 
  no 
  testimony 
  against 
  this 
  measure. 
  PacifiCorp, 
  Washington 
  State 
  University 
  Energy 
  
Program 
  and 
  Washington 
  Public 
  Utilities 
  District 
  Association 
  testified 
  with 
  suggestions. 
  
S.B. 
  5807: 
  Encourages 
  utilities 
  to 
  invest 
  in 
  and 
  own 
  distributed 
  solar 
  generation 
  facilities. 
   
  
o June 
  30, 
  2013: 
  Carried 
  over 
  upon 
  adjournment. 
  

WEST 
  VIRGINIA 
  
Legislation 
  
 
  
• S.B. 
  471: 
  Would 
  amend 
  the 
  Alternative 
  and 
  Renewable 
  Energy 
  Portfolio 
  Act 
  to 
  establishes 
  a 
  solar 
  
renewable 
  energy 
  credit 
  (SREC) 
  system, 
  create 
  a 
  distributed 
  solar 
  requirement, 
  and 
  require 
  that 
  all 
  
SRECs 
  be 
  awarded 
  only 
  for 
  generation 
  facilities 
  in 
  WV. 
  
o February 
  3, 
  2014: 
  Introduced 
  and 
  referred 
  to 
  Senate 
  Energy, 
  Industry 
  and 
  Mining. 
  
 
  
• H.B. 
  2176: 
  Would 
  require 
  electric 
  utilities 
  to 
  credit 
  any 
  excess 
  customer-­‐owned 
  renewable 
  generation 
  to 
  
the 
  customer-­‐generator's 
  billing 
  cycle 
  for 
  the 
  next 
  month. 
  At 
  the 
  end 
  of 
  each 
  calendar 
  year, 
  the 
  electric 
  
utility 
  would 
  pay 
  the 
  customer-­‐generator 
  for 
  any 
  unused 
  energy 
  credits. 
  
o March 
  29, 
  2013: 
  Public 
  hearing 
  held. 
  Will 
  carry 
  over 
  to 
  next 
  session.

WISCONSIN 
  
Rates 
  and 
  Regulation 
  
•

 
  

Quadrennial 
  Planning 
  Process 
  II 
  for 
  Focus 
  on 
  Energy, 
  Docket 
  No. 
  5-­‐FE-­‐100. 
  Focus 
  on 
  Energy 
  is 
  a 
  
statutory 
  statewide 
  collection 
  of 
  energy 
  efficiency 
  and 
  renewable 
  resource 
  programs 
  that 
  has 
  been 
  in 
  
place 
  since 
  2001 
  and 
  is 
  funded 
  by 
  investor-­‐owned, 
  municipal 
  and 
  cooperative 
  utilities. 
   
  The 
  WI 
  Public 
  
Service 
  Commission 
  (PSC) 
  decisions 
  in 
  the 
  first 
  planning 
  process 
  covered 
  2011-­‐14. 
  The 
  second 
  process 
  
will 
  cover 
  2015-­‐18. 
  
o July 
  3, 
  2013: 
  Opened 
  statutory 
  investigation. 
  

 Timeline of Key State Activities on Net Energy Metering

57

 
  
o

o

•

•

January 
  9, 
  2014: 
  Order 
  setting 
  scope. 
  The 
  PSC 
  will 
  consider 
  issues 
  in 
  five 
  categories: 
  goals 
  and 
  
priorities, 
  cost-­‐effectiveness 
  of 
  programs, 
  renewable 
  energy, 
  energy-­‐water 
  nexus, 
  and 
  other 
  issues. 
  
Cost-­‐effectiveness 
  will 
  include 
  the 
  issue 
  of 
  avoided 
  costs 
  and 
  will 
  encompass 
  DG. 
  
January 
  30, 
  2014: 
  The 
  PSC 
  issued 
  a 
  request 
  for 
  comments 
  on 
  five 
  issues: 
  (1) 
  Focus 
  on 
  Energy’s 
  role 
  
in 
  cost-­‐effectively 
  meeting 
  federal 
  carbon 
  standards; 
  (2) 
  relative 
  emphasis 
  of 
  energy 
  and 
  demand 
  
savings; 
  (3) 
  overall 
  energy 
  goal 
  in 
  lieu 
  of 
  kilowatt-­‐hour 
  (kWh) 
  and 
  therm 
  goals; 
  (4) 
  rate 
  impact 
  
mitigation 
  strategies; 
  and 
  (5) 
  renewable 
  energy 
  issues. 
   
  
March 
  14, 
  2014: 
  Comments 
  due. 
  (Changed 
  from 
  previous 
  February 
  21 
  deadline.) 
  
Winter/Spring 
  2014: 
  Staff 
  to 
  prepare 
  memorandum 
  for 
  comment. 
  
July 
  2014: 
  PSC 
  decision(s). 
  
Summer/Fall 
  2014: 
  Program 
  administration 
  plans/designs 
  programs. 
  
January 
  2015: 
  New 
  “Focus 
  on 
  Energy” 
  program 
  begins. 
  

o
o
o
o
o
 
  
Generic 
  rulemaking 
  on 
  distributed 
  resources 
  interconnection 
  rules, 
  Docket 
  No. 
  05-­‐GF-­‐233 
  
o May 
  17, 
  2013: 
  The 
  WI 
  PSC 
  issued 
  a 
  notice 
  of 
  investigation 
  to 
  review 
  a 
  petition 
  filed 
  February 
  22, 
  
2013, 
  by 
  RENEW 
  Wisconsin 
  to 
  amend 
  existing 
  interconnection 
  rules, 
  including 
  establishment 
  of 
  a 
  
fast 
  track 
  process. 
   
  
o June 
  17, 
  2013: 
  Comments 
  due. 
  WI 
  PSC 
  proceeded 
  without 
  a 
  hearing. 
  
o October 
  10, 
  2013: 
  The 
  PSC 
  on 
  a 
  2-­‐1 
  vote 
  declined 
  to 
  open 
  a 
  rulemaking 
  to 
  consider 
  amendments 
  to 
  
the 
  interconnection 
  rules. 
  Utilities 
  had 
  commented 
  that 
  compensation 
  and 
  cost 
  recovery 
  are 
  more 
  
important 
  DG 
  issues. 
  While 
  the 
  focus 
  was 
  on 
  interconnect 
  issues, 
  the 
  two 
  commissioners 
  who 
  voted 
  
no 
  commented 
  that 
  the 
  bigger 
  issues 
  of 
  rate 
  design 
  and 
  recovery 
  of 
  costs 
  in 
  fairness 
  to 
  all 
  
ratepayers 
  need 
  to 
  be 
  addressed 
  first. 
  
o November 
  13, 
  2013: 
  Final 
  order 
  issued. 
  
 
  
Wisconsin 
  Public 
  Service, 
  Docket 
  No. 
  6690-­‐UR-­‐122 
  
o March 
  29, 
  2013: 
  WPS 
  filed 
  a 
  general 
  rate 
  case 
  with 
  the 
  PSC 
  proposing 
  to: 
  1) 
  raise 
  certain 
  customer 
  
charges, 
  2) 
  reduce 
  the 
  size 
  limit 
  of 
  net-­‐metered 
  customer 
  generators 
  from 
  100 
  kW 
  to 
  20 
  kW, 
  not 
  to 
  
exceed 
  the 
  customer’s 
  expected 
  load, 
  3) 
  grandfather 
  customers 
  receiving 
  the 
  full 
  retail 
  rate 
  for 
  
generation 
  above 
  monthly 
  usage 
  through 
  December 
  31, 
  2021, 
  and 
  4) 
  limit 
  net 
  metering 
  to 
  
customers 
  on 
  energy-­‐only 
  rate 
  schedules. 
  Note: 
  The 
  PSC 
  in 
  December 
  2012 
  authorized 
  increases 
  in 
  
customer 
  charges 
  for 
  two 
  other 
  Wisconsin 
  utilities, 
  which 
  essentially 
  set 
  the 
  stage 
  for 
  the 
  request 
  
made 
  by 
  WPS. 
  (See 
  items 
  below.) 
  
o November 
  6, 
  2013: 
  The 
  PSC 
  voted 
  on 
  the 
  issues. 
  Among 
  the 
  determinations: 
  
! “It 
  is 
  appropriate 
  to 
  increase 
  the 
  monthly 
  customer 
  charges 
  for 
  the 
  small 
  energy-­‐only 
  rate 
  
classes 
  to 
  $10.40 
  per 
  month 
  and 
  $12.50 
  per 
  month 
  for 
  residential 
  and 
  small 
  commercial 
  
customers, 
  respectively, 
  adjusted 
  for 
  the 
  final 
  revenue 
  requirement. 
   
  Commissioner 
  Callisto 
  
dissented 
  and 
  would 
  have 
  authorized 
  a 
  lower 
  monthly 
  customer 
  charge 
  increase. 
  …
! It 
  is 
  reasonable 
  to 
  reduce 
  the 
  capacity 
  limit 
  for 
  WPSC’s 
  Pg-­‐4 
  Net 
  Energy 
  Billing 
  service 
  from 
  
100 
  kilowatts 
  (kW) 
  to 
  20 
  kW. 
  Commissioner 
  Callisto 
  dissented 
  and 
  would 
  have 
  retained 
  the 
  
100 
  kW 
  capacity 
  limit. 
  … 
  
! It 
  is 
  not 
  necessary 
  at 
  this 
  time 
  to 
  open 
  an 
  investigation 
  into 
  the 
  costs 
  and 
  system 
  benefits 
  
associated 
  with 
  customer-­‐owned 
  generation. 
  These 
  issues 
  can 
  be 
  investigated 
  as 
  part 
  of 
  
utility-­‐specific 
  rate 
  cases 
  next 
  year. 
  Commissioner 
  Callisto 
  dissented 
  and 
  would 
  have 
  opened 
  

 Timeline of Key State Activities on Net Energy Metering

58

 
  

•

•

 
  

a 
  generic 
  docket 
  to 
  investigate, 
  on 
  a 
  utility-­‐wide 
  basis, 
  the 
  costs 
  and 
  system 
  benefits 
  
associated 
  with 
  customer-­‐owned 
  generation. 
  “ 
  
! The 
  commission 
  also 
  granted 
  a 
  renewable 
  advocate 
  request 
  to 
  change 
  monthly 
  netting 
  to 
  
annual 
  netting 
  for 
  net 
  metered 
  customers. 
   
  
o November 
  14, 
  2013: 
  The 
  PSC 
  issued 
  an 
  order 
  to 
  reopen 
  the 
  record 
  and 
  request 
  additional 
  
comments. 
   
  
o November 
  21, 
  2013: 
  Comments 
  due. 
  
o December 
  15, 
  2013: 
  Final 
  decision 
  expected. 
  
 
  
Madison 
  Gas 
  and 
  Electric, 
  Docket 
  No. 
  3270-­‐UR-­‐118 
  
o December 
  14, 
  2012: 
  The 
  PSC 
  issued 
  a 
  final 
  decision 
  approving 
  increases 
  in 
  fixed 
  charges, 
  including 
  a 
  
20% 
  increase 
  in 
  the 
  residential 
  customer 
  charge. 
  In 
  discussing 
  drivers 
  for 
  MGE’s 
  request 
  for 
  a 
  higher 
  
customer 
  charge, 
  MGE 
  Assistant 
  VP-­‐Energy 
  Planning 
  Greg 
  Bollom 
  testified 
  on 
  April 
  2, 
  2012: 
  “[O]n 
  
the 
  electric 
  side 
  of 
  our 
  business 
  growing 
  customer 
  interest 
  in 
  distributed 
  generation 
  has 
  increased 
  
the 
  need 
  for 
  MGE 
  to 
  get 
  its 
  rates 
  and 
  costs 
  in 
  better 
  alignment 
  to 
  prevent 
  costs 
  from 
  being 
  
inappropriately 
  shifted 
  amongst 
  different 
  customers.” 
  
 
  
We 
  Energies, 
  Docket 
  No. 
  5-­‐UR-­‐106 
  
o December 
  21, 
  2012: 
  The 
  PSC 
  issued 
  a 
  final 
  decision 
  approving 
  the 
  rate 
  design 
  proposed 
  by 
  the 
  
company, 
  including 
  a 
  20% 
  increase 
  in 
  the 
  residential 
  customer 
  charge 
  and 
  increases 
  in 
  demand 
  
charges 
  and 
  lesser 
  increases 
  in 
  energy 
  charges 
  for 
  the 
  commercial 
  and 
  industrial 
  rate 
  classes. 
  

 COMMISSIONERS Bob Stump

BOB STUMP - Chairman Chairman
GARY PIERCE
BRENDA BURNS Direct Line: (602) 542-3935
BOB BURNS Fax: (602) 542-0752
SUSAN AR IZONA PO RATION COM 15510 E-ma"= 

March 12, 2014

Mr. Lyndon Rive

Chief Executive Of?cer
SolarCity Corporation

c/o Court Rich

Rose Law Group PC

6613 N. Scottsdale Rd., Ste. 200
Scottsdale, AZ 85250

RE: In the Matter of the Commission ?3 Investigation of Value and Cost of Distributed Generation,
Docket No. 

Dear Mr. Rive:

Recently, it has come to my attention that Tucson Electric Power Company has
received a number of customer complaints related to certain provisions of its interconnection
agreement, which all net metering customers must sign. interconnection agreement includes a
speci?c disclaimer, similar to the one set forth in Decision No. 74202, which clearly informs
customers that rates and tariffs are subject to change.

Some customers, however, have complained that the disclaimer is inconsistent with
information that they have been given by their solar providers; speci?cally, they say that solar
providers have told them that the rates, rules, and regulations applicable to net metering are
?grandfathered,? thereby implying that the rates associated with net metering are not subject to
change. Customers are then surprised, disappointed, and angry to learn from TEP that this may not
be the case.

I am concerned that SolarCity and other solar providers may have made misstatements to
customers, leading them to believe that the rates, terms, and conditions of their net metering service
will be ?grandfathered? once they have initiated net metering service. As you know, the Commission
hasjurisdiction over rates as well as its terms and conditions of service, including net
metering. In next rate case, or in some other subsequent TEP proceeding concerning net
metering or rate design, ?grandfathering? is one possible outcome; however, it is presumptuous to
tell customers that such an outcome is certain.

Customers rely upon solar providers? representations to evaluate whether to sign up for the
services offered. I am concerned that you?as well as other solar providers?may be communicating
with customers in a way that is both confusing and misleading and which deprives them of the
balanced information that they need in order to make informed decisions.

1200 WEST WASHINGTON. PHOENIX. ARIZONA 35007-2996 9' 400 WEST CONGRESS 5THEET.TUCSON. AFIIZONA 85701-1347


 
  

March 12, 2014
Page Two

In 2010, the Commission issued a decision which concluded that SolarCity is not a public
service corporation. Your Form 10-Q, however, which was ?led with the Securities and Exchange
Commission in 2013, includes statements that lead me to question that result. For example, the
following assertion appears to indicate that SolarCity sells energy to end users:

We offer our customers the option to either purchase and own solar energy
systems or to purchase the energy that solar energy systems produce
through various ?nanced arrangements. These financed arrangements
include long-term contracts that we structure as leases and power purchase
agreements. In both ?nanced structures, we install solar energy
system at our customer?s premises and charge the customer a fee
for the power that system produces.

SolarCity Corporation Form 10-Q at 35 (Nov. 12, 2013) (emphasis added). Furthermore, I would
note that your footprint in our state is substantial, especially in the Tucson area.

I am concerned that you are providing a service that is ?clothed with the public interest,? but
that you may not be measuring up to the very high standards required of such entities. In light of
these recent complaints, I will be placing this matter on a Commission open meeting agenda in the
near future in order to discuss these important concerns with my fellow commissioners.

In the interim, I would appreciate your written and docketed response to the following
questions:

1) What kinds of representations/statements regarding utility rates, charges, and conditions of
service do your sales representatives or other personnel make to potential customers who are thinking
about subscribing to your service?

2) What kinds of training do your sales representatives or other personnel receive in order to
ensure that they are providing potential customers with accurate and balanced information regarding
utility rates, charges, and conditions of service?

3) What efforts does your company take to monitor your sales representatives and other
personnel to ensure that they provide potential customers with accurate and balanced information
regarding utility rates, charges, and conditions of service?

I am sure you will agree that providing accurate and balanced information to your customers
is of vital importance. Your responses to these questions will assist me as I consider these important
issues. I have not yet made up my mind on any of these issues, and I look forward to reviewing your
responses, which I would appreciate receiving by March 31, 2014.

With best gards, 

Bob Stump
Chairman

701 Avenue. NW. Washington. Emit-26% 
202.505.5e15 Mobile: 202.258.2i?9 emmer@eei.0rg

Power by Assecrerreev -

 

Edward H. Comer

Edison Electric
Vice President General [sunset 81 Corporate Secretanr

Institute

Friday, February 14, 2014

Docket Control, Arizona Corporation Commission
1200 West Washington Street
Phoenix, AZ 85007

Re: Comments on Value and Cost of Distributed Generation (Including Net Metering) 
000001-14-0023

Whom it may concern,

Attached please find an original plus 13 copies of the Edison Electric Institute (EEI) filing
comments in response to Value and Cost of Distributed Generation (Including Net Metering)

Docket Number 

appreciates the Opportunity to provide comments. Questions may be directed to Edward

Comer: ecomer@eei.org and (202) 508-5002.

Sincerely, 4? 
?fe/WM/ 

Edward H. Comer

Vice President, General Counsel 8: Corporate Secretary
Edison Electric Institute

701 Avenue, NW

Washington, Dc 20004 

BEFORE THE
ARIZONA CORPORATION COMMISSION
Value and Cost of Distributed Generation;
(Including Net Metering)

)
)
)

Docket No. E-00000J-14-0023

COMMENTS OF
THE EDISON ELECTRIC INSTITUTE
In response to the January 27, 2014, Arizona Corporation Commission (“ACC” or
“Commission”) notice (“Notice”) issued in the above-referenced docket, the Edison Electric
Institute (“EEI”), on behalf of its members, respectfully submits its comments to assist the
Commission in its inquiry into the relevance and significance of various categories for assigning
monetary values to distributed generation (“DG”) benefits and costs.
DG systems will play an increasing role in our nation’s generation mix. The electric
industry supports rate policies that appropriately recognize the value that the grid provides to DG
customers and DG customers provide to the distribution system. It is very important that state
commissions, such as the ACC, consider updates to current rate policies for DG, particularly as
the levels of DG penetration become more significant, because current policies that create crosssubsidies among customers are neither equitable nor sustainable. The Commission should keep
prominently in mind that, even as the nation continues to see its generation resource portfolio
evolve, the traditional rationale for cost of service regulation, namely the protection of
customers, has not abated.
Accordingly, EEI’s comments identify for the Commission’s consideration some basic
principles applicable to developing rates for utility services. EEI’s comments also discuss the
merits of including certain categories of DG costs and benefits in any approach for calculating

 the appropriate compensation for DG and the services provided by the electric grid that are
consistent with Commission policy and precedents and are fair to all customers.
EEI is the association of all U.S. investor-owned electric companies. Its members
provide electricity for 220 million Americans, directly employ more than 500,000 workers, and
operate in all 50 states and the District of Columbia. With more than $85 billion in annual
capital expenditures, the electric power industry is responsible for millions of additional jobs.
Reliable, affordable, and sustainable electricity powers the economy and enhances the lives of all
Americans. EEI has 70 international electric companies as Affiliate Members, and 250 industry
suppliers and related organizations as Associate Members. Organized in 1933, EEI provides
public policy leadership, strategic business intelligence, and essential conferences and forums.
EEI submits these comments because the relative costs and benefits of DG are an issue facing the
investor-owned utility industry as a whole. EEI and its member companies therefore have a
substantial interest in this proceeding.
COMMENTS
EEI is pleased to submit comments responding to the Commission’s questions as to what
factors should be considered in developing a process and methodology for assigning prices to
DG benefits and costs. EEI commends the Commission for establishing this inquiry because
clarity as to what costs and benefits belong in setting rates for electricity and grid services will
provide all customers with greater transparency in pricing and is an essential tool in preventing
cost shifting and inequities for electricity customers. It is very important that this process and
methodology work in a sustainable way to enable new distributed generation customers to
participate fairly in electricity markets. If such a process and methodology sets artificially high

2

 prices for DG power, then it will result in market distortions that adversely impact both utilities
and their customers, in particular the customers least likely to install a DG system.
There is an important role for all kinds of electric generation, including distributed
generation such as rooftop solar generation, but it is important to integrate these sources in a
manner that achieves the lowest cost, reliable and environmentally sustainable approach for all
customers. EEI believes that rates paid to DG customers must be developed in a way that is
consistent with the methodologies used to develop rates for utility services and as compensation
for other comparable resources in order to avoid double-counting and long-term market
distortions. Moreover, any incentives for DG should be transparent and periodically reexamined,
especially in light of existing market maturity. While incentives such as limited net metering
were instituted to jump-start nascent markets for DG systems, markets have substantially
evolved and as a result these subsidies have served their intended purpose and should not be
extended or expanded.
I. Compensation for Distributed Generation Should be Cost-Based
Over many years of utility regulation, regulators have adopted, as a fundamental rule, the
proposition that regulation should be based on the costs of service, not the value of service.
They developed this approach because costs are readily observable whereas “value” of service
propositions are inherently uncertain and speculative and tend to lead to much greater
uncertainty. Therefore, rates for utility service like electricity, transmission and distribution
services are set so that customers pay for the costs of the services they receive from their utility
and the electric power grid. Furthermore, regulation attempts to allocate costs so that customers
pay for the costs incurred to serve them, not for costs incurred to serve other customers. These

3

 principles should apply to the services electric utilities provide to all customers, including
customers with DG systems. Proper cost identification and allocation are essential to fair
ratemaking and the avoidance of hidden cross-subsidies. Deviations from this policy lead to
distorted incentives and diseconomies that are not sustainable over time.
The rationale for, and benefits of, cost of service regulation have not disappeared:
Consumer protection. These cost of service principles do not allow for rate making based on
subjective valuations. Electric rates have historically been based on the known and measurable
cost of providing electric service, as approved by state regulators, and EEI believes this wellestablished approach to setting rates must apply to any methodology for determining adequate
compensation for DG.
Many DG advocates argue that the benefits DG installations provide to utility systems
and to society are very large and that such benefits should be used to offset a substantial portion
of the costs utilities incur to serve DG customers. Essentially, they argue that the benefits of DG
should be priced on the basis of its value, while the benefits of electricity service, as well as other
generation resources, should be priced based on their cost. This approach is fundamentally
unfair, unduly discriminatory and inconsistent with the traditional approach to regulation. Rateregulated utilities are able to recover only those actual costs they incur, as reflected in their
books of account, and only that portion that was prudently incurred. These costs make their way
into required revenues and are recovered in rates approved by state regulatory commissions.
This process provides certainty and transparency, and is the basis for consumer protection.
Furthermore, this is the construct that investors rely on when providing capital to investor-owned

4

 electric utilities and that underlies the U.S. Supreme Court’s standards for just and reasonable
rates.
II. Any DG Compensation Methodology Should Be Non-Discriminatory and Resulting
Rates Based on Known and Measurable Costs
It is important to establish that the basic payment system for power produced by both
distributed and utility generators is consistent and not unduly discriminatory. This is particularly
critical in light of the Commission’s finding that the net-metering tariff does cause a cost-shift
between DG and non-DG customers.1 To do this, amounts of electricity purchased by and sold
to DG customers should be separately quantified and separately valued. Simply subtracting the
amount of electricity that a DG customer generates from the amount of electricity the customer
purchases from the local utility (as is typically done under current net metering) does not occur
simultaneously and therefore does not accurately reflect the cost of electricity and grid services
that utilities provide to a DG customer. Thus, this shifts substantial costs to customers that do
not self-generate.
Correspondingly, customers with DG systems should pay for all of the services that
electric utilities provide to them, including distribution, transmission, and standby generation.
Customers who do not net meter should not subsidize those who do. DG customers should be
required to pay for grid services because these customers are connected to and still use the grid,
but in more complex ways than other customers. This is confirmed by the fact that as DG
installations increase then utilities must invest in new control systems, modify operating

1

EEI also appreciates that the ACC has indicated that evaluation of this cost-shifting will be an ongoing process and
that this cost-shifting will be evaluated in the future.

5

 procedures, and train operating personnel to safely and reliably accommodate DG systems on the
grid.
DG customers should be compensated for their electricity sales at rates commensurate
with what it costs electric utilities to serve their customers by producing electricity or purchasing
it in the wholesale market. DG customers should receive a credit for reducing electric utility
costs only if there are identifiable, verifiable costs that utilities save as a result of DG systems
being added at specific locations. Including intangible or difficult to measure components in the
process will ultimately lead to lack of confidence in the end product. Moreover, less-thancredible inputs will lead to significant disagreement among stakeholders, resulting in a costly and
less-than-optimal process. Furthermore, basing rates on the “value of solar” will have the
unintended consequence of constituting a regulatory barrier to other renewable technologies or
types of generation resources.
The Commission should instead require a methodology that includes only costs that are
measurable and verifiable. This will serve to protect non-DG customers, the vast majority of all
customers, from paying for benefits that are speculative, sensitive to unverifiable assumptions,
lack standard calculation approaches, or otherwise may not actually materialize as expected. The
methodology should rely on standard approaches to quantifying the cost of avoided energy,
capacity and system losses, applying the same degree of rigor that is used in evaluating demand
side management (“DSM”) and similar resources, especially if utilities are required to purchase
the output of DG systems. To this end, the evaluation of net metering and other billing policies
for DG should include an assessment of the services that DG customers still take from the utility
and the appropriate and fair payment for those services.

6

 A. Transmission and Generation Capacity Costs Are Not Avoided Until actual
projects are demonstrated to be deferred or canceled
EEI believes that although avoided transmission and distribution may be theoretically
relevant to determining adequate compensation for DG, the measurement of such components is
too speculative at this time. Currently, data does not support the notion that DG will assist in
capacity value for the grid because solar does not generally reduce peak use. This is largely due
to the fact that peak demand of residential customers occurs later in the afternoon and in the
early evening after solar resources have substantially reduced or even stopped producing energy
(i.e., peak-demand is not well correlated with solar output).
Moreover, transmission and generation capacity is not necessarily avoided, but in some
cases could be deferred. Nevertheless, even in the case of a possible delayed investment,
reliability rules and the way that integrated resource planning (“IRP”) or the rules in organized
markets work requires that utilities plan as if DG systems were not there at any time during a 2040 year planning horizon. Rules need to change for utilities to be able to take DG systems into
account in their planning processes. Once those rules are in place then coincident capacity
savings can potentially occur, but not before. Nevertheless, the threshold for considering
whether there are avoided capacity savings arising from DG associated with the distribution
system should be whether such benefits are known and measurable to the utility.
B. Any Methodology for Assigning Value to DG Must Account for DG Integration
Costs, including Increased Costs of Ancillary Services
With respect to grid support services, EEI believes it is important for the Commission to
recognize that because of the wide variability of DG solar systems and their outputs, the need for
ancillary services will increase and that will necessarily impose additional cost on the utility.

7

 Furthermore, it makes no sense to provide a credit for avoided grid costs to distributed generators
unless they also pay the underlying grid costs themselves.
In considering rates for distributed generators, it is fundamental to recognize the fact that
any DG system connected to the transmission and distribution system continues to use grid
services. Transmission and distribution system operators must take these new systems into
account to preserve the continued reliability, safety, and security of the grid. While customers
with DG systems generate some or all of their own electricity, they are still connected to the
local electric utility’s grid and use the grid both to buy power from their electric utility during
times when their DG systems are not producing enough to meet their needs and to sell power to
their electric utility when their systems are producing more electricity than the customers need.
DG customers are connnected to the grid and using grid services 24/7.2 In fact, interconnected
DG transforms the distribution system from a one-way delivery mode into a complex two-way
network for which electricity flows need to be carefully monitored and balanced.
Recent experiences in Germany and Hawaii and a recent study conducted by North
American Electric Reliability Corporation and the California ISO all demonstrate that high DG
penetration complicates the design and operation of the distribution grid and requires electric
utilities to invest in new systems to assure that the grid remains safe and reliable.3 Without such
utility-provided safeguards, the grid and customer equipment can become damaged. In this
regard, the Commission should include the integration costs associated with additional DG on a

2

See attached Exhibit A.

3

See http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERCCAISO_VG_Assessment_Final.pdf

8

 distribution system into any evaluation of avoided or delayed transmission and distribution
system costs.
C. The Commission Should Consider Only Known and Measurable Avoided
Costs/Financial Risks
With respect to the cost of energy and its delivery, the avoided energy costs are variable
costs associated with the price of energy, such as fuel, variable O&M and generation unit starts
that are avoided due to generation of DG. They are reflected directly in utility costs and rates.
Therefore it would be double-counting to pay this amount to DG generators. Also, in
quantifying displaced resources, current market prices should be used.
Costs associated with hedging and market price mitigation would only be applicable if it
was possible to know exactly what type of generation was displaced by the DG system.
Moreover, if there is a reduction of market prices for energy because of DG systems, it is
precisely that reduction that represents its compensation. DG systems should not be
compensated directly for reducing market prices. For example, wind power is not separately
compensated because of its impact on wholesale markets. It is the price for the sale of the power
itself that constitutes the compensation. Additionally, solar DG does not avoid Renewable
Energy Standard costs, but increases them since it makes procuring renewable energy more
expensive than if the utility were to purchase it from lower cost central station renewables.
D. Grid Security and Reliability Values Should Not Be Considered In Rates
Grid security and reliability are significant interests, but values for such measures are
difficult to quantify. Maintaining security and reliability require significant investment in the
grid by electric utilities, and yet electric utilities are not additionally compensated for the value
of providing these essential services to their customers. Rather, compensation is based on the
9

 cost of needed services. Even if it can be determined that DG systems may make known and
measureable net contributions to the security and reliability of the system, recognizing that these
systems may also present a negative impact to grid security and reliability, they should not
receive additional compensation just as utilities do not receive additional compensation for
similar contributions.
E. Environmental and Social Externalities Should Not Be Included in DG Rates
While solar energy has an important and increasingly larger role to play in our energy
mix, and the “value of solar” is important in considering future investment plans, this “value”
has no role in setting wholesale and retail electricity rates. Prices paid for renewable energy
from distributed generators should not include a value for externalities such as avoided emissions
and jobs, unless these are allowed to be recovered in utility rates. Treatment of such externalities
should be consistent for all customers and all resource types.
All sources of electric generation provide substantial jobs and economic benefits; electric
utilities are typically major drivers of their state and local economies. EEI is not aware of a
public utility commission that allows utilities to recover in their rates any of these values with
respect to central station solar, wind, or nuclear power and does not believe it would be equitable
for only DG solar to do so. If societal benefits are not charged for in utility rates, they should be
excluded from the methodology for developing rates to distributed generators.
In addition, there is no agreed method for measuring and verifying societal benefits. The
approaches developed to date, including the federal government’s proposals on the “social cost
of carbon,” (“SCC”) are admittedly highly uncertain and speculative. The SCC is a range of
estimates of the monetized damages associated with an incremental increase in carbon dioxide
10

 (“CO2”) emissions in a given year. The Interagency Working Group (“IWG”), spearheaded by
the White House Office of Management and Budget, develops these estimates to allow federal
agencies to incorporate the social benefits of reducing CO2 emissions into the required costbenefit analyses of regulatory actions that would affect cumulative global emissions. As the
IWG has noted, any efforts to assess the incremental impacts of CO2 emissions suffer from
uncertainty, speculation and a lack of information about future emissions, the effects of past and
future emissions on the climate system, the impact of changes in the climate on the physical and
biological environment and the translation of these estimates into economic damages. Due to the
serious limitations, both in terms of quantification and monetization, the IWG presents a range of
possible SCC estimates. For example, the 2015 estimates (computed by the IWG 2013) range
from $12 to $109 per metric ton of CO2 in 2007 dollars. These predictions are highly speculative
and variations are highly sensitive to small changes in assumption for factors such as the
discount rate. Accordingly, EEI does not believe the Commission should consider SCC in a
methodology for determining DG compensation.
CONCLUSION
WHEREFORE, for the foregoing reasons, the Edison Electric Institute respectfully
requests that the Commission accept these comments, and urges the Commission to adopt the
recommendations as set forth above to focus its analysis of the cost and benefits of DG solar on
the types of costs and proof requirements that the Commission applies in approving the rates that
utilities may charge to their customers.

11

 Dated: February 14, 2014

Respectfully submitted,

Edward H. Corner

Vice President, General Counsel and Corporate
Secretary

Aryeh Fishman

Associate General Counsel, Regulatory Legal
Affairs

Edison Electric Institute

701 Avenue, NW

Washington, DC 20004-2696

(202) 508-5000

Email: ecomer@eei.org


12

Exhibit A

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13

Studies

 

 

 POWER
RESEARCH INSTITUTE

 



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REALIZING THE FULL VALUE OF CENTRAL
AND DISTRIBUTED ENERGY RESOURCES

Access the full re art on Web site.

 

 

California 
  Net 
  Energy 
  Metering 
  (NEM) 
  
Draft 
  Cost-­‐Effectiveness 
  Evaluation 
   
  

NEM 
  Study 
  Introduction 
  
Prepared 
  by 
  
California 
  Public 
  Utilities 
  Commission 
  
Energy 
  Division 
  
 
  
September 
  26, 
  2013 
  
Project 
  Manager 
  
Ehren 
  Seybert 
  

Editors 
  
Gabe 
  Petlin, 
  Katie 
  Wu 
  

Supervisor 
  
Melicia 
  Charles 
  

Technical 
  Report 
  by 
  
Energy 
  and 
  Environmental 
  Economics, 
  Inc. 
   
  

 CPUC 
  NEM 
  Report 
  Introduction 
  

Introduction 
  to 
  the 
  Draft 
  Net 
  Energy 
  Metering 
  Cost-­‐
Effectiveness 
  Evaluation 
  

 
  
The 
   California 
   Public 
   Utilities 
   Commission 
   (CPUC) 
   has 
   contracted 
   with 
   Energy 
   and 
  
Environmental 
  Economics, 
  Inc. 
  (E3) 
  to 
  provide 
  an 
  evaluation 
  of 
  the 
  costs 
  and 
  benefits 
  of 
  the 
  net 
  
energy 
  metering 
  (NEM) 
  program 
  in 
  California. 
  This 
  study 
  fulfills 
  the 
  requirements 
  of 
  Assembly 
  
Bill 
   (AB) 
   2514 
   (Bradford, 
   2012) 
   and 
   Commission 
   Decision 
   (D.) 
   12-­‐05-­‐036, 
   to 
   study 
   “who 
  
benefits, 
  and 
  who 
  bears 
  the 
  economic 
  burden, 
  if 
  any, 
  of 
  the 
  net 
  energy 
  metering 
  program” 
  by 
  
October 
   1, 
   2013. 
    
   This 
   study 
   also 
   serves 
   as 
   an 
   update 
   to 
   the 
   CPUC’s 
   2010 
   NEM 
   Cost-­‐
Effectiveness 
  Evaluation.1 
  
 
  
NEM 
  is 
  an 
  electricity 
  tariff 
  billing 
  mechanism 
  designed 
  to 
  facilitate 
  the 
  installation 
  of 
  renewable 
  
customer 
   distributed 
   generation 
   (DG). 
    
   Under 
   NEM 
   tariffs, 
   customers 
   receive 
   a 
   bill 
   credit 
   for 
  
generation 
  that 
  is 
  exported 
  to 
  the 
  electric 
  grid 
  during 
  times 
  when 
  it 
  is 
  not 
  serving 
  onsite 
  load. 
  
Bill 
   credits 
   for 
   the 
   excess 
   generation 
   are 
   applied 
   to 
   a 
   customer’s 
   bill 
   at 
   the 
   same 
   retail 
   rate 
  
(including 
   generation, 
   distribution, 
   and 
   transmission 
   components) 
   that 
   the 
   customer 
   would 
  
have 
  paid 
  for 
  energy 
  consumption, 
  according 
  to 
  their 
  otherwise 
  applicable 
  rate 
  schedule. 
   
  This 
  
study 
   also 
   provides 
   a 
   separate 
   evaluation 
   of 
   the 
   NEM 
   fuel 
   cell 
   program, 
   which 
   credits 
   the 
  
generation 
   only 
   component 
   of 
   the 
   rate 
   for 
   participating 
   fuel 
   cells 
   that 
   achieve 
   targeted 
  
reductions 
  in 
  greenhouse 
  gas 
  emissions. 
  

 
  

Role 
  of 
  the 
  CPUC's 
  Energy 
  Division 
  in 
  the 
  Evaluation 
  
 
  
The 
   CPUC's 
   Energy 
   Division 
   was 
   responsible 
   for 
   contracting 
   with 
   E3 
   and 
   overseeing 
   the 
  
development 
  of 
  this 
  report. 
   
  Energy 
  Division 
  initiated 
  the 
  contract 
  process 
  in 
  the 
  spring 
  of 
  2012, 
  
and 
  E3 
  was 
  selected 
  following 
  a 
  competitive 
  bidding 
  process. 
   
   
  
 
  
In 
   October 
   2012, 
   Energy 
   Division 
   hosted 
   a 
   well-­‐attended 
   workshop 
   where 
   E3 
   consultants 
  
previewed 
   the 
   methodology 
   and 
   scope 
   of 
   the 
   cost-­‐benefit 
   analysis, 
   avoided 
   public 
   purpose 
  
charges, 
   and 
   income 
   distribution 
   sections 
   of 
   the 
   attached 
   report. 
   Formal 
   comments 
   were 
  
solicited 
  from 
  interested 
  parties 
  on 
  November 
  5, 
  2012, 
  and 
  reply 
  comments 
  were 
  received 
  on 
  
November 
   15, 
   2012. 
    
   E3 
   provided 
   responses 
   to 
   comments 
   in 
   the 
   December 
   study 
   scope 
   of 
  
work. 
   
  Unfortunately, 
  due 
  to 
  delays 
  in 
  processing 
  the 
  funding 
  needed 
  to 
  conduct 
  the 
  full 
  cost 
  of 
  
service 
  analysis, 
  the 
  methodology 
  for 
  the 
  NEM 
  full 
  cost 
  of 
  service 
  calculation 
  was 
  not 
  available 
  
for 
  public 
  comment. 
   
  Utility 
  costs 
  of 
  service 
  were 
  emulated 
  from 
  the 
  methodology 
  filed 
  by 
  each 
  
utility 
  in 
  its 
  most 
  recent 
  General 
  Rate 
  Case 
  (GRC). 
   
   
  
 
  

1

 
  http://www.cpuc.ca.gov/NR/rdonlyres/0F42385A-­‐FDBE-­‐4B76-­‐9AB3-­‐E6AD522DB862/0/nem_combined.pdf 
  

1 
  

 CPUC 
  NEM 
  Report 
  Introduction 
  

The 
  attached 
  NEM 
  Cost-­‐Effectiveness 
  Evaluation 
  is 
  a 
  draft 
  report 
  prepared 
  by 
  E3, 
  and 
  further 
  
refinements 
  may 
  be 
  necessary 
  based 
  on 
  solicited 
  comments 
  to 
  the 
  draft 
  report. 
  Parties 
  should 
  
not 
  cite 
  this 
  as 
  a 
  CPUC 
  report 
  or 
  cite 
  the 
  findings 
  in 
  this 
  version 
  of 
  the 
  report 
  as 
  conclusive. 
   
  

 
  

Comments 
  on 
  the 
  Draft 
  Report 
  
 
  
Energy 
   Division 
   invites 
   stakeholders 
   to 
   submit 
   informal 
   comments 
   on 
   the 
   analytics 
   and 
  
assumptions 
   used 
   in 
   E3's 
   draft 
   analysis, 
   in 
   support 
   of 
   our 
   finalizing 
   the 
   2013 
   NEM 
   Study. 
  
Comments 
  should 
  focus 
  on 
  and 
  be 
  limited 
  to 
  errors 
  in 
  the 
  calculations 
  used 
  in 
  the 
  report, 
  and 
  
be 
   no 
   longer 
   than 
   five 
   (5) 
   pages 
   in 
   length. 
   Interested 
   parties 
   should 
   email 
   comments 
   to 
   Mr. 
  
Ehren 
  Seybert 
  (Ehren.Seybert@cpuc.ca.gov) 
  by 
  October 
  10, 
  2013. 
   
  All 
  comments 
  received 
  will 
  
be 
  posted 
  to 
  the 
  CPUC’s 
  NEM 
  study 
  webpage 
  along 
  with 
  responses 
  from 
  E3.2 
   
  
 
  
Previous 
  presentation 
  materials, 
  stakeholder 
  comments, 
  and 
  the 
  draft 
  and 
  final 
  scope 
  of 
  work 
  
are 
  available 
  on 
  the 
  CPUC’s 
  NEM 
  study 
  webpage. 
   
  

 
  

Scope 
  of 
  the 
  Evaluation 
  
 
  
When 
  the 
  CPUC’s 
  Energy 
  Division 
  initiated 
  the 
  contract 
  process 
  for 
  an 
  evaluation 
  of 
  NEM 
  in 
  the 
  
spring 
  of 
  2012, 
  the 
  primary 
  focus 
  of 
  the 
  evaluation 
  was 
  to 
  incorporate 
  an 
   updated 
  and 
  more 
  
robust 
  data 
  set 
  to 
  the 
  prior 
  methodologies 
  used 
  in 
  the 
  2010 
  NEM 
  Cost-­‐Effectiveness 
  Evaluation. 
   
  
At 
   the 
   time, 
   the 
   analysis 
   was 
   limited 
   to 
   the 
   costs 
   and 
   benefits 
   of 
   generation 
   exports 
   to 
   the 
  
electric 
  grid. 
  Following 
  the 
  request 
  for 
  proposals 
  (RFP) 
  for 
  the 
  study, 
  however, 
  two 
  mandates 
  
were 
   adopted 
   – 
   Commission 
   D. 
   12-­‐05-­‐036 
   in 
   May 
   2012, 
   and 
   AB 
   2514 
   in 
   September 
   2012 
   – 
  
which 
  added 
  significant 
  breadth 
  and 
  scope 
  to 
  the 
  study. 
  These 
  additional 
  tasks 
  include: 
  
 
  
(1) A 
  cost-­‐benefit 
  study 
  of 
  NEM 
  at 
  the 
  capacity 
  needed 
  to 
  reach 
  the 
  solar 
  photovoltaic 
  goals 
  
of 
  the 
  California 
  Solar 
  Initiative 
  and 
  the 
  5% 
  net 
  energy 
  metering 
  program 
  cap. 
  The 
  costs 
  
and 
  benefits 
  of 
  NEM 
  should 
  be 
  evaluated 
  relative 
  to 
  energy 
  that 
  is 
  exported 
  to 
  the 
  grid 
  
and 
  energy 
  consumed 
  onsite. 
   
  
(2) An 
  evaluation 
  of 
  the 
  extent 
  to 
  which 
  NEM 
  customers 
  pay 
  their 
  share 
  of 
  utility 
  costs. 
   
  
(3) An 
  estimate 
  of 
  the 
  reduction 
  in 
  public 
  purpose 
  charges 
  avoided 
  by 
  NEM 
  customer-­‐
generators. 
   
  
(4) An 
  income 
  demographic 
  assessment 
  for 
  residential 
  customers 
  with 
  NEM 
  generation. 
  
 
  
Unfortunately, 
   the 
   inclusion 
   of 
   multifaceted 
   analytical 
   approaches, 
   at 
   different 
   penetration 
  
levels, 
   precludes 
   a 
   single, 
   simplified 
   answer 
   to 
   the 
   underlying 
   question 
   that 
   we 
   are 
   trying 
   to 
  
address: 
   That 
   is, 
   who 
   benefits 
   from, 
   and 
   who 
   bears 
   the 
   economic 
   burden, 
   if 
   any, 
   of 
   the 
   net 
  
energy 
  metering 
  program? 
   
  However, 
  when 
  taken 
  together, 
  the 
  various 
  analyses 
  included 
  in 
  the 
  
2

 
  http://www.cpuc.ca.gov/PUC/energy/Solar/nem_cost_effectiveness_evaluation.htm 
  

2 
  

 CPUC 
  NEM 
  Report 
  Introduction 
  

attached 
  NEM 
  Cost-­‐Effectiveness 
  Evaluation 
  shed 
  new 
  light 
  on 
  the 
  impacts 
  of 
  the 
  NEM 
  program 
  
in 
   California, 
   provided 
   that 
   the 
   results 
   are 
   interpreted 
   alongside 
   the 
   metrics 
   used 
   in 
   the 
  
evaluation, 
  and 
  in 
  the 
  context 
  of 
  current 
  DG 
  policies 
  and 
  utility 
  operations. 
   
  Two 
  of 
  the 
  more 
  
complex 
  issues 
  included 
  in 
  the 
  report 
  are 
  discussed 
  in 
  more 
  detail 
  below. 
   
   
   
  
 
  
Lastly, 
   it 
   is 
   important 
   to 
   note 
   that 
   the 
   attached 
   NEM 
   Cost-­‐Effectiveness 
   Evaluation 
   is 
   focused 
  
exclusively 
   on 
   the 
   utility 
   ratepayer 
   impacts 
   of 
   NEM, 
   and 
   does 
   not 
   include 
   the 
   overall 
   societal 
  
benefits 
   from 
   the 
   deployment 
   of 
   clean 
   energy 
   resources, 
   although 
   significant 
   environmental, 
  
public 
   health 
   and 
   other 
   non-­‐energy 
   benefits 
   occur. 
   The 
   importance 
   of 
   the 
   environmental 
  
benefits 
  that 
  result 
  from 
  of 
  the 
  deployment 
  of 
  renewable 
  generation 
  is 
  well 
  established 
  within 
  
the 
   California 
   Energy 
   Action 
   Plan, 
   and 
   is 
   reflected 
   in 
   a 
   number 
   of 
   the 
   state’s 
   DG 
   policies, 
  
including 
   the 
   Go 
   Solar 
   California 
   campaign, 
   the 
   Commission’s 
   Self-­‐Generation 
   Incentive 
  
Program, 
  as 
  well 
  as 
  the 
  NEM 
  program. 
   
   
  

NEM 
  Cost-­‐Benefit 
  Analysis 
  vs. 
  Full 
  Cost 
  of 
  Service 
   
  
 
  
At 
   its 
   most 
   basic 
   level, 
   the 
   attached 
   study 
   employs 
   two 
   separate 
   ratepayer 
   impact 
   measures: 
   A 
  
cost-­‐benefit 
   analysis 
   of 
   the 
   NEM 
   program 
   using 
   the 
   traditional 
   California 
   Standard 
   Practices 
  
Manual 
   (SPM) 
   Ratepayer 
   Impact 
   (RIM) 
   test, 
   which 
   estimates 
   the 
   net 
   benefits 
   (or 
   costs) 
   of 
   a 
  
demand-­‐side 
  resource 
  or 
  program 
  from 
  the 
  perspective 
  of 
  non-­‐participating 
  customers, 
  and 
  a 
  
full 
  cost 
  of 
  service 
  assessment, 
  which 
  compares 
  the 
  utility 
  cost 
  of 
  serving 
  NEM 
  customers 
  with 
  
their 
  actual 
  bill 
  payments. 
   
   
   
  
 
  
In 
  the 
  cost-­‐benefit 
  analysis, 
  E3 
  evaluates 
  the 
  change 
  in 
  utility 
  costs 
  associated 
  with 
  the 
  change 
  
in 
   usage 
   due 
   to 
   the 
   installation 
   of 
   DG. 
   If 
   the 
   customer 
   bill 
   savings 
   resulting 
   from 
   NEM 
   are 
  
greater 
  than 
  the 
  corresponding 
  reduction 
  in 
  utility 
  costs, 
  NEM 
  will 
  create 
  a 
  cost 
  shift 
  from 
  NEM 
  
customers 
  to 
  other 
  non-­‐participating 
  customers 
  as 
  utilities 
  adjust 
  their 
  rates 
  to 
  compensate 
  for 
  
the 
   shortfall. 
   Alternatively, 
   if 
   the 
   reductions 
   in 
   customer 
   bill 
   savings 
   are 
   less 
   than 
   the 
   reduction 
  
in 
  utility 
  costs, 
  non-­‐participating 
  customers 
  experience 
  a 
  net 
  benefit. 
  Note 
  that 
  this 
  approach 
  
does 
   not 
   address 
   or 
   reflect 
   any 
   pre-­‐existing 
   cost 
   shift 
   onto 
   NEM 
   customers 
   prior 
   to 
   the 
  
installation 
  of 
  distributed 
  generation. 
  
 
  
In 
   the 
   full 
   cost 
   of 
   service 
   analysis, 
   E3 
   evaluates 
   the 
   total 
   cost 
   to 
   serve 
   the 
   remaining 
   energy 
  
usage 
  after 
  accounting 
  for 
  the 
  change 
  in 
  usage 
  due 
  to 
  the 
  installation 
  of 
  DG. 
  The 
  cost 
  of 
  service 
  
assessment 
   compares 
   the 
   actual 
   bills 
   that 
   NEM 
   customers 
   pay 
   to 
   the 
   utility 
   costs 
   (including 
  
fixed 
  costs) 
  needed 
  to 
  serve 
  those 
  customers. 
   
   
  Utility 
  costs 
  of 
  service 
  are 
  emulated 
  from 
  the 
  
methodology 
  that 
  each 
  utility 
  used 
  in 
  their 
  most 
  recent 
  GRC. 
  
 
  
Despite 
  the 
  use 
  of 
  different 
  metrics, 
  a 
  central 
  driver 
  in 
  both 
  the 
  cost-­‐benefit 
  and 
  cost 
  of 
  service 
  
analyses 
   is 
   current 
   retail 
   rate 
   designs. 
    
   For 
   residential 
   NEM 
   customers, 
   tiered 
   rates 
   (for 
   which 
   a 
  
customer’s 
   marginal 
   electricity 
   rate 
   increases 
   with 
   cumulative 
   usage) 
   and 
   tiered 
   time-­‐of-­‐use 
  
rates 
  are 
  the 
  most 
  commonly 
  subscribed. 
   
  As 
  described 
  in 
  more 
  detail 
  below, 
  changes 
  to 
  the 
  
tiered 
   rates 
   would 
   have 
   a 
   significant 
   impact 
   on 
   the 
   study 
   results. 
    
   Similarly, 
   differences 
   in 
   retail 
  

3 
  

 CPUC 
  NEM 
  Report 
  Introduction 
  

rates 
  should 
  be 
  an 
  important 
  consideration 
  for 
  policymakers 
  outside 
  of 
  California 
  that 
  are 
  using 
  
this 
  study. 
   
   
  

 
  

Export 
  Only 
  vs. 
  All 
  NEM 
  Generation 
  
 
  
One 
   of 
   the 
   key 
   drivers 
   of 
   the 
   magnitude 
   of 
   any 
   cost 
   impact 
   is 
   what 
   generation 
   is 
   measured. 
   
  
Pursuant 
   to 
   AB 
   2514, 
   the 
   cost-­‐benefit 
   analysis 
   included 
   in 
   this 
   study 
   considers 
   all 
   NEM 
  
generation 
  as 
  well 
  as 
  only 
  the 
  generation 
  that 
  is 
  exported 
  to 
  the 
  grid. 
   
   
  
 
  
The 
  most 
  explicit 
  impact 
  of 
  NEM 
  is 
  associated 
  with 
  energy 
  exports 
  to 
  the 
  grid; 
  both 
  NEM 
  and 
  
Non-­‐NEM 
  DG 
  receive 
  bill 
  reductions 
  during 
  hours 
  when 
  generation 
  is 
  offsetting 
  onsite 
  load, 
  but 
  
only 
  NEM 
  customers 
  receive 
  bill 
  credit 
  for 
  generation 
  that 
  is 
  exported 
  to 
  the 
  grid. 
   
   
  
 
  
To 
   the 
   extent 
   that 
   NEM 
   compensation 
   allows 
   a 
   project 
   to 
   be 
   viable, 
   the 
   entire 
   NEM 
   generation 
  
is 
   a 
   useful 
   metric. 
    
   In 
   this 
   instance, 
   an 
   exact 
   measure 
   of 
   the 
   effect 
   of 
   NEM 
   on 
   ratepayers 
   would 
  
compare 
   the 
   state 
   of 
   the 
   world 
   with 
   NEM 
   to 
   that 
   without 
   NEM, 
   and 
   calculate 
   the 
   ratepayer 
  
costs 
  under 
  both. 
   
  Unfortunately, 
  the 
  state 
  of 
  the 
  world 
  in 
  the 
  absence 
  of 
  NEM 
  is 
  a 
  theoretical 
  
and 
  unknown 
  condition, 
  which 
  is 
  further 
  confounded 
  by 
  other 
  incentive 
  programs 
  designed 
  to 
  
facilitate 
   the 
   deployment 
   of 
   DG 
   (such 
   as 
   the 
   Federal 
   Income 
   Tax 
   Credit, 
   California 
   Solar 
  
Initiative, 
   and 
   Self-­‐Generation 
   Incentive 
   Program). 
    
   Because 
   it 
   is 
   uncertain 
   how 
   much 
  
renewable 
  DG 
  would 
  be 
  installed 
  in 
  California 
  without 
  NEM, 
  or 
  how 
  customers 
  might 
  choose 
  to 
  
size 
   their 
   DG 
   or 
   change 
   their 
   electricity 
   usage 
   to 
   better 
   align 
   with 
   the 
   DG 
   output, 
   the 
   all 
  
generation 
   scenario 
   included 
   in 
   the 
   attached 
   report 
   likely 
   overestimates 
   the 
   costs 
   that 
   are 
  
directly 
  associated 
  with 
  NEM. 
   
  

 
  

Solar 
  is 
  Primary 
  Focus 
  of 
  the 
  Report 
   
  
 
  
The 
   attached 
   report 
   focuses 
   exclusively 
   on 
   the 
   NEM 
   program 
   within 
   the 
   territories 
   of 
   the 
   three 
  
large 
  investor-­‐owned 
  utilities 
  (IOUs), 
  which 
  had 
  enrolled 
  over 
  150,000 
  customers 
  totaling 
  1,300 
  
MW 
   through 
   the 
   end 
   of 
   2012. 
    
   Collectively, 
   these 
   systems 
   generated 
   about 
   2,400 
   GWh 
   of 
  
annual 
   electricity. 
   The 
   vast 
   majority 
   of 
   customers 
   on 
   NEM 
   tariffs 
   had 
   installed 
   solar 
   PV 
   (99% 
   of 
  
accounts, 
   and 
   96% 
   of 
   capacity). 
   Customers 
   with 
   wind 
   and 
   bioenergy 
   generation 
   make 
   up 
   the 
  
remaining 
   1 
   percent. 
    
   A 
   separate 
   evaluation 
   of 
   fuel 
   cell 
   NEM, 
   which 
   provides 
   credits 
   at 
   the 
  
generation 
  only 
  component 
  of 
  the 
  rate 
  for 
  fuel 
  cells, 
  including 
  those 
  that 
  are 
  fueled 
  by 
  natural 
  
gas, 
  is 
  also 
  included 
  in 
  the 
  report. 
  
 
  
Customer-­‐sited 
  solar 
  PV 
  installations 
  that 
  are 
  not 
  enrolled 
  on 
  a 
  NEM 
  tariff 
  are 
  excluded 
  from 
  
this 
   report. 
    
   As 
   of 
   June 
   2013, 
   492 
   installations 
   in 
   IOU 
   services 
   areas 
   representing 
   over 
   110 
   MW 
  
of 
   generating 
   capacity 
   opted 
   to 
   not 
   take 
   NEM 
   tariffs, 
   presumably 
   because 
   their 
   solar 
  
generation 
   was 
   not 
   expected 
   to 
   exceed 
   load 
   at 
   any 
   time, 
   and 
   thus 
   no 
   benefits 
   would 
   be 
  
accrued 
  from 
  NEM.3 
   
   
  
3

 
  Source: 
  Energy 
  Division 
  Second 
  Quarter 
  2013 
  Interconnection 
  Data 
  Request 
  

4 
  

 CPUC 
  NEM 
  Report 
  Introduction 
  

 
  

Impact 
  of 
  Possible 
  Rate 
  Reform 
  
 
  
The 
   CPUC 
   currently 
   has 
   an 
   open 
   proceeding 
   analyzing 
   future 
   residential 
   rate 
   designs 
   beyond 
  
the 
   current 
   inclining 
   block 
   tiered 
   rates 
   that 
   are 
   in 
   place 
   for 
   most 
   residential 
   customers 
   today 
  
(R.12-­‐06-­‐013). 
   In 
   addition, 
   the 
   Legislature 
   recently 
   approved 
   AB 
   327 
   (Perea), 
   which 
   greatly 
  
expands 
  the 
  CPUC’s 
  authority 
  to 
  approve 
  residential 
  rate 
  designs 
  that 
  more 
  accurately 
  reflect 
  
the 
   true 
   cost 
   of 
   utility 
   service 
   and 
   move 
   away 
   from 
   the 
   current 
   tiered 
   rate 
   structure. 
   
  
 
  
A 
  large 
  portion 
  of 
  the 
  cost 
  impacts 
  associated 
  with 
  residential 
  NEM 
  that 
  are 
  identified 
  in 
  this 
  
report 
   are 
   the 
   result 
   of 
   the 
   current 
   rate 
   designs. 
   The 
   analysis 
   in 
   this 
   report 
   shows 
   that, 
   on 
  
average, 
  residential 
  NEM 
  customers 
  would 
  have 
  paid 
  utility 
  bills 
  that 
  are 
  154% 
  higher 
  than 
  the 
  
utility’s 
  cost 
  of 
  providing 
  service 
  if 
  they 
  had 
  not 
  installed 
  a 
  NEM-­‐eligible 
  DG 
  system. 
  This 
  high 
  
cost 
   is 
   due 
   to 
   the 
   fact 
   that 
   most 
   residential 
   NEM 
   customers 
   are 
   in 
   the 
   higher 
   tiers. 
   These 
  
customers 
  stand 
  to 
  benefit 
  the 
  most 
  by 
  installing 
  NEM-­‐eligible 
  DG 
  systems, 
  but 
  as 
  discussed 
  in 
  
section 
  4.5.1 
  of 
  the 
  report, 
  the 
  higher 
  cost 
  tiers 
  also 
  drive 
  most 
  of 
  the 
  residential 
  cost 
  impacts 
  
identified 
  in 
  the 
  report’s 
  cost-­‐benefit 
  analysis. 
   
  
 
  
While 
   forecasting 
   the 
   impact 
   of 
   specific 
   changes 
   to 
   the 
   current 
   rate 
   design 
   is 
   beyond 
   the 
   scope 
  
of 
  this 
  study, 
  the 
  impacts 
  of 
  the 
  larger 
  residential 
  customers 
  on 
  the 
  overall 
  cost-­‐benefit 
  analysis 
  
make 
  it 
  clear 
  that 
  changes 
  in 
  the 
  current 
  tiered 
  rate 
  structures 
  will 
  also 
  dramatically 
  improve 
  
the 
  cost-­‐benefit 
  results 
  of 
  NEM. 
   
  

5 
  

 Draft California Net Energy
Metering Evaluation
Prepared for:
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, CA 94102

September 26, 2013

 Draft California Net Energy
Metering Evaluation
Prepared for:
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, CA 94102

September 26, 2013

Energy and Environmental Economics, Inc.
101 Montgomery Street, Suite 1600
San Francisco, CA 94104
415.391.5100
www.ethree.com

 This report prepared by:
Snuller Price
Brian Horii
Michael King
Andrew DeBenedictis
Jenya Kahn-Lang
Katie Pickrell
Ben Haley
Jon Kadish
Ryan Jones
Julia Sohnen
Jerry Bowers, Advent Consulting Associates

 Table of Contents
1

2

3

4

Executive Summary .............................................................................. 1
1.1

Net Energy Metering (NEM) Overview ............................................. 1

1.2

Scope of Evaluation.............................................................................. 2

1.3

Summary of Cost-Benefit Analysis Results ..................................... 5

1.4

Summary of Cost of Service Results ................................................ 9

1.5

Public Purpose Charges .................................................................... 11

1.6

Income Distribution of NEM Participants ........................................ 11

Introduction ...........................................................................................13
2.1

Net Energy Metering (NEM) Program Overview .......................... 13

2.2

Analysis Framework ........................................................................... 16

2.3

Terminology Employed ...................................................................... 19

Customer Characterization .................................................................25
3.1

Installed NEM Capacity ..................................................................... 25

3.2

Forecasted Penetration Levels ........................................................ 27

3.3

Data and Methodology for Estimating NEM Customer Profiles . 30

Cost-Benefit Analysis ..........................................................................39
4.1

Cost-Benefit Analysis Approach ...................................................... 39

4.2

Bill Savings ........................................................................................... 43

4.3

Avoided Costs...................................................................................... 53

4.4

Program Costs..................................................................................... 63

 5

6

7

4.5

Cost-Benefit Analysis Results .......................................................... 68

4.6

Benchmarking to 2010 Study ........................................................... 77

4.7

NEMFC Results .................................................................................. 79

Full Cost of Service.............................................................................. 83
5.1

Full Cost of Service Approach.......................................................... 85

5.2

Full Cost of Service Results ............................................................. 95

Avoided Public Purpose and Other Charges................................. 105
6.1

Methodology ...................................................................................... 105

6.2

Results ................................................................................................ 105

Household Income of NEM Customers .......................................... 109
7.1

Methodology ...................................................................................... 109

7.2

Results ................................................................................................ 110

APPENDIX A: Data Collection and Binning Methods
APPENDIX B: NEM Bill Calculations
APPENDIX C: Avoided Cost Calculations
APPENDIX D: Cost of Service Calculations
APPENDIX E: NEM Customer Income Analysis
APPENDIX F: Public Model User Guide
APPENDEX G: Public Utility Code and Statutes

 Executive Summary

1 Executive Summary
1.1 Net Energy Metering (NEM) Overview
This study evaluates the ratepayer impacts of the California net energy metering
(NEM) program and fulfills the requirements of Assembly Bill (AB) 2514
(Bradford, 2012)1 and Commission Decision (D.) 12-05-036 to determine “who
benefits, and who bears the economic burden, if any, of the net energy
metering program,” by October 1, 2013.2
NEM is an electricity tariff that facilitates the deployment of on-site renewable
distributed generation (DG).3 Under NEM tariffs, customers receive a bill credit
for energy that they generate and export to the grid. In this study we evaluate
the two types of NEM: Renewable NEM, which provides credits at the full retail
rate for solar PV, wind, and bioenergy generation; and fuel cell NEM, which
provides credits at the generation only component of the rate for fuel cells,
including those fueled by natural gas.
The vast majority of NEM customers in California are solar PV (99% of accounts,
and 96% of capacity). At the end of 2012, California’s three largest investor-

1

See Appendix G for further information about AB 2514
This study will also serve as an update to the CPUC’s 2010 NEM Cost Effectiveness Evaluation (2010 NEM Study)
http://www.cpuc.ca.gov/NR/rdonlyres/0F42385A-FDBE-4B76-9AB3-E6AD522DB862/0/nem_combined.pdf
3
Public Utilities Code 2827 (b) (4)
2

© 2010 Energy and Environmental Economics, Inc.

Page  1 

 Executive Summary

owned utilities (IOUs)4 had approximately 150,000 customers enrolled in NEM,
totaling 1,300 MW of installed capacity. Collectively, these systems generated
about 2,400 GWh of electricity during 2012.

1.2 Scope of Evaluation
We did four principle analyses in this study to characterize “who benefits from,
and who bears the economic burden, if any, of, the net energy metering
program”5 as required in statute:
(1) Cost-benefit analysis of NEM to estimate any costs shifted from NEM
customers to other customers,
(2) Cost of service evaluation to estimate the degree NEM customers pay
their share of utility costs,
(3) Public purpose charge savings to estimate the reduction in payments of
NEM customers toward public purpose programs, and
(4) Income demographic assessment to learn more about the household
incomes of residential customers with NEM generation.
The study is based on the current NEM policy in California that is defined by a
number of rules, including the 5% NEM cap established by D. 12-05-036, the net
surplus compensation rate under AB 920 (Huffman, 2009), and the existing

4
5

The IOUs are Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric.
All quotes in this section are from AB 2514, the full text of which is provided in Appendix G.

© 2010 Energy and Environmental Economics, Inc.

Page  2 

 Executive Summary

retail tariff designs at each utility. Changes to the structure of the NEM policy,
or to the retail rate structures, would change the results of this study.

1.2.1 NEM COST-BENEFIT ANALYSIS
In the cost-benefit analysis, we compare the reduction in NEM customer bills to
the reduction in utility costs. To the extent that the NEM customer’s bill
reduction is greater than offsetting utility savings, NEM will create a cost shift
from NEM customers to other customers as utilities adjust their rates to
compensate for the shortfall. The results of the analysis are disaggregated by a
number of dimensions, including by “utility, and customer class,” and for
“household income groups within the residential class.”
One of the key drivers of the magnitude of any cost impact is what generation is
measured; all of the NEM generation, or only the electricity generated that is
exported to the grid.

We recognize that this issue is controversial, and

therefore measure the net cost both ways. The net cost of the specific
mechanism enabled by NEM, namely the ability to ‘export’ electricity to the
utility at the retail rate, is measured by the ‘export only’ case in this study. This
approach disregards NEM generation consumed on the customer premise. We
also calculate the net cost of the entire NEM generator output. To the extent
NEM compensation enables the whole DG project to be viable, and the total
output of the project results in a cost to non-NEM customers, the entire NEM
generation is the appropriate scope to measure the impact on non-NEM
customers.

© 2010 Energy and Environmental Economics, Inc.

Page  3 

 Executive Summary

We analyze the costs and benefits of NEM at three different levels of installed
capacity: A forecast from the actual installed capacity at the end of 2012 (‘2012
Snapshot’ case), totaling approximately 1,305 MW; the capacity needed to
reach the goals of the California Solar Initiative (CSI) (‘Full CSI Subscription’),
totaling 2,916MW6; and the capacity needed to reach the 5% net metering cap
as defined by D. 12-05-036 (‘Full NEM Subscription’), forecast to be reached in
2020 at approximately 5,573 MW.
Other key input assumptions for which there is uncertainty, such as future
natural gas prices, CO2 prices, retail rate escalation, cost of interconnecting and
integrating NEM generation, and avoidance of transmission and distribution
system capacity costs, are considered through sensitivity analyses.

1.2.2 COST OF SERVICE OF NEM
In addition to cost-benefit analysis, we evaluate “the extent to which each class
of ratepayers and each region of the state receiving service under the net
energy metering program is paying the full cost of the services provided to them
by electrical corporations.” In the cost of service assessment we compare the
resulting bills of NEM customers to their full cost of service. Full cost of service
is a regulated utility term that includes all utility costs including an appropriate
share of utility fixed costs to serve the customer. We emulate the methodology
each utility used in their most recent General Rate Case (GRC) cost of service
allocations.

6

The cost of service analysis is an indicator of whether NEM

Includes solar, wind, and other NEM generation

© 2010 Energy and Environmental Economics, Inc.

Page  4 

 Executive Summary

customers pay their fair share of utility costs for use of the utility distribution
system.

1.2.3 PUBLIC PURPOSE CHARGES
We disaggregate the NEM customer bill savings to estimate the savings of NEM
customers in public purpose charges. In addition to public purpose charges, we
decompose the bill savings into all of the other subcomponents of the NEM
customer bill.

1.2.4 INCOME DISTRIBUTION OF NEM CUSTOMERS
We estimate the distribution of the household income of residential NEM
customers based on the median household income by census tract and census
block group using 2010 data provided by the IOUs. The current methodology
for the publicly reported household income information is based on zip code,
which is less granular than census tract and census block group levels. We
believe the much smaller geographic areas and more homogenous
demographics in census tract provide much better accuracy.

1.3 Summary of Cost-Benefit Analysis Results
1.3.1 NET ENERGY METERING COST-BENEFIT ANALYSIS
Table 1 shows the net cost of NEM exports to the grid by residential and nonresidential customers for each of the three penetration levels. In 2020, with a
complete build out of systems to the existing NEM cap, the costs associated

© 2010 Energy and Environmental Economics, Inc.

Page  5 

 Executive Summary

with NEM electricity exported to the grid under the current NEM tariffs are
approximately $359 million per year, or 1% of the utility revenue requirement.
Table 1: Net Cost of NEM Generation Exports in 2020 (Millions $2012/year)

2012 Snapshot

Full CSI
Subscription

Full NEM
Subscription

Residential

$60

$83

$287

Non-Residential

$16

$37

$72

Total

$75

$120

$359

0.22%

0.34%

1.03%

% of Revenue
Requirement

Table 2 shows the net cost of all NEM generation by residential and nonresidential customers for each of the three penetration levels.

The costs

associated with all NEM generation are forecast to be approximately $1.1 billion
per year in 2020 (in $2012). This is approximately 3.2% of the forecasted utility
revenue requirement.

© 2010 Energy and Environmental Economics, Inc.

Page  6 

 Executive Summary

Table 2: Net Cost of All NEM Generation in 2020 (Millions $2012/year)

2012 Snapshot

Full CSI
Subscription

Full NEM
Subscription

Residential

$183

$251

$797

Non-Residential

$71

$185

$306

Total

$254

$436

$1,103

% of Revenue
Requirement

0.73%

1.25%

3.16%

Approximately 2/3 of the net transfer is from residential NEM systems, with 1/3
of the net transfer from non-residential NEM systems. This is despite nonresidential systems accounting for 56% of the installed NEM capacity.
The bill savings for NEM customers are entirely a function of the retail rate
designs for each customer class and utility. In particular, there are significant
differences between residential and commercial customer rates. The cost
impact from residential NEM systems is significantly greater (levelized net cost
of $0.20/kWh generated) in the All Generation case than the cost impact from
non-residential systems (levelized net cost of $0.08/kWh generated) due to the
residential inclining block rate design. Relative to the residential rates, the
commercial rates generally include lower energy charges as well as demand
charges related to the customer peak load. Because NEM systems tend to
reduce net energy consumption by a greater percentage than they reduce peak
demand, residential NEM customers tend to experience greater bill savings than
commercial customers.
Table 3 and Table 4 show the net cost of residential customers broken out by
customer size. The larger customers are generally customers in the higher

© 2010 Energy and Environmental Economics, Inc.

Page  7 

 Executive Summary

inclining block tiers. These results indicate that possible changes to the
residential rate structure could have significant impacts on the costs associated
with residential NEM generation.
Table 3: Levelized Cost of NEM for Residential Customers by Usage Bin - Export
Only (Levelized $/kWh)
PG&E

SCE

SDG&E

All IOUs

Number of
Customers

< 5 MWh

0.01

0.03

0.05

0.03

12,621

5 to 10 MWh

0.08

0.08

0.10

0.09

46,056

10 to 25 MWh

0.21

0.15

0.17

0.17

71,992

25 to 50 MWh

0.30

0.22

0.23

0.25

8,150

50 to 100 MWh

0.27

0.24

-

0.25

360

100 to 500 MWh

0.31

-

-

0.31

18

Average

0.18

0.14

0.14

0.15

139,197

Customer Usage

© 2010 Energy and Environmental Economics, Inc.

Page  8 

 Executive Summary

Table 4: Levelized Cost of NEM for Residential Customers by Usage Bin - All
Generation (Levelized $/kWh)
PG&E

SCE

SDG&E

All IOUs

Number of
Customers

< 5 MWh

0.02

0.03

0.05

0.04

12,621

5 to 10 MWh

0.14

0.11

0.15

0.13

46,056

10 to 25 MWh

0.30

0.18

0.23

0.23

71,992

25 to 50 MWh

0.35

0.23

0.26

0.28

8,150

50 to 100 MWh

0.33

0.25

-

0.28

360

100 to 500 MWh

0.35

-

-

0.35

18

Average

0.26

0.17

0.19

0.20

139,197

Customer Usage

In the remainder of the report we provide significantly more detail and
disaggregation of the results for each of the respective analyses, as well as
results of sensitivities. In addition, a spreadsheet tool of calculations and results
has been made available to enable further disaggregation and testing of
additional sensitivities.

1.4 Summary of Cost of Service Results
The full cost of service analysis looks at the degree to which NEM customers pay
the utility costs associated with providing them service. In the full cost of
service analysis we find that both the residential and non-residential customers
look significantly different than typical customers. Residential NEM customers
who install renewable DG are larger than the average residential customer.
Because of the utility tiered rate structures, residential NEM customer bills were
54% greater than their cost of service, on average, before the installation of

© 2010 Energy and Environmental Economics, Inc.

Page  9 

 Executive Summary

NEM generation. Non-residential NEM accounts had bills that exceeded their
full cost of service by 22%. In the residential class, the differences were largely
explained by the customer size and tiered rates. In the non-residential class, the
reasons are linked more to an account’s usage pattern, rather than total usage.
After the installation of NEM generation, the aggregate gap between bills and
the full cost of service shrinks dramatically. Whereas total annual bills were
$175 million in excess of the full cost of service before DG, the difference is only
$23 million after DG. The relative changes to bills and full cost of service,
however, are not uniform across all utilities and customer sectors. Table 5
shows that, with renewable DG, NEM residential customers pay 88% of their full
cost of service compared to 154% before DG, and non-residential NEM
customers pay 113%, compared to 122% before DG. Overall, based on limited
information for a single year, the NEM accounts appear to be paying slightly
more than their full cost of service.
Table 5: Percent Cost of Service Recovery from NEM Customers in 2011 With
and Without DG Systems (% of Full Cost of Service)
PG&E

SCE

SDG&E

All IOUs

Without
DG

With
DG

Without
DG

With
DG

Without
DG

With
DG

Without
DG

With
DG

Residential

171%

93%

152%

101%

101%

60%

154%

88%

NonResidential

128%

106%

110%

108%

124%

122%

122%

113%

Total

146%

101%

122%

107%

119%

112%

133%

106%

© 2010 Energy and Environmental Economics, Inc.

P a g e   10  

 Executive Summary

1.5 Public Purpose Charges
In 2020, with a complete deployment of systems to the NEM cap, NEM
customers avoid approximately $172 million in public purpose charges, or about
6.5% of the total estimated 2020 public purpose funding.
Table 6: Bill Savings in Public Purpose Charges from NEM in 2020 ($2012
Million/year)

2012 Snapshot

Full CSI
Subscription

Full NEM
Subscription

Residential

$15

$21

$67

Non-Residential

$18

$53

$80

Total

$33

$74

$147

Total as % of Total Public
Purpose Charges

2.0%

3.3%

6.5%

1.6 Income Distribution of NEM Participants
Within the residential sector, we find that the customers installing NEM systems
since 1999 have an average median household income (based on IOU-provided
data at the census tract level7) of $91,210, compared to the median income in
California of $54,283 and in the IOU service territories of $67,821. In our
population of NEM customers, 78% had higher than the median California
household income, and 34% had higher than the median household income of
IOU customers. Figure 1 shows the 2010 household income in the census tract
of the customers that installed NEM generation since 1999 and the IOU and

7

Some data was provided at the more granular census block group level.

© 2010 Energy and Environmental Economics, Inc.

P a g e   11  

 Executive Summary

California median household incomes overall. The median household income of
NEM customers has been relatively consistent since 1999, but peaked in 2007
and has been declining moderately since.
Figure 1: NEM 2010 Household Income by Installation Year Compared to IOU
and California Median Income

© 2010 Energy and Environmental Economics, Inc.

P a g e   12  

 Evaluation of Hawaii?s
Renewable Energy Policy
and Procurement

Final Report

January 2014 Revision

 

Energy: Environmental Economics

Evaluation of Hawaii?s
Renewable Energy Policy
and Procurement

Final Report

January 2014 Revision

2014 Copyright. All Rights Reserved.
Energy and Environmental Economics, Inc.
101 Montgomery Street, Suite 1600

San Francisco, CA 94104

415.391.5100



This material is based upon work supported by the Department of Energy, under

Award Number(s) 0E?0i50000123.

Disclaimer: This report was prepared as an account of work sponsored by an
agency of the United States Government. Neither the United States Government
nor any agency thereof, nor any of their employees, makes any warranty,
express or implied, or assumes any legal liability or responsibility for the
accuracy, completeness, or usefulness of any information, apparatus, product, or
process disclosed, or represents that its use would not infringe privately owned
rights. Reference herein to any specific commercial product, process, or service
by trade name, trademark, manufacturer, or otherwise does not necessarily
constitute or imply its endorsement, recommendation, or favoring by the United
States Government or any agency thereof. The views and opinions of authors
expressed herein do not necessarily state or reflect those of the United States

Government or any agency thereof.

Executive Summary .. 1
Cost-Benefit Analysis Methodology .. 6
2.1 Overview .. 6
2.2 Benefits .. 8
2.2.1 Avoided Cost Components .. 9
2.2.2 Avoided Cost Scenario Analysis .. 24
2.3 PUC Scenarios Developed .. 26
2.4 Costs ..30 
2.4.1 Utility-Scale Procurement Costs ..31
2.4.2 Feed In Tariff Costs .. 31
2.4.3 Net Energy Metering Costs .. 31
Results ..36
3.1 Avoided Cost Components .. 36
3.2 HECO Avoided Cost Results .. 39
3.3 HELCO Avoided Cost Results .. 44
3.4 MECO Avoided Cost Results .. 48
3.5 KIUC Avoided Cost Results .. 50
3.6 Avoided Cost Conclusions .. 53
3.7 Net Cost Comparison .. 54
3.7.1 Utility Procurement .. 54

Table of Contents

3.7.2 Feed-in Tariff .. 56

5

3.7.3 Net Energy Metering .. 59

3.8 Net Cost Policy Comparison Conclusions .. 66
Comparison to Alternate Policy Design .. 67
4.1 Traditional Net Energy Metering Policy .. 67
4.1.1 Net Energy Metering in Hawaii .. 67

4.1.2 California Net Energy Metering .. 68

4.2 Virtual Net Metering and Community Energy .. 70
4.2.1 Community Solar in Hawaii .. 70

4.2.2 California Virtual Net Metering .. 71

4.2.3 Colorado Community Solar Gardens .. 72

4.2.4 Sacramento Municipal Utility District Solar Shares
Program .. 74

4.3 Feed?In Tariff Policy .. 75
4.3.1 Hawaii Feed-In Tariff .. 76

4.3.2 California Feed-in tariff .. 78

4.3.3 Long Island Power Authority Feed-in Tariff .. 80

4.4 Alternate Policy Design Summary .. 80

Summary and Conclusions .. 81

Executive Summary

1 Executive Summary

The State of Hawaii has ambitious goals for renewable energy development with a
target of 40% of the State's electricity coming from renewable generation by
2030. Under a National Association of Regulatory Commissioners (NARUC) funded
grant, Energy and Environmental Economics, Inc. (E3) was retained by the Hawaii
Public Utilities Commission (PUC) to develop a methodology and compare the

economics of different renewable generation procurement options.

This study evaluates some of the key renewable policy and procurement options
in the service territories of Hawaiian Electric Company, Inc. (HECO), Hawaii
Electric Light Company, Inc. (HELCO), Maui Electric Company, Limited (MECO),
and Kauai Island Utility Cooperative (KIUC). After the completion ofthis first phase
of study, the PUC will continue to work with E3 to further refine the approach and
evaluate potential changes to the existing planning and procurement of
renewable energy with the goal of reducing costs of renewables to ratepayers in
Hawaii and or increasing their value. E3 will provide technical assistance to the
PUC in this next phase by updating and improving the modeling and evaluation
tools and running stakeholder workshops to incorporate and validate the

approach.

 

2014 Energy and Environmental Economics, Inc. a 1 

 Evaluation of Hawaii?s Renewable Energy Policy and Procurement

In this phase, we develop an economic framework that can consistently compare
procurement options across all the Hawaiian Islands using a transparent and
industry standard approach, and we then perform an assessment of current
renewable procurement options in Hawaii. The basis for comparison in this study
is net cost (or value) of each renewable procurement option to ratepayers. The
net cost is calculated as the difference between the cost of renewable purchases,
including any associated ratepayer costs for interconnection, integration, and
delivery, and the avoided costs, including displaced conventional power plants,
reduced fuel consumption, and other avoided costs. We evaluate the following
procurement Options; utility-scale renewables purchased through competitive
bidding, smaller scale renewable energy systems purchased through feed-in-tariff
(FIT), and behind the meter renewables ?purchased? through net energy metering

(NEM).

We find that renewable energy provides a significant opportunity for Hawaii to
reduce electricity costs to customers. There are many renewable technology
types that provide net value to ratepayers. These include various sizes of wind
energy and solar photovoltaic generation on each island, as well as in-iine
hydroelectric generation. Given the high costs of purchasing petroleum fuels for
energy on the islands, these approaches can lower utility costs. However, not
every approach to procuring renewable energy and deploying it in Hawaii
provides net value. We find that biofuel resources are more costly than
conventional generation and other renewable options. We find that customer-

owned generators that sell energy to the system through NEM tariffs at full retail

 

Page  2l

Executive Summary

credit impose costs that exceed the avoided costs (the value to the system).
However, these findings are based upon currently available information on energy
and system costs and it is expected that additional data and improvements to the
methodology would further strengthen the analysis. In addition, this initial version
of the analysis excludes certain externalities, equity considerations, and fuel price
volatility impacts as well as other important regulatory considerations that are not

easily monetized.

These findings are based on the current procurement approaches in place in
Hawaii. In this report we include a review of alternative procurement approaches
that could be considered as a means to further reduce ratepayer costs as the PUC

reviews different resource portfolios and reviews policies such as FIT and NEM.

Beyond the net value of specific renewable energy types, we find that the
portfolio of renewable energy systems is important, and there is value in a
diversity of geographic locations and technology types to smooth out the
production of renewable energy and reduce the volatility on the system. In the
analysis completed in Phase 1, diversity generally reduces variability in the
production of renewable energy over the course of the year and displaces higher
cost generation and the need for conventional generation. We suspect that

diversity will also decrease the costs to integrate renewable energy which could

 

2014 Energy and Environmental Economics, Inc. a 3 

 Evaluation of Hawaii?s Renewable Energy Policy and Procurement

be illustrated with more detailed modeling of the operation of the island grid

systems.l

As noted above, we recognize that there are more considerations around
developing renewable energy in Hawaii than net cost and that these are not
included in this study. Additional positive aspects of renewable energy that are
not considered include the financial certainty of renewable purchases and
reducing sensitivity to oil price fluctuations, and the positive environmental and
quality of life benefits from cleaner air, water, and reduced greenhouse gas (GHG)
emissions. Renewable energy also provides more intangible values of energy
independence and sustainability. There are also negative aspects not considered
that include increased land use and the visibility of renewable energy systems.
Finally, there are other considerations such as equity in access to renewable
energy and the distributional impacts amongst those who benefit and those who
bear any costs associated with renewables. We believe that all of these issues
should be considered in the development of renewable energy policy and the
development of specific projects. To the extent possible, these important
elements should be included in future regulatory proceedings in addition to the

net cost approach presented here.

 

1 "Implications of Wide?Area Geographic Diversity for Short?Term Variability of Solar Power.? Ryan Wiser and
Andrew Mills. LBNL. September 2010. 

"Operating Reserves and Variable Generation.? Erik Ela, Michael Milligan, and Brendan Kirby. NREL. August 2011.


 

Page 

Executive Summary

In conclusion, we believe that renewable energy continues to provide a great
opportunity for Hawaii to address its existing and future energy challenges.
Through careful planning and procurement of renewable generation that focuses

on ratepayer value, Hawaii can both reduce costs and improve the environment.

In the report that follows, we provide a detailed description of our methodology
for developing avoided costs. Then we show the results that support our
conclusions above. Next, the report provides an overview of alternative
renewable procurement approaches from otherjurisdictions which is intended to
inform future procurement decisions and policy designs in Hawaii. Finally, we
provide conclusions and next steps to improve and refine the tools developed to
date and engage stakeholders to consider modifications to renewable

procurement that can decrease costs and increase the value of renewables. These

modifications can provide greater ratepayer benefits of renewables to Hawaii.

 

2014 Energy and Environmental Economics, Inc. a 

 

 
 
 
  
     


50cm I - 7i.
OUNTAIN
A 
?b 
I


THE ECONOMICS OF
GRID 

AND WHERE DISTRIBUT ED 
PLL STORAGE COMPETES
UTILITY SERVICE

trap;- I 

AUTHORS

ROCKY MOUNTAIN INSTITUTE
Jon Creyts, Leia Guccione, Maite Madrazo, James
Mandel, Bodhi Rader, Dan Self, and Peter Bronski

HOMER ENERGY
Jeffrey Abromowitz, John Glassmire, and Peter
Lilienthal

COHNREZNICK THINK ENERGY
Mark Crowdis, John Richardson, Evan Schmitt, and
Helen Tocco

 
- MOUNTAIN


 

Since 1982, Rocky Mountain institute has advanced
market?based solutions that transform global energy
use to create a clean, prOSperous, and secure
future. An independent, nonprofit think-and-do

tank, RMI engages with businesses, communities,
and institutions to accelerate and scale replicable
solutions that drive the cost-effective shift from fossil
fuels to efficiency and renewables.

Please visit for more information.

ROCKY





Tl NR Hurt

Founded in 2000, CohnReznick Think Energy,

LLC is a fullrservice renewable energy consulting
firm specializing in request for proposal (REP)
management, project development support, due
diligence advisory, and energy purchasing services.
CohnReznick Think Energy has assembled a

team skilled in energy, economic, financial, and
policy analysis; project management; engineering;
technology and resource evaluation; and project
deveIOpment. The team has worked on more than
38 active solar projects representing over 500 MWs

of capacity.

 

HOMER Energy, LLC provides software, consulting,
and market access services for analyzing and
optimizing microgrids and other distributed power
systems that incorporate high penetrations of
renewable energy sources. The HOMER software
is the global standard for economic analysis of
sustainable microgrid systems, with over 100,000
users in 193 countries. HOMER was originally
developed at the US. Department of Energy?s
National Renewable Energy Laboratory (NREL). Its
developers are now the principals of HOMER Energy,
which has the exclusive license.

THE ECONOMICS OF GRID DEFECTION 2

TABLE OF CONTENTS


KW  V, . . 
ii 00

Declining Costs for Distributed Energy Technologies
Adoption Driving Forces for Off?Grid Systems
Regulatory changes



Purpose
Why Solar?PIus?Batteries?
Analytical Approach

+x
H. 

Commercial Applications

Residential Applications

The lniluence oiecceleratec.? technology improvements and concurrent in-Iestrnents
in demand?side improvements?A Focus on Los Angeles County

Beyond Los Angeles??A Look at Regional Utility Rate Deciles

A: Additional solar?plus?battery system cost information

B: irnprovumntf: a 1d loaf! iiexii: iiLy
C: Additional technical performance assumptions

D: Homer Modeling

E: Financial assumptions section

F: Diesel standby generator permitting, emissions. and run time.

G: Analytical results by geography

@58995 THE Ecomoriics OF GRID DEFECTJON l3
INSTITUTEU

 

EXECUTIVE SUMMARY

 

         

     

  

.1  
mmw.u\w.7._ 

W4.) .

. .4 . 
 




 

     

    

         

       

EXECUTIVE SUMMARY

Distributed electricity generation, especially solar
PV, is rapidly spreading and getting much cheaper.
Distributed electricity storage is doing the same,
thanks largely to mass production of batteries for
electric vehicles. Solar power is already starting

to erode some utilities? sales and revenues. But
what happens when solar and batteriesjoin forces?
Together they can make the electric grid optional for
many customers?without compromising reliability
and increasingly at prices cheaper than utility retail
electricity. Equipped with a solar?plus?battery system,
customers can take or leave traditional utility service
with what amounts to a ?utility in a box.?

This ?utility in a box? represents a fundamentally
different challenge for utilities. Whereas other
technologies, including solar PV and other distributed
resources without storage, net metering, and

energy efficiency still require some degree of grid
dependence, solar?pius?batteries enable customers
to cut the cord to their utility entirely.

Notably, the point at which solar?pius?battery
systems reach grid parity?already here in some

areas and imminent in many others for millions

of US customers?is well within the 30-year
planned economic life of central power plants

and transmission infrastructure. Such parity and
the customer defections it could trigger would
strand those costly utility assets. Even before mass

defection, a growing number of early adopters could
trigger a spiral of falling sales and rising electricity
prices that make defection via soiar-plus-battery
systems even more attractive and undermine utilities?
traditional business models.

How soon could this happen? This analysis shows
when and where US. customers could choose to
bypass their utility without incurring higher costs or
decreased reliability. It therefore maps how quickly
different regions? utilities must change how they do
business or risk losing it. New market realities are
creating a profoundly different competitive landscape
as both utilities and their regulators are challenged

to adapt. Utilities thus must be a part of helping to
design new business, revenue, and regulatory models.

Our analysis focuses on five representative U.S.
geographies (NY, KY, TX, CA, and Hi). Those
geographies cover a range of solar resource
potential, retail utility electricity prices, and solar PV
penetration rates, considered across both commercial
and residential regionally-specific load profiles. After
considering many distributed energy technologies,
we focus on solarnplus?battery systems because

the technologies are increasingly cost effective,
relatively mature, commercially available today,

and can operate fully independent of the grid, thus
embodying the greatest potential threat.

 

ROCKY
Mot 'Ni HIN


THE ECONOMICS OF GRID DEFECTION 5

We model four possible scenarios:

Base case?Uses an average of generally
accepted cost forecasts for solar?plus?battery
systems that can meet 100% ofa building?s load,
in combination with occasional use of a diesel
generatOr (for commercial systems only]

Accelerated technology improvement?
Assumes that solar PV and battery technologies
experience more aggressive cost declines,
reaching or surpassing US. Department of
Energy 2020 targets

Demand?side improvement?includes
investments in energy efficiency and user-
controlled load flexibility

Combined improvement?Considers the
combined effect of accelerated technology
improvements and demand?side improvements

We compare our modeled scenarios against a
reasonable range of retail electricity price forecasts
bound by US. Energy Information Administration (EIA)
forecasts on the low side and a 3% real increase per
year on the high side.

FIGURE 1: OFF-GRID VS. UTILITY PRICE PROJECTIONS
COMMERCIAL- BASE CASE


LCOE Retail

LCOE Retail
Los Angeles. CA 
Honolulu. HI ..

Louisville. KY
Westchester, NY .
San Antonio. TX .-

$140.
$120.
$100.
$030. 
$0.5m 

Hi 

$Q4o.

$0.20 -

 

 


201i;l 2018 2022 2025 2030 2034 2038 2042 2046 2050



INSTITUTE 

EXECUTIVE SUI IMARY

The analysis yields several important conclusions:

-, - yr;   For certain customers, including

many customer segments in Hawaii, grid parity is
here today. It will likely be here before 2030 and
potentially as early as 2020 for tens of millions of
commercial and residential customers in additional
geographies, including New York and California (see
Figures 1 and 2). In general, grid parity arrives sooner
for commercial than residential customers. Under
more aggressive assumptions, such as accelerated
technology improvements or investments in demand-
side improvements, grid parity will arrive much sooner
(see Figures 3 and 4).

  i -  --  Ouranalysis
is based on average load profiles; in each geography
there will be segments ofthe customer base for whom
the economics improve much sooner. In addition,

FIGURE 2: OFF-GRID VS. UTILITY PRICE PROJECTIONS


2012$lkWh]

LCOE Retail
LCOE Retail

LosAngeIes.CA --

Louisville, KY
Westchester, NY

San Antonio. TX -- . Honolulu. HI

$130-
stso-g



stoo-
$030-
soso-

$0Ao;

 

  

sozoa

 

 

$2014 2013 2022 2026 2030 2034 2038 2042 2046 2050

 

THE ECONOMICS OF GRID DEFECTION 6

EXECUTIVE SUM MARY

FIGURE 3: COMMERCIAL PARITY TIMELINE

36' Base Case - Demand-Side Improvements Louisville. KY Los Angeles, CA
ATI - Accelerated Technology Improvements Cl - Combined Improvements Westchester, NY Honolulu, HI
San Antonio, TX

Parity is here already or

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(2
coming In the next decade ATI 
.61 
"A'lLCI
2015 2020 2025 I 2030 2035 2040 2045 2050
FIGURE 4: RESIDENTIAL PARITY TIMELINE
BC - Base Case DSI - Demand-Side Improvements Louisville, KY Los Angeles, CA
ATl?Accelerated Technology Improvements Cl Combined Improvements -- - Westchester, NY Honolulu, HI

San Antonio. TX

Parity Is here already or

 

 

 

 

 

 

 

 

 

 

 

 

 

coming in the next decade ?43?2015 2020 2025 2030 2035 2040 2045 2050
53385}; THE ECONOMICS OF GRID DEFECTION 17



motivating factors such as customer desires for
increased power reliability and low?carbon electricity
generation are driving early adopters ahead of grid
parity, including with smaller grid-dependent solar?
plus-battery systems that can help reduce demand
charges, provide backup power, and other benefits.
Still others will look at investments in solar-plus-
battery systems as part of an integrated package that
includes efficiency and load flexibility. This early state
could accelerate the infamous utility death spiral?self-
reinforcing upward rate pressures, making further self?
generation or total defection economic faster.

  The ?old? cost recovery model, based on
sales, by which utilities recover costs and an
allowed market return on distribution networks, central
power plants, andiortransmission lines will become
obsolete. This is especially profound in certain regions
of the country. In the Southwest across all sold
by utilities, for example, our conservative base case
shows solar-plus?battery systems undercutting utility
retail electricity prices for the most expensive one?
fifth of load served in the year 2024; under more
aggressive assumptions, off-grid systems prove
cheaper than all utility?sold electricity in the region

just a decade out from today (see Figure 5).


MOUNTRIN
INSTITUTE 

EXECUTIVE SUMMARY

Though many utilities see the impending
arrival of solar?plus-battery grid parity as a threat,
they could also see such systems as an opportunity to
add value to the grid and their business models. The
important next question is how utilities might adjust
their existing business models or adopt new business
models?either within existing regulatory frameworks
or under an evolved regulatory landscape?to tap into
and maximize new sources of value that build the best
electricity system of the future at lowest cost to serve
customers and society. These questions will be the
subject ofa forthcoming companion piece.

FIGURE 5: US. SOUTHWEST 2024 SOLAR-PLUS-
BATTERY COMMERCIAL SCENARIOS
VS. ESTIMATED UTILITY RATE DECILES

$0.24 -

$020.

 

$0.16-
$m2-
$0.08

$0.04.

 

 

 

$0

ECONOMICS OF GRID DEFECTION I 8

 . LI. J'VALUE OF THE GRID
TO DG CUSTOMERS

IEE Issue Brief
September 2013
Updated October 2013

 

..
INNOVATION
. ELECTRICITY
EFFICIENCY




 

- An Institute of The Edison Foundation

 

Value of the Grid to DG Customers

IEE Issue Brief
September 2013
Updated October 2013

Prepared by
Lisa Wood
IEE
Robert Borlick
Borlick Associates

 VALUE OF THE GRID TO DG CUSTOMERS
Some advocates of distributed generation (DG) claim that the DG customer derives no benefit
from being connected to the host utility’s distribution system.1 While it is easy to say that a DG
customer is “free from the grid,” that is simply not true – even for a DG customer (or a microgrid) that produces the exact amount of energy that it consumes in any given day or other time
interval.2
This paper describes how a DG customer (or a micro grid) that is connected to the host utility’s
distribution system 24/7 utilizes grid services on a continuous, ongoing basis. The point is to
recognize the value of these grid services and to develop a methodology for the DG customer to
pay for using the services. The utility’s cost of providing grid services consists of at least four
components – the typical fixed costs associated with: (i) transmission, (ii) distribution, (iii)
generation capacity, and (iv) the costs of ancillary and balancing services that the grid provides
throughout the day for the DG customer.
There is a related question about how much DG customers should be paid, or credited, for the
excess electric energy they produce on-site and inject into the grid. This paper does not
explicitly address this “value of on-site energy” issue.
THE BENEFITS OF REMAINING CONNECTED TO THE DISTRIBUTION SYSTEM
Consider a residential or small commercial customer with solar PV panels on its rooftop. Figure
1 displays a typical hourly pattern of energy production and consumption for such a customer.
The green area is the energy delivered by the host utility and consumed by the customer. The
area under the blue curve is the energy produced on-site by the solar panels. The area below the
blue curve and above the green line is the excess energy injected into the utility’s distribution
system. The key take-away from this graphic is that the customer’s consumption and generation
are almost never equal; consequently, most of the time the customer is using the external power
system to offset the difference between the customer’s consumption of electric energy and its on1 A recent Forbes article, “Distributed Generation Grabs Power from Centralized Utilities,” August 8, 2013,
ignores and fails to mention the grid services that are provided to DG customers continuously by the host
utility.
2 The term, DG, refers to small retail customers with on-site generation that are net metered.

1

 site production. In most cases the customer will be taking energy from the grid during many
hours of the day. For example, the customer depicted in Figure 1 takes power from the grid in
all hours except from noon to about 4:30 pm.
Figure 1: Typical Energy Production and Consumption for a Small Customer with Solar PV
5.00

Customer uses grid to
export excess power
4.00

3.00

Utility provides power

Kilowatt
2.00

Customer generation,
grid support needed

Utility provides power
1.00

0.00
1am

2

3

4

5

6

7

8

9

10

11 12pm

Consumption

1

2

3

4

5

6

7

8

9

10

11 12am

Solar Production

Customers with any type of DG that are connected to the grid will be utilizing external grid
services to:
▪

balance supply and demand in sub-second intervals to maintain a stable frequency (i.e.,
regulation service);

▪

resell energy during hours of excess generation and deliver energy during hours of deficit
generation;

▪

provide the energy needed to serve the customer’s total load during times when on-site
generation is inoperable due to equipment maintenance, unexpected physical failure, or
prolonged overcast conditions (i.e., backup service);

▪

provide voltage and frequency control services and maintain high AC waveform quality.

Clearly, even if the customer’s total energy production over some time interval (e.g., a monthly
billing cycle) exactly equals its consumption over that same interval, that customer is still
utilizing at least some, if not all, of the above grid services during that time interval.

2

 So what value does a customer with solar PV generation derive from remaining connected to the
grid? Let’s begin by examining the charges that a typical residential customer consuming an
average of about 1000 kilowatt-hours (kWh) per month [average consumption based on Energy
Information Administration (EIA) data and rounded] will pay for grid services, excluding the
charges for the electric energy itself. These charges are designed to allocate to the customer its
fair share of the fixed costs associated with the transmission system, the distribution system,
balancing and ancillary services, and the utility’s (or the retail supplier’s) investment in
generation capacity.3 As stated earlier, the electric energy charges designed to recover the cost
of the energy (kWh) consumed by the customer (including the associated transmission and
distribution losses), are excluded here. Table 1 illustrates these charges for a typical residential
customer.4
Table 1 – Non-Energy Charges Paid by a Typical Residential Customer on a Retail Tariff

Average Residential Customer:
Non-Energy Charges as Percent of Typical Monthly Bill
Average Monthly Usage (kWh)*
1000
Average Monthly Bill ($)*
$110
Typical Monthly Fixed Charges
Ancillary/Balancing Services
Transmission Systems
Distribution Services
Generation Capacity ^
Total Fixed Charges for Customer
Fixed Charges as Percent of Monthly Bill

$1
$10
$30
$19
$60
55%

*Based on Energy Information Administration (EIA) data, 2011
^The charge for capacity varies depending upon location. This is just an estimate.

In this example, the typical residential customer consumes, on average, about 1000 kWh per
month and pays an average monthly bill of about $110 (based on EIA data). About half of that
bill (i.e., $60 per month) covers charges related to the non-energy services provided by the grid,

3 In “retail choice” states the retail customer can choose its energy supplier, which may not be the utility. In
all other states the utility will be the retail supplier.
4 Other charges, such as sales and franchise taxes and environmental charges could be added to the table;
however, the focus of this paper is on the grid services that are provided by the host utility.

3

 including a charge for generation capacity. Because residential retail rates are almost always
designed to recover most of the power system’s fixed costs through kWh charges, a DG
customer will avoid paying some or all of its fair share of the fixed costs of grid services.
Ultimately the fixed costs that the DG customer does not pay, which are significant, will be
shifted to other retail customers. In this example, each DG customer shifts up to $720 per year in
costs (i.e., $60 * 12 months) to other retail non-DG customers. To put this into context, if 50
percent of the residential customers in a given utility service territory had DG, the non-DG
residential customers in that service territory could experience bill increases of up to 55 percent –
from $110 per month to $170 per month. Clearly this cost shift is substantial and simply not fair.
IEE submits that DG customers should pay their fair share of the cost of the grid because
pushing any of this cost onto non-DG customers raises serious economic efficiency and fairness
issues. Indeed this is one of the key issues in the current debate over net metering.
To illustrate the value provided by the grid for a solar PV customer, consider what it would cost
that customer to self-provide the technical equivalent of these services through some
combination of energy storage and/or thermal generation (e.g., a Generac home generator).
Preliminary estimates of the monthly costs that a typical residential customer would have to
incur to self-provide the balancing and backup services that the grid currently provides are
substantially higher than the $60 charge shown in Table 1.5 Furthermore, this cost estimate of
self-provision excludes the additional cost of maintaining the level of voltage and frequency
control and AC waveform quality currently provided by the grid. An off-the-grid DG customer
(or micro-grid) simply cannot provide, at reasonable cost, the same quality of service that a large
power system provides. So, in fact, most DG customers remain connected to the grid today and
utilize grid services.
This straightforward cost comparison to “self providing” grid services reveals three things. First,
the balancing and backup services that the grid provides to DG customers are needed and have
substantial value. Second, it does not make economic sense for a DG customer to self-provide
these services. Third, it is unfair for DG customers to avoid paying for these grid services,
5 The Electric Power Research Institute (EPRI) is developing estimates of the cost of self-providing grid
services and expects to release its results in 2014.

4

 thereby shifting the cost burden to non-DG customers. Obviously, DG customers should pay
their fair share of the cost of the grid services that the host utility provides.
ECONOMIES OF SCALE ASSOCIATED WITH POWER SYSTEMS
In many ways, the growth of DG and micro grids today goes full circle back to the early days of
the electric power industry. Initially power systems were isolated and each served its own
service area. As service areas expanded, utilities began to interconnect. PJM was the first entity
to interconnect utilities for reliability purposes and to centrally provide balancing services. This
evolution was driven by the substantial economies of scale that still exist today as ISO/RTO
markets continue to grow and expand.6
These interconnection entities developed for good reasons. When a small power system
interconnects with a larger one, all members of the resulting combined entity benefit. However,
it has been observed that the small system benefits disproportionately more than the incumbent
members. For example, the small system’s operating reserve margin will decrease substantially.
This phenomenon is even more pronounced when a micro-grid interconnects with a power
system.
DG MARKET IS GROWING, PRICING IT RIGHT IS KEY
Although net metering was a convenient vehicle for kick-starting the DG market, there are now
serious questions among state policymakers regarding its continuation and needed reforms. One
main concern, addressed by this paper, is that net-metered customers are avoiding payment of
their fair share of the grid services described earlier, thereby causing those lost revenues to be
recovered from other customers. As also demonstrated in this paper, these “grid” costs are quite
significant – about 55 percent of the monthly electric bill for a residential customer as
demonstrated in Table 1. Although this may not have been a major problem when the DG
market was in its infancy, sending the wrong price signals to both customers and to the DG
industry is a major problem as the DG market rapidly grows and develops.

6 Entergy’s decision to join MISO is a recent example.

5

 REVENUE DECOUPLING WILL NOT RESOLVE THE DG COST-SHIFTING ISSUE
Revenue decoupling is currently being used to promptly restore utility net revenues that would
otherwise be lost due to declining electricity sales resulting from utility investments in energy
efficiency (EE). Although revenue decoupling makes the utility whole, it does so by explicitly
shifting costs from participating EE customers to nonparticipating EE customers using a public
or system benefits charge (which is typically visible and transparent to all customers as a charge
on their utility bills). Decoupling causes the same cost shifting problem that is created by DG
with net metering. However, a fundamental difference is that the magnitude of the “cost
shifting” to non DG customers is on a much larger scale than the cost shifting due to energy
efficiency. A recent study revealed that decoupling rate adjustments for energy efficiency are
quite small – about 2 to 3 percent of the retail rate.7 In contrast, as described earlier in this paper,
a DG customer could shift up to 55 percent of the retail rate onto non-DG customers (and, unlike
efficiency charges, which are transparent, the DG cost shifting is essentially invisible to
customers).
The amount of cost-beneficial energy efficiency is limited because the more you achieve, the less
cost-beneficial the next increment of energy savings becomes. This “diminishing return” aspect
means that energy efficiency increases only when it makes economic sense. In contrast, no such
economic limit applies to DG. In fact, costs – particularly for rooftop solar PV – are expected to
decline over time. Although regulators have been willing to accept a relatively limited amount
of cost shifting to promote utility investments in energy efficiency (about 2-3 percent of rates, on
average), they are unlikely to accept the magnitude of cost shifting that will accompany the rapid
expansion in net-metered DG unless some reforms to net metering are put into place.8
ALTERNATIVE APPROACHES TO END COST SHIFTING DUE TO NET METERING
Three basic approaches to net metering are under examination across the nation, each of which
seeks to ensure that a DG customer using grid services pays its fair share of the costs of those
services while still receiving fair compensation for the excess energy that it produces:
7 “A Decade of Decoupling for US Energy Utilities: Rate Impacts, Designs, and Observations.” Pamela
Morgan, Graceful Systems LLC. February 2013.
8 Distributed generation and net metering were very hot topics at the Summer 2013 NARUC meetings with at
least five panel discussions addressing them.

6

 ▪

Redesign retail tariffs such that they are more cost-reflective (including adoption of one or
more demand charges);

▪

Charge the DG customer for its gross consumption under its current retail tariff and
separately compensate the customer for its gross (i.e., total on-site) generation; and

▪

Impose transmission and distribution (T&D) “standby” charges on DG customers.

These three approaches are illustrative and are further described below.
Redesign Retail Tariffs (APS Proposal). To address the fundamental issue that a residential
customer with rooftop solar should be compensated at a fair rate for the power it exports (sells)
to the grid and also pay a fair price for its use of grid services, APS is proposing two options.9
The first option requires the customer to take service under an existing demand-based rate
schedule. The demand charge would cover a reasonable portion of the cost of grid services.
The second option allows the customer to choose an existing APS rate schedule for its total
electric consumption and APS will purchase all of the customer’s rooftop solar generation at
market-based wholesale rates. This option ensures recovery of grid services and sends more
accurate price signals to DG customers. It is also conceptually very close to what Austin Energy
has already put in place.
Treat On-site Generation and Consumption Separately (Austin Energy Tariff). Austin
Energy has implemented a solar tariff that fully compensates its DG customers for their gross onsite generation while separately charging them for their gross consumption under its existing
retail tariff.10 This approach effectively ensures that the cost of grid services are recovered from
DG customers while also compensating DG customers for their generation at the utility’s full
avoided cost of procuring energy. The Public Utility Regulatory Policies Act (PURPA), under
Title II, provides an established precedent for such compensation.11 This approach requires a
separate meter for on-site generation.

9 APS conversation, July 2013.
10 Rabago, K.R., The ‘Value Of Solar’ Rate: Designing An Improved Residential Solar Tariff, Solar Industry,
February, 2013. Available at www.solarindustrymag.com.
11 Although PURPA only applies to generating resources that are Qualified Facilities (QFs), this condition has
not been applied if the customer receives a credit on its electric bill, rather than a monetary payment for its
generated energy.

7

 Implement T&D Standby Charges for DG Customers (Dominion Tariff). Dominion
requires a residential net-metered DG customer with a solar installation whose rated output is
greater than 10kW and up to 20kW, to pay a monthly transmission standby charge of $1.40 per
kW and a monthly distribution standby charge of $2.79 per kW. However, these standby charges
are respectively reduced, dollar for dollar, by the customer’s transmission and distribution
charges that are recovered through kWh charges applied to the customer's monthly electricity
consumption up to the point where each standby charge is fully phased out. This became
effective on April 1, 2012. Dominion also proposed a placeholder for a future generation
standby charge, but it was not approved. The Commission ruled that a generation standby
charge should be studied and filed in a future proceeding.
A FINAL THOUGHT
In light of the rapid growth in net-metered DG, it is critical that these customers pay their fair
share of the cost of grid services provided to them – and sooner rather than later. Updating net
metering policies to put an end to the cost shifting that is occurring today should be done now.

8

 About IEE
IEE is an Institute of The Edison Foundation focused on advancing
the adoption of innovative and efficient technologies among electric
utilities and their technology partners that will transform the power
grid. IEE promotes the sharing of information, ideas, and experiences
among regulators, policymakers, technology companies, thought leaders, and the electric power industry. IEE also identifies policies that
support the business case for adoption of cost-effective technologies.
IEE’s members are committed to an affordable, reliable, secure, and
clean energy future.
IEE is governed by a Management Committee of electric industry Chief
Executive Officers. IEE members are the investor-owned utilities that
represent about 70% of the U.S. electric power industry. IEE has a
permanent Advisory Committee of leaders from the regulatory community, federal and state government agencies, and other informed
stakeholders. IEE has a Strategy Committee of senior electric industry
executives and 30 smart grid techology company partners.
 
Visit us at: www.edisonfoundation.net/IEE

For more information contact:
Lisa Wood
Executive Director
IEE
701 Pennsylvania Avenue, N.W.
Washington, D.C. 20004-2696
202.508.5440
lwood@edisonfoundation.net