The Renewables Portfolio Standard
Where are we now?
Where do we go from here?
A consumer perspective
CCPUC Annual Meeting
October 5, 2009
Matthew Freedman
The Utility Reform Network
matthew@turn.org

California Retail Renewable Procurement
Procured renewable electricity as a percentage of total retail sales
28%
26%
24%
22%
% of total sales from renewables
20%
18%
16%
14%
12%
PG&E
10%
SCE
8%
SDG&E
6% IOU average
4% ESP average
2%
0%
2001 2002 2003 2004 2005 2006 2007 2008 2009* 2010* 2011* 2012*
*forecast in IOU filings

California Investor Owned Utility Renewable Energy Contracts
Initial Execution vs. Expected Initial Online/Delivery Dates
8,000
7,000
Contracts Executed
6,000 Projected online date
Megawatts
5,000
4,000
3,000
2,000
1,000
0
2002
2003
2005
2006
2008
2009
2010
2011
2012
2013
2015
2016
2018
2004
2007
2014
2017

Projected IOU cumulative RPS deficits
4,000
PG&E
SCE
2,000 SDG&E
Total deficit (Gwh)
-
2004 2005 2006 2007 2008 2009* 2010* 2011* 2012*
(2,000)
(4,000)
(6,000)
8.6% of SCE retail sales
(8,000)
8.8% of PG&E retail sales

SB 14/AB 64 Provisions
Sets targets/timetables (20% by 2013, 25% by 2016, 33% by 2020)
• CPUC may delay targets if retail seller demonstrates inadequate
transmission, permitting/interconnection delays for contracted generation,
insufficient supply.
• Eliminates IOU cumulative deficits.
Cost containment (MPR + 6% of IOU revenues through 2020)
Municipal utilities subject to comparable targets and resource eligibility
• Program must be submitted to CEC for review
• CEC/ARB penalties
Maintains current definitions for eligible renewable technologies

SB 14/AB 64 Provisions
Transmission
• Clarifies CPUC retail “backstop” cost recovery for renewable
transmission upgrades
• Requires CPUC to issue a CPCN decision on new transmission
applications within 18 months of filing unless an extension is necessary
to complete requisite CEQA reviews
Limits “undelivered” renewable energy to no more than 30% of total RPS
procurement
• Authorizes use of unbundled/undelivered RECs from out-of-state
resources
Directs CPUC to approve certain cost-of-service UOG applications for
renewable generation
• Must provide “comparable or superior value to ratepayers” relative to
PPA options
• No obligation on IOU to propose any UOG. Limited to 8.25% of retail
sales (25% of 33% RPS)

Governor’s RPS Executive Order
Shaky legal status creates risk of litigation and delay
• Retail sellers cannot be obligated to procure beyond 20% (§399.15(b)
(1)) or if above-market funds are exhausted (§399.15(d)(3)).
• ARB is prohibited from altering the GHG reduction programs
administered by other agencies (Cal. Health and Safety §38574).
• Applicability ends when this Governor leaves office
• Program can be held hostage to litigation threats by various parties
Unknown program structure will create chaos
• Targets, timetables, resource eligibility, delivery, flexibility
• Can ARB establish and enforce cost-containment?
• Could be low-carbon standard -- open to different resources (IGCC,
CHP, sequestration). Eligibility rules could change with little notice
• Retail sellers/munis likely to delay long-term commitments
• Above-market funds in current RPS program are already exhausted
• Potential delays in project development due to investor concerns

IOU RPS procurement
In-state v. Out-of-state MWs contracted by year
2009
2008
Out-of-state
2007 In state
2006
2005
2004
2003
2002
- 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
Contracted MW executed by year

Delivery from out-of-state renewable projects
Current RPS rules allow virtually any transaction to count as “delivered”
• Retail seller must buy bundled energy + RECs from generator
• Any import of electricity into CA can be “repurposed” as renewable
• No incremental import test
• ”Piece of paper and a lump of coal”
Most Western RPS programs have more stringent delivery requirements
SB 14 would modify delivery requirements for out-of-state resources
• Delivery assumed if first point of interconnection is to facilities of a CA
transmission service provider. Includes out-of-state ISO facilities.
• Otherwise, delivered imports must be directly scheduled from the
generator into CA without substituting brown power or delivering in a
different hour/day/month.
• Allows retail sellers to procure up to 30% of RPS obligations with
undelivered renewable energy (including unbundled RECs).

Value of Out-of-State RPS resources to consumers
Out-of-state resources are cheaper and easier to build
• Lowers RPS compliance cost but diminishes value to California
GHG benefits likely to be subsumed within national/regional cap-and-trade
• RECs don’t contain GHG emission reductions
• Cap will define total emissions
Utilities engaging in REC-like deals
• Renewable power sold into nearby market hubs
• Imports need not be incremental or additional
• Significant contracts with existing renewables
No local or in-state benefits
• Jobs, tax revenues, investment
• Minimal or no displacement of in-state fossil fuel consumption
• Price hedging value may be minimal
Increased reliance on out-of-state could lead to demise of in-state projects
• Developers of in-state projects could relocate or cancel
• Potential for new in-state transmission projects to be stranded?

IOU renewable contracts
Above vs. Below MPR
3,000
2,000
MW of executed renewable contracts
1,000
(Below) / Above MPR
0
2002 2003 2004 2005 2006 2007 2008 2009
(1,000)
(2,000)
(3,000)
Above MPR
(4,000)
At/Below MPR
(5,000)
(6,000)
(7,000)

RPS cost containment
Cost containment and benchmarking should be part of the RPS program
• Can help discipline market and establish off-ramps if costs skyrocket
• Allows/forces CPUC to compare the relative above-market cost of
alternatives
• Establishes an explicit threshold for determining what is unreasonable
Various approaches offer potentially different results
• Market Price Referent + Above-market funds
• Total program cost cap (including transmission and system costs)
• Feed-in-Tariff
• Technology-specific cost curves
• ”Just and Reasonable”

Next steps to provide stability, clarity
and maximize consumer benefits
Statutory authorization for 33% with basic program rules
• Minimize endless implementation battles
• Avoid market disruptions and uncertainty
Focus on siting/permitting/land-use challenges
• Multi-agency issues -- BLM, DFG, and others
• Develop streamlined processes, identify suitable land
Develop needed transmission on an expedited basis
• Major obstacle to renewable generators coming online
Continue annual solicitations
• Select least-cost/best-fit projects using enhanced viability screen
• Consider terminating nonperforming PPAs
• Initiate auctions for distributed PV installations